UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________________________
Form 10-K
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2014 |
Commission file number: 001-32997
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Magnum Hunter Resources Corporation
(Name of registrant as specified in its charter)
| Delaware | 86-0879278 |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
777 Post Oak Boulevard, Suite 650, Houston, Texas 77056
(Address of principal executive offices, including zip code)
(Address of principal executive offices, including zip code)
Registrant’s telephone number including area code: (832) 369-6986
Securities registered under Section 12(b) of the Act:
| Title of Each Class | Name of Each Exchange on Which Registered |
Common Stock, par value $.01 per share 10.25% Series C Cumulative Perpetual Preferred Stock 8.0% Series D Cumulative Preferred Stock Depositary Shares, each representing a 1/1,000 interest in a share of 8.0% Series E Cumulative Convertible Preferred Stock | NYSE NYSE MKT NYSE MKT NYSE MKT |
Securities registered under Section 12(g) of the Act:
None
None
____________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes ¨ No x
Indicate by check mark if the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
| Large accelerated filer | x | Accelerated filer | ¨ | |
| Non-accelerated filer | ¨ | (Do not check if a smaller reporting company) | Smaller reporting company | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act Yes ¨ No x
State the aggregate market value of voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $1,560,087,080
As of February 23, 2015, 200,935,464 shares of the registrant’s common stock were issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Documents incorporated by reference: Portions of the registrant’s notice of annual meeting of shareholders and proxy statement to be filed pursuant to Regulation 14A within 120 days after the registrant’s fiscal year end of December 31, 2014 are incorporated by reference into Part III of this Form 10-K.
MAGNUM HUNTER RESOURCES CORPORATION
2014 Annual Report on Form 10-K
Table of Contents
Table of Contents
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CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS
This annual report on Form 10-K includes “forward-looking statements” as defined in Section 27A of the Securities Act of 1933, as amended, referred to as the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, referred to as the Exchange Act. All statements other than statements of historical facts included or incorporated herein may constitute forward-looking statements. Actual results could vary significantly from those expressed or implied in such statements and are subject to a number of risks and uncertainties. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect operations, financial performance, and other factors as discussed in this annual report and other filings made by us with the Securities and Exchange Commission, or SEC. Among the factors that could cause results to differ materially are those risks discussed in this and other reports filed by us with the SEC. You are urged to carefully review and consider the cautionary statements and other disclosures made in this and those filings, specifically those under the heading “Risk Factors.” Forward-looking statements speak only as of the date of the document in which they are contained, and we do not undertake any duty to update any forward-looking statements except as may be required by law.
NON-GAAP FINANCIAL MEASURES
We refer to the term PV-10 in this annual report on Form 10-K. This is a supplemental financial measure that is not prepared in accordance with U.S. generally accepted accounting principles, or GAAP. Any analysis of non-GAAP financial measures should be used only in conjunction with results presented in accordance with GAAP. PV-10 is the present value of the estimated future cash flows from estimated total proved reserves after deducting estimated production and ad valorem taxes, future capital costs, abandonment costs, net of salvage value, and operating expenses, but before deducting any estimates of future income taxes. The estimated future cash flows are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and 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 investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry. However, PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows.
The SEC has adopted rules to regulate the use in filings with the SEC and in public disclosures of “non-GAAP financial measures,” such as PV-10. These measures are derived on the basis of methodologies other than in accordance with GAAP. These rules govern the manner in which non-GAAP financial measures are publicly presented and require, among other things:
| • | a presentation with equal or greater prominence of the most comparable financial measure or measures calculated and presented in accordance with GAAP; and |
| • | a statement disclosing the purposes for which the company’s management uses the non-GAAP financial measure. |
For a reconciliation of PV-10 to the standardized measure of our proved oil and gas reserves at December 31, 2014, see “Business—Non-GAAP Measures; Reconciliations” in Item 1 of this annual report.
| Item 1. | BUSINESS |
Unless stated otherwise or unless the context otherwise requires, all references in this annual 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 gas company engaged primarily in the exploration for and the exploitation, acquisition, development and production of natural gas and natural gas liquids resources in the United States. We are focused in what we believe to be two of the most prolific unconventional shale resource plays in the United States, specifically, the Marcellus Shale and the Utica Shale plays located in the Appalachian Basin within the States of West Virginia and Ohio. We also own (i) primarily non-operated oil and gas properties in the Williston Basin/Bakken Shale located in Divide County, North Dakota and (ii) operated natural gas properties in Kentucky. Through our substantial equity investment in Eureka Hunter Holdings, LLC (“Eureka Hunter Holdings”), of which Eureka Hunter Pipeline, LLC (“Eureka Hunter Pipeline”) is a wholly-owned subsidiary, we are also involved in midstream operations, primarily in West Virginia and Ohio. Our wholly-owned subsidiary, Alpha Hunter Drilling, LLC (“Alpha Hunter”), currently owns and operates six portable, trailer mounted drilling rigs, which are used for both our Appalachian Basin drilling operations and to provide drilling services to third parties.
Our principal business strategy is to (i) focus on high return projects in the liquids rich Marcellus Shale and the dry gas and liquids rich Utica Shale in West Virginia and Ohio, (ii) utilize our expertise in unconventional resource plays to improve our rates of return, (iii) focus on properties with operating control, (iv) continue development of the Eureka Hunter Pipeline gathering system in West Virginia and Ohio, (v) selectively monetize assets at opportune times and attractive prices to the extent such assets are deemed non-core assets or we deem the disposition thereof desirable in furtherance of our principal business strategy and (vi) reduce costs in the current commodity price environment. In order to execute on our strategy, we have taken the following steps to increase our liquidity and reduce costs:
| i. | Based on our decision to focus on the exploration, development and production of natural gas and natural gas liquids in the Appalachian Basin of West Virginia and Ohio, during 2014, we divested substantially all of our remaining oil and gas properties in the Eagle Ford Shale in Atascosa County, Texas, all of our oil and gas properties in Alberta and Saskatchewan, Canada and certain of our non-operated oil and gas properties in Divide County, North Dakota for aggregate gross proceeds of approximately $212 million (see “-Our Significant Recent Developments”); |
| ii. | We have approved a substantially reduced fiscal year 2015 upstream capital expenditure budget, compared with our budget for fiscal year 2014. The reduction in our upstream capital expenditure budget is primarily due to the current commodity price environment. Our upstream capital expenditure budget for fiscal year 2015 is $100 million, but we intend to reevaluate this budget on a quarterly basis. Our upstream capital expenditure budget may be reduced or increased depending on realized prices for our natural gas, natural gas liquids and oil, investment opportunities, continued effective implementation of cost reduction initiatives, including reduction of oil and gas field service costs, and funding allocations. We have allocated approximately $70 million of our upstream capital expenditure budget to our Marcellus Shale and Utica Shale exploration and development drilling program in West Virginia and Ohio, approximately $10 million to our properties in the Williston Basin/Bakken Shale in North Dakota (substantially all of which are non-operated) and approximately $20 million for additional leasehold acreage acquisitions in the Marcellus Shale and Utica Shale plays. We expect this Appalachian Basin-focused upstream capital expenditure program to further drive our production volumes and enable us to achieve a projected 2015 average daily production volume of approximately 29,000 to 33,000 Boe/d; |
| iii. | In late 2014, we restructured our investment in Eureka Hunter Holdings, which provided us with greater flexibility in the funding of our midstream capital expenditure requirements. This restructuring resulted from the replacement of our then existing principal co-investor in Eureka Hunter Holdings with MSIP II Buffalo Holdings LLC, an affiliate of Morgan Stanley Infrastructure, Inc. (“MSI”). We expect that the 2015 capital expenditure requirements of Eureka Hunter Holdings will be funded primarily by cash flows from its midstream operations, borrowings under the existing Eureka Hunter Pipeline revolving credit facility and capital contributions provided by MSI pursuant to the funding arrangements agreed to between us and MSI (see “-Our Significant Recent Developments-Midstream Operations-Eureka Hunter Holdings”); |
| iv. | We entered into a Fourth Amended and Restated Credit Agreement and a Second Lien Term Loan Agreement in October 2014. The amended credit agreement provides for an asset-based, senior secured revolving credit facility with an initial borrowing base of $50 million, which is subject to periodic borrowing base redeterminations based on the amount of our estimated proved reserves. Additionally, we obtained a $340 million term loan under our second |
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lien term loan facility, which is not subject to any borrowing base determinations. A portion of the proceeds of the term loan were used to pay off existing borrowings under the revolving credit facility, and the size of the revolving credit facility was substantially reduced. By obtaining the second lien term loan and reducing the size of our revolving credit facility, we dramatically reduced our exposure to decreases in borrowing availability resulting from borrowing base redeterminations under our “borrowing base” lending arrangement based on declines in commodity prices; and
| v. | Due to the various sales of all of our Canadian assets and a large portion of our Bakken Shale assets located in North Dakota, and the increasing focus on our natural gas and natural gas liquids exploration, development and production activities in West Virginia and Ohio, and in an effort to reduce general and administrative costs, we closed our Denver, Colorado and Calgary, Alberta offices effective January 31, 2015, and all our employees at those two offices were separated from employment. We also moved the responsibilities of the former personnel at those now-closed offices to existing personnel at our Houston and Grapevine, Texas offices. We anticipate that the closure of these offices and consolidation of responsibilities will result in reductions to general and administrative expenses of approximately $2.5 million annually. We have also reduced our reliance on outside consultants and are seeking to obtain better pricing and other terms from many of our suppliers of oil and gas field products and services. |
As a result of recent divestitures throughout the past year, we are now strategically focused on our Marcellus Shale and Utica Shale plays in the Appalachian Basin in West Virginia and Ohio.
Appalachian Basin / Marcellus Shale and Utica Shale / West Virginia and Ohio
Appalachian Basin. Our Appalachian Basin drilling operations are focused on development in the natural gas and natural gas 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 asset base in this region through additional acquisitions, leasing activities, joint ventures and significant drilling efforts.
Marcellus Shale. As of January 31, 2015, we had a total of approximately 79,933 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, 2015, approximately 75% of our mineral leases in the Marcellus Shale area were held by production.
As of January 31, 2015, we had (i) 55 horizontal wells (44.4 net) producing in the Marcellus Shale (including non-operated wells) and (ii) five horizontal wells (five net) drilled in the play, which have been topholed. As of January 31, 2015, our five most recently completed Company operated horizontal wells targeting the Marcellus Shale generated an average of approximately 16,830 Mcfe/d (13,433 Mcfe/d wet gas and 3,397 Mcfe/d condensate) and 7,786 Mcfe/d (5,509 Mcfe/d wet gas and 2,277 Mcfe/d condensate) average IP-24 hour and IP-30 day rates, respectively, measured on a well by well basis, eliminating rate restrictions.
Utica Shale. As of January 31, 2015, we had a total of approximately 128,095 net leasehold acres prospective for the Utica Shale. Approximately 92,727 of the net acres are located in Ohio (a portion of which acreage overlaps our Marcellus Shale acreage), and approximately 35,368 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 40,000 of our Utica Shale net acres are located in the wet gas window of the play. Approximately 53% of our acreage in the Utica Shale is held by shallow production.
As of January 31, 2015, we had (i) two horizontal wells (two net) awaiting completion in the Utica Shale, and (ii) three horizontal wells (three net) in the play drilled to their deep intermediate casing point at approximately 10,600 feet. The Company’s 100% owned Stewart Winland 1300U (Utica well) in Tyler County West Virginia tested at a peak rate of 46.5 MMcf of natural gas per day (~7,750 Boe/d) on an adjustable rate choke with 7,810 psi FCP. The Stewart Winland 1300U well was drilled and cased to true vertical depth of 10,825 feet with a 5,289 foot horizontal lateral, and successfully fraced with 22 stages. We have also drilled and completed the Stalder #3UH (Utica Well) in Monroe County Ohio, our first dry gas well in the Utica Shale in Ohio, to a true vertical depth of 10,653 feet with a 5,050 foot horizontal lateral, which was successfully fraced with 20 stages. Initial flow tests on the Stalder #3UH well tested at a peak rate of 32.5 MMcf of natural gas per day (~ 5,400 Boe/d) on an adjustable rate choke with 4,300 psi FCP.
We intend to drill and/or complete a total of approximately 14 gross (14 net) horizontal wells in the Marcellus Shale and Utica Shale in 2015. 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 overall drilling and completion costs.
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Southern Appalachian Basin
Our southern Appalachian Basin properties are owned by our wholly-owned subsidiary, Magnum Hunter Production, Inc. (“MHP”). As of January 31, 2015, these properties included approximately 208,309 net leasehold acres, primarily in Kentucky. Our primary production from these properties consists of natural gas and natural gas liquids and comes from the Devonian Shale formation and the Mississippian Weir sandstone. As of January 31, 2015, we had 1,421 wells (600.6 net) producing in the southern Appalachian Basin.
Williston Basin / Bakken Shale / North Dakota
We initially entered the Williston Basin/Bakken Shale through an asset acquisition in May 2011 and subsequently expanded our asset base in the Williston Basin/Bakken Shale through additional acquisitions, leasing activities, joint ventures and significant drilling efforts. During the past couple of years we sold certain non-operated oil and gas properties in Divide County, North Dakota and all of our oil and gas properties in Alberta and Saskatchewan, Canada. See “-Our Significant Recent Developments-Divestitures.”
As of January 31, 2015, we had a total of approximately 65,650 net leasehold acres (substantially all of which are non-operated) prospective for the Bakken/Three Forks Sanish formations in Divide County, North Dakota, which we refer to as our Williston Basin Properties. As of January 31, 2015, we had 174 wells (58.6 net) producing on our Williston Basin Properties.
Midstream Operations
We are involved in midstream operations through our substantial equity investment in Eureka Hunter Holdings. Eureka Hunter Pipeline owns and operates a gas gathering system in West Virginia and Ohio, referred to as the Eureka Hunter Gas Gathering System. Eureka Hunter Holdings also provides natural gas treating and processing service solutions to third party producers and midstream companies through its wholly owned subsidiary, TransTex Hunter, LLC (“TransTex”). We expect Eureka Hunter Holdings will obtain funding for its midstream operations during 2015 primarily from cash flow from its midstream operations, borrowings under the existing Eureka Hunter Pipeline revolving credit facility and capital contributions from MSI. See “-Our Significant Recent Developments-New Partnership with Morgan Stanley Infrastructure.”
Our substantial equity investment in Eureka Hunter Holdings is a strategic asset for the development and delineation of our acreage positions in both the Utica Shale and Marcellus Shale plays. The continuing commercial development of the Eureka Hunter Gas Gathering System supports 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 Eureka Hunter Gas Gathering System is being constructed primarily out of 20-inch and 16-inch high-pressure steel pipe with an estimated 2.1 Bcf/d of initial throughput capacity. As of January 31, 2015, Eureka Hunter Pipeline had completed the construction of over 160 miles of pipeline as part of the Eureka Hunter Gas Gathering System.
In January 2015, the Eureka Hunter Gas Gathering System flowed an average of approximately 365,000 MMBtu of natural gas per day. During January 2015, the Eureka Hunter Gas Gathering System gathered a total of 10 Bcf of natural gas (with a peak day of approximately 406,300 MMBtu of gathered natural gas) delivered to various interconnects on the system. We expect that the Eureka Hunter Gas Gathering System will gather substantial additional natural gas volumes from us and third party producers throughout 2015. We expect that the development of 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 plays.
Oil Field Services Operations
Our oil field services operations, which are conducted through Alpha Hunter, 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. As of January 31, 2015, our operating fleet consisted of five Schramm T200XD drilling rigs and one Schramm T500XD drilling rig. The Schramm T500XD robotic walking drilling rig can also drill the horizontal sections of wells in the Marcellus Shale and Utica Shale plays and was designed especially for pad drilling with its unique footprint and capability to walk and rotate without being dismantled.
As of January 31, 2015, (i) four of our Schramm T200XD drilling rigs were under term contracts to a large producer in the Appalachian Basin area for the top-hole drilling of multiple wells through December 2015; (ii) one of our Schramm T200XD drilling rigs will be used by us for our top-hole drilling program during 2015; and (iii) our Schramm T500XD drilling rig was under contract to one
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of our subsidiaries for our Marcellus Shale and Utica Shale drilling program. As a result of our decision to reduce capital spending in 2015, and in expectation that the decline in overall commodity prices will soon drive down general oil and gas field service costs, we have temporarily idled the Schramm T500XD drilling rig, and we expect the rig to remain idle for up to another 30 to 60 days.
Summary of Proved Reserves, Production and Acreage
The natural gas and oil reserves and production information provided below includes reserves and production associated with our southern Appalachian Basin and Williston Basin properties.
| i. | As of December 31, 2014, we had approximately 83.8 MMBoe of estimated proved reserves, of which approximately 87% was natural gas and natural gas liquids and approximately 66% was classified as proved developed producing reserves. By comparison, as of December 31, 2013, after adjusting for properties sold during 2014, our estimated proved reserves were approximately 67.3 MMBoe, of which approximately 75% was natural gas and natural gas liquids and approximately 53% was classified as proved developed producing reserves. Our estimated proved reserves, on a Boe basis, at year-end 2014 increased 25% from year-end 2013 (as adjusted). |
| ii. | As of December 31, 2014, we had proved reserves with a PV-10 value of $909.3 million. This compares with proved reserves with a PV-10 value of $745.8 million as of December 31, 2013, after adjusting for properties sold during 2014. The PV-10 value of our estimated proved reserves at year-end 2014 increased approximately 22% from year-end 2013, after adjusting for properties sold during 2014. PV-10 values are typically different from the standardized measure of proved reserves due to the inclusion in the standardized measure of estimated future income taxes. However, as a result of our net operating loss carryforwards of $710 million and other future expected tax deductions, the standardized measure of our proved reserves at December 31, 2014 of $909.3 million was the same as our PV-10 value. See “—Non-GAAP Measures; Reconciliations” for a definition of PV-10 and a reconciliation of our PV-10 value to our standardized measure. |
| iii. | Our average daily production volumes for the year ended December 31, 2014 were 16,879 Boe/d, which represented an increase of 43.9% from the year ended December 31, 2013. Our average daily production volumes for the quarter ended December 31, 2014, were approximately 17,178 Boe/d. |
| iv. | As of January 31, 2015, we had approximately 79,933 net leasehold acres in the Marcellus Shale and approximately 128,095 net leasehold acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage). |
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Reserve Summary
| At December 31, 2014 | ||||||||||||||||
Proved Reserves(1) | PV-10 (2)(3) | % Proved Developed | % Natural Gas / NGLs | |||||||||||||
| Productive Wells | ||||||||||||||||
Area | (MMBoe) | (in millions) | Gross | Net | ||||||||||||
Appalachian Basin (4) | 75.9 | $ | 765.8 | 71% | 95% | 3,403 | 2,507.3 | |||||||||
| Williston Basin | 7.9 | $ | 143.5 | 72% | 14% | 174 | 58.6 | |||||||||
Other (5) | — | — | — | — | 3 | 1.2 | ||||||||||
| Total at December 31, 2014 | 83.8 | $ | 909.3 | 71% | 87% | 3,580 | 2,567.1 | |||||||||
(1) | 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. |
(2) | In accordance with SEC requirements, estimated future production is priced based on 12-month un-weighted arithmetic average of the first-day-of-the-month price for the period January through December 2014, using $94.99 per barrel of oil and $4.31 per MMBtu of natural gas and adjusted by lease for transportation fees and regional price differentials. The use of SEC pricing rules may not be indicative of actual prices realized by the Company in the future. |
(3) | The standardized measure of our proved reserves at December 31, 2014 was $909.3 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. |
(4) | Primarily Marcellus Shale and Utica Shale properties, but also includes reserves and production associated with our southern Appalachian Basin properties owned by MHP. |
(5) | Pertains to certain miscellaneous properties in Texas and Louisiana. |
Our Business Strategy
Key elements of our business strategy include:
Focus on Liquids Rich Marcellus and Dry Gas and Liquids Rich Utica Reserves
As a result of our divestitures throughout the past two years, we are now strategically focused on the further development and exploitation of our asset base in the Marcellus Shale and the Utica Shale in West Virginia and Ohio. As of January 31, 2015, we had a total of approximately 230,032 gross acres (208,028 net acres) in our Marcellus Shale and Utica Shale asset base.
We intend to focus our development and acquisition efforts primarily on our highest return projects, including liquids rich gas (greater than 1,250 Btu) in the Marcellus Shale in West Virginia and Ohio and the dry gas and liquids rich area of the Utica Shale in southeastern Ohio and western West Virginia. We have allocated a significant portion of our 2015 upstream capital expenditure budget to these high return projects in the Marcellus Shale and Utica Shale plays. We will continue to consider strategic “bolt-on” acquisitions, primarily leasehold acreage, in our Marcellus Shale and Utica Shale asset base, on a very selective and value accretive basis, if such acquisitions have the potential to enhance long-term asset values and realize economies of scale.
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 available and, to the extent appropriate and cost-effective, applies them to our leasehold acreage and reserves 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 Company operated unconventional resource plays have improved significantly, resulting in substantially better initial production rates, or IP rates, estimated ultimate recoveries, and, ultimately, rates of return on capital deployed. Additionally, our focus on development and exploitation of our leasehold acreage provides the opportunity to capture economies of scale, such as pad drilling, and to reduce rig mobilization time and cost.
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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 through our past knowledge and experience. During the past five years, we have significantly increased the number of wells that we operate and control. As of January 31, 2015, we were operating approximately 83% of our producing wells. As of January 31, 2015, we were the operator on leasehold acreage accounting for approximately 79% of our year-end 2014 proved reserves. Approximately 85% to 90% of our upstream capital expenditure budget for 2015 relates specifically to our operated properties located in the Marcellus Shale and Utica Shale plays.
Continued Development of the Eureka Hunter Gas Gathering System
Eureka Hunter Pipeline is continuing the commercial development and build-out of the Eureka Hunter Gas Gathering System in West Virginia and Ohio. We expect this system expansion to enable us to continue to develop our substantial natural gas and natural gas liquids resources in our Marcellus Shale and Utica Shale acreage positions, as well as provide Eureka Hunter Pipeline the opportunity for substantial cash flow from the increasing gathering needs of third party producers in these regions.
Selected Monetization of Assets
We are now focused on our asset base in the Marcellus Shale and Utica Shale in West Virginia and Ohio. During the past two years we have monetized assets no longer considered core through divestitures.
In 2013, we sold (i) our core Eagle Ford Shale properties for a contract purchase price of $401 million of cash and stock; (ii) certain non-core properties in Burke County, North Dakota for a contract purchase price of $32.5 million in cash; and (iii) certain non-core properties in various counties of North Dakota for a contract purchase price of $45 million in cash.
In 2014 we continued divesting non-core assets. In 2014, we sold (i) substantially all of our remaining Eagle Ford Shale oil and gas properties in Atascosa County, Texas in January 2014 for a contract purchase price of $24.9 million in cash and stock; (ii) certain oil and gas properties in Alberta, Canada in April 2014 for a contract purchase price of CAD $9.5 million (approximately U.S. $8.7 million); (iii) all of our ownership interest in our Canadian subsidiary, Williston Hunter Canada, Inc. (“WHI Canada”) in May 2014 for a contract purchase price of CAD $75.0 million (approximately U.S. $68.8 million), whose assets included oil and gas properties in the Tableland Field in Saskatchewan, Canada; (iv) certain non-operated oil and gas properties in Divide County, North Dakota in September 2014 for a contract purchase price of $23.5 million in cash; and (v) certain non-operated oil and gas properties in Divide County, North Dakota in October 2014 for a contract purchase price of $84.8 million in cash. During 2014, these transactions resulted in aggregate gross proceeds in excess of $210.7 million in cash and stock, before customary purchase price adjustments.
We expect to continue to selectively monetize certain of our properties and interests if attractive opportunities for further divestitures are presented, to the extent such assets are deemed non-core assets or we deem the disposition thereof desirable in furtherance of our principal business strategy as it relates to our goals for an attractive rate of return on capital deployed.
Continuing Cost Reduction Initiatives
We continue to focus on cost reductions within our organization, which has included the closing of our offices in Calgary, Alberta and Denver, Colorado, and the separation from employment of all employees at those offices, in late January 2015. We anticipate that the closure of these offices will result in reductions to general and administrative expenses of approximately $2.5 million annually. We have also moved the responsibilities of the former personnel at those now-closed offices to existing personnel at the Company’s Houston and Grapevine, Texas offices.
We have also reduced our reliance on outside consultants and are seeking to obtain better pricing and other terms from our suppliers of oil and gas field products and services. We anticipate obtaining overall oil and gas field product and service cost reductions ranging from 10% to 40%, dependent on the type of product or service being utilized. We believe these reductions in cost will allow us to execute our planned 2015 drilling program in the Appalachian Basin to continue the development of our substantial acreage positions in this region.
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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 Reserves
We believe our portfolio of properties and drilling opportunities in our natural gas and natural gas liquids operating regions, combined with timely development and potential additional acquisitions of properties in these regions, present us with highly economic growth opportunities even in a lower commodity price environment. As of December 31, 2014, approximately 87.4% and 88.3% of our proved reserves and proved developed producing reserves, respectively, were natural gas and natural gas liquids. As of December 31, 2014, we held ownership interests in (i) approximately 1,982 gross (1,906.7 net) wells in West Virginia and Ohio, (ii) approximately 174 gross (58.6 net) wells in North Dakota and (iii) approximately 1,421 gross (600.6 net) wells in the southern Appalachian Basin.
Improving Results in Natural Gas and Natural Gas Liquids Resource Areas
As a result of our improved drilling and completion techniques, our IP rates have steadily increased over the last two years. As of January 31, 2015, our five most recently completed Company-operated horizontal wells targeting the Marcellus Shale generated an average of approximately 16,830 Mcfe/d (13,433 Mcfe/d wet gas and 3,397 Mcfe/d condensate) and 7,786 Mcfe/d (5,509 Mcfe/d wet gas and 2,277 Mcfe/d condensate) average IP-24 hour and IP-30 day rates, respectively, measured on a well by well basis, eliminating rate restrictions.
Our 100% owned Stewart Winland 1300U (Utica well) tested at a peak rate of 46.5 MMcf of natural gas per day (~7,750 Boe/d) on an adjustable rate choke with 7,810 psi FCP. The Stewart Winland 1300U well was drilled and cased to true vertical depth of 10,825 feet with a 5,289 foot horizontal lateral, and successfully fraced with 22 stages. We have also drilled and completed the Stalder #3UH (Utica well), our first dry gas well in the Utica Shale in Ohio, to a true vertical depth of 10,653 feet with a 5,050 foot horizontal lateral, which was successfully fraced with 20 stages. Initial flow tests on the Stalder #3UH well tested at a peak rate of 32.5 MMcf of natural gas per day (~ 5,400 Boe/d) on an adjustable rate choke with 4,300 psi FCP.
Operational Control over Significant Portion of Assets
We operate a significant portion of our assets (approximately 83% of our producing wells as of January 31, 2015). Consequently, we have substantial control over the timing, allocation and amount of a significant portion of our planned 2015 upstream 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 core operated areas as we execute on our strategy.
Access to the Eureka Hunter Gas Gathering System
Our substantial equity investment in Eureka Hunter Holdings is a strategic asset for the development and delineation of our acreage position in both the Utica Shale and Marcellus Shale plays. The continuing commercial development of the Eureka Hunter Gas Gathering System supports the development of our existing and anticipated future Marcellus Shale and Utica Shale acreage positions
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.
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Our Significant Recent Developments
Divestitures
Canadian Assets
On April 10, 2014, we closed on the sale of certain non-core, operated working interests in oil and gas properties located in Alberta, Canada to BDJ Energy Inc., an Alberta corporation. The sales price for the transaction, which had an effective date of January 1, 2014, was CAD $9.5 million (approximately US $8.7 million) in cash, subject to customary purchase price adjustments. At closing, these properties consisted of operated working interests in approximately 1,910 gross (961 net) leasehold acres and three producing wells.
On May 12, 2014, we closed on the sale of our 100% equity ownership interest in WHI Canada to Steppe Resources Inc., an Alberta corporation. The sales price for the transaction, which had an effective date of March 1, 2014, was CAD $75.0 million (approximately U.S. $68.8 million) in cash, subject to customary purchase price adjustments. At closing, WHI Canada's assets accounted for approximately 630 Boe/d, net to the ownership interest sold to the buyer, consisted primarily of operated working interests in oil and gas properties located in the Tableland Field in Saskatchewan, Canada, and included 52,520 gross (49,470 net) leasehold acres with 84 gross wells.
North Dakota Assets
On September 30, 2014, we closed on the sale of certain non-operated working interests in oil and gas properties located in Divide County, North Dakota to a privately held company affiliated with Formation Energy L.P. The sales price for the transaction, which had an effective date of April 1, 2014, was $23.5 million in cash, subject to customary purchase price adjustments. At closing, these properties accounted for approximately 170 Boe/d , net to the ownership interest sold to the buyer, and consisted of a non-operated working interest in approximately 34,600 gross (2,852 net) leasehold acres.
On October 15, 2014, we closed on the sale of certain non-operated working interests in oil and gas properties located in Divide County, North Dakota to an independent exploration and production company. The sales price for the transaction, which had an effective date of August 1, 2014, was $84.8 million in cash, subject to customary purchase price adjustments. At closing, these properties accounted for approximately 720 Boe/d, net to the ownership interest sold to the buyer, and consisted of a non-operated working interest in approximately 105,661 gross (12,500 net) leasehold acres.
Eagle Ford Shale Assets
On January 28, 2014, we closed on the sale of certain non-core, operated and non-operated working interests in oil and gas properties located in Atascosa County, 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 sales price for the transaction, which had an effective date of December 1, 2013, was $15.5 million in cash, after customary purchase price adjustments, and 65,650,000 ordinary shares of NSE, with an initial fair value of approximately $9.4 million ($2.5 million as of December 31, 2014). As of December 1, 2013, these properties produced an aggregate of approximately 300 Boe/d (gross) from working interests in five horizontal wells, four of which we operated, and consisted of approximately 5,182 net leasehold acres. As a result of the sale, we own approximately 17% of the total outstanding common shares of NSE.
In connection with the closing of the sale, Shale Hunter, LLC, our wholly-owned subsidiary (“Shale Hunter”), entered into a transition services agreement with NSE Texas. The transition services agreement provides that, during a specified transition period, Shale Hunter will provide NSE Texas with certain transitional services relating to the properties we sold to NSE Texas, for a monthly fee of $50,000.
West Virginia Assets
On November 3, 2014, we closed on the sale of certain non-core, operating working interests in oil and gas properties located primarily in Calhoun and Roane Counties, West Virginia. The sales price for the transaction, which had an effective date of August 1, 2014, was $1.2 million in cash, subject to customary purchase price adjustments.
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Asset Acquisitions
Ormet Asset Purchase Agreement
In June 2014, we entered into an agreement to acquire mineral interests from the Ormet Corporation in approximately 1,700 net acres, consisting of 1,375 net acres in Monroe County, Ohio and 325 net acres in Wetzel County, West Virginia. Prior to the execution of this agreement, the Company held leasehold interests in a portion of the subject acreage, which leasehold interests covered only the Marcellus zone and were subject to a 12.5% royalty on production to the Ormet Corporation. On July 24, 2014, the Company closed on the transaction for total cash consideration of approximately $22.7 million. Through this asset purchase, we acquired the mineral interests, including any royalty interests, in the underlying acreage, giving the Company 100% ownership of and rights to oil, natural gas, and other minerals located in or under and that may be produced from the property, at any depth. Following this purchase, we allocated approximately $11.1 million of the purchase price to proved oil and gas property costs and approximately $11.6 million of the purchase price to unproved oil and gas property costs.
MNW Lease Acquisitions
In August 2013, we entered into an Asset Purchase Agreement (the “MNW APA”) with MNW Energy, LLC (“MNW”) pursuant to which MNW agreed to sell to us certain oil and gas leases and sub-leases covering up to 32,000 net leasehold acres located in Washington, Noble and Monroe Counties, Ohio. The acquisitions of leasehold acreage under the MNW APA have occurred over a period of time, in staggered closings, subject to satisfaction of certain closing conditions, including our right to receive satisfactory title to the leasehold acreage.
During the year ended December 31, 2014, we purchased a total of 16,456 net leasehold acres from MNW, in multiple closings, for total consideration of $67.3 million.
On January 14, 2015, we purchased approximately 2,665 net leasehold acres located in Washington County, Ohio from MNW, for an aggregate purchase price of approximately $12.0 million (an average cost of approximately $4,500 per net leasehold acre).
As of January 31, 2015, we had acquired a total of approximately 25,044 net leasehold acres from MNW, or approximately 78.3% of the 32,000 total net leasehold acres originally subject to purchase under the MNW APA. We believe that MNW may not be able to provide us with satisfactory title to all of the remaining net leasehold acres subject to purchase under the MNW APA, and therefore we anticipate that not all of the remaining net leasehold acres will ultimately be acquired by us.
Reclassification of Southern Appalachian Basin Properties
In September 2013, we adopted a plan to divest all of our interests in MHP, whose properties are located in the southern Appalachian Basin, primarily in Kentucky and Tennessee. During the first, second and into the third quarters of 2014, we were engaged in discussions regarding the sale of MHP with a number of prospective purchasers, and we actively marketed the sale of MHP utilizing the services of an investment bank. However, in late September 2014, we withdrew our plan to divest MHP in order to further evaluate potential upside opportunities underlying the acreage in which MHP has leasehold rights or mineral interest rights held in fee. As a result, on September 30, 2014, we had ceased all marketing efforts regarding MHP, and consequently MHP no longer met the criteria for classification as a discontinued operation as of September 30, 2014.
As of September 30, 2014, we measured the carrying value of MHP’s individual long-lived assets previously classified as held for sale at the lesser of (i) their carrying amount before each asset was classified as held for sale, adjusted for any depreciation or amortization expense that would have been recognized had it been continuously classified as held and used, and (ii) their fair value at the date of the subsequent decision not to sell. As a result of this assessment, we recorded additional impairments of $1.9 million to the carrying amount of MHP’s unproved oil and natural gas properties and $17.0 million to the carrying amount of MHP’s proved oil and natural gas properties, which were recorded in exploration expense and impairment of proved oil and gas properties, respectively. In addition, we recorded depreciation expense of $1.7 million related to long-lived assets, whose fair value exceeded book value, adjusted for depreciation expense, as of September 30, 2014. In total, we recorded approximately $67.6 million of impairment related to MHP from September 30, 2013 through December 31, 2014.
We reclassified the results of MHP’s operations from discontinued operations to continuing operations for all periods presented in our consolidated financial statements, selected financial data, and management’s discussion and analysis of financial condition and results of operations, and MHP’s assets and liabilities have been reclassified out of assets and liabilities held for sale and included with our other assets held and used as of December 31, 2014.
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Midstream Operations
New Partnership with Morgan Stanley Infrastructure
On September 16, 2014, we entered into an agreement (the “Transaction Agreement”) with MSI and Eureka Hunter Holdings relating to a separate purchase agreement between MSI and Ridgeline Midstream Holdings, LLC (“Ridgeline”), an affiliate of ArcLight Capital Partners, LLC, providing for the purchase by MSI of all convertible preferred and common equity interests in Eureka Hunter Holdings owned by Ridgeline.
The Transaction Agreement provided for a new amended and restated limited liability company agreement for Eureka Hunter Holdings (the “New LLC Agreement”) to be entered into by the Company, MSI, and the minority interest members of Eureka Hunter Holdings contemporaneously with the closing of MSI's purchase of Ridgeline's equity interests in Eureka Hunter Holdings, which occurred on October 3, 2014. In connection with the closing and the execution and delivery of the New LLC Agreement, all the convertible preferred equity interests and common equity interests in Eureka Hunter Holdings acquired by MSI from Ridgeline (approximately 41% of the total equity interests in Eureka Hunter Holdings) were converted into a new class of equity interests in Eureka Hunter Holdings (“Series A-2 Units”). Our common equity interests in Eureka Hunter Holdings held by us on that date were also converted into a new class of equity interests in Eureka Hunter Holdings (“Series A-1 Units”). The Series A-2 Units have preferential distribution rights over the Series A-1 Units under certain circumstances. The preference on distribution rights provides the Series A-2 Unit members with downside protection through disproportionate distributions if certain specified internal rates of return are not achieved. Once the specified internal rates of return are achieved, however, then the Series A-1 Unit members will benefit from disproportionately larger distributions.
Additionally, pursuant to the Transaction Agreement and a separate letter agreement (the “Letter Agreement”) entered into among us, Eureka Hunter Holdings and MSI in November 2014, (i) the parties agreed to adjust our capital account downward by 1,227,182 Series A-1 Units in Eureka Hunter Holdings to take into account certain capital expenditures incurred by Eureka Hunter Pipeline in connection with certain of Eureka Hunter Pipeline’s fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects; (ii) on November 20, 2014, we made a $20 million cash capital contribution to Eureka Hunter Holdings in exchange for additional Series A-1 Units; (iii) on December 18, 2014, MSI made a $10 million cash capital contribution to Eureka Hunter Holdings in exchange for additional Series A-2 Units; and (iv) on December 18, 2014, MSI purchased from us an additional 1,505,374 Series A-1 Units in Eureka Hunter Holdings for $55 million in cash, which additional Series A-1 Units were immediately converted into an identical number of Series A-2 Units. Under the terms of the Letter Agreement, we also agreed to make a $13.3 million capital contribution in cash to Eureka Hunter Holdings on or before March 31, 2015 in exchange for additional Series A-1 Units. However, we and MSI are currently engaged in discussions regarding Eureka Hunter Holdings’ 2015 capital expenditure budget, including the amount, timing and expected funding of the various anticipated capital expenditures. We anticipate that, as a result of these discussions, the parties will determine the priority, timing and (to the extent not funded by operating cash flows or borrowings) allocation between the parties of the funding of the anticipated expenditures that will most effectively serve the 2015 project plans of Eureka Hunter Pipeline. We also anticipate that, as part of these determinations, MSI will make the $13.3 million cash capital contribution referred to above in exchange for additional Series A-2 Units under the terms of the carried interest provisions described below. See Item 7 “Management's Discussion and Analysis of Financial Condition and Results of Operations” for a description of our revolving credit facility, including a description of the restrictions under that facility on our ability to make investments in Eureka Hunter Holdings.
The Transaction Agreement and the Letter Agreement further provide that, if the members of Eureka Hunter Holdings approve a capital contribution for certain capital expenditures, and in connection therewith we validly exercise our right to not make our portion of such capital contribution, MSI will fund an amount in excess of its pro rata share of such capital contribution, which excess amount will equal the capital contribution not made by us. We refer to this as the “carried interest” provided by MSI. In such case, however, we have the right to make up our portion of such capital contribution, not to exceed $60 million in the aggregate, for a period of one year following the date of funding of the carried interest by MSI or until an MLP IPO (as defined in the New LLC Agreement), if earlier.
We currently own approximately 48.60% and MSI currently owns approximately 49.84% of the Class A Common Units in Eureka Hunter Holdings. If MSI makes the $13.3 million capital contribution referred to above, MSI’s equity interest in Eureka Hunter Holdings will increase and our equity interest in Eureka Hunter Holdings will decrease based on the number of new Series A-2 Units acquired by MSI (assuming no other capital contributions by the parties).
Pursuant to the New LLC Agreement and the Letter Agreement, as a result of MSI’s purchase of Series A-1 Units from us in December 2014, the board of managers of Eureka Hunter Holdings was expanded from five to six managers and MSI appointed
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an MSI representative as the sixth manager, so that currently the board of managers of Eureka Hunter Holdings consists of three representatives of Magnum Hunter and three representatives of MSI.
Prior to the expansion of the board of managers, the Company had majority representation on the board of managers of Eureka Hunter Holdings.
As a result of the reconstitution of the board of managers of Eureka Hunter Holdings as well as certain substantive participation rights granted to MSI in the New LLC Agreement, the Company determined it no longer held a controlling financial interest in Eureka Hunter Holdings and, therefore, the Company deconsolidated Eureka Hunter Holdings from the Company's consolidated financial statements effective December 18, 2014 and recognized a gain upon deconsolidation of $509.6 million. Our retained equity interest in Eureka Hunter Holdings is accounted for using the equity method of accounting following deconsolidation.
Eureka Hunter Pipeline Credit Facility
In March 2014, Eureka Hunter Pipeline entered into a new secured revolving credit facility with a new group of lenders , which had an aggregate commitment of $117.0 million, with a potential to increase the aggregate commitment up to $150.0 million. Proceeds from the initial borrowing under the Eureka Hunter Pipeline credit facility were used to extinguish Eureka Hunter Pipeline’s two credit agreements with SunTrust Bank and Pennant Park. Eureka Hunter Pipeline incurred a prepayment penalty of $2.2 million in connection with the early termination of the Pennant Park credit agreement, and wrote off approximately $2.7 million in unamortized deferred finance costs associated with those credit agreements.
On November 19, 2014, Eureka Hunter Pipeline entered into an amendment to the new credit facility that resulted in an increase in the aggregate loan commitments available to Eureka Hunter Pipeline thereunder from an aggregate principal amount of $117 million to $225 million.
As of January 31, 2015, Eureka Hunter Pipeline had $130 million of borrowings outstanding under the credit facility. As discussed above, on December 18, 2014, our investment in Eureka Hunter Holdings, the parent of Eureka Hunter Pipeline, changed from a controlling financial interest in a consolidated subsidiary to an equity method investment in Eureka Hunter Holdings. As a result, the outstanding balance under the Eureka Hunter Pipeline credit facility has been deconsolidated as of December 18, 2014.
Magnum Hunter Credit Facilities
Fourth Amended and Restated Credit Agreement and Second Lien Term Loan
On October 22, 2014, we entered into (i) a Fourth Amended and Restated Credit Agreement, by and among the Company, as borrower, Bank of Montreal, as administrative agent, the lenders party thereto and the agents party thereto, and (ii) a Second Lien Credit Agreement by and among the Company, as borrower, Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent, the lenders party thereto and the agents party thereto. These transactions allowed us to restructure certain financial covenants and reduce our reliance on “borrowing base” lending arrangements, and significantly increased our available liquidity.
The amended and restated credit agreement provides for an asset-based, senior secured revolving credit facility maturing October 22, 2018 with an initial borrowing base of $50 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 $250 million.
The second lien credit agreement provides for a $340 million term loan facility secured by, subject to certain exceptions, a second lien on substantially all of the assets (excluding undeveloped leasehold acreage) of the Company and our restricted subsidiaries. The entire $340 million second lien term loan was drawn on October 22, 2014. We used the proceeds of the second lien term loan to repay amounts outstanding under our revolving credit facility, to pay transaction expenses related to the new credit facilities, to fund operations in the Marcellus and Utica Shale plays in West Virginia and Ohio and for working capital and general corporate purposes. Amounts borrowed under the second lien term loan that are repaid or prepaid may not be reborrowed. The second lien term loan has a maturity date of October 22, 2019 and amortizes (beginning December 31, 2014) in equal quarterly installments of principal in an aggregate annual amount equal to 1.00% of the original principal amount of the second lien term loan (equivalent to approximately $850,000 per quarter) .
At December 31, 2014, we would not have been in compliance with our current ratio financial covenant under our revolving credit facility, which required that the Company maintain a current ratio of not less than 1.0 to 1.0 as of that date. We have obtained a waiver from our lenders, effective December 31, 2014, of the current ratio covenant requirement for the December 31, 2014
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compliance period, and have entered into an amendment with our lenders that, among other things, lowers the current ratio requirement to 0.75 to 1.0 for the fiscal quarter ending March 31, 2015. The current ratio requirement increases to 1.0 to 1.0 for the fiscal quarter ending June 30, 2015 and each fiscal quarter ending thereafter. The amendment also modified the leverage ratio requirement to remain at not more than 2.5x beginning with the December 31, 2014 compliance period and through the December 31, 2015 compliance period. We believe that these waivers and modifications to our financial covenant ratios as well as the successful execution of certain contemplated transactions will enable us to maintain compliance with such ratios for 2015. See Item 7 - “Liquidity and Capital Resources.”
Capital Market and Equity Financings
During the year ended December 31, 2014, we raised approximately $188.2 million in net cash proceeds, after offering discounts, commissions and placement fees, but before other offering expenses, from capital market and equity transactions, including:
| i. | $149.7 million in net proceeds from the May 2014 issuance of 21,428,580 shares of our common stock, together with warrants to purchase up to an aggregate of 2,142,858 shares of common stock, in a private placement at a price of $7.00 per share; |
| ii. | $28.9 million in net proceeds from the March 2014 issuance of 4,300,000 shares of our common stock in a private placement at a price of $7.00 per share; and |
| iii. | $9.7 million in net proceeds from the issuance of 2,375,273 shares of our common stock upon exercise of stock options. |
Natural Gas and Oil Prices
During the third and fourth quarters of 2014, benchmark crude oil prices declined dramatically and benchmark natural gas prices softened. The basis differential for natural gas prices in Appalachia also widened against NYMEX natural gas prices during 2014. If prices continue to decline as a result of increased supply without sufficient takeaway capacity for this region, this could impact the amount of natural gas that companies are willing to produce until additional takeaway capacity becomes available.
During the three months ended December 31, 2014, our realized commodity sales prices declined compared to the three month period ended September 30, 2014. These declines were consistent with overall declines in commodity markets in the United States. The table below shows the impact that volatility in the oil and natural gas markets has had on our realized prices over the past year.
| Average Realized Prices (U.S. Dollars) | ||||||||||||||||||
| Year Ended | Three Months Ended | Year Ended | ||||||||||||||||
| December 31, 2013 | March 31, 2014 | June 30, 2014 | September 30, 2014 | December 31, 2014 | December 31, 2014 | |||||||||||||
| Oil (per Bbl) | $ | 90.04 | $ | 83.14 | $ | 97.13 | $ | 90.55 | $ | 58.79 | $ | 83.53 | ||||||
| Natural gas (per Mcf) | $ | 4.07 | $ | 5.56 | $ | 5.13 | $ | 3.43 | $ | 2.87 | $ | 4.19 | ||||||
| NGLs (per BOE) | $ | 43.61 | $ | 57.19 | $ | 55.71 | $ | 41.29 | $ | 38.05 | $ | 48.04 | ||||||
2015 Capital Expenditure Budget
We have approved a substantially reduced fiscal year 2015 upstream capital expenditure budget, compared with our budget for fiscal year 2014. Our upstream capital expenditure budget for fiscal year 2015 is $100 million, but we intend to reevaluate this budget on a quarterly basis.
Our 2015 upstream capital expenditure budget may be reduced or increased depending on realized prices for our natural gas, natural gas liquids and oil, investment opportunities, continued effective implementation of cost reduction initiatives, including reduction of oil and gas field service costs, and funding allocations. Our upstream capital expenditure budget is also subject to change based on a number of other factors, including economic and industry conditions at the time of drilling, prevailing and anticipated prices for natural gas and oil, the results of our exploration and development 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 new drilling locations. We anticipate that a minimum of approximately $43 million in upstream capital expenditures may be necessary to maintain the level of our reserves during 2015.
We have allocated approximately $70 million of our upstream capital expenditure budget to our Marcellus Shale and Utica Shale exploration and development drilling program in West Virginia and Ohio, approximately $10 million to our properties in the Williston
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Basin/Bakken Shale in North Dakota (substantially all of which are non-operated) and approximately $20 million for additional leasehold acreage acquisitions in the Marcellus Shale and Utica Shale plays.
Because of the volatility of commodity prices and the risks involved in our industry, we believe in remaining flexible in our capital budgeting process. During 2015, we intend to reevaluate our upstream capital expenditure budget on a quarterly basis. We intend to limit capital spending to allow upstream oil and gas field service cost reductions to catch up with the dramatic drop in benchmark commodity prices that has occurred over the past several months. Therefore, we expect that most of our 2015 upstream capital expenditures will occur during the second half of 2015. Additionally, the focus on minimizing capital spending may change throughout the year as we continue discussions with interested parties regarding potential joint venture opportunities to fund our exploration and development drilling activities in Ohio.
We expect that our 2015 upstream capital expenditure budget of $100 million will be funded from a combination of internally-generated cash flows, borrowings under our Magnum Hunter revolving credit facility, anticipated sales of certain assets, potential joint venture opportunities, possible capital markets transactions and other anticipated strategic initiatives in progress. See “Management's Discussion and Analysis of Financial Condition and Results of Operations” in this annual report for a description of our Magnum Hunter revolving credit facility.
We expect that the 2015 capital expenditure requirements of Eureka Hunter Holdings will be funded primarily by cash flow from its midstream operations, borrowings under Eureka Hunter Pipeline’s existing revolving credit facility and capital contributions provided by MSI. We and MSI are currently engaged in discussions regarding Eureka Hunter Holdings’ 2015 capital expenditure budget, including the amount, timing and expected funding of the various anticipated capital expenditures. We anticipate that, as a result of these discussions, the parties will determine the priority, timing and (to the extent not funded by operating cash flows or borrowings) allocation between the parties of the funding of the anticipated expenditures that will most effectively serve the 2015 project plans of Eureka Hunter Pipeline. We also anticipate that, as part of these determinations, MSI will make the $13.3 million cash capital contribution to Eureka Hunter Holdings that we are otherwise required to make at the end of March 2015 in exchange for additional Series A-2 Units under the terms of the carried interest provided by MSI. See “-Our Significant Recent Developments-Midstream Operations-Eureka Hunter Holdings”, see “Management's Discussion and Analysis of Financial Condition and Results of Operations” in this annual report for a description of Eureka Hunter Pipeline’s revolving credit facility, and See Item 7 “Management's Discussion and Analysis of Financial Condition and Results of Operations” for a description of our revolving credit facility, including a description of the restrictions under that facility on our ability to make investments in Eureka Hunter Holdings.
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 Appalachian Basin properties are located primarily 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 asset base through additional acquisitions, leasing activities, joint ventures and significant drilling efforts. As of January 31, 2015, we had a total of approximately 79,933 net leasehold acres in the Marcellus Shale and approximately 128,095 net leasehold acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage). We believe approximately 40,000 of our Utica Shale net acres are located in the wet gas window of the play.
As of December 31, 2014, proved reserves attributable to our Appalachian Basin properties were 75.9 MMBoe, of which 66% were classified as proved developed producing. As of December 31, 2014, these proved reserves had a PV-10 value of $765.8 million.
We intend to drill and/or complete a total of approximately 14 gross (14 net) horizontal wells in the Marcellus Shale and Utica Shale in 2015 under our $100 million upstream capital expenditure budget.
Marcellus Shale Properties
As of January 31, 2015, we had a total of approximately 79,933 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, 2015, approximately 75% of our mineral leases in the Marcellus Shale area were held by production.
As of January 31, 2015, we had (i) 55 horizontal wells (44.4 net) producing in the Marcellus Shale (including non-operated wells), and (ii) five horizontal wells (five net) drilled, which had been top-holed and were awaiting completion. As of January 31, 2015,
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our five most recently completed Company-operated horizontal wells targeting the Marcellus Shale generated an average of approximately 16,830 Mcfe/d (13,433 Mcfe/d wet gas and 3,397 Mcfe/d condensate) and 7,786 Mcfe/d (5,509 Mcfe/d wet gas and 2,277 Mcfe/d condensate) average IP-24 hour and IP-30 day rates, respectively, measured on a well by well basis, eliminating rate restrictions. For IP-30 day rates, all wells on a single pad are put on production causing the pad to become compression restricted. This type of compression is designed at an economic rate over the life of the well.
The liquids rich natural gas produced in our core Marcellus Shale area (which has a Btu content ranging from 1,220 to 1,450), coupled with a location near the energy-consuming regions of the mid-Atlantic and northeastern U.S., historically have allowed us to sell our natural gas at a premium to prevailing NYMEX spot prices. In the past, producers in the Appalachian Basin developed oil and natural gas from shallow Mississippian age sandstone and Upper Devonian age shales with low permeability, which is prevalent throughout 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 (“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 the Eureka Hunter Gas Gathering System. As of January 31, 2015, Stone Energy had drilled and completed 21 producing Marcellus Shale wells pursuant to this joint development program.
In January 2013, we entered into joint development and operating agreements with Eclipse Resources I, LP (“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 the Eureka Hunter Gas Gathering System. As of January 31, 2015, we had drilled one Marcellus Shale well and four Utica Shale wells pursuant to this joint development program. As of January 31, 2015, we were testing the three most recent Utica Shale wells on the Company’s Stalder Pad in the contract area.
During 2015, we plan to drill and/or complete a total of six gross (six net) wells in the Marcellus Shale under our $100 million upstream capital expenditure budget.
Utica Shale Properties
As of January 31, 2015, we had a total of approximately 128,095 net leasehold acres prospective for the Utica Shale. Approximately 92,727 of the net acres are located in Ohio (a portion of which acreage overlaps our Marcellus Shale acreage), and approximately 35,368 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 40,000 of our Utica Shale net acres are located in the wet gas window of the play. Approximately 53% of our acreage in the Utica Shale is held by shallow production (“HBP”).
As of January 31, 2015, we had two horizontal wells (two net) awaiting completion in the Utica Shale, and three horizontal wells (three net) in the play drilled to their deep intermediate casing point at approximately 10,600 feet and awaiting further drill-out and completion.
Our 100% owned Stewart Winland 1300U (Utica well) in Tyler County, West Virginia tested at a peak rate of 46.5 MMcf of natural gas per day (~7,750 Boe/d) on an adjustable rate choke with 7,810 psi FCP. The Stewart Winland 1300U well was drilled and cased to true vertical depth of 10,825 feet with a 5,289 foot horizontal lateral, and successfully fraced with 22 stages. We have also drilled and completed the Stalder #3UH (Utica well) in Monroe County, Ohio, our first dry gas well in the Utica Shale in Ohio, to a true vertical depth of 10,653 feet with a 5,050 foot horizontal lateral, which was successfully fraced with 20 stages. Initial flow tests on the Stalder #3UH well tested at a peak rate of 32.5 MMcf of natural gas per day (~ 5,400 Boe/d) on an adjustable rate choke with 4,300 psi FCP.
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The Utica Shale is located in the Appalachian Basin of the United States. 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. The Utica Shale resides throughout most of our acreage 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 shale rock 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 (“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 2014, a number of oil and gas companies made significant investments in acquiring Utica Shale acreage in eastern Ohio. As of January 31, 2015, the ODNR reported that in the Utica Shale in Ohio there were 729 producing horizontal wells, 324 horizontal wells that had been drilled but were not yet completed or connected to a pipeline, 288 horizontal wells that were being drilled and 1,791 horizontal wells that had been permitted, of which 450 had not been spudded.
During 2014, most of the drilling activity in the Utica Shale occurred in eastern Ohio and southwestern West Virginia, where our acreage is located. During 2015, we plan to drill and/or complete a total of eight gross (eight net) wells in the Utica Shale under our $100 million upstream capital expenditure budget.
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Marcellus Shale and Utica Shale Drilling in 2014
The following table contains certain information regarding our Marcellus Shale and Utica Shale horizontal wells drilled or completed in 2014.
| MHR Working | First | Horizontal Lateral | # of Frac | |||||||
| Well Name | County | Interest | Production | Length (feet) | Stages | |||||
| Operated | ||||||||||
| Stewart Winland #1300 UH | Tyler, WV | 100% | 12/11/2014 | 5,289 | 22 | |||||
| Steward Winland #1301 UH | Tyler, WV | 100% | 12/15/2014 | 5,762 | 29 | |||||
| Stewart Winland #1302 UH | Tyler, WV | 100% | 12/15/2014 | 5,676 | 29 | |||||
| Stewart Winland #1303 MH | Tyler, WV | 100% | 12/15/2014 | 5,762 | 29 | |||||
| Everett Weese #1414 | Tyler, WV | 100% | 12/30/2014 | 5,887 | 29 | |||||
| Everett Weese #1415 | Tyler, WV | 100% | 12/30/2014 | 6,504 | 32 | |||||
| Stalder #3 UH | Monroe, OH | 47% | 2/9/2014 | 5,500 | 22 | |||||
| Stalder #2 UH | Monroe, OH | 47% | testing | 5,442 | 28 | |||||
As of January 31, 2015, all of the wells completed in 2014 and listed in the table above were on production, except for the Stalder #3UH and the Stalder #2UH, which were being tested. These two wells were subsequently put on production in February 2015.
Recent Marcellus Shale and Utica Shale Activities
During the fourth quarter of 2014, we completed the drilling of four gross (four net) wells and completed nine gross (7.5 net) wells in the Marcellus Shale and Utica Shale plays. These nine gross (7.5 net) completed wells are currently flowing to sales through the Eureka Hunter Gas Gathering System. Our net production in the fourth quarter of 2014 attributable to our Marcellus Shale and Utica Shale operations was approximately 84,756 Mcfe/d.
Stewart Winland Pad. On our Stewart Winland Pad located in Tyler County, West Virginia, we have drilled and cased the Stewart Winland #1301, #1302, and #1303 wells, in the Marcellus Shale to a true vertical depth of 6,155 feet with a 5,750 foot average horizontal lateral. We drilled and cased the Stewart Winland #1300 well, our second dry gas Utica Shale well, to a true vertical depth of 10,825 feet with a 5,289 foot horizontal lateral. The Stewart Winland #1300 tested at a peak rate of 46.5 MMcf of natural gas per day (~7,750 Boe/d) on an adjustable rate choke with 7,810 psi FCP. As of December 12, 2014, these three Marcellus Shale wells, along with the Stewart Winland #1300, were flowing to sales.
Stalder Pad. On our Stalder Pad located in Monroe County, Ohio, the Stalder #2MH, our first Marcellus Shale well, was drilled and cased to a true vertical depth of 6,070 feet with a 5,474 foot horizontal lateral. We have also drilled and completed the Stalder #3UH, our first dry gas well in the Utica Shale, to a true vertical depth of 10,653 feet with a 5,050 foot horizontal lateral, which was successfully fraced with 20 stages. Initial flow tests on the Stalder #3UH tested at a peak rate of 32.5 MMcf of natural gas per day (~ 5,400 Boe/d) on an adjustable rate choke with 4,300 psi FCP. Three additional down-dip Utica Shale laterals have been drilled off the Stalder Pad; the Stalder #6UH, #7UH and #8UH. These three wells have been drilled and cased to a true vertical depth of 10,660, with 24, 25, and 26 successful fracture stimulation stages completed, respectively. As of January 31, 2015, we were testing the three new wells on Stalder Pad.
Farley Pad. On our Farley Pad located in Washington County, Ohio, we have 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 also drilled and cased the Farley #1304H well in the Utica Shale to a true vertical depth of 7,914 feet with a 5,400 foot horizontal lateral. These wells, along with the Farley #1305H, drilled in 2013, are awaiting completion and evaluation. We expect to begin fracture stimulation of the Farley #1306H and #1304H wells by summer 2015 as part of our $100 million upstream capital expenditure budget.
WVDNR Pad. On our WVDNR Pad located in Wetzel County, West Virginia, we have drilled and completed the WVDNR #1207, #1208 and #1209, our Marcellus Shale wells, to an average vertical depth of 7,500 feet with a 4,000 foot average horizontal lateral. These three wells began flowing to sales in April 2014, and were subsequently shut-in in May 2014 to prepare for drilling four additional down-dip laterals off the existing WVDNR Pad. For the seven-day period prior to shut-in, the WVDNR #1207, #1208, and #1209 had an average net daily production of 9,450Mcfe/d (~1,575 Boe/d). We have also drilled and completed the WVDNR #1410, #1411, #1412 and #1413 wells, in the Marcellus Shale, to a true vertical depth of 7,500 feet with a 4,760 foot average horizontal lateral. As of December 31, 2014, the Company had concluded all completion activities and begun flowback operations on this pad, and these four wells began flowing to sales in January 2015.
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Ormet Pad. On our Ormet Pad located in Monroe County, Ohio, being our second Ormet Pad, the Company has planned five down-dip Marcellus Shale wells and four down-dip Utica Shale laterals. Each of the Ormet #8-15UH, #9-15UH and #10-15UH wells have been drilled and cased to the 9 5/8” casing point at a vertical depth of ~10,600 feet, with a ~4,700 foot average horizontal lateral. Alpha Hunter began drilling the Ormet #10-15UH well in June 2014 with its Schramm TXD500 robotic drilling rig. As of December 31, 2014, the Ormet #8-15UH was flowing to sales at a rate in excess of 5 MMcf/d with a flowing pressure of 4,050 psi on a natural completion (no fracture stimulation).
Everett Weese Pad. On our Everett Weese Pad located in Tyler County, West Virginia, we drilled and completed three Marcellus Shale wells, the Everett Weese #1107, #1108, and #1109. These three wells were shut-in during mid-July 2014 in preparation for drilling and completing two additional Marcellus Shale wells on the Everett Weese Pad. We drilled and completed the two additional Marcellus Shale wells, the Everett Weese #1414 and #1415 wells, in December 2014. All of these Everett Weese Pad wells were turned to sales in January 2015.
We plan to continue to refine our drilling and completion techniques in the Marcellus Shale and the Utica Shale plays and thereby work to improve initial production rates and ultimate recoveries while at the same time lowering drilling and completion costs.
Southern Appalachian Basin Properties
Our southern Appalachian Basin properties are owned by our subsidiary, MHP.
As of January 31, 2015, our southern Appalachian Basin properties included approximately 208,309 net leasehold acres, primarily in Kentucky. Our primary production from the southern Appalachian Basin properties consists of natural gas and natural gas liquids and comes from the Devonian Shale formation and the Mississippian Weir sandstone.
In December 2014, our Arch #14 well located in Harlan County, Kentucky, was turned to sales, with production under a managed choke at a rate of 740 Mcf/d with a flowing tubing pressure of 1,300 psi.
Our southern Appalachian Basin 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 Divide County, North Dakota, which are located in the Williston Basin/Bakken Shale, as our Williston Basin Properties.
We initially entered the Williston Basin/Bakken Shale through an asset acquisition in May 2011 and subsequently expanded our asset base through additional acquisitions, leasing activities and significant drilling efforts. We have since sold a significant amount of certain non-operated oil and gas properties in Divide County, North Dakota. See “- Our Significant Recent Developments - Divestitures - North Dakota Assets.”
As of January 31, 2015, we had a total of approximately 65,650 net leasehold acres remaining that are prospective for the Bakken/Three Forks Sanish formations in Divide County, North Dakota. As of January 31, 2015, we had approximately 174 gross (58.6 net) wells producing on our Williston Basin Properties. As of January 31, 2015, we operated seven of our Williston Basin Properties wells. As of December 31, 2014, proved reserves attributable to our Williston Basin Properties were 7.9 MMBoe, of which 93% were oil and natural gas liquids and 66% were classified as proved developed producing. As of December 31, 2014, these proved reserves had a PV-10 value of $143.5 million.
The Company, along with its operating partners, have invested substantial commitment, capital and effort to install power grids, water gathering systems, gas gathering and crude oil pipelines and a truck terminal to increase efficiencies and reduce costs throughout the Williston Basin Properties. We believe these efforts will help drive production costs down and add future value.
During 2015, we expect that our participation in any new wells on our Williston Basin Properties will only be as a non-operated working interest owner, and only if we believe such participation is consistent with our principal business strategy and will provide a positive rate of return to the Company during a lower commodity price environment.
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,
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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.
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The following table contains certain information regarding our Bakken/Three Forks Sanish horizontal wells drilled or completed in 2014 (substantially all of which are non-operated).
| Well Name | Formation | MHR Working Interest | First Production | Horizontal Lateral Length (Feet) | # of Frac Stages | ||||||
| Almos Farms 01 12-3TFH (1-12-162-99) | Bakken | 47.50 | % | 1/10/2014 | 9,431 | 25 | |||||
| Almos Farms 01 12-5TFH (1-12-162-99) | Bakken | 47.50 | % | 3/25/2014 | 9,506 | 43 | |||||
Almos Farms 1-26HN (13,14-23,24-163-100) (1) | Sanish | 1.31 | % | Sold (1) | 10,083 | Sold (1) | |||||
Almos Farms 1-26HS (26-35-163-100) (1) | Sanish | 13.39 | % | Sold (1) | 9,681 | 26 | |||||
Almos Farms 1B-26HN (14-23-163-100) (1) | Sanish | 1.91 | % | Sold (1) | 10,018 | 30 | |||||
| Baja 2215-7H (22-15-163-99) | Sanish | 31.25 | % | 6/18/2014 | 9,755 | 25 | |||||
Beetle 3031-3H (30-31-163-98) (2) | Bakken | 47.12 | % | 9,834 | 25 | ||||||
| Bel Air 2314-5H (23-14-163-99) | Bakken | 44.02 | % | 4/18/2014 | 10,271 | 25 | |||||
| Bel Air 2314-7H (23-14-163-99) | Bakken | 44.02 | % | 4/1/2014 | 10,089 | 25 | |||||
| Bel Air 1423-8H (14-23-163-99) | Sanish | 45.19 | % | 4/18/2014 | 9,616 | 25 | |||||
Bernie A 20-17-162-98H 2XC (1) | Sanish | 9.84 | % | 6/20/2014 (1) | 10,031 | 30 | |||||
Bernie B 20-17-162-98H 3XB (1) | Sanish | 9.85 | % | 6/25/2014 (1) | 9,575 | 30 | |||||
| BH Pacer 3427 2 MBH (34-27-164-99) | Bakken | 95.52 | % | 1/31/2014 | 5,299 | 24 | |||||
| Bonneville 3625-5TFH (25-36-163-100) | Sanish | 26.77 | % | 4/18/2014 | 9,428 | 25 | |||||
| Bonneville 3625-7TFH (25-36-163-100) | Sanish | 26.77 | % | 4/17/2014 | 9,506 | 25 | |||||
| Charger 0706-8H (18-19-162-98) | Sanish | 47.67 | % | 10/23/2014 | 9,526 | 25 | |||||
| Comet 2635-5H (26-35-163-99) | Bakken | 44.02 | % | 4/17/2014 | 9,585 | 25 | |||||
| Comet 2635-7H (26-35-163-99) | Bakken | 44.02 | % | 4/17/2014 | 9,195 | 25 | |||||
| Comet 2635-8H (26-35-163-99) | Sanish | 45.19 | % | 4/20/2014 | 8,896 | 25 | |||||
Coronet 2413-8H (13-24,18-19-163-98,99) (2) | Sanish | 46.73 | % | 9,936 | 25 | ||||||
| Haffner 1-31H (19-30-31-162-95) | Bakken | 3.00 | % | 2/16/2014 | 14,729 | 50 | |||||
Kathlyn Hall 18-19-162-99H 3DN (1) | Sanish | 10.00 | % | 4/2/2014 (1) | 9,769 | 30 | |||||
Les Hall 18-19-162-99H 2DM (1) | Sanish | 10.00 | % | 4/2/2014 (1) | 9,611 | 30 | |||||
| Marauder 2413-1H (13-24-162-98) | Sanish | 17.52 | % | 10/7/2014 | 9,244 | 25 | |||||
| Marauder 2413-3H (13-24-162-98) | Sanish | 17.52 | % | 10/9/2014 | 9,619 | 25 | |||||
| Matador 2734-7H (27-34-163-99) | Bakken | 28.45 | % | 6/19/2014 | 9,165 | 25 | |||||
Nelson 18-19-161-98H 1BP (1) | Sanish | 8.61 | % | 1/27/2014 (1) | 9,562 | 30 | |||||
| Ness 3229-4H (29-32-163-98) | Sanish | 47.50 | % | 10,316 | In-progress | ||||||
| Ness 3229-6H (29-32-163-98) | Sanish | 47.50 | % | 9,819 | In-progress | ||||||
| Odyssey 0508-6H (5*8*162-98) | Sanish | 47.83 | % | 9,074 | In-progress | ||||||
Orlynne 3-2H (3-10-162-100) (1) | Sanish | 1.31 | % | 3/16/2014 (1) | 10,055 | 26 | |||||
Overland 20-17-162-9811 2MD (1) | Sanish | 9.62 | % | Sold (1) | 8,854 | Sold (1) | |||||
Ranchero 1918-2H (18-19-163-98) (2) | Sanish | 47.50 | % | 10,072 | 25 | ||||||
| Stingray 1819-6H (18-19-162-98) | Sanish | 46.26 | % | 10/23/2014 | 9,944 | 25 | |||||
Strom 2536-8H (25-36,30-31-163-98,99) (2) | Sanish | 46.83 | % | 9,002 | 25 | ||||||
Tomlinson 3-1HN (25-36-162-100) (1) | Sanish | 3.28 | % | 3/14/2014 (1) | 10,111 | 26 | |||||
Torgeson 2-15HN (3-10-163-100) (1) | Sanish | 2.97 | % | Sold (1) | 9,960 | 17 | |||||
Torgeson 2B-15HN (3-10-163-100) (1) | Sanish | 2.97 | % | Sold (1) | 10,087 | 30 | |||||
(1) | We participated in the drilling and/or completion of this well and subsequently sold our interest in the well during the year ended December 31, 2014. |
(2) | This well was drilled and completed during the year ended December 31, 2014, but did not begin producing until February 2015. |
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Recent Williston Basin Activities
Oneok Gas Gathering Arrangement. In 2012, we entered into a gas purchase agreement with Oneok Inc. (“Oneok”), pursuant to which Oneok has constructed 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 purchases our natural gas and natural gas liquids production from the dedicated properties, and we are 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 from certain of our Divide County properties beginning in 2013. 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 existing or future state gas flaring regulations.
Cross-Border Pipeline. In conjunction with the Oneok system, we completed, during 2014, construction of a cross-border low pressure pipeline. The cross-border pipeline allows gas to flow from the Canadian assets we sold to Steppe Resources, Inc. in May 2014 into the Oneok system and further credits our Oneok minimum yearly gas sales volume.
Other Upstream Properties
The Company owns certain other scattered miscellaneous oil and gas properties in Texas and Louisiana. We have not allocated any capital to these assets for 2015.
Midstream Operations
We have a substantial equity investment in Eureka Hunter Holdings which we consider to be a strategic asset for the development and delineation of our acreage position in both the Utica Shale and Marcellus Shale plays. Eureka Hunter Pipeline, a wholly-owned subsidiary of Eureka Hunter Holdings, owns and operates the Eureka Hunter Gas Gathering System in West Virginia and Ohio. Given the substantial investment we continue to hold in Eureka Hunter Holdings and the importance the gas gathering assets of Eureka Hunter Pipeline have on our ongoing operations, we believe it is important to continue providing more informative details relative to the operational activities of Eureka Hunter Holdings and its subsidiaries.
As of January 31, 2015, Eureka Hunter Pipeline had completed the construction of over 160 miles of 20-inch and 16-inch high-pressure steel pipe with an estimated 2.1 Bcf/d of initial throughput capacity, all of which is currently active 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 Monroe and Washington Counties in Ohio.
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. Eureka Hunter Holdings (and its predecessor) have developed, and Eureka Hunter Holdings continues to develop, these assets into the 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 gas gathering needs of third party producers in these regions. The first completed six-mile section of the Eureka Hunter Gas Gathering System was turned to sales in December 2010.
In 2012, Eureka Hunter Pipeline completed the construction of its 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, Eureka Hunter Pipeline successfully bored under the Ohio River to continue the construction of the lateral into Ohio. Eureka Hunter Pipeline is currently planning to construct a second bore underneath the Ohio River in late 2015 to 2016. In 2014, Eureka Hunter Pipeline completed two 20-inch lines, approximately five miles in length, for gathering both dry gas Utica Shale production, and wet natural gas from our Ormet Pad.
In the fourth quarter of 2012, Eureka Hunter Pipeline completed the construction of its 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 Eureka Hunter Pipeline’s Eureka Carbide Facility, near the community of Carbide in Wetzel County.
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Eureka Hunter Pipeline completed the initial construction of the Eureka Carbide Facility in 2012. This facility includes (i) 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, (ii) 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 (iii) 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. In 2014, Eureka Hunter Pipeline added new mainline compression equipment at the facility, to handle expected additional volume demand and reduce line pressure for producers.
In the fourth quarter of 2012, Eureka Hunter Pipeline completed the construction of its Mobley lateral section of the pipeline, which is a 20-inch residue 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.
Eureka Hunter Pipeline has completed construction of its 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.
Eureka Hunter Pipeline has completed construction of its 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.
Eureka Hunter Pipeline has completed its 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. Eureka Hunter Pipeline continues 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. Eureka Hunter Pipeline’s Tippens lateral will transport Utica dry gas into its multiple interconnects at Clarington, Ohio.
In 2014, Eureka Hunter Pipeline completed construction on its Crescent lateral section of the pipeline, which consists 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.
In 2014, Eureka Hunter Pipeline completed construction on it REX-TEX lateral section of the pipeline, which consists of approximately 5.5 miles of 20-inch and 22-inch pipeline for gathering dry gas Utica Shale production from the Crescent lateral to interconnections with Rockies Express Pipeline, Spectra Energy, Dominion Transmission, and Blue Racer.
Eureka Hunter Pipeline’s 2015 projects include 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. In addition, Eureka Hunter Pipeline plans to construct a separate pipeline system for gathering liquids rich gas production from the Eureka Hunter Gas Gathering System at our Ormet Pad northerly to interconnect with a third party pipeline for ultimate delivery of liquids rich gas to the third party's plant for processing. Eureka Hunter Pipeline has also added another interconnect for wet Marcellus to Blue Racer’s Natrium plant, which gives Eureka Hunter Pipeline over 600 mmsfc/d of processing connected to its wet system.
Eureka Hunter Pipeline’s other projects for 2015 include the completion of the Ritchie lateral which is expected to 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.
Natural Gas Treating and Processing
TransTex is a full service provider for the natural gas treating and processing needs of producers and midstream companies. TransTex currently conducts treating and processing operations in Texas, Louisiana and West Virginia and anticipates possible future operations in Arkansas, Mississippi and Ohio. As of January 31, 2015, TransTex owned approximately 74 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. TransTex’s 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. TransTex also offers full turnkey services including the installation, operation and maintenance of facilities. TransTex’s customers include small, independent producers, as well as large, publicly-traded companies.
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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 Continuum Energy Services, L.L.C. (formerly known as Seminole Energy Services, L.L.C.) and certain of its affiliates (collectively, “Continuum Energy”). We operate these gathering facilities, which are located in southeastern Kentucky, northeastern Tennessee and western Virginia. We have gas gathering and gas gathering facilities operating agreements with Continuum Energy. The Continuum 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 Continuum 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 Basin natural gas production, to major East Coast natural gas markets.
Gas Processing. We own a 50% equity interest in a liquids extraction plant in Rogersville, Tennessee, used for the processing of natural gas delivered through Continuum 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 Continuum Energy. Gas processing fees are volume dependent and are shared with Continuum Energy. During 2014, in connection with the restructuring of our agreements with Continuum Energy, further described below, the Rogersville processing plant was upgraded to provide for the removal of more ethane from the produced natural gas liquids while increasing the amount of propane retained. This upgrade is expected to improve the economics of the Rogersville since plant propane generally commands a higher sales price per gallon than ethane.
Restructuring of the Continuum Energy Agreements. Our agreements with Continuum Energy referred to above were restructured in connection with a global settlement we reached with Continuum Energy in January 2014 hat resolved certain legal proceedings instituted by the parties. The restructured agreements resulted in the following: (i) we obtained a reduction in the gas gathering rates we pay for the natural gas production owned or controlled by us which is gathered by Continuum Energy's Appalachia gathering system; (ii) the parties agreed to construct an 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 Continuum 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 Continuum Energy; (iv) the parties agreed to the modification of (v) the natural gas processing rates we pay for processing gas at the Rogersville plant, (vi) the allocation to us of natural gas liquids recovered from gas processed at the Rogersville plant, (vii) 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 (viii) certain deductions to the natural gas liquids purchase price we pay for the purchase by Continuum Energy of our natural gas liquids produced from the Rogersville plant; and (ix) the sale by Continuum Energy to us of Continuum 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 Continuum Energy and us.
As a result of the restructuring effected by the settlement agreement, we have realized operational savings of approximately $250,000 per month.
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 both for our Appalachian Basin operations and to provide drilling services to third parties. At January 31, 2015, 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 for Marcellus and Utica Shale wells owned by us and third parties 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.
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At January 31, 2015, (i) four of our 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 2015; (ii) one of our Schramm T200XD drilling rigs will be used by us for our top-hole drilling program; and (iii) our Schramm T500XD drilling rig was under contract to one of our subsidiaries for our Marcellus Shale and Utica Shale drilling program. As a result of our decision to reduce capital spending in 2015, and in expectation that the decline in overall commodity prices will soon drive down general oil and gas field service costs, we have temporarily idled the Schramm T500XD drilling rig, and we expect the rig to remain idle for up to another 30 to 60 days.
Marketing and Pricing
General
We derive revenue principally from the sale of natural gas and oil. As a result, our revenues are determined, to a large degree, by prevailing prices for natural gas and crude oil. We sell our natural gas and oil on the open market at prevailing market prices. The market prices for natural gas and oil are dictated by general supply and demand and other forces outside of our control, and we cannot accurately predict or control the prices we may receive for our natural gas and oil.
The Company generally markets its oil and natural gas production under “month-to-month” or “spot” contracts.
Marketing of 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 truck, pipeline or 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 Midstream Services
Eureka Hunter Pipeline markets its 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. Eureka Hunter Pipeline’s 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 them.
TransTex markets its gas treatment plants and services in very much the same manner as Eureka Hunter Pipeline markets its gathering services. Much of TransTex’s gas treatment business growth comes from existing customers seeking additional plants and services. New business is generated by TransTex’s marketing team by regularly visiting with producers that have new or expanded drilling and production operations in those areas served by its gas treatment business, by tracking drilling permits and through other producer referrals. TransTex also expands its 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.
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Pricing
Our revenues, cash flows, profitability and future rate of growth depend substantially upon prevailing prices for oil and natural gas, which have declined dramatically in recent months. 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 on certain properties. Historically, the prices received for oil and natural gas have fluctuated widely on certain properties. Among the factors that can cause these fluctuations are:
| i. | uncertainty in the global economy; |
| ii. | changes in global supply and demand for oil and natural gas; |
| iii. | the condition of the United States and global economies; |
| iv. | the actions of certain foreign countries; |
| v. | the price and quantity of imports of foreign oil and liquid natural gas; |
| vi. | political conditions, including embargoes, war or civil unrest in or affecting oil producing activities of certain countries; |
| vii. | the level of United States and global oil and natural gas exploration and production activity; |
| viii. | the level of United States and global oil and natural gas inventories; |
| ix. | production or pricing decisions made by the Organization of Petroleum Exporting Countries; |
| x. | weather conditions; |
| xi. | technological advances affecting energy consumption or production; and |
| xii. | 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:
| i. | our production and/or sales of oil and natural gas are less than expected; |
| ii. | payments owed under a derivative contract come due prior to receipt of the covered month’s production revenue; or |
| iii. | 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.
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As of December 31, 2014, we had the following derivatives in place:
| Weighted Average | |||||||
| Natural Gas | Period | MMBtu/d | Price per MMBtu | ||||
| Swaps | Jan 2015 - Dec 2015 | 40,000 | $4.09 | ||||
| Weighted Average | |||||||
| Crude Oil | Period | Bbl/d | Price per Bbl | ||||
Collars (1) | Jan 2015 - Dec 2015 | 259 | $85.00 - $91.25 | ||||
| Ceilings sold (call) | Jan 2015 - Dec 2015 | 1,570 | $120.00 | ||||
| Floors sold (put) | Jan 2015 - Dec 2015 | 259 | $70.00 | ||||
(1) A collar is a sold call and a purchased put. Some collars are “costless” collars with the premiums netting to approximately zero.
MHP Sponsored Drilling Partnerships
Prior to our acquisition of NGAS Resources, Inc. (“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, were 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 continue to manage the drilling partnerships and the programs in our capacity as managing general partner. All of the project wells have been drilled and completed. We do not expect to sponsor any additional drilling partnerships in the future.
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 . 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, 2014. These estimates were determined based on prices for the twelve-month period ended December 31, 2014, and lease operating expenses as of June 30, 2014. Since January 1, 2014, 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 and regular survey reports provided to the U.S. Department of Energy. 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.
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Proved Reserves
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, 2014.
| Proved Reserves (SEC Prices at 12/31/14) | ||||||||||||
| Category | Oil | NGLs | Gas | PV-10 (1) | ||||||||
| (MBbl) | (MBbl) | (MMcf) | (in thousands) | |||||||||
| Proved Developed | 6,938 | 10,587 | 251,628 | $ | 750,149 | |||||||
| Proved Undeveloped | 3,583 | 3,816 | 101,373 | $ | 159,114 | |||||||
| Total Proved | 10,521 | 14,403 | 353,001 | $ | 909,263 | |||||||
_______________
(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 2014, using $94.99 per barrel of oil and $4.31 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 United States. 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. Risk Factors—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”. You should also read the notes following the table below and our consolidated financial statements for the year ended December 31, 2014 in conjunction with the following reserve estimates.
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The following table sets forth our estimated proved reserves at the end of each of the past three years:
| 2014 | 2013 | 2012 | |||||||||
| Description | |||||||||||
| Proved Developed Reserves | |||||||||||
| Oil (MBbl) | 6,938 | 12,085 | 16,355 | ||||||||
| NGLs (MBbl) | 10,587 | 6,989 | 6,263 | ||||||||
| Natural Gas (MMcf) | 251,628 | 176,585 | 125,526 | ||||||||
| Proved Undeveloped Reserves | |||||||||||
| Oil (MBbl) | 3,583 | 12,250 | 20,472 | ||||||||
| NGLs (MBbl) | 3,816 | 3,432 | 2,863 | ||||||||
| Natural Gas (MMcf) | 101,373 | 70,197 | 37,094 | ||||||||
Total Proved Reserves (MBoe)(1)(2) | 83,758 | 75,888 | 73,056 | ||||||||
PV-10 Value (in millions)(3) | $ | 909.3 | $ | 922.1 | $ | 981.2 | |||||
| Standardized Measure (in millions) | $ | 909.3 | $ | 844.5 | $ | 847.7 | |||||
_______________
(1) | The estimates of reserves in the table above conform to the guidelines of the SEC. Estimated recoverable proved reserves have been determined without regard to any economic impact that may result from our financial derivative activities. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The reserve information shown is estimated. The certainty of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, and the precision of the engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and present value are based on various assumptions, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. |
(2) | We converted natural gas to oil equivalent at a ratio of six Mcf of natural gas to one Bbl of oil. |
(3) | 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 2014 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 2014, using $94.99 per barrel of oil and $4.31 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. |
As of December 31, 2014, our proved undeveloped reserves, or PUDs, on an SEC case basis totaled 101.4 Bcf of natural gas and 7.4 MMBoe of crude oil and NGLs for a total of 24.3 MMBoe. Increases in natural gas PUDs that occurred during the year were due primarily to increased drilling activity in the Marcellus Shale and Utica Shale properties. Decreases in crude oil and natural gas liquids PUDs were due to sales of undeveloped proved reserves and the revision of previous estimates of reserves.
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The following table summarizes the changes in our proved undeveloped reserves for the year ended December 31, 2014:
| Proved Undeveloped Reserves (MBoe) | For the Year Ended December 31, 2014 |
| Proved undeveloped reserves—beginning of year | 27,382 |
Revisions of previous estimates (1) | (7,976) |
| Extensions and discoveries | 21,338 |
| Conversions to proved developed reserves | (13,569) |
| Sales of reserves in place | (2,881) |
| Proved undeveloped reserves—end of year | 24,294 |
_______________
(1) | Downward revisions in estimated proved undeveloped reserves were primarily related to our Williston Basin Properties and resulted from lower than expected performance, higher operating expenses and downward fluctuating prices during the year. |
Our capital expenditures associated with the conversion of proved undeveloped reserves to proved developed reserves were approximately $128.9 million for the year ended December 31, 2014. We expect to develop all of our proved undeveloped reserves as of December 31, 2014 within five years of their initial booking.
The following table summarizes the changes in our proved reserves for the year ended December 31, 2014:
| Proved Reserves (MBoe) | For the Year Ended December 31, 2014 |
| Proved reserves—beginning of year | 75,888 |
| Revisions of previous estimates | (4,476) |
| Extensions and discoveries | 26,988 |
| Production | (6,259) |
| Sales of reserves in place | (8,383) |
| Proved reserves—end of year | 83,758 |
| Proved developed reserves—beginning of year | 48,506 |
| Proved developed reserves—end of year | 59,463 |
Additions to proved reserves result from (i) extension of the proved acreage of previously discovered reserves through additional drilling in periods subsequent to discovery and (ii) discovery of new fields with proved reserves or of new reservoirs of proved reserves in oil or gas fields. Extensions and discoveries increased 26,126 MBoe to 26,988 MBoe in 2014 from 862 MBoe in 2013. The largest extensions and discoveries were all related to activity in our Marcellus Shale and Utica Shale development program which included the wells completed on the Stewart Winland, Stalder, WVDNR and Ormet Pads.
SEC Rules Regarding Reserves Reporting
In December 2008, the SEC adopted revisions to its rules designed to modernize oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:
| i. | Commodity Prices: Economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price unless contractual arrangements designate the price to be used. |
| ii. | Disclosure of Unproved Reserves: Probable and possible reserves may be disclosed separately on a voluntary basis. |
| iii. | Proved Undeveloped Reserve Guidelines: Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time. |
| iv. | Reserves Estimation Using New Technologies: Reserves may be estimated through the use of reliable technology in addition to flow tests and production history. |
| v. | Reserves Personnel and Estimation Process: Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate. |
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| vi. | Non-Traditional Resources: The definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction. |
Reserve Estimation
CG&A evaluated our oil and gas reserves on a consolidated basis as of December 31, 2014. The technical persons responsible for preparing our proved reserves estimates meet the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. CG&A is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists. The evaluation prepared by CG&A was supervised by Todd Brooker, Senior Vice President of CG&A. According to biographical information contained in CG&A’s reserve report, Mr. Brooker has been an employee of CG&A since 1992 and his responsibilities with CG&A include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. Also, according to biographical information contained in CG&A’s reserves report, Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a B.S. in petroleum engineering, is a registered Professional Engineer in the State of Texas and is also a member of the Society of Petroleum Engineers. CG&A does not own an interest in any of our properties and is not employed by us on a contingent basis.
In 2014, we established a Reserves Committee to provide oversight of the integrity of our oil, natural gas and natural gas liquids reserves. The members of the Reserves Committee are officers of the Company appointed by our chief executive officer. The Reserves Committee reports to the Governance Committee of our board of directors. We also maintain an internal staff consisting of petroleum engineers and geoscience professionals who work closely with CG&A to ensure the integrity, accuracy and timeliness of the data used to calculate our proved oil and gas reserves. The members of our Reserves Committee and our internal technical team members, meet with CG&A periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to CG&A for our properties such as ownership interest; oil and gas production; well test data; commodity prices; and operating and development costs. The preparation of our proved reserve estimates is completed in accordance with our internal control procedures, which include the verification of input data used by CG&A, as well as extensive management review and approval. All of our reserve estimates are reviewed and approved by our Reserves Committee. Currently, our Reserves Committee consists of Mr. James W. Denny, III, our executive vice president of operations, and Mr. Hershal C. Ferguson, III, our executive vice president of exploration. Mr. Denny is a registered professional engineer, certified earth scientist and member of the American Petroleum Institute, the National Society of Professional Engineers, the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. Mr. Denny is a graduate of the University of Louisiana-Lafayette and holds a B.S. in petroleum engineering. Mr. Ferguson is a geologist and member of the American Association of Petroleum Geologists, the Houston Geological Society, the Society of Petroleum Engineers and the Texas Independent Producers & Royalty Owners Association. Mr. Ferguson is a graduate of the University of Texas at Austin and holds a degree in geology. Reserve estimates for each of our divisions are also reviewed and approved by the president of that division.
The technologies used in the estimation of our proved reserves are commonly employed in the oil and gas industry and include seismic and micro-seismic operations, reservoir simulation modeling, analyzing well performance data and geological and geophysical mapping.
Acreage and Productive Wells Summary
The following table sets forth our gross and net developed and undeveloped oil and natural gas leasehold acreage as of January 31, 2015:
Developed Acreage(1) | Undeveloped Acreage(2) | Total Acreage | |||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||
Appalachian Basin (3) | 265,640 | 181,195 | 296,412 | 248,884 | 562,052 | 430,079 | |||||||||||
| Williston Basin | 93,637 | 37,901 | 49,227 | 27,749 | 142,864 | 65,650 | |||||||||||
Other (4) | 1,777 | 880 | 618 | 546 | 2,395 | 1,426 | |||||||||||
| Total at January 31, 2015 | 361,054 | 219,976 | 346,257 | 277,179 | 707,311 | 497,155 | |||||||||||
(1) | Developed acreage is the number of acres allocated or assignable to producing wells or wells capable of production. |
(2) | Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage includes proved reserves. |
(3) | Approximately 55,585 gross acres and 48,207 net acres overlap in our Utica Shale and Marcellus Shale areas. The Appalachian Basin acreage in the table also includes acreage associated with our southern Appalachian Basin properties. |
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(4) | Pertains to certain miscellaneous properties in Texas and Louisiana. |
Substantially all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing lease is renewed or we have obtained production from the acreage subject to the lease before the end of the primary term; in which event, the lease will remain in effect until the cessation of production.
The following table sets forth the gross and net acres of undeveloped land subject to leases summarized in the preceding January 31, 2015 table that are not currently held by production and therefore will expire during the periods indicated below if not ultimately held by production by drilling efforts:
| Expiring Acreage | |||||||||||||||||||||||||||||
| 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||
Appalachian Basin (1) | 3,154 | 2,867 | 35,614 | 29,687 | 6,743 | 5,496 | 21,328 | 19,799 | 49,353 | 40,008 | 38 | 38 | |||||||||||||||||
| Williston Basin | 23,558 | 13,105 | 12,563 | 5,829 | 6,846 | 5,443 | 2,137 | 1,771 | — | — | — | — | |||||||||||||||||
Other (2) | — | — | 618 | 546 | — | — | — | — | — | — | — | — | |||||||||||||||||
| 26,712 | 15,972 | 48,795 | 36,062 | 13,589 | 10,939 | 23,465 | 21,570 | 49,353 | 40,008 | 38 | 38 | ||||||||||||||||||
(1) | Expiring acreage in the Appalachian Basin includes our southern Appalachian Basin properties located in Kentucky. |
(2) | Pertains to certain miscellaneous properties in Texas and Louisiana. |
Productive wells consist of producing wells and wells capable of production, including shut-in wells and gas wells awaiting pipeline connection to commence deliveries and oil wells awaiting connection to production facilities.
The following table sets forth the number of productive oil and gas wells attributable to the Company's properties as of January 31, 2015:
Producing Oil Wells | Producing Gas Wells | Total Producing Wells | |||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||
Appalachian Basin (1) | 714 | 633.9 | 2,689 | 1,873.4 | 3,403 | 2,507.3 | |||||||||||
| Williston Basin | 174 | 58.6 | — | — | 174 | 58.6 | |||||||||||
Other (2) | — | — | 3 | 1.2 | 3 | 1.2 | |||||||||||
| Total | 888 | 692.5 | 2,692 | 1,874.6 | 3,580 | 2,567.1 | |||||||||||
(1) | Includes wells associated with our southern Appalachian Basin properties located in Kentucky. |
(2) | Pertains to certain miscellaneous properties in Texas and Louisiana. |
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Drilling Results
The following table summarizes our drilling activity for the past three years. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells. All of our drilling activities were conducted on a contract basis by independent drilling contractors, except for certain of our activities in the Eagle Ford Shale, Marcellus Shale and Utica Shale where we also utilized the drilling equipment of our wholly-owned oil field services subsidiary.
| 2014 | 2013 | 2012 | |||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| Exploratory Wells: | |||||||||||||||||
| Productive | 17 | 9.3 | 15 | 4.1 | 55 | 19.2 | |||||||||||
| Unproductive | — | — | — | — | — | — | |||||||||||
| Total Exploratory | 17 | 9.3 | 15 | 4.1 | 55 | 19.2 | |||||||||||
| Developmental Wells: | |||||||||||||||||
| Productive | 54 | 30.0 | 86 | 36.3 | 84 | 33.5 | |||||||||||
| Unproductive | — | — | — | — | — | — | |||||||||||
| Total Development | 54 | 30.0 | 86 | 33.5 | 84 | 33.5 | |||||||||||
| Total wells | |||||||||||||||||
| Productive | 71 | 39.3 | 101 | 40.4 | 139 | 52.7 | |||||||||||
| Unproductive | — | — | — | — | — | — | |||||||||||
| Total wells | 71 | 39.3 | 101 | 40.4 | 139 | 52.7 | |||||||||||
Success Ratio (1) | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | |||||
(1) | The success ratio is calculated as follows: (total wells drilled—non-productive wells—wells awaiting completion) / (total wells drilled—wells awaiting completion). |
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Oil and Gas Production, Prices and Costs
The following table shows the approximate net production from continuing operations attributable to our oil and gas interests, the average sales price and the average lease operating expense, attributable to our total oil and gas production and for fields that contain 15% of our total proved reserves. Production and sales information relating to properties acquired is reflected in this table only since the closing date of the acquisition and may affect the comparability of the data between the periods presented.
| 2014 | 2013 | 2012 | ||||||||||
| Post Rock | Oil Production (Bbl) | 18,937 | 4,325 | 2,280 | ||||||||
| (Marcellus and Utica Shales) | Natural Gas Production (Mcf) | 7,048,360 | 4,442,449 | 4,434,407 | ||||||||
| NGLs Production (Bbl) | 273,517 | 150,283 | — | |||||||||
| Total Production (Boe) | 1,467,181 | 895,016 | 741,348 | |||||||||
| Oil Average Sales Price | $ | 70.96 | $ | 83.84 | $ | 72.79 | ||||||
| Natural Gas Average Sales Price | $ | 3.92 | $ | 3.98 | $ | 3.20 | ||||||
| NGLs Average Sales Price | $ | 50.17 | $ | 50.39 | $ | — | ||||||
| Average Production Costs per Boe | $ | 2.64 | $ | 3.37 | 2.35 | |||||||
| Average Transportation, Processing, and Other Related Costs per Boe | $ | 10.87 | $ | 8.70 | $ | 0.10 | ||||||
| Middlebourne Field | Oil Production (Bbl) | 130,415 | 56,815 | 48,299 | ||||||||
| (Marcellus and Utica Shales) | Natural Gas Production (Mcf) | 8,784,322 | 4,069,464 | 6,447,582 | ||||||||
| NGLs Production (Bbl) | 412,289 | 130,925 | 24,659 | |||||||||
| Total Production (Boe) | 2,006,757 | 865,984 | 1,147,555 | |||||||||
| Oil Average Sales Price | $ | 76.88 | $ | 82.63 | $ | 82.77 | ||||||
| Natural Gas Average Sales Price | $ | 4.27 | $ | 4.22 | $ | 3.29 | ||||||
| NGLs Average Sales Price | $ | 51.45 | $ | 50.88 | $ | 33.67 | ||||||
| Average Production Costs per Boe | $ | 2.04 | $ | 2.05 | $ | 1.24 | ||||||
| Average Transportation, Processing, and Other Related Costs per Boe | $ | 7.29 | $ | 6.86 | $ | 3.01 | ||||||
| Total Company | Oil Production (Bbl) | 1,569,522 | 1,641,426 | 993,399 | ||||||||
| Natural Gas Production (Mcf) | 21,787,942 | 13,211,556 | 14,289,108 | |||||||||
| NGLs Production (Bbl) | 960,018 | 437,534 | 154,317 | |||||||||
| Total Production (Boe) | 6,161,333 | 4,281,000 | 3,528,500 | |||||||||
| Oil Average Sales Price | $ | 83.53 | $ | 90.04 | $ | 82.77 | ||||||
| Natural Gas Average Sales Price | $ | 4.19 | $ | 4.07 | $ | 3.21 | ||||||
| NGLs Average Sales Price | $ | 48.04 | $ | 43.61 | $ | 36.79 | ||||||
| Average Production Costs per Boe | $ | 7.77 | $ | 10.91 | $ | 8.54 | ||||||
| Average Transportation, Processing, and Other Related Costs per Boe | $ | 7.03 | $ | 5.27 | $ | 3.05 | ||||||
Title to Properties
We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often only minimal investigation of record title is made at the initial time of lease acquisition. A more comprehensive mineral title opinion review, a topographic evaluation and infrastructure investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped leases. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include:
| i. | customary royalty interests; |
| ii. | liens incident to operating agreements and for current taxes; |
| iii. | obligations or duties under applicable laws; |
| iv. | development obligations under oil and gas leases; |
| v. | net profit interests; |
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| vi. | overriding royalty interests; |
| vii. | non-surface occupancy leases; and |
| viii. | lessor consents to placement of wells. |
Non-GAAP Measures; Reconciliations
This annual report contains certain financial measures that are non-GAAP measures. We have provided reconciliations within this report of the non-GAAP financial measures to the most directly comparable GAAP financial measures. These non-GAAP financial measures should be considered in addition to, but not as a substitute for, measures for financial performance prepared in accordance with GAAP that are presented in this report.
PV-10 is the present value of the estimated future cash flows from estimated total proved reserves after deducting estimated production and ad valorem taxes, future capital costs, abandonment costs, net of salvage value, and operating expenses, but before deducting any estimates of future income taxes. The estimated future cash flows are discounted at an annual rate of 10% to determine their “present value”. We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and 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 investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry. However, PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.
The standardized measure of discounted future net cash flows relating to our total proved oil and gas reserves as of December 31, 2014 is as follows:
| As of December 31, 2014 (unaudited) | |||
| (in thousands) | |||
| Future cash inflows | $ | 3,282,768 | |
| Future production costs | (1,443,121 | ) | |
| Future development costs | (219,509 | ) | |
| Future income tax expense | — | ||
| Future net cash flows | 1,620,138 | ||
| 10% annual discount for estimated timing of cash flows | (710,875 | ) | |
| Standardized measure of discounted future net cash flows related to proved reserves | $ | 909,263 | |
| Reconciliation of Non-GAAP Measure | |||
| PV-10 | $ | 909,263 | |
| Less income taxes: | |||
| Undiscounted future income taxes | — | ||
| 10% discount factor | — | ||
| Future discounted income taxes | — | ||
| Standardized measure of discounted future net cash flows | $ | 909,263 | |
PV-10 values are typically different from the standardized measure of proved reserves due to the inclusion in the standardized measure of estimated future income taxes. However, as a result of our net operating loss carryforwards of $710 million and other future expected tax deductions, the standardized measure of our proved reserves at December 31, 2014 of $909.3 million was the same as our PV-10 value.
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Competition
The oil and natural gas industry is highly competitive in all phases. We encounter competition from other oil and natural gas companies, including midstream services companies, in all areas of operation, including the acquisition of leases and properties, the securing of drilling, fracturing and other oilfield services and equipment and, with respect to our midstream operations, the acquisition of commitments from third party producers for the treating and gathering of natural gas. Our competitors include numerous independent oil and natural gas companies and individuals, as well as major international oil companies. Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resources than we do.
The prices of our products are driven by the world oil market and North American natural gas markets. Thus, competitive pricing behavior in this regard is considered unlikely. However, competition in the oil and natural gas exploration industry exists in the form of competition to acquire the most promising properties and obtain the most favorable prices for the costs of drilling and completing wells. Competition for the acquisition of oil and gas properties is intense with many properties available in a competitive bidding process in which we may lack technological information or expertise available to other bidders. Therefore, we may not be successful in acquiring and developing profitable properties in the face of this competition. Our ability to acquire additional properties in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in an efficient manner even in a highly competitive environment. See “Item 1A. Risk Factors—Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.”
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 grow. However, there can be no assurance that we can establish such relationships or that those relationships will result in increased availability of drilling rigs.
Governmental Regulation
Our oil and natural gas exploration, development and production activities, and our midstream services activities, are subject to extensive laws, rules and regulations promulgated by federal, state and foreign legislatures and agencies. Failure to comply with such laws, rules and regulations can result in substantial penalties, including the delay or stopping of our operations. The legislative and regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability.
Our exploration, development and production activities and our midstream services activities, including the construction, operation and maintenance of wells, pipelines, plants and other facilities and equipment for exploring for, developing, producing, treating, gathering, processing and storing oil, natural gas and other products, are subject to stringent federal, state, local and foreign laws and regulations governing environmental quality, including those relating to oil spills, pipeline ruptures and pollution control, which are constantly changing. Although such laws and regulations can increase the cost of planning, designing, installing and operating such facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with existing federal, state, local and foreign laws, rules and regulations governing the release of materials in the environment or otherwise relating to the protection of the environment, will not have a material effect upon our business operations, capital expenditures, operating results or competitive position. See “Item 1A. Risk Factors—Our operations expose us to substantial costs and liabilities with respect to environmental matters.”
We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions. The U.S. Environmental Protection Agency (“EPA”) recently asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. Additionally, the EPA is pursuing additional regulation of hydraulic fracturing activities under existing programs. On May 9, 2014, the EPA issued an Advance Notice of Proposed Rulemaking seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. EPA also announced that in 2015 it will release new Clean Water Act effluent guidelines applicable to unconventional oil and gas wastewater discharges. The U.S. Bureau of Land Management is expected to release in 2015 a final rule applicable to hydraulic fracturing operations on federal and tribal lands. In addition, legislation to provide for federal regulation of hydraulic fracturing is periodically been introduced in the U.S. Congress, but has never passed. The EPA is continuing to develop its comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. The EPA expects to release a draft of the report in early 2015 with a final peer-reviewed report expected in 2016. The results of such a study, once completed, could further spur action towards federal legislation and regulation of hydraulic fracturing activities. Several states, including Texas, have implemented, new
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regulations pertaining to hydraulic fracturing, including a requirement to disclose chemicals used in connection therewith. These existing and any future regulatory requirements may result in additional costs and operational restrictions and delays, which could have an adverse impact on our business, financial condition, results of operations and cash flows. In December 2014, the Governor of New York announced that the state would maintain its moratorium on hydraulic fracturing in the state. At the local level, some municipalities have passed zoning ordinances that prohibit oil and gas development and hydraulic fracturing in particular. See “Item 1A. Risk Factors-Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.”
Climate change has become the subject of an important public policy debate. Climate change remains a complex issue, with some scientific research suggesting that an increase in greenhouse gas emissions (“GHGs”) may pose a risk to society and the environment. The oil and natural gas exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane. On January 14, 2015, the White House announced a goal to reduce methane emissions from the oil and gas sector by 40-45% from 2012 emission levels by 2025. That same day and in support of the effort, EPA announced that it will release a proposed rule in the summer of 2015 that if finalized will directly regulate methane emissions from the oil and gas industry. The commercial risk associated with the production of fossil fuels lies in the uncertainty of government-imposed climate change legislation, including cap and trade schemes, and regulations that may affect us, our suppliers and our customers. The cost of meeting these requirements may have an adverse impact on our business, financial condition, results of operations and cash flows, and could reduce the demand for our products. See “Item 1A. Risk Factors-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.”
Formation
We were incorporated in the State of Delaware on June 4, 1997. In 2005, we began oil and gas operations under the name Petro Resources Corporation. In July 2009, we changed our name to Magnum Hunter Resources Corporation.
Employees
As of December 31, 2014, we had approximately 440 full-time employees. None of our employees is represented by a union. Management considers our relations with employees to be very good.
Facilities
Our principal executive offices are currently located in Houston, Texas, and consist of approximately 20,700 square feet of leased commercial office space. Our lease expires with respect to approximately 9,300 and 5,400 square feet of this space in April 2016 and May 2019, respectively.
We own a commercial office building in Grapevine, Texas containing approximately 10,200 square feet of office space and also lease approximately 3,400 square feet of office space in another commercial office building in Grapevine under a lease that expires in 2016. These offices house our principal accounting, financial reporting, information systems, and legal and human resources functions.
In August 2014, we announced our intention to relocate our corporate headquarters from Houston, Texas to the Dallas, Texas area. The Company’s finance, treasury and reserve engineering departments will be moving to the Dallas area as part of the corporate headquarters relocation. Additionally, we plan to consolidate our accounting, financial reporting, information systems, legal and human resources departments, which are currently located in Grapevine, Texas, to the new corporate headquarters. In connection with the corporate headquarters relocation, we entered into a sublease agreement to lease approximately 18,500 square feet of commercial office space in Irving (Las Colinas), Texas. We are currently building out that space and anticipate a move in date on or about April 9, 2015. The sublease expires on January 31, 2018.
The corporate headquarters for Eureka Hunter Holdings and its subsidiaries will remain in Houston, Texas. Eureka Hunter Pipeline also maintains two field offices in Reno, Ohio.
Our Appalachian Basin offices consist of approximately 22,000 square feet of office space in an approximately 29,000 square foot commercial office building we own in Marietta, Ohio, approximately 25,773 square feet of office and residential space in a multi-use building we own in Marietta, Ohio and an additional 7,800 square feet of field office space in buildings located on approximately 3.5 acres we own in Reno, Ohio. In addition, we own approximately 347 acres of undeveloped land in Tyler County, West Virginia and approximately 135 acres of undeveloped land in Ritchie County Ohio. We also occupy approximately 9,100 square feet of office space in a 45,000 square foot office building owned by us in Lexington, Kentucky. We also lease certain other field offices in Kentucky and West Virginia and an equipment storage yard in Kentucky.
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We maintain a field office and equipment storage yard on approximately 10 acres of land we own in Lavaca County, Texas related to our natural gas treating operations.
Segment Reporting; Major Customers
For information as to the geographic areas and industry segments in which we operate or (in the case of our former Canadian operations) operated, namely U.S. Upstream, Canadian Upstream, Midstream and Marketing, and Oil Field Services, see “Note 20 - Segment Reporting” in the notes to our consolidated financial statements included in this annual report. For information regarding our major customers for fiscal years 2014, 2013 and 2012, see “Note 16 - Major Customers” in the notes to our consolidated financial statements. This information is incorporated in this Item 1 by reference.
Available Information
Our principal executive offices are currently located at 777 Post Oak Blvd., Suite 650, Houston, Texas 77056. Our telephone number at this office is (832) 369-6986. We file annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a website that contains reports, proxy and information statements and other information that is electronically filed with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov.
We also make available free of charge on our website (www.magnumhunterresources.com) our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, any amendments to those reports and our proxy statements filed with or furnished to the SEC under the Exchange Act as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. Information on our website does not constitute part of this or any other report filed with or furnished to the SEC.
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GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a description of the meanings of some of the oil and natural gas industry terms used in this report.
| Bbl | Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons. |
| Bcf | Billion cubic feet of natural gas. |
| Boe | Barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
| Condensate | Hydrocarbons which are in the gaseous state under reservoir conditions and which become liquid when temperature or pressure is reduced. A mixture of pentanes and higher hydrocarbons. |
| DD&A | Depreciation, Depletion, Amortization & Accretion. |
| Development well | A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive. |
| EUR | Estimated ultimate recovery. |
| Exploratory well | A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir. |
| Field | An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. |
| Frac or fracing | Hydraulic fracturing, a common practice that is used to stimulate production of oil and natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into a formation to fracture the surrounding rock and stimulate production. |
| IP-24 hour or IP-24 | A measurement of the gross amount of production by a newly-opened well during the first 24 hours of production. |
| IP-7 day or IP-7 | A measurement of the average daily gross amount of production by a newly-opened well during the first seven days of production. |
| IP-30 day or IP-30 | A measurement of the average daily gross amount of production by a newly-opened well during the first 30 days of production. |
| LOE | Lease operating expense. |
| MBbl | Thousand barrels of crude oil or other liquid hydrocarbons. |
| MBoe | Thousand barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
| Mcf | Thousand cubic feet of natural gas. |
| Mcfe | Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
| MMBbl | Million barrels of crude oil or other liquid hydrocarbons. |
| MMBoe | Million barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
| MMBtu | Million British Thermal Units. |
| MMcf | Million cubic feet of natural gas. |
| NYMEX | New York Mercantile Exchange. |
| NGLs | Natural gas liquids, or liquid hydrocarbons found in association with natural gas. |
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| Proved oil and gas reserves | 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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. | |
| i. | The area of the reservoir considered as proved includes: (a) The area identified by drilling and limited by fluid contacts, if any, and (b) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. | |
| ii. | In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. | |
| iii. | Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. | |
| iv. | Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (a) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (b) The project has been approved for development by all necessary parties and entities, including governmental entities. | |
| v. | Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. For 2009 and subsequent years, the price shall be the average price during the 12-month period prior to the ending date of the period covered by the reserve report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. | |
| Proved developed oil and gas reserves | Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. | |
| Proved undeveloped oil and gas reserves | Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. | |
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| Probable reserves | Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. |
| Possible reserves | Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the Company believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. Where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. |
| R/P | The reserves to production ratio. The reserve portion of the ratio is the amount of a resource known to exist in an area and to be economically recoverable. The production portion of the ratio is the amount of resource used in one year at the current rate. |
| Secondary recovery | A recovery process that uses mechanisms other than the natural pressure of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase. |
| Standardized measure | The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment costs, net of salvage value, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes. |
| Water flood | A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil and enhance hydrocarbon recovery. |
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| Working interest | The operating interest that gives the owner thereof the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations. |
| /d | “Per day” when used with volumetric volumes. |
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| 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, 2014, we had incurred an accumulated deficit of $784.5 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.
Natural gas and oil prices declined dramatically in the third and fourth quarters of 2014. 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 natural gas and oil production heavily influence our revenue, profitability, access to capital and future rate of growth. Natural gas and oil 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 natural gas and oil have been extremely volatile. Recently, natural gas and oil prices have declined dramatically.
During the past five years, the NYMEX price for West Texas intermediate light sweet crude oil, which we refer to as NYMEX-WTI, has ranged from a low of $44.45 per Bbl, in January 2015 to a high of $113.93 per Bbl in April 2011. The Henry Hub spot market price of natural gas has ranged from a low of $1.82 per MMBtu in April 2012 to a high of $7.92 per MMBtu in March 2014. During 2014, NYMEX-WTI prices ranged from $53.27 to $107.26 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.75 to $7.92 per MMBtu. On January 30, 2015, the NYMEX-WTI price for crude oil was $48.24 per Bbl and the Henry Hub spot market price of natural gas was $2.68 per MMBtu, representing decreases of 55% and 66%, respectively, from the high of $107.26 per Bbl of oil and $7.92 per MMBtu for natural gas during 2014.
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:
| i. | the current uncertainty in the global economy; |
| ii. | changes in global supply and demand for oil and natural gas; |
| iii. | the condition of the U.S. and global economies; |
| iv. | the actions of certain foreign countries; |
| v. | the price and quantity of imports of foreign oil and natural gas; |
| vi. | political conditions, including embargoes, war or civil unrest in or affecting other oil producing activities of certain countries; |
| vii. | the level of global oil and natural gas exploration and production activity; |
| viii. | the level of global oil and natural gas inventories; |
| ix. | production or pricing decisions made by the Organization of Petroleum Exporting Countries, or OPEC; |
| x. | weather conditions; |
| xi. | technological advances affecting energy consumption; and |
| xii. | 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. In addition, a sustained decline in oil or natural gas prices might result in substantial downward estimates of our proved reserves. Our revolving credit facility and second lien term loan agreement contain financial covenants based on our
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levels of proved reserves and proved developed and producing reserves. In addition, the borrowing base of our revolving credit facility is based, in part, on our proved reserves. Reductions in our estimated proved reserves could result in our failure to satisfy these reserve coverage ratios, which could result in an event of default under the revolving credit facility and second lien term loan agreement, and could result in a reduction of our borrowing base under our revolving credit facility.
Drilling for and producing natural gas and oil 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 natural gas and oil 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:
| i. | delays imposed by or resulting from compliance with regulatory requirements; |
| ii. | unusual or unexpected geological formations; |
| iii. | pressure or irregularities in geological formations; |
| iv. | shortages of or delays in obtaining equipment and qualified personnel; |
| v. | equipment malfunctions, failures or accidents; |
| vi. | unexpected operational events and drilling conditions; |
| vii. | pipe or cement failures; |
| viii. | casing collapses; |
| ix. | lost or damaged oilfield drilling and service tools; |
| x. | loss of drilling fluid circulation; |
| xi. | uncontrollable flows of oil, natural gas and fluids; |
| xii. | fires and natural disasters; |
| xiii. | environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases; |
| xiv. | adverse weather conditions; |
| xv. | reductions in oil and natural gas prices; |
| xvi. | natural gas and oil property title problems; and |
| xvii. | market limitations for natural gas and oil. |
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 natural gas or oil 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 natural gas or oil 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 natural gas or oil will be present or, if present, whether natural gas or oil 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.
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We have relatively limited experience in drilling wells in the Marcellus and Utica Shale 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 relatively limited experience in the drilling and completion of Marcellus and Utica Shale formation wells, including relatively 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 and Utica Shale 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, 2015, our core natural gas reserves and operations are primarily located in West Virginia and Ohio. 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 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 natural gas and oil reserves are inherently imprecise. The process of estimating natural gas and oil 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 natural gas and oil 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 natural gas, natural gas liquids and oil 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, 2014 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:
| i. | actual prices we receive for oil and natural gas; |
| ii. | actual cost of development and production expenditures; |
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| iii. | the amount and timing of actual production; and |
| iv. | 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 and development 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 2014 of our common stock, private offerings in 2012 of our senior notes and, to a lesser extent, public (including years-past ATM) offerings of our common stock.
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, proceeds from non-core asset sales and potential joint venture or other strategic opportunities. However, our cash flow from operations and access to capital is subject to a number of variables, including:
| i. | the prices at which oil, natural gas and natural gas liquids are sold; |
| ii. | our proved reserves; |
| iii. | the amount of oil and natural gas we are able to produce from our wells; |
| iv. | our ability to acquire, locate and produce new reserves; and |
| v. | our ability to access capital markets at opportune times. |
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 and restrictions under our revolving credit facility and second lien term loan. 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.
Our indebtedness could adversely affect our financial condition and our ability to operate our business.
As of January 31, 2015, our total outstanding indebtedness was approximately $948.3 million. This indebtedness consisted primarily of outstanding letters of credit under our revolving credit facility and borrowings under our second lien term loan and our senior notes. 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:
| i. | it may be difficult for us to satisfy our obligations, including debt service requirements under our credit and other debt agreements, or maintain compliance with financial and other debt covenants; |
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| ii. | our ability to obtain additional financing for working capital, capital expenditures, debt service requirements and other general corporate purposes may be impaired; |
| iii. | 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; |
| iv. | 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 |
| v. | 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 financial and other 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.
Downgrades of our credit ratings could adversely affect our business and our results of operations and financial condition.
On January 16, 2015, Standard & Poor’s Ratings Services lowered our corporate credit rating from B- to CCC+, lowered its rating on our second lien term loan from B to B- and lowered its rating on our senior unsecured debt from CCC to CCC-, with negative outlook. The downgrade in these ratings was due in part to our current liquidity position and Standard & Poor’s revised pricing assumptions for oil and natural gas. Our credit ratings could be lowered further if our liquidity position worsens or if prices of natural gas and oil continue at their currently depressed levels or further decline. Reduced credit ratings could adversely affect the value of our outstanding securities, our existing debt and our ability to raise additional capital in the capital markets and could also make it more difficult for us to negotiate reasonable terms with our vendors and suppliers, which could adversely affect our business and our results of operations and financial position.
Restrictive covenants in our revolving credit facility, second lien credit agreement, 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, the second lien credit agreement and the indenture governing our senior notes contain certain covenants that, among other things, restrict our ability to, with certain exceptions:
| i. | incur indebtedness and issue preferred stock; |
| ii. | grant liens on our assets; |
| iii. | make certain restricted payments, including payment of dividends on our outstanding common and preferred stock; |
| iv. | change the nature of our business; |
| v. | acquire or make expenditures for oil and gas properties outside of the U.S. and Canada; |
| vi. | acquire certain assets or businesses or make certain asset sales; |
| vii. | dispose of all or substantially all our assets or enter into mergers, consolidations or similar transactions; |
| viii. | make investments, loans or advances; |
| ix. | enter into transactions with affiliates; |
| x. | create new subsidiaries; and |
| xi. | enter into certain derivatives transactions. |
The credit agreement governing our revolving credit facility requires us to satisfy certain financial covenants, including maintaining:
| i. | commencing with the fiscal quarter ending March 31, 2015, a current ratio (as defined in the credit agreement for our revolving credit facility) of not less than (a) 0.75 to 1.0 for the fiscal quarter ending March 31, 2015 and (b) 1.0 to 1.0 for the fiscal quarter ending June 30, 2015 and for each fiscal quarter ending thereafter; |
| ii. | a leverage ratio (secured net debt to EBITDAX (as defined in the credit agreement for our revolving credit facility) with, beginning with the fiscal quarter ending March 31, 2016, a limitation on netting of up to $100,000,000 of |
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unencumbered cash) of not more than (a) 2.50 to 1.00 as of the last day of the fiscal quarter ended December 31, 2014, (b) 2.50 to 1.00 as of the last day of the fiscal quarters ending March 31, June 30, September 30 and December 31, 2015 and (c) 2.00 to 1.00 as of the last day of each fiscal quarter ending thereafter; and
| iii. | a ratio of proved reserves to secured debt of not less than 1.5 to 1.0 (the “Proved Reserves Coverage Ratio”) and a ratio of proved developed and producing reserves to secured debt of not less than 1.0 to 1.0 (the “PDP Reserves Coverage Ratio”), each as of the last day of any fiscal quarter commencing with the fiscal quarter ended December 31, 2014. |
The second lien credit agreement also requires us to satisfy certain financial covenants, including maintaining:
| i. | the Proved Reserves Coverage Ratio and PDP Reserves Coverage Ratio described above; and |
| ii. | commencing with the fiscal quarter ending March 31, 2016, a leverage ratio (secured net debt to EBITDAX (as defined in the second lien credit agreement) with a limitation on netting of up to $100,000,000 of unencumbered cash) of not more than 2.5 to 1.0 as of the last day of any fiscal quarter for the trailing four-quarter period then ended. |
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.
Our failure to timely file certain periodic reports with the SEC in the future would limit our access to the public markets to raise debt or equity capital.
During 2013, we did not file within the time frames 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 Shale 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 were ineligible to use abbreviated and less costly SEC filings.
We have now timely filed all our required SEC reports for a period of twelve months, and we are now eligible to use abbreviated and less costly SEC filings to register our securities for sale. However, additional late SEC filings would limit 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.
In addition, we anticipate that the filing of this annual report will render us unable to use our currently effective universal shelf Form S-3 registration statement as we expect that, on the date of filing of this report, the Company will no longer meet the criteria of a Well-Known Seasoned Issuer under which the Form S-3 registration statement was originally filed as an automatic shelf registration statement. Accordingly, we are preparing to file a post-effective amendment to the existing registration statement to convert it to a non-automatic shelf registration statement to enable us to issue securities from time to time, including issuances of common stock, in ATM offerings. We plan to file the post-effective amendment to the registration statement during the first quarter of 2015. However, the post-effective amendment must be declared effective by the SEC and may be subject to review by the SEC, which review could delay our ability to raise debt or equity capital under the registration statement, and thus adversely affect access to financing at a time when such financing may be critical to our business.
A pending SEC investigation and pending securities 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
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sufficiency of our internal controls and our decisions to change auditors from Hein & Associates LLP to PricewaterhouseCoopers LLP, (“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,” in late 2013, certain class action cases that remained outstanding against the Company were consolidated (the “Securities Case”) in the United States District Court for the Southern District of New York. The complaints in the Securities Case alleged 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 Annual Report on Form 10-K for the fiscal year ended December 31, 2012 (which was filed by the Company with the SEC in June 2013), the dismissal of the Company’s previous independent registered accounting firm, and other matters. The complaints demanded 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.
On June 23, 2014, the United States District Court for the Southern District of New York issued an opinion and order granting the Company’s and the individual defendants’ motion to dismiss the Securities Case and, accordingly, the Securities Case has now been dismissed. The plaintiffs have appealed the decision to the U.S. Court of Appeals for the Second Circuit. We have incurred and may continue to incur significant professional fees and other costs defending the Securities Case. Depending on the outcome of the appeal, 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, as further described in “Item 3. Legal Proceedings,” we have one remaining stockholder derivative case outstanding. On March 19, 2014, Richard Harveth filed a stockholder derivative suit in the 125th District Court of Harris County, Texas on behalf of the Company against the Company’s directors and senior officers. This suit is referred to as the Derivative Case. The Derivative Case generally asserts 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 complaint demands 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. The Company is presently seeking dismissal of the Derivative Case.
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.
In addition, our board of directors, management and employees may spend a substantial amount of time on the 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.
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As a result of the outstanding SEC investigation, the Securities Case and the Derivative Case (and the other shareholder derivative cases that have been dismissed), 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 and global markets may have a material adverse impact on our business and financial condition that we currently cannot predict.
The United States 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. Economic production and business 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 natural gas and oil 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 natural gas and oil transportation arrangements may hinder our access to natural gas and oil markets or delay our production. The availability of a ready market for our natural gas and oil production depends on a number of factors, including the demand for and supply of natural gas and oil 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 natural gas or oil 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 natural gas and oil 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 and Utica Shale areas may not occur for lack of financing. In addition, capital constraints could limit the ability to build or expand gathering systems, such as the 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.
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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 our 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 440 full-time employees as of December 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:
| i. | the nature and timing of the operator’s drilling and other activities; |
| ii. | the timing and amount of required capital expenditures; |
| iii. | the operator’s geological and engineering expertise and financial resources; |
| iv. | the approval of other participants in drilling wells; and |
| v. | the operator’s selection of suitable technology. |
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Competition in the natural gas and oil 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 natural gas and oil, 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 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 and Utica 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 natural 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
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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.
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 (i) comprehensive general liability insurance, (ii) employer’s liability and workers' compensation insurance, (iii) automobile liability insurance, (iv) environmental insurance, (v) property insurance, (vi) directors' and officers' insurance, (vii) control of well insurance, (viii) pollution insurance and (ix) 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:
| i. | 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; |
| ii. | abnormally pressured formations; |
| iii. | mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses; |
| iv. | fires and explosions; |
| v. | personal injuries and death; and |
| vi. | natural disasters. |
Eureka Hunter Pipeline’s 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:
| i. | production is less than expected; |
| ii. | the counterparty to the derivative contract defaults on its contract obligations; or |
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| iii. | 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 and second lien term loan, 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, 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.
If the prices of natural gas and oil continue at current levels or further decline, we will not be able to hedge future production at the same level as our current derivative contracts and our results of operations and financial condition would be negatively impacted.
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 consolidated financial statements.
Write-downs of the carrying values of our oil and natural gas properties could occur if oil and gas prices remain depressed or decline further 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 senior 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, 2014, the Company recognized $118.5 million 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 $301.3 million for the year ended December 31, 2014, due primarily to the dramatic reduction in prices for oil and gas as well as 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, prices could remain depressed or decline further or other 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.
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There are restrictive covenants, governance and other provisions in the New LLC Agreement that may restrict the ability of Eureka Hunter Holdings to pursue its business strategies and our ability to exert influence over and manage the business and operations of Eureka Hunter Holdings and its subsidiaries.
We are involved in midstream operations through our substantial equity investment in Eureka Hunter Holdings. The New LLC Agreement contains certain covenants that, among other things, restrict the ability of Eureka Hunter Holdings and its subsidiaries to, with certain exceptions:
| i. | issue additional equity interests; |
| ii. | pay distributions to its owners, or repurchase or redeem any of its equity securities; |
| iii. | incur indebtedness; |
| iv. | modify, amend or terminate material contracts; |
| v. | make any material acquisitions, dispositions or divestitures; or |
| vi. | enter into a sale, merger, consolidation or other change of control transaction. |
Further, pursuant to the terms of the New LLC Agreement, the number and composition of the board of managers of Eureka Hunter Holdings may change over time based on MSI’s percentage ownership interest in Eureka Hunter Holdings, or the failure of Eureka Hunter Holdings to satisfy certain performance standards on and after December 31, 2018. Currently, the board of managers of Eureka Hunter Holdings is composed of six members, three of whom are designated by us and three of whom are designated by MSI. Any decrease in the proportion of members that we are entitled to designate to the board of managers of Eureka Hunter Holdings will adversely affect our ability to exert influence over and manage the business and operations of Eureka Hunter Holdings and its subsidiaries.
The New LLC Agreement also allows MSI, as the holder of the Series A-2 Units, to initiate a “Qualified Public Offering” of securities of Eureka Hunter Holdings at any time, so long as MSI holds at least a 20% of the total Class A Common Units in Eureka Hunter Holdings. A Qualified Public Offering means an underwritten initial public offering of securities of Eureka Hunter Holdings for which aggregate cash proceeds to be received by Eureka Hunter Holdings from such offering are at least $25 million and which results in equity securities of Eureka Hunter Holdings being listed on a national securities exchange.
The New LLC Agreement also contains transfer restrictions on Magnum Hunter’s ownership interests in Eureka Hunter Holdings (subject to certain exceptions) and certain “drag-along�� and “tag-along” rights in favor of MSI.
These restrictive covenants, governance and other provisions may restrict the ability of Eureka Hunter Holdings to pursue its business strategies and our ability to exert influence over and manage the business and operations of Eureka Hunter Holdings and its subsidiaries.
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 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 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 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.
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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.
Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the United States, including wetlands. The term “waters of the United States” has been broadly defined to include certain inland water bodies, including certain wetlands and intermittent streams. On April 21, 2014, the EPA proposed a new definition of “waters of the United States” that, if finalized, would tend to broaden rather than narrow the scope. As a result of a settlement reached in 2011, the United States Fish and Wildlife Service is required to make a determination on whether to list numerous species as endangered or threatened under the Endangered Species Act over the next several years. The final designation of previously unprotected species in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations, delays, or prohibitions on our exploration and production activities.
The Eureka Hunter Gas Gathering System and the expected future expansion of these operations by Eureka Hunter Pipeline are subject to additional governmental regulations.
Eureka Hunter Pipeline is currently continuing the construction of the 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. Eureka Hunter Pipeline has completed certain sections of the pipeline and anticipates 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 the control of Eureka Hunter Pipeline and require the expenditure of significant amounts of capital. There can be no assurance that pipeline construction projects will be completed on schedule or at the budgeted cost, or at all. The Eureka Hunter Gas Gathering System is also subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations can restrict or impact Eureka Hunter Pipeline’s business activities in many ways, including restricting the manner in which substances are disposed, 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 Eureka Hunter Pipeline’s business due to its handling of natural gas and other petroleum products, air emissions related to 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 Eureka Hunter Pipeline 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 compliance costs and the cost of any remediation that may become necessary. Eureka Hunter Pipeline 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.
The Obama Administration’s budget proposals for fiscal years 2015 and 2016 include proposals that would, among other things, eliminate or reduce certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures.
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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, 2014, we had net operating loss carry-forwards of approximately $710 million that expire in varying amounts through 2034. We have recorded a full valuation allowance against our net tax asset because we do not believe the net operating loss carry-forwards are realizable as of December 31, 2014. In addition, 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. Operations related to well stimulation, including hydraulic fracturing, are typically regulated by state oil and natural gas commissions. In guidance released in 2014, the EPA asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation 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 is periodically introduced in the U.S. Congress, but has never passed. On May 9, 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Several states, including Texas, have implemented, new regulations pertaining to hydraulic fracturing, including requirement to disclose 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. In the event state, local, or municipal legal restrictions are adopted in areas where we conduct operations, we may incur substantial costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. 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 2016. 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 in 2015. 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. The U.S. Department of the Interior, Bureau of Land Management (BLM) published a revised proposed rule on May 24, 2013 that would update existing regulation for hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. BLM is expected to release a final rule in 2015.
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,
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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. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions on all hydraulically-fractured wells constructed or refractured after January 1, 2015. On January 14, 2015, the White House announced a goal to reduce methane emissions from the oil and gas sector by 40-45% from 2012 emission levels by 2025. That same day and in support of the effort, EPA announced that it will release a proposed rule in the summer of 2015 that will directly regulate methane emissions from the oil and gas industry.
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 (“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. Those regulations were challenged in federal court. On June 23, 2014, the U.S. Supreme Court held that greenhouse gas emissions alone cannot trigger an obligation to obtain an air permit. However, the Supreme Court upheld the EPA’s authority to regulate GHG emissions from stationary sources, concluding sources that trigger air permitting requirements based on their traditional criteria pollutant emissions must include a limit for greenhouse gases in their permit. On June 2, 2014 the EPA unveiled proposed regulations to limit GHG emissions from existing power plants. The EPA has also 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.
In early 2014, President Obama announced the “Climate Action Plan,” a broad-based plan designed to cut carbon pollution. A major focus of that plan is methane emission reductions. In April 2014, the EPA announced that it was seeking input on how to best obtain additional methane reductions from potentially significant sources of methane and VOCs in the upstream oil and gas sector. The EPA released five technical white papers covering emissions from specific oil and gas sources and outlining potential mitigation techniques. The EPA has indicated that it plans to use the white papers to determine whether new regulations are needed to obtain additional reductions in emissions from these sources.
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
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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 human health and safety aspects of our operations, 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 well drilling, construction, completion, water management activities, 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 (“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 (“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. While rules proposed by the CFTC and federal banking regulators would allow for non-cash collateral and exemptions from margin for non-financial companies using swaps to hedge risk, the rules are not final and therefore some uncertainty remains. Many entities, including our counterparties, are now subject to significantly increased regulatory oversight which is expected to include, under regulations that are not yet final, 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 this regulatory regime once it is entirely in place, 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.
Any acquisitions we pursue present risks.
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:
| i. | estimated recoverable reserves; |
| ii. | exploration and development potential; |
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| iii. | future oil and natural gas prices; |
| iv. | operating costs; and |
| v. | 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 and Ohio regions, we may pursue acquisitions of properties located in other geographic areas.
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:
| i. | 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; |
| ii. | the unexpected loss of key employees or customers from acquired businesses; |
| iii. | difficulties resulting from our integration of the operations, systems and management of the acquired business; and |
| iv. | 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:
| i. | estimated recoverable reserves; |
| ii. | exploration and development potential; |
| iii. | future oil and natural gas prices; |
| iv. | operating costs; |
| v. | potential seller indemnification obligations; |
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| vi. | the creditworthiness of the buyer; and |
| vii. | 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 and Preferred 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 23, 2015, the last reported sale price of our common stock, as reported on the NYSE, was $2.66 per share. Recently, the price of our common stock has declined substantially. This decline correlates, in part, to the overall recent decline in natural gas and oil prices. The price of our common stock may be subject to further downward pressure if the prices of natural gas and oil continue at current levels or further decline.
Overall, 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 December 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 $9.27 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:
| i. | changes in oil and natural gas prices; |
| ii. | variations in quarterly drilling, production and operating results; |
| iii. | acquisitions and dispositions of assets; |
| iv. | results of our midstream operations; |
| v. | changes in financial estimates by securities analysts; |
| vi. | changes in market valuations of comparable companies; |
| vii. | additions or departures of key personnel; |
| viii. | the level of our overall indebtedness; |
| ix. | future issuances of our common stock and related dilution to existing stockholders; |
| x. | legal or regulatory proceedings or the threat thereof; and |
| xi. | 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.
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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, 2014, there were 200,505,749 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 5.4% of the outstanding shares of our common stock as of February 23, 2015.
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:
| i. | the ability of our board of directors to issue shares of our common stock and preferred stock without stockholder approval; |
| ii. | the ability of our board of directors to make, alter, or repeal our bylaws without stockholder approval; |
| iii. | 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; |
| iv. | 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 |
| v. | 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 General Corporation Law of the State of Delaware. 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 February 23, 2015, our board of directors and executive officers collectively beneficially owned approximately 5.4% 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
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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.
We may not be able to pay dividends on our preferred stock in the future.
Our Series C Cumulative Perpetual Preferred Stock, Series D Cumulative Preferred Stock, and Series E Cumulative Preferred Stock currently accrue dividends at annual rates of 10.25%, 8.0% and 8.0%, respectively. The credit agreement governing our revolving credit facility, the second lien credit agreement, and the indenture governing our senior notes contain certain covenants that, among other things, restrict our ability to make certain payments, including the payment of dividends on our preferred stock if there is an event of default under any of our credit facilities. There can be no assurance that we will be able to continue to pay dividends on our preferred stock in the future. If we fail to pay dividends on our preferred stock, (i) the market price of our preferred stock will likely be adversely affected; (ii) we will no longer be eligible to use the abbreviated and less costly Form S-3 registration statement to register our securities for sale; and (iii) we cannot pay dividends on any junior class of securities or repurchase or redeem any shares of a junior class of security. In addition, if we have four “Quarterly Dividend Defaults,” whether consecutive or non-consecutive, with respect to a series of preferred stock, then (i) the stated dividend rate of the series increases to a stated penalty rate, (ii) the series has the right to appoint two directors to our board and (iii) if not paid in cash, dividends must be paid in shares of common stock or (if the common stock is not publicly traded) in shares of the series of preferred stock (until the dividend default has been cured). A “Quarterly Dividend Default” is any failure to pay in full a monthly dividend within any quarterly dividend period.
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, and the vesting restrictions on our outstanding shares of restricted common stock may lapse, which would dilute our existing common stockholders.
As of December 31, 2014, we had:
| i. | outstanding warrants that had an exercise price of (a) $8.50 per warrant share and a final maturity of April 2016 and were exercisable for an aggregate of 17,030,622 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 2,142,858 shares of our common stock; |
| ii. | 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 13,194,956 shares of our common stock (and of which an aggregate of 9,140,323 stock options and stock appreciation rights, or approximately 69.3%, were exercisable as of December 31, 2014 and of which an aggregate of 176,225 stock options and stock appreciation rights, or approximately 1.3%, had exercise prices below $3.14, the closing sales price of our common stock on the NYSE on December 31, 2014; |
| iii. | 2,317,013 shares of restricted common stock that will vest in tranches over time through January 8, 2017; and |
| iv. | 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.
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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. | UNRESOLVED STAFF COMMENTS |
None.
| Item 2. | PROPERTIES |
The information required by Item 2. is contained in “Item 1. Business.”
| 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 were 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. The cases filed in the Southern District of New York were consolidated and have since been dismissed. The plaintiffs in the Securities Cases had 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 asserted 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 demanded 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. In January 2014, the Company and the individual defendants filed a motion to dismiss the Securities Cases. On June 23, 2014, the United States District Court for the Southern District of New York granted the Company’s and the individual defendants' motion to dismiss the Securities Cases and, accordingly, the Securities Cases have now been dismissed. The plaintiffs have appealed the decision to the U.S. Court of Appeals for the Second Circuit. The Company intends to continue vigorously defending 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. 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. 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. 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,
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2013, the Southern District of Texas allowed Joseph Vitellone to substitute for Mr. Bassett as plaintiff in that action. On March 19, 2014 Richard Harveth filed another stockholder derivative suit in the 125th District Court of Harris County, Texas. 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 20, 2013, the United States District Court for the Southern District of Texas granted the Company’s motion to dismiss the stockholder derivative case maintained by Joseph Vitellone and entered a final judgment of dismissal. The court held that Mr. Vitellone failed to plead particularized facts demonstrating that pre-suit demand on the Company’s board was excused. In addition, on December 13, 2013, the 151st Judicial District Court of Harris County, Texas dismissed the lawsuit filed by Steven Handshu for want of prosecution after the plaintiff failed to serve any defendant in that matter. On January 21, 2014, the Hanft complaint was dismissed with prejudice after the plaintiff in that action filed a voluntary motion for dismissal. On February 18, 2014, the United States District Judge for the District of Delaware granted the Company’s supplemental motion to dismiss the Derivative Case filed by Mark Respler. All of the Derivative Cases have now been dismissed, except the Derivative Case filed by Richard Harveth, for which the Company is presently seeking dismissal. It is possible 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 (“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, which has now been dismissed. It is possible that additional similar actions may be filed and that similar stockholder demands could be made.
In April 2013, the Company also received a 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 2013 letter. In 2014, the SEC issued additional subpoenas for documents and testimony and has taken testimony from certain individuals. The Company intends to cooperate with the subpoenas.
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 a case styled 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. In October 2014, in a case styled Exterran Energy Solutions, LP v. Eureka Hunter Pipeline, LLC and Magnum Hunter Resources Corporation, Civil Action No. 2014-63353, in the District Court of Harris County, Texas, Exterran Energy Solutions, LP, one of the co-defendants in the Phipps lawsuit, filed suit against the Company and Eureka Hunter Pipeline seeking a declaratory judgment that Eureka Hunter Pipeline is obligated to indemnify Exterran with respect to claims arising out of the incident. In April 2014, the estate of the other deceased third-party contractor employee sued the Company, Eureka Hunter Pipeline and certain other parties in a case styled Antoinette M. Miller v. Magnum Hunter Resources Corporation et al, Civil Action No. 14-C-111, in the Circuit Court of Ohio County, West Virginia. The plaintiffs allege 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 employees. The plaintiffs have demanded judgment for an unspecified amount of compensatory, general and punitive damages. Various cross-claims have been asserted. In May 2014, the injured third-party contractor employee sued Magnum Hunter Resources Corporation and certain other parties in a case styled Jonathan Whisenhunt v. Magnum Hunter Resources Corporation et al, Civil Action No. 14-C-135, in the Circuit Court of Ohio County, West Virginia. The claim filed by the injured third-party contractor employee, Jonathan Whisenhunt, has been resolved and dismissal of this case is anticipated in the near term. A portion of the settlement was paid by an insurer of Eureka Hunter Pipeline, and the remainder paid by the co-defendants or their insurers. The cross-claims among the defendants in the Whisenhunt litigation have not been resolved. 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
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incident. However, the Company believes that its insurance coverage will be sufficient to cover any losses or liabilities it may incur as a result of this incident.
PRC Williston Matter
On December 16, 2013, Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a D.B. Zwirn Special Opportunities Fund, L.P. (together, the “Plaintiffs”) filed suit against PRC Williston in the Court of Chancery of the State of Delaware. PRC Williston and the Plaintiffs entered into Participation Agreements in February 2007 in connection with the Plaintiffs extending credit to PRC Williston pursuant to a credit agreement entitling the Plaintiffs 12.5% collective interest in any distributions in respect of the equity interests of the members of PRC Williston. Plaintiffs claimed that they were entitled to compensation for 12.5% of alleged past distributions on equity from PRC Williston to Magnum Hunter and 12.5% of any transfers of funds to Magnum Hunter from the proceeds of the December 30, 2013 sale of PRC Williston’s assets. On December 23, 2013, the Chancery Court entered a temporary restraining order prohibiting PRC Williston from transferring, assigning, removing, distributing or otherwise displacing to Magnum Hunter, Magnum Hunter’s creditors, or any other person or entity, $5.0 million of the proceeds received by PRC Williston in connection with the sale of its assets. On March 18, 2014, the Court granted Plaintiff’s motion for a preliminary injunction, extending the relief granted by the temporary restraining order until after a full trial on the merits.
On July 24, 2014, the Company, PRC Williston, and the Plaintiffs executed a Settlement and Release Agreement (“the Settlement Agreement”). Per the terms of the Settlement Agreement, PRC Williston paid approximately $2.9 million in cash to Drawbridge Special Opportunities Fund LP. As a result of the Settlement Agreement, the Company, PRC Williston, and the Plaintiffs agreed to release each other from all claims, past, present or future, related to the dispute. In addition, with the execution of the Settlement Agreement, the parties agreed to terminate, in all respects, the Participation Agreements and that none of the parties would have any further rights or obligations thereunder. With the cash settlement payment and the termination of the Participation Agreements, the Company now has rights and claims to 100% of the equity interests in PRC Williston and its remaining assets and liabilities. Consequently, there is no longer any non-controlling interest in PRC Williston’s equity reflected in our consolidated financial statements.
| Item 4. | MINE SAFETY DISCLOSURES |
Not applicable.
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PART II
| 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 23, 2015, the last reported sale price of our common stock, as reported on the NYSE, was $2.66 per share.
| High | Low | ||||||
| 2015: | |||||||
| First quarter (through February 23, 2015) | $ | 3.43 | $ | 1.60 | |||
| 2014: | |||||||
| Fourth quarter | $ | 5.75 | $ | 2.75 | |||
| Third quarter | 8.32 | 5.19 | |||||
| Second quarter | 9.10 | 7.02 | |||||
| First quarter | 9.27 | 7.06 | |||||
| 2013: | |||||||
| Fourth quarter | $ | 8.12 | $ | 5.96 | |||
| Third quarter | 6.39 | 3.59 | |||||
| Second quarter | 4.27 | 2.37 | |||||
| First quarter | 4.69 | 3.61 | |||||
Holders
As of December 31, 2014, based on information from our transfer agent, American Stock Transfer and Trust Company, we had 331 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, second lien term loan, and the indenture governing our senior notes. It is anticipated that earnings, if any, will be retained for the future operation of our business.
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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, 2014:
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a)) | |||||||
| (a) | (b) | (c) | |||||||
| Equity compensation plans approved by security holders | 13,194,956 | $ | 5.91 | 3,269,562 | |||||
| Equity compensation plans not approved by security holders | — | — | — | ||||||
Total | 13,194,956 | $ | 5.91 | 3,269,562 | |||||
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 12 - 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, 2014 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, 2009, and that dividends were reinvested.
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COMPARISON OF FIVE YEAR CUMULATIVE TOTAL RETURNS
| December 31, | |||||||||||
| 2009 | 2010 | 2011 | 2012 | 2013 | 2014 | ||||||
| Magnum Hunter Resources Corporation | 100.00 | 464.52 | 347.74 | 257.42 | 471.61 | 202.58 | |||||
| S & P 500 | 100.00 | 115.06 | 117.49 | 136.30 | 180.44 | 205.14 | |||||
| Dow Jones US Expl & Production | 100.00 | 116.74 | 111.85 | 118.36 | 156.05 | 139.24 | |||||
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| 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. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Certain prior-year balances have been reclassified to correspond with current-year presentation. As a result of the Company’s decision in September 2014 to withdraw its plan to divest MHP and to cease all marketing efforts, the results of operations of MHP, which had previously been reported as a component of discontinued operations, have been reclassified to continuing operations for all periods presented. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations” to our consolidated financial statements.
Our consolidated financial statements and this selected financial data reflect the results of operations for Eureka Hunter Holdings for the period from January 1, 2014 up to December 18, 2014 and for all years preceding 2014 since the formation of Eureka Hunter Holdings. The deconsolidation of Eureka Hunter Holdings from the Company’s consolidated financial statements effective December 18, 2014 will have a material impact on the presentation of our assets, liabilities, and consolidated statement of operations since the Company began accounting for its investment in Eureka Hunter Holdings using the equity method of accounting effective December 18, 2014.
Prospectively from December 18, 2014, the impact of deconsolidation and change in accounting method, will result in the Company recording its investment in Eureka Hunter Holdings as a single financial caption in the consolidated balance sheet, and our proportionate share in earnings (loss) in Eureka Hunter Holdings will be recognized as a single financial caption in the consolidated statement of operations, whereas historically we have reported the separate assets, liabilities, revenue and expenses of Eureka Hunter Holdings in our consolidated financial statements. As a result of deconsolidation, we recorded a one-time gain on deconsolidation of approximately $510 million. See “Note 2 - Deconsolidation of Eureka Hunter Holdings” in our notes to our consolidated financial statements.
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| Year Ended December 31, | |||||||||||||||||||
| 2014 | 2013 | 2012 | 2011 | 2010 | |||||||||||||||
| (in thousands, except per-share data) | |||||||||||||||||||
| Statement of Operations Data | |||||||||||||||||||
| Revenues and other | $ | 391,469 | $ | 304,538 | $ | 159,937 | $ | 80,545 | $ | 28,609 | |||||||||
| Loss from continuing operations, net of tax | (137,833 | ) | (232,113 | ) | (129,357 | ) | (87,256 | ) | (19,613 | ) | |||||||||
| Income (loss) from discontinued operations, net of tax | 4,561 | (62,561 | ) | (9,773 | ) | 10,844 | 1,613 | ||||||||||||
| Gain (loss) on disposal of discontinued operations, net of tax | (13,855 | ) | 71,510 | 2,409 | — | 4,329 | |||||||||||||
| Net loss | (147,127 | ) | (223,164 | ) | (136,721 | ) | (76,412 | ) | (13,671 | ) | |||||||||
| Dividends on preferred stock | (54,707 | ) | (56,705 | ) | (34,706 | ) | (14,007 | ) | (2,467 | ) | |||||||||
| Loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units | (51,692 | ) | — | — | — | — | |||||||||||||
| Net loss attributable to common shareholders | $ | (249,873 | ) | $ | (278,881 | ) | $ | (167,414 | ) | $ | (90,668 | ) | $ | (16,267 | ) | ||||
| Basic and Diluted Earnings (Loss) Per Share | |||||||||||||||||||
| Continuing operations | $ | (1.27 | ) | $ | (1.69 | ) | $ | (1.03 | ) | $ | (0.90 | ) | $ | (0.34 | ) | ||||
| Discontinued operations | (0.05 | ) | 0.05 | (0.04 | ) | 0.10 | 0.09 | ||||||||||||
| Net loss per share | $ | (1.32 | ) | $ | (1.64 | ) | $ | (1.07 | ) | $ | (0.80 | ) | $ | (0.25 | ) | ||||
| Statement of Cash Flows Data | |||||||||||||||||||
| Net cash provided by (used in) | |||||||||||||||||||
| Operating activities | $ | (18,665 | ) | $ | 111,711 | $ | 58,011 | $ | 33,838 | $ | (1,168 | ) | |||||||
| Investing activities | (318,119 | ) | (127,860 | ) | (1,009,207 | ) | (361,715 | ) | (118,281 | ) | |||||||||
| Financing activities | 348,195 | 656 | 996,442 | 342,193 | 117,721 | ||||||||||||||
| Balance Sheet Data | |||||||||||||||||||
| Total assets | $ | 1,669,829 | $ | 1,856,651 | $ | 2,198,632 | $ | 1,168,760 | $ | 248,967 | |||||||||
| Long-term debt | 937,963 | 876,106 | 886,769 | 285,824 | 25,699 | ||||||||||||||
| Other long-term obligations | 31,566 | 109,275 | 155,677 | 124,609 | 4,834 | ||||||||||||||
| Redeemable preferred stock | 100,000 | 236,675 | 200,878 | 100,000 | 70,236 | ||||||||||||||
| Shareholders’ equity | $ | 431,855 | $ | 450,730 | $ | 711,652 | $ | 490,652 | $ | 103,322 | |||||||||
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| 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 gas company engaged primarily in the exploration for and the exploitation, acquisition, development and production of natural gas and natural gas liquids resources in the United States. We are focused in what we believe to be two of the most prolific unconventional shale resource plays in the United States, specifically, the Marcellus Shale in West Virginia and Ohio and the Utica Shale in southeastern Ohio and western West Virginia. We also own (i) primarily non-operated oil and gas properties in the Williston Basin/Bakken Shale in Divide County, North Dakota and (ii) operated natural gas properties in Kentucky. Through our substantial equity investment in Eureka Hunter Holdings, we are also involved in midstream operations, primarily in West Virginia and Ohio. Our wholly-owned subsidiary, Alpha Hunter, currently owns and operates six portable, trailer mounted drilling rigs, which are used both for our Appalachian Basin drilling operations and to provide drilling services to third parties.
As discussed in Item 1 - “Our Business”, our principal business strategy is to to (i) focus on high return projects in the liquids rich Marcellus Shale and the dry gas and liquids rich Utica Shale in West Virginia and Ohio, (ii) utilize our expertise in unconventional resource plays to improve our rates of return, (iii) focus on properties with operating control, (iv) continue development of the Eureka Hunter Gas Gathering System in West Virginia and Ohio, (v) selectively monetize assets at opportune times and attractive prices to the extent such assets are deemed non-core assets or we deem the disposition thereof desirable in furtherance of our principal business strategy and (vi) reduce costs in the current commodity price environment. We believe the increased scale in our core natural gas and natural gas liquids resource plays allows for ongoing cost recovery and production efficiencies as we exploit and monetize our asset base. We are focused on the further development and exploitation of our core acreage, selective bolt-on acquisitions of additional operated properties and mineral leasehold acreage positions in our core natural gas and natural gas liquids operating regions, continued development of midstream operations through our substantial equity investment in Eureka Hunter Holdings and the monetization of selected assets.
Financial and Operational Performance Highlights
The following are key financial and operational performance highlights for the Company for year ended December 31, 2014:
| i. | Oil and natural gas revenues from continuing operations increased by 21.7% to $268.5 million compared to $220.7 million for the year ended December 31, 2013. |
| ii. | We reported a net loss from continuing operations of $137.8 million, compared to a net loss from continuing operations of $232.1 million for the year ended December 31, 2013. |
| iii. | Our total oil and natural gas production from continuing operations increased to 16,879 Boe/d compared to 11,728 Boe/d for the year ended December 31, 2013. Such production for the year ended December 31, 2014 was comprised of 58.9% natural gas and 41.1% liquids. |
| iv. | We drilled and completed our first two Utica dry gas wells, the Stalder #3UH (~47% working interest) and the Stewart Winland #1300U (~100% working interest), which tested at peak rates of 32.5 MMcf of natural gas per day and 46.5 MMcf of natural gas per day, respectively. |
| v. | As of December 31, 2014, we had approximately 274,653 net leasehold acres in our core operating areas, including (a) approximately 79,683 net acres in the Marcellus Shale, (b) approximately 125,680 acres in the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage) and (c) approximately 69,290 net acres in the Williston Basin/Bakken Shale in North Dakota. |
| vi. | We completed in excess of $212 million in divestitures, including sales of our remaining Eagle Ford Shale properties in south Texas and certain non-core North Dakota properties (see “Business—Our Significant Recent Developments”); |
| vii. | Our capital expenditures of $700.6 million during 2014 increased from $570.7 million in 2013 as we focused our efforts on drilling in the Marcellus Shale and Utica Shale. |
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| viii. | In 2014, we issued 25,728,580 shares of our common stock in two separate private placements with aggregate net proceeds to the Company of $178.4 million, after deducting sales agent commissions and other issuance costs. |
As a result of recent divestitures throughout 2014, we are now strategically focused on our Marcellus Shale and Utica Shale plays in the Appalachian Basin in West Virginia and Ohio.
Comparability of the Company’s Consolidated Financial Statements
Our consolidated financial statements reflect the results of operations for Eureka Hunter Holdings for the period from January 1, 2014 up to December 18, 2014 and for the years ended December 31, 2013 and 2012. The deconsolidation of Eureka Hunter Holdings from the Company’s consolidated financial statements effective December 18, 2014 will have a materially different impact in future periods on the presentation of our consolidated assets, liabilities, revenues and expenses since the Company began accounting for its investment in Eureka Hunter Holdings using the equity method of accounting effective December 18, 2014.
Prospectively from December 18, 2014, the impact of deconsolidation and change in accounting method, will result in the Company recording its investment in Eureka Hunter Holdings as a single financial caption in the consolidated balance sheet, and our proportionate share in earnings (loss) in Eureka Hunter Holdings will be recognized as a single financial caption in the consolidated statements of operations, whereas historically we have reported the separate assets, liabilities, revenue and expenses of Eureka Hunter Holdings in our consolidated financial statements. As a result of deconsolidation, we recorded a one-time gain of approximately $510 million. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”, in the notes to our consolidated financial statements.
Additionally, certain prior-year balances have been reclassified to correspond with current-year presentation. Specifically, as a result of our decision in September 2014 to withdraw our plan to divest MHP and to cease all marketing efforts, the results of operations of MHP, which had previously been reported as a component of discontinued operations, have been reclassified to continuing operations for all periods presented.
Also, for all periods presented in the consolidated statements of operations, we have separately classified transportation and processing expenses incurred to deliver gas to processing plants and to selling points, which were previously included as components of lease operating expenses and severance taxes and marketing. The Company has renamed lease operating expenses as “Production costs” and presented transportation and processing expenses as “Transportation, processing, and other related costs” in order to provide more meaningful information on costs associated with production and development.
Market Update
During the third and fourth quarters of 2014, spot and future market prices for oil and natural gas experienced significant declines as markets reacted to macroeconomic factors related to, among others, oil supplies and increased production in the United States, the rate of economic growth domestically and internationally, and the oil production outlook provided by the Organization of Petroleum Exporting Countries (“OPEC”). In addition, the basis differential for natural gas prices in Appalachia widened against NYMEX natural gas prices during 2014. If prices continue to decline as a result of increased supply and volumes of natural gas in storage without sufficient takeaway capacity for this region, this could impact the amount of natural gas that companies are willing to produce until additional takeaway capacity becomes available.
During the three months ended December 31, 2014, our realized commodity sales prices declined substantially compared to the three month period ended September 30, 2014. These declines are consistent with overall declines observed in commodity markets in the United States. The table below shows the impact that volatility in the oil and natural gas markets has had on our realized prices over the past year.
| Average Realized Prices (U.S. Dollars) | ||||||||||||
| Year Ended | Three Months Ended | Year Ended | ||||||||||
| December 31, 2013 | March 31, 2014 | June 30, 2014 | September 30, 2014 | December 31, 2014 | December 31, 2014 | |||||||
| Oil (per Bbl) | 90.04 | 83.14 | 97.13 | 90.55 | 58.79 | 83.53 | ||||||
| Natural gas (per Mcf) | 4.07 | 5.56 | 5.13 | 3.43 | 2.87 | 4.19 | ||||||
| NGLs (per BOE) | 43.61 | 57.19 | 55.71 | 41.29 | 38.05 | 48.04 | ||||||
As a result of these declines in prices for commodities, the results of our operations for 2014 may not be indicative of results in 2015 as realized prices for production may remain low or continue to decline. The decline in market prices for oil and natural gas also triggered an impairment of our proved oil and gas properties of $301 million for the year ended December 31, 2014, the majority of
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which related to our working interests in oil and gas properties in the Williston Basin. Further declines in market prices may trigger additional impairments to our proved oil and gas properties, and decrease the cash flow generated from our upstream operations.
As of January 31, 2015, we had not shut-in any production as a result of the volatility in the current market prices for commodities. However, further declines in market prices may result in some wells becoming uneconomic to produce without a reduction in lifting costs.
We have also significantly reduced our upstream capital expenditure budget for 2015 to $100 million, most of which is targeted for the second half of the year in order to allow service cost reductions to catch up with the decline in commodity prices. However, market pricing for commodities will be a key factor in the actual amount and timing of our capital expenditures in 2015.
We expect that many oil and gas exploration and development companies will continue to reevaluate their capital spending for the coming year, and may decide to curtail further capital expenditures, which could impact our oilfield services segment. The Schramm T500XD drilling rig under contract to our wholly-owned subsidiary, Triad Hunter, LLC (“Triad Hunter”), will be temporarily idle for up to the next 30 to 60 days as a result of our reduction in capital spending and to allow service cost reductions to catch up with the decline in commodity prices. However, four of our T200XD drilling rigs are deployed for a third party under firm contracts through the end of 2015. In addition, although our other T200XD drilling rig, which was under a pad-by-pad contract, is now being temporarily demobilized, we expect to utilize this rig as part of our top-hole drilling program during 2015. As a result, we do not expect any reduced capital spending by third party producers to have a material adverse effect on our oilfield services business in 2015.
Liquidity and Capital Resources
Overview
We generally rely on cash generated from operations, borrowings under our credit facilities, proceeds from sales of assets and proceeds from the sale of securities in the capital markets, when market conditions are favorable, to meet 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 credit facilities, and more broadly, on our ability to access the capital markets, all of which are 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 credit facilities will be available, or available on acceptable terms, or at all, in the foreseeable future.
As of December 31, 2014, the outstanding principal amount of our debt, gross of unamortized discounts, was $961.4 million, of which $10.8 million becomes due in the next twelve months, and we had a working capital deficiency of $48.2 million. Additionally, as of December 31, 2014, we would not have been in compliance with our current ratio financial covenant under our revolving credit facility, which required that the Company have a current ratio of not less than 1.0 to 1.0 as of that date. We have obtained a waiver from our lenders, effective December 31, 2014, of the current ratio financial covenant requirement for the December 31, 2014 compliance period, and have entered into an amendment with our lenders that, among other things, lowers the current ratio requirement to 0.75 to 1.0 for the fiscal quarter ending March 31, 2015. The current ratio requirement increases to 1.0 to 1.0 for the fiscal quarter ending June 30, 2015 and each fiscal quarter ending thereafter. The amendment also modified the leverage ratio requirement to remain at not more than 2.5x beginning with the December 31, 2014 compliance period through the December 31, 2015 compliance period. We believe that these waivers and modifications to our financial covenant ratios as well as the successful execution of certain contemplated transactions discussed below will enable us to maintain compliance with such ratios for 2015.
Our failure to service any 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.
Our future capital resources and liquidity depend, in part, on our success in developing our oil and natural gas properties, growing production from our properties and increasing our proved reserves. Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proved reserves, which is typical in the capital-intensive oil and natural gas industry. We therefore continuously monitor our liquidity and evaluate our development plans in view of a variety of factors, including, but not limited to, our cash flows, capital resources, acquisition opportunities and drilling successes.
Our cash flow from operations is driven by commodity prices and production volumes, production costs, taxes, the effect of commodity derivatives and general and administrative expenses. Prices for oil and natural gas are primarily affected by national
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and international economic and political environments, national and global supply and demand for hydrocarbons, seasonal influences of weather and other factors beyond our control. During the fourth quarter of 2014, natural gas prices continued to decline due to a mild start to the winter which caused December storage numbers to increase when compared December 2013, and increases in overall production of natural gas from producers in the Marcellus and Utica Shale plays. Additionally, prices for crude oil, from which we derived over 48.8% of our oil and natural gas revenues for the year ended December 31, 2014, declined by 35.1% during that quarter. While we still have exposure to crude oil market prices, our properties now produce predominantly natural gas and NGLs and sales from these products will be a larger component of our overall revenues in 2015. These recent declines in market prices for commodities and certain natural gas transportation capacity restraints that have resulted in an oversupply of natural gas in the Appalachian Basin have resulted in lower realized prices for the year ended December 31, 2014 compared to prior periods.
Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices will cause us to (i) decrease our production volumes, if continued production will not be profitable based on such prices, and (ii) decrease our exploration and development expenditures, which may adversely affect future production volumes. Cash flows from operations are primarily used to fund exploration and development of our oil and natural gas properties and other capital expenditures. Although recent declines in market prices have affected our realized prices, we did not have to shut-in production from any of our wells during the year ended December 31, 2014 due to all existing production being deemed economic. However, we are taking a more restrained approach to outlays of our capital expenditures in 2015, with an approved capital expenditure budget of up to $100 million. We are also focusing on cost reductions within our organization, which has included the closing of our offices in Calgary, Alberta and Denver, Colorado in late January 2015. We anticipate that the closure of these offices will result in reductions to general and administrative expenses of approximately $2.5 million annually.
A prolonged period of low market prices for oil and natural gas, like the current commodity price environment, or further declines in the market prices for oil and natural gas, may result in certain of our wells being shut-in, capital expenditures being further curtailed, or a combination of both, until market prices recover sufficiently to provide acceptable economic returns on such wells. Our upstream capital expenditure budget is based upon our plans to further explore and develop our oil and natural gas interests, but we have flexibility in the timing of a substantial portion of our discretionary capital spending. Consequently, market conditions may cause us to defer certain capital projects to future periods.
We have historically utilized our revolving credit facility to fund a portion of our operating and capital needs, which facility is subject to periodic changes in the borrowing base based upon fluctuations in our proved reserves. On October 22, 2014, we substantially reduced the borrowing base of our revolving credit facility to $50 million, and obtained a second lien term loan for $340 million, the proceeds from which were used, in part, to pay off the outstanding balance on our revolving credit facility.
As of December 31, 2014, we had no outstanding borrowings under our revolving credit facility, but our borrowing capacity has been reduced by the amount of certain outstanding natural gas firm transportation letters of credit totaling $39.3 million. As a result, our borrowing capacity under the facility at December 31, 2014 was $10.7 million; however, we are constrained in the amount of additional indebtedness we may incur and still remain compliant with our proved reserves to secured debt ratio covenants required by our second lien term loan.
Factors that will affect our liquidity in 2015 include expected increases in production and operating cash flows associated with new and previously completed wells, which had been shut-in for a substantial portion of 2014 due to pad drilling. All of these wells are currently producing in early 2015. While the Company is currently evaluating the monetization of certain of our assets, market factors, including further declines in the prices of oil and natural gas, may result in postponement of such asset sales.
We intend to fund our 2015 upstream capital budget, excluding any acquisitions, from a combination of internally-generated cash flows, borrowings under our revolving credit facility, proceeds from capital markets transactions, to the extent we access such capital markets at opportune times, and asset sales. A substantial portion of our capital expenditures are discretionary in nature, and we may need to exercise flexibility in the timing and extent of such expenditures as a result of market conditions to manage our capital needs.
While we believe that our capital resources from existing cash balances, anticipated cash flow from operating activities, available borrowing capacity under our revolving credit facility, proceeds from future sales of assets and proceeds from capital market transactions, to the extent that we access such capital markets at opportune times, will be adequate to execute our corporate strategies and meet our debt services obligations in 2015, there are certain risks and uncertainties that could negatively impact our results of operations and financial condition. Although the Company is no longer exposed to significant reductions in our borrowing capacity from redeterminations of our borrowing base, we are constrained on the amount of additional borrowing that the Company may incur. Sustained declines in prices for commodities may also put downward pressure on cash provided from our operations.
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We expect that a combination of operating cash flows and financing, capital markets or other liquidity-generating transactions will be necessary to meet our fixed charges and capital commitments during the remainder of 2015, while also maintaining compliance with our debt financial covenant ratios. These transactions may include (i) entry into asset management agreements whereby a third party agrees to provide credit support to the interstate pipeline companies in replacement of our firm transportation letters of credit (an “AMA”), resulting in the cancellation of our outstanding firm transportation letters of credit and a corresponding increase in the borrowing capacity under our revolving credit facility, (ii) conducting sales of assets, including selling a portion of our equity interest in Eureka Hunter Holdings, (iii) issuing common stock through at the market (“ATM”) offerings under a Form S-3 registration statement, and/or (iv) entering into a joint venture under which we would sell or contribute all or a portion of our Utica Shale undeveloped leasehold acreage in Ohio to fund capital expenditures and provide working capital. However, our second lien term loan requires us to offer to pay our second lien term loan lenders a portion of the net proceeds received from certain sales of our assets to the extent the net proceeds from such sales exceed a cumulative total of $200 million, against which amount a total of approximately $125 million of net proceeds from 2014 asset sales have already been applied. Our revolving credit facility and our senior notes indenture also contain certain restrictions on asset sales. We believe the most likely sources of liquidity for 2015 to be the potential transactions outlined below. Although we believe these transactions can be completed, we have not entered into definitive agreements with respect to any of these transactions and cannot provide assurance that we will be able to consummate them on the terms contemplated or at all.
We are currently engaged in discussions with several third parties relating to a proposed AMA whereby we would enter into a natural gas marketing agreement with such third party during the first quarter of 2015 and, in connection therewith, the third party would substitute its credit support for our firm transportation letters of credit of $39.3 million, which would then be canceled, resulting in an increase in borrowing capacity under our revolving credit facility.
We have also initiated discussions to sell a portion of our equity interest in Eureka Hunter Holdings by the end of the second quarter of 2015, with such portion representing less than 8% of the outstanding common units of Eureka Hunter Holdings. Based on our current ownership interest in Eureka Hunter Holdings of approximately 48%, we anticipate that this transaction, if completed, could provide up to $75 million in additional liquidity, before (i) any repayment of debt under our second lien term loan required as a result of our receipt of more than an aggregate of $200 million in net proceeds from certain asset sales, as referred to above, and (ii) any potential increases in the borrowing base under our revolving credit facility that may occur as a result of any such repayment of second lien term loan debt (which increases would require the consent of the lenders under the revolving credit facility).
We have also commenced marketing activities to form a joint venture with a third party investor or investors for the further development of our undeveloped leasehold acreage in Ohio. We anticipate a joint venture agreement will be reached by the second quarter of 2015 providing for a total commitment by the investor of up to a total of approximately $500 million which would consist of an upfront cash payment by the investor and the remainder as a capital expenditure carry, whereby the investor would fund the Company’s pro rata share of the capital expenditures required to develop the acreage sold or contributed to the joint venture. We anticipate that the joint venture will be comprised of approximately 93,000 undeveloped net acres across the liquids rich and dry gas windows of the Utica Shale formation located in southeastern Ohio.
We anticipate that the filing of this annual report will render us unable to use our currently effective universal shelf Form S-3 registration statement as we expect that, on the date of filing of this report, the Company will no longer meet the criteria of a Well-Known Seasoned Issuer under which the Form S-3 registration statement was originally filed as an automatic shelf registration statement. Accordingly, we are preparing to file a post-effective amendment to the existing registration statement to enable us to issue securities from time to time, including issuances of common stock in ATM offerings. We plan to file the post-effective amendment to the registration statement during the first quarter of 2015. Based on the current market price of our common stock and the amount of available authorized but unissued shares of our common stock, the proceeds from potential ATM offerings could provide up to $225 million in additional liquidity, after the post-effective amendment to the registration statement is declared effective by the SEC and if market conditions at the time support such a transaction.
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Liquidity Position
We define liquidity as funds available under our revolving credit facility plus year-end cash and cash equivalents, excluding amounts held by our subsidiaries that are unrestricted subsidiaries under our revolving credit facility. The following table summarizes our liquidity position at December 31, 2014 compared to December 31, 2013:
| December 31, 2014 | December 31, 2013 | ||||||
| (in thousands) | |||||||
| Borrowing base under MHR senior revolving credit facility | $ | 50,000 | $ | 242,500 | |||
| Cash and cash equivalents | 53,180 | 33,669 | |||||
| Borrowings under MHR Senior Revolving Credit Facility | — | (218,000 | ) | ||||
| Letters of credit issued | (39,261 | ) | (7,225 | ) | |||
| Liquidity | $ | 63,919 | $ | 50,944 | |||
Liquidity Transactions
We continue to focus our efforts on improving our liquidity by (i) accessing the credit and capital markets where economic and when market conditions allow, (ii) focusing our exploration and development activities on our core oil and natural gas producing assets, (iii) marketing and divesting certain oil and natural gas assets, and (iv) reducing our non-essential general and administrative costs. During the year ended December 31, 2014, we closed on sales of non-core assets, accessed capital and credit markets and raised cash through private offerings of common stock for aggregate gross proceeds of approximately $526.3 million, as follows:
| i. | cash proceeds of approximately $15.5 million, before customary purchase price adjustments, and $9.4 million in common shares of NSE, from our sale of certain oil and natural gas assets in the Eagle Ford Shale area; |
| ii. | aggregate cash proceeds of approximately $178.4 million from the private placements of 25,728,580 shares of our common stock and 2,142,858 warrants to purchase common stock; |
| iii. | cash proceeds of approximately CAD $9.5 million (or US $8.7 million), from our sale of certain oil and natural gas assets in Alberta, Canada to BDJ Energy; |
| iv. | cash proceeds of approximately CAD $75.0 million (or US $68.8 million), from the sale of our 100% interest in WHI Canada, a wholly-owned subsidiary; |
| v. | aggregate cash proceeds of approximately $109.5 million from the sale of our ownership interests in certain non-operated oil and natural gas properties located in Divide County, North Dakota and Calhoun and Roane Counties, West Virginia, which occurred in three separate transactions; |
| vi. | cash proceeds of $81 million, net of $241 million used to pay off the outstanding balance of our revolving credit facility, from a new second lien term loan; and |
| vii. | cash proceeds of $55 million from the sale of an additional 5.5% interest in Eureka Hunter Holdings to MSI. |
Sources of Cash
For the year ended December 31, 2014, our primary sources of cash were proceeds received from the sales of assets, proceeds from issuances of common stock, and borrowings under our senior revolving credit facility and second lien term loan. We utilized $193.1 million of proceeds from the sale of assets, $178.4 million from issuances of common stock, and $629.4 million of borrowings under our revolving credit facility and other debt agreements to fund our acquisitions and drilling program, repay debt, and pay $45.6 million in dividends on our preferred stock.
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, $41.7 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 Eureka Hunter Holdings Series A Preferred Units 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
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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.
The following table summarizes our sources and uses of cash for the periods noted:
| Years Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| (in thousands) | ||||||||||||
| Cash flows provided by (used in) operating activities | $ | (18,665 | ) | $ | 111,711 | $ | 58,011 | |||||
| Cash flows used in investing activities | (318,119 | ) | (127,860 | ) | (1,009,207 | ) | ||||||
| Cash flows provided by financing activities | 348,195 | 656 | 996,442 | |||||||||
| Effect of foreign currency translation | 56 | (417 | ) | (2,474 | ) | |||||||
| Net increase (decrease) in cash and cash equivalents | $ | 11,467 | $ | (15,910 | ) | $ | 42,772 | |||||
Operating Activities
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, which the Company manages using derivative instruments, and significant declines in prices will cause us to (i) decrease our production volumes, if continued production will not be profitable based on such prices, and (ii) decrease our exploration and development expenditures, which may adversely affect our production volumes. Cash flows from operations are primarily used to fund exploration and development of our oil and natural gas properties and other capital expenditures.
Net cash used in operating activities for the year ended December 31, 2014 was $18.7 million. Net cash provided by operating activities for the years ended December 31, 2013 and 2012 was $111.7 million, and $58.0 million, respectively. The decrease in net cash provided by operating activities was primarily due to increases in payments of accounts payable and accrued liabilities. Cash provided by operating activities for the year ended December 31, 2014, included cash flows used by discontinued operations of $10.3 million. Cash provided by operating activities for the years ended December 31, 2013 and 2012 included cash flows provided by discontinued operations of $73.6 million, and $261.6 million, respectively. We do not expect the absence of cash flows from discontinued operations to have a material impact on future liquidity and capital resources.
Investing Activities
Our cash used in investing activities for the year ended December 31, 2014 was $318.1 million, principally from our drilling and completion programs in the Marcellus and Utica Shale plays as well as expansion programs for the Eureka Hunter Gas Gathering System. These net cash outflows were partially offset by cash proceeds from the sale of non-core assets and working interests of $193.1 million, including the sale of our 100% equity interest in WHI Canada, the sale of certain of our working interests in proved and unproved acreage in Divide County, North Dakota and a partial sale of our equity interest in Eureka Hunter Holdings.
Net cash used in investing activities during 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 Shale properties and certain North Dakota non-core properties.
Net cash used in investing activities during 2012 was $1.0 billion, 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,
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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.
Non-Cash Investing Items
During the year ended December 31, 2014, in connection with the sale of certain assets by Shale Hunter, LLC, we acquired 65,650,000 common shares of NSE, an Australian Securities Exchange listed Australian company, with a fair value of approximately $9.4 million upon acquisition.
Financing Activities
Net cash provided by financing activities was $348.2 million, $0.7 million and $996.4 million for the years ended December 31, 2014, 2013, and 2012, respectively. During 2014, the significant components of financing activities included $629.4 million of borrowings under our credit facilities and other debt agreements, and proceeds from the issuance of shares of common stock. We raised $178.4 million in net proceeds, after offering discounts, commissions and placement fees, but before other offering expenses, through private offerings of 25,728,580 shares of our common stock and 2,142,858 warrants to purchase common stock. These increases were partially offset by debt pay-down under our credit facilities and other debt agreements of $467.7 million. In addition, we paid preferred dividends of $45.6 million and paid deferred financing costs of $14.2 million during the year ended December 31, 2014.
During 2013, the significant components of financing activities included $374.0 million of borrowings under our credit facilities and other debt agreements, 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 on our preferred stock 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 on our preferred stock, $20.3 million in deferred financing costs, and $1.8 million to settle a contingency related to 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.
As of December 31, 2014, we had $597.4 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.
As a result of our failure to file our Annual Report on Form 10-K for the year ended December 31, 2012 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013 within the time frames required by the SEC, during 2014 we were limited in our ability to access the public markets to raise debt or equity capital. We have now timely filed all our required SEC reports for a period of twelve months, and we are now eligible to use abbreviated and less costly SEC filings, such as the SEC's Form S-3 registration statement, to register our securities for sale. Additionally, we are now able to file a shelf registration statement on Form S-3 to 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. On August 5, 2014, we filed an automatically effective universal shelf Form S-3 registration statement to register the sale of an unlimited amount of equity and debt securities. However, we anticipate that the filing of this annual report will render us unable to use the universal shelf Form S-3 registration statement as we expect that, on the date of filing of this report, the Company will no longer meet the criteria of a Well-Known Seasoned Issuer under which the Form S-3 registration statement was originally filed. Accordingly, we are preparing to file a post-effective amendment to the registration statement on Form S-3 to convert it to a non-automatic shelf registration statement to enable us to issue securities from time to time, including issuances of common stock in ATM offerings. We plan to file the new Form S-3 registration statement during the first quarter of 2015.
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Credit Facilities
Revolving Credit Facility
On December 13, 2013, the Company entered into a Third Amended and Restated Credit Agreement (“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 (“Prior Credit Agreement”).
On May 6, 2014, the Company and the other parties to the Credit Agreement entered into the First Amendment to Third Amended and Restated Credit Agreement (the “Amendment”). The Amendment increased the borrowing base from $232.5 million to $325.0 million in connection with the regular semi-annual redetermination of the Company's borrowing base derived from the Company's proved crude oil and natural gas reserves. The borrowing base may be increased or decreased in connection with such redeterminations up to a maximum commitment level of $750.0 million. The Amendment provided that such increased borrowing base may be reduced (i) by the lesser of $25.0 million or 50% of the net proceeds from issuances by the Company of common equity on or before July 1, 2014 (other than common equity issued pursuant to any stock incentive or stock option plan or any other compensatory arrangements); (ii) by certain specified reductions in connection with certain proposed asset dispositions; (iii) on July 1, 2014 by $25.0 million less any prior adjustment of the borrowing base due to an equity issuance as contemplated by clause (i); and (iv) by $0.25 for each $1.00 of any additional Senior Notes issued by the Company. The Amendment further provided that from May 6, 2014 through July 1, 2014 the Applicable Margin (as defined in the Credit Agreement) component of the interest charged on revolving borrowings under the Credit Agreement shall be 2.75% for ABR Loans (as defined in the Credit Agreement) and 3.75% for Eurodollar Loans (as defined in the Credit Agreement). From and after July 1, 2014 through the date of the Company’s delivery of a certificate for the quarter ended June 30, 2014, with respect to, among other things, the Company’s compliance with the covenants in the Credit Agreement (the “Compliance Certificate”), the Applicable Margin component of interest charged on revolving borrowings under the Credit Agreement would have ranged from 1.50% to 2.25% for ABR Loans and from 2.50% to 3.25% for Eurodollar Loans. From and after the Company’s delivery of the Compliance Certificate, the Applicable Margin component of interest charged on revolving borrowings under the Credit Agreement would have ranged from 1.00% to 1.75% for ABR Loans and from 2.00% to 2.75% for Eurodollar Loans.
In addition, the Amendment modified certain of the Credit Agreement’s financial covenants, including:
| i. | permitting the Company to take into account the borrowing base increase as though it occurred on March 31, 2014 for purposes of maintaining a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0; |
| ii. | providing for a ratio of EBITDAX to Interest Expense of not less than (a) 2.0 to 1.0 for the fiscal quarter ended March 31, 2014, (b) 2.25 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (c) 2.50 to 1.0 for the fiscal quarter ended December 31, 2014 and for each fiscal quarter ending thereafter; and |
| iii. | beginning with the fiscal quarter ended June 30, 2014, providing for a ratio of total Debt to EBITDAX of not more than (a) 4.75 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014, (b) 4.50 to 1.0 for the fiscal quarter ended December 31, 2014, and (c) 4.25 to 1.0 for the fiscal quarter ending March 31, 2015 and for each fiscal quarter ending thereafter. |
The Amendment also (i) amended the definition of EBITDAX and provided that certain acquisitions and dispositions be given pro forma effect in the calculation of EBITDAX; (ii) increased the letter of credit commitment from $10.0 million to $50.0 million and provided that outstanding letter of credit exposure not be included in certain determinations of Debt; (iii) required the total value of the Company’s oil and gas properties included in the reserve reports for the borrowing base determinations in which the lenders under the Credit Agreement have perfected liens be increased from 80% to 90%; and (iv) modified certain covenants in the Credit Agreement with respect to permitted investments by the Company to increase flexibility.
On October 22, 2014, the Company entered into the Fourth Amended and Restated Credit Agreement (“New Credit Agreement”), by and among the Company, as borrower, Bank of Montreal, as administrative agent, the lenders party thereto and the agents party thereto. The New Credit Agreement amended and restated the Credit Agreement, dated as of December 13, 2013, as amended.
The New Credit Agreement provides for an asset-based, senior secured revolving credit facility maturing October 22, 2018 (“Revolving Facility”) with an initial borrowing base of $50 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 $250 million. As discussed below,
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however, provisions of the Second Lien Term Loan Agreement limit the amount of indebtedness that the Company may incur under the New Credit Agreement.
The terms of the New Credit Agreement provide that the Revolving Facility may be used for loans, and subject to a $50 million sublimit, letters of credit. The New Credit Agreement provides for a commitment fee of 0.5% of the unused portion of the borrowing base 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 higher of (a) the Prime Rate (as determined by the Bank of Montreal), (b) the overnight federal funds effective rate, plus 0.50% per annum, and (c) the adjusted one-month LIBOR plus 1.00% or (ii) the adjusted LIBO Rate (which is based on LIBOR), plus, in each of the cases described in clauses (i) and (ii), an applicable margin ranging from 1.00% to 2.00% for ABR loans and from 2.00% to 3.00% for adjusted LIBO Rate loans. Accrued interest on each ABR loan is payable in arrears on the last day of each March, June, September and December and accrued interest on each adjusted LIBO Rate loan is payable in arrears on the last day of the Interest Period (as defined in the New Credit Agreement) applicable to the borrowing of which such adjusted LIBO Rate loan is a part and, in the case of an adjusted LIBO Rate borrowing with an Interest Period of more than three months’ duration, each day prior to the last day of such Interest Period that occurs at intervals of three months’ duration after the first day of such Interest Period.
The New 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 cash 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 New 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, (viii) enter into transactions with affiliates, and (ix) enter into hedging transactions.
In addition, the New Credit Agreement requires the Company to satisfy certain financial covenants, including maintaining:
| i. | commencing with the fiscal quarter ending March 31, 2015, a current ratio (as defined in the New Credit Agreement)of not less than (a) 0.75 to 1.0 for the fiscal quarter ending March 31, 2015 and (b) 1.0 to 1.0 for the fiscal quarter ending June 30, 2015 and for each fiscal quarter ending thereafter; |
| ii. | a leverage ratio (secured net debt to EBITDAX (as defined in the New Credit Agreement) with, beginning with the fiscal quarter ending March 31, 2016, a limitation on netting of up to $100,000,000 of unencumbered cash) of not more than (a) 2.5 to 1.0 as of the last day of the fiscal quarter ended December 31, 2014, (b) 2.50 to 1.00 as of the last day of the fiscal quarters ending March 31, June 30, September 30 and December 31, 2015 and (c) 2.0 to 1.0 as of the last day of the fiscal quarter ending March 31, 2016 and each fiscal quarter ending thereafter; and |
| iii. | the proved reserves based asset coverage ratios contained in the Second Lien Term Loan Agreement described below. |
At December 31, 2014, we would not have been in compliance with our current ratio financial covenant under the New Credit Agreement, which required that the Company maintain a current ratio of not less than 1.0 to 1.0 as of that date. We have obtained a waiver from our lenders, effective December 31, 2014, of the current ratio covenant requirement for the December 31, 2014 compliance period and have entered into a First Amendment to Credit Agreement and Limited Waiver, dated February 24, 2015 (the “First Amendment”), that, among other things, lowers the current ratio requirement to 0.75 to 1.0 for the fiscal quarter ending March 31, 2015. The current ratio requirement increases to 1.0 to 1.0 for the fiscal quarter ending June 30, 2015 and each fiscal quarter ending thereafter. The First Amendment also modified the leverage ratio requirement to remain at not more than 2.5 beginning with the December 31, 2014 compliance period through the December 31, 2015 compliance period. We believe that these waivers and modifications to our financial covenant ratios as well as the successful execution of certain contemplated transactions discussed above will enable us to maintain compliance with such ratios for 2015.
Pursuant to the First Amendment, until such time as the Company can demonstrate (i) a current ratio of 1.0 to 1.0 as of the last day of a fiscal quarter or, if there is a proposed Liquidity Event (described below) or other arms-length liquidity event with a non-affiliate or unrestricted subsidiary, demonstrate a current ratio of 1.0 to 1.0 on a pro forma basis as of the last day of a calendar month assuming that the Liquidity Event (or other liquidity event) had occurred during such calendar month and (ii) in the case of a decrease of the Rates for ABR Loans and Eurodollar Loans, pro forma compliance with the other applicable financial covenants as of the last day of the fiscal quarter most recently ended, (such period, the “Adjusted Period”), then:
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| i. | neither the Company nor any of its restricted subsidiaries may make additional investments in excess of $2 million in the aggregate in oil and gas properties (other than acreage swaps and associated assets) and other applicable assets; |
| ii. | neither the Company nor any of its restricted subsidiaries may make additional capital contributions to or other investments in unrestricted subsidiaries in amounts in excess of $2 million in the aggregate; and |
| iii. | the Company cannot make any additional capital contributions to or other investments in Eureka Hunter Holdings. |
For purposes of the First Amendment, a “Liquidity Event” means any event or events resulting in (i) an increase in Liquidity (as defined in the New Credit Agreement) of at least $36,000,000 as a result of an arm’s length transaction with a person or entity that is not an affiliate of the Company or (ii) the receipt by the Company or any restricted subsidiary of aggregate net cash proceeds of at least $73,000,000 as a result of one or more arm’s length transactions with either (a) persons or entities who are not affiliates of the Company or (c) the Company’s unrestricted subsidiaries.
In addition, effective March 31, 2015, if a Liquidity Event (described in clause (i) of the preceding paragraph) has not occurred prior to such date, or April 30, 2015 if a proposed Liquidity Event described in clause (ii) of the preceding paragraph for which a pro forma current ratio calculation is used has not occurred prior to such date, the rates for ABR Loans and Eurodollar Loans shall automatically increase by 1.00% and the commitment fee shall automatically increase by 0.25% and such elevated rates shall continue until the day immediately preceding the date on which the Adjusted Period ends.
The obligations of the Company under the New 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 New Credit Agreement) and any “Event of Default” under the Second Lien Term Loan Agreement, subject to certain cure periods.
Subject to certain exceptions, the Revolving Facility is secured by substantially all of the assets of the Company and its restricted subsidiaries, including, without limitation, no less than 90% of the present value (with a discount rate of 10%) of the proved oil and gas reserves of the Company and its restricted subsidiaries. Additionally, any collateral pledged as security for the Second Lien Term Loan (as defined below) is required to be pledged as security for the New Credit Agreement. In connection with the New 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.
Second Lien Term Loan
On October 22, 2014, the Company also entered into a Second Lien Credit Agreement (“Second Lien Term Loan Agreement”), by and among the Company, as borrower, Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent, the lenders party thereto and the agents party thereto.
The Second Lien Term Loan Agreement provides for a $340 million term loan facility (“Second Lien Term Loan”), secured by, subject to certain exceptions, a second lien on substantially all of the assets (except unproved leases) of the Company and its restricted subsidiaries. The entire $340 million Second Lien Term Loan was drawn on October 22, 2014, net of a discount of $10.2 million. The Company used the proceeds of the Second Lien Term Loan to repay amounts outstanding under its Credit Agreement, to pay transaction expenses related to the New Credit Agreement and the Second Lien Term Loan Agreement, and for working capital and general corporate purposes. Amounts borrowed under the Second Lien Term Loan that are repaid or prepaid may not be reborrowed. The Second Lien Term Loan has a maturity date of October 22, 2019 and amortizes (beginning December 31, 2014) in equal quarterly installments of principal in an aggregate annual amount equal to 1.00% of the original principal amount of the Second Lien Term Loan (equivalent to approximately $850,000 per quarter).
Borrowings under the Second Lien Term Loan will, at the Company’s election, bear interest at either (i) an alternate base rate (which is equal to the higher of (a) the prime rate (as determined by Credit Suisse AG), (b) the overnight federal funds effective rate, plus 0.50% per annum, and (c) the adjusted one-month LIBOR plus 1.00%) plus 6.50% or (ii) the adjusted LIBO Rate (which is based on LIBOR) plus 7.50%.
The Second Lien Term Loan Agreement contains negative covenants substantially similar to those in the New Credit Agreement 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) dispose of all or substantially all of its assets or enter into mergers, consolidations, or similar transactions; (iv) change the nature of its business; (v) make investments, loans, or advances or guarantee obligations; (vi) pay cash dividends or make certain other payments; (vii) enter into transactions with affiliates; (viii) enter into sale and leaseback transactions;
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(ix) enter into hedging transactions; and (x) amend its organizational documents or the New Credit Agreement. The Second Lien Term Loan Agreement limits the amount of indebtedness that the Company may incur under the New Credit Agreement to the greater of (i) the sum of $50 million plus the aggregate amount of loans repaid or prepaid under the Second Lien Term Loan Agreement and (ii) an amount equal to 25% of Adjusted Consolidated Net Tangible Assets (as defined in the Second Lien Term Loan Agreement) of the Company and its restricted subsidiaries; provided, in the case of clause (ii), after giving effect to such incurrence of indebtedness and the application of proceeds therefrom, aggregate secured debt may not exceed 25% of the Adjusted Consolidated Net Tangible Assets of the Company and its restricted subsidiaries as of the date of such incurrence.
The Second Lien Term Loan Agreement also requires the Company to satisfy certain financial covenants, including maintaining
| i. | a ratio of proved reserves to secured debt of not less than 1.5 to 1.0 and a ratio of proved developed and producing reserves to secured debt of not less than 1.0 to 1.0, each as of the last day of any fiscal quarter commencing with the fiscal quarter ended December 31, 2014; and |
| ii. | commencing with the fiscal quarter ending March 31, 2016, a leverage ratio (secured net debt to EBITDAX (as defined in the Second Lien Term Loan Agreement) with a limitation on netting of up to $100,000,000 of unencumbered cash) of not more than 2.5 to 1.0 as of the last day of any fiscal quarter for the trailing four-quarter period then ended. |
At December 31, 2014, the Company was in compliance with all of its financial covenants applicable for the period, contained in the Second Lien Term Loan.
The obligations of the Company under the Second Lien Term Loan may be accelerated upon the occurrence of an Event of Default (as defined in the Second Lien Term Loan Agreement). Events of Default are substantially similar to Events of Default under the Credit Agreement (except that a breach of a financial covenant under the New Credit Agreement will not constitute an Event of Default under the Second Lien Term Loan Agreement until acceleration of any borrowings under the New Credit Agreement) and include customary events for these types of financings.
In connection with the Second Lien Term Loan Agreement, the Company and its restricted subsidiaries also entered into customary ancillary agreements and arrangements, which among other things, provide that the Second Lien Term Loan is unconditionally guaranteed by such restricted subsidiaries.
The Company incurred direct financing costs associated with entering into the Amendment and the New Credit Agreement and the Second Lien Term Loan in the amount of $12.0 million, which are being deferred and amortized over the remaining term of the agreements.
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, 2014, 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
| i. | equal in right of payment to all of our existing and future senior unsecured indebtedness; |
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| ii. | 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; |
| iii. | 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, and TransTex), other than indebtedness and other liabilities owed to us; and |
| iv. | 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:
| i. | equal in right of payment to all existing and future senior unsecured indebtedness of the guarantor; |
| ii. | 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; |
| iii. | 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, and TransTex), other than indebtedness and other liabilities owed to us; and |
| iv. | 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:
| i. | incur or guarantee additional indebtedness or issue certain preferred stock; |
| ii. | pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness or make certain other restricted payments; |
| iii. | transfer or sell assets; |
| iv. | make loans and other investments; |
| v. | create or permit to exist certain liens; |
| vi. | enter into agreements that restrict dividends or other payments or distributions from our restricted subsidiaries to us; |
| vii. | consolidate, merge or transfer all or substantially all of our assets; |
| viii. | engage in transactions with affiliates; and |
| ix. | create unrestricted subsidiaries. |
These covenants are subject to certain exceptions and qualifications as described in the indenture. At December 31, 2014, 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
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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.
Results of Operations
Years ended December 31, 2014, 2013 and 2012
The following table sets forth summary information from continuing operations regarding oil, natural gas and NGLs 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 and Canadian operations have been excluded from the amounts below because they are reflected as discontinued operations for all years presented.
Certain prior-year balances have been reclassified to correspond with current-year presentation. As a result of the Company’s decision in September 2014 to withdraw its plan to divest MHP and to cease all marketing efforts, the results of operations of MHP, which had previously been reported as a component of discontinued operations, have been reclassified to continuing operations for all periods presented.
Also, for all periods presented in the consolidated statements of operations, we have separately classified transportation and processing expenses incurred to deliver gas to processing plants and to selling points, which were previously included as components of lease operating expenses and severance taxes and marketing. The Company has renamed lease operating expenses as “Production costs” and presented transportation and processing expenses as “Transportation, processing, and other related costs” in order to provide more meaningful information on costs associated with production and development.
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See the “Glossary of Oil and Natural Gas Terms” section of this annual report for explanations of the terms used below.
| Years Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| (in thousands except per unit) | ||||||||||||
| Oil and natural gas revenue and production | ||||||||||||
| Revenues (U.S. Dollars) | ||||||||||||
| Oil | $ | 131,109 | $ | 147,798 | $ | 82,225 | ||||||
| Natural gas | 91,277 | 53,821 | 45,825 | |||||||||
| NGLs | 46,115 | 19,080 | 5,678 | |||||||||
| Total oil and natural gas sales | $ | 268,501 | $ | 220,699 | $ | 133,728 | ||||||
| Production | ||||||||||||
| Oil (MBbl) | 1,570 | 1,641 | 993 | |||||||||
| Gas (MMcf) | 21,788 | 13,212 | 14,289 | |||||||||
| NGLs (MBoe) | 960 | 438 | 154 | |||||||||
| Total (MBoe) | 6,161 | 4,281 | 3,529 | |||||||||
| Boe/d | 16,879 | 11,728 | 9,643 | |||||||||
| Average prices (U.S. Dollars) | ||||||||||||
| Oil (per Bbl) | $ | 83.53 | $ | 90.04 | $ | 82.77 | ||||||
| Gas (per Mcf) | $ | 4.19 | $ | 4.07 | $ | 3.21 | ||||||
| NGLs (per Boe) | $ | 48.04 | $ | 43.61 | $ | 36.79 | ||||||
| Total average price (per Boe) | $ | 43.58 | $ | 51.55 | $ | 37.89 | ||||||
| Costs and expenses (per Boe) | ||||||||||||
| Production costs | $ | 7.77 | $ | 10.91 | $ | 8.54 | ||||||
| Severance tax and marketing | $ | 2.82 | $ | 4.27 | $ | 2.28 | ||||||
| Transportation, processing, and other related costs | $ | 7.03 | $ | 5.27 | $ | 3.05 | ||||||
| Exploration | $ | 19.24 | $ | 23.45 | $ | 22.78 | ||||||
| Impairment of proved oil and natural gas property | $ | 48.90 | $ | 11.68 | $ | 1.09 | ||||||
| Depletion, depreciation, and accretion | $ | 23.84 | $ | 25.08 | $ | 20.53 | ||||||
General and administrative expense (1) | $ | 17.64 | $ | 19.26 | $ | 17.67 | ||||||
| Other segments (in thousands) | ||||||||||||
| Midstream natural gas gathering, processing and marketing revenues | $ | 97,916 | $ | 61,178 | $ | 13,040 | ||||||
| Midstream natural gas gathering, processing and marketing expenses | $ | 84,764 | $ | 52,099 | $ | 8,028 | ||||||
| Oilfield services revenues | $ | 23,134 | $ | 18,431 | $ | 12,333 | ||||||
| Oilfield services expenses | $ | 15,686 | $ | 14,825 | $ | 10,037 | ||||||
_________________
| (1) | General and administrative expense includes: (i) acquisition related expenses of $27,000 (nominal per Boe) in 2014, $2.8 million ($0.64 per Boe) in 2013, and $4.7 million ($1.33 per Boe) in 2012; (ii) non-cash stock compensation expense of $12.5 million ($2.02 per Boe) in 2014, $13.6 million ($3.18 per Boe in 2013, and $15.7 million ($4.45 per Boe) in 2012; and (iii) a non-cash loss of $32.6 million in 2014 related to the downward adjustment of the Company’s equity interest in Eureka Hunter Holdings related to excess capital expenditures of Eureka Hunter Pipeline in 2014. See “Note 2 - Deconsolidation of Eureka Hunter Holdings” to the consolidated financial statements. |
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Years ended December 31, 2014 and 2013
Oil and natural gas production. Production increased by 43.9%, or 1,880 MBoe, to 6,161 MBoe for the year ended December 31, 2014 compared to 4,281 MBoe for the year ended December 31, 2013. Our average daily production was 16,879 Boe/d during 2014, representing an overall increase of 43.9%, or 5,151 Boe/d, compared to 11,728 Boe/d for 2013. Natural gas production from the Appalachian Basin alone increased from 12,962 MMcf for the year ended December 31, 2013 to 21,215 MMcf for the year ended December 31, 2014, an increase of 63.7%. Production of natural gas and NGLs was favorable during the 2014 period as a result of new Marcellus wells that began producing from the Collins, Spencer, Ormet, Stalder, and Mills Wetzel pads/units. Oil and NGLs production for the year ended December 31, 2014 was 2,530 MBoe versus 2,079 MBoe for the year ended December 31, 2013, an increase of 21.7%, primarily as a result of increased NGLs production. The increase in NGLs production in 2014 results from our Marcellus wells, which have a high liquid content. The additional wells coming on production during 2014 resulted in NGLs being comparably higher in 2014.
Further, production of oil declined in 2014 as the result of our divestiture of non-core properties from the Williston/Bakken fields. Production from the Williston/Bakken fields decreased 10.3%, from 1,284 MBbl in oil production during the year ended December 31, 2013 to 1,152 MBbl during the year ended December 31, 2014.
Total production for 2014, on a Boe basis, was 41.1% oil and NGLs and 58.9% natural gas compared to 48.6% oil and NGLs and 51.4% natural gas for 2013.
Oil and natural gas sales. Oil and natural gas sales increased 21.7%, or $47.8 million, for the year ended December 31, 2014 to $268.5 million from $220.7 million for the year ended December 31, 2013. The increase in oil and gas sales primarily resulted from higher production volumes from our Marcellus wells and the tie-in of certain wells in the Williston/Bakken fields to the Oneok gas gathering system. Our total sales prices were impacted by increases in prices received for natural gas and NGLs of 2.9% and 10.2%, respectively, offset by a decline in the price received for oil sales of 7.2%. Our natural gas sales benefited from increased production and higher demand due to a longer and colder winter in the northeastern United States. In addition, natural gas sales increased due to sales from our Collins, Mills Wetzel, Ormet, Spencer, Stewart Winland, and WVDNR wells in 2014, which were not on production until April and May of 2013. Of the total increase in oil and natural gas sales for the 2014 period, $51.3 million was attributable to our increase in production, offset by $3.4 million attributable to decreases in prices received. The prices we receive for our products are generally tied to commodity index prices.
Midstream natural gas gathering, processing, and marketing revenues. During the year ended December 31, 2013, the midstream operations segment consisted of Eureka Hunter Pipeline, TransTex, and Magnum Hunter Marketing operations. Following a series of transactions and capital contributions that occurred up to and including December 18, 2014, we no longer hold a controlling financial interest in Eureka Hunter Holdings, of which Eureka Hunter Pipeline and TransTex are wholly-owned subsidiaries. The results of operations of Eureka Hunter Holdings, including Eureka Hunter Pipeline and TransTex, have been included in our consolidated financial statements up to December 18, 2014. From December 18, 2014 through December 31, 2014, the results of our midstream operations segment consist only of Magnum Hunter Marketing operations.
Revenue from the midstream operations segment increased by $36.7 million, or 60.1%, for the year ended December 31, 2014 to $97.9 million from $61.2 million for the year ended December 31, 2013. TransTex revenues decreased by $3.5 million primarily as a result of inventory sales during the first quarter of 2013. Eureka Hunter Pipeline revenues increased by $14.3 million as a result of new growth in third party customer contracts as well as increased volumes of natural gas product gathered from its pipeline gathering system from existing customers. Eureka Hunter Pipeline increased throughput volumes by 170.8% or 47.7 million MMBtu for the year ended December 31, 2014 from 27.9 million MMBtu for the year ended December 31, 2013 to 75.6 million MMBtu for the year ended December 31, 2014. Magnum Hunter Marketing revenues increased by $26.2 million to $67.3 million during the year ended December 31, 2014 from $41.1 million during the year ended December 31, 2013. Magnum Hunter Marketing revenues increased primarily due to its marketing contract with Jaybee Oil & Gas (“Jaybee”), and also as a result of new customers, growth from existing customers, and increased gas and NGLs revenues from the MarkWest processing plant. Increases related to the marketing contract with Jaybee are not expected to continue, as Jaybee began marketing all of its natural gas production previously marketed by Magnum Hunter Marketing effective July 1, 2014. The loss of the marketing contract with Jaybee is not expected to have a significant impact on profits, as the margin on purchases and sales of Jaybee’s natural gas were insignificant overall.
Oilfield services revenue. Drilling services revenue increased by 25.5% or $4.7 million, for the year ended December 31, 2014 to $23.1 million from $18.4 million for the year ended December 31, 2013. This increase was primarily attributable to higher utilization of the fleet of rigs. During the year ended December 31, 2014, our drilling rig revenue days increased from 1,484 to 2,129 as compared to the year ended December 31, 2013. For the year ended December 31, 2014, the total effective equipment performance of our drilling rigs was 97%, and our rigs were 100% utilized. We have temporarily idled the drilling rig operating for Triad Hunter, a Schramm T500XD, for approximately 30 to 60 days. However, four of our T200XD drilling rigs are deployed for a third party under firm contracts through the end of 2015. In addition, although our other T200XD rig, which was under a pad-by-pad contract, is now
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being temporarily demobilized, we expect to utilize this rig as part of our top-hole drilling program during 2015. As a result, we do not expect any reduced capital spending by third party producers to have a material adverse effect on our oilfield services business in 2015.
Other revenue. Other revenues, consisting primarily of regulated retail gas billing revenues from the Appalachian region of the U.S. Upstream segment, decreased by $2.3 million for the year ended December 31, 2014.
Gain (loss) on sale of assets. We recorded a net gain on sale of assets of $2.5 million for the year ended December 31, 2014, compared to a net loss on sale of assets of $44.6 million for the year ended December 31, 2013. During the year ended December 31, 2014, gains of $5.5 million related to the sale of certain oil and natural gas properties located in Divide County, North Dakota and $2.7 million related to the sales of assets in Lewis, Calhoun and Roane Counties, West Virginia were partially offset by a loss of $4.5 million related to additional costs in 2014 associated with the divestiture of Eagle Ford Shale properties in South Texas in 2013. Of the total net loss on sale of assets recorded during the year ended December 31, 2013, $44.4 million related to the sale of certain of our properties in Burke County, North Dakota.
Production costs. Our production costs increased $1.2 million, or 2.5%, for the year ended December 31, 2014 to $47.9 million ($7.77 per Boe) from $46.7 million ($10.91 per Boe) for the year ended December 31, 2013. The increase in production costs was comprised of $20.5 million attributable to increased production volumes offset by $19.3 million attributable to lower costs/Boe and the sale of certain assets in the Williston Basin. Of the decrease in costs/Boe, $1.9 million and $14.3 million was due to lower recurring costs in the Appalachian and Williston Basins, respectively, and $3.1 million was due to lower non-recurring workover expenses primarily in the Williston Basin for the year ended December 31, 2014 as compared to the year ended December 31, 2013.
Severance taxes and marketing. Our severance taxes and marketing decreased by $0.9 million, or 5.1%, for the year ended December 31, 2014 to $17.3 million ($2.82 per Boe) from $18.3 million ($4.27 per Boe) for the year ended December 31, 2013. The decrease in severance taxes and marketing was attributable primarily lower taxes due to sales of certain oil and natural gas properties in the Williston Basin, partially offset by increases in our production and sales.
Transportation, processing, and other related costs. Our transportation, processing, and other related costs increased by $20.7 million, or 92.0%, for the year ended December 31, 2014 to $43.3 million ($7.03 per Boe) from $22.5 million ($5.27 per Boe) for the year ended December 31, 2013. The increase was attributable primarily to increased natural gas and NGLs production from our Appalachian properties as additional wells began producing during the year ended December 31, 2014.
Exploration. We record exploration costs, geological and geophysical costs, and unproved property impairments and leasehold expiration as exploration expense. We recorded $118.5 million of exploration expense for the year ended December 31, 2014, compared to $100.4 million for the year ended December 31, 2013. During 2014, the Company’s exploration expense was primarily attributable to $103.1 million of leasehold impairments relating to leases in the Williston Basin region that expired undrilled during the year ended December 31, 2014 or are expected to expire and that the Company does not plan to develop, and $10.0 million related to leases in the Appalachian Basin, a portion of which relates to the impairment of MHP’s carrying value upon reclassification into assets held for use and continuing operations as of September 30, 2014. The Company’s exploration expense during the year ended December 31, 2013 primarily related to leases in the Williston Basin.
Impairment of proved oil and natural gas properties. Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis bi-annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of our oil and natural gas properties and compare these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows.
During the year ended December 31, 2014, we recorded impairment of $261.3 million for proved oil and natural gas properties in the Williston Basin, $6.0 million for proved oil and natural gas properties in the Appalachian Basin, and $33.8 million for proved oil and natural gas properties in western Kentucky, a portion of which relates to the impairment of MHP’s carrying value upon reclassification into assets held for use and continuing operations as of September 30, 2014. During the year ended December 31, 2013, we recorded impairments on our proved oil and natural gas properties in the Williston and Appalachian Basins of $50.0 million. We calculated the estimated fair values using a discounted cash flow model. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.
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Midstream natural gas gathering, processing and marketing expenses. Expenses from the midstream operations increased $32.7 million or 62.7% to $84.8 million for the year ended December 31, 2014 from $52.1 million for the year ended December 31, 2013 due to increased cost of gas marketed by Magnum Hunter Marketing along with Eureka Hunter Holdings’ increased activities.
Oil field services expense. Oil field services expenses increased $0.9 million or 5.8% to $15.7 million for the year ended December 31, 2014 from $14.8 million for the year ended December 31, 2013.
Depletion, depreciation, amortization and accretion. Our DD&A increased $39.5 million, or 36.8% to $146.9 million for the year ended December 31, 2014 from $107.4 million for the year ended December 31, 2013 due to increases in accumulated costs from our capital expenditure and acquisition programs during 2013 and 2014, and increased production in 2014. Our DD&A/Boe decreased by $1.24 or 4.9%, to $23.84 Boe for the year ended December 31, 2014, compared to $25.08 Boe for the year ended December 31, 2013. The decrease in DD&A per Boe was primarily attributable to an increase in natural gas reserves. Natural gas wells generally have a lower DD&A rate on a Boe basis than oil and NGLs. The Company’s natural gas production increased significantly due to its drilling in the Appalachian Basin.
General and administrative. Our G&A increased $26.2 million, or 31.8% to $108.7 million ($17.64 per Boe) for the year ended December 31, 2014 from $82.5 million ($19.26 per Boe) for the year ended December 31, 2013. G&A expenses increased overall during 2014 mainly due to a one-time, non-cash charge of $32.6 million related to the Letter Agreement with MSI, in which our capital account with Eureka Hunter Holdings was adjusted downward by 1,227,182 Series A-1 Units in order to take into account certain excess capital expenditures incurred by Eureka Hunter Pipeline in connection with certain of its fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects. Excluding the one-time charge discussed above, G&A expenses decreased $6.4 million, or 7.8%, to $76.1 million ($12.35 per Boe) for the year ended December 31, 2014 compared to the year ended December 31, 2013, primarily due to decreases in share based compensation expense and 401k matching expense of $4.9 million. Decreases in professional services fees related to accounting and auditing services and consulting fees of $5.3 million were partially offset by increases in other professional services fees of $2.5 million. These decreases were offset by increases in various other general and administrative expenses of approximately $1.5 million.
Interest expense, net. Our interest expense, net of interest income, increased by 19.3%, from $72.4 million for the year ended December 31, 2013 to $86.3 million for the year ended December 31, 2014. Our higher average debt level during 2014 primarily accounted for $9.0 million of the increase, and higher amortization and write-off of deferred financing costs accounted for $4.9 million of the increase. We incurred a $2.2 million prepayment penalty through the early termination of credit agreements of Eureka Hunter Pipeline which was included in interest expense. In addition, interest expense includes the write-off of $2.7 million in unamortized deferred financing costs related to those terminated agreements, the write-off of $1.7 million in unamortized deferred financing costs related to the May 6, 2014 amendment of the MHR Senior Revolving Credit Facility, and the write-off of $1.4 million in unamortized deferred financing costs related to the October 22, 2014 New Credit Agreement. Interest expense was offset by capitalized interest of $2.0 million and $2.6 million during the years ended December 31, 2014 and 2013, respectively. We capitalize interest on projects lasting six months or longer.
Commodity and financial derivative activities. Our commodity and financial derivative activity resulted in net losses of $72.3 million and $25.3 million for the years ended December 31, 2014 and 2013, respectively. The following table summarizes the realized and unrealized gains and losses on change in fair value of our derivative contracts for the periods indicated:
| Years Ended December 31, | |||||||
| 2014 | 2013 | ||||||
| (in thousands) | |||||||
| Commodity derivatives | |||||||
| Realized gain (loss) on settled transactions | $ | 1,306 | $ | (8,216 | ) | ||
| Unrealized gain on open contracts | 18,236 | 869 | |||||
| Total commodity derivatives | 19,542 | (7,347 | ) | ||||
| Financial derivatives | |||||||
Loss on embedded derivatives(1) | (91,796 | ) | (17,927 | ) | |||
| Net loss | $ | (72,254 | ) | $ | (25,274 | ) | |
(1) | Substantially all of the losses associated with our embedded derivatives were associated with the Eureka Hunter Holdings’ Series A Preferred Units, which were extinguished on October 3, 2014. |
We do not designate our derivative instruments as hedges.
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At December 31, 2013, the Company had preferred stock embedded derivative liabilities resulting from certain conversion features, redemption options, and other features of our Eureka Hunter Holdings Series A Preferred Units. The Eureka Hunter Holdings Series A Preferred Units were converted at fair value to a new class of equity of Eureka Hunter Holdings on October 3, 2014, and the associated embedded derivative was extinguished upon conversion.
During 2014, we recognized losses on this embedded derivative of $91.8 million prior to the extinguishment of the host contract, compared to unrealized losses of $17.7 million in 2013. The increase in the losses recognized for the embedded derivative was driven primarily by increases in total enterprise value and a reduction in the expected term of the conversion feature. The fair value of the embedded derivative at the time of extinguishment of $173.2 million was included with the carrying value of the host contract in determining the loss on extinguishment of the Eureka Hunter Holdings Series A Preferred Units.
The change in expected term is the result of management’s assessment of the likely time horizon for which a liquidity event will occur resulting in conversion of the Eureka Hunter Holdings Series A Preferred Shares to Class A Common Units of Eureka Hunter Holdings. Multiple factors were considered in determining the expected term, which led to using a probability weighted average of the potential timing of a liquidity event. The recent adoption of Eureka Hunter Holdings’ LLC Management Incentive Compensation Plan, the payout under which is linked to a defined liquidity event, led to management’s assessment of the potential timing of a liquidity event. The weighting was based on the current market for master limited partnership initial public offerings. These factors impacted our assessment of the expected term, and resulted in a shorter time horizon input for purposes of the fair value calculation that was based on the weighted average of potential expected liquidity events.
The change in total enterprise value was also impacted significantly by the agreement reached between MSI and Ridgeline for MSI to purchase all of Ridgeline's equity interests in Eureka Hunter Holdings, and which closed in October 2014. Management considered the purchase price of that transaction in its determination of total enterprise value.
Also at December 31, 2014, the Company has recognized an asset for an embedded derivative asset related to a convertible security, due to the conversion feature of the promissory note received as partial consideration for the sale of Hunter Disposal. An unrealized loss of $4 thousand and $185 thousand is recorded for this embedded derivative instrument in the years ended December 31, 2014 and 2013, respectively. Both contracts originated in 2012 and have resulted in no cash outlays as of December 31, 2014.
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 realized and unrealized gains and losses on our consolidated statements of operations under the caption entitled “Gain (loss) on derivative contracts, net”.
Gain on deconsolidation. On October 3, 2014, MSI acquired all of the Series A Preferred Units and Class A Common Units of Eureka Hunter Holdings held by Ridgeline, which represented approximately 40.9% of the then outstanding equity units of Eureka Hunter Holdings. As a result of the New LLC Agreement becoming effective on October 3, 2014, the Eureka Hunter Holdings Series A Preferred Units and the Class A Common Units purchased by MSI from Ridgeline were converted into Series A-2 Common Units (“Series A-2 Units”), and were accounted for as a preferred equity interest, initially at fair value, by the Company. During the fourth quarter of 2014, MSI made further capital contributions to Eureka Hunter Holdings for which it received additional Series A-2 Units from Eureka Hunter Holdings and MSI purchased an approximate 5.5% equity interest in Eureka Hunter Holdings from the Company bringing MSI’s ownership interest in Eureka Hunter Holdings to 49.84% as of December 18, 2014. As a result of these transactions and other rights and preferences afforded to MSI, we determined that we no longer held a controlling financial interest in Eureka Hunter Holdings. We recognized a gain of $510 million from the deconsolidation of Eureka Hunter Holdings on December 18, 2014 as a result of these transactions. See “Note 2 - Deconsolidation of Eureka Hunter Holdings” to the consolidated financial statements.
Income tax benefit. The Company recorded no income tax or benefit during the year ended December 31, 2014 and recorded a net deferred tax benefit at the applicable statutory rates of $85.4 million during the year ended December 31, 2013, 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.
Income (loss) from discontinued operations, net of tax. 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 WHI Canada. The Company reflected these operations as discontinued operations, net of taxes, for all periods presented. The Company closed on the sale of its interests in WHI Canada during the second quarter of 2014. Tax benefit recognized as a result of discontinued operations was none and $11.8 million for years ended December 31, 2014 and 2013, respectively.
The Company recognized income from discontinued operations, net of tax, of $4.6 million for the year ended December 31, 2014 compared to a loss from discontinued operations, net of tax, of $62.6 million for the year ended December 31, 2013.
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The following table summarizes the income (loss) from discontinued operations for the periods indicated:
| Years Ended December 31, | |||||||
| 2014 | 2013 | ||||||
| (in thousands) | |||||||
| Eagle Ford Hunter | $ | — | $ | 14,732 | |||
| Williston Hunter Canada | 4,561 | (77,293 | ) | ||||
| $ | 4,561 | $ | (62,561 | ) | |||
Gain (loss) on disposal of discontinued operations, net of tax. The Company recognized a loss on disposal of discontinued operations of $13.9 million for the year ended December 31, 2014 and a gain on disposal of discontinued operations of $71.5 million for the year ended December 31, 2013. The following table summarizes the gain (loss) on disposal of discontinued operations for the periods indicated:
| Years Ended December 31, | |||||||
| 2014 | 2013 | ||||||
| (in thousands) | |||||||
| Eagle Ford Hunter | $ | (7,070 | ) | $ | 144,378 | ||
| Williston Hunter Canada | (6,785 | ) | (72,868 | ) | |||
| $ | (13,855 | ) | $ | 71,510 | |||
Net loss attributable to non-controlling interest. Net loss attributable to non-controlling interest was $3.7 million in 2014. Net loss attributable to non-controlling interest of $1.0 million in 2013 represented 12.5% of the net income or loss incurred by our subsidiary, PRC Williston, and 1.9% of the net loss incurred by our former subsidiary, Eureka Hunter Holdings.
On December 30, 2013, PRC Williston, in which the Company owned an 87.5% interest as of December 31, 2013, sold substantially all of its assets. On July 24, 2014, the Company executed a settlement and release agreement with Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a D.B. Zwirn Special Opportunities Fund, L.P. As a result of this settlement agreement, the Company now owns 100% of the equity interests in PRC Williston and has all rights and claims to its remaining assets and liabilities. Consequently, there is no longer any non-controlling interest in PRC Williston’s equity reflected in the consolidated financial statements as of December 31, 2014.
On October 3, 2014, all of the Eureka Hunter Holdings Series A Preferred Units and Class A Common Units held by MSI were converted into Series A-2 Units following their acquisition from Ridgeline. The Series A-2 Units held by MSI and the Class A Common Units (now Series A-1 Units) issued in connection with the TransTex acquisition represented non-controlling interests in Eureka Hunter Holdings in the Company’s consolidated balance sheet. As a result of the deconsolidation of Eureka Hunter Holdings, the Company derecognized the non-controlling interests attributed to Eureka Hunter Holdings as part of the gain on deconsolidation.
Dividends on preferred stock. Total dividends on our preferred stock were approximately $54.7 million in 2014 versus $56.7 million in 2013. The Series E Preferred Stock had a stated value of $95.1 million as of December 31, 2014 and 2013, and carries a cumulative dividend rate of 8.0% per annum. The Series D Preferred Stock had a stated value of $221.2 million at December 31, 2014 and 2013, 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, 2014 and 2013, and carries a cumulative dividend rate of 10.25% per annum. The Series A Preferred Units of Eureka Hunter Holdings had a liquidation preference of $200.6 million as of December 31, 2013, and carried a cumulative dividend rate of 8.0% per annum. During 2014, all of the Eureka Hunter Holdings Series A Preferred Units were converted into Series A-2 Units of Eureka Hunter Holdings.
Net loss attributable to common shareholders. Net loss attributable to common shareholders was $249.9 million in 2014 versus $278.9 million in 2013. Net loss attributable to common shareholders during the year ended December 31, 2014 includes loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units of $51.7 million. Our net loss per common share, basic and diluted, was $1.32 per share in 2014 compared to $1.64 per share in 2013. Our weighted average shares outstanding increased by 19.0 million shares, or 11%, to approximately 189.1 million shares, principally as a result of the shares issued for cash in private placements during March and May of 2014. Our net loss per share from continuing operations was $1.27 per share for the year ended December 31, 2014, compared to a loss from continuing operations of $1.69 per share for the year ended December 31, 2013.
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Years ended December 31, 2013 and 2012
Oil and natural gas production. Production increased by 21.3%, or 752 MBoe, to 4,281 MBoe for the year ended December 31, 2013 compared to 3,529 MBoe for the year ended December 31, 2012. Our average daily production was 11,728 Boe/d during 2013, representing an overall increase of 21.6%, or 2,085 Boe/d, compared to 9,643 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 NGLs. Production for 2013, on a Boe basis, was 48.6% oil and NGLs and 51.4% natural gas compared to 32.5% oil and NGLs and 67.5% 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 NGLs 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 NGLs, 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 increased 65.0%, or $87.0 million, for the year ended December 31, 2013 to $220.7 million from $133.7 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 $37.89 Boe to $51.55 Boe, or 36.1% primarily due to higher natural gas prices. The $87.0 million increase in revenues comprised an increase of approximately $60.6 million attributable to increased production volumes of 752 MBoe, and $26.3 million due to an increase in price of $13.66 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.
Midstream natural gas gathering, processing and marketing revenues. Revenue from the midstream operations segment (which, in 2013 and 2012, consisted of Eureka Hunter Pipeline, Magnum Hunter Marketing, and TransTex operations) increased by $48.1 million, or 369.2%, for the year ended December 31, 2013 to $61.2 million from $13.0 million for the year ended December 31, 2012. The increase by company was as follows: TransTex - $5.8 million; Eureka Hunter Pipeline - $5.2 million and Magnum Hunter Marketing - $36.7 million. TransTex 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 NGLs from the Mobley Processing Plant.
Oilfield services revenue. Oilfield services revenue increased by 49.4%, or $6.1 million, for the year ended December 31, 2013 to $18.4 million from $12.3 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 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 three rigs to our fleet.
Other revenue. 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.
Production costs. Our production costs increased $16.6 million, or 55.0%, for the year ended December 31, 2013 to $46.7 million ($10.91 Boe) from $30.1 million ($8.54 Boe) for the year ended December 31, 2012. The increase in production costs attributable to volume produced was $6.4 million and the increase related to increased costs/Boe was $10.1 million. Of the increase in costs/Boe, $1.3 million was due to increased non-recurring workover and well site reclamation costs in the Appalachian Basin. Also included is an increase of $3.7 million from the Williston Basin higher contribution to total production from higher cost stripper and non-operated properties and an increase of $3.1 million of Williston Basin electrification implementation costs. Various other costs contributed an additional $2.0 million of the increase in production costs during the year ended December 31, 2013 compared to the year ended December 31, 2012.
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Severance taxes and marketing. Our severance taxes and marketing increased by $10.2 million, or 127.3%, for the year ended December 31, 2013 to $18.3 million from $8.0 million for the year ended December 31, 2012. The increase in severance taxes and marketing was due to the increase in oil and gas sales as explained above.
Transportation, processing, and other related costs. Our transportation, processing, and other related costs increased by $11.8 million, or 109.3%, for the year ended December 31, 2013 to $22.5 million from $10.8 million for the year ended December 31, 2012. In late 2012, we began processing our Marcellus gas through the Mobley Processing Plant, causing processing costs to increase by $6.3 million during the year ended December 31, 2013. The remainder of the increase is due to increased NGLs production as additional wells began producing during the year ended December 31, 2013.
Exploration. We record exploration costs, geological and geophysical costs, and unproved property impairments and leasehold expiration as exploration expense. We recorded $100.4 million of exploration expense for the year ended December 31, 2013, compared to $80.4 million for the year ended December 31, 2012. During 2013, the Company’s exploration expense was primarily attributable to $98.9 million of impairments and expirations, which included $89.2 million, $6.8 million, and $3.0 million associated with the Company’s unproved properties in the Williston Basin, Appalachian Basin. and western Kentucky, 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, $2.2 million, and $1.4 million in the Williston Basin, Appalachian Basin, western Kentucky, and south Texas areas, respectively, and $2.6 million of geological and geophysical costs.
Impairment of proved oil and natural gas properties. We review for impairment our 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 $50.0 million consisting primarily of $8.5 million in the Williston Basin, $1.2 million in the Appalachian Basin, and $40.0 million in western Kentucky as compared to proved property impairment charges of $3.8 million in 2012, primarily in the Williston Basin. Our impairments related to western Kentucky in 2013 included $26.9 million of impairment to record the assets of MHP at the estimated selling price less costs to sell. Remaining impairments during 2013 were due to changes in production estimates and lease operating costs.
Midstream natural gas gathering, processing and marketing expenses. Midstream segment expense increased $44.1 million or 549.0% to $52.1 million for the year ended December 31, 2013 from $8.0 million for the year ended December 31, 2012 due the costs associated with the increases in revenue.
Oil field services expenses. Oil field services expense increased $4.8 million or 47.7% to $14.8 million for the year ended December 31, 2013 from $10.0 million for the year ended December 31, 2012 due to the addition of three rigs to our fleet.
Depletion, depreciation, amortization and accretion. Our DD&A increased $34.9 million, or 48.2% to $107.4 million for the year ended December 31, 2013 from $72.4 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 DD&A per Boe increased by $4.55, or 22.2%, to $25.08 per Boe for the year ended December 31, 2013, compared to $20.53 Boe for the year ended December 31, 2012. The increase in DD&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 G&A increased $20.1 million, or 32.3%, to $82.5 million ($19.26 Boe) for the year ended December 31, 2013 from $62.3 million ($17.67 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 ($3.18 Boe) for the year ended December 31, 2013 and $15.7 million ($4.45 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 and divestiture-related costs of $2.8 million ($0.64 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 ($1.33 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, net. Our interest expense, net of interest income, increased $20.7 million, or 40.1%, to $72.4 million for the year ended December 31, 2013 from $51.6 million for the year ended December 31, 2012. 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
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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.
Commodity and financial derivative activities. Our commodity and financial derivative activity resulted in a net loss of $25.3 million during the year ended December 31, 2013 compared with a gain of $22.2 million for the year ended December 31, 2012. The following table summarizes the realized and unrealized gains and losses on change in fair value of our derivative contracts for the periods indicated:
| Years Ended December 31, | |||||||
| 2013 | 2012 | ||||||
| (in thousands) | |||||||
| Commodity derivatives | |||||||
| Realized gain (loss) on settled transactions | $ | (8,216 | ) | $ | 11,294 | ||
| Unrealized gain on open contracts | 869 | 2,124 | |||||
| Total commodity derivatives | (7,347 | ) | 13,418 | ||||
| Financial derivatives | |||||||
Gain (loss) on embedded derivatives(1) | (17,927 | ) | 8,821 | ||||
| Net gain (loss) | $ | (25,274 | ) | $ | 22,239 | ||
(1) Substantially all of the gains and (losses) associated with our embedded derivatives were associated with the Eureka Hunter Holdings’ Series A Preferred Units.
We do not designate our derivative instruments as hedges.
At December 31, 2013, the Company had preferred stock embedded derivative liabilities resulting from certain conversion features, redemption options, and other features of Eureka Hunter Holdings’ Series A Preferred Units. 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. An unrealized loss of $0.2 million is recorded for this contract in 2013. Both derivative instruments originated in 2012 and resulted in no cash outlays during the year ended December 31, 2013.
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 realized and unrealized gains and losses on our consolidated statements of operations under the caption entitled, “Gain (loss) on derivative contracts, net”.
Deferred tax benefit. The Company recorded a net deferred tax benefit at the applicable statutory rates of $85.4 million and $24.7 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 discontinued operations, net of tax. On February 17, 2012, we closed the sale of Hunter Disposal, 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 December 31, 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 WHI Canada. 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 $11.8 million and $3.1 million for the years ended December 31, 2013 and 2012, respectively.
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Loss from discontinued operations, net of tax was $62.6 million and $9.8 million for the years ended December 31, 2013 and 2012, respectively. The following table summarizes the loss from discontinued operations for the periods indicated:
| Years Ended December 31, | |||||||
| 2013 | 2012 | ||||||
| (in thousands) | |||||||
| Eagle Ford Hunter | $ | 14,732 | $ | 18,086 | |||
| Hunter Disposal | — | 230 | |||||
| Williston Hunter Canada | (77,293 | ) | (28,089 | ) | |||
| $ | (62,561 | ) | $ | (9,773 | ) | ||
Gain on disposal of discontinued operations, net of tax. Gain on disposal of discontinued operations was $71.5 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 for the periods indicated:
| Years Ended December 31, | |||||||
| 2013 | 2012 | ||||||
| (in thousands) | |||||||
| Eagle Ford Hunter | $ | 144,378 | $ | — | |||
| Hunter Disposal | — | 2,409 | |||||
| Williston Hunter Canada | (72,868 | ) | — | ||||
| $ | 71,510 | $ | 2,409 | ||||
Net loss attributable to non-controlling interest. Net loss attributable to non-controlling interest was $1.0 million and $4.0 million in 2013 and 2012, respectively. 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 then majority-owned 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. Total dividends on our preferred stock 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, respectively, and carries a cumulative dividend rate of 10.25% per annum. The Series A 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 9.2%, to approximately 170.1 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 $1.69 per share for the year ended December 31, 2013, compared to a loss from continuing operations of $1.03 per share for the year ended December 31, 2012.
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Related Party Transactions
The following table sets forth the related party transaction activities for the years ended December 31, 2014, 2013 and 2012, respectively:
| Years Ended | |||||||||||||
| December 31, | |||||||||||||
| 2014 | 2013 | 2012 | |||||||||||
| (in thousands) | |||||||||||||
| GreenHunter Resources, Inc. | |||||||||||||
Salt water disposal (1) | $ | 4,682 | $ | 3,033 | $ | 2,400 | |||||||
Equipment rental (1) | 291 | 282 | 1,000 | ||||||||||
Gas gathering-trucking (1) | 652 | — | — | ||||||||||
MAG tank panels (1) | 800 | — | — | ||||||||||
| Office space rental | 44 | 13 | — | ||||||||||
Interest income from note receivable (2) | 154 | 205 | 191 | ||||||||||
Dividends earned from Series C shares (2) | 220 | 220 | — | ||||||||||
Unrealized gain/(loss) on investments (2) | 951 | 730 | 1,333 | ||||||||||
| Pilatus Hunter, LLC | |||||||||||||
Airplane rental expenses (3) | $ | 281 | $ | 166 | $ | 174 | |||||||
| Executive of the Company | |||||||||||||
Corporate apartment rental expense (4) | $ | — | $ | — | $ | 23 | |||||||
Eureka Hunter Holdings (5) | |||||||||||||
| Transportation costs | $ | 353 | $ | — | $ | — | |||||||
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| (1) | GreenHunter Resources, Inc. (“GreenHunter”) is an entity of which Gary C. Evans, our Chairman and CEO, is the Chairman, a major shareholder and interim CEO. Eagle Ford Hunter received, and Triad Hunter and Viking International Resources Co., Inc., wholly-owned subsidiaries of the Company, receive services related to brine water and rental equipment from affiliates of GreenHunter. 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 wholly-owned subsidiary, Hunter Disposal LLC, (“Hunter Disposal”), to an affiliate 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 was $75,000, and $79,000 at December 31, 2014 and December 31, 2013, respectively. See “Note 9 - Fair Value of Financial Instruments” for additional information. 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) | We 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 year ended December 31, 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. |
| (5) | Following a sequence of transactions up to and including December 18, 2014, the Company no longer held a controlling financial interest in Eureka Hunter Holdings. The Company deconsolidated Eureka Hunter Holdings and accounts for its retained interest as of December 31, 2014 under the equity method of accounting. See “Note 2 - Deconsolidation of Eureka Hunter Holdings” and “Note 10 - Investments and Derivatives”. |
In connection with the sale of Hunter Disposal to an affiliate of GreenHunter, Triad Hunter entered into agreements with Hunter Disposal and another affiliate of GreenHunter for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and the rental of tanks by Triad Hunter for a five-year term. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”. On December 22, 2014, Triad Hunter entered into an amendment to Produced Water Hauling and Disposal Agreement dated February 17, 2012 with the affiliate of GreenHunter to secure long-term water disposal at reduced rates through December 31, 2019. On December 29, 2014, Triad Hunter made a prepayment of $1.0 million towards services to be provided under the amendment. The GreenHunter affiliate will provide a 50% credit for all services until the prepayment amount is utilized in full, which is anticipated to occur in 2015.
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As of December 31, 2013, Mr. Evans, the Company's Chairman and Chief Executive Officer, held 27,641 Class A Common Units of Eureka Hunter Holdings. On October 3, 2014, in connection with the effectiveness of the New LLC Agreement, these Class A Common Units were converted into Series A-1 Units.
Triad Hunter and Eureka Hunter Pipeline are parties to an Amended and Restated Gas Gathering Services Agreement, which was executed on March 21, 2012, and amended on October 3, 2014 in connection with the effectiveness of the New LLC Agreement. Under the terms of the gas gathering agreement, Triad Hunter reserved throughput capacity on the gas gathering pipeline system of Eureka Hunter Holdings for which Triad Hunter has committed to a minimum reservation fee of approximately $0.75 per MMBtu. See “Note 18 - Commitments and Contingencies”.
In addition, the Company and Eureka Hunter Holdings entered into a Services Agreement on March 20, 2012, and amended on September 15, 2014, under which the Company agreed to provide administrative services to Eureka Hunter Holdings related to its operations. The terms of the Services Agreement provide that the Company will receive an administrative fee of $500,000 per annum and a personnel services fee equal to the Company’s employee cost plus 1.5% subject to mutually agreed upon increases from time to time. Under the terms of the New LLC Agreement, certain specified employees of the Company, for which the Company previously billed a personnel services fee, will become employees of Eureka Hunter Holdings or a subsidiary thereof on or before March 31, 2015, unless otherwise modified or amended. Upon the deconsolidation of Eureka Hunter Holdings on December 18, 2014, Eureka Hunter Pipeline became a related party.
On July 18, 2014, the Company entered into a consulting agreement with Kirk J. Trosclair, a former executive of Alpha Hunter, a wholly-owned subsidiary of the Company. Mr. Trosclair ceased employment with Alpha Hunter on July 18, 2014 and is currently the Chief Operating Officer of GreenHunter. The agreement has a term of 12 months and provides that Mr. Trosclair will receive monthly compensation of $10,000, and Mr. Trosclair is eligible to continue vesting in previously Company granted stock options and unvested restricted stock awards, subject to continued service under the consulting agreement. In connection with this agreement, for the year ended December 31, 2014, the Company paid Mr. Trosclair $71,000, which included reimbursement of expenses incurred on behalf of the Company.
Contractual Commitments
The following table summarizes our contractual commitments as of December 31, 2014 (in thousands):
| Contractual Obligations | Total | 2015 | 2016-2017 | 2018-2019 | After 2019 | |||||||||||||||
Long-term debt (1) | $ | 961,388 | $ | 10,770 | $ | 18,077 | $ | 329,716 | $ | 602,825 | ||||||||||
Interest on long-term debt (2) | 456,898 | 87,448 | 174,386 | 168,144 | 26,920 | |||||||||||||||
Gas transportation and compression contracts (3) | 120,514 | 11,567 | 23,158 | 23,134 | 62,655 | |||||||||||||||
Asset retirement obligations (4) | 26,524 | 295 | 9,536 | 2,769 | 13,924 | |||||||||||||||
| Operating lease obligations | 1,039 | 502 | 360 | 177 | — | |||||||||||||||
| Drilling rig installments | 5,200 | 5,200 | — | — | — | |||||||||||||||
| Contribution to Eureka Hunter Holdings | 13,300 | 13,300 | — | — | — | |||||||||||||||
| Total | $ | 1,584,863 | $ | 129,082 | $ | 225,517 | $ | 523,940 | $ | 706,324 | ||||||||||
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(1) | See “Note 11 - Long-Term Debt”, to our consolidated financial statements. |
(2) | Interest payments have been calculated by applying the interest rate in effect as of December 31, 2014 on the debt facilities in place as of December 31, 2014. This results in a weighted average per annum interest rate of 9.19%. |
(3) | Our obligations related to gas transportation and compression contracts increased from approximately $28.7 million as of December 31, 2013 to $120.5 million as of December 31, 2014 due to the inclusion of contracts with Eureka Hunter Pipeline, a formerly majority owned subsidiary which was deconsolidated as of December 18, 2014. As a result of the change in our accounting method for our investment in Eureka Hunter Holdings, all such contracts are being disclosed as transactions with affiliates and related parties. See “Note 2 - Deconsolidation of Eureka Hunter Holdings” and “Note 17 - Related Party Transactions”. Gas transportation and compression contracts in the table above do not include the commitments for firm transportation with TGT and REX as discussed below because the firm transportation agreements have not been signed. The execution of each firm transportation agreement is contingent upon TGT and REX, as applicable, receiving appropriate approvals from FERC. |
(4) | See “Note 8 - Asset Retirement Obligations” to our consolidated financial statements for a discussion of our asset retirement obligations. |
Under the terms of the Letter Agreement with MSI dated November 18, 2012, we agreed to make a $13.3 million capital contribution in cash to Eureka Hunter Holdings on or before March 31, 2015 in exchange for additional Series A-1 Units. However, we and MSI are currently engaged in discussions regarding Eureka Hunter Holdings’ 2015 capital expenditure budget, including the amount,
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timing and expected funding of the various anticipated capital expenditures. We anticipate that, as a result of these discussions, the parties will determine the priority, timing and (to the extent not funded by operating cash flows or borrowings) allocation between the parties of the funding of the anticipated expenditures that will most effectively serve the 2015 project plans of Eureka Hunter Pipeline. We also anticipate that, as part of these determinations, MSI will make the $13.3 million cash capital contribution referred to above in exchange for additional Series A-2 Units under the terms of the MSI carried interest provisions described below. See Item 7 “Management's Discussion and Analysis of Financial Condition and Results of Operations” for a description of our revolving credit facility, including a description of the restrictions under that facility on our ability to make investments in Eureka Hunter Holdings.
The Transaction Agreement and the Letter Agreement further provide that, if the members of Eureka Hunter Holdings approve a capital contribution for certain capital expenditures, and in connection therewith we validly exercise our right to not make our portion of such capital contribution, MSI will fund an amount in excess of its pro rata share of such capital contribution, which excess amount will equal the capital contribution not made by us. We refer to this as the “carried interest” provided by MSI. In such case, however, we have the right to make up our portion of such capital contribution, not to exceed $60 million in the aggregate, for a period of one year following the date of funding of the carried interest by MSI or until an MLP IPO (as defined in the New LLC Agreement), if earlier. See “Note 2 - Deconsolidation of Eureka Hunter Holdings” and “Note 22 - Subsequent Events” to our consolidated financial statements.
No dividends on preferred securities issued by the Company have been included in the table above because the total amounts to be paid are not determinable. See “Note 13 - Shareholders' Equity” and “Note 14 - Redeemable Preferred Stock” to our consolidated financial statements for further details regarding our obligations to preferred shareholders.
Commitments for Firm Transportation
Throughout 2014, Triad Hunter's natural gas production has been delivered into an over-supplied market in Appalachia, where natural gas has been trading at a significant discount to the Henry Hub Natural Gas spot price (“Henry Hub”). Triad Hunter has been exploring alternative natural gas transportation routes for delivery into markets where natural gas supply is more tempered with respect to demand. By accessing such markets, Triad Hunter expects the differential between Henry Hub pricing and our realized price for natural gas to improve.
On March 21, 2012, Triad Hunter entered into the Amended and Restated Gas Gathering Services Agreement with Eureka Hunter Pipeline. Through this contract, Triad Hunter committed to the payment of monthly reservation fees for certain maximum daily quantities of gas delivered each day for transportation under various individual transaction confirmations. In previous periods, Eureka Hunter Pipeline and Triad Hunter were both subsidiaries of the Company. Upon the deconsolidation of Eureka Hunter Holdings on December 18, 2014, Eureka Hunter Pipeline became a related party. As of December 31, 2014, Triad Hunter and Eureka Hunter Pipeline were parties to six individual transaction confirmations with terms ranging from eight to fourteen years. Triad Hunter’s maximum daily quantity committed was 135,000 MMBtu per day at an aggregate reservation fee of $0.75 per MMBtu. Triad Hunter’s remaining obligation under the contract was $98.0 million as of December 31, 2014.
On August 18, 2014, Triad Hunter executed a Precedent Agreement for Texas Gas Transmission LLC's (“TGT”) Northern Supply Access Line (the “TGT Transportation Services Agreement”). Pursuant to the TGT Transportation Services Agreement, Triad Hunter committed to purchase 100,000 MMBtu per day of firm transportation. The term of the TGT Transportation Services Agreement will commence on the date the pipeline project is available for service, currently anticipated to be in early 2017, and will end 15 years thereafter. The execution of a Firm Transportation Agreement (“FTA”) is contingent upon TGT receiving appropriate approvals from the Federal Energy Regulatory Commission (“FERC”) for its pipeline project. Upon executing an FTA, Triad Hunter will have minimum annual contractual obligations for reservation charges of approximately $12.8 million over the 15 year term of the agreement.
Additionally, on October 8, 2014, Triad Hunter and Rockies Express Pipeline LLC (“REX”) executed a Precedent Agreement (the “REX Transportation Services Agreement”) for the delivery by Triad Hunter and the transportation by REX of natural gas produced by Triad Hunter. Pursuant to the REX Transportation Services Agreement, Triad Hunter committed to purchase 100,000 MMBtu per day of firm transportation from REX. The term of the REX Transportation Services Agreement will commence on the date the pipeline project is available for service, currently anticipated to be between mid-2016 and mid-2017, and will end 15 years thereafter. The execution of an FTA is contingent upon REX receiving appropriate approvals from FERC for its pipeline project. Upon executing an FTA, Triad Hunter will have minimum annual contractual obligations for reservation charges of approximately $16.4 million over the 15 year term of the agreement.
Triad Hunter is required to provide credit support to TGT and REX under the provisions of their respective agreements, which may include letters of credit or specified cash collateral. In November 2014, Triad Hunter posted a $36.9 million letter of credit in
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accordance with the provisions of the REX Transportation Services Agreement. Additionally, in October 2015, Triad Hunter will be required to begin posting letters of credit related to the TGT Transportation Services Agreement of approximately $13 million, escalating thereafter up to $65 million by December 2016, assuming Triad Hunter retains this firm transportation agreement. This credit support is required to demonstrate Triad Hunter’s ability to pay the monthly reservation charges to REX and TGT upon completion and the entry into service of the respective pipeline extension projects.
Triad Hunter is currently engaged in discussions with third parties that have expressed an interest in executing an AMA. If such an AMA is entered into with a third party asset manager, we expect that, subject to TGT and REX counterparty consent, the third party asset manager would immediately step into Triad Hunter's credit support obligations with either TGT, REX, or possibly both, and would purchase Triad Hunter's natural gas at specified delivery points at negotiated prices, and would manage and schedule all of Triad Hunter's natural gas transportation agreements.
These agreements with TGT and REX will provide alternative routes for delivery of Triad Hunter's natural gas production into markets where there is not presently a surplus in supply, and is expected to improve the margins on our natural gas production.
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, 2014, the off-balance sheet arrangements and transactions that we have entered into include operating lease agreements and commitments to purchase firm transportation from third parties. 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 principles generally accepted in the United States of America (“GAAP”). The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported amounts of assets, liabilities, revenues and expenses. 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 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”.
Consolidation and Deconsolidation of Subsidiaries
The consolidated financial statements include the accounts of the Company and entities in which it holds a controlling financial interest. All significant intercompany balances and transactions are eliminated in consolidation. The Company deconsolidates entities in which it no longer holds a controlling financial interest as of the date control is lost and recognizes a gain or loss in accordance with the derecognition provisions of Accounting Standards Codification (“ASC”) Topic 810, Consolidation. The results of operations and assets and liabilities are included in the Company’s consolidated financial statements with all significant intercompany balances eliminated through the date of deconsolidation. Subsequently, retained interests in an entity, if any, are initially measured at fair value and accounted for based on the nature of the retained interest in accordance with GAAP.
Investments in affiliates
Investments in non-controlled affiliates over which the Company is able to exercise significant influence but not control are accounted for under the equity method of accounting. Under the equity method of accounting, the Company’s share of the investee’s underlying net income or loss is recorded as earnings (loss) from equity method investment. Distributions received from the investment reduce the Company’s investment balance. When an investee accounted for using the equity method issues its own shares or when the Company sells a portion of its interest in the investee that results in a reduction in the Company's interest in the investee a gain or loss is recognized equal to the proportionate change in the Company’s interest in the investee’s net assets. Investments in equity method investees are evaluated for impairment as events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If a decline in the value of an equity method investment is determined to be other than temporary, a loss is recorded.
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Oil and Gas Activities—Successful Efforts
We follow 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 we determine 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 as a normal retirement with no resulting gain or loss recognized in income if the amortization rate is not significantly affected; otherwise it is accounted for as the sale of an asset and a gain or loss is recognized. A sale of an entire field is generally assessed for treatment as a discontinued operation.
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 proved developed producing reserves.
Unproved oil and gas leasehold costs that are individually significant are periodically assessed for impairment of value by comparing current quotes and recent acquisitions, future lease expirations, 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 in the consolidated statements of operations.
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 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 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. We record these advance payments in the property accounts. 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.
Proved 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:
| i. | the quality and quantity of available data; |
| ii. | the interpretation of that data; |
| iii. | the accuracy of various mandated economic assumptions; and |
| iv. | 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, 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.
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The estimates of proved reserves materially impact depreciation, depletion, amortization and accretion (“DD&A”) expense. If the estimates of proved reserves decline, the rate at which we record DD&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.
See also “Business” and “Properties—Proved Reserves” and “Note 23 - Other Information” to our consolidated financial statements regarding our estimated proved reserves.
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 its 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 obligation’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as accretion expense in the accompanying consolidated statements of operations.
The ARO 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 a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated ARO. The liability for current ARO is reported in other current liabilities. See “Note 8 - Asset Retirement Obligations”.
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 Company also has previously recognized 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 9 - Fair Value of Financial Instruments”, “Note 10 - Investments and Derivatives”, and “Note 13 - Shareholders' Equity”.
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Goodwill and Intangible Assets
In accordance with GAAP, goodwill is not amortized to earnings, but is assessed annually 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 assessment date, and all goodwill has been allocated to the Company’s midstream segment. 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. ASC Topic 350, Intangibles - Goodwill and Other 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 qualitative analysis as of April 1, 2014 and determined that no impairment existed.
As a result of the Company’s loss of its controlling financial interest in Eureka Hunter Holdings, the Company determined an event had occurred which required a reassessment of its goodwill as of December 18, 2014. The Company performed a qualitative assessment of goodwill as of December 18, 2014 and determined that no impairment existed prior to deconsolidation. The Company also performed an analysis to determine the amount of goodwill allocated to the Eureka Hunter Holdings business. As a result, all goodwill and intangible assets were derecognized as part of the gain on deconsolidation. See “Note 2 - Deconsolidation of Eureka Hunter Holdings” to our consolidated financial statements.
Intangible assets consist primarily of acquired gas treating agreements and customer relationships. Such assets are being amortized over their estimated useful lives, which range from 2 to 13 years up to December 18, 2014, when they were deconsolidated. 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.
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 its 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.
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. Prices for production are defined in sales contracts and are readily determinable or estimable based on available data.
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.
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 and Uncertain Tax Positions
Income taxes are accounted for in accordance with ASC Topic 740, Income Taxes 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. Interest and penalties related to income taxes are recognized in “Income tax benefit” in the consolidated statement of operations.
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Under accounting standards for uncertainty in income taxes, 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, 2014 or 2013.
We apply the intra-period tax allocation rules, using the with and without approach, to allocate income taxes among continuing operations, discontinued operations, other comprehensive income (loss), and additional paid-in capital when we meet the criteria as prescribed in the rules.
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.
In April 2014, the FASB issued ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 updates the requirements for reporting discontinued operations in ASC Subtopic 205-20, Presentation of Financial Statements - Discontinued Operations, by requiring classification as discontinued operations of a component of an entity or a group of components of an entity if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when either 1) the component or group of components of an entity meet the criteria to be classified as held for sale, 2) are disposed of by sale, or 3) are disposed of other than by sale (e.g. abandonment or a distribution to owners in a spinoff). The amendments in this update expand the disclosure requirements related to discontinued operations and disposals of individually significant components that do not qualify for discontinued operations presentation in the financial statements. This ASU is effective prospectively for all disposals (or classification as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 supersedes the revenue recognition requirements in ASC Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the ASC. The core principle of the revised standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. To achieve that core principle, an entity should apply the following steps: identify the contract(s) with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 requires entities to disclose both quantitative and qualitative information that enables users of financial statements to understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. This amendment is effective for annual reporting periods beginning after December 15, 2016, including interim periods within those reporting periods. The guidance allows for either a “full retrospective” adoption or a “modified retrospective” adoption, however early application is not permitted. The Company is currently evaluating the adoption methods and the impact of this ASU on its consolidated financial statements and financial statement disclosures.
In June 2014, the FASB issued ASU 2014-12, Compensation - Stock Compensation: Accounting for Share Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 clarifies that a performance target that affects vesting and that could be achieved after the requisite service period should be treated as a performance condition. An entity should apply existing guidance in ASC Topic 718 as it relates to awards with performance conditions that affect vesting to account for such awards. As such, the performance target should not be reflected in estimating the grant-date fair value of the award. This amendment is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern: Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. This update requires an entity’s management to evaluate for each annual and interim reporting period whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued or available to be issued. The update further requires certain disclosures when substantial doubt is alleviated as a result of consideration of management’s plans, and requires an express statement and other disclosures when substantial doubt is not alleviated. This amendment is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
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In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging: Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity. This update requires that, for hybrid financial instruments issued in the form of a share, an entity should determine the nature of the host contract by considering the economic characteristics and risks of the entire hybrid financial instrument, including the embedded derivative feature that is being evaluated for separate accounting from the host contract. The effects of initially adopting the amendment should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. This amendment is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption, including adoption in an interim period, is permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
In November 2014, the FASB issued ASU 2014-17, Business Combinations: Pushdown Accounting. ASU 2014-17 provides an acquired entity with the option to apply pushdown accounting in its separate financial statements upon the occurrence of an event in which an acquirer obtains control of the acquired entity. The election to apply pushdown accounting may be made each time there is a change-in-control event. If the acquired entity does not elect to apply pushdown accounting upon a change-in-control event, it can elect to apply pushdown accounting to its most recent change-in-control event in a subsequent reporting period as a change in accounting principle. This amendment is effective as of November 18, 2014. The adoption of this updated standard did not have a material impact on the Company’s consolidated financial statements and financial statement disclosures.
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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 energy prices, interest rates, market prices for publicly traded equity instruments, and other related factors. These risks can affect revenues and cash flow from operating, investing, and financing activities. 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
The Company’s most significant market risk relates to the market prices for natural gas, crude oil, and NGLs. Recent declines in market prices for natural gas, crude oil, and NGLs have resulted in lower realized sales prices for the Company’s production during the year ended December 31, 2014. Further declines could impact the extent to which the Company develops portions of its proved and unproved oil and natural gas properties, and could possibly include temporarily shutting in certain wells that are uneconomic to produce if commodity prices drop below break-even levels. 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 period of time, we could be required under successful efforts accounting rules to perform a write down of the carrying value of our oil and natural gas properties.
The Company’s risk-management policies provide for the use of derivative instruments to manage commodity price risks. We may enter into financial swaps and collars to reduce the risk of commodity price fluctuation. As per the applicable accounting requirements, 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. Although our derivative hedging instruments may qualify for cash flow hedge accounting, we do not currently elect hedge accounting for our commodity derivative instruments.
As of December 31, 2014, the Company had derivative instruments in place to reduce the price risk associated with future production of 14.6 Bcf of natural gas and 0.1 MMBbls of crude oil. The derivative instruments represent a gross asset of $18.1 million and a gross liability of $1.6 million; or a net asset of $16.5 million. The table below shows the impact that a 10% increase or decrease in underlying commodity price index would have on the fair value of derivative instruments as of December 31, 2014:
| As of December 31, 2014 | |||||||||
| Fair Value: | Fair Value: | ||||||||
| Fair Value As Reported | 10% Price Increase | 10% Price Decrease | |||||||
| (in thousands) | |||||||||
| Gas | $ | 15,400 | $ | 11,382 | $ | 19,419 | |||
| Crude oil | 1,111 | 866 | 1,267 | ||||||
| Total Fair Value | $ | 16,511 | $ | 12,248 | $ | 20,686 | |||
| Change in Fair Value | $ | (4,263 | ) | $ | 4,175 | ||||
Any realized derivative gains or losses, however, would be substantially offset by the realized sales value of production covered by the derivative instruments.
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The table below is a summary of the Company's commodity derivatives as of December 31, 2014:
| Weighted Avg | ||||
| Natural Gas | Period | MMBtu/d | Price per MMBtu | |
| Swaps | Jan 2015 - Dec 2015 | 40,000 | $4.09 | |
| Weighted Avg | ||||
| Crude Oil | Period | Bbl/d | Price per Bbl | |
Collars (1) | Jan 2015 - Dec 2015 | 259 | $85.00 - $91.25 | |
| Ceilings sold (call) | Jan 2015 - Dec 2015 | 1,570 | $120.00 | |
| Floors sold (put) | Jan 2015 - Dec 2015 | 259 | $70.00 | |
(1) A collar is a sold call and a purchased put. Some collars are “costless” collars with the premiums netting to approximately zero.
At December 31, 2014, the fair value of our open commodity derivative contracts was an asset of $16.5 million.
As of December 31, 2014, Bank of America, Bank of Montreal, Citibank, N.A., and the Royal Bank of Canada are the only counterparties to our commodity derivatives positions and all but one of these counterparties were participants in the MHR Senior Revolving Credit Facility. Although borrowings under the MHR Senior Revolving Credit Facility are used as collateral for our commodity derivatives with those counterparties participating in the MHR Senior Revolving Credit Facility, we had no outstanding borrowings under that credit facility as of December 31, 2014. Additionally, certain counterparties to our commodity derivatives positions are no longer participants in our credit facilities following the execution of new credit agreements on October 22, 2014. As a result, we are exposed to credit losses in the event of nonperformance by the counterparties where our open commodity derivative contracts are in a gain position. We do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.
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 commodity derivative contracts for the years ended December 31, 2014, 2013 and 2012:
| For the Year Ended December 31, | |||||||||||
| 2014 | 2013 | 2012 | |||||||||
| (in thousands) | |||||||||||
| Gain (loss) on settled transactions | $ | 1,306 | $ | (8,216 | ) | $ | 11,294 | ||||
| Gain on open contracts | 18,237 | 869 | 2,124 | ||||||||
| Total gain (loss), net | $ | 19,543 | $ | (7,347 | ) | $ | 13,418 | ||||
See “Note 10 - Investments and Derivatives” in the accompanying consolidated financial statements for additional information on derivative instruments.
Interest Rate Risk
Borrowings under the MHR Senior Revolving Credit Facility are subject to variable interest rates. The balance of the Company’s long-term debt on the Company’s consolidated balance sheet is subject to fixed interest rates. At December 31, 2014, the Company had no borrowings outstanding under the MHR Senior Revolving Credit Facility; accordingly, at that date, the Company was not subject to variable interest rates under the facility.
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Financial Instrument Price Risk
We have investments in both publicly-traded and non-publicly-traded financial instruments. Our ability to divest of these instruments is a function of overall market liquidity which is impacted by, among other things, the amount of outstanding securities of a particular issuer, trading history of the issuer, overall market conditions, and entity-specific facts and circumstances that impact a particular issuer. As a result, market volatility and overall financial performance and liquidity of the issuer could result in significant fluctuations in the fair value of these instruments, and we may be unable to recover the full cost of these investments. A 10% increase or decrease in market prices for our marketable securities would increase or decrease fair value by $0.4 million.
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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 (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive loss, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2014. 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, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, 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, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 2, 2015, expressed an unqualified opinion thereon.
/s/ BDO USA, LLP
Dallas, Texas
March 2, 2015
F-1
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, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 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.
In our opinion, Magnum Hunter Resources Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the 2013 COSO Framework.
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, 2014 and 2013, and the related consolidated statements of operations, comprehensive loss, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2014 and our report dated March 2, 2015, expressed an unqualified opinion thereon.
/s/ BDO USA, LLP
Dallas, Texas
March 2, 2015
F-2
Table of Contents
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
| December 31, | |||||||
| 2014 | 2013 | ||||||
| ASSETS | |||||||
| CURRENT ASSETS | |||||||
| Cash and cash equivalents | $ | 53,180 | $ | 41,713 | |||
| Restricted cash | — | 5,000 | |||||
| Accounts receivable: | |||||||
| Oil and natural gas sales | 16,319 | 25,099 | |||||
| Joint interests and other, net of allowance for doubtful accounts of $308 and $196 at December 31, 2014 and 2013, respectively | 23,888 | 30,582 | |||||
| Derivative assets | 16,586 | 608 | |||||
| Inventory | 2,268 | 7,158 | |||||
| Investments | 3,864 | 2,262 | |||||
| Prepaid expenses and other assets | 4,091 | �� | 2,938 | ||||
| Assets held for sale | — | 5,366 | |||||
| Total current assets | 120,196 | 120,726 | |||||
| PROPERTY, PLANT AND EQUIPMENT | |||||||
| Oil and natural gas properties, successful efforts method of accounting | 1,346,645 | 1,355,288 | |||||
| Accumulated depletion, depreciation, and accretion | (248,410 | ) | (130,629 | ) | |||
| Total oil and natural gas properties, net | 1,098,235 | 1,224,659 | |||||
| Gas transportation, gathering and processing equipment and other, net | 77,423 | 289,420 | |||||
| Total property, plant and equipment, net | 1,175,658 | 1,514,079 | |||||
| OTHER ASSETS | |||||||
| Deferred financing costs, net of amortization of $15,099 and $9,735 as of December 31, 2014 and 2013, respectively | 22,856 | 20,008 | |||||
| Derivative assets | — | 25 | |||||
| Intangible assets, net | — | 6,530 | |||||
| Goodwill | — | 30,602 | |||||
| Other assets | 3,928 | 1,644 | |||||
| Investment in affiliates, equity method | 347,191 | 350 | |||||
| Assets held for sale | — | 162,687 | |||||
| Total assets | $ | 1,669,829 | $ | 1,856,651 | |||
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
F-3
Table of Contents
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
| December 31, | |||||||
| 2014 | 2013 | ||||||
| LIABILITIES AND SHAREHOLDERS' EQUITY | |||||||
| CURRENT LIABILITIES | |||||||
| Current portion of long-term debt | $ | 10,770 | $ | 3,804 | |||
| Accounts payable | 130,502 | 107,837 | |||||
| Accounts payable to related parties | 90 | 23 | |||||
| Accrued liabilities | 20,277 | 44,629 | |||||
| Revenue payable | 5,450 | 6,313 | |||||
| Derivative liabilities | — | 1,903 | |||||
| Other liabilities | 1,356 | 6,491 | |||||
| Liabilities associated with assets held for sale | — | 12,865 | |||||
| Total current liabilities | 168,445 | 183,865 | |||||
| Long-term debt, net of current portion | 937,963 | 876,106 | |||||
| Asset retirement obligations | 26,229 | 16,163 | |||||
| Derivative liabilities, long-term | — | 76,310 | |||||
| Other long-term liabilities | 5,337 | 2,279 | |||||
| Long-term liabilities associated with assets held for sale | — | 14,523 | |||||
| Total liabilities | 1,137,974 | 1,169,246 | |||||
| COMMITMENTS AND CONTINGENCIES (Note 18) | |||||||
| REDEEMABLE PREFERRED STOCK | |||||||
| Series C Cumulative Perpetual Preferred Stock, (“Series C Preferred Stock”) cumulative dividend rate 10.25% per annum, 4,000,000 authorized, 4,000,000 issued and outstanding as of December 31, 2014 and 2013, with a liquidation preference of $25.00 per share | 100,000 | 100,000 | |||||
| Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC (the “Eureka Hunter Holdings Series A Preferred Units”), cumulative distribution rate of 8.0% per annum, none and 9,885,048 issued and outstanding as of December 31, 2014 and 2013, respectively, with a liquidation preference of $200,620 as of December 31, 2013 | — | 136,675 | |||||
| 100,000 | 236,675 | ||||||
| SHAREHOLDERS' EQUITY | |||||||
| Preferred Stock of Magnum Hunter Resources Corporation, 10,000,000 authorized, including authorized shares of Series C Preferred Stock | |||||||
| Series D Cumulative Preferred Stock, (“Series D Preferred Stock”) cumulative dividend rate 8.0% per annum, 5,750,000 authorized, 4,424,889 issued and outstanding as of December 31, 2014 and December 31, 2013, with a liquidation preference of $50.00 per share | 221,244 | 221,244 | |||||
| Series E Cumulative Convertible Preferred Stock, (“Series E Preferred Stock”) cumulative dividend rate 8.0% per annum, 12,000 authorized, 3,803 issued and 3,722 shares outstanding as of December 31, 2014 and 2013, with a liquidation preference of $25,000 per share | 95,069 | 95,069 | |||||
| Common stock, $0.01 par value per share, 350,000,000 shares authorized, 201,420,701 and 172,409,023 issued and 200,505,749 and 171,494,071 outstanding as of December 31, 2014 and 2013, respectively | 2,014 | 1,724 | |||||
| Additional paid in capital | 909,783 | 733,753 | |||||
| Accumulated deficit | (784,546 | ) | (586,365 | ) | |||
| Accumulated other comprehensive loss | (7,765 | ) | (19,901 | ) | |||
| Treasury stock, at cost | |||||||
| Series E Preferred Stock, 81 shares as of December 31, 2014 and 2013 | (2,030 | ) | (2,030 | ) | |||
| Common stock, 914,952 shares as of December 31, 2014 and 2013 | (1,914 | ) | (1,914 | ) | |||
| Total Magnum Hunter Resources Corporation shareholders' equity | 431,855 | 441,580 | |||||
| Non-controlling interest | — | 9,150 | |||||
| Total shareholders' equity | 431,855 | 450,730 | |||||
| Total liabilities and shareholders’ equity | $ | 1,669,829 | $ | 1,856,651 | |||
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
F-4
Table of Contents
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share and per share data)
| Year Ended December 31, | |||||||||||
| 2014 | 2013 | 2012 | |||||||||
| REVENUES AND OTHER | |||||||||||
| Oil and natural gas sales | $ | 268,501 | $ | 220,699 | $ | 133,728 | |||||
| Midstream natural gas gathering, processing, and marketing | 97,916 | 61,178 | 13,040 | ||||||||
| Oilfield services | 23,134 | 18,431 | 12,333 | ||||||||
| Other revenue | 1,918 | 4,230 | 836 | ||||||||
| Total revenue | 391,469 | 304,538 | 159,937 | ||||||||
| OPERATING EXPENSES | |||||||||||
| Production costs | 47,857 | 46,689 | 30,119 | ||||||||
| Severance taxes and marketing | 17,344 | 18,282 | 8,043 | ||||||||
| Transportation, processing, and other related costs | 43,292 | 22,549 | 10,775 | ||||||||
| Exploration | 118,509 | 100,389 | 80,375 | ||||||||
| Midstream natural gas gathering, processing, and marketing | 84,764 | 52,099 | 8,028 | ||||||||
| Oilfield services | 15,686 | 14,825 | 10,037 | ||||||||
| Impairment of proved oil and gas properties | 301,276 | 50,011 | 3,839 | ||||||||
| Depreciation, depletion, amortization and accretion | 146,868 | 107,385 | 72,438 | ||||||||
| (Gain) loss on sale of assets, net | (2,456 | ) | 44,641 | 596 | |||||||
General and administrative (1) | 108,687 | 82,461 | 62,347 | ||||||||
| Total operating expenses | 881,827 | 539,331 | 286,597 | ||||||||
| OPERATING LOSS | (490,358 | ) | (234,793 | ) | (126,660 | ) | |||||
| OTHER INCOME (EXPENSE) | |||||||||||
| Interest income | 156 | 265 | 202 | ||||||||
| Interest expense | (86,463 | ) | (72,621 | ) | (51,846 | ) | |||||
| Gain (loss) on derivative contracts, net | (72,254 | ) | (25,274 | ) | 22,239 | ||||||
| Gain on deconsolidation of Eureka Hunter Holdings, LLC | 509,563 | — | — | ||||||||
| Loss from equity method investment | (1,038 | ) | (994 | ) | (1,971 | ) | |||||
| Other income | 2,561 | 15,897 | 4,014 | ||||||||
| Total other income (expense), net | 352,525 | (82,727 | ) | (27,362 | ) | ||||||
| LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX | (137,833 | ) | (317,520 | ) | (154,022 | ) | |||||
| Income tax benefit | — | 85,407 | 24,665 | ||||||||
| LOSS FROM CONTINUING OPERATIONS, NET OF TAX | (137,833 | ) | (232,113 | ) | (129,357 | ) | |||||
| Income (loss) from discontinued operations, net of tax | 4,561 | (62,561 | ) | (9,773 | ) | ||||||
| Gain (loss) on disposal of discontinued operations, net of tax | (13,855 | ) | 71,510 | 2,409 | |||||||
| NET LOSS | (147,127 | ) | (223,164 | ) | (136,721 | ) | |||||
| Net loss attributable to non-controlling interests | 3,653 | 988 | 4,013 | ||||||||
| NET LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION | (143,474 | ) | (222,176 | ) | (132,708 | ) | |||||
| Dividends on preferred stock | (54,707 | ) | (56,705 | ) | (34,706 | ) | |||||
| Loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units | (51,692 | ) | — | — | |||||||
| NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ | (249,873 | ) | $ | (278,881 | ) | $ | (167,414 | ) | ||
| Weighted average number of common shares outstanding, basic and diluted | 189,135,500 | 170,088,108 | 155,743,418 | ||||||||
| Loss from continuing operations per share, basic and diluted | $ | (1.27 | ) | $ | (1.69 | ) | $ | (1.03 | ) | ||
| Income (loss) from discontinued operations per share, basic and diluted | (0.05 | ) | 0.05 | (0.04 | ) | ||||||
| NET LOSS PER COMMON SHARE, BASIC AND DILUTED | $ | (1.32 | ) | $ | (1.64 | ) | $ | (1.07 | ) | ||
| AMOUNTS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION | |||||||||||
| Loss from continuing operations, net of tax | $ | (134,180 | ) | $ | (231,125 | ) | $ | (125,344 | ) | ||
| Income (loss) from discontinued operations, net of tax | (9,294 | ) | 8,949 | (7,364 | ) | ||||||
| Net loss | $ | (143,474 | ) | $ | (222,176 | ) | $ | (132,708 | ) | ||
(1) 2014 includes the recognition of a $32.6 million non-cash loss related to the downward adjustment of the Company’s equity interest in Eureka Hunter Holdings related to excess capital expenditures in 2014. See “Note 2 - Deconsolidation of Eureka Hunter Holdings” in the accompanying Notes to Consolidated Financial Statements.
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
F-5
Table of Contents
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(in thousands)
| Year ended December 31, | |||||||||||
| 2014 | 2013 | 2012 | |||||||||
| NET LOSS | $ | (147,127 | ) | $ | (223,164 | ) | $ | (136,721 | ) | ||
| OTHER COMPREHENSIVE INCOME (LOSS) | |||||||||||
| Foreign currency translation gain (loss) | (1,204 | ) | (10,928 | ) | 3,883 | ||||||
| Unrealized gain (loss) on available for sale investments | (7,401 | ) | 8,178 | (309 | ) | ||||||
| Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities | — | (8,262 | ) | — | |||||||
| Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc. | 20,741 | — | — | ||||||||
| Total other comprehensive income (loss) | 12,136 | (11,012 | ) | 3,574 | |||||||
| COMPREHENSIVE LOSS | (134,991 | ) | (234,176 | ) | (133,147 | ) | |||||
| Comprehensive loss attributable to non-controlling interests | 3,653 | 988 | 4,013 | ||||||||
| COMPREHENSIVE LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION | $ | (131,338 | ) | $ | (233,188 | ) | $ | (129,134 | ) | ||
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
F-6
Table of Contents
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(in thousands)
| Number of Shares | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Series D Preferred Stock | Series E Preferred Stock | Common Stock | Exchangeable Common Stock | Series D Preferred Stock | Series E Preferred Stock | Common Stock | Exchangeable Common Stock | Additional Paid in Capital | Accumulated Deficit | Accumulated Other Comprehensive Loss | Treasury Stock | Unearned Common Shares in KSOP | Non-controlling Interest | Total Shareholders' Equity | |||||||||||||||||||||||||||||||||||||||||
| BALANCE, January 1, 2012 | 1,438 | — | 129,803 | 3,694 | $ | 71,878 | $ | — | $ | 1,298 | $ | 37 | $ | 569,690 | $ | (140,070 | ) | $ | (12,463 | ) | $ | (1,310 | ) | $ | (604 | ) | $ | 2,196 | $ | 490,652 | |||||||||||||||||||||||||
| Share based compensation | — | — | 108 | — | — | — | 1 | — | 15,695 | — | — | — | — | — | 15,696 | ||||||||||||||||||||||||||||||||||||||||
| Shares of common stock issued for payment of 401K plan matching contributions | — | — | 199 | — | — | — | 2 | — | 872 | — | — | — | — | — | 874 | ||||||||||||||||||||||||||||||||||||||||
| Sale of Preferred Stock | 2,771 | 1 | — | — | 138,563 | 25,000 | — | — | (18,928 | ) | — | — | — | — | — | 144,635 | |||||||||||||||||||||||||||||||||||||||
| Sale of Common Stock | — | — | 35,000 | — | — | — | 350 | — | 147,891 | — | — | — | — | — | 148,241 | ||||||||||||||||||||||||||||||||||||||||
| Shares of Common Stock issued upon exercise of warrants and options | — | — | 1,438 | — | — | — | 14 | — | 2,317 | — | — | — | — | — | 2,331 | ||||||||||||||||||||||||||||||||||||||||
| Preferred dividends | — | — | — | — | — | — | — | — | — | (34,706 | ) | — | — | — | — | (34,706 | ) | ||||||||||||||||||||||||||||||||||||||
| Shares of Common Stock issued for acquisitions | — | — | 297 | — | — | — | 3 | — | 1,899 | — | — | — | — | — | 1,902 | ||||||||||||||||||||||||||||||||||||||||
| Shares of Preferred Stock issued for acquisitions | — | 3 | — | — | — | 69,371 | — | — | (4,403 | ) | — | — | — | — | — | 64,968 | |||||||||||||||||||||||||||||||||||||||
| Shares of Common Stock issued upon exchange of MHR Exchangeco Corporation's exchangeable shares | — | — | 3,188 | (3,188 | ) | — | — | 32 | (32 | ) | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||
| Purchase of outstanding non-controlling interest in a subsidiary | — | — | — | — | — | — | — | — | — | — | — | — | — | (497 | ) | (497 | ) | ||||||||||||||||||||||||||||||||||||||
| Common units of Eureka Hunter Holdings issued for asset acquisition | — | — | — | — | — | — | — | — | — | — | — | — | — | 12,453 | 12,453 | ||||||||||||||||||||||||||||||||||||||||
| Common shares returned to Treasury from KSOP | — | — | — | — | — | — | — | — | — | — | — | (604 | ) | 604 | — | — | |||||||||||||||||||||||||||||||||||||||
| Purchase of treasury shares | — | — | — | — | — | — | — | — | — | — | — | (1,750 | ) | — | — | (1,750 | ) | ||||||||||||||||||||||||||||||||||||||
| Net loss | — | — | — | — | — | — | — | — | — | (132,708 | ) | — | — | — | (4,013 | ) | (136,721 | ) | |||||||||||||||||||||||||||||||||||||
| Foreign currency translation | — | — | — | — | — | — | — | — | — | — | 3,883 | — | — | — | 3,883 | ||||||||||||||||||||||||||||||||||||||||
| Unrealized gain on available for sale securities | — | — | — | — | — | — | — | — | — | — | (309 | ) | — | — | — | (309 | ) | ||||||||||||||||||||||||||||||||||||||
| BALANCE, December 31, 2012 | 4,209 | 4 | 170,033 | 506 | $ | 210,441 | $ | 94,371 | $ | 1,700 | $ | 5 | $ | 715,033 | $ | (307,484 | ) | $ | (8,889 | ) | $ | (3,664 | ) | $ | — | $ | 10,139 | $ | 711,652 | ||||||||||||||||||||||||||
| Share based compensation | — | — | 183 | — | — | — | 2 | — | 13,622 | — | — | — | — | — | 13,624 | ||||||||||||||||||||||||||||||||||||||||
| Shares of common stock issued for payment of 401K plan matching contribution | — | — | 221 | — | — | — | 2 | — | 1,190 | — | — | — | — | — | 1,192 | ||||||||||||||||||||||||||||||||||||||||
| Sale of Preferred Stock | 216 | — | — | — | 10,803 | 698 | — | — | (1,320 | ) | — | — | — | — | — | 10,181 | |||||||||||||||||||||||||||||||||||||||
| Dividends on preferred stock | — | — | — | — | — | — | — | — | — | (56,705 | ) | — | — | — | — | (56,705 | ) | ||||||||||||||||||||||||||||||||||||||
| Conversion of exchangeable common stock for common stock | — | — | 506 | (506 | ) | — | — | 5 | (5 | ) | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||
| Fees on equity issuance | — | — | — | — | — | — | — | — | (109 | ) | — | — | — | — | — | (109 | ) | ||||||||||||||||||||||||||||||||||||||
| Depositary shares representing Series E Preferred Stock returned from escrow | — | — | — | — | — | — | — | — | — | — | — | (280 | ) | — | — | (280 | ) | ||||||||||||||||||||||||||||||||||||||
| Shares of common stock issued upon exercise of common stock options | — | — | 1,466 | — | — | — | 15 | — | 5,337 | — | — | — | — | — | 5,352 | ||||||||||||||||||||||||||||||||||||||||
| Dividends on common stock in the form of 17,030,622 warrants with fair value of $21.6 million | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||
| Net loss | — | — | — | — | — | — | — | — | — | (222,176 | ) | — | — | — | (988 | ) | (223,164 | ) | |||||||||||||||||||||||||||||||||||||
| Foreign currency translation | — | — | — | — | — | — | — | — | — | — | (10,928 | ) | — | — | — | (10,928 | ) | ||||||||||||||||||||||||||||||||||||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
F-7
Table of Contents
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(in thousands)
| Unrealized loss on available for sale securities | — | — | — | — | — | — | — | — | — | — | (84 | ) | — | — | — | (84 | ) | ||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | — | — | — | — | — | — | — | — | — | — | (1 | ) | (1 | ) | ||||||||||||||||||||||||||||||||||||||
| BALANCE, December 31, 2013 | 4,425 | 4 | 172,409 | — | $ | 221,244 | $ | 95,069 | $ | 1,724 | $ | — | $ | 733,753 | $ | (586,365 | ) | $ | (19,901 | ) | $ | (3,944 | ) | $ | — | $ | 9,150 | $ | 450,730 | ||||||||||||||||||||||||||
| Share based compensation | — | — | 657 | — | — | — | 7 | — | 11,356 | — | — | — | — | — | 11,363 | ||||||||||||||||||||||||||||||||||||||||
| Shares withheld for taxes | — | — | — | — | — | — | — | — | (480 | ) | — | — | — | — | — | (480 | ) | ||||||||||||||||||||||||||||||||||||||
| Shares of common stock issued for payment of 401k plan matching contribution | — | — | 250 | — | — | — | 2 | — | 1,591 | — | — | — | — | — | 1,593 | ||||||||||||||||||||||||||||||||||||||||
| Sale of common stock | — | — | 25,729 | — | — | — | 257 | — | 178,153 | — | — | — | — | — | 178,410 | ||||||||||||||||||||||||||||||||||||||||
| Shares of common stock issued upon exercise of common stock options | — | — | 2,375 | — | — | — | 24 | — | 9,639 | — | — | — | — | — | 9,663 | ||||||||||||||||||||||||||||||||||||||||
| Shares of common stock issued in exchange for shares of Ambassador Oil & Gas Limited | — | — | 1 | — | — | — | — | — | 5 | — | — | — | — | — | 5 | ||||||||||||||||||||||||||||||||||||||||
| Dividends on preferred stock | — | — | — | — | — | — | — | — | — | (54,707 | ) | — | — | — | — | (54,707 | ) | ||||||||||||||||||||||||||||||||||||||
| Repurchase of non-controlling interest | — | — | — | — | — | — | — | — | (5,111 | ) | — | — | — | — | 2,236 | (2,875 | ) | ||||||||||||||||||||||||||||||||||||||
| Extinguishment of Eureka Hunter Holdings Series A Preferred Units | — | — | — | — | — | — | — | — | (51,692 | ) | — | — | — | — | 389,235 | 337,543 | |||||||||||||||||||||||||||||||||||||||
| Forfeiture of Eureka Hunter Holdings Series A-1 Units | — | — | — | — | — | — | — | — | 32,569 | — | — | — | — | — | 32,569 | ||||||||||||||||||||||||||||||||||||||||
| Issuance of Eureka Hunter Holdings Series A-2 Units | — | — | — | — | — | — | — | — | — | — | — | — | — | 40,000 | 40,000 | ||||||||||||||||||||||||||||||||||||||||
| Deconsolidation of Eureka Hunter Holdings | — | — | — | — | — | — | — | — | — | — | — | — | — | (436,968 | ) | (436,968 | ) | ||||||||||||||||||||||||||||||||||||||
| Net loss | — | — | — | — | — | — | — | — | — | (143,474 | ) | — | — | — | (3,653 | ) | (147,127 | ) | |||||||||||||||||||||||||||||||||||||
| Foreign currency translation | — | — | — | — | — | — | — | — | — | — | (1,204 | ) | — | — | — | (1,204 | ) | ||||||||||||||||||||||||||||||||||||||
| Unrealized loss on available for sale securities, net | — | — | — | — | — | — | — | — | — | — | (7,401 | ) | — | — | — | (7,401 | ) | ||||||||||||||||||||||||||||||||||||||
| Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc. | — | — | — | — | — | — | — | — | — | — | 20,741 | — | — | — | 20,741 | ||||||||||||||||||||||||||||||||||||||||
| BALANCE, December 31, 2014 | 4,425 | 4 | 201,421 | — | $ | 221,244 | $ | 95,069 | $ | 2,014 | $ | — | $ | 909,783 | $ | (784,546 | ) | $ | (7,765 | ) | $ | (3,944 | ) | $ | — | $ | — | $ | 431,855 | ||||||||||||||||||||||||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
F-8
Table of Contents
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| Year Ended December 31, | |||||||||||
| 2014 | 2013 | 2012 | |||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||
| Net loss | $ | (147,127 | ) | $ | (223,164 | ) | $ | (136,721 | ) | ||
| Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | |||||||||||
| Depletion, depreciation, amortization and accretion | 146,868 | 134,867 | 135,896 | ||||||||
| Share-based compensation | 12,469 | 13,624 | 15,696 | ||||||||
| Impairment of proved oil and gas properties | 301,276 | 89,041 | 4,096 | ||||||||
| Exploration | 116,945 | 115,069 | 116,686 | ||||||||
| Impairment of other operating assets | 730 | — | — | ||||||||
| (Gain) loss on sale of assets | 11,399 | (7,318 | ) | (3,074 | ) | ||||||
| Cash paid for plugging wells | (107 | ) | (14 | ) | — | ||||||
| Gain on deconsolidation of Eureka Hunter Holdings | (509,563 | ) | — | — | |||||||
| Loss from capital account adjustment of Eureka Hunter Holdings | 32,569 | — | — | ||||||||
| Loss from equity method investment | 1,038 | 994 | 1,971 | ||||||||
| Unrealized loss (gain) on open derivative contracts | (18,232 | ) | 17,058 | (10,945 | ) | ||||||
| Loss on extinguished embedded derivative | 91,792 | — | — | ||||||||
| Unrealized loss (gain) on investments | — | (8,003 | ) | 229 | |||||||
| Amortization and write off of deferred financing cost and discount on Senior Notes included in interest expense | 9,679 | 4,836 | 7,399 | ||||||||
| Deferred tax benefit | — | (84,527 | ) | (21,595 | ) | ||||||
| Changes in operating assets and liabilities: | |||||||||||
| Accounts receivable, net | 8,533 | 22,781 | (73,549 | ) | |||||||
| Inventory | 4,381 | 4,658 | (6,198 | ) | |||||||
| Prepaid expenses and other current assets | (3,071 | ) | (1,073 | ) | (538 | ) | |||||
| Accounts payable | (51,930 | ) | 42,050 | 16,390 | |||||||
| Revenue payable | (2,953 | ) | (11,589 | ) | 8,776 | ||||||
| Accrued liabilities | (23,361 | ) | 2,421 | 3,492 | |||||||
| Net cash provided by (used in) operating activities | (18,665 | ) | 111,711 | 58,011 | |||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | |||||||||||
| Change in restricted cash | 5,000 | (3,500 | ) | — | |||||||
| Capital expenditures and advances | (562,324 | ) | (631,511 | ) | (568,610 | ) | |||||
| Cash paid in acquisitions, net of cash received of $0; $0; and $34, respectively | — | — | (444,844 | ) | |||||||
| Deconsolidation of the cash of Eureka Hunter Holdings | (6,380 | ) | — | — | |||||||
| Proceeds from sale of assets | 193,139 | 506,297 | 4,158 | ||||||||
| Proceeds from partial sale of equity interest in Eureka Hunter Holdings | 55,000 | — | — | ||||||||
| Change in deposits and other long-term assets | (2,554 | ) | 854 | 89 | |||||||
| Net cash used in investing activities | (318,119 | ) | (127,860 | ) | (1,009,207 | ) | |||||
| CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||||
| Proceeds from issuing Senior Notes | — | — | 596,907 | ||||||||
| Proceeds from borrowings on debt | 629,392 | 373,991 | 546,043 | ||||||||
| Principal repayments of debt | (467,745 | ) | (380,923 | ) | (542,654 | ) | |||||
| Proceeds from sale of Series A preferred units in Eureka Hunter Holdings | 11,956 | 35,280 | 149,655 | ||||||||
| Issue Series A Common units of Eureka Hunter Holdings, net of costs | 8,180 | — | — | ||||||||
| Issue Series A-2 Units of Eureka Hunter Holdings, net of costs | 40,000 | — | — | ||||||||
| Net proceeds from sale of common stock | 178,410 | — | 148,241 | ||||||||
| Net proceeds from sale of preferred shares | — | 10,072 | 144,635 | ||||||||
| Repurchase noncontrolling interest | (2,875 | ) | — | — | |||||||
| Proceeds from exercise of warrants and options | 9,663 | 5,352 | 2,331 | ||||||||
| Change in other long-term liabilities | 1,023 | (1,222 | ) | 186 | |||||||
| Purchase of treasury shares | — | — | (1,750 | ) | |||||||
| Payment of deferred financing costs | (14,208 | ) | (1,246 | ) | (20,313 | ) | |||||
| Preferred stock dividends paid | (45,601 | ) | (40,648 | ) | (26,839 | ) | |||||
| Net cash provided by financing activities | 348,195 | 656 | 996,442 | ||||||||
| Effect of foreign exchange rate changes on cash | 56 | (417 | ) | (2,474 | ) | ||||||
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 11,467 | (15,910 | ) | 42,772 | |||||||
| CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR | 41,713 | 57,623 | 14,851 | ||||||||
| CASH AND CASH EQUIVALENTS, END OF YEAR | $ | 53,180 | $ | 41,713 | $ | 57,623 | |||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
F-9
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 oil and gas company engaged primarily in the exploration for and the exploitation, acquisition, development and production of natural gas and natural gas liquids resources predominantly in shale plays in the United States, along with certain oil field service activities and a substantial investment in midstream operations.
Presentation of Consolidated Financial Statements
The consolidated financial statements include the accounts of the Company and entities in which it holds a controlling financial 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 Company deconsolidates entities in which it no longer holds a controlling financial interest as of the date control is lost. The results of operations and assets and liabilities of deconsolidated entities are included in the Company’s consolidated financial statements with all significant intercompany balances eliminated through the date of deconsolidation. Subsequently, retained interests in an entity, if any, are accounted for based on the nature of the retained interest in accordance with GAAP.
The consolidated financial statements also reflect the interests of our wholly-owned subsidiary, Magnum Hunter Production, Inc. (“MHP”), and in various managed drilling partnerships. The Company accounts for the interests in these partnerships using the proportionate consolidation method.
Use of Estimates in the Preparation of Financial Statements
Preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant recurring items subject to such estimates and assumptions include those related to stock based compensation, the valuation of commodity and financial derivative instruments, embedded derivative assets and liabilities, asset retirement obligations and other liabilities.
The estimates of proved, probable and possible oil and gas reserves are used as significant inputs in determining the depletion of oil and gas properties and the impairment of proved and unproved oil and gas properties. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks.
Non-recurring items subject to significant estimates include the fair value of the Company’s retained financial interest in equity method investees.
Actual results could differ from the estimates and assumptions utilized.
Non-Controlling Interest in Consolidated Subsidiaries
For the years ended December 31, 2013 and 2012, the Company consolidated Eureka Hunter Holdings, LLC (“Eureka Hunter Holdings”) in which it owned a 56.4% and 61.0% interest at 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 (“TransTex Hunter”), and Eureka Hunter Land, LLC. Eureka Hunter Pipeline engages in midstream operations involving the gathering of natural gas through its ownership and operation of a gas gathering system located in northwestern West Virginia and southeastern Ohio, in the Marcellus and Utica Shale plays. TransTex Hunter sells and leases gas treating and processing equipment, much of which is leased to third party operators for treating natural gas at the wellhead.
Following a series of transactions and capital contributions that occurred up to and including December 18, 2014, the Company no longer holds a controlling financial interest in Eureka Hunter Holdings. Accordingly, the results of operations of Eureka Hunter Holdings have been consolidated in the accompanying consolidated financial statements up to December 18, 2014. The Company held a 48.6% equity interest in Eureka Hunter Holdings at December 18, 2014 and at year-end 2014 and accounts for this retained interest under the equity method of accounting with the Company’s share of Eureka Hunter Holdings’ earnings recorded in “loss
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from equity method investment” in the accompanying consolidated statements of operations. See “Note 2 - Deconsolidation of Eureka Hunter Holdings” and “Note 10 - Investments and Derivatives”.
Changes in the non-controlling interests attributable to entities in which the Company holds a controlling financial interest are accounted for as equity transactions, as they are considered investments by owners and distributions to owners acting in their capacity as owners. No gains or losses are recognized as the carrying value of the non-controlling interest is adjusted to reflect the change in the Company’s ownership interest in the subsidiary.
Reclassification of Prior-Year Balances
Certain prior year balances have been reclassified to correspond with the current year presentation. As a result of the Company’s decision in September 2014 to withdraw its plan to divest MHP and to cease all marketing efforts, the results of operations of MHP, which had previously been reported as a component of discontinued operations, have been reclassified to continuing operations for all periods presented, and all assets and liabilities that were previously reported as assets and liabilities held for sale in our consolidated balance sheet have been reclassified to assets and liabilities held for use as of December 31, 2014. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”.
The Company has separately classified transportation and processing expenses incurred to deliver gas to processing plants and/or to selling points, which were previously included as components of lease operating expenses and severance taxes and marketing, in the accompanying consolidated statements of operations for all periods presented. The Company has also renamed lease operating expenses as “Production costs” and presented transportation and processing expenses as “Transportation, processing, and other related costs” in order to provide more meaningful information on costs associated with production and development.
SIGNIFICANT ACCOUNTING POLICIES
Financial Instruments
The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, notes receivable, payables and accrued liabilities, derivatives, and certain long-term debt instruments approximate fair value as of December 31, 2014 and 2013. See “Note 9 - Fair Value of Financial Instruments”.
Cash and cash equivalents
Cash and cash equivalents include cash in banks and highly liquid investment securities that have original maturities of three months or less. At December 31, 2014, the Company had cash deposits in excess of FDIC insured limits at various financial institutions.
Accounts Receivable
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. Accounts receivable (oil and natural gas sales) consist of accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. 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. At December 31, 2014 and 2013, the Company did not have any allowance for doubtful accounts with respect to its oil and natural gas sales accounts receivable.
Accounts receivable from joint interest owners and other consists primarily of joint interest owner obligations due within 30 days of the invoice date. The Company reviews accounts receivable periodically and reduces the carrying amount by a valuation allowance that reflects its best estimate of the amount that may not be collectible. At December 31, 2014 and 2013, the Company had $308 thousand and $196 thousand, respectively, in allowances for doubtful accounts with respect to its joint interest accounts receivable.
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.
Freestanding derivative instruments are recorded at fair value in the consolidated balance sheets 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 fair value of derivatives in earnings, as it has not designated its 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, net” line item within the “Other Income (expense)” section of the consolidated statements of operations.
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The Company may be party to contracts or has purchased certain investments that contain an embedded derivative. If the embedded derivative is not clearly and closely related to the host contract, and as a separate instrument would qualify as a derivative, the derivative is separated from the host contract, held at fair value and reported separately from the host instrument in the consolidated balance sheets. The Company recognizes changes in the fair value of the bifurcated derivative in “Gain (loss) on derivative contracts, net”.
Inventory
The Company’s materials and supplies inventory is acquired for use in future well completion and 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 to oilfield services expense in the accompanying consolidated statements of operations. As of December 31, 2014, the Company’s materials and supplies inventory is anticipated to be entirely used within the coming year, and all inventories are classified as current. See “Note 7 - Inventory”.
The Company’s commodities inventories consist of crude oil held in storage and is carried at the lower of average lifting 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 production costs expense in the consolidated statements of operations. See “Note 7 - Inventory”.
Investments
Available for sale investments are comprised of common and preferred stock of companies publicly traded with quoted prices in active markets. 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. The Company has no investments classified as trading securities or held to maturity securities.
Investments in non-controlled affiliates over which the Company is able to exercise significant influence but not control are accounted for under the equity method of accounting. Under the equity method of accounting, the Company’s share of the investee’s underlying net income or loss is recorded as earnings (loss) from equity method investment. Distributions received from the investment reduce the Company’s investment balance. When an investee accounted for using the equity method issues its own equity or when the Company sells a portion of its interest in the investee that results in a reduction in the Company's interest in the investee a gain or loss is recognized equal to the proportionate change in the Company’s interest in the investees net assets. Investments in equity method investees are evaluated for impairment as events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If a decline in the value of an equity method investment is determined to be other than temporary, a loss is recorded. The Company evaluated its investment in Eureka Hunter Holdings and determined that impairment was not indicated as of December 31, 2014.
Oil and Natural Gas Properties
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 as a normal retirement with no resulting gain or loss recognized in income if the amortization rate is not significantly affected; otherwise it is accounted for as the sale of an asset and a gain or loss is recognized. A sale of an entire field is generally assessed for treatment as a discontinued operation.
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 proved developed producing reserves.
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Unproved oil and gas leasehold costs that are individually significant are periodically assessed for impairment of value by comparing current quotes and recent acquisitions, future lease expirations, and taking into account management's intent, and a loss is recognized at the time of impairment by providing an impairment allowance recognized in “Exploration” expense in the consolidated statements of operations.
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 of proved and risk-adjusted probable and possible reserves. 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 in the property accounts. If a lease associated with an unproved property 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. If the Company sells its entire interest in an unproved property, the cost of the property and any proceeds received from the sale are charged to “(Gain) loss on sale of assets, net” in the consolidated statements of operations.
The estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which the Company records depletion 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.
Gas Transportation, Gathering and Processing Equipment and Other
The Company’s 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. 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 of assets is included in “(Gain) loss on sale of assets, net” in the period of disposition.
Furniture, fixtures and other equipment are carried at cost. Depreciation of furniture, fixtures and other 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 of assets is included in “(Gain) loss on sale of assets, net” in the period of disposition.
Deferred Financing Costs
The Company may, from time to time, enter into or modify certain debt arrangements such as senior debentures, term loans, and lines of credit to fund capital expenditure plans and to fund other corporate expenses. Financing costs incurred as a result of these instruments are deferred over the life of the debt instrument using the straight line method for lines of credit and the effective interest method for term loans. As of December 31, 2014, the Company had net deferred financing costs of $22.9 million and recorded interest expense of $9.7 million related to the amortization and write-off of deferred financing costs for the year ended December 31, 2014.
The Company evaluates changes and modifications of debt instruments under the guidance provided in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 470, Debt, which provides that unamortized deferred financing costs attributable to an extinguished debt instrument should be included in any gain or loss recognized on extinguishment. The Company records losses attributable to extinguished debt instruments as a component of interest expense.
F-13
Goodwill and Other Intangible Assets
In accordance with GAAP, goodwill is not amortized to earnings, but is assessed annually 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 its annual assessment date, and all goodwill had been allocated to the Company’s midstream segment. 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. ASC Topic 350, Intangibles - Goodwill and Other, 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 qualitative analysis as of April 1, 2014 and determined that no impairment existed.
As a result of the Company’s loss of its controlling financial interest in Eureka Hunter Holdings, the Company determined an event had occurred which required a reassessment of its goodwill as of December 18, 2014. The Company performed a qualitative assessment of goodwill as of December 18, 2014 and determined that no impairment existed prior to deconsolidation. The Company also performed an analysis to determine the amount of goodwill allocated to the Eureka Hunter Holdings business. As a result, all goodwill and intangible assets were derecognized as part of the gain on deconsolidation. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
Intangible assets consisted primarily of acquired gas treating agreements and customer relationships of Eureka Hunter Holdings. Such assets were being amortized over the estimated useful lives, which ranged from 2 to 13 years, up to December 18, 2014, when they were deconsolidated. 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.
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 proceeds from the production are received.
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 its 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 obligation’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as accretion expense in the accompanying consolidated statements of operations.
The ARO 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 a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated ARO. The liability for current ARO is reported in other current liabilities.
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. Prices for production are defined in sales contracts and are readily determinable or estimable based on available data.
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.
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.
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Production Costs
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.
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.
Transportation, Processing, and Other Related Costs
Transportation, processing, and other related costs are comprised of transportation and gathering expenses incurred to deliver natural gas to the processing plant and/or selling point, and are expensed as incurred.
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.
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 its 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 and Uncertain Tax Positions
Income taxes are accounted for in accordance with ASC Topic 740, Income Taxes, 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. Interest and penalties related to income taxes are recognized in “Income tax benefit” in the consolidated statement of operations.
Under accounting standards for uncertainty in income taxes, 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, 2014 or 2013.
We apply the intra-period tax allocation rules, using the with and without approach, to allocate income taxes among continuing operations, discontinued operations, other comprehensive income (loss), and additional paid-in capital when we meet the criteria as prescribed in the rules.
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, unvested restricted stock awards, stock warrants and any outstanding convertible securities. Potentially dilutive common share equivalents are not included in the computation of diluted earnings per share if they are anti-dilutive.
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Other Comprehensive Income (Loss)
The functional currency of the Company's operations in Canada is the Canadian dollar. For purposes of consolidation, the Company translated the assets and liabilities of its Canadian subsidiary into U.S. dollars at current exchange rates while revenues and expenses were 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 years ended December 31, 2014, 2013, and 2012 the Company recognized a translation loss of $1.2 million, a loss of $10.9 million, and a gain of $3.9 million, respectively.
During the year ended December 31, 2014, the Company completed the sale of its Canadian subsidiary, Williston Hunter Canada, Inc. (“WHI Canada”) and reclassified $20.7 million of the accumulated comprehensive loss attributable to this entity to “Gain (loss) on disposal of discontinued operations, net of tax” in the accompanying consolidated financial statements.
Unrealized gains and losses on changes in fair value of common and preferred stock of publicly traded companies designated as available for sale securities, 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.
As of December 31, 2014, the Company had recorded $7.4 million in unrealized losses on available for sale securities in “Accumulated other comprehensive loss”.
Regulated Activities
Energy Hunter Securities, Inc. (“Energy Hunter Securities”) is a 100%-owned subsidiary and was a registered broker-dealer and member of the Financial Industry Regulatory Authority (“FINRA”) at December 31, 2013. Among other regulatory requirements, it was subject to the net capital provisions of Rule 15c3-1 under the Securities Exchange Act of 1934, as amended. Because it did not hold customer funds or securities or owe money or securities to customers, Energy Hunter Securities was required to maintain minimum net capital equal to the greater of $5,000 or 6.67% of its aggregate indebtedness.
On September 26, 2014, Energy Hunter Securities filed a Uniform Request for Withdrawal From Broker-Dealer Registration with the Securities and Exchange Commission (“SEC”). As of December 31, 2014, Energy Hunter Securities’ had fulfilled all requests from FINRA and its broker-dealer registration has been terminated.
Sentra Corporation, a wholly-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 the Kentucky 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. During the years ended December 31, 2014, 2013, and 2012, 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 $718,000, $216,000, and $511,000, respectively.
Recently Issued Accounting Standards
Accounting standards-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews all new pronouncements to determine their impact, if any, on its financial statements.
In April 2014, the FASB issued ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 updates the requirements for reporting discontinued operations in ASC Subtopic 205-20, Presentation of Financial Statements - Discontinued Operations, by requiring classification as discontinued operations of a component of an entity or a group of components of an entity if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when either 1) the component or group of components of an entity meet the criteria to be classified as held for sale, 2) are disposed of by sale, or 3) are disposed of other than by sale (e.g. abandonment or a distribution to owners in a spinoff). The amendments in this update expand the disclosure requirements related to discontinued operations and disposals of individually significant components that do not qualify for discontinued operations presentation in the financial statements. This ASU is effective prospectively for all disposals (or classification as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
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In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 supersedes the revenue recognition requirements in ASC Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the ASC. The core principle of the revised standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. To achieve that core principle, an entity should apply the following steps: identify the contract(s) with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 requires entities to disclose both quantitative and qualitative information that enables users of financial statements to understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. This amendment is effective for annual reporting periods beginning after December 15, 2016, including interim periods within those reporting periods. The guidance allows for either a “full retrospective” adoption or a “modified retrospective” adoption, however early application is not permitted. The Company is currently evaluating the adoption methods and the impact of this ASU on its consolidated financial statements and financial statement disclosures.
In June 2014, the FASB issued ASU 2014-12, Compensation - Stock Compensation: Accounting for Share Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 clarifies that a performance target that affects vesting and that could be achieved after the requisite service period should be treated as a performance condition. An entity should apply existing guidance in ASC Topic 718 as it relates to awards with performance conditions that affect vesting to account for such awards. As such, the performance target should not be reflected in estimating the grant-date fair value of the award. This amendment is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern: Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. This update requires an entity’s management to evaluate for each annual and interim reporting period whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued or available to be issued. The update further requires certain disclosures when substantial doubt is alleviated as a result of consideration of management’s plans, and requires an express statement and other disclosures when substantial doubt is not alleviated. This amendment is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging: Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity. This update requires that, for hybrid financial instruments issued in the form of a share, an entity should determine the nature of the host contract by considering the economic characteristics and risks of the entire hybrid financial instrument, including the embedded derivative feature that is being evaluated for separate accounting from the host contract. The effects of initially adopting the amendment should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. This amendment is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption, including adoption in an interim period, is permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
In November 2014, the FASB issued ASU 2014-17, Business Combinations: Pushdown Accounting. ASU 2014-17 provides an acquired entity with the option to apply pushdown accounting in its separate financial statements upon the occurrence of an event in which an acquirer obtains control of the acquired entity. The election to apply pushdown accounting may be made each time there is a change-in-control event. If the acquired entity does not elect to apply pushdown accounting upon a change-in-control event, it can elect to apply pushdown accounting to its most recent change-in-control event in a subsequent reporting period as a change in accounting principle. This amendment is effective as of November 18, 2014. The adoption of this updated standard did not have any impact on the Company’s consolidated financial statements and financial statement disclosures.
NOTE 2 - DECONSOLIDATION OF EUREKA HUNTER HOLDINGS
On September 16, 2014, the Company entered into an agreement (the “Transaction Agreement”) with MSIP II Buffalo Holdings LLC, an affiliate of Morgan Stanley Infrastructure, Inc. (“MSI”) and a non-related party, and Eureka Hunter Holdings relating to a separate purchase agreement between MSI and Ridgeline Midstream Holdings, LLC (“Ridgeline”) providing for the purchase by MSI of all the Eureka Hunter Holdings Series A Preferred Units and Class A Common Units owned by Ridgeline. The Transaction Agreement contemplated two closings comprised of (i) the purchase by MSI of Ridgeline's equity interests in Eureka Hunter Holdings and the execution of the Second Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings (the “New LLC Agreement”) (the “First Closing”); and (ii) the purchase by MSI of an additional equity interest in Eureka Hunter Holdings
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from the Company as further described below. On October 3, 2014, the First Closing contemplated in the Transaction Agreement was consummated between MSI and Ridgeline. The Company was not a party to the transaction between MSI and Ridgeline.
Contemporaneously with the First Closing, the New LLC Agreement for Eureka Hunter Holdings became effective. In accordance with the terms of the New LLC Agreement, all of the Eureka Hunter Holdings Series A Preferred Units and Class A Common Units of Eureka Hunter Holdings acquired by MSI from Ridgeline were converted into Series A-2 Common Units, a new class of equity interests of Eureka Hunter Holdings (the “Series A-2 Units”). Magnum Hunter's Class A Common Units held on the date of the First Closing were also converted into a new class of common equity (the “Series A-1 Units”). The Series A-2 Units have preferential distribution rights over the Series A-1 Unit holders in the event a Sale Transaction or Initial Public Offering (both as defined in the New LLC Agreement) occurs subsequent to January 1, 2017. The Series A-2 Units also include certain veto rights with regards to a Sale Transaction or Initial Public Offering prior to January 1, 2017 unless certain thresholds are achieved (as provided in the New LLC Agreement). The preference on distribution rights provides the Series A-2 Unit members with downside protection through disproportionate distributions if certain specific internal rates of return are not achieved. Once the specified internal rates are achieved, however, then the Series A-1 Unit members will benefit from disproportionately larger distributions.
As a result of the conversion of the Eureka Hunter Holdings Series A Preferred Units into Series A-2 Units, the features, terms, and cash flows associated with the Series A-2 Units are substantially different than those of the former Eureka Hunter Holdings Series A Preferred Units. Consequently, the conversion was treated as an extinguishment of a class of preferred equity, and an issuance of a new class of preferred equity that was recorded initially at fair value. Additionally, the accrued and unpaid dividends outstanding on the Eureka Hunter Holdings Series A Preferred Units and the fair value associated with the embedded derivative attached to the Eureka Hunter Holdings Series A Preferred Units, which was previously accounted for as a liability in the consolidated financial statements, was included in determining the total carrying value of the equity to be extinguished. See “Note 14 - Redeemable Preferred Stock”.
The Transaction Agreement further provided that Magnum Hunter would sell to MSI in a second closing, that was expected to occur in January 2015 (the “Second Closing”), a portion of its Eureka Hunter Holdings Series A-1 Units, which, assuming completion of the full amount of additional capital contributions expected to be made by MSI, would constitute approximately 6.5% of the total common equity interests then outstanding in Eureka Hunter Holdings. Any Series A-1 Units purchased by MSI from the Company under a second closing would convert immediately into Series A-2 Units. The purchase price of such additional equity interests was expected to be approximately $65 million. Such closing, together with follow on capital contributions made by MSI in 2014, would result in the Company and MSI owning approximately equal equity interests in Eureka Hunter Holdings, which collectively would constitute an approximate 98% equity interest in Eureka Hunter Holdings.
The Transaction Agreement and the Letter Agreement (described below) further provide that the Company has the right, under certain circumstances, to not make its portion of certain required future capital contributions to Eureka Hunter Holdings, and, if the Company validly exercises its right to do so, MSI would make the capital contributions which otherwise would be made by the Company, with the Company having the right to make catchup capital contributions before the earlier of one year from the date of the capital contribution or an MLP IPO (as defined in New LLC Agreement) that would bring the Company's ownership interest back to the level prior to the capital call. We refer to this as the “carried interest” provided by MSI. This carried interest is at no cost to the Company but is subject to a maximum limit of $60 million. As of December 31, 2014, the Company had deferred capital contributions of $30 million, for which it has the right to make future catch-up contributions.
On November 18, 2014, the Company, Eureka Hunter Holdings and MSI entered into a letter agreement (the “Letter Agreement”) amending certain provisions of the Transaction Agreement entered into on September 16, 2014, pursuant to which the Company, Eureka Hunter Holdings, and MSI agreed to reduce the Company’s capital account in Eureka Hunter Holdings by 1,227,182 Series A-1 Units with a fair value of $32.6 million, effective as of the date of the New LLC Agreement, to take into account certain excess capital expenditures incurred by Eureka Hunter Pipeline in connection with certain of Eureka Hunter Pipeline’s fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects. As a result of the reduction in the Company’s capital account, the Company recorded a loss of $32.6 million, which is reflected in “General and administrative expense”. In executing the Letter Agreement, the Company, Eureka Hunter Holdings and MSI also agreed to adjust the amount and timing of (i) certain capital contributions by the Company and MSI to Eureka Hunter Holdings and (ii) MSI’s purchase of a portion of the Company’s equity interests in Eureka Hunter Holdings pursuant to the Second Closing as follows:
| i. | In connection with certain of Eureka Hunter Pipeline’s capital projects for fiscal year 2014, on November 20, 2014, MSI made a $30 million capital contribution in cash to Eureka Hunter Holdings in exchange for additional Series A-2 Units. |
| ii. | On November 20, 2014, the Company made a $20 million capital contribution in cash to Eureka Hunter Holdings in exchange for additional Series A-1 Units. |
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| iii. | In addition, in connection with a closing that occurred on December 18, 2014, MSI made a $10 million capital contribution in cash to Eureka Hunter Holdings in exchange for additional Series A-2 Units. |
| iv. | The Second Closing was accelerated to the date of closing of MSI’s capital contribution referred to in item (iii) above, and, pursuant to the accelerated closing, the Company sold to MSI 5.5% of its Series A-1 Units (reduced from the amount originally provided to be sold to MSI at the Second Closing under the Transaction Agreement) for $55 million in cash (correspondingly reduced from the amount originally provided to be received by the Company from MSI at the Second Closing). The Series A-1 Units sold to MSI by the Company were converted into Series A-2 Units upon receipt by MSI on a one-for-one basis, as provided in the Transaction Agreement and the New LLC Agreement. |
| v. | The Company has also agreed to make a $13.3 million capital contribution in cash to Eureka Hunter Holdings on or before March 31, 2015 in exchange for additional Series A-1 Units. However, the Company and MSI subsequently entered into discussions regarding Eureka Hunter Holdings’ 2015 capital expenditure budget, including the amount, timing and expected funding of the various anticipated capital expenditures. The Company anticipates that, as a result of these discussions, the parties will determine the priority, timing and (to the extent not funded by operating cash flows or borrowings) allocation between the parties of the funding of the anticipated expenditures that will most effectively serve the 2015 project plans of Eureka Hunter Pipeline. The Company also anticipates that, as part of these determinations, MSI will make the $13.3 million cash capital contribution referred to above in exchange for additional Series A-2 Units under the terms of the carried interest provisions discussed above. See “Note 11 - Long-Term Debt” for a description of the Company’s revolving credit facility, including a description of the restrictions under that facility on the Company’s ability to make investments in Eureka Hunter Holdings. |
At December 31, 2014, the Company and MSI owned 48.60% and 49.84%, respectively of the equity interests of Eureka Hunter Holdings.
The Transaction Agreement also provided MSI with certain substantive participation rights which allow MSI to participate in the management and operation of Eureka Hunter Holdings. As a result of MSI acquiring additional Series A-2 Units, which brought their total equity interest in Eureka Hunter Holdings to 49.84% as of December 18, 2014, the board of managers of Eureka Hunter Holdings was expanded from five to six members and MSI appointed the sixth manager, so that the board of managers of Eureka Hunter Holdings consists of three representatives of Magnum Hunter and three representatives of MSI. Prior to the expansion of the board of managers, the Company had majority representation on the board of managers of Eureka Hunter Holdings. As a result of the loss of majority representation on the board of managers as well as certain substantive participation rights granted to MSI in the New LLC Agreement, the Company determined it no longer held a controlling financial interest in Eureka Hunter Holdings and, therefore, the Company deconsolidated Eureka Hunter Holdings from the Company's consolidated financial statements effective December 18, 2014.
Upon loss of control and deconsolidation, the Company’s retained equity interest in Eureka Hunter Holdings was 48.60%, which is accounted for using the equity method of accounting following deconsolidation. Upon deconsolidation on December 18, 2014, the Company recognized its retained interest in Eureka Hunter Holdings at fair value of $347.3 million in accordance with the derecognition provisions of ASC Topic 810, Consolidation. The Company recognized a pre-tax gain of $509.6 million on the deconsolidation, measured as the sum of i) the fair value of the consideration received for the 5.5% equity interest sold by the Company to MSI, ii) the fair value of the Company’s retained investment, and iii) the carrying amount of the non-controlling interest prior to deconsolidation, less the carrying amount of the net assets of Eureka Hunter Holdings at December 18, 2014. Approximately $187.2 million of the pre-tax gain is attributable to the remeasurement of the retained investment in the former subsidiary to fair value. See “Note 9 - Fair Value of Financial Instruments” for the method used to determine the fair value of the Company’s retained interest in Eureka Hunter Holdings. Eureka Hunter Holdings is considered an affiliate and a related party subsequent to the deconsolidation as the Company as a result of the Company’s continued investment in and transactions with Eureka Hunter Holdings.
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Summarized income information for Eureka Hunter Holdings from December 18, 2014 through December 31, 2014 is as follows:
| Fourteen days ended December 31, 2014 | ||||
| (in thousands) | ||||
| Operating revenues | $ | 2,124 | ||
| Operating income | $ | 74 | ||
| Net loss | $ | (207 | ) | |
| Magnum Hunter's 48.6% interest in Eureka Hunter Holdings net loss for the period from December 18, 2014 to December 31, 2014 | $ | (101 | ) | |
Summarized balance sheet information for Eureka Hunter Holdings as of December 31, 2014 is as follows:
| December 31, 2014 | ||||
| (in thousands) | ||||
| Current assets | $ | 17,113 | ||
| Non-current assets | $ | 445,450 | ||
| Current liabilities | $ | 63,313 | ||
| Non-current liabilities | $ | 100,037 | ||
The following table reconciles the carrying value of the Company’s equity method investment in Eureka Hunter Holdings to the net assets of Eureka Hunter Holdings.
| December 31, 2014 | ||||
| (in thousands) | ||||
| Net Assets of Eureka Hunter Holdings attributable to Magnum Hunter, at December 18, 2014 | $ | 145,418 | ||
| Basis difference | 201,874 | |||
| Loss from equity method investment Eureka Hunter Holdings for the period from December 18, 2014 to December 31, 2014 | (101 | ) | ||
| Magnum Hunter’s investment in Eureka Hunter Holdings | $ | 347,191 | ||
The recognition of the Company's retained interest in Eureka Hunter Holdings at fair value upon deconsolidation resulted in a basis difference between the carrying value of the Company’s investment in Eureka Hunter Holdings and its proportionate share in net assets of Eureka Hunter Holdings. In accordance with ASC Topic 323, Investments - Equity Method, the difference (the “basis difference”) between the initial fair value of the Company's investment and the proportional interest in the underlying net assets of Eureka Hunter Holdings will be accounted for as if Eureka Hunter Holdings were a consolidated subsidiary. Under this method, the basis difference will be allocated to the Company's proportionate share of Eureka Hunter Holdings’ identifiable assets and liabilities. The portion of the basis difference attributable to tangible and definite lived intangible assets will be amortized over their respective estimated useful lives and reflected as a component of “Income (loss) from equity method investment”.
Magnum Hunter is currently determining the fair value of certain assets of Eureka Hunter Holdings. The valuation is expected to be finalized in the first half of 2015. The Company has estimated that the amortization of the basis difference allocable to the 14 day period from December 18, 2014 to December 31, 2014 (the “short period”) was not material. However, once a final allocation of fair value is made, the related depreciation and amortization for the short period may be significantly different from its initial estimate. The Company does not expect that its loss from equity method investment in Eureka Hunter Holdings during the short period will be materially different as a result of the fair value determination.
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NOTE 3 - ACQUISITIONS, DIVESTITURES, AND DISCONTINUED OPERATIONS
Acquisitions
The Company has recognized $27,000, $2.8 million, and $4.7 million of transaction expenses related to acquisitions in its general and administrative expenses for the years ended December 31, 2014, 2013, and 2012, respectively. Substantially all of the Company's acquisitions contained a significant amount of unproved acreage, as is consistent with the Company's business strategy.
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.
TransTex Gas Services, LP Assets Acquisition
On April 2, 2012, the Company, through Eureka Hunter Holdings, 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. The goodwill acquired in the TransTex acquisition, which is associated with the Eureka Hunter Holdings, was deductible for tax purposes prior to the deconsolidation of Eureka Hunter Holdings. 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 determined at that time utilizing a discounted future cash flow analysis. The goodwill and intangible assets associated with the TransTex acquisition were derecognized as a result of the deconsolidation of Eureka Hunter Holdings on December 18, 2014. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
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 17 - Related Party Transactions”.
Baytex Energy USA Assets Acquisition
On May 22, 2012, the Company, through its wholly-owned subsidiary, Bakken Hunter, LLC (“Bakken Hunter”), 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.
Acquisition of Viking International Resources Co., Inc.
On November 2, 2012, Triad Hunter, LLC (“Triad Hunter”), 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 the 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 13 - 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.
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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, 2014, 2013, and 2012 (TransTex revenues and operating loss were included through December 18, 2014, the date of deconsolidation of Eureka Hunter Holdings):
| For the year ended December 31, | |||||||||||||||||||||||
| 2014 | 2013 | 2012 | |||||||||||||||||||||
| Revenues | Operating Income (loss) | Revenues | Operating Income (loss) | Revenues | Operating Income (loss) | ||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||
| Eagle Operating assets | $ | 2 | $ | 938 | $ | 7,331 | $ | (26,867 | ) | $ | 5,500 | $ | (3,019 | ) | |||||||||
| TransTex assets | $ | 9,729 | $ | (2,995 | ) | $ | 12,765 | $ | (812 | ) | $ | 7,014 | $ | (393 | ) | ||||||||
| Baytex Energy USA assets | $ | 102,146 | $ | (352,151 | ) | $ | 100,572 | $ | (101,627 | ) | $ | 18,430 | $ | (6,649 | ) | ||||||||
| VIRCO acquisition | $ | 3,194 | $ | (7,936 | ) | $ | 4,453 | $ | (177 | ) | $ | 1,094 | $ | 450 | |||||||||
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 2011. 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 2011, nor are they necessarily indicative of future consolidated results.
| Pro Forma | ||||
| For the Year Ended December 31, | ||||
| 2012 | ||||
| (in thousands except for per share amount, unaudited) | ||||
| Oil and natural gas sales | $ | 159,085 | ||
| Operating loss | $ | (108,177 | ) | |
| Net loss | $ | (150,777 | ) | |
| Net loss attributable to Magnum Hunter Resources Corporation | $ | (146,764 | ) | |
| Net loss attributable to common shareholders | $ | (188,736 | ) | |
| Loss per common share, basic and diluted | $ | (1.21 | ) | |
Samson Resources Assets Acquisition
On December 20, 2012, Bakken Hunter, 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.
Agreements to Purchase Utica Shale Acreage
On August 12, 2013, Triad Hunter entered into an asset purchase agreement, with MNW Energy, LLC (“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 agreed to acquire from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in such counties, over a period of time, in staggered closings, subject to certain conditions. The maximum purchase price, if MNW delivers 32,000 acres with acceptable title, would be $142.1 million, excluding title costs. During the years ended December 31, 2014 and 2013, Triad Hunter purchased 16,456 and 5,922 net leasehold acres, respectively, from MNW for an aggregate purchase price of $67.3 million and $24.6 million, respectively. See “Note 18 - Commitments and Contingencies”.
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Ormet Asset Acquisition
On June 18, 2014, the Company entered into an Asset Purchase Agreement (“Ormet Asset Purchase Agreement”) with Ormet Corporation for the purchase of certain mineral interests in approximately 1,700 net acres, consisting of 1,375 net acres in Monroe County, Ohio and 325 net acres in Wetzel County, West Virginia. Prior to the execution of the Ormet Asset Purchase Agreement, the Company held leasehold interests in a portion of the subject acreage, which leasehold interests covered only the Marcellus zone and were subject to a 12.5% royalty on production to Ormet Corporation. On July 24, 2014, the Company closed on the purchase of the sub-surface mineral rights, including any royalty interests, in the underlying acreage, giving the Company an approximate 100% net revenue interest in and rights to oil, natural gas, and other minerals located in or under and that may be produced from the property, at any depth. The total purchase price for this transaction was approximately $22.7 million cash.
Discontinued Operations
In September 2013, the Company adopted a plan to divest all of its interests in (i) MHP, whose oil and natural gas operations are located primarily in the southern Appalachian Basin in Kentucky and Tennessee, and (ii) the Canadian operations of WHI Canada, which was a wholly-owned subsidiary of the Company.
Planned Divestiture of Magnum Hunter Production
In connection with the Company’s adoption of a plan to divest of its interest in MHP in September 2013, the Company determined that the planned divestiture met the assets held for sale criteria and the criteria for classification as a discontinued operation. The Company classified the associated assets and liabilities of MHP as assets and liabilities held for sale in the consolidated balance sheet as of September 30, 2013 and reflected the results of MHP’s operations as discontinued operations in the consolidated statements of operations for the three and nine months ended September 2013 and 2012. The Company determined at each interim and annual period subsequent to September 30, 2013, and until September 30, 2014, that the planned divestiture continued to meet the criteria for classification as a discontinued operation based upon its ongoing marketing activities. Consequently, the Company continued to report the results of operations for MHP, including the results of operations of MHP for comparable periods presented from a preceding year, as a component of discontinued operations in the Company’s consolidated financial statements for each interim and annual period from September 30, 2013 through June 30, 2014, and reported the assets and liabilities of MHP as assets and liabilities held for sale on the corresponding consolidated balance sheets.
During the year ended December 31, 2013, the Company recorded an impairment expense of $18.5 million, net of tax, to record MHP at the estimated selling price less costs to sell. Based upon additional information on estimated selling prices obtained through active marketing of the assets, the Company recorded an additional impairment expense during the quarter ended March 31, 2014 of $18.6 million, net of tax, to reflect the net assets at their estimated selling prices, less costs to sell. The Company did not record any impairment for MHP for the three month period ended June 30, 2014.
Effective September 2014, the Company withdrew its plan to divest MHP to further evaluate the oil and natural gas exploration and development upside opportunities underlying the acreage the Company has access to through MHP’s leasehold and mineral interest rights. As a result of this decision the Company ceased all marketing activities for MHP, and consequently MHP no longer met the criteria for classification as a discontinued operation as of September 30, 2014.
As of September 30, 2014, the Company measured the carrying value of MHP’s individual long-lived assets previously classified as held for sale at the lesser of (i) their carrying amount before each asset was classified as held for sale, adjusted for any depreciation or amortization expense that would have been recognized had it been continuously classified as held and used, and (ii) their fair value at the date of the subsequent decision not to sell. As a result of this assessment, the Company recorded additional impairments of $1.9 million to the carrying amount of MHP’s unproved oil and natural gas properties and $17.0 million to the carrying amount of MHP’s proved oil and natural gas properties, which were recorded in exploration expense and impairment of proved oil and gas properties, respectively. In addition, the Company recorded depreciation expense of $1.7 million related to long-lived assets, whose fair value exceeded book value, adjusted for depreciation expense, as of September 30, 2014. In total, the Company recorded approximately $67.6 million of impairment related to MHP from September 30, 2013 through December 31, 2014.
The Company reclassified the results of MHP’s operations from discontinued operations to continuing operations for all periods presented in these consolidated financial statements, and MHP’s assets and liabilities have been reclassified out of assets and liabilities held for sale and included with the Company’s other assets held and used as of December 31, 2014.
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Williston Hunter Canada Asset Sale
On April 10, 2014, WHI Canada closed on the sale of certain oil and natural gas properties and assets located in Alberta, Canada for cash consideration of CAD $9.5 million in cash (approximately U.S. $8.7 million at the exchange rate as of the close of business on April 10, 2014). The effective date of the sale was January 1, 2014. The Company recognized a gain of $6.1 million which is recorded in gain (loss) on disposal of discontinued operations.
Sale of Williston Hunter Canada
On May 12, 2014, the Company closed on the sale of 100% of its ownership interest in the Company’s Canadian subsidiary, WHI Canada, whose assets consisted primarily of oil and natural gas properties located in the Tableland Field in Saskatchewan, Canada, for a purchase price of CAD $75.0 million (approximately U.S. $68.8 million at the exchange rate as of the close of business on May 12, 2014), prior to customary purchase price adjustments, with an effective date of March 1, 2014, of which CAD $18.4 million was placed in escrow pending final approval from the Canadian Revenue Authority. The Company received the cash held in escrow in July 2014. The Company recognized a loss of $12.9 million which is recorded in gain (loss) on disposal of discontinued operations. The loss on disposal of WHI Canada for the year ended December 31, 2014 includes $20.7 million in foreign currency translation adjustment which was reclassified out of accumulated other comprehensive income upon closing the sale of our foreign operation.
There were no assets or liabilities held for sale at December 31, 2014. The following shows the Company’s assets and liabilities held for sale at December 31, 2013:
| December 31, 2013 | |||
| (in thousands) | |||
| Accounts receivable | $ | 4,362 | |
| Other current assets | 1,004 | ||
| Oil and natural gas properties, net | 150,770 | ||
| Gas transportation, gathering, and processing equipment and other, net | 11,721 | ||
| Other long-term assets | 196 | ||
| Total assets held for sale | $ | 168,053 | |
| Accounts payable | $ | 7,292 | |
| Accrued liabilities and other liabilities | 5,573 | ||
| Asset retirement obligations | 8,678 | ||
| Other long-term liabilities | 5,845 | ||
| Total liabilities held for sale | $ | 27,388 | |
Sale of Hunter Disposal
On February 17, 2012, the Company, through its wholly-owned subsidiary Triad Hunter, sold 100% of its equity ownership interest in Hunter Disposal to a wholly-owned subsidiary of GreenHunter Resources, Inc. (“GreenHunter”), for total consideration of $9.3 million, comprised of cash of $2.2 million, 1,846,722 restricted common shares of GreenHunter, valued at $2.6 million based on a closing price of $1.79 per share, discounted for restrictions, 88,000 shares of GreenHunter 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 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 9 - 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 is a related party as described in “Note 17 - 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
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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 Magnum Hunter’s 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 recognized a gain on the sale of $172.5 million, net of tax.
In the months that followed closing, the Company and Penn Virginia were unable to agree upon the final settlement of the working capital adjustments as called for in the purchase and sale agreement and the disagreement was subsequently submitted to arbitration. The determination by the arbitrator was received by the Company on July 25, 2014 and resulted in a downward adjustment of the cash portion of the purchase price of $33.7 million plus accrued interest of $1.3 million. This liability was settled in cash on July 31, 2014. The Company had previously reserved and recognized substantially all of this obligation in its financial statements as of December 31, 2013. For the years ended December 31, 2014 and 2013, the Company recorded downward adjustments to the gain on sale of Eagle Ford Hunter of $7.1 million and $28.1 million, respectively.
The Company included the results of operations of WHI Canada, which has historically been the only member of our Canadian Upstream segment, through May 12, 2014, Eagle Ford Hunter, which has historically been included as part of the U.S. Upstream segment, through April 24, 2013, and Hunter Disposal, which has historically been included as part of the Oilfield Services segment, through February 17, 2012 in discontinued operations as follows:
| Year Ended December 31, | |||||||||||
| 2014 | 2013 | 2012 | |||||||||
| (in thousands) | |||||||||||
| Revenues | $ | 8,533 | $ | 67,490 | $ | 114,068 | |||||
Expenses (1) | (3,975 | ) | (130,331 | ) | (122,099 | ) | |||||
| Other income (expense) | 3 | 186 | (94 | ) | |||||||
| Income (loss) from discontinued operations before tax | 4,561 | (62,655 | ) | (8,125 | ) | ||||||
Income tax benefit (expense) (2) | — | 94 | (1,648 | ) | |||||||
| Income (loss) from discontinued operations, net of tax | 4,561 | (62,561 | ) | (9,773 | ) | ||||||
Gain (loss) on disposal of discontinued operations, net of taxes (3)(4) | (13,855 | ) | 71,510 | 2,409 | |||||||
| Income (loss) from discontinued operations, net of tax | $ | (9,294 | ) | $ | 8,949 | $ | (7,364 | ) | |||
_____________________
| (1) | Includes impairment expense of $65.4 million, and $0.3 million for the years ended December 31, 2013 and 2012, respectively, and exploration expense of $0.1 million, $19.9 million, and $36.8 million for the years ended December 31, 2014, 2013, and 2012, respectively relating to the discontinued operations of WHI Canada, which is recorded in income (loss) from discontinued operations. |
| (2) | The Company’s 2013 effective tax rate on the loss from discontinued operations is 0.2% 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 none, $11.9 million, and $1.4 million for the years ended December 31, 2014, 2013, and 2012, respectively. |
| (4) | The Company’s 2013 effective tax rate on the gain on disposal of discontinued operations is 14.23% 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, (“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 and Williston Hunter, 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 loss on the sale of $7.1 million.
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On September 30, 2014, Bakken Hunter, a wholly-owned subsidiary of the Company, closed on the sale of certain non-operated working interests in oil and natural gas properties located in Divide County, North Dakota for cash consideration of $23.5 million, subject to customary purchase price adjustments. The effective date of the sale was April 1, 2014. The Company recognized a gain on the sale of $7.2 million pending final adjustments.
On October 15, 2014, Bakken Hunter closed on the sale of certain non-operated working interests in oil and natural gas properties located in Divide County, North Dakota for cash consideration of approximately $84.8 million, subject to customary purchase price adjustments. During the year ended December 31, 2014, the Company recorded an impairment expense of $15.2 million to record these assets at the estimated selling price less costs to sell. The effective date of the sale was August 1, 2014. The Company recognized a loss on the sale of $2.7 million pending final adjustments.
Sale of Certain Other Eagle Ford Shale Assets
On January 28, 2014, the Company, through its wholly-owned subsidiary Shale Hunter, LLC (“Shale Hunter”) and certain other affiliates, closed on the sale of certain of their oil and natural gas properties and related assets located 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 assets sold consisted primarily of interests in leasehold acreage located in Atascosa County, Texas and working interests in five horizontal wells, of which four were operated by the Company. The effective date of the sale was December 1, 2013. As consideration for the assets sold, the Company received aggregate purchase price consideration of $15.5 million in cash, after customary purchase price adjustments, and 65,650,000 ordinary shares of NSE with a fair value of approximately $9.4 million at January 28, 2014 (based on the closing market price of $0.14 per share on January 28, 2014). These investment holdings represented approximately 17% of the total shares outstanding of NSE as of the closing date, and have been designated as available for sale securities, which are recorded at fair value of approximately $2.5 million and included in investments in the consolidated balance sheet as of December 31, 2014. The Company recognized a loss on the sale of the Shale Hunter assets of $4.5 million during the first quarter of 2014.
In connection with the closing of the sale, Shale Hunter and NSE Texas entered into a transition services agreement which provides that, during a specified transition period ending on July 28, 2015 unless otherwise extended or modified, Shale Hunter will provide NSE Texas with certain transitional services relating to the assets sold for which Shale Hunter is receiving a monthly fee.
Sale of Certain West Virginia Assets
On November 3, 2014, Triad Hunter closed on the sale of certain non-core working interests in oil and gas properties located primarily in Calhoun and Roane Counties, West Virginia for cash consideration of $1.2 million, subject to customary purchase price adjustments. During the three months ended September 30, 2014, the Company recorded an impairment expense of $5.7 million to record these assets at the estimated selling price less costs to sell. The effective date of the sale was August 1, 2014. The Company recognized a gain on the sale of approximately $1.1 million pending final adjustments.
NOTE 4 - OIL & NATURAL GAS SALES
During the years ended December 31, 2014, 2013, and 2012, the Company recognized sales from oil, natural gas, and natural gas liquids (“NGLs”) as follows:
| Year Ended December 31, | |||||||||||
| 2014 | 2013 | 2012 | |||||||||
| (in thousands) | |||||||||||
| Oil | $ | 131,109 | $ | 147,798 | $ | 82,225 | |||||
| Natural gas | 91,277 | 53,821 | 45,825 | ||||||||
| NGLs | 46,115 | 19,080 | 5,678 | ||||||||
| Total oil and natural gas sales | $ | 268,501 | $ | 220,699 | $ | 133,728 | |||||
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NOTE 5 - PROPERTY, PLANT, & EQUIPMENT
Oil and Natural Gas Properties
Capitalized Costs
The following sets forth the net capitalized costs under the successful efforts method for oil and natural gas properties as of:
| December 31, | |||||||
| 2014 | 2013 | ||||||
| (in thousands) | |||||||
| Mineral interests in properties: | |||||||
| Unproved leasehold costs | $ | 481,643 | $ | 469,337 | |||
| Proved leasehold costs | 257,185 | 336,357 | |||||
| Wells and related equipment and facilities | 560,060 | 438,275 | |||||
| Uncompleted wells, equipment and facilities | 46,346 | 97,748 | |||||
| Advances to operators for wells in progress | 1,411 | 13,571 | |||||
| Total costs | 1,346,645 | 1,355,288 | |||||
| Less accumulated depreciation, depletion, and amortization | (248,410 | ) | (130,629 | ) | |||
| Net capitalized costs | $ | 1,098,235 | $ | 1,224,659 | |||
Depreciation, depletion, and amortization expense for proved oil and natural gas properties was $121.9 million, $69.0 million, and $49.2 million for the years ended December 31, 2014, 2013, and 2012, respectively.
During the years ended December 31, 2014, 2013 and 2012, the Company recorded proved property impairments as follows:
| Year Ended December 31, | |||||||||||
| 2014 | 2013 | 2012 | |||||||||
| (in thousands) | |||||||||||
| Williston Basin | $ | 261,270 | $ | 8,498 | $ | 3,631 | |||||
| Appalachian Basin | 6,001 | 1,151 | 76 | ||||||||
| Western Kentucky | 33,811 | 40,043 | 67 | ||||||||
| South Texas | 194 | 319 | 65 | ||||||||
| $ | 301,276 | $ | 50,011 | $ | 3,839 | ||||||
Impairment of proved oil and gas properties related to Western Kentucky during the years ended December 31, 2014 and 2013 included write-downs to fair value of MHP’s proved oil and gas property of $33.8 million and $26.9 million, respectively.
Exploration
The following table provides the Company's exploration expense for 2014, 2013 and 2012:
| Year Ended December 31, | |||||||||||
| 2014 | 2013 | 2012 | |||||||||
| (in thousands) | |||||||||||
| Geological and geophysical | $ | 1,564 | $ | 1,402 | $ | 2,570 | |||||
| Leasehold impairments: | |||||||||||
| Williston Basin | 103,147 | 89,167 | 59,214 | ||||||||
| Appalachian Basin | 9,978 | 6,773 | 15,033 | ||||||||
| Western Kentucky | 3,820 | 3,047 | 2,154 | ||||||||
| South Texas | — | — | 1,404 | ||||||||
| $ | 118,509 | $ | 100,389 | $ | 80,375 | ||||||
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The Company did not drill any dry holes during the years ended December 31, 2014, 2013, or 2012. All wells drilled were completed as producing wells.
Capitalized Exploratory Well Costs Greater Than a Year
As of December 31, 2014, the Company had suspended exploratory well costs capitalized for periods greater than one year related to the Farley pad in Washington County, Ohio and the Farley #1305H well. The Farley pad was constructed to drill multiple horizontal wells into a previously untested zone in the Utica formation. The Company spud the Farley #1305H in April of 2013 and experienced well pressure instability during the fracture stimulation stage of completion. Further fracture stimulation and evaluation of this well will depend on the outcome of the drilling and completion of the Farley #1306H and #1304H wells, which were drilled in 2014 and are expected to be fracture stimulated and tested during mid-year 2015. Aggregate cost incurred through December 31, 2014 for the Farley pad and the Farley #1305H well were $1.1 million and $13.8 million, respectively.
Gas Transportation, Gathering, and Processing Equipment and Other
The historical cost of gas transportation, gathering, and processing equipment and other property, presented on a gross basis with accumulated depreciation, as of December 31, 2014 and 2013, is summarized as follows:
| December 31, | |||||||
| 2014 | 2013 | ||||||
| (in thousands) | |||||||
| Gas transportation, gathering and processing equipment and other | $ | 100,436 | $ | 315,642 | |||
| Less accumulated depreciation and depletion | (23,013 | ) | (26,222 | ) | |||
| Net capitalized costs | $ | 77,423 | $ | 289,420 | |||
Depreciation expense for other property and equipment was $22.1 million, $15.6 million, and $8.1 million, for the years ended December 31, 2014, 2013, and 2012, respectively.
As a result of the deconsolidation of Eureka Hunter Holdings, the Company derecognized gas transportation, gathering and processing equipment relating to Eureka Hunter Holdings of $439.0 million, net of accumulated depreciation and depletion of $30.3 million.
NOTE 6 - INTANGIBLE ASSETS
Following the change in accounting treatment of the Company’s investment in Eureka Hunter Holdings on December 18, 2014, the net unamortized intangible assets of TransTex were derecognized and included in the carrying amount of Eureka Hunter Holdings in determining the gain on deconsolidation. There are no remaining intangible assets as of December 31, 2014. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
The following table summarizes the Company's net intangible assets during the year ended December 31, 2013:
| December 31, | ||||
| 2013 | ||||
| (in thousands) | ||||
| Customer relationships | $ | 5,434 | ||
| Trademark | 859 | |||
| Existing contracts | 4,199 | |||
| Total intangible assets | 10,492 | |||
| Accumulated amortization: | ||||
| Customer relationships | (1,248 | ) | ||
| Trademark | (137 | ) | ||
| Existing contracts | (2,577 | ) | ||
| Intangible assets, net of accumulated amortization | $ | 6,530 | ||
Amortization expense for intangible assets was $2.0 million, $2.5 million, and $1.5 million for the years ended December 31, 2014, 2013, and 2012, respectively. As a result of the deconsolidation of the Company’s interest in Eureka Hunter Holdings, the Company expects no additional aggregate amortization of intangible assets over the next five years.
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NOTE 7 - INVENTORY
The following table sets forth the composition of the Company's inventory as of December 31, 2014 and December 31, 2013.
| December 31, | |||||||
| 2014 | 2013 | ||||||
| (in thousands) | |||||||
| Materials and supplies | $ | 1,436 | $ | 6,790 | |||
| Oil in tanks | 832 | 368 | |||||
| Inventory | $ | 2,268 | $ | 7,158 | |||
NOTE 8 - 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 its ARO was approximately $26.5 million and $16.2 million at December 31, 2014 and 2013, respectively.
The following table summarizes the changes in the Company’s ARO balances during the years ended December 31, 2014 and 2013:
| December 31, | |||||||
| 2014 | 2013 | ||||||
| (in thousands) | |||||||
| Asset retirement obligation at beginning of period | $ | 16,216 | $ | 30,680 | |||
| Assumed in acquisition | — | 17 | |||||
| Liabilities incurred | 218 | 253 | |||||
| Liabilities settled | (107 | ) | (98 | ) | |||
| Liabilities sold | (2,598 | ) | (7,614 | ) | |||
| Accretion expense | 1,478 | 2,264 | |||||
| Revisions in estimated liabilities | 3,208 | 1,935 | |||||
| Reclassified as liabilities associated with assets held for sale | — | (11,148 | ) | ||||
| Reclassified from liabilities associated with assets held for sale | 8,109 | — | |||||
| Correction of prior year error | — | (73 | ) | ||||
| Asset retirement obligation at end of period | 26,524 | 16,216 | |||||
| Less: current portion | (295 | ) | (53 | ) | |||
| Asset retirement obligation at end of period | $ | 26,229 | $ | 16,163 | |||
NOTE 9 - 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:
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| i. | Level 1 — Quoted prices (unadjusted) for identical assets or liabilities in active markets; |
| ii. | 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; |
| iii. | Level 3 — Significant inputs to the valuation model are unobservable. |
Transfers between Levels 1 and 2 occur at the end of the reporting period in which it is determined that the observability of significant inputs has increased or decreased. There were no transfers between levels of the fair value hierarchy during 2014 and 2013.
The Company used the following fair value measurements for certain of its assets and liabilities during the years ended December 31, 2014 and 2013:
Level 1 Classification:
Available for Sale Securities
At December 31, 2014 and 2013, the Company held common and preferred stock of publicly traded companies with quoted prices in an active market. Accordingly, the fair market value measurements of these securities have been classified as Level 1.
Level 2 Classification:
Commodity Derivative Instruments
At December 31, 2014 and December 31, 2013, 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 10 - Investments and Derivatives”.
As of December 31, 2014 and December 31, 2013, the Company’s derivative contracts were with financial institutions, many of which were either senior lenders to the Company or affiliates of such senior lenders, and some of which had investment grade credit ratings. Certain counterparties to the Company’s commodity derivatives positions are no longer participants in the Company’s credit facilities following the execution of new credit agreements on October 22, 2014. See “Note 11 - Long-Term Debt”. 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 a preferred stock derivative liability resulting from its Eureka Hunter Holdings Series A Preferred Units, which contained certain conversion features, redemption options, and other features.
The fair value of the bifurcated conversion feature was valued using the “with and without” analysis in a simulation model based upon management’s estimate of the expected life of the conversion feature. The key inputs used in the model to determine fair value were estimated volatility, credit spread, and the estimated enterprise value of Eureka Hunter Holdings.
The selection of assumptions for expected term and total enterprise value were made based on a weighting of possible outcomes. The term of the conversion feature, which was linked to the terms of the Eureka Hunter Holdings Amended and Restated Limited Liability Company Agreement (“Eureka Hunter Holdings LLC Agreement”), could range from zero to six years. During the three-month period ended June 30, 2014, the Company changed the estimated term to one to two years due to changes in the Company's expectation of when the conversion feature with respect to the Eureka Hunter Holdings Series A Preferred Units would be exercised. On October 3, 2014, MSI purchased all of the issued and outstanding Eureka Hunter Holdings Series A Preferred Units and Class A Common Units held by Ridgeline, which constituted all of the issued and outstanding Eureka Hunter Holdings Series A Preferred Units. In making the Company's determination of the total enterprise value for Eureka Hunter Holdings, the Company considered the purchase price associated with MSI's purchase of the Eureka Hunter Holdings Series A Preferred Units, and its implied value to
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the enterprise as a whole. The issued and outstanding Eureka Hunter Holdings Series A Preferred Units were converted at fair value to a new class of preferred equity of Eureka Hunter Holdings on October 3, 2014, pursuant to the provisions of the New LLC Agreement, which became effective October 3, 2014. See “Note 14 - Redeemable Preferred Stock”.
The fair value calculation is sensitive to movements in volatility, estimated remaining term, and the total enterprise value of Eureka Hunter Holdings. A decrease in the estimated term of the conversion feature results in a higher fair value of the conversion feature. As the implied volatility of the instruments increases so too does the fair value of the derivative liability arising from the conversion and redemption features. Similarly, as the total enterprise value of Eureka Hunter Holdings increases, the fair value of the derivative liability increases. Decreases in volatility and total enterprise value would result in a reduction to the fair value of the derivative liability associated with these instruments.
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 to GreenHunter, a related party. See “Note 3 - Acquisitions, 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:
| December 31, 2014 | ||||
| Life | 2.1 | years | ||
| Risk-free interest rate | 0.95 | % | ||
| Estimated volatility | 91 | % | ||
| Dividend | — | |||
| GreenHunter Resources Stock price at end of period | $ | 0.71 | ||
The sensitivity of the estimate of volatility used in determining the fair value of the convertible security embedded derivative would not have a significant impact to the Company’s financial statements based on the value of the assets as compared to the financial statements as a whole.
The following tables present financial assets and liabilities which are adjusted to fair value on a recurring basis at December 31, 2014 and 2013:
| Fair Value Measurements on a Recurring Basis | |||||||||||
| December 31, 2014 | |||||||||||
| (in thousands) | |||||||||||
| Level 1 | Level 2 | Level 3 | |||||||||
| Available for sale securities | $ | 3,864 | $ | — | $ | — | |||||
| Commodity derivative assets | — | 16,511 | — | ||||||||
| Convertible security derivative assets | — | — | 75 | ||||||||
| Total assets at fair value | $ | 3,864 | $ | 16,511 | $ | 75 | |||||
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| Fair Value Measurements on a Recurring Basis | |||||||||||
| December 31, 2013 | |||||||||||
| (in thousands) | |||||||||||
| Level 1 | Level 2 | Level 3 | |||||||||
| Available for sale securities | $ | 1,819 | $ | — | $ | — | |||||
| Commodity derivative assets | — | 554 | — | ||||||||
| Convertible security derivative assets | — | — | 79 | ||||||||
| Total assets at fair value | $ | 1,819 | $ | 554 | $ | 79 | |||||
| Commodity derivative liabilities | $ | — | $ | 2,279 | $ | — | |||||
| Convertible preferred stock derivative liabilities | — | — | 75,934 | ||||||||
| Total liabilities at fair value | $ | — | $ | 2,279 | $ | 75,934 | |||||
The following table presents the changes in the fair value of the derivative assets and liabilities measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31, 2014, 2013 and 2012:
| Embedded Derivatives | |||||||
| Series A Preferred Units | Convertible Security | ||||||
| (in thousands) | |||||||
| Fair value at December 31, 2011 | $ | — | $ | — | |||
| Issuance of embedded derivative (liability) asset | (52,240 | ) | 405 | ||||
| Decrease in fair value recognized in gain on derivative contracts, net | 8,692 | (141 | ) | ||||
| Fair value at December 31, 2012 | $ | (43,548 | ) | $ | 264 | ||
| Issuance of embedded liability | (14,645 | ) | — | ||||
| Increase in fair value recognized in loss on derivative contracts, net | (17,741 | ) | (185 | ) | |||
| Fair value at December 31, 2013 | $ | (75,934 | ) | $ | 79 | ||
| Issuance of redeemable preferred stock | (5,479 | ) | — | ||||
| Increase in fair value recognized in loss on derivative contracts, net | (91,792 | ) | (4 | ) | |||
| Conversion of Eureka Hunter Holdings Series A Preferred Units to Series A-2 Units | 173,205 | — | |||||
| Fair value as of December 31, 2014 | $ | — | $ | 75 | |||
During the year ended December 31, 2014, the valuation of the conversion feature embedded in the Eureka Hunter Holdings Series A Preferred Units increased the fair value of the embedded derivative liability by approximately $91.8 million as a result of changes in the total enterprise value of Eureka Hunter Holdings and the Company’s estimate of the expected remaining term of the conversion feature up to and prior to conversion. Management’s estimate of the expected remaining term of the conversion option shortened the time horizon previously estimated by management, resulting in a higher fair value of the conversion feature. Management’s estimates were based upon several factors, including market prices for like-kind transactions, an estimate of the likelihood of each of the possible settlement options, which included redemption through a call or put option, or a liquidity event that triggers conversion to Class A Common Units of Eureka Hunter Holdings.
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Other Fair Value Measurements
The following table presents the carrying amounts and fair values categorized by fair value hierarchy level of the Company’s financial instruments not carried at fair value:
| Fair Value | December 31, 2014 | December 31, 2013 | ||||||||||||||||
| Hierarchy Level | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | ||||||||||||||
| (in thousands) | ||||||||||||||||||
| Senior Notes | Level 2 | $ | 597,355 | $ | 498,000 | $ | 597,230 | $ | 651,300 | |||||||||
| MHR Senior Revolving Credit Facility | Level 3 | — | — | 218,000 | 218,000 | |||||||||||||
| MHR Second Lien Term Loan | Level 3 | 329,140 | 329,140 | — | — | |||||||||||||
| Eureka Hunter Pipeline term loan | Level 3 | — | — | 50,000 | 58,291 | |||||||||||||
| Equipment notes payable | Level 3 | 22,238 | 22,150 | 18,615 | 17,676 | |||||||||||||
The fair value of the Company's Senior Notes is based on quoted market prices available for Magnum Hunter’s Senior Notes. The fair value hierarchy for the Company's Senior Notes is Level 2 (quoted prices for identical or similar assets in markets that are not active).
The carrying values of the Company's senior revolving credit facility (“MHR Senior Revolving Credit Facility”) approximate fair value as the facility is subject to short-term floating interest rates that approximate the rates available to the Company at these dates. The fair value hierarchy for the MHR Senior Revolving Credit Facility is Level 3.
The carrying value of the Company’s second lien term loan as of December 31, 2014 approximates fair value based upon to the limited passage of time since being issued at a 3% discount and the Company’s credit rating remaining stable since entering into the second lien term loan on October 22, 2014.
The fair value of Eureka Hunter Pipeline's term loan as of December 31, 2013 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. Eureka Hunter Pipeline’s second lien term loan was paid in full in March 2014.
The fair value of all fixed-rate notes and the credit facility is based on interest rates currently available to the Company.
Fair Value on a Non-Recurring Basis
The Company follows the provisions of ASC Topic 820, Fair Value Measurement, for non-financial assets and liabilities measured at fair value on a non-recurring basis. As it relates to Magnum Hunter, ASC Topic 820 applies to certain non-financial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; measurements of the fair value of retained interests in deconsolidated subsidiaries, measurements of oil and natural gas property impairments, and the initial recognition of AROs, for which fair value is used. 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.
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A reconciliation of the beginning and ending balances of Magnum Hunter's ARO is presented in “Note 8 - Asset Retirement Obligations”. Other fair value measurements made on a non-recurring basis during the years ended December 31, 2014, 2013, and 2012 consist of the following:
| Fair Value Measurements on a Non-recurring Basis | ||||||||||||
| (Level 1) | (Level 2) | (Level 3) | ||||||||||
| Year ended December 31, 2014 | (in thousands) | |||||||||||
| Fair value of proved properties impaired | $ | — | $ | — | $ | 584,895 | ||||||
| Fair value of long-lived assets of MHP | — | — | 28,443 | |||||||||
| Fair value of retained interest in Eureka Hunter Holdings | — | — | 347,291 | |||||||||
| Year ended December 31, 2013 | ||||||||||||
| Fair value of proved properties impaired | $ | — | $ | — | $ | 329,409 | ||||||
| Fair value of long-lived assets of MHP | — | — | 87,149 | |||||||||
| Year ended December 31, 2012 | ||||||||||||
| Fair value of proved properties impaired | $ | — | $ | — | $ | 372,450 | ||||||
| Fair value of acquisitions | — | — | 532,150 | |||||||||
Proved Properties Impairment
The Company recorded impairment charges from continuing operations of $301.3 million, $50.0 million and $3.8 million during the years ended December 31, 2014, 2013 and 2012, respectively, as a result of writing down the carrying value of certain properties to fair value. In order to determine the amounts of the impairment charges, 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 proved, probable, and possible 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 discounted cash flow model utilizing a 10 percent discount 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.
Impairment of Long-Lived Assets of MHP
As of September 30, 2014, the Company has measured the carrying value of certain long-lived assets of MHP previously classified as held for sale at their fair value in connection with their reclassification to assets held and used. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”. The fair value of these assets was derived using a variety of assumptions including market precedent transactions for similar assets, analyst pricing, and risk-adjusted discount rates for similar transactions. The Company has designated these valuations as Level 3.
Retained Interest in Eureka Hunter Holdings
On December 18, 2014, the Company sold to MSI a common equity interest in Eureka Hunter Holdings comprising approximately 5.5% of the total common equity interests in Eureka Hunter Holdings pursuant to the Transaction Agreement and Letter Agreement. The closing of this transaction, and other transactions contemplated by the Transaction Agreement and Letter Agreement, resulted in the Company’s investment in Eureka Hunter Holdings changing from a controlling financial interest in a consolidated subsidiary to an equity method investment in Eureka Hunter Holdings. As a result, the Company remeasured its retained interest in Eureka Hunter Holdings at fair value. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”. The fair value of the Series A-2 Units issued to MSI upon extinguishment of its Class A Common Units and Series A Preferred Units, the downward adjustment of the Company’s Series A-1 Units and the Company’s retained interest was determined by utilizing a hybrid of a probability-weighted expected return model and an option pricing model. This methodology involves an analysis of future values for the enterprise under a range of different scenarios and corresponding allocations of the enterprise value outcomes to the various securities having a claim on value. The key assumptions used in the model to determine fair value upon were as follows: (i) the pricing to be achieved upon a liquidating event or initial public offering, (ii) the cost of equity for Eureka Hunter Holdings, (iii) the timing and probability of an
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initial public offering as contemplated in the New LLC Agreement of Eureka Hunter Holdings at discreet points in time, and (iv) the expected volatility of the equity of Eureka Hunter Holdings.
Acquisitions
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 10 - INVESTMENTS AND DERIVATIVES
Investment Holdings
On February 17, 2012, the Company received 1,846,722 restricted common shares of GreenHunter and 88,000 shares of GreenHunter 10% Series C Preferred Stock as partial consideration for the sale by Triad Hunter, of its equity ownership interest in Hunter Disposal to GreenHunter. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”. The GreenHunter common stock investment is accounted for under the equity method and had no carrying value as of December 31, 2014 and $0.6 million at December 31, 2013. The GreenHunter common shares are publicly traded and have a fair value of $1.3 million and $2.1 million at December 31, 2014 and 2013, respectively, which is not reflected in the carrying value since the Company’s investment is accounted for using the equity method. The Series C Preferred Stock had a fair value of $1.3 million and $1.7 million at December 31, 2014 and 2013, respectively. The GreenHunter Series C Preferred Stock is publicly traded with a readily determinable fair value and is classified as available for sale.
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 reclassified out of comprehensive income and into other income.
On January 28, 2014, the Company acquired 65,650,000 common shares of NSE valued at approximately $9.4 million (based on the closing market price of $0.14 per share on January 28, 2014) in partial consideration of an asset sale. These shares have a fair value of $2.5 million at December 31, 2014 and are classified as available for sale.
On December 18, 2014, the Company lost its controlling financial interest in Eureka Hunter Holdings as a result of capital contributions made by MSI to Eureka Hunter Holdings and a subsequent sale by the Company of a portion of its equity interest in Eureka Hunter Holdings to MSI. The Company will continue to exercise significant influence through its retained equity interest of 48.6% and through representation on Eureka Hunter Holdings’ board of managers. As a result, the Company determined the equity method should be used to account for its retained interest. The Company recorded its retained interest in Eureka Hunter Holdings initially at a fair value of $347.3 million. After recording the Company’s equity in net loss of Eureka Hunter Holdings of $0.1 million for the period from December 18, 2014 to December 31, 2014, the carrying value of the Company’s equity interest in Eureka Hunter Holdings was $347.2 million.
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Below is a summary of changes in investments for the years ended December 31, 2014 and 2013:
Available for Sale Securities (1) | Equity Method Investments | ||||||
| (in thousands) | |||||||
| Carrying value at December 31, 2011 | $ | 497 | $ | — | |||
| Additional cost basis from acquisition | — | 4,043 | |||||
| Transfers from cost method investments | 1,770 | — | |||||
| Loss from equity method investment, including impairment of carrying value | — | (1,971 | ) | ||||
| Change in fair value recognized in other comprehensive loss | (309 | ) | — | ||||
| Carrying value at December 31, 2012 | $ | 1,958 | $ | 2,072 | |||
| Securities received as consideration | 42,300 | — | |||||
| Sales of securities | (50,562 | ) | — | ||||
| Realized gain recognized in net income | 8,262 | — | |||||
| Decrease in carrying amount return of capital | — | (138 | ) | ||||
| Loss from equity method investment | — | (994 | ) | ||||
| Other adjustments | (55 | ) | — | ||||
| Change in fair value recognized in other comprehensive loss | (84 | ) | — | ||||
| Carrying value at December 31, 2013 | $ | 1,819 | $ | 940 | |||
| Securities received as consideration | 9,446 | — | |||||
| Equity in net loss recognized in other income (expense) | — | — | |||||
| Fair value of retained interest in Eureka Hunter Holdings | — | 347,292 | |||||
| Loss from equity method investment | — | (1,038 | ) | ||||
| Other adjustments | — | (3 | ) | ||||
| Change in fair value recognized in other comprehensive loss | (7,401 | ) | — | ||||
| Carrying value as of December 31, 2014 | $ | 3,864 | $ | 347,191 | |||
(1) Available for sale securities above includes $147,000 that has been classified as held for sale associated with MHP
as of December 31, 2013.
The Company's investments have been presented in the consolidated balance sheet as of December 31, 2014 and December 31, 2013 as follows:
| December 31, 2014 | |||||||||||
| (in thousands) | |||||||||||
| Available for Sale Securities | Equity Method Investments | Total | |||||||||
| Investments - Current | $ | 3,864 | $ | — | $ | 3,864 | |||||
| Investments - Non-current | — | 347,191 | 347,191 | ||||||||
| Carrying value as of December 31, 2014 | $ | 3,864 | $ | 347,191 | $ | 351,055 | |||||
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| December 31, 2013 | |||||||||||
| (in thousands) | |||||||||||
| Available for Sale Securities | Equity Method Investments | Total | |||||||||
| Investments - Current | $ | 1,672 | $ | 590 | $ | 2,262 | |||||
| Investments - Non-current | — | 350 | 350 | ||||||||
| Investments - Held for Sale | 147 | — | 147 | ||||||||
| Carrying value as of December 31, 2013 | $ | 1,819 | $ | 940 | $ | 2,759 | |||||
The cost for equity securities and their respective fair values as of December 31, 2014 and 2013 are as follows:
| December 31, 2014 | |||||||||||||||
| Cost | Gross Unrealized Gains | Gross Unrealized Losses | Fair Value | ||||||||||||
| (in thousands) | |||||||||||||||
| Securities available for sale, carried at fair value: | |||||||||||||||
| Equity securities | $ | 9,876 | $ | — | $ | (7,323 | ) | $ | 2,553 | ||||||
| Equity securities - related party (see “Note 17 - Related Party Transactions”) | 2,200 | — | (889 | ) | 1,311 | ||||||||||
| Total Securities available for sale | $ | 12,076 | $ | — | $ | (8,212 | ) | $ | 3,864 | ||||||
| December 31, 2013 | |||||||||||||||
| Cost | Gross Unrealized Gains | Gross Unrealized Losses | Fair Value | ||||||||||||
| (in thousands) | |||||||||||||||
| Securities available for sale, carried at fair value: | |||||||||||||||
| Equity securities | $ | 428 | $ | — | $ | (281 | ) | $ | 147 | ||||||
| Equity securities - related party (see “Note 17 - Related Party Transactions”) | 2,200 | — | (528 | ) | 1,672 | ||||||||||
| Total Securities available for sale | $ | 2,628 | $ | — | $ | (809 | ) | $ | 1,819 | ||||||
Commodity and Financial Derivative Instruments
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.
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 is expected to be offset by the increased amount it received for its production.
Occasionally, 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
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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 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, 2014:
| Weighted Avg | ||||
| Natural Gas | Period | MMBtu/d | Price per MMBtu | |
| Swaps | Jan 2015 - Dec 2015 | 40,000 | $4.09 | |
| Weighted Avg | ||||
| Crude Oil | Period | Bbl/d | Price per Bbl | |
Collars (1) | Jan 2015 - Dec 2015 | 259 | $85.00 - $91.25 | |
| Ceilings sold (call) | Jan 2015 - Dec 2015 | 1,570 | $120.00 | |
| Floors sold (put) | Jan 2015 - Dec 2015 | 259 | $70.00 | |
(1) A collar is a sold call and a purchased put. Some collars are “costless” collars with the premiums netting to approximately zero.
As of December 31, 2014, Bank of America, Bank of Montreal, Citibank, N.A., and the Royal Bank of Canada are the only counterparties to the Company's commodity derivatives positions. All but one of these counterparties were participants in the MHR Senior Revolving Credit Facility. Although borrowings under the MHR Senior Revolving Credit Facility are used as collateral for the Company’s commodity derivatives with those counterparties participating in the MHR Senior Revolving Credit Facility, the Company had no outstanding borrowings under that credit facility as of December 31, 2014. Additionally, certain counterparties to the Company's commodity derivatives positions are no longer participants in the Company's credit facilities following the execution of new credit agreements on October 22, 2014. As a result, the Company is exposed to credit losses in the event of nonperformance by the counterparties where the Company’s open commodity derivative contracts are in a gain position. The Company does not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions. See “Note 11 - Long-Term Debt”.
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. See “Note 9 - Fair Value of Financial Instruments” and “Note 13 - Shareholders' Equity”. During October 2014, all issued and outstanding Eureka Hunter Holdings Series A Preferred Units were converted to a new class of preferred equity of Eureka Hunter Holdings. See “Note 14 - Redeemable Preferred Stock”. As a result of the conversion, the preferred stock derivative liability was extinguished.
At December 31, 2014 and 2013, the Company has recognized an embedded derivative asset associated with the conversion feature of the promissory note receivable from GreenHunter received as partial consideration for the sale of Hunter Disposal. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”.
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The following table summarizes the fair value of the Company's derivative contracts as of the dates indicated:
| Derivatives not designated as hedging instruments | |||||||||||||||
| Derivative Assets | Derivative Liabilities | ||||||||||||||
| December 31, | December 31, | ||||||||||||||
| 2014 | 2013 | 2014 | 2013 | ||||||||||||
| Commodity | (in thousands) | ||||||||||||||
| Derivative assets | $ | 16,511 | $ | 529 | $ | — | $ | — | |||||||
| Derivatives assets, long term | — | 25 | — | — | |||||||||||
| Derivative liabilities | — | — | — | (1,903 | ) | ||||||||||
| Derivative liabilities, long term | — | — | — | (376 | ) | ||||||||||
| Total commodity | $ | 16,511 | $ | 554 | $ | — | $ | (2,279 | ) | ||||||
| Financial | |||||||||||||||
| Derivative assets | $ | 75 | $ | 79 | $ | — | $ | — | |||||||
| Derivative liabilities, long term | — | — | — | (75,934 | ) | ||||||||||
| Total financial | $ | 75 | $ | 79 | $ | — | $ | (75,934 | ) | ||||||
| Total derivatives | $ | 16,586 | $ | 633 | $ | — | $ | (78,213 | ) | ||||||
Certain of the Company's derivative instruments are subject to enforceable master netting arrangements that provide for the net settlement of all derivative contracts between the Company and a counterparty in the event of default or upon the occurrence of certain termination events. The tables below summarize the Company's commodity derivatives and the effect of master netting arrangements on the presentation in the Company's consolidated balance sheets as of:
| December 31, 2014 | |||||||||||
| Gross Amounts of Recognized Assets and Liabilities | Gross Amounts Offset on the Consolidated Balance Sheet | Net Amount | |||||||||
| (in thousands) | |||||||||||
| Current assets: Fair value of derivative contracts | $ | 18,146 | $ | (1,635 | ) | $ | 16,511 | ||||
| Long-term assets: Fair value of derivative contracts | — | — | — | ||||||||
| Current liabilities: Fair value of derivative contracts | (1,635 | ) | 1,635 | — | |||||||
| Long-term liabilities: Fair value of derivative contracts | — | — | — | ||||||||
| Total fair value of derivative contracts | $ | 16,511 | $ | — | $ | 16,511 | |||||
| December 31, 2013 | |||||||||||
| Gross Amounts of Assets and Liabilities | Gross Amounts Offset on the Consolidated Balance Sheet | Net Amount | |||||||||
| (in thousands) | |||||||||||
| Current assets: Fair value of derivative contracts | $ | 4,034 | $ | (3,505 | ) | $ | 529 | ||||
| Long-term assets: Fair value of derivative contracts | 516 | (491 | ) | 25 | |||||||
| Current liabilities: Fair value of derivative contracts | (5,408 | ) | 3,505 | (1,903 | ) | ||||||
| Long-term liabilities: Fair value of derivative contracts | (867 | ) | 491 | (376 | ) | ||||||
| Total fair value of derivative contracts | $ | (1,725 | ) | $ | — | $ | (1,725 | ) | |||
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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, 2014, 2013 and 2012:
| For the Year Ended December 31, | |||||||||||
| 2014 | 2013 | 2012 | |||||||||
| (in thousands) | |||||||||||
| Gain (loss) on settled transactions | $ | 1,306 | $ | (8,216 | ) | $ | 11,294 | ||||
| Gain (loss) on open contracts | 18,232 | (17,058 | ) | 10,945 | |||||||
| Loss on extinguished embedded derivative | (91,792 | ) | — | — | |||||||
| Total gain (loss), net | $ | (72,254 | ) | $ | (25,274 | ) | $ | 22,239 | |||
NOTE 11 - LONG-TERM DEBT
Notes payable at December 31, 2014 and 2013 consisted of the following:
| As of December 31, | |||||||
| 2014 | 2013 | ||||||
| (in thousands) | |||||||
| Senior Notes Payable due May 15, 2020, interest rate of 9.75%, net of unamortized discount of $2.6 million and $2.8 million at December 31, 2014 and 2013, respectively | $ | 597,355 | $ | 597,230 | |||
Various equipment and real estate notes payable with maturity dates February 2015 - November 2017, interest rates of 4.25% - 7.94% (1) | 22,238 | 18,615 | |||||
Eureka Hunter Pipeline Credit Agreement due March 28, 2018, interest rate of 3.66% (2) | — | — | |||||
| Eureka Hunter Pipeline second lien term loan due August 16, 2018, interest rate of 12.5% | — | 50,000 | |||||
| MHR Senior Revolving Credit Facility due April 13, 2018, interest rate of 2.92% at December 31, 2014 | — | 218,000 | |||||
| MHR second lien term loan due October 22, 2019, interest rate of 8.5%, net of unamortized discount of $10.0 million at December 31, 2014 | 329,140 | — | |||||
| $ | 948,733 | $ | 883,845 | ||||
| Less: current portion | (10,770 | ) | (3,967 | ) | |||
| Total long-term debt obligations, net of current portion | $ | 937,963 | $ | 879,878 | |||
_________________
(1) Balance as of December 31, 2013 includes notes classified as liabilities associated with assets held for sale of which $0.2 million is current and $3.8 million is long term.
(2) | As a result of the deconsolidation of Eureka Hunter Holdings, this loan or revolver was derecognized with Eureka Hunter Holdings’ other liabilities. See “Note 2 - Deconsolidation of Eureka Hunter Holdings” |
The following table presents the approximate annual maturities of debt, gross of unamortized discount:
| (in thousands) | |||
| 2015 | $ | 10,770 | |
| 2016 | 12,129 | ||
| 2017 | 5,948 | ||
| 2018 | 3,959 | ||
| 2019 | 325,757 | ||
| Thereafter | 602,825 | ||
| $ | 961,388 | ||
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.
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On December 18, 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, the Company 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 exchanged 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 or 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, 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, 2014, 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 equal to the greater of:
| i. | 1.0% of the principal amount of the note; and |
| ii. | 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
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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.
MHR Senior Revolving Credit Facility and Second Lien Term Loan
Revolving Credit Facility
On December 13, 2013, the Company entered into a Third Amended and Restated Credit Agreement (“Credit Agreement”) by and among the Company, Bank of Montreal, as Administrative Agent, the lenders a party thereto and the agents a 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 (“Prior Credit Agreement”).
On May 6, 2014, the Company and the other parties to the Credit Agreement entered into the First Amendment to Third Amended and Restated Credit Agreement (the “Amendment”). The Amendment increased the borrowing base from $232.5 million to $325.0 million in connection with the regular semi-annual redetermination of the Company's borrowing base derived from the Company's proved crude oil and natural gas reserves. The borrowing base could have been increased or decreased in connection with such redeterminations up to a maximum commitment level of $750.0 million. The Amendment provided that such increased borrowing base shall be reduced (i) by the lesser of $25.0 million or 50% of the net proceeds from issuances by the Company of common equity on or before July 1, 2014 (other than common equity issued pursuant to any stock incentive or stock option plan or any other compensatory arrangements); (ii) by certain specified reductions in connection with certain proposed asset dispositions; (iii) on July 1, 2014 by $25.0 million less any prior adjustment of the borrowing base due to an equity issuance as contemplated by clause (i); and (iv) by $0.25 for each $1.00 of any additional Senior Notes issued by the Company. The Amendment further provided that from May 6, 2014 through July 1, 2014 the Applicable Margin (as defined in the Credit Agreement) component of the interest charged on revolving borrowings under the Credit Agreement was 2.75% for alternate base rate (“ABR”) Loans (as defined in the Credit Agreement) and 3.75% for Eurodollar Loans (as defined in the Credit Agreement). From and after July 1, 2014 through the date of the Company’s delivery of a certificate for the quarter ended June 30, 2014, with respect to, among other things, the Company’s compliance with the covenants in the Credit Agreement (the “Compliance Certificate”), the Applicable Margin component of interest charged on revolving borrowings under the Credit Agreement ranged from 1.50% to 2.25% for ABR Loans and from 2.50% to 3.25% for Eurodollar Loans. From and after the Company’s delivery of the Compliance Certificate, the Applicable Margin component of interest charged on revolving borrowings under the Credit Agreement ranged from 1.00% to 1.75% for ABR Loans and from 2.00% to 2.75% for Eurodollar Loans.
In addition, the Amendment modified certain of the Credit Agreement’s financial covenants, including:
| i. | permitting the Company to take into account the borrowing base increase as though it occurred on March 31, 2014 for purposes of maintaining a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0; |
| ii. | providing for a ratio of EBITDAX to Interest Expense of not less than (a) 2.0 to 1.0 for the fiscal quarter ended March 31, 2014, (b) 2.25 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (c) 2.50 to 1.0 for the fiscal quarter ended December 31, 2014 and for each fiscal quarter ending thereafter; and |
| iii. | beginning with the fiscal quarter ended June 30, 2014, providing for a ratio of total Debt to EBITDAX of not more than (a) 4.75 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014, (b) 4.50 to 1.0 for the fiscal quarter ended December 31, 2014, and (c) 4.25 to 1.0 for the fiscal quarter ending March 31, 2015 and for each fiscal quarter ending thereafter. |
The Amendment also (i) amended the definition of EBITDAX and provided that certain acquisitions and dispositions be given pro forma effect in the calculation of EBITDAX; (ii) increased the letter of credit commitment from $10.0 million to $50.0 million and provided that outstanding letter of credit exposure not be included in certain determinations of Debt; (iii) required the total value of the Company’s oil and gas properties included in the reserve reports for the borrowing base determinations in which the lenders under the Credit Agreement have perfected liens be increased from 80% to 90%; and (iv) modified certain covenants in the Credit Agreement with respect to permitted investments by the Company to increase flexibility.
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On October 22, 2014, the Company entered into the Fourth Amended and Restated Credit Agreement by and among the Company, as borrower, Bank of Montreal, as administrative agent, the lenders a party thereto and the agents a party thereto as amended by that certain First Amendment to the Credit Agreement and Waiver, dated February 24, 2015 (as amended, the “New Credit Agreement”). The New Credit Agreement amended and restated the Credit Agreement, dated as of December 13, 2013, by and among those parties, as amended.
The New Credit Agreement provides for an asset-based, senior secured revolving credit facility maturing October 22, 2018 (the “Revolving Facility”) with an initial borrowing base of $50 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 $250 million. As discussed below, however, provisions of the Second Lien Credit Agreement (“Second Lien Term Loan Agreement”) limit the amount of indebtedness that the Company may incur under the New Credit Agreement.
The terms of the New Credit Agreement provide that the Revolving Facility may be used for loans, and subject to a $50 million sublimit, letters of credit. The New Credit Agreement provides for a commitment fee of 0.5% of the unused portion of the borrowing base under the Revolving Facility.
Borrowings under the Revolving Facility will, at the Company’s election, bear interest at either (i) an ABR equal to the higher of (a) the Prime Rate (as determined by the Bank of Montreal), (b) the overnight federal funds effective rate, plus 0.50% per annum, and (c) the adjusted one-month LIBOR plus 1.00% or (ii) the adjusted LIBO Rate (which is based on LIBOR), plus, in each of the cases described in clauses (i) and (ii), an applicable margin ranging from 1.00% to 2.00% for ABR loans and from 2.00% to 3.00% for adjusted LIBO Rate loans. Accrued interest on each ABR loan is payable in arrears on the last day of each March, June, September and December and accrued interest on each adjusted LIBO Rate loan is payable in arrears on the last day of the Interest Period (as defined in the New Credit Agreement) applicable to the borrowing of which such adjusted LIBO Rate loan is a part and, in the case of an adjusted LIBO Rate borrowing with an Interest Period of more than three months’ duration, each day prior to the last day of such Interest Period that occurs at intervals of three months’ duration after the first day of such Interest Period.
The New 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 cash 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 New 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, (viii) enter into transactions with affiliates, and (ix) enter into hedging transactions.
In addition, the New Credit Agreement requires the Company to satisfy certain financial covenants, including maintaining:
| i. | commencing with the fiscal quarter ending March 31, 2015, a current ratio (as defined in the New Credit Agreement) of not less than (a) 0.75 to 1.0 for the fiscal quarter ending March 31, 2015 and (b) 1.0 to 1.0 for the fiscal quarter ending June 30, 2015 and for each fiscal quarter ending thereafter; |
| ii. | a leverage ratio (secured net debt to EBITDAX (as defined in the New Credit Agreement) with, beginning with the fiscal quarter ending March 31, 2016, a limitation on netting of up to $100,000,000 of unencumbered cash) of not more than (a) 2.5 to 1.0 as of the last day of the fiscal quarter ended December 31, 2014, (b) 2.50 to 1.00 as of the last day of the fiscal quarters ending March 31, June 30, September 30, and December 31, 2015 and (c) 2.0 to 1.0 as of the last day of each fiscal quarter ending March 31, 2016 and each fiscal quarter ending thereafter; and |
| iii. | the proved reserves based asset coverage ratios contained in the Second Lien Term Loan Agreement described below. |
At December 31, 2014, the Company would not have been compliance with its current ratio financial covenant under the New Credit Agreement, which required the Company maintain a current ratio of not less than 1.0 to 1.0 as of that date. The Company has obtained a waiver from its lenders, effective December 31, 2014, of the current ratio covenant requirement for the December 31, 2014 compliance period and entered into a First Amendment to Credit Agreement and Limited Waiver, dated February 24, 2015 (the “First Amendment”), that, among other things, lowers the current ratio requirement to 0.75 to 1.0 for the fiscal quarter ending March 31, 2015. The current ratio requirement increases to 1.0 to 1.0 for the fiscal quarter ending June 30, 2015 and each fiscal quarter ending thereafter. The First Amendment also modified the leverage ratio requirement to remain at not more than 2.5x beginning with the December 31, 2014 compliance period through the December 31, 2015 compliance period. The Company
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believes that these waivers and modifications to its financial covenant ratios together with the successful execution of certain contemplated asset sales and other transactions will enable it to maintain compliance with such ratios for 2015.
Pursuant to the First Amendment, until such time as the Company can demonstrate a (i) current ratio of 1.0 to 1.0 as of the last day of a fiscal quarter or, if there is a proposed Liquidity Event (described below) or other arms-length liquidity event with a non-affiliate or unrestricted subsidiary, demonstrate a current ratio of 1.0 to 1.0 on a pro forma basis as of the last day of a calendar month assuming that the Liquidity Event (or other liquidity event) had occurred during such calendar month and (ii) in the case of a decrease of the Rates for ABR Loans and Eurodollar Loans, pro forma compliance with the other applicable financial covenants as of the last day of the fiscal quarter most recently ended, (such period, the “Adjusted Period”), then:
| i. | neither the Company nor any of its restricted subsidiaries may make additional investments in excess of $2 million in the aggregate in oil and gas properties (other than acreage swaps and associated assets) and other applicable assets; |
| ii. | neither the Company nor any of its restricted subsidiaries may make additional capital contributions to or other investments in unrestricted subsidiaries in amounts in excess of $2 million in the aggregate; and |
| iii. | the Company cannot make any additional capital contributions to or other investments in Eureka Hunter Holdings. |
For purposes of the First Amendment, a “Liquidity Event” means any event or events resulting in (i) an increase in Liquidity (as defined in the New Credit Agreement) of at least $36,000,000 as a result of an arm’s length transaction with a person or entity that is not an affiliate of the Company or (ii) the receipt by the Company or any restricted subsidiary of aggregate net cash proceeds of at least $73,000,000 as a result of one or more arm’s length transactions with either (a) persons or entities who are not affiliates of the Company or (b) the Company’s unrestricted subsidiaries.
In addition, effective March 31, 2015, if a Liquidity Event (described in clause (i) of the preceding paragraph) has not occurred prior to such date, or April 30, 2015 if a proposed Liquidity Event described in clause (ii) of the preceding paragraph for which a pro forma current ratio calculation is used has not occurred prior to such date, the rates for ABR Loans and Eurodollar Loans shall automatically increase by 1.00% and the commitment fee shall automatically increase by 0.25% and such elevated rates shall continue until the day immediately preceding the date on which the Adjusted Period ends.
The Company posted letters of credit for $39.3 million million using availability under the Company’s Senior Revolving Credit Facility. The borrowing capacity under the Senior Revolving Credit Facility was reduced by $39.3 million. No amounts are outstanding under the Senior Revolving Credit Facility as of December 31, 2014.
The obligations of the Company under the New 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 New Credit Agreement) and any “Event of Default” under the Second Lien Term Loan Agreement, subject to certain cure periods.
Subject to certain exceptions, the Revolving Facility is secured by substantially all of the assets of the Company and its restricted subsidiaries, including, without limitation, no less than 90% of the present value (with a discount rate of 10%) of the proved oil and gas reserves of the Company and its restricted subsidiaries. Additionally, any collateral pledged as security for the Second Lien Term Loan (as defined below) is required to be pledged as security for the New Credit Agreement. In connection with the New 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. The Company’s restricted subsidiaries under the New Credit Agreement and the Second Lien Term Loan do not include the Company’s investee, which conducts midstream operations, Eureka Hunter Holdings, and its subsidiaries, Eureka Hunter Pipeline, and TransTex Hunter.
Second Lien Term Loan
On October 22, 2014, the Company also entered into a Second Lien Credit Agreement (the “Second Lien Term Loan Agreement”), by and among the Company, as borrower, Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent, the lenders party thereto and the agents party thereto.
The Second Lien Term Loan Agreement provides for a $340 million term loan facility (“Second Lien Term Loan”), secured by, subject to certain exceptions, a second lien on substantially all of the assets (except unproved leases) of the Company and its restricted subsidiaries. The entire $340 million Second Lien Term Loan was drawn on October 22, 2014, net of a discount of $10.2
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million. The Company used the proceeds of the Second Lien Term Loan to repay amounts outstanding under its Credit Agreement, to pay transaction expenses related to the New Credit Agreement and the Second Lien Term Loan Agreement, and for working capital and general corporate purposes. Amounts borrowed under the Second Lien Term Loan that are repaid or prepaid may not be reborrowed. The Second Lien Term Loan has a maturity date of October 22, 2019 and will amortize (beginning December 31, 2014) in equal quarterly installments in an aggregate annual amount equal to 1.00% of the original principal amount of the Second Lien Term Loan.
Borrowings under the Second Lien Term Loan will, at the Company’s election, bear interest at either (i) an alternate base rate (which is equal to the higher of (a) the prime rate (as determined by Credit Suisse AG), (b) the overnight federal funds effective rate, plus 0.50% per annum, and (c) the adjusted one-month LIBOR plus 1.00%) plus 6.50% or (ii) the adjusted LIBO Rate, which means an interest rate per annum equal to the greater of (a) 1.00% per annum and (b) the product of (i) the LIBO Rate in effect for such Interest Period and (ii) the Statutory Reserve Rate, plus 7.50%.
The Second Lien Term Loan Agreement contains negative covenants substantially similar to those in the New Credit Agreement 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) dispose of all or substantially all of its assets or enter into mergers, consolidations, or similar transactions; (iv) change the nature of its business; (v) make investments, loans, or advances or guarantee obligations; (vi) pay cash dividends or make certain other payments; (vii) enter into transactions with affiliates; (viii) enter into sale and leaseback transactions; (ix) enter into hedging transactions; and (x) amend its organizational documents or the New Credit Agreement. The Second Lien Term Loan Agreement limits the amount of indebtedness that the Company may incur under the New Credit Agreement to the greater of (i) the sum of $50 million plus the aggregate amount of loans repaid or prepaid under the Second Lien Term Loan Agreement and (ii) an amount equal to 25% of Adjusted Consolidated Net Tangible Assets (as defined in the Second Lien Term Loan Agreement) of the Company and its restricted subsidiaries; provided, in the case of clause (ii), after giving effect to such incurrence of indebtedness and the application of proceeds therefrom, aggregate secured debt may not exceed 25% of the Adjusted Consolidated Net Tangible Assets of the Company and its restricted subsidiaries as of the date of such incurrence.
The Second Lien Term Loan Agreement also requires the Company to satisfy certain financial covenants, including maintaining
| i. | a ratio of the present value of proved reserves using five year strip pricing to secured debt of not less than 1.5 to 1.0 and a ratio of the present value proved developed and producing reserves using five year strip pricing to secured debt of not less than 1.0 to 1.0, each as of the last day of any fiscal quarter commencing with the fiscal quarter ended December 31, 2014; and |
| ii. | commencing with the fiscal quarter ending March 31, 2016, a leverage ratio (secured net debt to EBITDAX (as defined in the Second Lien Term Loan Agreement) with a limitation on netting of up to $100,000,000 of unencumbered cash) of not more than 2.5 to 1.0 as of the last day of any fiscal quarter for the trailing four-quarter period then ended. |
At December 31, 2014, the Company was in compliance with all of its covenants applicable for the period, contained in the Second Lien Term Loan Agreement.
The obligations of the Company under the Second Lien Term Loan Agreement may be accelerated upon the occurrence of an Event of Default (as defined in the Second Lien Term Loan Agreement). Events of Default are substantially similar to Events of Default under the New Credit Agreement (except that a breach of a financial covenant under the New Credit Agreement will not constitute an Event of Default under the Second Lien Term Loan Agreement until acceleration) and include customary events for these types of financings.
In connection with the Second Lien Term Loan Agreement, the Company and its restricted subsidiaries also entered into customary ancillary agreements and arrangements, which among other things, provide that the Second Lien Term Loan is unconditionally guaranteed by such restricted subsidiaries.
The Company incurred direct financing costs associated with entering into the Amendment and the New Credit Agreement and the Second Lien Term Loan Agreement in the amount of $12.0 million, which were deferred and are being amortized over the remaining term of the agreements.
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Eureka Hunter Pipeline Credit Facilities
Upon executing the new Eureka Hunter Pipeline Credit Agreement on March 28, 2014, Eureka Hunter Pipeline terminated its revolving credit agreement with SunTrust Bank and the term loan agreement with Pennant Park (“Original Eureka Hunter Credit Facilities”). Eureka Hunter Pipeline used proceeds from the Eureka Hunter Pipeline Credit Agreement to pay in full all outstanding obligations related to the termination of the Original Eureka Hunter Credit Facilities, which included the principal outstanding amount of $50.0 million, a prepayment penalty of $2.2 million, and accrued, unpaid interest of $1.5 million.
Eureka Hunter Pipeline Credit Agreement
On March 28, 2014, Eureka Hunter Pipeline entered into the Eureka Hunter Pipeline Credit Agreement, by and among Eureka Hunter Pipeline, as borrower, ABN AMRO Capital USA, LLC, as a lender and as administrative agent, and the other lenders a party thereto.
The credit agreement, which has a maturity date of March 28, 2018, provides for a revolving credit facility in an aggregate principal amount of up to $117.0 million (with the potential to increase the aggregate commitment under the credit agreement to an aggregate principal amount of up to $150.0 million, subject to the consent of the lender parties and the satisfaction of certain conditions), secured by a first lien on substantially all of the assets of Eureka Hunter Pipeline and its subsidiaries, which include TransTex Hunter, as well as by Eureka Hunter Pipeline’s pledge of the equity in its subsidiaries. The subsidiaries of Eureka Hunter Pipeline also guarantee Eureka Hunter Pipeline’s obligations under the credit agreement. The credit agreement is non-recourse to Magnum Hunter. The Company incurred deferred financing costs directly associated with entering into the Eureka Hunter Pipeline Credit Agreement in the amount of $1.2 million which are being amortized straight-line over the term of the revolving credit facility. The straight-line method of amortization results in substantially the same periodic amortization as the effective interest method.
On November 19, 2014, Eureka Hunter Pipeline entered into an amendment to the Eureka Hunter Pipeline Credit Agreement. Pursuant to the amendment, the number of lenders under the Eureka Hunter Pipeline Credit Agreement increased from five to thirteen and the aggregate loan commitments available to Eureka Hunter Pipeline under the Eureka Hunter Pipeline Credit Agreement correspondingly increased from an aggregate principal amount of $117.0 million to $225.0 million. In addition, the amendment lowered the commitment fee and the interest rates payable under the Eureka Hunter Pipeline Credit Agreement.
On December 18, 2014, the Company’s investment in Eureka Hunter Holdings, the parent of Eureka Hunter Pipeline, changed from a controlling financial interest in a consolidated subsidiary to an equity method investment in Eureka Hunter Holdings. As a result, the outstanding balance under the Eureka Hunter Pipeline Credit Agreement has been deconsolidated as of December 31, 2014. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
Equipment Note Payable
On January 23, 2014, the Company’s wholly owned subsidiary, Alpha Hunter Drilling, LLC, entered into a master loan and security agreement with CIT Finance LLC 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.
Building Note Payable
Effective September 30, 2014, MHP refinanced its $3.8 million term loan with Traditional Bank, Inc. that was due to mature in early 2015. The new loan is collateralized by an office building owned by MHP and carried an initial principal balance of $3.8 million at an interest rate of 4.875% with a maturity date of September 30, 2024.
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Interest Expense
The following table sets forth interest expense for the years ended December 31, 2014, 2013 and 2012:
| Year Ended December 31, | |||||||||||
| 2014 | 2013 | 2012 | |||||||||
| (in thousands) | |||||||||||
| Interest expense incurred on debt, net of amounts capitalized | $ | 76,784 | $ | 67,803 | $ | 44,447 | |||||
| Amortization and write-off of deferred financing costs | 9,679 | 4,818 | 7,399 | ||||||||
| Total interest expense | $ | 86,463 | $ | 72,621 | $ | 51,846 | |||||
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 $2.0 million was capitalized as part of the construction of Eureka Hunter Holdings’ gas gathering system during the year ended 2014, prior to deconsolidation on December 18, 2014, and $2.6 million and $4.4 million was capitalized during the years ended December 31, 2013 and 2012 respectively.
For the year ended December 31, 2014, interest expense incurred on debt includes a $2.2 million prepayment penalty incurred by Eureka Hunter Pipeline as a result of its early termination of the Original Eureka Hunter Credit Facilities on March 28, 2014, which penalty represents an additional cost of borrowing for a period shorter than contractual maturity. In addition, interest expense includes the write-off of $2.7 million in unamortized deferred financing costs related to those terminated agreements, which costs were expensed at the time of early extinguishment, $1.7 million in unamortized deferred financing costs related to the May 6, 2014, Amendment of the MHR Senior Revolving Credit Facility and the write-off of $1.4 million in unamortized deferred financing costs related to the New Credit Agreement.
NOTE 12 - SHARE-BASED COMPENSATION
Employees, officers, directors and other persons who contribute to the success of Magnum Hunter are eligible for grants of unrestricted common stock, restricted common stock, common stock options, and stock appreciation rights under the Company's Amended and Restated Stock Incentive Plan. At December 31, 2014, 27,500,000 shares of the Company's common stock are authorized to be issued under the plan, and 11,035,482 shares have been issued as of December 31, 2014, of which 2,317,013 shares remained unvested at December 31, 2014. Additionally, 13,194,956 options to purchase shares and stock appreciation rights were outstanding as of December 31, 2014, of which 3,973,183 remained unvested at December 31, 2014.
The Company recognized share-based compensation expense of $12.5 million, $13.6 million, and $15.7 million for the years ended December 31, 2014, 2013, and 2012 respectively.
A summary of stock option and stock appreciation rights activity for the years ended December 31, 2014, 2013, and 2012 is presented below:
| 2014 | 2013 | 2012 | ||||||||||||||||||
| Weighted-Average Exercise Price | Weighted-Average Exercise Price | Weighted-Average Exercise Price | ||||||||||||||||||
| Shares | Shares | Shares | ||||||||||||||||||
| Outstanding at beginning of the year | 16,891,419 | $ | 5.69 | 14,846,994 | $ | 6.01 | 12,566,199 | $ | 5.64 | |||||||||||
| Granted | — | $ | — | 4,937,575 | $ | 4.11 | 4,978,750 | $ | 6.00 | |||||||||||
| Exercised | (2,375,273 | ) | $ | 4.09 | (1,466,025 | ) | $ | 3.66 | (1,304,050 | ) | $ | 1.54 | ||||||||
| Forfeited or expired | (1,321,190 | ) | $ | 6.27 | (1,427,125 | ) | $ | 5.51 | (1,393,905 | ) | $ | 7.14 | ||||||||
| Outstanding at end of the year | 13,194,956 | $ | 5.91 | 16,891,419 | $ | 5.69 | 14,846,994 | $ | 6.01 | |||||||||||
| Exercisable at end of the year | 9,140,323 | $ | 6.22 | 9,983,743 | $ | 5.96 | 8,683,622 | $ | 5.97 | |||||||||||
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A summary of the Company’s non-vested common stock options and stock appreciation rights for the years ended December 31, 2014, 2013, and 2012 is presented below:
| Non-vested Options | 2014 | 2013 | 2012 | |||||
| Non-vested at beginning of the year | 6,907,476 | 6,163,372 | 5,650,782 | |||||
| Granted | — | 4,937,575 | 4,978,750 | |||||
| Vested | (1,915,526 | ) | (3,133,700 | ) | (3,405,434 | ) | ||
| Forfeited | (1,018,767 | ) | (1,059,771 | ) | (1,060,726 | ) | ||
| Non-vested at end of the year | 3,973,183 | 6,907,476 | 6,163,372 | |||||
Total unrecognized compensation cost related to the non-vested common stock options and stock appreciation rights was $3.2 million, $14.1 million, and $12.6 million as of December 31, 2014, 2013, and 2012, respectively. The unrecognized compensation cost at December 31, 2014 is expected to be recognized over a weighted-average period of 0.95 years. At December 31, 2014, the aggregate intrinsic value for the outstanding options and stock appreciation rights was $6.4 million; and the weighted average remaining contract life of the outstanding options was 5.57 years.
No options or stock appreciation rights were granted during the year ended December 31, 2014. The assumptions used in the fair value method calculations for the years ended 2013 and 2012 are disclosed in the following table:
| Year Ended December 31, | ||||
| 2013 | 2012 | |||
Weighted average fair value per option granted during the period (1) | $2.52 | $3.72 | ||
Assumptions (2) : | ||||
Weighted average stock price volatility (3) | 80.61% | 82.64% | ||
| Weighted average risk free rate of return | 0.78% | 0.77% | ||
Weighted average estimated forfeiture rate (4) | 2.45% | —% | ||
| Weighted average expected term | 4.65 years | 4.51 years | ||
________________________________
(1) | Calculated using the Black-Scholes fair value based method for service and performance based grants and the Lattice Model for market based grants. |
(2) | The Company has not paid cash dividends on its common stock. |
(3) | The volatility assumption was estimated based upon a blended calculation of historical volatility and implied volatility over the life of the awards. |
(4) | For the year 2012, the Company estimated forfeitures to be zero based on the majority of options being granted to executive officers who are less likely to forfeit shares. |
During the years ended December 31, 2014 and 2013, the Company granted 105,812 and 182,994 fully vested shares of common stock, respectively, to the Company’s board members as payment of board and committee meeting fees and chairperson retainers.
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 restricted shares 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. On November 6, 2014, the Company granted 1,451,500 restricted shares of common stock to officers, executives, and employees of the Company which vest over a 3-year period with 33% of the restricted shares vesting one year from the date of the grant. The Company also granted 216,348 restricted shares to the directors of the Company on November 6, 2014 which vest one year from the date of the grant. The Company granted 65,000 additional restricted shares of common stock to officers, executives, and employees of the Company throughout the year ended December 31, 2014 for a total 3,275,033 restricted shares of common stock granted. The shares had a fair value at the time of grant of $18.5 million based on the stock price on grant date and estimated forfeiture rate of 3.4%.
During December 2014 the Compensation Committee of the Board of Directors modified the restricted stock grant which occurred during November 2014. The modification was to fully vest the third tranche of the award which originally would have vested on November 6, 2017. Under the modified terms, the stock award vested one-third on December 19, 2014 and the remaining tranches will vest equally on November 6, 2015 and 2016. The Company recognized $2.6 million incremental compensation expense
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attributable to the modification. The method used to value the original award and the modified award were the same as described above with the only adjustments being to the expected forfeiture rate for the third tranche.
A summary of the Company’s non-vested common shares granted under the Stock Incentive Plan as of December 31, 2014, 2013, and 2012 is presented below:
| 2014 | 2013 | 2012 | ||||||||||||||||||
| Weighted-Average Share Price | Weighted-Average Share Price | Weighted-Average Share Price | ||||||||||||||||||
| Non-vested Shares | Shares | Shares | Shares | |||||||||||||||||
| Non-vested at beginning of the year | 27,500 | $ | 7.24 | 65,025 | $ | 6.09 | 155,049 | $ | 4.43 | |||||||||||
| Granted | 3,239,796 | $ | 5.66 | 210,494 | $ | 4.66 | 69,791 | $ | 4.29 | |||||||||||
| Forfeited | (170,000 | ) | $ | 7.26 | — | $ | — | — | $ | — | ||||||||||
| Vested | (780,283 | ) | $ | 4.48 | (248,019 | ) | $ | 4.75 | (159,815 | ) | $ | 4.46 | ||||||||
| Non-vested at end of the year | 2,317,013 | $ | 5.97 | 27,500 | $ | 7.24 | 65,025 | $ | 6.09 | |||||||||||
Total unrecognized compensation cost related to the above non-vested shares amounted to $9.7 million, $0.2 million, and $0.4 million as of December 31, 2014, 2013, and 2012, respectively. The unrecognized compensation cost at December 31, 2014 is expected to be recognized over a weighted-average period of 1.96 years.
Eureka Hunter Holdings, LLC Management Incentive Compensation Plan
On May 12, 2014, the Board of Directors of Eureka Hunter Holdings approved the Eureka Hunter Holdings, LLC Management Incentive Compensation Plan (the “Eureka Hunter Holdings Plan”) to provide long-term incentive compensation to attract and retain officers and employees of Eureka Hunter Holdings and its affiliates and allow such individuals to participate in the economic success of Eureka Hunter Holdings and its affiliates.
The Eureka Hunter Holdings Plan consists of (i) 2,336,905 Class B Common Units representing membership interests in Eureka Hunter Holdings (“Class B Common Units”), and (ii) 2,336,905 Incentive Plan Units issuable pursuant to a management incentive compensation plan, which represent the right to receive a dollar value up to the baseline value of a corresponding Class B Common Unit (“Incentive Plan Units”). The Eureka Hunter Holdings Plan is administered by the board of managers of Eureka Hunter Holdings, and, as administrator of the Eureka Hunter Holdings Plan, the board may from time to time make awards under the Eureka Hunter Holdings Plan to selected officers and employees of Eureka Hunter Holdings or its affiliates (“Award Recipients”).
Upon approval of the plan on May 12, 2014, the board of managers of Eureka Hunter Holdings granted 894,102 Class B Common Units and 894,102 Incentive Plan Units to key employees of Eureka Hunter Holdings and its subsidiaries. During the fourth quarter of 2014, the board of managers granted an additional 413,110 Class B Common Units and 413,110 Incentive Plan Units to key employees of Eureka Hunter Holdings and its subsidiaries. The Class B Common Units and Incentive Plan Units are accounted for in accordance with ASC 718, Compensation - Stock Compensation. In accordance with ASC 718, compensation cost is accrued when the performance condition (i.e. a liquidity event) is probable of being achieved. The Company assessed the probability of a liquidity event up to and including the date of deconsolidation of Eureka Hunter Holdings and concluded that as of December 18, 2014, a liquidity event, as defined, was not probable, and therefore, no compensation cost has been recognized.
NOTE 13 - SHAREHOLDERS' EQUITY
Common Stock
During the years ended December 31, 2014, 2013, and 2012, the Company issued:
| i. | 657,317, 182,994, and 108,397 shares net of shares withheld for taxes, 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. |
| ii. | 2,375,273, 1,466,025, and 1,438,275 shares, respectively, of the Company’s common stock upon the exercise of warrants and options for total proceeds of approximately $9.7 million, $5.4 million, and $2.3 million, respectively. |
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.
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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.
On March 31, 2014, the Company issued 4,300,000 shares of the Company’s common stock in a private placement at a price of $7.00 per share, with net proceeds to the Company of $28.9 million after deducting sales agent commissions and other issuance costs. The Company subsequently filed a Form S-1 Registration Statement with the SEC which was declared effective on July 23, 2014 to register the resale of these shares by the holders thereof to satisfy the Company’s registration obligations under the private placement. A post-effective amendment filed to convert the Form S-1 Registration Statement to a Form S-3 Registration Statement was declared effective by the SEC on September 11, 2014.
On May 9, 2014, the Company issued 21,428,580 shares of the Company’s common stock, together with warrants to purchase up to an aggregate of 2,142,858 shares of common stock at an exercise price of $8.50 per share, in a private placement at a price of $7.00 per share, with net proceeds to the Company of $149.7 million after deducting issuance costs. The Company subsequently filed a Form S-1 Registration Statement with the SEC to register the resale of these shares by the holders thereof to satisfy the Company’s registration obligations under the private placement. A pre-effective amendment filed to convert the Form S-1 Registration Statement to a Form S-3 Registration Statement was declared effective by the SEC on August 22, 2014.
Magnum Hunter Resources Corporation 401(k) Employee Stock Ownership Plan
During the years ended December 31, 2014, 2013, and 2012, the Company issued an aggregate of 249,531; 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 (“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, 2014, except for statutorily required “safe harbor” matching contributions. Shares issued to and held by the Plan are included in our EPS calculation.
During the years ended December 31, 2014, 2013, and 2012, the Company recognized $1.6 million, $1.2 million and $0.9 million, respectively in compensation attributable to its KSOP. As of December 31, 2014 the KSOP held 585,239 shares of the Company’s common stock.
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 Resources, Inc., 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 years ended December 31, 2013 and 2012, 505,835 and 3,188,036, respectively, of the exchangeable shares were exchanged for common shares of the Company. As of December 31, 2014 and 2013, there were no exchangeable shares outstanding.
Common Stock Warrants
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 the 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. The remaining warrants which were not exercised consisted of 97,780 warrants
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with an exercise price of $15.13 which expired on February 13, 2014 and 40,608 warrants with an exercise price of $19.04 which expired on November 17, 2014.
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 became exercisable on August 5, 2014, the date that our registration statement was declared effective by the SEC with respect to the issuance of the common stock underlying the warrants. The warrants are subject to redemption at the option of the Company at $0.001 per warrant upon not less than thirty days’ notice to the holders.
On May 9, 2014, the Company issued 2,142,858 warrants to purchase common stock with an exercise price of $8.50 per share, subject to certain anti-dilution adjustments, in conjunction with the May 2014 private placement sales of common stock. The warrants became exercisable beginning on May 29, 2014, and will expire on April 15, 2016. The warrants are subject to redemption at the option of the Company at $0.001 per warrant upon not less than thirty days’ notice to the holders, only if the Company also redeems the warrants it previously issued pursuant to that certain Warrants Agreement, dated October 15, 2013, by and between the Company and American Stock Transfer & Trust Company, Inc. The warrants were issued in connection with the May 2014 sale of 21,428,580 common shares, and the proceeds for the sale of the common shares and the warrants have been reflected in the Company’s capital accounts as increases to common stock and additional paid in capital.
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, 2014, 2013, and 2012 is presented below:
| 2014 | 2013 | 2012 | |||||||||||||||
| Weighted - | Weighted - | Weighted - | |||||||||||||||
| Average | Average | Average | |||||||||||||||
| Shares | Exercise Price | Shares | Exercise Price | Shares | Exercise Price | ||||||||||||
| Outstanding at beginning of year | 17,169,010 | $ | 8.56 | 13,376,277 | $ | 10.56 | 13,525,832 | $ | 10.48 | ||||||||
| Granted | 2,142,858 | $ | 8.50 | 17,030,622 | $ | 8.50 | — | $ | — | ||||||||
| Exercised, forfeited, or expired | (138,388 | ) | $ | 16.28 | (13,237,889 | ) | $ | 10.50 | (149,555 | ) | $ | 3.32 | |||||
| Outstanding at end of year | 19,173,480 | $ | 8.50 | 17,169,010 | $ | 8.56 | 13,376,277 | $ | 10.56 | ||||||||
| Exercisable at end of year | 19,173,480 | $ | 8.50 | 17,169,010 | $ | 8.56 | 13,376,277 | $ | 10.56 | ||||||||
At December 31, 2014, the warrants had no aggregate intrinsic value; and the weighted average remaining contract life was 1.29 years.
Series D Preferred Stock
Each share of Series D Preferred Stock, par value $0.01 per share, has a liquidation preference of $50.00 per share. 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 its 8.0% Series D 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 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
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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 Preferred Stock and 8.0% Series D Preferred Stock in respect of dividends and distributions upon liquidation.
In November 2012, the Company issued 2,774,850 Depositary Shares 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.
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 December 2012, the Company sold in a public offering an aggregate of 1,000,000 Depositary Shares. 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. 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
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 December 30, 2013, PRC Williston sold substantially all of its assets. On July 24, 2014, the Company executed a settlement and release agreement with the holders of the equity participation rights. As a result of this settlement agreement, the Company now owns 100% of the equity interests in PRC Williston and has all rights and claims to its remaining assets and liabilities, which are not significant. Consequently, there is no longer any non-controlling interest in PRC Williston’s equity reflected in the consolidated financial statements as of December 31, 2014.
On April 2, 2012, Eureka Hunter Holdings, then 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. In October 2014, these Class A Common Units were converted to Series A-1 Units.
In October 2014, all of the Eureka Hunter Holdings Series A Preferred Units and Class A Common Units held by Ridgeline were purchased by MSI and converted into Series A-2 Units (see “Note 14 - Redeemable Preferred Stock”). The Series A-2 Units held by MSI and the Series A-1 Units issued in connection with the TransTex acquisition represented non-controlling interests in Eureka Hunter Holdings in the Company’s consolidated balance sheet. As a result of the deconsolidation of Eureka Hunter Holdings, the Company derecognized the non-controlling interests attributed to Eureka Hunter Holdings as part of the gain on deconsolidation (see “Note 2 - Deconsolidation of Eureka Hunter Holdings”).
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Preferred Dividends Incurred
A summary of dividends incurred by the Company for the years ended December 31, 2014, 2013, and 2012 is presented below:
| Year Ended December 31, | |||||||||||
| 2014 | 2013 | 2012 | |||||||||
| (in thousands) | |||||||||||
| Dividend on Eureka Hunter Holdings Series A Preferred Units | $ | 12,760 | $ | 14,323 | $ | 8,090 | |||||
| Accretion of the carrying value of the Eureka Hunter Holdings Series A Preferred Units | 6,583 | 6,918 | 3,775 | ||||||||
| Dividend on Series C Preferred Stock | 10,248 | 10,248 | 10,248 | ||||||||
| Dividend on Series D Preferred Stock | 17,698 | 17,655 | 11,699 | ||||||||
| Dividend on Series E Preferred Stock | 7,418 | 7,561 | 894 | ||||||||
| Total dividends on Preferred Stock | $ | 54,707 | $ | 56,705 | $ | 34,706 | |||||
Net Income or Loss per Share Data
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, 2014, 2013 and 2012:
| December 31, | ||||||||
| 2014 | 2013 | 2012 | ||||||
| (in thousands of shares) | ||||||||
| Series E Preferred Stock | 10,946 | 10,946 | 10,897 | |||||
| Warrants | 19,173 | 17,169 | 13,376 | |||||
| Restricted shares granted, not yet issued | 2,369 | 28 | — | |||||
| Common stock options | 13,195 | 16,891 | 14,847 | |||||
| Total | 45,683 | 45,034 | 39,120 | |||||
NOTE 14 - REDEEMABLE PREFERRED STOCK
Series C Preferred Stock
Each share of Series C Preferred Stock, par value $0.01 per share, has a liquidation preference of $25.00 per share. 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.
Eureka Hunter Holdings 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. Pursuant to this Unit Purchase Agreement, Ridgeline committed, subject to certain conditions, to purchase up to $200 million of Eureka Hunter Holdings Series A Preferred Units, of which $200 million were purchased through September 16, 2014.
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During the years ended December 31, 2014, 2013, and 2012, Eureka Hunter Holdings issued 610,000, 1,800,000, and 7,590,000 Eureka Hunter Holdings Series A Preferred Units, respectively, to Ridgeline for net proceeds of $12.0 million, $35.3 million, and $148.6 million, respectively, net of transaction costs. Eureka Hunter Holdings paid cumulative distributions quarterly on the Eureka Hunter Holdings Series A Preferred Units at a fixed rate of 8% per annum of the initial liquidation preference. The distribution rate was increased to 10% if any distribution was not paid when due. The board of managers of Eureka Hunter Holdings had the option to 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 had the option to 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 Eureka Hunter Holdings Series A Preferred Units were convertible into Class A Common Units of Eureka Hunter Holdings upon demand by Ridgeline or by Eureka Hunter Holdings upon the consummation of a qualified initial public offering. The conversion rate was 1:1, subject to adjustment from time to time based upon certain anti-dilution and other provisions. Eureka Hunter Holdings was allowed to redeem all outstanding Eureka Hunter Holdings Series A Preferred Units at their liquidation preference, which involved a specified IRR hurdle, any time after March 21, 2017. Holders of the Eureka Hunter Holdings Series A Preferred Units could force the redemption of all outstanding Eureka Hunter Holdings Series A Preferred Units any time after March 21, 2020. The Eureka Hunter Holdings Series A Preferred Units were recorded as temporary equity because a forced redemption by the holders of the preferred units was outside the control of Eureka Hunter Holdings.
During the years ended December 31, 2014, 2013, and 2012, the Company paid cash distributions of $10.2 million, $5.2 million, and $3.4 million, respectively. The Company accrued distributions not yet paid of $3.9 million and $3.0 million during the years ended December 31, 2013 and 2012, respectively, to the holder of the Eureka Hunter Holdings Series A Preferred Units. During such years, distributions in the amount of $1.9 million, $8.2 million, and $1.7 million, respectively, were paid-in-kind to the holder of the Eureka Hunter Holdings Series A Preferred Units, and the Company issued 97,492, 412,157, and 82,892 Eureka Hunter Holdings Series A Preferred Units, respectively, as payment.
The Company evaluated the Eureka Hunter Holdings Series A Preferred Units and determined that they should be considered a “debt host” and not an “equity host”. This evaluation was 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. 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 required bifurcation and separate accounting as embedded derivatives. The fair value of the embedded features were determined at the issuance dates and were bifurcated from the issuance values of the Eureka Hunter Holdings Series A Preferred Units and presented in long term liabilities. The fair value of this embedded feature was $173.2 million and $75.9 million at October 3, 2014 and December 31, 2013, respectively. See “Note 9 - Fair Value of Financial Instruments”. The embedded derivative associated with the Eureka Hunter Holdings Series A Preferred Units was extinguished upon conversion as discussed in “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
On October 3, 2014, the outstanding Eureka Hunter Holdings Series A Preferred Units were purchased from Ridgeline by MSI and converted into Series A-2 Units of Eureka Hunter Holdings.
As a result of the conversion of the Eureka Hunter Holdings Series A Preferred Units into Series A-2 Units, the Company recognized a new preferred interest which was considered a permanent equity interest in Eureka Hunter Holdings. The Series A-2 Units non-controlling interest was derecognized upon deconsolidation and included as part of the gain on deconsolidation. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
Extinguishment of Eureka Hunter Holdings Series A Preferred Units
On October 3, 2014, in connection with the Transaction Agreement and Letter Agreement between the Company and MSI and the effectiveness of the New LLC Agreement, the conversion feature associated with the Eureka Hunter Holdings Series A Preferred Units was modified. Specifically, the conversion feature was modified to allow for settlement through the issuance of Series A-2 Units, a form of preferred equity of Eureka Hunter Holdings.
The Company has accounted for the modification to the conversion feature as an extinguishment of the old preferred units and issuance of new preferred units due to the liquidation preference and other substantive features and veto rights provided to the holders of the Series A-2 Units. At the date of conversion, the Company determined the Series A-2 Units had a fair value of $389 million and recognized a loss on extinguishment of the Eureka Hunter Holdings Preferred Series A Units of $51.7 million for the difference between the fair value of the Series A-2 Units and the carrying amount of the Eureka Hunter Holdings Series A Preferred Units, including the embedded derivative liability and accrued dividends at October 3, 2014. The loss on extinguishment is reflected as an adjustment to the net loss available to common stockholders in accordance with ASC Topic 260, Earnings per Share. See “Note 9 - Fair Value of Financial Instruments” for the method used to determine the fair value of the Series A-2 Units.
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NOTE 15 - INCOME TAXES
The total provision for income taxes applicable to continuing operations consists of the following:
| Year Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| (in thousands) | ||||||||||||
| Deferred income tax benefit | ||||||||||||
| Federal | $ | — | $ | (78,743 | ) | $ | (24,584 | ) | ||||
| State | — | (6,664 | ) | (81 | ) | |||||||
| Total deferred tax benefit | $ | — | $ | (85,407 | ) | $ | (24,665 | ) | ||||
| Total income tax benefit | $ | — | $ | (85,407 | ) | $ | (24,665 | ) | ||||
At December 31, 2014, the Company had net operating loss carry forwards (“NOLs”) available for U.S. federal income tax purposes of approximately $710 million, which expire in varying amounts during the tax years 2018 through 2034. The deferred tax asset recorded for the U.S. NOLs does not include $38.1 million of deductions for excess stock-based compensation (tax effected $14.8 million). The Company will recognize the NOLs tax assets associated with excess stock-based compensation tax deductions only when all other components of the NOLs 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, 2014, 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 $206.8 million against the net deferred tax assets of the Company at December 31, 2014. The Company is uncertain on a more likely than not basis that the NOLs 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, 2014, 2013, and 2012 to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income:
| Year Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| (in thousands) | ||||||||||||
| Income tax benefit at statutory U.S. rate | $ | (48,242 | ) | $ | (111,132 | ) | $ | (53,908 | ) | |||
| State income taxes (net of federal benefit) | (3,616 | ) | (4,331 | ) | (53 | ) | ||||||
| Tax effect of permanent differences | (498 | ) | 750 | (555 | ) | |||||||
| Provision to return adjustment | (11,736 | ) | — | — | ||||||||
| Foreign statutory tax rate differences | 297 | — | — | |||||||||
| Tax effect of loss attributable to non-controlled interest | 1,279 | 346 | 797 | |||||||||
| Tax benefit recognized as tax expense in discontinued operations | — | (28,989 | ) | — | ||||||||
| Change in valuation allowance | 63,341 | 58,341 | 29,047 | |||||||||
| Other | (825 | ) | (392 | ) | 7 | |||||||
| Total continuing operations | — | (85,407 | ) | (24,665 | ) | |||||||
| Discontinued operations | — | 11,773 | 3,071 | |||||||||
| Total tax benefit | $ | — | $ | (73,634 | ) | $ | (21,594 | ) | ||||
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Income (loss) before income taxes was as follows:
| Year Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| (in thousands) | ||||||||||||
| Domestic | $ | (134,853 | ) | $ | (317,520 | ) | $ | (154,022 | ) | |||
| Foreign | (2,980 | ) | — | — | ||||||||
| Loss from continuing operations | (137,833 | ) | (317,520 | ) | (154,022 | ) | ||||||
| Gain (loss) from discontinued operations | 4,561 | (62,655 | ) | (8,125 | ) | |||||||
| Gain (loss) on disposal of discontinued operations | (13,855 | ) | 83,378 | 3,830 | ||||||||
| Loss before income tax | $ | (147,127 | ) | $ | (296,797 | ) | $ | (158,317 | ) | |||
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:
| Year Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| (in thousands) | ||||||||||||
| Deferred tax assets: | ||||||||||||
| Net operating loss carry forwards | $ | 263,452 | $ | 155,507 | $ | 193,310 | ||||||
| Property and equipment | 63,823 | — | — | |||||||||
| Capital loss carry forward | 38,401 | — | — | |||||||||
| Share-based compensation | 15,035 | 10,156 | 7,950 | |||||||||
| Depletion carry forwards | 1,047 | 1,047 | 997 | |||||||||
| Tax credits | 53 | 53 | 53 | |||||||||
| US investment in Canada | — | 74,148 | — | |||||||||
| Other | 1,562 | 561 | 532 | |||||||||
| Deferred tax liabilities: | ||||||||||||
| Property and equipment | — | (90,950 | ) | (206,650 | ) | |||||||
| Investment in Eureka Hunter Holdings | (176,606 | ) | — | — | ||||||||
| Valuation allowance | ||||||||||||
| Tax credits | (53 | ) | (53 | ) | (53 | ) | ||||||
| Depletion carry forwards | (1,047 | ) | (1,047 | ) | (997 | ) | ||||||
| Capital loss carry forward | (38,401 | ) | — | — | ||||||||
| Net operating losses | (167,266 | ) | (75,274 | ) | (69,400 | ) | ||||||
| US investment in Canada | — | (74,148 | ) | — | ||||||||
| Net deferred tax asset (liability) | $ | — | $ | — | $ | (74,258 | ) | |||||
The increase in valuation allowance above of $56.2 million includes a $7.1 million decrease related to discontinued operations.
As of December 31, 2014, 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 twelve 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, 2014, the Company has accrued no amounts for potential payment of interest and penalties.
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Following is a reconciliation of the total amounts of unrecognized tax benefits during the years ended December 31, 2014, 2013 and 2012:
| Year Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| (in thousands) | ||||||||||||
| Unrecognized tax benefits at January 1 | $ | 3,879 | $ | 3,879 | $ | — | ||||||
| Change in unrecognized tax benefits taken during a prior period | — | — | — | |||||||||
| Change in unrecognized tax benefits taken during the current period (netted against the US net operating loss) | — | — | 3,879 | |||||||||
| Decreases in unrecognized tax benefits from settlements with taxing authorities | — | — | — | |||||||||
| Reductions to unrecognized tax benefits from lapse of statutes of limitations | — | — | — | |||||||||
| Unrecognized tax benefits at December 31 | $ | 3,879 | $ | 3,879 | $ | 3,879 | ||||||
NOTE 16 - 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 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, 2014, 2013 and 2012. 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, NGLs and gas revenues from continuing operations represented by its major purchasers during the periods presented:
| Year Ended December 31, | ||||||||
| 2014 | 2013 | 2012 | ||||||
| Samson Resources Company | 24 | % | 31 | % | 17 | % | ||
| Teneska Marketing Ventures | 17 | % | 10 | % | 14 | % | ||
| Markwest Liberty Midstream | 15 | % | 6 | % | — | |||
| Baytex Energy USA LTD | 7 | % | 11 | % | 15 | % | ||
| Continuum Midstream, LLC | 5 | % | 6 | % | 13 | % | ||
| South Jersey | 2 | % | 5 | % | 14 | % | ||
| Plains Marketing, LP | — | 4 | % | 11 | % | |||
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NOTE 17 - RELATED PARTY TRANSACTIONS
The following table sets forth the related party balances as of December 31, 2014 and 2013:
| As of December 31, | |||||||
| 2014 | 2013 | ||||||
| (in thousands) | |||||||
GreenHunter (1) | |||||||
| Accounts receivable (payable) - net | $ | (228 | ) | $ | 23 | ||
Derivative assets (2) | $ | 75 | $ | 79 | |||
Investments (2) | $ | 1,311 | $ | 2,262 | |||
Notes receivable (2) | $ | 1,224 | $ | 1,768 | |||
| Prepaid expenses | $ | 1,000 | $ | 9 | |||
Eureka Hunter Holdings (3) | |||||||
| Accounts receivable (payable) - net | $ | 122 | $ | — | |||
| Equity method investment | $ | 347,191 | $ | — | |||
| Pilatus Hunter | |||||||
| Accounts receivable (payable) - net | $ | 12 | $ | — | |||
The following table sets forth the related party transaction activities for the years ended December 31, 2014, 2013 and 2012:
| Years Ended | |||||||||||||
| December 31, | |||||||||||||
| 2014 | 2013 | 2012 | |||||||||||
| (in thousands) | |||||||||||||
| GreenHunter | |||||||||||||
Salt water disposal (1) | $ | 4,682 | $ | 3,033 | $ | 2,400 | |||||||
Equipment rental (1) | 291 | 282 | 1,000 | ||||||||||
Gas gathering-trucking (1) | 652 | — | — | ||||||||||
MAG tank panels (1) | 800 | — | — | ||||||||||
| Office space rental | 44 | 13 | — | ||||||||||
Interest income from note receivable (2) | 154 | 205 | 191 | ||||||||||
Dividends earned from Series C shares (2) | 220 | 220 | — | ||||||||||
Unrealized loss on investments (2) | 951 | 730 | 1,333 | ||||||||||
| Pilatus Hunter, LLC | |||||||||||||
Airplane rental expenses (4) | 281 | 166 | 174 | ||||||||||
| Executive of the Company | |||||||||||||
Corporate apartment rental expense (5) | — | — | 23 | ||||||||||
Eureka Hunter (3) | |||||||||||||
| Transportation costs | 353 | — | — | ||||||||||
_________________________________
(1) | GreenHunter is an entity of which Gary C. Evans, the Company's Chairman and CEO, is the Chairman, a major shareholder and interim CEO. Eagle Ford Hunter received, and Triad Hunter and 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. |
(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. See “Note 9 - Fair Value of Financial Instruments”. The Company has recorded interest |
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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) | Following a sequence of transactions up to and including, December 18, 2014, the Company no longer held a controlling financial interest in Eureka Hunter Holdings. The Company deconsolidated Eureka Hunter Holdings and accounts for its retained interest as of December 31, 2014 under the equity method of accounting. See “Note 2 - Deconsolidation of Eureka Hunter Holdings” and “Note 10 - Investments and Derivatives”. |
(4) | 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. |
(5) | During the year ended December 31, 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 3 - Acquisitions, Divestitures, and Discontinued Operations”. On December 22, 2014, Triad Hunter entered into an Amendment to Produced Water Hauling and Disposal Agreement with GreenHunter Water to secure long-term water disposal at reduced rates through December 31, 2019. To ensure disposal capacity, in connection with the amendment on December 29, 2014 Triad Hunter made a prepayment of $1.0 million towards services to be provided under the Produced Water Hauling and Disposal Agreement. GreenHunter Water will provide a 50% credit for all services performed under the agreement until the prepayment amount is utilized in full, which is anticipated to occur during the year ending December 31, 2015.
As of December 31, 2013, Mr. Evans, the Company's Chairman and Chief Executive Officer, held 27,641 Class A Common Units of Eureka Hunter Holdings. On October 3, 2014, in connection with the New LLC Agreement, these Class A Common Units were converted into Series A-1 Units.
Triad Hunter and Eureka Hunter Pipeline are parties to an Amended and Restated Gas Gathering Services Agreement, which was executed on March 21, 2012, and amended on October 3, 2014 in contemplation of the New LLC Agreement. Under the terms of the gathering agreement, Triad Hunter reserved throughput capacity in the gas gathering pipeline system of Eureka Hunter Holdings for which Triad Hunter has committed to minimum reservation fees of approximately $0.75 per MMBtu. See “Note 18 - Commitments and Contingencies”.
In addition, the Company and Eureka Hunter Holdings entered into a Services Agreement on March 20, 2012, and amended on September 15, 2014, under which the Company agreed to provide administrative services to Eureka Hunter Holdings related to its operations. The terms of the Services Agreement provide that the Company will receive an administrative fee of $500,000 per annum and a personnel services fee equal to the Company’s employee cost plus 1.5% subject to mutually agreed upon increases from time to time. Under the terms of the New LLC Agreement, on or before March 31, 2015, unless extended, certain specified employees of the Company that perform service for Eureka Hunter Holdings and its subsidiaries and for whom, the Company previously billed a personnel services fee, will become employees of Eureka Hunter Holdings or a subsidiary of Eureka Hunter Holdings. Upon the deconsolidation of Eureka Hunter Holdings on December 18, 2014, Eureka Hunter Holdings and its subsidiaries became related parties of the Company.
On July 18, 2014, the Company entered into a consulting agreement with Kirk J. Trosclair, a former executive of Alpha Hunter Drilling, a wholly-owned subsidiary of the Company. Mr. Trosclair ceased employment with the Company on July 18, 2014 and is currently the Chief Operating Officer of GreenHunter. The agreement has a term of 12 months and provides that Mr. Trosclair will receive monthly compensation of $10,000, and Mr. Trosclair is eligible to continue vesting in previously granted stock options and unvested restricted stock awards, subject to continued service under the consulting agreement. In connection with this agreement, for the year ended December 31, 2014, the Company paid Mr. Trosclair $71,000, which includes reimbursement of expenses incurred on behalf of the Company.
NOTE 18 - COMMITMENTS AND CONTINGENCIES
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 were filed in
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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. The cases filed in the Southern District of New York were consolidated and have since been dismissed. The plaintiffs in the Securities Cases had 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 asserted 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 demanded 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. In January 2014, the Company and the individual defendants filed a motion to dismiss the Securities Cases. On June 23, 2014, the United States District Court for the Southern District of New York granted the Company’s and the individual defendants' motion to dismiss the Securities Cases and, accordingly, the Securities Cases have now been dismissed. The plaintiffs have appealed the decision to the U.S. Court of Appeals for the Second Circuit. The Company intends to continue vigorously defending 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. 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. 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. 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, the Southern District of Texas allowed Joseph Vitellone to substitute for Mr. Bassett as plaintiff in that action. On March 19, 2014 Richard Harveth filed another stockholder derivative suit in the 125th District Court of Harris County, Texas. 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 20, 2013, the United States District Court for the Southern District of Texas granted the Company’s motion to dismiss the stockholder derivative case maintained by Joseph Vitellone and entered a final judgment of dismissal. The court held that Mr. Vitellone failed to plead particularized facts demonstrating that pre-suit demand on the Company’s board was excused. In addition, on December 13, 2013, the 151st Judicial District Court of Harris County, Texas dismissed the lawsuit filed by Steven Handshu for want of prosecution after the plaintiff failed to serve any defendant in that matter. On January 21, 2014, the Hanft complaint was dismissed with prejudice after the plaintiff in that action filed a voluntary motion for dismissal. On February 18, 2014, the United States District Judge for the District of Delaware granted the Company’s supplemental motion to dismiss the Derivative Case filed by Mark Respler. All of the Derivative Cases have now been dismissed, except the Derivative Case filed by Richard Harveth, for which the Company is presently seeking dismissal. It is possible 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 (“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, which has now been dismissed. It is possible that additional similar actions may be filed and that similar stockholder demands could be made.
In April 2013, the Company also received a 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 2013 letter. In 2014, the SEC issued additional subpoenas for documents and testimony and has taken testimony from certain individuals. The Company intends to cooperate with the subpoenas.
Any potential liability, if any, from these claims cannot currently be estimated.
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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 also 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 a case styled 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. In October 2014, in a case styled Exterran Energy Solutions, LP v. Eureka Hunter Pipeline, LLC and Magnum Hunter Resources Corporation, Civil Action No. 2014-63353, in the District Court of Harris County, Texas, Exterran Energy Solutions, LP, one of the co-defendants in the Phipps lawsuit, filed suit against the Company and Eureka Hunter Pipeline seeking a declaratory judgment that Eureka Hunter Pipeline is obligated to indemnify Exterran with respect to the Phipps lawsuit. In April 2014, the estate of the other deceased third-party contractor employee sued the Company, Eureka Hunter Pipeline and certain other parties in a case styled Antoinette M. Miller v. Magnum Hunter Resources Corporation et al, Civil Action No. 14-C-111, in the Circuit Court of Ohio County, West Virginia. The plaintiffs allege 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 employees. The plaintiffs have demanded judgment for an unspecified amount of compensatory, general and punitive damages. Various cross-claims have also been asserted. In May 2014, the injured third-party contractor employee sued Magnum Hunter Resources Corporation and certain other parties in a case styled Jonathan Whisenhunt v. Magnum Hunter Resources Corporation et al, Civil Action No. 14-C-135, in the Circuit Court of Ohio County, West Virginia. The claim filed by the injured third-party contractor employee, Jonathan Whisenhunt, has been resolved and dismissal of this case is anticipated in the near term. A portion of the settlement was paid by an insurer of Eureka Hunter Pipeline, and the remainder paid by the co-defendants or their insurers. The cross-claims among the defendants in the Whisenhunt litigation have not been resolved. 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, the Company believes that its insurance coverage will be sufficient to cover any losses or liabilities it may incur as a result of this incident.
PRC Williston Matter
On December 16, 2013, Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a D.B. Zwirn Special Opportunities Fund, L.P. (together, the “Plaintiffs”) filed suit against PRC Williston in the Court of Chancery of the State of Delaware. PRC Williston and the Plaintiffs entered into Participation Agreements in February 2007 in connection with the Plaintiffs extending credit to PRC Williston pursuant to a credit agreement entitling the Plaintiffs 12.5% collective interest in any distributions in respect of the equity interests of the members of PRC Williston. Plaintiffs claimed that they were entitled to compensation for 12.5% of alleged past distributions on equity from PRC Williston to Magnum Hunter and 12.5% of any transfers of funds to Magnum Hunter from the proceeds of the December 30, 2013 sale of PRC Williston’s assets. On December 23, 2013, the Chancery Court entered a temporary restraining order prohibiting PRC Williston from transferring, assigning, removing, distributing or otherwise displacing to Magnum Hunter, Magnum Hunter’s creditors, or any other person or entity, $5.0 million of the proceeds received by PRC Williston in connection with the sale of its assets. On March 18, 2014, the Court granted Plaintiff’s motion for a preliminary injunction, extending the relief granted by the temporary restraining order until after a full trial on the merits.
On July 24, 2014, the Company, PRC Williston, and the Plaintiffs executed a Settlement and Release Agreement (“the Settlement Agreement”). Per the terms of the Settlement Agreement, PRC Williston paid approximately $2.9 million in cash to Drawbridge Special Opportunities Fund LP. As a result of the Settlement Agreement, the Company, PRC Williston, and the Plaintiffs agreed to release each other from all claims, past, present or future, related to the dispute. In addition, with the execution of the Settlement Agreement, the parties agreed to terminate, in all respects, the Participation Agreements and that none of the parties would have any further rights or obligations thereunder. With the cash settlement payment and the termination of the Participation Agreements, the Company now has rights and claims to 100% of the equity interests in PRC Williston and its remaining assets and liabilities. Consequently, there is no longer any non-controlling interest in PRC Williston’s equity reflected in our consolidated financial statements.
General
We are also a defendant in several other lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on our consolidated financial condition or results of operations.
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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 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, 2014 and 2013 was $640,695.
Gas Gathering and Processing Agreements
On December 14, 2011, the Company entered into a 120 -month gas transportation contract with Equitrans, L.P. The contract became effective on August 1, 2012, and expires on July 31, 2022. The Company's remaining obligation under the contract was approximately $19.4 million as of December 31, 2014. With the Virco Acquisition on November 2, 2012, Triad Hunter assumed a 120-month gas transportation contract with Dominion Field Services, Inc., which expires on December 31, 2022. The Company's remaining obligation under the contract was $3.1 million as of December 31, 2014.
Eureka Hunter Pipeline Gas Gathering Agreement
On March 21, 2012, Triad Hunter entered into the Amended and Restated Gas Gathering Services Agreement with Eureka Hunter Pipeline. Under the terms of this agreement, Triad Hunter committed to the payment of monthly reservation fees for certain maximum daily quantities of gas delivered each day for transportation under various individual transaction confirmations. In previous periods, Eureka Hunter Pipeline and Triad Hunter were both wholly-owned subsidiaries of the Company. Upon the deconsolidation of Eureka Hunter Holdings on December 18, 2014, Eureka Hunter Pipeline became a related party (see “Note 2 - Deconsolidation of Eureka Hunter Holdings” and “Note 17 - Related Party Transactions”). As of December 31, 2014, Triad Hunter and Eureka Hunter Pipeline were parties to six individual transaction confirmations with terms ranging from eight to fourteen years. Triad Hunter’s maximum daily quantity committed was 135,000 MMBtu per day at an aggregate reservation fee of $0.75 per MMBtu. Triad Hunter’s remaining obligation under the contract was $98.0 million as of December 31, 2014.
TGT Transportation Agreement
On August 18, 2014, Triad Hunter executed a Precedent Agreement for Texas Gas Transmission LLC’s (“TGT”) Northern Supply Access Line (“TGT Transportation Services Agreement”). Through executing the TGT Transportation Services Agreement, Triad Hunter committed to purchase 100,000 MMBtu per day of firm transportation capacity on TGT’s Northern Supply Access Line. The term of the TGT Transportation Services Agreement will commence with the date the pipeline project is available for service, currently anticipated to be in early 2017, and will end 15 years thereafter. The execution of a Firm Transportation Agreement is contingent upon TGT receiving appropriate approvals from the Federal Energy Regulatory Commission (“FERC”) for their pipeline project. Upon executing a Firm Transportation Agreement, the Company will have minimum annual contractual obligations for reservation charges of approximately $12.8 million over the 15 year term of the agreement.
On October 21, 2014, Triad Hunter executed a Credit Support Agreement with TGT, related to the TGT Transportation Services Agreement executed on August 18, 2014, (“Precedent Agreement Date”). In accordance with the provisions of the Credit Support Agreement, Triad Hunter will provide TGT with letters of credit on the dates and in the amounts that follow (“Credit Support Amount”):
| i | during the period beginning on the date that is fourteen months after the Precedent Agreement Date and ending on the day immediately prior to the date that is twenty-one months after the Precedent Agreement Date, an amount equal to $13.0 million; |
| ii | during the period beginning on the date that is twenty-one months after the Precedent Agreement Date and ending on the day immediately prior to the date that is twenty-eight months after the Precedent Agreement Date, an amount equal to $36.0 million; and |
| iii | during the period beginning on the date that is twenty-eight months after the Precedent Agreement Date and ending on the date the Credit Support Agreement terminates, an amount equal to $65.0 million. |
Provided however, that the Credit Support Amount shall be subject to reduction (on a cumulative basis) at specified dates depending on Triad Hunter's Interest Coverage Ratio or if Triad Hunter meets the creditworthiness standards established in the Texas Gas FERC Gas Tariff as in effect on such date that Triad Hunter meets the said standard. Due to recent changes in the transportation market in the southern Appalachian Basin and the additional announcements of new pipeline capacity under construction in this region, the Company is currently reviewing the possible cancellation of this agreement.
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REX Transportation Agreement
On October 8, 2014, Triad Hunter executed a Precedent Agreement with Rockies Express Pipeline LLC (“REX”), (“REX Transportation Services Agreement”) for the delivery by Triad Hunter and the transportation by REX of natural gas produced by Triad Hunter. In executing the REX Transportation Services Agreement, Triad Hunter committed to purchase 100,000 MMBtu per day of firm transportation from REX. The term of the REX Transportation Services Agreement will commence with the date the pipeline project is available for service, currently anticipated to be between mid-2016 and mid-2017, and will end 15 years thereafter. The execution of a Firm Transportation Agreement is contingent upon REX receiving appropriate approvals from FERC for their pipeline project. Upon executing a Firm Transportation Agreement, the Company will have minimum annual contractual obligations for reservation charges of approximately $16.4 million over the 15 year term of the agreement.
In addition, the Company was required to provide credit support to REX, in the form of a letter of credit, in the initial amount of twenty-seven months of Triad Hunter’s reservation charges, within 45 days of executing the REX Transportation Services Agreement. The Company posted a letter of credit for $36.9 million for the benefit of REX on November 25, 2014, using availability under the Company’s Senior Revolving Credit Facility. The borrowing capacity under the Senior Revolving Credit Facility was reduced by $36.9 million. No amounts have been drawn against the letter of credit as of December 31, 2014.
Future minimum gathering, processing, and transportation commitments related to the REX Transportation Services Agreement and the TGT Transportation Services Agreement are not included in the table below, as they are not contractual obligations until the execution of Firm Transportation Agreements, subject to the related projects being approved by FERC. Future minimum gathering, processing, and transportation commitments at December 31, 2014, are as follows (in thousands):
| 2015 | $ | 11,567 | |
| 2016 | $ | 11,591 | |
| 2017 | $ | 11,567 | |
| 2018 | $ | 11,567 | |
| 2019 | $ | 11,567 | |
| Thereafter | $ | 62,655 | |
Agreement to Purchase Utica Shale Acreage
On August 12, 2013, Triad Hunter entered into an asset purchase agreement with MNW. Pursuant to the purchase agreement, Triad Hunter agreed to acquire from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in such counties within the state of Ohio, over a period of time, in staggered closings, subject to certain conditions. During the year ended December 31, 2013, Triad Hunter purchased a total of 5,922 net leasehold acres from MNW for $24.6 million in multiple closings.
On December 30, 2013, a lawsuit was filed against the Company, Triad Hunter, MNW and others by Dux Petroleum, LLC (“Dux”) asserting certain claims relating to the acreage covered by the asset purchase agreement with MNW. As a result of the litigation, no purchases were made during the first quarter of 2014. On May 28, 2014, the litigation was settled by all parties. As part of the settlement, the Company and Triad Hunter agreed to collectively pay Dux the aggregate amount of $500,000. Subsequent to the settlement of the lawsuit, Triad Hunter resumed closings of lease acquisitions from MNW.
On October 28, 2014, Triad Hunter and MNW entered into the First Amendment to the Asset Purchase Agreement and Partial Release of Earn-Out Agreement (“Amendment”). In connection with the asset purchase agreement with MNW dated August 12, 2013, Triad Hunter and MNW also entered into an earn-out agreement dated August 12, 2013, which provided for MNW to perform certain consulting services for Triad Hunter and to be paid for such services through the release by Triad Hunter of escrow funds being withheld from the purchase price at each closing under the asset purchase agreement. The Amendment terminates MNW's obligation to perform further consulting services under the earn-out agreement, provides for the disbursement of funds to MNW that have been held in escrow from closings to date, and amends the asset purchase agreement to end further withholdings of escrow funds from the purchase price at future closings.
During the year ended December 31, 2014, Triad Hunter purchased a total of 16,456 net leasehold acres from MNW for $67.3 million in multiple closings, and also released $0.4 million in escrowed funds, for a total disbursement to MNW of approximately $67.7 million. As of December 31, 2014, under the asset purchase agreement, Triad Hunter has now acquired a total of approximately 22,379 net leasehold acres from MNW, or approximately 70% of the approximately 32,000 total net leasehold acres originally anticipated under the asset purchase agreement.
F-63
Settlement Agreement with Continuum Energy Services
On January 10, 2014, the Company and certain of its subsidiaries entered into an Omnibus Settlement Agreement and Release (“Settlement Agreement”) dated January 9, 2014 with Continuum Energy Services, L.L.C. (formerly known as Seminole Energy Services, L.L.C.) and certain of its affiliates (collectively, “Continuum”). In connection with and pursuant to the terms of the Settlement Agreement, the Company and Continuum 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 to terminate, amend and enter into certain new, related agreements effective immediately prior to year-end on December 31, 2013 (“New Agreements”).
By entering into the New Agreements, the Company and Continuum restructured their existing agreements. The Company obtained a reduction in gas gathering rates it pays for natural gas owned or controlled by the Company that is gathered on the Stone Mountain Gathering System located in the state of Kentucky. The Company and Continuum 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. The parties also agreed to reduce and extend the Company's contractual horizontal well drilling obligations owed to Continuum. The Company's future drilling obligation to Continuum, which required the Company to drill and complete four wells in southern Appalachia, expired on June 30, 2014, and, pursuant to the Settlement Agreement, the Company paid Continuum $450,000 as a result of the Company’s decision not to drill two of the required four wells.
The Company and Continuum also agreed to modify the natural gas processing rates the Company pays for processing at the Rogersville Plant, the Company's allocation of NGLs recovered from gas processed and the costs of blend stock necessary to blend with the NGLs produced from the Rogersville Plant, and certain deductions to the NGLs purchase price the Company will pay Continuum for the Company's NGLs produced from the Rogersville Plant. Additionally, Continuum sold to the Company Continuum'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 Continuum and the Company.
Drilling Rig Purchase
During June 2014, the Company, through its 100% owned subsidiary, Alpha Hunter Drilling, LLC, executed an agreement to purchase a new drilling rig for a total purchase price of approximately $6.5 million, including a $1.3 million deposit due on July 1, 2014 with the remainder due upon delivery, which was expected to be on or about January 15, 2015.
In February 2015, the Company was notified that the rig was complete and available for delivery. However, the Company has not taken delivery of the rig and has notified the seller that until performance issues related to a separate rig of the same model purchased by the Company from the seller are resolved, that it does not intend to take delivery of the rig. See “Note 22 - Subsequent Events”.
PVA Arbitration Decision
On July 25, 2014, the Company received the final determination from the arbitrator in the disagreement related to the final working capital adjustments pertaining to the sale of Eagle Ford Hunter to Penn Virginia in 2013. As a result, the Company recorded a total liability of $33.7 million, plus accrued interest of $1.3 million, based upon the final determination made by the arbitrator. This amount was settled in cash on July 31, 2014. The arbitrator declined to rule, on the basis of lack of authority, on two claims made by Penn Virginia related to working capital adjustments governed by a transition services agreement in the amount of $7.8 million. Any potential liability from these claims cannot currently be estimated. Management has determined these additional claims are meritless.
Operating Leases
As of December 31, 2014, office space rentals with terms of 12 months or greater include office spaces in Houston, Texas, at a monthly cost of $33,800, and office spaces in Grapevine, Texas, with monthly payments of approximately $4,800.
F-64
Future minimum lease commitments under non-cancelable operating leases at December 31, 2014, are as follows (in thousands):
| 2015 | $ | 502 | |
| 2016 | $ | 239 | |
| 2017 | $ | 121 | |
| 2018 | $ | 124 | |
| 2019 | $ | 53 | |
| Thereafter | $ | — | |
Services Agreement
On March 21, 2012, Triad Hunter entered into the Amended and Restated Gas Gathering Services Agreement with Eureka Hunter Pipeline. Further, on March 20, 2012, and amended on March 21, 2012, the Company and Eureka Hunter Holdings entered into a Services Agreement to provide administrative services. The terms of the Services Agreement provide that the Company will receive an Administrative Services fee of $500,000 per annum and a Personnel Services fee equal to the Company’s employee cost plus 1.5% subject to mutually agreed upon increases from time to time. Upon the deconsolidation of Eureka Hunter Holdings on December 18, 2014, Eureka Hunter Pipeline became a related party. See “Note 17 - Related Party Transactions”.
Environmental 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. As of December 31, 2014, the Company is unaware of any material capital expenditures which may be required for environmental control.
On December 13, 2014, the Company lost control of the Stalder 3UH well located in Monroe County, Ohio. On December 23, 2014, the well was temporarily capped and the well head assembly had been successfully replaced. There is currently no evidence of environmental damage to the immediate area as a result of the blowout, and no personnel were injured in connection with the well control operations on the Stalder Pad. The Company believes that there has been no damage to the overall structure or integrity of the Stalder 3UH well and that the three other Utica Shale wells and the one Marcellus Shale well also located on the Company’s Stalder Pad have been unaffected and are currently producing. The Company further believes that its control of well insurance will be adequate to cover all losses incurred by it in connection with the blowout of the Stalder 3UH well (subject to the normal retention amount of the insurance policy).
NOTE 19 - SUPPLEMENTAL CASH FLOW INFORMATION
The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing transactions:
| Year Ended December 31, | |||||||||||
| 2014 | 2013 | 2012 | |||||||||
| (in thousands) | |||||||||||
| Cash paid for interest | $ | 73,192 | $ | 67,736 | $ | 35,669 | |||||
| Cash paid for taxes | $ | — | $ | 1,200 | $ | — | |||||
| Non-cash transactions | |||||||||||
| Change in accrued capital expenditures - increase (decrease) | $ | 127,068 | $ | (65,634 | ) | $ | 34,621 | ||||
| Eureka Hunter Holdings, LLC Series A convertible preferred unit dividends paid in kind | $ | 1,950 | $ | 8,243 | $ | 1,658 | |||||
| Non-cash additions to asset retirement obligation | $ | 3,426 | $ | 2,132 | $ | 8,492 | |||||
| Common stock issued for 401k matching contributions | $ | 1,593 | $ | 1,192 | $ | 874 | |||||
| Preferred stock issued for acquisitions | $ | — | $ | — | $ | 64,968 | |||||
| Eureka Hunter Holdings, LLC Class A common units issued for an acquisition | $ | — | $ | — | $ | 12,453 | |||||
| Non-cash consideration received from sale of assets | $ | 9,447 | $ | 42,300 | $ | 7,120 | |||||
| Loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units | $ | (51,692 | ) | $ | — | $ | — | ||||
| Common stock issued for acquisitions | $ | — | $ | — | $ | 1,902 | |||||
F-65
The Company issued dividends on common stock in the form of 17,030,622 warrants with fair value of $21.6 million during the year ended December 31, 2013.
NOTE 20 - 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, were classified as assets held for sale and discontinued operations. 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 NGLs in the U.S. for transportation to market. The Oilfield Services segment provides drilling services to oil and natural gas exploration and production companies. The customers of the Company’s Midstream and Oilfield Services segments are the Company and its subsidiaries and also 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, 2014, 2013, and 2012.
| For the Year Ended December 31, 2014 | |||||||||||||||||||||||||||
| U.S. Upstream | Canadian Upstream | Midstream and Marketing (1) | Oil Field Services | Corporate Unallocated(2) | Intersegment Eliminations | Total | |||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||
| Total revenue | $ | 270,615 | $ | — | $ | 109,658 | $ | 31,392 | $ | — | $ | (20,196 | ) | $ | 391,469 | ||||||||||||
| Depreciation, depletion, and accretion | 127,607 | — | 15,737 | 3,524 | — | — | 146,868 | ||||||||||||||||||||
| Gain on sale of assets | (2,075 | ) | — | (12 | ) | (369 | ) | — | — | (2,456 | ) | ||||||||||||||||
| Other operating expenses | 556,085 | — | 93,138 | 26,642 | 81,746 | (20,196 | ) | 737,415 | |||||||||||||||||||
| Other income (expense) | 1,340 | — | (99,221 | ) | (813 | ) | 454,921 | (3,702 | ) | 352,525 | |||||||||||||||||
| Income (loss) from continuing operations before income tax | (409,662 | ) | — | (98,426 | ) | 782 | 373,175 | (3,702 | ) | (137,833 | ) | ||||||||||||||||
| Income (loss) from discontinued operations, net of tax | (7,155 | ) | 10,636 | — | — | (12,775 | ) | — | (9,294 | ) | |||||||||||||||||
| Net income (loss) | $ | (416,817 | ) | $ | 10,636 | $ | (98,426 | ) | $ | 782 | $ | 360,400 | $ | (3,702 | ) | $ | (147,127 | ) | |||||||||
| Total assets | $ | 1,162,732 | $ | — | $ | 454 | $ | 46,995 | $ | 462,025 | $ | (2,377 | ) | $ | 1,669,829 | ||||||||||||
| Total capital expenditures | $ | 470,538 | $ | 305 | $ | 221,455 | $ | 8,079 | $ | 231 | $ | — | $ | 700,608 | |||||||||||||
| For the Year Ended December 31, 2013 | |||||||||||||||||||||||||||
| U.S. Upstream | Canadian Upstream | Midstream and Marketing (1) | Oil Field Services | Corporate Unallocated | Intersegment Eliminations | Total | |||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||
| Total revenue | $ | 225,498 | $ | — | $ | 69,306 | $ | 21,527 | $ | — | $ | (11,793 | ) | $ | 304,538 | ||||||||||||
| Depreciation, depletion, and accretion | 92,713 | — | 12,318 | 2,354 | — | — | 107,385 | ||||||||||||||||||||
| Loss on sale of assets | 44,629 | — | 8 | 4 | — | — | 44,641 | ||||||||||||||||||||
| Other operating expenses | 267,935 | — | 60,497 | 19,252 | 49,241 | (9,620 | ) | 387,305 | |||||||||||||||||||
| Other income (expense) | (656 | ) | — | (22,358 | ) | (507 | ) | (61,446 | ) | 2,240 | (82,727 | ) | |||||||||||||||
| Income (loss) from continuing operations before income tax | (180,435 | ) | — | (25,875 | ) | (590 | ) | (110,687 | ) | 67 | (317,520 | ) | |||||||||||||||
| Income tax benefit | 56,418 | — | — | — | 28,989 | — | 85,407 | ||||||||||||||||||||
| Total income (loss) from discontinued operations, net of tax | 159,225 | (150,207 | ) | — | — | — | (69 | ) | 8,949 | ||||||||||||||||||
| Net income (loss) | $ | 35,208 | $ | (150,207 | ) | $ | (25,875 | ) | $ | (590 | ) | $ | (81,698 | ) | $ | (2 | ) | $ | (223,164 | ) | |||||||
| Total assets | $ | 1,373,041 | $ | 68,367 | $ | 296,739 | $ | 44,193 | $ | 77,684 | $ | (3,373 | ) | $ | 1,856,651 | ||||||||||||
Total capital expenditures (3) | $ | 444,385 | $ | 15,352 | $ | 87,498 | $ | 22,440 | $ | 1,037 | $ | — | $ | 570,712 | |||||||||||||
F-66
| For the Year Ended December 31, 2012 | |||||||||||||||||||||||||||
| U.S. Upstream | Canadian Upstream | Midstream and Marketing (1) | Oil Field Services | Corporate Unallocated | Intersegment Eliminations | Total | |||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||
| Total revenue | $ | 134,339 | $ | — | $ | 15,692 | $ | 13,552 | $ | — | $ | (3,646 | ) | $ | 159,937 | ||||||||||||
| Depreciation, depletion, and accretion | 65,040 | — | 5,963 | 967 | — | 468 | 72,438 | ||||||||||||||||||||
| Loss (gain) on sale of assets | 246 | — | �� | (250 | ) | 600 | — | — | 596 | ||||||||||||||||||
| Other operating expenses | 167,423 | — | 11,706 | 10,838 | 27,137 | (3,541 | ) | 213,563 | |||||||||||||||||||
| Other income (expense) | (10,210 | ) | — | 7,388 | (482 | ) | (24,121 | ) | 63 | (27,362 | ) | ||||||||||||||||
| Income (loss) from continuing operations before income tax | (108,580 | ) | — | 5,661 | 665 | (51,258 | ) | (510 | ) | (154,022 | ) | ||||||||||||||||
| Income tax benefit | 24,665 | — | — | — | — | — | 24,665 | ||||||||||||||||||||
| Total income (loss) from discontinued operations, net of tax | 18,856 | (25,021 | ) | — | 145 | — | (1,344 | ) | (7,364 | ) | |||||||||||||||||
| Net income (loss) | $ | (65,059 | ) | $ | (25,021 | ) | $ | 5,661 | $ | 810 | $ | (51,258 | ) | $ | (1,854 | ) | $ | (136,721 | ) | ||||||||
| Total assets | $ | 1,602,022 | $ | 392,918 | $ | 245,207 | $ | 23,810 | $ | 93,612 | $ | (158,937 | ) | $ | 2,198,632 | ||||||||||||
Total capital expenditures (3) | $ | 927,456 | $ | 86,612 | $ | 84,348 | $ | 11,657 | $ | 785 | $ | — | $ | 1,110,858 | |||||||||||||
______________
(1) | Includes operations of Eureka Hunter Holdings, which represents approximately 38.6%, 40.7%, and 71.6% of Midstream and Marketing revenues for the years ended December 31, 2014, 2013, and 2012, respectively, and which was deconsolidated as of December 18, 2014. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”. |
(2) | Includes the Company’s retained interest in Eureka Hunter Holdings which has a value of $347 million at December 31, 2014. |
(3) | Presentation of capital expenditures has been changed from prior year presentation in order to reflect capital expenditures incurred rather than cash paid for capital expenditures. |
NOTE 21 - CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS
Guarantor Subsidiaries
Certain of the Company’s subsidiaries, including Alpha Hunter Drilling, LLC, Bakken Hunter, Shale Hunter, Magnum Hunter Marketing, LLC, MHP, NGAS Hunter, LLC, Triad Hunter, and Virco (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. The Guarantor Subsidiaries may also guarantee any debt of the Company issued pursuant to the Form S-3 Registration Statement filed by the Company with the SEC on August 5, 2014.
These condensed consolidating guarantor financial statements have been revised to reflect Eagle Ford Hunter and PRC Williston as a non-guarantors as the subsidiaries are no longer guarantors of the Company’s Senior Notes. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”.
Condensed consolidating financial information for Magnum Hunter Resources Corporation, the Guarantor Subsidiaries and the other subsidiaries of the Company (“Non Guarantor Subsidiaries”) as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013, and 2012 is as follows:
F-67
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Balance Sheets
(in thousands)
| As of December 31, 2014 | ||||||||||||||||||||
| Magnum Hunter Resources Corporation | 100% Owned Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating / Eliminating Adjustments | Magnum Hunter Resources Corporation Consolidated | ||||||||||||||||
| ASSETS | ||||||||||||||||||||
| Current assets | $ | 85,647 | $ | 36,338 | $ | 589 | $ | (2,378 | ) | $ | 120,196 | |||||||||
| Intercompany accounts receivable | 1,113,417 | — | — | (1,113,417 | ) | — | ||||||||||||||
| Property and equipment (using successful efforts accounting) | 5,506 | 1,170,122 | 30 | — | 1,175,658 | |||||||||||||||
| Investment in subsidiaries | (91,595 | ) | 94,134 | — | (2,539 | ) | — | |||||||||||||
| Investment in affiliate, equity-method | 347,191 | — | — | — | 347,191 | |||||||||||||||
| Other assets | 22,804 | 3,980 | — | — | 26,784 | |||||||||||||||
| Total Assets | $ | 1,482,970 | $ | 1,304,574 | $ | 619 | $ | (1,118,334 | ) | $ | 1,669,829 | |||||||||
| LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||||||||||||||||
| Current liabilities | $ | 25,347 | $ | 142,914 | $ | 2,567 | $ | (2,383 | ) | $ | 168,445 | |||||||||
| Intercompany accounts payable | — | 1,073,091 | 42,560 | (1,115,651 | ) | — | ||||||||||||||
| Long-term liabilities | 925,767 | 43,762 | — | — | 969,529 | |||||||||||||||
| Redeemable preferred stock | 100,000 | — | — | — | 100,000 | |||||||||||||||
| Shareholders' equity (deficit) | 431,856 | 44,807 | (44,508 | ) | (300 | ) | 431,855 | |||||||||||||
| Total Liabilities and Shareholders' Equity | $ | 1,482,970 | $ | 1,304,574 | $ | 619 | $ | (1,118,334 | ) | $ | 1,669,829 | |||||||||
F-68
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Balance Sheets
(in thousands)
| As of December 31, 2013 | ||||||||||||||||||||
| Magnum Hunter Resources Corporation | 100% Owned Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating / Eliminating Adjustments | Magnum Hunter Resources Corporation Consolidated | ||||||||||||||||
| ASSETS | ||||||||||||||||||||
| Current assets | $ | 53,161 | $ | 43,841 | $ | 27,096 | $ | (3,372 | ) | $ | 120,726 | |||||||||
| Intercompany accounts receivable | 965,138 | — | — | (965,138 | ) | — | ||||||||||||||
| Property and equipment (using successful efforts accounting) | 7,214 | 1,272,027 | 234,838 | — | 1,514,079 | |||||||||||||||
| Investment in subsidiaries | 372,236 | 102,314 | — | (474,550 | ) | — | ||||||||||||||
| Other assets | 17,308 | 100,894 | 103,644 | — | 221,846 | |||||||||||||||
| Total Assets | $ | 1,415,057 | $ | 1,519,076 | $ | 365,578 | $ | (1,443,060 | ) | $ | 1,856,651 | |||||||||
| LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||||||||||||||||
| Current liabilities | $ | 54,826 | $ | 97,520 | $ | 34,929 | $ | (3,410 | ) | $ | 183,865 | |||||||||
| Intercompany accounts payable | — | 921,237 | 43,866 | (965,103 | ) | — | ||||||||||||||
| Long-term liabilities | 818,651 | 39,067 | 127,663 | — | 985,381 | |||||||||||||||
| Redeemable preferred stock | 100,000 | — | 136,675 | — | 236,675 | |||||||||||||||
| Shareholders' equity (deficit) | 441,580 | 461,252 | 22,445 | (474,547 | ) | 450,730 | ||||||||||||||
| Total Liabilities and Shareholders' Equity | $ | 1,415,057 | $ | 1,519,076 | $ | 365,578 | $ | (1,443,060 | ) | $ | 1,856,651 | |||||||||
F-69
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Operations
(in thousands)
| For the Year Ended December 31, 2014 | ||||||||||||||||||||
| Magnum Hunter Resources Corporation | 100% Owned Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating / Eliminating Adjustments | Magnum Hunter Resources Corporation Consolidated | ||||||||||||||||
| Revenues | $ | 142 | $ | 368,537 | $ | 43,611 | $ | (20,821 | ) | $ | 391,469 | |||||||||
| Expenses | (370,646 | ) | 772,355 | 144,714 | (17,121 | ) | 529,302 | |||||||||||||
| Income (loss) from continuing operations before equity in net income of subsidiaries | 370,788 | (403,818 | ) | (101,103 | ) | (3,700 | ) | (137,833 | ) | |||||||||||
| Equity in net income of subsidiaries | (513,580 | ) | (8,181 | ) | — | 521,761 | — | |||||||||||||
| Income (loss) from continuing operations before income tax | (142,792 | ) | (411,999 | ) | (101,103 | ) | 518,061 | (137,833 | ) | |||||||||||
| Income tax benefit | — | — | — | — | — | |||||||||||||||
| Income (loss) from continuing operations | (142,792 | ) | (411,999 | ) | (101,103 | ) | 518,061 | (137,833 | ) | |||||||||||
| Income from discontinued operations, net of tax | — | — | 4,561 | — | 4,561 | |||||||||||||||
| Gain (loss) on disposal of discontinued operations, net of tax | (20,027 | ) | 97 | 6,075 | — | (13,855 | ) | |||||||||||||
| Net income (loss) | (162,819 | ) | (411,902 | ) | (90,467 | ) | 518,061 | (147,127 | ) | |||||||||||
| Net loss attributable to non-controlling interest | — | — | — | 3,653 | 3,653 | |||||||||||||||
| Net income (loss) attributable to Magnum Hunter Resources Corporation | (162,819 | ) | (411,902 | ) | (90,467 | ) | 521,714 | (143,474 | ) | |||||||||||
| Dividends on preferred stock | (35,364 | ) | — | (19,343 | ) | — | (54,707 | ) | ||||||||||||
| Loss on extinguishment of Eureka Hunter Holdings | (51,692 | ) | — | — | — | (51,692 | ) | |||||||||||||
| Net income (loss) attributable to common shareholders | $ | (249,875 | ) | $ | (411,902 | ) | $ | (109,810 | ) | $ | 521,714 | $ | (249,873 | ) | ||||||
| For the Year Ended December 31, 2013 | ||||||||||||||||||||
| Magnum Hunter Resources Corporation | 100% Owned Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating / Eliminating Adjustments | Magnum Hunter Resources Corporation Consolidated | ||||||||||||||||
| Revenues | $ | 2,629 | $ | 277,854 | $ | 35,848 | $ | (11,793 | ) | $ | 304,538 | |||||||||
| Expenses | 112,754 | 461,173 | 59,991 | (11,860 | ) | 622,058 | ||||||||||||||
| Income (loss) from continuing operations before equity in net income of subsidiaries | (110,125 | ) | (183,319 | ) | (24,143 | ) | 67 | (317,520 | ) | |||||||||||
| Equity in net income of subsidiaries | (298,775 | ) | (424 | ) | — | 299,199 | — | |||||||||||||
| Income (loss) from continuing operations before income tax | (408,900 | ) | (183,743 | ) | (24,143 | ) | 299,266 | (317,520 | ) | |||||||||||
| Income tax benefit | 28,989 | 56,422 | (4 | ) | — | 85,407 | ||||||||||||||
| Income (loss) from continuing operations | (379,911 | ) | (127,321 | ) | (24,147 | ) | 299,266 | (232,113 | ) | |||||||||||
| Income (loss) from discontinued operations, net of tax | (7,813 | ) | 22,661 | (77,340 | ) | (69 | ) | (62,561 | ) | |||||||||||
| Gain (loss) on disposal of discontinued operations, net of tax | 144,378 | — | (72,868 | ) | — | 71,510 | ||||||||||||||
| Net income (loss) | (243,346 | ) | (104,660 | ) | (174,355 | ) | 299,197 | (223,164 | ) | |||||||||||
| Net income attributable to non-controlling interest | — | — | — | 988 | 988 | |||||||||||||||
| Net income (loss) attributable to Magnum Hunter Resources Corporation | (243,346 | ) | (104,660 | ) | (174,355 | ) | 300,185 | (222,176 | ) | |||||||||||
| Dividends on preferred stock | (35,464 | ) | — | (21,241 | ) | — | (56,705 | ) | ||||||||||||
| Net income (loss) attributable to common shareholders | $ | (278,810 | ) | $ | (104,660 | ) | $ | (195,596 | ) | $ | 300,185 | $ | (278,881 | ) | ||||||
F-70
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Operations
(in thousands)
| For the Year Ended December 31, 2012 | ||||||||||||||||||||
| Magnum Hunter Resources Corporation | 100% Owned Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating / Eliminating Adjustments | Magnum Hunter Resources Corporation Consolidated | ||||||||||||||||
| Revenues | $ | 729 | $ | 141,772 | $ | 21,080 | $ | (3,644 | ) | $ | 159,937 | |||||||||
| Expenses | 54,047 | 212,071 | 32,487 | 15,354 | 313,959 | |||||||||||||||
| Loss from continuing operations before equity in net income of subsidiaries | (53,318 | ) | (70,299 | ) | (11,407 | ) | (18,998 | ) | (154,022 | ) | ||||||||||
| Equity in net income of subsidiaries | (102,545 | ) | 458 | (23,362 | ) | 125,449 | — | |||||||||||||
| Income (loss) from continuing operations before income tax | (155,863 | ) | (69,841 | ) | (34,769 | ) | 106,451 | (154,022 | ) | |||||||||||
| Income tax benefit | 11,290 | 13,375 | — | — | 24,665 | |||||||||||||||
| Income (loss) from continuing operations | (144,573 | ) | (56,466 | ) | (34,769 | ) | 106,451 | (129,357 | ) | |||||||||||
| Loss from discontinued operations, net of tax | — | (209 | ) | (9,564 | ) | — | (9,773 | ) | ||||||||||||
| Gain on disposal of discontinued operations, net of tax | — | 2,409 | — | — | 2,409 | |||||||||||||||
| Net income (loss) | (144,573 | ) | (54,266 | ) | (44,333 | ) | 106,451 | (136,721 | ) | |||||||||||
| Net income attributable to non-controlling interest | — | — | — | 4,013 | 4,013 | |||||||||||||||
| Net income (loss) attributable to Magnum Hunter Resources Corporation | (144,573 | ) | (54,266 | ) | (44,333 | ) | 110,464 | (132,708 | ) | |||||||||||
| Dividends on preferred stock | (22,842 | ) | — | (11,864 | ) | — | (34,706 | ) | ||||||||||||
| Net income (loss) attributable to common shareholders | $ | (167,415 | ) | $ | (54,266 | ) | $ | (56,197 | ) | $ | 110,464 | $ | (167,414 | ) | ||||||
F-71
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Comprehensive Income (Loss)
(in thousands)
| For the Year Ended December 31, 2014 | |||||||||||||||||||
| Magnum Hunter Resources Corporation | 100% Owned Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating / Eliminating Adjustments | Magnum Hunter Resources Corporation Consolidated | |||||||||||||||
| Net income (loss) | $ | (162,819 | ) | $ | (411,902 | ) | $ | (90,467 | ) | $ | 518,061 | $ | (147,127 | ) | |||||
| Foreign currency translation loss | — | — | (1,204 | ) | — | (1,204 | ) | ||||||||||||
| Unrealized gain (loss) on available for sale securities | — | (7,401 | ) | — | — | (7,401 | ) | ||||||||||||
| Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc. | 20,741 | — | — | — | 20,741 | ||||||||||||||
| Comprehensive income (loss) | (142,078 | ) | (419,303 | ) | (91,671 | ) | 518,061 | (134,991 | ) | ||||||||||
| Comprehensive (income) loss attributable to non-controlling interest | — | — | — | 3,653 | 3,653 | ||||||||||||||
| Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation | $ | (142,078 | ) | $ | (419,303 | ) | $ | (91,671 | ) | $ | 521,714 | $ | (131,338 | ) | |||||
| For the Year Ended December 31, 2013 | |||||||||||||||||||
| Magnum Hunter Resources Corporation | 100% Owned Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating / Eliminating Adjustments | Magnum Hunter Resources Corporation Consolidated | |||||||||||||||
| Net income (loss) | $ | (243,346 | ) | $ | (104,660 | ) | $ | (174,355 | ) | $ | 299,197 | $ | (223,164 | ) | |||||
| Foreign currency translation loss | — | — | (10,928 | ) | — | (10,928 | ) | ||||||||||||
| Unrealized gain (loss) on available for sale securities | 8,262 | (84 | ) | — | — | 8,178 | |||||||||||||
| Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities | (8,262 | ) | — | — | — | (8,262 | ) | ||||||||||||
| Comprehensive income (loss) | (243,346 | ) | (104,744 | ) | (185,283 | ) | 299,197 | (234,176 | ) | ||||||||||
| Comprehensive (income) loss attributable to non-controlling interest | — | — | — | 988 | 988 | ||||||||||||||
| Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation | $ | (243,346 | ) | $ | (104,744 | ) | $ | (185,283 | ) | $ | 300,185 | $ | (233,188 | ) | |||||
| For the Year Ended December 31, 2012 | |||||||||||||||||||
| Magnum Hunter Resources Corporation | 100% Owned Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating / Eliminating Adjustments | Magnum Hunter Resources Corporation Consolidated | |||||||||||||||
| Net income (loss) | $ | (144,573 | ) | $ | (54,266 | ) | $ | (44,333 | ) | $ | 106,451 | $ | (136,721 | ) | |||||
| Foreign currency translation loss | — | — | 3,883 | — | 3,883 | ||||||||||||||
| Unrealized gain (loss) on available for sale securities | — | (309 | ) | — | — | (309 | ) | ||||||||||||
| Comprehensive income (loss) | (144,573 | ) | (54,575 | ) | (40,450 | ) | 106,451 | (133,147 | ) | ||||||||||
| Comprehensive (income) loss attributable to non-controlling interest | — | — | — | 4,013 | 4,013 | ||||||||||||||
| Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation | $ | (144,573 | ) | $ | (54,575 | ) | $ | (40,450 | ) | $ | 110,464 | $ | (129,134 | ) | |||||
F-72
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Cash Flows
(in thousands)
| For the Year Ended December 31, 2014 | ||||||||||||||||||||
| Magnum Hunter Resources Corporation | 100% Owned Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating / Eliminating Adjustments | Magnum Hunter Resources Corporation Consolidated | ||||||||||||||||
| Cash flow from operating activities | $ | (347,898 | ) | $ | 255,088 | $ | 74,145 | $ | — | $ | (18,665 | ) | ||||||||
| Cash flow from investing activities | 107,595 | (248,928 | ) | (176,786 | ) | — | (318,119 | ) | ||||||||||||
| Cash flow from financing activities | 250,194 | 301 | 97,700 | — | 348,195 | |||||||||||||||
| Effect of exchange rate changes on cash | — | — | 56 | — | 56 | |||||||||||||||
| Net increase (decrease) in cash | 9,891 | 6,461 | (4,885 | ) | — | 11,467 | ||||||||||||||
| Cash at beginning of period | 47,895 | (17,651 | ) | 11,469 | — | 41,713 | ||||||||||||||
| Cash at end of period | $ | 57,786 | $ | (11,190 | ) | $ | 6,584 | $ | — | $ | 53,180 | |||||||||
| For the Year Ended December 31, 2013 | ||||||||||||||||||||
| Magnum Hunter Resources Corporation | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating / Eliminating Adjustments | Magnum Hunter Resources Corporation Consolidated | ||||||||||||||||
| Cash flow from operating activities | $ | (371,351 | ) | $ | 397,213 | $ | 99,153 | $ | (13,304 | ) | $ | 111,711 | ||||||||
| Cash flow from investing activities | 422,303 | (411,473 | ) | (138,690 | ) | — | (127,860 | ) | ||||||||||||
| Cash flow from financing activities | (29,929 | ) | 796 | 16,485 | 13,304 | 656 | ||||||||||||||
| Effect of exchange rate changes on cash | — | — | (417 | ) | — | (417 | ) | |||||||||||||
| Net increase (decrease) in cash | 21,023 | (13,464 | ) | (23,469 | ) | — | (15,910 | ) | ||||||||||||
| Cash at beginning of period | 26,872 | (4,187 | ) | 34,938 | — | 57,623 | ||||||||||||||
| Cash at end of period | $ | 47,895 | $ | (17,651 | ) | $ | 11,469 | $ | — | $ | 41,713 | |||||||||
| For the Year Ended December 31, 2012 | ||||||||||||||||||||
| Magnum Hunter Resources Corporation | 100% Owned Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating / Eliminating Adjustments | Magnum Hunter Resources Corporation Consolidated | ||||||||||||||||
| Cash flow from operating activities | $ | (458,921 | ) | $ | 281,782 | $ | 236,360 | $ | (1,210 | ) | $ | 58,011 | ||||||||
| Cash flow from investing activities | (364,045 | ) | (287,204 | ) | (357,961 | ) | 3 | (1,009,207 | ) | |||||||||||
| Cash flow from financing activities | 831,080 | 1,781 | 162,374 | 1,207 | 996,442 | |||||||||||||||
| Effect of exchange rate changes on cash | — | — | (2,474 | ) | — | (2,474 | ) | |||||||||||||
| Net increase (decrease) in cash | 8,114 | (3,641 | ) | 38,299 | — | 42,772 | ||||||||||||||
| Cash at beginning of period | 18,758 | (546 | ) | (3,361 | ) | — | 14,851 | |||||||||||||
| Cash at end of period | $ | 26,872 | $ | (4,187 | ) | $ | 34,938 | $ | — | $ | 57,623 | |||||||||
NOTE 22 - SUBSEQUENT EVENTS
Closing of additional MNW Interests
On January 14, 2015, Triad Hunter purchased approximately 2,665 net acres of undeveloped leasehold in the Utica Shale in Ohio for $12.0 million under its asset purchase agreement with MNW. Following this purchase, approximately 6,956 net acres remain to be purchased by the Company under the asset purchase agreement with MNW, contingent upon the remaining leasehold acreage being cured of title defects acceptable to Triad Hunter.
F-73
Departure of Officer and Closing of Certain Offices
Effective January 31, 2015, R. Glenn Dawson resigned from his position as Executive Vice President of the Company and President of the Company’s Williston Basin Division, and as an employee of the Company. In connection with Mr. Dawson’s resignation, the Company and Mr. Dawson entered into a letter agreement regarding severance (the “Severance Agreement”) and a Release and Confidentiality Agreement, each dated as of January 29, 2015. Pursuant to the Severance Agreement, the Company agreed to pay Mr. Dawson a total of CAD $550,000 ($435,000 USD) in severance pay, less applicable statutory withholding deductions (the “Severance Amount”). The Severance Amount, the determination of which took into account certain rights of Canadian employees to severance under Canadian law, will be paid by the Company to Mr. Dawson in approximately equal bi-weekly installments during the period from February 1, 2015 to June 15, 2015. Pursuant to the Release and Confidentiality Agreement, Mr. Dawson provided a customary general release of claims against the Company and its affiliates, including claims relating to severance under Canadian law, and agreed to customary confidentiality provisions.
Due to a combination of the sale last year of all of the Company’s Canadian assets and a substantial portion of its Bakken assets located in North Dakota, the increasing focus on the Company’s natural gas and NGLs exploration and production activities located in West Virginia and Ohio, and in an effort to reduce general and administrative costs, the Company has closed its Denver, Colorado and Calgary, Alberta offices effective January 31, 2015 and terminated all employees at those locations. The Company has also moved the responsibilities of the former personnel at those now-closed offices to existing personnel at the Company’s Houston and Grapevine, Texas offices.
New Corporate Office in Irving, Texas
In connection with the Company’s announced plans to relocate its corporate headquarters from Houston, Texas to the Dallas, Texas area, the Company’s finance, treasury and reserve engineering departments will be moving to the Dallas. Additionally, the Company plans to consolidate its accounting, financial reporting, information systems, legal and human resources departments, which are currently located in Grapevine, Texas, to its new corporate headquarters. In connection with the corporate headquarters relocation, the Company entered into a sublease agreement to lease commercial office space in Irving (Las Colinas), Texas, in order to relocate its corporate headquarters. The commencement date of the sublease was January 16, 2015, and the sublease expires on January 31, 2018. The sublease rent is $366,000 per year.
ND Pipeline Agreements
On January 16, 2015, Bakken Hunter executed an Agreement for the Construction, Ownership and Operation of the ND Pipeline Facilities (the “ND Pipeline Facilities Agreement) and a Gas Purchase Agreement with Steppe Petroleum Inc (“Steppe”). Under the terms of the ND Pipeline Facilities Agreement, Bakken Hunter agreed to construct a gas gathering pipeline (the “ND Pipeline”), approximately one mile in length, spanning from the Canadian border to the Oneok Rockies Divide County gas gathering system, which is owned and operated by ONEOK Rockies Midstream, LLC (“Oneok”). Bakken Hunter currently acts as operator of the ND Pipeline and Steppe has borne all the costs associated with the operation, construction, and modifications to the ND Pipeline until such time as either (i) Bakken Hunter exercises its right to cause Steppe to takeover operatorship, or (ii) Steppe exercises their right to step in as or replace Bakken Hunter as operator. Upon execution of the agreement, Steppe became obligated to reimburse Bakken Hunter approximately $689,000 for costs incurred for the construction of the ND Pipeline.
Bakken Hunter also agreed to purchase all natural gas that is gathered from Steppe’s wells through the ND Pipeline and delivered into the Oneok Rockies Divide County gas gathering system. Bakken Hunter sells all natural gas purchased from Steppe to Oneok in a back-to-back transaction. Bakken Hunter must remit to Steppe all proceeds from natural gas sold to Oneok under this agreement less an administrative fee of $0.05 per Mcf gathered.
Rig Purchase by Alpha Hunter Drilling, LLC.
In February 2015, the Company was notified that the drilling rig, for which Alpha Hunter Drilling had executed a purchase contract and made a deposit of $1.3 million in June 2014, was complete and available for delivery. However, the Company has not taken delivery of the rig and has notified the seller that until performance issues related to a separate drilling rig of the same model previously purchased by the Company from the seller are resolved, that it does not intend to take delivery of the new rig.
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NOTE 23 - OTHER INFORMATION
Quarterly Data (Unaudited)
Certain prior-year balances have been reclassified to correspond with current-year presentation. As a result of the Company’s decision in September 2014 to withdraw its plan to divest MHP and to cease all marketing efforts, the results of operations of MHP, which had previously been reported as a component of discontinued operations, have been reclassified to continuing operations for all periods presented. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”.
The following tables set forth unaudited summary financial results on a quarterly basis for the most recent two years.
| Quarter Ended | |||||||||||||||
| March 31, | June 30, | September 30, | December 31, | Year Ended | |||||||||||
| 2014 | |||||||||||||||
| (in thousands) | |||||||||||||||
Total revenue (1) | $ | 113,482 | $ | 138,463 | $ | 79,670 | $ | 59,854 | $ | 391,469 | |||||
Operating income (loss) (2) | $ | (32,762 | ) | $ | 1,555 | $ | (57,576 | ) | $ | (401,575 | ) | $ | (490,358 | ) | |
Income (loss) from continuing operations (3) | $ | (56,557 | ) | $ | (61,407 | ) | $ | (123,189 | ) | $ | 103,320 | $ | (137,833 | ) | |
| Income (loss) from discontinued operations, net of tax | $ | 3,369 | $ | 1,192 | $ | — | $ | — | $ | 4,561 | |||||
Gain (loss) on disposal of discontinued operations, net of tax | $ | (8,513 | ) | $ | (5,212 | ) | $ | (258 | ) | $ | 128 | $ | (13,855 | ) | |
| Net income (loss) attributable to Magnum Hunter Resources Corporation | $ | (61,592 | ) | $ | (64,647 | ) | $ | (120,683 | ) | $ | 103,448 | $ | (143,474 | ) | |
| Net income (loss) attributable to common shareholders | $ | (76,468 | ) | $ | (79,997 | ) | $ | (136,175 | ) | $ | 42,767 | $ | (249,873 | ) | |
| Basic and diluted income (loss) from continuing operations per common share | $ | (0.41 | ) | $ | (0.41 | ) | $ | (0.68 | ) | $ | 0.23 | $ | (1.27 | ) | |
| Basic and diluted income (loss) per common share | $ | (0.44 | ) | $ | (0.43 | ) | $ | (0.68 | ) | $ | 0.23 | $ | (1.32 | ) | |
| 2013 | |||||||||||||||
| Total revenue | $ | 59,382 | $ | 76,686 | $ | 78,291 | $ | 90,179 | $ | 304,538 | |||||
Operating loss (4) | $ | (41,437 | ) | $ | (34,412 | ) | $ | (119,874 | ) | $ | (39,070 | ) | $ | (234,793 | ) |
| Loss from continuing operations | $ | (61,584 | ) | $ | (3,634 | ) | $ | (152,513 | ) | $ | (14,382 | ) | $ | (232,113 | ) |
Income (loss) from discontinued operations, net of tax (5) | $ | 16,884 | $ | (3,764 | ) | $ | (75,573 | ) | $ | (108 | ) | $ | (62,561 | ) | |
Gain (loss) on disposal of discontinued operations, net of tax (6) | — | 172,452 | (69,521 | ) | (31,421 | ) | 71,510 | ||||||||
| Net income (loss) attributable to Magnum Hunter Resources Corporation | $ | (44,197 | ) | $ | 165,440 | $ | (296,882 | ) | $ | (46,537 | ) | $ | (222,176 | ) | |
| Net income (loss) attributable to common shareholders | $ | (57,685 | ) | $ | 151,311 | $ | (311,299 | ) | $ | (61,208 | ) | $ | (278,881 | ) | |
| Basic and diluted loss from continuing operations per common share | $ | (0.44 | ) | $ | (0.10 | ) | $ | (0.98 | ) | $ | (0.17 | ) | $ | (1.69 | ) |
| Basic and diluted income (loss) per common share | $ | (0.34 | ) | $ | 0.89 | $ | (1.83 | ) | $ | (0.36 | ) | $ | (1.64 | ) | |
______________
(1) | Total revenues increased during the quarter ended June 30, 2014 primarily due to increases in natural gas gathering, processing, and marketing revenues as a result of new customers, growth from existing customers, and increased gas and NGLs revenues from the Markwest processing plant. Revenues decreased during the quarter ended September 30, 2014 due to decreases in natural gas gathering, processing, and marketing revenues. This decrease was due to the decision made by a third party customer to begin marketing their own natural gas, which had previously been marketed by the Company. Revenues decreased during the quarter ended December 31, 2014 due to decreases in oil prices, as well as decreased volumes due to the sales of certain oil and natural gas properties located in Divide County, North Dakota during the fourth quarter. |
F-75
(2) | The quarter-ended June 30, 2014 income from operations was primarily driven by the increase in total revenues during that quarter, as discussed above. The loss from operations during the following quarter was due mainly to the decrease in total revenues, as discussed above. Loss from operations during the quarter ended December 31, 2014 was partially due to the decrease in revenues as discussed above, but also due to exploration expense of $66.1 million related mainly to the Williston Basin, impairment of proved oil and gas properties of $261.5 million mainly in the Williston Basin, and increased general and administrative expenses. General and administrative expenses during the quarter ended December 31, 2014 included a one-time charge of $32.6 million related to the Letter Agreement with MSI, in which the Company’s capital account with Eureka Hunter Holdings was adjusted down in order to take into account certain excess capital expenditures incurred by Eureka Hunter Pipeline in connection with certain of Eureka Hunter Pipeline’s fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects. |
(3) | Loss from continuing operations during the quarters ended June 30, 2014 and September 30, 2014 includes loss on derivative contracts of $42.8 million and $49.6 million, respectively, primarily as a result of the unrealized loss on the embedded derivative liability resulting from certain features of the Eureka Hunter Holdings Series A Preferred Units. The unrealized losses were driven by increases in total enterprise value and a reduction in the expected term of the conversion feature. Income from continuing operations for the quarter ended December 31, 2014 includes a gain of $510 million from the deconsolidation of Eureka Hunter Holdings. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”. |
(4) | 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. |
(5) | 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. |
(6) | 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 $55.6 million, net of tax, to reflect the net assets of WHI 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 $18.2 million, net of tax, to reflect changes in the estimated fair values of the net assets of WHI Canada which the Company had decided to sell during the quarter ended September 30, 2013. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”. |
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):
| For the Year Ended December 31, | |||||||||||
| 2014 | 2013 | 2012 | |||||||||
| Purchase of non-producing leases | $ | 124,411 | $ | 149,592 | $ | 414,037 | |||||
| Purchase of producing properties | 12,246 | 1,358 | 159,290 | ||||||||
| Exploration costs | 9,907 | 11,531 | 165,789 | ||||||||
| Development costs | 321,053 | 273,944 | 262,486 | ||||||||
| Asset retirement obligation | 6,085 | 2,186 | 407 | ||||||||
| $ | 473,702 | $ | 438,611 | $ | 1,002,009 | ||||||
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 2014 and 2013, and Cawley, Gillespie, & Associates, Inc. and AJM Deloitte in 2012. 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.
F-76
| Total Proved Reserves | Crude Oil | NGLs | Natural Gas | ||||||
| (MBbl) | (MBbl) | (MMcf) | |||||||
| Balance December 31, 2011 | 17,124 | 4,585 | 139,237 | ||||||
| Revisions of previous estimates | 7,936 | 4,632 | 25,644 | ||||||
| Purchase of reserves in place | 10,613 | — | 12,082 | ||||||
| Extensions, discoveries, and other additions | 3,305 | 110 | 544 | ||||||
| Sale of reserves in place | (10) | — | (63) | ||||||
| Production | (2,141) | (202) | (14,824) | ||||||
| Balance December 31, 2012 | 36,827 | 9,125 | 162,620 | ||||||
| Revisions of previous estimates | 3,766 | 2,382 | 100,456 | ||||||
| Purchase of reserves in place | — | — | 88 | ||||||
| Extensions, discoveries, and other additions | 577 | 71 | 1,285 | ||||||
| Sale of reserves in place | (14,506) | (698) | (4,185) | ||||||
| Production | (2,329) | (458) | (13,482) | ||||||
| Balance December 31, 2013 | 24,335 | 10,422 | 246,782 | ||||||
| Extensions, discoveries and other additions | 1,705 | 3,226 | 132,345 | ||||||
| Revisions of previous estimates | (6,540) | 2,149 | (511) | ||||||
| Sales of reserves in place | (7,321) | (434) | (3,768) | ||||||
| Production | (1,658) | (960) | (21,847) | ||||||
| Balance December 31, 2014 | 10,521 | 14,403 | 353,001 | ||||||
| Developed reserves, included above | |||||||||
| December 31, 2012 | 16,355 | 6,262 | 125,526 | ||||||
| December 31, 2013 | 12,085 | 6,990 | 176,585 | ||||||
| December 31, 2014 | 6,938 | 10,587 | 251,628 | ||||||
| Proved undeveloped reserves, included above: | |||||||||
| December 31, 2012 | 20,472 | 2,863 | 37,094 | ||||||
| December 31, 2013 | 12,250 | 3,432 | 70,197 | ||||||
| December 31, 2014 | 3,583 | 3,816 | 101,373 | ||||||
The purchases of reserves in place during the year ended December 31, 2012, includes approximately 2,217 MBoe of proved reserves acquired in the Eagle Operating Assets Acquisition, approximately 8,595 MBoe of proved reserves acquired in the Baytex Energy USA Assets Acquisition, approximately 1,429 MBoe acquired in the Virco acquisition and various smaller acquisitions. The sale of reserves in place during the year ended December 31, 2013, includes approximately 11,459 MBoe of proved reserves included in the sale of Eagle Ford Hunter and approximately 4,308 MBoe of proved reserves in the sale of certain North Dakota Oil and Natural Gas Properties (see “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”). Extensions, discoveries and other additions during the year ended December 31, 2014, related to (i) extension of the proved acreage of previously discovered reserves through additional drilling in periods subsequent to discovery and (ii) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions and discoveries increased 26,126 MBoe in 2014 to 26,988 MBoe from a base of 862 MBoe in 2013. The largest extensions and discoveries were all related to activity in our Marcellus Shale and Utica Shale development program which included the wells completed on the Stewart Winland, Stalder, WVDNR and Ormet pads.
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, 2014, 2013, and 2012 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, 2014, 2013, and 2012 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.
F-77
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:
| Years Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| (in thousands) | ||||||||||||
| Future cash inflows | $ | 3,282,768 | $ | 3,711,260 | $ | 4,248,384 | ||||||
| Future production costs | (1,443,121 | ) | (1,423,306 | ) | (1,520,260 | ) | ||||||
| Future development costs | (219,509 | ) | (421,797 | ) | (603,809 | ) | ||||||
| Future income tax expense | — | (149,367 | ) | (230,500 | ) | |||||||
| Future net cash flows | 1,620,138 | 1,716,790 | 1,893,815 | |||||||||
| 10% annual discount for estimated timing of cash flows | (710,875 | ) | (872,280 | ) | (1,046,162 | ) | ||||||
| Standardized measure of discounted future net cash flows | $ | 909,263 | $ | 844,510 | $ | 847,653 | ||||||
Future cash flows as shown above were reported without consideration for the effects of commodity derivative transactions outstanding at each period end.
No provision for income taxes has been provided in the above standardized measure of discounted future net cash flows as of December 31, 2014, as a result of the Company’s net operating loss carryforwards of $710 million and other future expected tax deductions. See “Note 15 - Income Taxes”.
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:
| Years Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| (in thousands) | ||||||||||||
| Balance, beginning of period | $ | 844,510 | $ | 847,653 | $ | 474,396 | ||||||
| Net changes in prices and production costs | (281,352 | ) | (7,355 | ) | 13,647 | |||||||
| Changes in estimated future development costs | (57,348 | ) | (261,591 | ) | (391,318 | ) | ||||||
| Sales and transfers of oil and gas produced during the period | (166,611 | ) | (190,151 | ) | (179,384 | ) | ||||||
| Net changes due to extensions, discoveries, and improved recovery | 332,684 | 12,829 | 60,468 | |||||||||
Net changes due to revisions of previous quantity estimates (1) | (55,176 | ) | 341,003 | 290,500 | ||||||||
| Previously estimated development costs incurred during the period | 269,017 | 283,736 | 245,168 | |||||||||
| Accretion of discount | 95,547 | 90,153 | 85,377 | |||||||||
| Purchase of minerals in place | — | 218 | 217,791 | |||||||||
| Sale of minerals in place | (141,847 | ) | (236,885 | ) | (354 | ) | ||||||
Changes in timing and other (2) | (7,720 | ) | (91,088 | ) | 22,436 | |||||||
| Net change in income taxes | 77,559 | 55,988 | 8,926 | |||||||||
| Standardized measure of discounted future net cash flows | $ | 909,263 | $ | 844,510 | $ | 847,653 | ||||||
______________
F-78
(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, 2014, the Company made downward revisions of 6,540 MBbl of oil and 511 MMcf of natural gas, and upward revisions of 2,149 MBbl of natural gas liquids 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, 2013, the Company made upward revisions of 3,766 MBbls of oil, 2,382 MBbl of natural gas liquids, and 100,456 MMcf of natural gas. For the year ended December 31, 2012, the Company made upward revisions of 7,936 MBbls of oil, 4,632 MBbl of 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:
| 2014 | 2013 | 2012 | ||||||||||
| Oil (per Bbl) | $ | 85.21 | $ | 93.13 | $ | 88.37 | ||||||
| Natural gas liquids (per Bbl) | $ | 50.64 | $ | 43.79 | $ | 53.94 | ||||||
| Gas (per Mcf) | $ | 4.69 | $ | 4.14 | $ | 3.08 | ||||||
In accordance with SEC requirements, the pricing used in our standardized measure of future net revenues is based on the 12-month un-weighted arithmetic average of the first-day-of-the-month price for the period January through December 2014 and adjusted by lease for transportation fees and regional price differentials. The use of SEC pricing rules may not be indicative of actual prices realized by the Company in the future.
| Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
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, 2014. Based upon that evaluation, the CEO and CFO concluded that the Company's disclosure controls and procedures were effective as of December 31, 2014.
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 has conducted an assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2014 based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 COSO Framework). Based on the assessment, management has concluded that, as of December 31, 2014, the Company's internal control over financial reporting was effective.
Our independent registered public accounting firm has audited the effectiveness of our internal control over financial reporting as of December 31, 2014 as stated in their report, dated March 2, 2015, which appears herein.
F-79
Changes in Internal Control Over Financial Reporting
During 2014, Management made significant changes and improvements in our internal control over financial reporting that have resulted in remediation of the material weaknesses disclosed in previous filings. Specifically, the material weakness related to intra period tax allocation was remediated through improvements in staff and training of tax personnel, involvement of third-party tax consultants, additional reviews around tax disclosures in the financial statement and implementation of procedures and checklists in the tax provision process. Additionally, the material weakness associated with account reconciliations has been remediated through implementation of account reconciliation software, training and emphasis on defined reconciliation procedures and spreadsheet controls, and additional layers of review of account reconciliations. Lastly, the material weakness connected with property accounting was remediated as a result of emphasis and directive by senior management around performance of controls with respect to land and property accounting processes, improved communication and coordination across divisions and functions, added level of precision in performing controls, and overall improvements in procedures related to lease records, ownership interests, impairments, capital accrual and reserves.
| Item 9B. | OTHER INFORMATION |
None.
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PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
Information as to Item 10 will be set forth in the 2015 Proxy Statement, or the Proxy Statement, for the Company’s Annual Meeting of Common Stockholders anticipated to be held in June 2015, or the Annual Meeting, and is incorporated herein by reference.
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. | 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. 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. | 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.
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PART IV
| Item 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
| 1. | Financial Statement Schedules: The consolidated financial statements of the Company and the Report of Independent Registered Public Accounting Firm as set forth in Part II, Item 8 of this Annual Report: |
| Report of Independent Registered Public Accounting Firm | F-1 |
| Consolidated Balance Sheets at December 31, 2014 and 2013 | F-3 |
| Consolidated Statements of Operations for the years ended December 31, 2014, 2013, and 2012 | F-5 |
| Consolidated Statements of Comprehensive Loss for the years ended December 31, 2014, 2013, and 2012 | F-6 |
| Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2014, 2013, and 2012 | F-7 |
| Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013, and 2012 | F-9 |
| Notes to the Consolidated Financial Statements | F-10 |
| 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. |
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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: March 2, 2015
| Signature | Title | Date |
| /s/ Gary C. Evans | Chairman of the Board and | March 2, 2015 |
| Gary C. Evans | Chief Executive Officer (Principal Executive Officer) | |
| /s/ Joseph C. Daches | Senior Vice President, | March 2, 2015 |
| Joseph C. Daches | Chief Financial Officer (Principal Financial Officer) | |
| /s/ J. Raleigh Bailes, Sr. | Director | March 2, 2015 |
| J. Raleigh Bailes, Sr. | ||
| /s/ Rocky Duckworth | Director | March 2, 2015 |
| Rocky Duckworth | ||
| /s/ Victor G. Carrillo | Director | March 2, 2015 |
| Victor G. Carrillo | ||
| /s/ Stephen C. Hurley | Director | March 2, 2015 |
| Stephen C. Hurley | ||
| /s/ Joe L. McClaugherty | Lead Director | March 2, 2015 |
| Joe L. McClaugherty | ||
| /s/ Jeff Swanson | Director | March 2, 2015 |
| Jeff Swanson | ||
| INDEX TO EXHIBITS | ||
| Exhibit Number | Description | |
| 2.1+ | Arrangement Agreement between the Registrant and NGAS Resources, Inc., dated December 23, 2010 (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 30, 2010). | |
| 2.2+ | Arrangement Agreement between the Registrant and NuLoch Resources Inc., dated January 19, 2011 (incorporated by reference from the Registrant’s current report on Form 8-K filed on January 25, 2011). | |
| 2.2.1+ | Plan of Arrangement under Section 193 of the Business Corporations Act (Alberta) with respect to the Acquisition of NuLoch Resources Inc. by the Registrant (incorporated by reference from the Registrant’s registration statement on Form S-4 filed on April 8, 2011). | |
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| 2.3+ | Asset Purchase Agreement, dated March 21, 2012, by and among Eureka Hunter Holdings, LLC, TransTex Gas Services LP, and Eureka Hunter Acquisition Sub LLC (incorporated by reference from the Registrant’s current report on Form 10-Q filed on May 3, 2012). | |
| 2.3.1 | First Amendment to Asset Purchase Agreement, dated April 2, 2012, by and between Eureka Hunter Holdings, LLC, TransTex Gas Services, LP, and Eureka Hunter Acquisition Sub LLC (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on May 3, 2012). | |
| 2.4+ | Purchase and Sale Agreement, dated as of April 17, 2012, by and between Baytex Energy USA Ltd. and Bakken Hunter, LLC (incorporated by reference from the Registrant’s current report on Form 8-K filed on April 24, 2012). | |
| 2.4.1 | First Amendment to Purchase and Sale Agreement, dated May 17, 2012, by and between Baytex Energy USA Ltd. and Bakken Hunter, LLC (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 23, 2012). | |
| 2.4.2 | Second Amendment to Purchase and Sale Agreement, dated May 22, 2012, by and between Baytex Energy USA Ltd. and Bakken Hunter, LLC (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 23, 2012). | |
| 2.5+ | Stock Purchase Agreement, dated as of October 24, 2012, by and among Triad Hunter, LLC, Viking International Resources Co., Inc., all of the stockholders of Viking International Resources Co., Inc., and solely for the purposes set forth therein, the Registrant (incorporated by reference from the Registrant’s current report on Form 8-K filed on October 30, 2012). | |
| 2.6+ | Purchase and Sale Agreement, dated as of November 21, 2012, between Samson Resources Company and Bakken Hunter, LLC (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 28, 2012).+ | |
| 2.7+ | Stock Purchase Agreement, dated as of April 2, 2013, between the Registrant, Penn Virginia Oil & Gas Corporation, and Penn Virginia Corporation (incorporated by reference from the Registrant's current report on Form 8-K filed on April 8, 2013). | |
| 2.8+ | Asset Purchase Agreement, dated as of August 12, 2013, between Triad Hunter, LLC and MNW Energy, LLC (incorporated by reference from the Registrant's quarterly report on Form 10-Q filed on November 8, 2013). | |
| 2.9+ | Purchase and Sale Agreement, dated as of September 2, 2013, between Williston Hunter, Inc. and Oasis Petroleum of North America LLC (incorporated by reference from the Registrant's current report on Form 8-K filed on September 4, 2013).+ | |
| 2.10+ | Purchase and Sale Agreement, dated as of November 19, 2013, by and among PRC Williston, LLC, Williston Hunter ND, LLC and Enduro Operating LLC (incorporated by reference from the Registrant's current report on Form 8-K filed on November 22, 2013). | |
| 2.11+ | Purchase and Sale Agreement, dated January 21, 2013, among Shale Hunter, LLC, Magnum Hunter Resources Corporation, Magnum Hunter Production, Inc. and Energy Hunter Partners 2012-A Drilling & Production Fund, Ltd., New Standard Energy Texas LLC and New Standard Energy Limited (incorporated by reference from the Registrant's current report on Form 8-K filed on January 23, 2014). | |
| 2.11.1+ | Transition Services Agreement, dated January 28, 2014, between Shale Hunter, LLC and New Standard Energy Texas LLC (incorporated by reference from the Registrant's current report on Form 8-K filed on January 30, 2014). | |
| 2.12+ | Purchase and Sale Agreement, dated March 31, 2014, between Williston Hunter Canada, Inc. and BDJ Energy Inc. (incorporated by reference from the Registrant’s Quarterly Report on Form 10-Q filed on May 9, 2014). | |
| 2.13+ | Share Purchase Agreement, dated April 21, 2014, between the Registrant and Steppe Resources Inc. (incorporated by reference from the Registrant’s Quarterly Report on Form 10-Q filed on May 9, 2014). | |
| 2.14+@ | Transaction Agreement, dated September 15, 2014 (entered into on September 16, 2014), by and among Eureka Hunter Holdings, LLC, the Registrant, MSIP II Buffalo Holdings LLC (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on September 22, 2014). | |
113
| 2.14.1+ | Letter Agreement, dated November 18, 2014, by and among Eureka Hunter Holdings, LLC, the Registrant and MSIP II Buffalo Holdings, LLC (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on November 24, 2014). | |
| 2.15+ | Purchase and Sale Agreement, dated September 29, 2014, entered into on September 30, 2014, between Bakken Hunter, LLC and LGFE-BH L.P. (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on October 6, 2014). | |
| 2.16+ | Purchase and Sale Agreement, dated October 9, 2014, by and between Bakken Hunter, LLC and SM Energy Company (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on October 14, 2014). | |
| 3.1 | Restated Certificate of Incorporation of the Registrant, filed February 13, 2002 (incorporated by reference from the Registrant’s registration statement on Form SB-2 filed on March 21, 2006). | |
| 3.1.1 | Certificate of Amendment of Certificate of Incorporation of the Registrant, filed May 8, 2003 (incorporated by reference from the Registrant’s registration statement on Form SB-2 filed on March 21, 2006). | |
| 3.1.2 | Certificate of Amendment of Certificate of Incorporation of the Registrant, filed June 6, 2005 (incorporated by reference from the Registrant’s registration statement on Form SB-2 filed on March 21, 2006). | |
| 3.1.3 | Certificate of Amendment of Certificate of Incorporation of the Registrant, filed July 18, 2007 (incorporated by reference from the Registrant’s quarterly report on Form 10-QSB filed on August 14, 2007). | |
| 3.1.4 | Certificate of Ownership and Merger Merging Magnum Hunter Resources Corporation with and into Petro Resources Corporation, filed July 13, 2009 (incorporated by reference from the Registrant’s current report on Form 8-K filed on July 14, 2009). | |
| 3.1.5 | Certificate of Amendment of Certificate of Incorporation of the Registrant, filed November 3, 2010 (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 2, 2010). | |
| 3.1.6 | Certificate of Amendment of Certificate of Incorporation of the Registrant, filed May 9, 2011 (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on March 31, 2011). | |
| 3.1.7 | Certificate of Amendment of Certificate of Incorporation of the Registrant, filed June 29, 2011 (incorporated by reference from the Registrants registration statement on Form S-4 filed on January 14, 2013). | |
| 3.1.8 | Certificate of Amendment of Certificate of Incorporation of the Registrant, filed January 25, 2013 (incorporated by reference from Amendment No. 1 to the Registrant’s registration statement on Form S-4 filed on February 5, 2013). | |
| 3.2 | Amended and Restated Bylaws of the Registrant, dated March 15, 2001 as amended on April 14, 2006, and May 26, 2011 (incorporated by reference from the Registrant's quarterly report on Form 10-Q filed on August 9, 2011). | |
| 4.1 | Form of certificate for common stock (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 18, 2011). | |
| 4.2 | Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated December 10, 2009 (incorporated by reference from the Registrant’s registration statement on Form 8-A filed on December 10, 2009). | |
| 4.2.1 | Certificate of Amendment of Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated August 2, 2010 (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on August 12, 2010). | |
| 4.2.2 | Certificate of Amendment of Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated September 8, 2010 (incorporated by reference from the Registrant’s current report on Form 8-K filed on September 15, 2010). | |
| 4.3 | Certificate of Designation of Rights and Preferences of 8.0% Series D Cumulative Preferred Stock, dated March 16, 2011 (incorporated by reference from the Registrant’s current report on Form 8-K filed on March 17, 2011). | |
114
| 4.4 | Indenture, dated May 16, 2012, by and among the Registrant, the Guarantors named therein, Wilmington Trust, National Association and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 16, 2012). | |
| 4.4.1 | First Supplemental Indenture, dated October 18, 2012, by and among the Registrant, the Guarantors named therein, Wilmington Trust, National Association, as Trustee, and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent (incorporated by reference from the Registrant's registration statement on Form S-4 filed on January 14, 2013). | |
| 4.4.2 | Second Supplemental Indenture, dated December 13, 2012, by and among the Registrant, the Guarantors named therein, Wilmington Trust, National Association, as Trustee, and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent (incorporated by reference from the Registrant's registration statement on Form S-4 filed on January 14, 2013). | |
| 4.4.3 | Third Supplemental Indenture, dated April 24, 2013, by and among the Registrant, the Guarantors named therein, Wilmington Trust, National Association, as Trustee, and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent (incorporated by reference from the Registrant’s annual report on Form 10-K filed on June 14, 2013). | |
| 4.4.4 | Fourth Supplemental Indenture, dated July 23, 2013, by and among Shale Hunter, LLC, Wilmington Trust, National Association, as Trustee, and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on August 9, 2013). | |
| 4.4.5# | Fifth Supplemental Indenture, dated January 27, 2014, by and among the Registrant, Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent, and Wilmington Trust, National Association, as Trustee. | |
| 4.4.6# | Sixth Supplemental Indenture, dated November 10, 2014, by and among Bakken Hunter Canada, Inc., Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent, and Wilmington Trust, National Association, as Trustee. | |
| 4.4.7# | Seventh Supplemental Indenture, dated December 4, 2014, by and among Triad Holdings, LLC, Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent, and Wilmington Trust, National Association, as Trustee. | |
| 4.5 | Certificate of Designations of Rights and Preferences of the 8.0% Series E Cumulative Convertible Preferred Stock of the Registrant, dated November 2, 2012 (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 8, 2012). | |
| 4.6 | Deposit Agreement, dated as of November 2, 2012, by and among the Registrant, American Stock Transfer & Trust Company, as Depositary, and the holders from time to time of the depositary receipts described therein (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 8, 2012). | |
| 10.1* | Amended and Restated Stock Incentive Plan of Registrant (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 3, 2010). | |
| 10.1.1* | First Amendment to Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s proxy statement on Annex C of Schedule 14A filed on April 1, 2011). | |
| 10.1.2 | Second Amendment to the Magnum Hunter Resources Corporation Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s registration statement on Form S-8 filed on February 14, 2013). | |
| 10.1.3* | Third Amendment to the Magnum Hunter Resources Corporation Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s current report on Form 8-K filed on January 23, 2013). | |
| 10.2* | Form of Stock Option Agreement under the Registrant’s Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 18, 2011). | |
| 10.3* | Form of Restricted Stock Award Agreement under the Registrant’s Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 3, 2010). | |
| 10.4* | Form of Stock Appreciation Right Agreement under the Registrant’s Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 3, 2010). | |
115
| 10.5* | Form of Executive Change of Control Retention Agreements (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 29, 2012). | |
| 10.5.1* | Amendment to Form of Executive Change of Control Retention Agreements (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 29, 2012). | |
| 10.6* | Form of Indemnification Agreement for Directors (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on June 7, 2013). | |
| 10.7* | Form of Indemnification Agreement for Officers (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on June 7, 2013). | |
| 10.8 | Omnibus Settlement Agreement and Release, dated as of January 9, 2014, by and among the Registrant, Magnum Hunter Production, Inc., Eureka Hunter Pipeline, LLC, Seminole Energy Services, L.L.C., Seminole Gas Company, L.L.C., Seminole Murphy Liquids Terminal, L.L.C., NGAS Gathering II, LLC, and NGAS Gathering, LLC (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on January 14, 2014). | |
| 10.9 | Securities Purchase Agreement, dated as of March 20, 2014, by and among the Registrant and investors party thereto (incorporated by reference from the Registrant’s registration statement on Form S-1 filed on March 31, 2014). | |
| 10.10 | Registration Rights Agreement, dated as of March 20, 2014, by and among the Registrant and investors party thereto (incorporated by reference from the Registrant’s registration statement on Form S-1 filed on March 31, 2014). | |
| 10.11 | Credit Agreement, dated March 28, 2014, by and among Eureka Hunter Pipeline, LLC, as borrower, ABN AMRO Capital USA, LLC, as lender and administrative agent, and the other lenders party thereto (incorporated by reference from the Registrant’s Quarterly Report on Form 10-Q filed on May 9, 2014). | |
| 10.11.1 | First Amendment to Credit Agreement, dated as of November 19, 2014, by and among Eureka Hunter Pipeline, LLC, ABN AMRO Capital USA, LLC, as administrative agent, and the lenders party thereto (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on November 24, 2014). | |
| 10.12* | Eureka Hunter Holdings, LLC Management Incentive Compensation Plan (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on May 16, 2014). | |
| 10.12.1* | Form of Eureka Hunter Holdings, LLC Equity Incentive Plan Award Letter (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on May 16, 2014). | |
| 10.12.2* | Form of Eureka Hunter Holdings, LLC Class B Common Unit Agreement (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on May 16, 2014). | |
| 10.13 | Securities Purchase Agreement, dated as of May 27, 2014, by and among the Registrant and investors party thereto (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on May 30, 2014). | |
| 10.14 | Registration Rights Agreement, dated as of May 27, 2014, by and among the Registrant and investors party thereto (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on May 30, 2014). | |
| 10.15 | Form of Warrant to Purchase Shares of Common Stock of the Registrant (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on May 30, 2014). | |
| 10.16@ | Second Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings, LLC, dated October 3, 2014, by and among Eureka Hunter Holdings, LLC, the Registrant, MSIP II Buffalo Holdings, LLC, and certain other limited liability company members (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on October 9, 2014). | |
| 10.17 | Fourth Amended and Restated Credit Agreement, dated October 22, 2014, by and among the Registrant, Bank of Montreal, the lenders party thereto and the agents party thereto (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on October 28, 2014). | |
| 10.17.1# | First Amendment to Credit Agreement and Limited Waiver, dated February 24, 2015, by and among the Registrant, the guarantors party thereto, the lenders party thereto and Bank of Montreal. | |
116
| 10.18 | Second Lien Credit Agreement, dated October 22, 2014, by and among the Registrant, Credit Suisse AG, Cayman Islands Branch, the lenders party thereto and the agents party thereto (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on October 28, 2014). | |
| 10.19*# | Letter Agreement, dated January 29, 2015, by and between the Registrant and R. Glenn Dawson. | |
| 10.20# | Release and Confidentiality Agreement, dated January 29, 2015, by and between the Registrant and R. Glenn Dawson. | |
| 12.1# | Computation of Ratio of Earnings to Fixed Charges. | |
| 21.1# | List of Subsidiaries. | |
| 23.1# | Consent of BDO USA, LLP. | |
| 23.2# | Consent of Cawley Gillespie & Associates, Inc. | |
| 31.1# | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 31.2# | Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 32.1^ | Certification of the Chief Executive Officer and Chief Financial Officer provided pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| 99.1# | Independent Engineer Reserve Report for the year ended December 31, 2014 prepared by Cawley Gillespie & Associates, Inc. | |
| 101.INS# | XBRL Instance Document. | |
| 101.SCH# | XBRL Taxonomy Extension Schema Document. | |
| 101.CAL# | XBRL Taxonomy Extension Calculation Linkbase Document. | |
| 101.LAB# | XBRL Taxonomy Extension Label Linkbase Document. | |
| 101.PRE# | XBRL Taxonomy Extension Presentation Linkbase Document. | |
| 101.DEF# | XBRL Taxonomy Extension Definition Presentation Linkbase Document. | |
| * | The referenced exhibit is a management contract, compensatory plan or arrangement. | |
| + | 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. | |
| ^ | This exhibit is furnished herewith and shall not be deemed filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act. | |
117