10-K 1 mhr-20151231x10xk.htm 10-K 10-K
 
 
 
 
 
UNITED STATES
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, 2015
Commission file number: 001-32997
____________________________________
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.)
909 Lake Carolyn Parkway, Suite 600, Irving, Texas 75039
(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
OTC Marketplace
OTC Marketplace
OTC Marketplace
OTC Marketplace
Securities registered under Section 12(g) of the Act:
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.                                                     x
            
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
¨
 
Accelerated filer
x
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: $385,477,813
As of April 29, 2016, 260,563,308 shares of the registrant’s common stock were issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None.
 
 
 
 
 





        


MAGNUM HUNTER RESOURCES CORPORATION
2015 Annual Report on Form 10-K

Table of Contents
 
 
Page
 
 
 
 
 
Item 1.
 
 
 
Item 1A.
 
 
 
Item 1B.
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
Item 5.
 
 
 
Item 6.
 
 
 
Item 7.
 
 
 
Item 7A.
 
 
 
Item 8.
F-1
 
 
 
Item 9.
 
 
 
Item 9A.
 
 
 
Item 9B.
 
 
 
Item 10.
 
 
 
Item 11.
 
 
 
Item 12.
 
 
 
Item 13.
 
 
 
Item 14.
 
 
 
Item 15.




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, 2015, 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 two 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 primarily non-operated oil and gas properties in the Williston Basin/Bakken Shale in Divide County, North Dakota and operated natural gas properties in Kentucky. Through our substantial equity investment in Eureka Midstream Holdings, LLC, formerly known as Eureka Hunter Holdings, LLC (“Eureka Midstream Holdings”), of which Eureka Midstream, LLC, formerly known as Eureka Hunter Pipeline, LLC (“Eureka Midstream”) 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 both for our Appalachian Basin drilling operations as well as to provide drilling services to third parties.

Chapter 11 Bankruptcy Filings

On December 15, 2015 (the “Petition Date”), Magnum Hunter Resources Corporation and certain of its wholly owned subsidiaries, namely, Alpha Hunter Drilling, LLC, Bakken Hunter Canada, Inc., Bakken Hunter, LLC, Energy Hunter Securities, Inc. (“Energy Hunter Securities”), Hunter Aviation, LLC, Hunter Real Estate, LLC, Magnum Hunter Marketing, LLC, Magnum Hunter Production, Inc. (“MHP”), Magnum Hunter Resources GP, LLC, Magnum Hunter Resources, LP, Magnum Hunter Services, LLC, NGAS Gathering, LLC, NGAS Hunter, LLC, PRC Williston LLC (“PRC Williston”), Shale Hunter, LLC, Triad Holdings, LLC, Triad Hunter, LLC, Viking International Resources Co., Inc., and Williston Hunter ND, LLC (collectively, the “Filing Subsidiaries” and, together with the Company, the “Debtors”), filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Chapter 11 cases (the “Chapter 11 Cases”) were jointly administered by the Bankruptcy Court under the caption In re Magnum Hunter Resources Corporation, et al., Case No. 15-12533.

Our subsidiaries and affiliates excluded from the filing include wholly owned subsidiaries Magnum Hunter Management, LLC, Sentra Corporation, 54NG, LLC, and our 44.53% owned affiliate, Eureka Midstream Holdings (collectively, the “Non-Debtors”).

On April 18, 2016, the Bankruptcy Court approved our Chapter 11 plan of reorganization (the “Plan”), which, among other things, resolved the Debtors’ pre-petition obligations, set forth the revised capital structure of the newly reorganized entity, and provided for corporate governance subsequent to exit from bankruptcy. The effective date of the Plan is expected to be May 6, 2016 (the “Effective Date”).

Prior to filing the Chapter 11 Cases, on December 15, 2015, the Company and the other Debtors entered into a Restructuring Support Agreement (as amended, the “RSA”) with the following parties:

•
Substantially all of the Second Lien Lenders and Noteholders (each as defined herein) party to the Senior Secured Bridge Financing Facility (as defined in “Note 11 - Long-Term Debt”);

•
Lenders holding approximately 66.5% in principal amount outstanding under the Second Lien Term Loan Agreement (as described in “Note 11 - Long-Term Debt”) (the “Second Lien Lenders”); and

•
Holders, in the aggregate, of approximately 79.0% in principal amount outstanding of our unsecured 9.750% Senior Notes due 2020 (the “Senior Notes”) (collectively, the “Noteholders”).


5


The agreed terms of the restructuring of the Debtors, as contemplated in the RSA, were memorialized in the Plan and include the following key elements:

•
Substantial Deleveraging of Balance Sheet. Our funded debt is expected to be restructured as follows:
◦
The Senior Secured Bridge Financing Facility was repaid in full from the proceeds of the debtor-in-possession financing facility (the “DIP Facility”) upon entry of an order by the Bankruptcy Court on January 11, 2016 approving, on a final basis, the debtor-in-possession financing.
◦
On the Effective Date, the Second Lien Term Loan is expected to be converted into new common equity of the reorganized Company, receiving 36.87% of the new common equity.
◦
On the Effective Date, the Senior Notes are expected to be converted into new common equity of the reorganized Company, receiving 31.33% of the new common equity.
◦
On the Effective Date, the DIP Facility is expected to be converted into 28.80% of the new common equity.
◦
Our general unsecured claims are projected to receive a blended recovery as specified in the RSA and the Plan, to be paid in cash, through a combination of payments to be made pursuant to Bankruptcy Court orders (lien claimant motion, taxes, etc.) and a cash pool of approximately $23.0 million included in the Plan. Holders of certain of our general unsecured claims elected to receive new common equity instead of cash, which is expected to dilute the new common equity issued to the holders of the Senior Notes and the lenders of the Second Lien Term Loan as described in the Plan.
◦
Holders of our preferred stock and common equity are expected to receive no recovery under the RSA and the Plan.
◦
The Other Secured Debt (as defined in the RSA and the Plan) is expected to be reinstated.

•
DIP Facility: A $200 million multi-draw DIP Facility entered into with certain Second Lien Lenders and Noteholders.

•
Business Plan: A business plan (the “Business Plan”) was developed jointly with the Debtors, the Second Lien Lenders that have backstopped the DIP Facility (the “Second Lien Backstoppers”) and the Noteholders that have backstopped the DIP Facility (the “Noteholder Backstoppers,” and together with the Second Lien Backstoppers, the “Backstoppers”).

•
Valuation for Settlement Purposes: For settlement purposes only, the Plan reflects a total enterprise value of the Company of $900 million. Such settlement value is not indicative of any party’s views regarding total enterprise value, but rather is a settled value for the purpose of determining equity splits and conversion rates for the various claimants.

•
Eureka Midstream Holdings: The Debtors restructured certain key agreements between Eureka Midstream Holdings and its subsidiaries, on the one hand, and the Debtors, on the other, with the consent of the Backstoppers.

•
Reorganized Company Status: The reorganized Company is expected to be a private company upon emergence from the Chapter 11 Cases and is expected to seek public listing of its new common equity when market conditions warrant and as determined by the New Board (as defined below) as informed by input from the Backstoppers.

•
Releases: The Plan provided for release, exculpation, and injunction provisions, including customary carve-outs, to the fullest extent permitted by applicable law and consistent with the terms of the RSA, and the Backstoppers have agreed not to “opt-out” of the consensual “third-party” releases granted to, among others, the Debtors’ current and former directors and officers.

•
Incentive Plans: The new board of directors of the reorganized Company is authorized to adopt management incentive programs to be paid exclusively with the funds of the reorganized Company. The management incentive plan will not give rise to any claims against the debtors or their estates.

•
Governance: The reorganized Company has a seven-person board of directors (the “New Board”), consisting of (i) the Chief Executive Officer, (ii) two directors selected by the Noteholder Backstoppers, (iii) two directors selected by the Second Lien Backstoppers, (iv) one director jointly selected by the Noteholder Backstoppers and the Second Lien Backstoppers, who serves as the non-executive chairman, and (v) one director selected by the Noteholder Backstoppers, based upon a slate of three candidates jointly determined by the Noteholder Backstoppers and the Second Lien Backstoppers. Members of the current management team of the Debtors have remained in place during the pendency of the Chapter 11 Cases and are expected to remain in place until the Company’s emergence from bankruptcy; however, on May 6, 2016,

6


Mr. Evans tendered his voluntary resignation as our Chief Executive Officer and Chairman of the Board of Directors, which resignation is expected to be effective following the filing of this Annual Report on Form 10-K.

Additionally, on the Effective Date the Debtors expect to enter into an exit financing facility.

Under the Bankruptcy Code, debtors have the right to assume or reject certain contracts, subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the assumption of a contract requires a debtor to satisfy pre-petition obligations under the contract, which may include payment of pre-petition liabilities in whole or in part. Rejection of a contract is typically treated as a breach occurring as of the moment immediately preceding the Chapter 11 filing. Subject to certain exceptions, this rejection relieves the debtor from performing its future obligations under the contract but entitles the counterparty to assert a pre-petition general unsecured claim for damages. Parties to contracts rejected by a debtor may file proofs of claim against that debtor’s estate for damages.

On January 7, 2016, the Debtors filed a motion seeking entry of an order establishing procedures for the assumption or rejection of contracts pursuant to section 365 of the Bankruptcy Code (the “Contract Procedures Motion”). The court entered an order approving the Contract Procedures Motion on February 26, 2016. On March 14, 2016, the Debtors filed the plan supplement, which included a schedule of assumed contracts and a schedule of rejected contracts, and since then have filed two amended plan supplements and additional motions with respect to assumed and rejected contracts. Through the contract assumption and rejection process, the Debtors were able to successfully renegotiate approximately a dozen midstream and downstream contracts.

The Debtors continue to review and analyze their contractual obligations and retain the right, until eight days following the Effective Date, to move contracts from the schedule of assumed contracts to the schedule of rejected contracts or from the schedule of rejected contracts to the schedule of assumed contracts.

Business Strategy

Key elements of our business strategy include:

Focus on Liquids Rich Marcellus and Dry Gas Utica Reserves

As a result of our divestitures throughout the past three 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 December 31, 2015, we had a total of approximately 214,884 gross acres (197,903 net acres) in our Marcellus Shale and Utica Shale asset base.

Utilize Expertise in Unconventional Resource Plays

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. Improved drilling and completion techniques have resulted in substantially better initial production rates, or IP rates, and estimated ultimate recoveries. Additionally, our focus on the 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.

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 December 31, 2015, we were the operator on leasehold acreage accounting for approximately 80% of our year-end 2015 proved reserves, and we were operating approximately 83% of our producing wells.

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 three years we have monetized assets no longer considered core through divestitures.


7


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 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.

In 2015, we sold ownership interests in approximately 5,210 net undeveloped and unproven leasehold acres located in Tyler County, West Virginia for $37.8 million in cash.

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.

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 moved the responsibilities of the former personnel at those now-closed offices to existing personnel at our corporate headquarters. During 2015 we relocated our corporate headquarters, including our finance, treasury, and reserve engineering departments, from Houston, Texas, to Irving, Texas. We also consolidated our accounting, financial reporting, information systems, legal and human resources departments formerly located in Grapevine, Texas, to the new corporate headquarters. We have continued to reduce our reliance on outside consultants and to seek better pricing and other terms from our suppliers of oil and gas field products and services.

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 large portfolio of properties and drilling opportunities in our natural gas and natural gas liquids operating regions presents us with substantial growth opportunities. As of December 31, 2015, approximately 91.4% and 90.5% of our proved reserves and proved developed producing reserves, respectively, were natural gas and natural gas liquids. As of December 31, 2015, we held ownership interests in (i) approximately 1,983 gross (1,909.8 net) wells in West Virginia and Ohio, (ii) approximately 166 gross (56.5 net) wells in North Dakota and (iii) approximately 1,401 gross (600.4 net) wells in the southern Appalachian Basin.

Operational Control over Significant Portion of Assets

We operate a significant portion of our assets (approximately 83% of our producing wells as of December 31, 2015). Consequently, we have substantial control over the timing, allocation and amount of a significant portion of our future upstream capital expenditures, which allows us the flexibility to reallocate these expenditures depending on commodity prices, rates of return and prevailing industry conditions.

Access to the Eureka Midstream Gas Gathering System

Our substantial equity investment in Eureka Midstream 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 Midstream Gas Gathering System supports the development of our existing and anticipated future Marcellus Shale and Utica Shale acreage positions.


8


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, 2015, we had approximately 239,051 MMcfe of estimated proved reserves, of which approximately 91% was natural gas and natural gas liquids and approximately 89% was classified as proved developed producing reserves. By comparison, as of December 31, 2014 our estimated proved reserves were approximately 502,547 MMcfe, of which approximately 87% was natural gas and natural gas liquids and approximately 66% was classified as proved developed producing reserves. Our estimated proved reserves at year-end 2015 decreased 52% from year-end 2014, on an Mcfe basis. The decrease in proved reserves relates to downward revisions due to additional information gathered from continued production, lower pricing levels, and liquidity constraints.
ii.
As of December 31, 2015, we had proved reserves with a PV-10 value of $110.6 million. This compares with proved reserves with a PV-10 value of $909.3 million as of December 31, 2014. The PV-10 value of our estimated proved reserves at year-end 2015 decreased approximately 87.8% from year-end 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 $1,031 million and other future expected tax deductions, the standardized measure of our proved reserves at December 31, 2015 of $110.6 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, 2015 were 134,025 Mcfe/d, which represented an increase of 32.7% from the year ended December 31, 2014.
iv.
As of December 31, 2015, we had approximately 74,054 net leasehold acres in the Marcellus Shale and approximately 123,849 net leasehold acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage).
Reserve Summary
 
At December 31, 2015
 
Proved
Reserves(1)
 
PV-10 (2)(3) 
 
% 
Proved Developed 
 
%
Natural Gas / NGLs
 
 
 
 
 
Productive Wells
Area 
(MMcfe)
 
(in millions)
 
Gross
 
Net
Appalachian Basin (4)
221,683

 
$
85.5

 
89%
 
97%
 
3,384

 
2,510.2

Williston Basin
17,368

 
$
25.1

 
100%
 
15%
 
166

 
56.5

Other (5)
—

 
—

 
—
 
—
 
3

 
1.2

Total at December 31, 2015
239,051

 
$
110.6

 
89%
 
91%
 
3,553

 
2,567.9

________________________________    
(1) 
MMcfe is defined as one million cubic feet 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 2015, using $50.28 per barrel of oil and $2.59 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 us in the future.
(3) 
The standardized measure of our proved reserves at December 31, 2015 was $110.6 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.


9


2016 Capital Expenditure Budget

Our upstream capital expenditure budget for fiscal year 2016 has not yet been approved by the New Board. We consider various factors when determining our budget, including 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 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 expect that our 2016 upstream capital expenditure budget will be funded primarily from borrowings under our exit financing facility, as well as internally-generated cash flows. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this annual report for a description of our liquidity and capital resources.

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 December 31, 2015, we had a total of approximately 74,054 net leasehold acres in the Marcellus Shale and approximately 123,849 net leasehold acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage). As of December 31, 2015, we had approximately 3,384 gross (2,510.2 net) wells producing on our Appalachian Basin Properties, of which we operated 2,943 wells, or approximately 87%.

As of December 31, 2015, proved reserves attributable to our Appalachian Basin properties were 221,683 MMcfe, of which 88% were classified as proved developed producing. As of December 31, 2015, total proved reserves attributable to our Appalachian Basin properties had a PV-10 value of $85.5 million.

Marcellus Shale Properties

As of December 31, 2015, we had a total of approximately 74,054 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 December 31, 2015, approximately 80% of our mineral leases in the Marcellus Shale area were held by production.

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 Midstream Gas Gathering System. As of December 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 Midstream Gas Gathering System. As of December 31, 2015, we had drilled one Marcellus Shale well and four Utica Shale wells pursuant to this joint development program.


10


Utica Shale Properties

As of December 31, 2015, we had a total of approximately 123,849 net leasehold acres prospective for the Utica Shale. Approximately 92,138 of the net acres are located in Ohio (a portion of which acreage overlaps our Marcellus Shale acreage), and approximately 31,711 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. Approximately 54% of our acreage in the Utica Shale is held by shallow production.

Marcellus Shale and Utica Shale Drilling in 2015

The following table contains certain information regarding our Marcellus Shale and Utica Shale horizontal wells drilled or completed in 2015.
 
 
 
 
MHR Working
 
First
 
Horizontal Lateral
 
# of Frac
Well Name
 
County
 
Interest
 
Production
 
Length (feet)
 
Stages
Operated
 
 
 
 
 
 
 
 
 
 
Stalder #6 UH
 
Monroe, OH
 
49%
 
2/22/2015
 
5,744
 
24
Stalder #7 UH
 
Monroe, OH
 
49%
 
2/17/2015
 
6,051
 
25
Stalder #8 UH
 
Monroe, OH
 
49%
 
2/12/2015
 
6,226
 
26

The Stalder #2MH and the Stalder #3UH, which were drilled and completed during 2014, were being tested as of December 31, 2014 and were subsequently shut in for the preparation of drilling the Stalder #6UH, the Stalder #7UH, and the Stalder #8UH during 2015. These two wells began producing during December 2015.

Southern Appalachian Basin Properties

Our southern Appalachian Basin properties are owned by our subsidiary, MHP. As of December 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. As of December 31, 2015, we had 1,401 gross (600.4 net) wells producing in the southern Appalachian Basin.

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.

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. 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. In connection with the Chapter 11 Cases, we agreed to assume our agreements with Continuum Energy, subject to certain agreed upon amendments. These amendments will, among other things, provide us with lower gas gathering rates, gas processing rates and liquids processing rates. In addition, we will continue to operate these gathering facilities.

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 and all of our oil and gas properties in Alberta and Saskatchewan, Canada.


11


As of December 31, 2015, we had a total of approximately 51,957 net leasehold acres remaining that are prospective for the Bakken/Three Forks Sanish formations in Divide County, North Dakota. As of December 31, 2015, we had approximately 166 gross (56.5 net) wells producing on our Williston Basin Properties, of which we operated eight wells. Proved reserves attributable to our Williston Basin Properties were 17,368 MMcfe as of December 31, 2015, all of which were classified as proved developed producing. These proved reserves had a PV-10 value of $25.1 million as of December 31, 2015.

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 purchased our natural gas and natural gas liquids production from the dedicated properties, and we were 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 allowed us to realize revenues from our natural gas stream in the Divide County area. On April 14, 2016, the Bankruptcy Court entered an order approving a motion to reject the gas purchase agreement with Oneok. We anticipate that our natural gas and natural gas production from the dedicated properties will continue to be sold by the operator of these dedicated properties pursuant to the operator’s separate gas purchase agreement with Oneok.

Our Williston Basin properties are supported by infrastructure that includes 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.

We did not participate in the drilling of any new wells on our Williston Basin Properties during 2015. During 2016, 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 to us a positive rate of return during a lower commodity price environment.

Other Upstream Properties

We own certain other scattered miscellaneous oil and gas properties in Texas and Louisiana. We do not expect to allocate any capital to these assets for 2016.

Midstream Operations

We have a substantial equity investment in Eureka Midstream 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 Midstream, a wholly owned subsidiary of Eureka Midstream Holdings, owns and operates the Eureka Midstream Gas Gathering System in West Virginia and Ohio. TransTex, LLC, formerly known as TransTex Hunter, LLC (“TransTex”), a wholly owned subsidiary of Eureka Midstream Holdings, provides natural gas treating and processing services.

Eureka Midstream Gas Gathering System

We acquired assets in 2010 that included gas gathering systems and pipeline rights-of-way in West Virginia and Ohio. Eureka Midstream Holdings (and its predecessor) have developed, and Eureka Midstream Holdings continues to develop, these assets into the Eureka Midstream 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 Eureka Midstream Gas Gathering System is being constructed primarily out of 20-inch and 16-inch high-pressure steel pipe. The first completed six-mile section of the Eureka Midstream Gas Gathering System was turned to sales in December 2010.

The Eureka Midstream 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 Midstream has continued to construct additional sections of the pipeline in West Virginia and Ohio, allowing for the gathering of production from multiple well pads including our Ormet and Stalder pads. We expect that the development of the Eureka Midstream 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.


12


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. TransTex owns 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.
 
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 December 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.

At December 31, 2015, two of our Schramm T200XD drilling rigs remained under term contracts to a third party in the Appalachian Basin area for the top-hole drilling of multiple wells. Three of our Schramm T200XD drilling rigs are currently stacked due to the downturn in the industry. Our Schramm T500XD drilling rig, which was under contract to one of our subsidiaries for our Marcellus Shale and Utica Shale drilling program, is currently stacked due to our suspension of all drilling and completion activity.

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.

We generally market our oil and natural gas production under “month-to-month” or “spot” contracts.

Marketing of Production

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) produced in Ohio and West Virginia that are 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.


13


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.

Pricing

Our revenues, cash flows, profitability and future rate of growth depend substantially upon prevailing prices for oil and natural gas, which declined dramatically during the third and fourth quarters of 2014 and remained low throughout 2015 and into 2016. 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 have historically used 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 have entered into futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts. 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.

14



We had no remaining open commodity derivatives as of December 31, 2015. On May 7, 2015, we obtained consent under the MHR Senior Revolving Credit Facility to terminate our open commodity derivative positions. We received approximately $11.8 million in cash proceeds from the termination of the majority of our open commodity derivative positions that were terminated on May 7, 2015. On November 2, 2015, we terminated our open commodity derivative positions with Bank of Montreal and received approximately $0.9 million in cash proceeds. On December 31, 2015, our commodity derivative positions with Citibank, N.A. expired.
 
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. Similarly to the NGAS drilling partnerships, these two drilling partnerships participate 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.

All drilling partnerships and programs dissolved when MHP filed for bankruptcy on December 15, 2015. MHP intends to liquidate and wind up the drilling partnerships and programs, in accordance with the agreements governing each, as quickly as reasonably practicable.

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, 2015. These estimates were determined based on prices for the twelve-month period ended December 31, 2015, and lease operating expenses as of July 31, 2015. Since January 1, 2015, 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.


15


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, 2015.
 
Proved Reserves (SEC Prices at December 31, 2015)
Category 
Oil
 
NGLs
 
Gas
 
PV-10 (1)
 
(MBbl)
 
(MBbl)
 
(MMcf)
 
(in thousands)
Proved Developed
3,430

 
6,181

 
156,076

 
$
105,296

Proved Undeveloped
—

 
—

 
25,309

 
$
5,293

Total Proved
3,430

 
6,181

 
181,385

 
$
110,589

_______________
(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 2015, using $50.28 per barrel of oil and $2.59 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, 2015 in conjunction with the following reserve estimates.

16


The following table sets forth our estimated proved reserves at the end of each of the past three years:
 
2015
 
2014
 
2013
Description
 
 
 
 
 
Proved Developed Reserves
 
 
 
 
 
Oil (MBbl)
3,430
 
6,938
 
12,085
NGLs (MBbl)
6,181
 
10,587
 
6,989
Natural Gas (MMcf)
156,076
 
251,628
 
176,585
Proved Undeveloped Reserves
 
 
 
 
 
         Oil (MBbl)
—

 
3,583
 
12,250
         NGLs (MBbl)
—

 
3,816
 
3,432
         Natural Gas (MMcf)
25,309
 
101,373
 
70,197
 
 
 
 
 
 
Total Proved Reserves (MMcfe)(1)(2)   
239,051
 
502,547
 
455,318
 
 
 
 
 
 
PV-10 Value (in millions)(3)  
$
110.6

 
$
909.3

 
$
922.1

Standardized Measure (in millions)
$
110.6

 
$
909.3

 
$
844.5

_______________
(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) 
MMcfe is defined as one million cubic feet equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
(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 2015 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 2015, using $50.28 per barrel of oil and $2.59 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, 2015, our proved undeveloped reserves, or PUDs, on an SEC case basis totaled 25.3 Bcf of natural gas. Decreases in PUDs were due to the revision of previous estimates of reserves resulting primarily from downward fluctuating prices during the year. We expect to develop all of our proved undeveloped reserves as of December 31, 2015 within five years of their initial booking.

The following table summarizes the changes in our proved undeveloped reserves for the year ended December 31, 2015:

Proved Undeveloped Reserves (Mmcfe)
For the Year  Ended 
December 31, 2015
Proved undeveloped reserves—beginning of year
145,766

Revisions of previous estimates
(145,766
)
Extensions and discoveries
25,309

Proved undeveloped reserves—end of year
25,309



17


The following table summarizes the changes in our proved reserves for the year ended December 31, 2015:
Proved Reserves (Mmcfe)
For the Year  Ended 
December 31, 2015
Proved reserves—beginning of year
502,548

Revisions of previous estimates
(240,354
)
Extensions and discoveries
25,309

Production
(48,452
)
Proved reserves—end of year
239,051

Proved developed reserves—beginning of year
356,778

Proved developed reserves—end of year
213,742


Downward revisions to proved reserves resulted from additional information gathered from continued production, lower pricing levels, and liquidity constraints. Extensions and discoveries were related to activity in our Marcellus Shale and Utica Shale development program which included the wells completed on the Stalder 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.
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, 2015. 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.


18


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. Hershal C. Ferguson, III, who serves as the Chairman of our Reserves Committee for the board of directors in addition to being our Executive Vice President of Exploration, and Mr. Keith Yankowsky, our Chief Operating Officer. Together with Mrs. Dana Haynes and Mr. Kurt Wielitzka, these individuals make up the Reserves Group that manages our reserve process. 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. Mr. Yankowsky has substantial experience overseeing a variety of engineering and operational functions specifically related to horizontal drilling and fracture stimulation techniques within the Marcellus and Utica Shale plays. Mr. Yankowsky earned a Bachelor of Science degree in Petroleum Engineering from Marietta College, Marietta, Ohio. Mr. Kurt Wielitzka is the Assistant Vice President of Reservoir and Production. Mr. Wielitzka is a graduate of Marietta College where he recieved a Bachelor of Science degree in petroleum engineering. Mrs. Dana Haynes is the Manager of Reservoir Engineering, a petroleum engineer and a member of the Society of Petroleum Engineers. She is a graduate of Texas A&M University, College Station, Texas. Reserve estimates for each of our divisions are also reviewed and approved by the president of each 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 December 31, 2015:
 
Developed 
Acreage(1) 
 
Undeveloped 
Acreage(2) 
 
Total Acreage
 
Gross 
 
Net 
 
Gross 
 
Net 
 
Gross 
 
Net
Appalachian Basin (3)
264,439
 
180,149
 
282,737
 
240,107
 
547,176
 
420,256
Williston Basin
96,480
 
38,901
 
21,545
 
13,056
 
118,025
 
51,957
Total at December 31, 2015
360,919
 
219,050
 
304,282
 
253,163
 
665,201
 
472,213
_______________
(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 49,248 gross acres and 44,630 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.            

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.



19


The following table sets forth the gross and net acres of undeveloped land subject to leases summarized in the preceding December 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
 
 
 
 
2016
 
2017
 
2018
 
2019
 
2020
 
2021
 
Gross
Net
 
Gross
Net
 
Gross
Net
 
Gross
Net
 
Gross
Net
 
Gross
Net
Appalachian Basin (1)
83,450

70,469

 
4,530

3,882

 
29,573

28,354

 
50,000

41,233

 
622

328

 
104

45

Williston Basin
12,563

5,842

 
6,846

5,443

 
2,137

1,771

 
—

—

 
—

—

 
—

—

Other (2)
512

351

 
—

—

 
—

—

 
—

—

 
—

—

 
—

—

 
96,525

76,662

 
11,376

9,325

 
31,710

30,125

 
50,000

41,233

 
622

328

 
104

45

_______________
(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.

We periodically assess our unproved oil and gas leasehold costs for impairment, by considering current quotes and recent acquisitions, future lease expirations, and our intent and ability to drill. We recognize a loss at the time of impairment by providing an impairment allowance in “Exploration” expense in our consolidated statements of operations. We recognized $59.8 million of leasehold impairments during the year ended December 31, 2015.

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 our properties as of December 31, 2015:
 
Producing 
Oil Wells
 
Producing 
Gas Wells
 
Total Producing 
Wells
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Appalachian Basin (1)
716

 
634.4

 
2,668

 
1,875.8

 
3,384

 
2,510.2

Williston Basin
166

 
56.5

 
—

 
—

 
166

 
56.5

Other (2)
—

 
—

 
3

 
1.2

 
3

 
1.2

Total
882

 
690.9

 
2,671

 
1,877.0

 
3,553

 
2,567.9

_______________
(1) 
Includes wells associated with our southern Appalachian Basin properties located in Kentucky.
(2) 
Pertains to certain miscellaneous properties in Texas and Louisiana.
 

20


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.
 
2015
 
2014
 
2013
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory Wells:
 
 
 
 
 
 
 
 
 
 
 
Productive
—

 
—

 
17

 
9.3

 
15

 
4.1

Unproductive
—

 
—

 
—

 
—

 
—

 
—

Total Exploratory
—

 
—

 
17

 
9.3

 
15

 
4.1

Developmental Wells:
 
 
 
 
 
 
 
 
 
 
 
Productive
3

 
1.5

 
54

 
30.0

 
86

 
36.3

Unproductive
—

 
—

 
—

 
—

 
—

 
—

Total Development
3

 
1.5

 
54

 
30.0

 
86

 
36.3

Total wells
 
 
 
 
 
 
 
 
 
 
 
Productive
3

 
1.5

 
71

 
39.3

 
101

 
40.4

Unproductive
—

 
—

 
—

 
—

 
—

 
—

Total wells
3

 
1.5

 
71

 
39.3

 
101

 
40.4

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).


21


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.
 
 
2015
 
2014
 
2013
Post Rock
Oil Production (MBbl)
32

 
19

 
4

 
Natural Gas Production (MMcf)
12,288

 
7,048

 
4,442

 
NGLs Production (MBbl)
494

 
274

 
150

 
Total Production (MMcfe)
15,446

 
8,803

 
5,370

 
Oil Average Sales Price
$
16.15

 
$
70.96

 
$
83.84

 
Natural Gas Average Sales Price
$
1.85

 
$
3.92

 
$
3.98

 
NGLs Average Sales Price
$
17.92

 
$
50.17

 
$
50.39

 
Average Production Costs per Mcfe
$
0.42

 
$
0.44

 
$
0.56

 
Average Transportation, Processing, and Other Related Costs per Mcfe
$
1.64

 
$
2.05

 
$
1.72

Middlebourne Field
Oil Production (MBbl)
124

 
130

 
57

 
Natural Gas Production (MMcf)
14,379

 
8,762

 
4,052

 
NGLs Production (MBbl)
538

 
411

 
130

 
Total Production (MMcfe)
18,356

 
12,012

 
5,174

 
Oil Average Sales Price
$
18.94

 
$
76.88

 
$
82.64

 
Natural Gas Average Sales Price
$
1.88

 
$
4.27

 
$
4.22

 
NGLs Average Sales Price
$
17.15

 
$
51.44

 
$
50.89

 
Average Production Costs per Mcfe
$
0.24

 
$
0.34

 
$
0.33

 
Average Transportation, Processing, and Other Related Costs per Mcfe
$
1.02

 
$
1.22

 
$
1.14

Hannibal Field
Oil Production (MBbl)
41

 
69

 
4

 
Natural Gas Production (MMcf)
4,059

 
1,746

 
1

 
NGLs Production (MBbl)
57

 
88

 
—

 
Total Production (MMcfe)
4,648

 
2,685

 
26

 
Oil Average Sales Price
$
29.47

 
$
82.52

 
$
90.44

 
Natural Gas Average Sales Price
$
2.22

 
$
3.33

 
$
3.63

 
NGLs Average Sales Price
$
14.16

 
$
42.76

 
$
—

 
Average Production Costs per Mcfe
$
0.27

 
$
1.24

 
$
9.90

 
Average Transportation, Processing, and Other Related Costs per Mcfe
$
0.76

 
$
1.20

 
$
0.02

Total Company
Oil Production (MBbl)
1,094

 
1,570

 
1,641

 
Natural Gas Production (MMcf)
34,777

 
21,788

 
13,212

 
NGLs Production (MBbl)
1,263

 
960

 
438

 
Total Production (MMcfe)
48,919

 
36,968

 
25,686

 
Oil Average Sales Price
$
39.13

 
$
83.53

 
$
90.04

 
Natural Gas Average Sales Price
$
2.00

 
$
4.19

 
$
4.07

 
NGLs Average Sales Price
$
16.71

 
$
48.04

 
$
43.61

 
Average Production Costs per Mcfe
$
0.82

 
$
1.29

 
$
1.82

 
Average Transportation, Processing, and Other Related Costs per Mcfe
$
1.34

 
$
1.17

 
$
0.88


22


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;
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.


23


The standardized measure of discounted future net cash flows relating to our total proved oil and gas reserves as of December 31, 2015 is as follows:
 
As of
December 31, 2015 (unaudited)
 
(in thousands)
Future cash inflows
$
598,161

Future production costs
(369,478
)
Future development costs
(16,712
)
Future income tax expense
—

Future net cash flows
211,971

10% annual discount for estimated timing of cash flows
(101,382
)
Standardized measure of discounted future net cash
flows related to proved reserves
$
110,589

 
 
Reconciliation of Non-GAAP Measure
 
PV-10
$
110,589

Less income taxes:
 
Undiscounted future income taxes
—

10% discount factor
—

Future discounted income taxes
—

Standardized measure of discounted future net cash flows
$
110,589


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 $1,031 million and other future expected tax deductions, the standardized measure of our proved reserves at December 31, 2015 of $110.6 million was the same as our PV-10 value.

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.

24


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”) has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (the “SDWA”) 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 chemical substance and mixtures used in hydraulic fracturing. The public comment period on the EPA’s advance notice ended in September 2014, and a final notice of proposed rulemaking is expected in 2016. In addition, in April 2015, the EPA proposed regulations under the CWA to regulate wastewater discharges from hydraulic fracturing to publicly owned treatment works (the final rule is expected to be issued in 2016). In addition to rulemakings, increased scrutiny of the oil and natural gas industry may occur as a result of the EPA’s FY2014-2016 National Enforcement Initiative, “Ensuring Energy Extraction Activities Comply with Environmental Laws,” through which the EPA will address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environments.
 
The U.S. Bureau of Land Management (“BLM”) published a final rule in March 2015 governing hydraulic fracturing activities on federal and Indian lands that replaces a prior draft of proposed rulemaking issued by the agency in May 2012. The rule requires public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. However, a federal judge has granted a preliminary injunction preventing enforcement of the rules at this time.

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 commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater in 2011 and issued a draft assessment for public comment and peer review in June 2015; the assessment is expected to be finalized in 2016. The draft assessment concluded that hydraulic fracturing has not led to widespread, systemic impacts on drinking water resources, but it does have the potential to impact drinking water resources; however, this conclusion has recently been criticized by the EPA’s Science Advisory Board. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or 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 SDWA or other regulatory mechanisms.

Several states have implemented new 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 and in June 2015 the State of New York officially banned hydraulic fracturing for natural gas. At the local level, some municipalities have passed zoning ordinances that prohibit oil and gas development and hydraulic fracturing in particular. See “Item

25


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. In September 2015, the EPA proposed methane emission standards for new and modified oil and gas sources, which the EPA expects to finalize in June 2016. This proposed rule targets specific emission sources in the oil and gas sector and imposes distinct requirements for each type of source. Under the proposed rule, oil and gas companies will have to, among other things, limit emissions from new and modified pneumatic pumps, capture gas from the completion of fracked wells, find and repair leaks, and limit emissions from several types of equipment used at gas transmission compressor stations, including compressors and pneumatic controllers. On March 10, 2016, the EPA announced that it will commence drafting proposed methane emission standards for existing oil and gas sources, although the substance and timing of such regulation remains unclear. To aid in the efforts to reduce methane emissions from the oil and gas sector, in January 2016, the BLM also proposed rules to reduce methane emissions from venting, flaring and leaking on public lands.

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. In accordance with the Plan, our certificate of incorporation and bylaws are expected to be amended and restated in their entirety on the Effective Date.

Employees

As of December 31, 2015, we had approximately 348 full-time employees. None of our employees is represented by a union. Management considers our relations with employees to be very good.

Facilities

During 2015, we relocated our principal executive offices from Houston, Texas to our current location in Irving, Texas, where we lease approximately 18,500 square feet of commercial office space. Our lease expires on January 31, 2018.

As of December 31, 2015, we leased approximately 20,700 square feet of commercial office space in Houston, Texas, which formerly housed our corporate headquarters, including our finance, treasury, and reserve engineering departments. The lease with respect to approximately 9,300 and 5,400 square feet of this space would have expired in April 2016 and May 2019, respectively. On January 11, 2016, the Bankruptcy Court approved our motion to reject the Houston, Texas office lease.

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 formerly housed our principal accounting, financial reporting, information systems, and legal and human resources functions, which were relocated to the new corporate headquarters in Irving, Texas during 2015. On March 14, 2016, we filed a plan supplement with the Bankruptcy Court, which included a schedule of rejected contracts, in which we sought to reject the Grapevine, Texas office lease. Accordingly, on the Effective Date the Grapevine, Texas office lease is expected to be terminated.

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.

26



Segment Reporting; Major Customers

For information as to the geographic areas and industry segments in which we operate, namely Upstream, Midstream, 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 2015, 2014 and 2013, 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 909 Lake Carolyn Parkway, Suite 600, Irving, Texas 75039. 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.

27


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.
 
 

28


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.

29


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 filed voluntary petitions for relief under the Bankruptcy Code and are subject to the risks and uncertainties associated with bankruptcy cases.

On the Petition Date, we and certain of our wholly owned subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code. As a result, our business and operations are subject to various risks, including but not limited to the following: (i) incurring increased costs related to the Chapter 11 Cases and related litigation, (ii) a loss of, or a disruption in the materials or services received from, suppliers, contractors or service providers with whom we have commercial relationships, (iii) potential increased difficulty in retaining and motivating our key employees through the process of reorganization, and potential increased difficulty in attracting new employees, and (iv) the effects of significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring activities rather than focusing exclusively on business operations.

We are also subject to risks and uncertainties with respect to the actions and decisions of creditors and other third parties who have interests in our Chapter 11 Cases that may be inconsistent with our plans. These risks and uncertainties could affect our business and operations in various ways and may significantly increase the duration of the Chapter 11 Cases. Because of the risks and uncertainties associated with Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 Cases may have on our corporate or capital structure.    

We have substantial liquidity needs and may be required to seek additional financing. If we are unable to obtain financing on satisfactory terms or maintain adequate liquidity, our ability to replace our proved reserves or to maintain current production levels and generate revenue will be limited.

Our principal sources of liquidity historically have been equity contributions, borrowings under our credit facilities, net cash provided by operating activities, proceeds from sales of certain non-core assets, and net proceeds from the issuance of our senior notes. Our capital program will require additional financing above the level of cash generated by our operations to fund growth. If our cash flow from operations remains depressed or decreases as a result of lower commodity prices or otherwise, our ability to expend the capital necessary to replace our proved reserves, maintain our leasehold acreage or maintain current production may be limited, resulting in decreased production and proved reserves over time.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with preparation for and consummation of the Chapter 11 proceedings.

Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to maintain adequate cash on hand and (ii) our ability to generate cash flow from operations. Our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control. In the event that cash on hand and cash flow from operations is not sufficient to meet our liquidity needs, we may be required to seek additional financing. We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited if it is available at all. Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

Natural gas and oil prices declined dramatically in the third and fourth quarters of 2014 and remained low throughout 2015 and into 2016. 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. The speed and severity of the decline in oil and gas prices that began in 2014 and continued throughout 2015 and into 2016 has adversely affected our business, financial condition, and results of operations and contributed to our decision to file the Chapter 11 Cases.


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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 $34.73 per Bbl, in December 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 $1.53 per MMBtu in December 2015 to a high of $7.92 per MMBtu in March 2014. During 2015, NYMEX-WTI prices ranged from $34.73 to $61.43 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.53 to $3.29 per MMBtu.

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 has and may continue to result in substantial downward estimates of our proved reserves.

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;

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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.

We have significant exposure to fluctuations in commodity prices since none of our estimated future production is covered by commodity derivatives and we may not be able to enter into commodity derivatives covering our estimated future production on favorable terms or at all.

In the past, we have entered into financial commodity derivative contracts to mitigate the potential negative impact on cash flow caused by changes in oil and natural gas prices. However, we have no remaining open commodity derivative contracts as of December 31, 2015. Subsequent to the termination of these derivative contracts, we have not entered into additional derivative contracts. During the Chapter 11 proceedings, our ability to enter into new commodity derivatives covering additional estimated future production will be dependent upon either entering into unsecured hedges or obtaining Bankruptcy Court approval to enter into secured hedges. As a result, we may not be able to enter into additional commodity derivatives covering our production in future periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivatives in the future, we could be more affected by changes in commodity prices than our competitors who engage in hedging arrangements. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations.

If we are able to enter into any commodity derivatives, they may limit the benefit we would receive from increases in commodity prices. These arrangements would also expose us to risk of financial losses in some circumstances, including the following:

i.
our production could be materially less than expected; or
ii.
the counterparties to the contracts could fail to perform their contractual obligations.

If our actual production and sales for any period are less than the production covered by any commodity derivatives (including reduced production due to operational delays) or if we are unable to perform our exploration and development activities as planned, we might be required to satisfy a portion of our obligations under those commodity derivatives without the benefit of the cash flow from the sale of that production, which may materially impact our liquidity. Additionally, if market prices for our production exceed collar ceilings or swap prices, we would be required to make monthly cash payments, which could materially adversely affect our liquidity.

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, natural gas reserves, and operations are geographically concentrated 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. In addition, our estimates of proved reserves have been, and could continue to be, reduced due to our inability to finance such reserves.

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, 2015 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:


35


i.
actual prices we receive for oil and natural gas;
ii.
actual cost of development and production expenditures;
iii.
the amount and timing of actual production;
iv.
changes in governmental regulations or taxation; and
v.
changes in our ability to finance future development costs.

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 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; following the filing of our annual report on Form 10-K for the year ended December 31, 2015, we intend to seek to suspend our Exchange Act reporting obligations.

We have not filed within the time frames required by the SEC our annual report on Form 10-K for the year ended December 31, 2015, and consequently we are no longer eligible to use abbreviated and less costly SEC filings to register our securities for sale. Further, soon after filing our annual report on Form 10-K for the year ended December 31, 2015, we intend to seek to suspend our Exchange Act reporting obligations. As a result, we will no longer be eligible to use such abbreviated SEC filings, which will 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.

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

36


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 Midstream Gas Gathering System, necessary to gather our gas to deliver to interstate pipelines. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than those quoted on NYMEX or than we currently project for these specific regions, which would adversely affect our results of operations.

A portion of our natural gas and oil production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.

We depend on a relatively small number of purchasers for a substantial portion of our revenue. The inability of one or more of our purchasers to meet their obligations may adversely affect our financial results.

We derive a significant amount of our revenue from a relatively small number of purchasers of our production. Our inability to continue to provide services to key customers, if not offset by additional sales to our other customers, could adversely affect our financial condition and results of operations. These companies may not provide the same level of our revenue in the future for a variety of reasons, including their lack of funding, a strategic shift on their part in moving to different geographic areas in which we do not operate or our failure to meet their performance criteria. In the event that purchasers of our production may experience financial difficulties or seek bankruptcy, our receivables from such purchasers may not be collectible. 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 348 full-time employees as of December 31, 2015. 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.


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Our business may suffer if we lose key personnel.

Our operations depend on the continuing efforts of our executive officers 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.

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

38


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 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 Midstream’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.

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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.

Additional 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. 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, 2015, we recognized $59.8 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 $275.4 million for the year ended December 31, 2015, 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.

There are restrictive covenants, governance and other provisions in the New LLC Agreement that may restrict the ability of Eureka Midstream Holdings to pursue its business strategies and our ability to exert influence over and manage the business and operations of Eureka Midstream Holdings and its subsidiaries.

We are involved in midstream operations through our substantial equity investment in Eureka Midstream Holdings. The New LLC Agreement contains certain covenants that, among other things, restrict the ability of Eureka Midstream Holdings and its subsidiaries to, with certain exceptions:


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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 Midstream Holdings may change over time based on MSI’s percentage ownership interest in Eureka Midstream Holdings, or the failure of Eureka Midstream Holdings to satisfy certain performance standards on and after December 31, 2018. Currently, the board of managers of Eureka Midstream 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 Midstream Holdings will adversely affect our ability to exert influence over and manage the business and operations of Eureka Midstream 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 Midstream Holdings at any time, so long as MSI holds at least a 20% of the total Class A Common Units in Eureka Midstream Holdings. A Qualified Public Offering means an underwritten initial public offering of securities of Eureka Midstream Holdings for which aggregate cash proceeds to be received by Eureka Midstream Holdings from such offering are at least $25 million and which results in equity securities of Eureka Midstream Holdings being listed on a national securities exchange.

The New LLC Agreement also contains transfer restrictions on Magnum Hunter’s ownership interests in Eureka Midstream 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 Midstream Holdings to pursue its business strategies and our ability to exert influence over and manage the business and operations of Eureka Midstream 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. These drilling partnerships and their associated programs, including their dissolution, liquidation and winding up, 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. All drilling partnerships and programs dissolved when MHP filed for bankruptcy on December 15, 2015. These NGAS historical drilling partnerships and our sponsored drilling partnerships, including the liquidation and winding up of these partnerships, expose us to additional risks that could negatively affect our financial condition and results of operations. These additional risks include risks relating to potential challenges to tax positions taken by the investment partnerships, risks relating to disagreements with partners in the investment partnerships, especially with respect to the appropriate wind up of the drilling partnerships and programs, and risks relating to our general liability, in our capacity as general partner and liquidator 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.

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

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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 (the “CWA”) 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” (“WOTUS”) has been broadly defined to include certain inland water bodies, including certain wetlands and intermittent streams. The EPA and the Army Corps of Engineers released a rule to revise the definition of WOTUS for all CWA programs, which went into effect in August 2015. In October 2015, the U.S. Court of Appeals for the Sixth Circuit stayed the WOTUS rule nationwide pending further action of the court. The new WOTUS rule could significantly expand federal control of land and water resources across the U.S., triggering substantial additional permitting and regulatory requirements. On February 22, 2016, the U.S. Court of Appeals for the Sixth Circuit concluded that it has jurisdiction to hear the merits of a challenge to the new WOTUS rule. Failure to obtain or comply with permits or other CWA requirements could result in administrative, civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages.

The Oil Pollution Act of 1990 (“OPA”), which amended the CWA, imposes ongoing requirements on owners and operators of facilities that handle certain quantities of oil, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental clean-up and restoration costs that could be incurred in connection with an oil spill. In addition, OPA establishes strict liability for owners and operators of facilities that are the site of a release of oil into regulated waters. If a release into regulated waters occurs, we could be liable for clean-up costs, natural resources damages and public and private damages.

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 Midstream Gas Gathering System and the expected future expansion of these operations by Eureka Midstream are subject to additional governmental regulations.

Eureka Midstream is currently continuing the construction of the Eureka Midstream 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 Midstream 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 Midstream Gas Gathering System involve numerous regulatory, environmental, political and legal uncertainties beyond the control of Eureka Midstream 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 Midstream 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 Midstream’s business activities in many ways, including restricting the manner in which substances are disposed and discharged, 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 even 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 Midstream’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 Midstream Gas Gathering System could subject Eureka Midstream 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 Midstream may not be able to recover some or any of these costs from insurance.


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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.

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.

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 generally exempt from regulation under the SDWA’s Underground Injection Control (“UIC”) program and have historically been regulated by state oil and natural gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities. For example, in guidance released in 2014, the EPA asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation to provide for federal regulation of hydraulic fracturing under the SDWA 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 chemical substances and mixtures used in hydraulic fracturing. The public comment period on the EPA’s advance notice ended in September 2014, and a final notice of proposed rulemaking is expected in 2016. In addition, in April 2015, the EPA proposed regulations under the CWA to regulate wastewater discharges from hydraulic fracturing to publicly owned treatment works (the final rule is expected to be issued in 2016). In addition to rulemakings, increased scrutiny of the oil and natural gas industry may occur as a result of the EPA’s FY2014-2016 National Enforcement Initiative, “Ensuring Energy Extraction Activities Comply with Environmental Laws,” through which the EPA will address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environments.

Several states have implemented, new regulations pertaining to hydraulic fracturing, including requirement to disclose chemicals used in connection therewith. For example, Texas enacted a law that requires hydraulic fracturing operators to disclose the chemicals used in the fracturing process on a well-by-well basis. There have also been a variety of regulatory initiatives at the state and local level to restrict oil and gas drilling operations in certain locations, including permitting, well construction or water withdrawal regulations. For example, in 2013, Texas adopted amended rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. In addition, in November 2014, voters in the City of Denton, Texas, approved a local ordinance banning fracking. In May 2015, this local ordinance was preempted by state legislation. Texas also has water withdrawal restrictions allowing suspension of withdrawal rights in times of shortages. In the event state, local, or municipal legal restrictions on hydraulic fracturing 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 commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater in 2011 and issued a draft assessment for public comment and peer review in June 2015; the assessment is expected to be finalized in 2016. The draft assessment concluded that hydraulic fracturing has not led to widespread, systemic impacts on drinking

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water resources, but it does have the potential to impact drinking water resources; however, this conclusion has recently been criticized by the EPA’s Science Advisory Board. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or 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 SDWA or other regulatory mechanisms.

The U.S. Department of the Interior, Bureau of Land Management (“BLM”) published a final rule in March 2015 governing hydraulic fracturing activities on federal and Indian lands that replaces a prior draft of proposed rulemaking issued by the agency in May 2012. The rule requires public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. However, a federal judge has granted a preliminary injunction preventing enforcement of the rules at this time.

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 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, the EPA has adopted various regulations addressing GHGs under existing provisions of the federal Clean Air Act. In 2010 the EPA adopted two sets of regulations that restrict emissions of GHGs under existing provisions of the 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. The EPA has 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 2012, the EPA issued regulations subjecting certain oil and gas operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs that require operators to significantly reduce volatile organic compounds, or VOC, emissions from natural gas wells that are hydraulically fractured through the use of “green completions” to capture natural gas that would otherwise escape into the air. The EPA also issued regulations that establish standards for VOC emissions from several types of equipment at natural gas well sites, including storage tanks, compressors, dehydrators and pneumatic controllers, as well as natural gas gathering and boosting stations, processing plants, and compressor stations. In September 2015, the EPA proposed expanding the 2012 NSPS to impose volatile organic compound emissions limits on certain oil and natural gas operations that were previously unregulated, including hydraulically fractured oil wells. The proposed NSPS would limit natural gas emissions during well completions, impose new leak detection, and ongoing survey, repair, and recordkeeping requirements. The revised NSPS are expected to be finalized in June 2016. In addition, in October 2015, the EPA revised the existing National Ambient Air Quality Standards for ground level ozone to make the standard more stringent by reducing the standard to between 65 to 70 parts per billion for both the 8 hour primary and secondary standards protective of public health and public welfare.

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. In September 2015, the EPA proposed methane emission standards for new and modified oil and gas sources, which the EPA expects to finalize in June 2016. This proposed rule targets specific emission sources in the oil and gas sector and imposes distinct requirements for each type of source. Under the proposed rule, oil and gas companies will have to, among other things, limit emissions from new and modified pneumatic pumps, capture gas from the completion of fracked wells, find and repair leaks, and limit emissions from several types of equipment used at gas transmission compressor stations, including compressors and

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pneumatic controllers. On March 10, 2016, the EPA announced that it will commence drafting proposed methane emission standards for existing oil and gas sources, although the substance and timing of such regulation remains unclear. To aid in the efforts to reduce methane emissions from the oil and gas sector, in January 2016, the BLM also proposed rules to reduce methane emissions from venting, flaring and leaking on public lands.

On August 3, 2015, President Obama and the EPA announced the Clean Power Plan, which seeks to reduce carbon dioxide emissions by 32 percent from 2015 levels by 2030; however, on February 9, 2016, the U.S. Supreme Court stayed the implementation of the plan while it is being challenged in court. Furthermore, the U.S. is a party to the Paris Agreement adopted in December 2015 to reduce global GHG emissions. Also, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states already have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for the oil, natural gas and natural gas liquids we produce.

Finally, some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate change that could have significant physical effect, such as increased frequency and severity of storms, droughts and floods and other climatic events. If such effects were to occur, they could have an adverse effect on our assets and operations.

We must obtain governmental permits and approvals for our operations, which can be a costly and time consuming process, which may result in delays and restrictions on our operations.

Regulatory authorities exercise considerable discretion in the timing and scope of specific permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration, development or production operations or our midstream operations. For example, we are often required to prepare and present to federal, state, local or foreign authorities data pertaining to the effect or impact that proposed exploration for or development or production of oil or natural gas, pipeline construction, natural gas compression, treating or processing facilities or equipment and other associated equipment may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.

Our operations expose us to substantial costs and liabilities with respect to environmental matters.

Our oil and natural gas operations are subject to stringent federal, state, local and foreign laws and regulations governing human health and safety aspects of our operations, the release, discharge and disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things: (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling or pipeline construction activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to clean up or mitigate pollution from former and ongoing operations, such as requirements to close waste pits and plug abandoned wells, or at off-site waste disposal locations; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Numerous governmental agencies, such as the EPA, and analogous state agencies (and, in some cases, private individuals) enforce these laws and regulations, which are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties, the imposition of investigatory or remedial obligations for failure to comply or the issuance of injunctions limiting or prohibiting our activities. Some environmental laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs regardless of negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. Changes in environmental laws, rules 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

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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;
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 in the future may 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:


46


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;
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 shares of our existing common and preferred stock are expected to be canceled in our Chapter 11 proceedings.

We have a significant amount of indebtedness that is senior to our existing common and preferred stock in our capital structure. As a result, in accordance with our Plan, the existing shares of our common and preferred stock are expected to be canceled in our Chapter 11 proceedings and are not expected to be entitled to any recovery. Any trading in shares of our common and preferred stock during the pendency of the Chapter 11 proceedings is highly speculative and poses substantial risks to purchasers of shares of our common and preferred stock. On the Effective Date, these securities will be canceled and removed from further trading by the Financial Industry Regulatory Authority.

Item 1B.
UNRESOLVED STAFF COMMENTS

None.

47


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 us and certain of our 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 us and certain of our 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 we made certain false or misleading statements in its filings with the SEC, including statements related to our internal and financial controls, the calculation of non-cash share-based compensation expense, the late filing of our 2012 Form 10-K, the dismissal of our previous independent registered accounting firm, our characterization of the auditors’ position with respect to the dismissal, and other matters identified in our 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 our internal controls made in connection with a public offering that we 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 our 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 subsequently appealed the decision dismissing the Securities Cases to the U.S. Court of Appeals for the Second Circuit. On June 23, 2015, the U.S. Court of Appeals for the Second Circuit entered a Summary Order unanimously affirming the Southern District of New York’s dismissal of the Securities Cases in favor of us and the individual defendants. 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 our 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 our 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 our 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 our 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 our investors regarding our 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 our 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 our 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 our supplemental motion to dismiss the Derivative Case filed by Mark Respler. On July 22, 2014, the 125th District Court of Harris County, Texas issued an Order and Final Judgment granting the Company’s and the individual defendants’ motion for summary judgment in its entirety and entering a final judgment dismissing the suit filed by Richard Harveth. The plaintiffs may file an appeal. All of the Derivative Cases have now been dismissed. It is possible that additional stockholder derivative suits could be filed over these events.

In addition, we 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 General Corporation Law of the State of Delaware. 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 sought various books and records relating to the claims in the Securities Cases and the Derivative Cases, as well as costs and attorneys’ fees. We 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.

SEC Wells Notice

In April 2013, we received a letter from the staff of the SEC’s Division of Enforcement (the “Staff”) stating that the Staff was conducting an inquiry regarding our internal controls, change in outside auditors and public statements to investors and asking us to preserve documents relating to these matters. In connection with the Staff’s inquiry, on March 24, 2015, we received a “Wells Notice” from the Staff, stating that the Staff had made a preliminary determination to recommend that the SEC file an enforcement action against us. On that date, the Staff issued similar Wells Notices to (i) Gary C. Evans, our current Chairman and Chief Executive Officer, (ii) J. Raleigh Bailes, Sr., our former director and former Chairman of our Audit Committee, (iii) our former chief financial officer who was in office at the time of our decision to dismiss our prior independent registered public accounting firm and (iv) our former chief accounting officer who had resigned from that position in October 2012.

The Wells Notice issued to the Company stated that the proposed action against us would allege violations of Sections 17(a)(2) and 17(a)(3) of the Securities Act of 1933 and Sections 13(a), 13(b)(2)(A), and 13(b)(2)(B) of the Securities Exchange Act of 1934 and Rules 13a-l, 13a-13, and 13a-15(a) thereunder. The proposed actions against the individuals would allege violations of those same provisions, as well as violations of Section 13(b)(5) of the Securities Exchange Act of 1934 and Rules 13a-14 and 13a-15(c) thereunder. The proposed actions described in the Wells Notices did not include any claims for securities fraud under Section 10(b) of the Securities Exchange Act of 1934 or Rule 10b-5 thereunder or under Section 17(a)(1) of the Securities Act of 1933.

We and certain of the individual respondents (other than Mr. Evans and Mr. Bailes) thereafter negotiated a settlement with the SEC, which the SEC Commissioners approved on March 10, 2016. Pursuant to the settlement, without admitting or denying the SEC’s findings, we agreed to pay a civil penalty of $250,000 to the SEC (the “Civil Penalty”), subject to Bankruptcy Court approval, and were ordered to cease and desist from violating Sections 13(a), 13(b)(2)(A) and 13(b)(2)(B) of the Securities Exchange Act and Rules 13a-1, 13a-13 and 13-15(a) thereunder. The two former officers referred to above, who oversaw our accounting department at the relevant times, as well as two former outside accounting professionals, were ordered to cease and desist from violating these provisions and were subjected to additional financial penalties or administrative suspensions in their individual capacities.

On March 23, 2016, Mr. Evans, our current Chairman and Chief Executive Officer, and Mr. Bailes, our former director and former Chairman of our Audit Committee, received letters from the Staff stating that the Staff had concluded its investigations of Mr. Evans and Mr. Bailes and that, based on the information the Staff possessed as of that date, the Staff did not intend to recommend an enforcement action by the SEC against either of them. Furthermore, none of our other current officers or directors were required to pay any penalties or were subjected to any sanctions in their individual capacity pursuant to the settlement.

On March 11, 2016, we filed a motion with the Bankruptcy Court seeking approval of our settlement with the SEC and authority to pay the Civil Penalty to the SEC. On March 29, 2016, the Bankruptcy Court entered an order approving our motion.

Twin Hickory Matter

On April 11, 2013, a flash fire occurred at Eureka Midstream’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 Midstream 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 us and Eureka Midstream seeking a declaratory judgment that Eureka Midstream 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 us, Eureka Midstream 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 alleged that Eureka Midstream 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 demanded judgments for an unspecified amount of compensatory, general and punitive damages. Various cross-claims were asserted. In May 2014, the injured third-party contractor employee sued Magnum Hunter 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.

49


The claim filed by the injured third-party contractor employee, Jonathan Whisenhunt, has been resolved and dismissed. A portion of the settlement was paid by an insurer of Eureka Midstream, and the remainder paid by unrelated third party co-defendants or their insurers. The cross-claims among the defendants in the Whisenhunt litigation have been resolved. In addition, the claims filed by Antoinette M. Miller and Karen S. Phipps have been successfully mediated and have been resolved and dismissed. Insurers providing coverage to Eureka Midstream, Magnum Hunter and other affiliated or related entities paid a portion of the settlements, with the remainder being paid by unrelated third party co-defendants or their insurers. Accordingly, all lawsuits relating to this matter have been resolved.

Samson Matter

In June 2015, Samson Resources Company (“Samson”) executed and filed ten oil and gas well liens in Divide County, North Dakota (the “Samson Liens”) to secure payments it contends were owed by Bakken Hunter. In July 2015, Bakken Hunter filed a complaint against Samson in a case styled Bakken Hunter, LLC v. Samson Resources Company, Case No. 4:15-cv-0008, in the United States District Court for the District of North Dakota, Northwestern Division. In its complaint, Bakken Hunter alleges that Samson breached certain agreements by, among other things, failing to promptly pay and discharge certain expenses resulting in third party liens, failing to keep accurate records, failing to make its accounts available to Bakken Hunter for audit and failing to respond to Bakken Hunter’s concerns about Samson’s billing and accounting practices. Bakken Hunter is seeking equitable relief and damages in an unliquidated amount and seeking a declaration that the Samson Liens are void. In August 2015, Samson filed and served its answer and counterclaims against Bakken Hunter, generally denying Bakken Hunter’s allegations and asserting its own claims for breach of contract, contending that Bakken Hunter failed to pay its proportionate share of certain expenses as a non-operator of certain oil and gas properties. In its counterclaims, among other relief, Samson sought a declaration that the Samson Liens were valid and sought in its counterclaims to foreclose on the Samson Liens. This matter has been stayed as a result of Samson’s bankruptcy filing in the United States Bankruptcy Court for the District of Delaware, Case No. 15-11942 (CSS). In November 2015, Bakken Hunter filed a Proof of Claim against Samson in the Samson bankruptcy; the Proof of Claim is based on the same facts alleged in Bakken Hunter’s complaint against Samson. During the pendency of these matters, Samson has continued to withhold all revenues owed to Bakken Hunter with respect to Bakken Hunter’s non-operated working interests in the oil and gas properties in Divide County, North Dakota as to which Samson is an operator under a theory of recoupment applicable to the expenses Samson claims Bakken Hunter, as a non-operated working interest owner, has failed to pay. Our Plan includes an agreed stipulation (the “Samson Stipulation”) between Bakken Hunter and Samson. Pursuant to the Samson Stipulation, among other things, (i) the joint operating agreement (the “Samson JOA”) between the parties will be assumed by Bakken Hunter in its bankruptcy proceeding, consistent with the terms of the Samson Stipulation; (ii) both parties reserved all rights of their respective claims against each other; (iii) the parties agreed to cooperate to complete Bakken Hunter’s ongoing audits under the Samson JOA for years 2013, 2014 and 2015; and (iv) so long as Bakken Hunter is not in default under the Samson JOA (including the current payment of joint interest billings), Samson shall cease offsetting Bakken Hunter’s revenue and timely remit such revenue to Bakken Hunter in the following manner: (a) each month, Samson shall remit all revenue due to Bakken under the Samson JOA up to the amount paid by Bakken Hunter to Samson in respect of the prior month’s joint interest billings plus any amounts for which Bakken Hunter properly reduced payment in accordance with the Samson JOA (such total, the “Prior Month’s Reimbursement”) and (b) any revenue in excess of the Prior Month’s Reimbursement will be placed into an escrow account pending resolution of the parties’ various claims. While the outcome of these lawsuits cannot be predicted with certainty, we do not expect any of these lawsuits to have a material adverse effect on our consolidated financial condition or results of operations.

Eclipse Matter

In November 2015, Eclipse Resources I, LP (“Eclipse”) filed a complaint against Triad Hunter in a case styled Eclipse Resources I, LP v. Triad Hunter, LLC, Civil Action G.D. No. 2015-4589, in the Court of Common Pleas of Centre County, Pennsylvania. In its complaint, Eclipse alleged that Triad Hunter failed to honor its obligations under an Operating Agreement in constructing and operating a well located in Monroe County, Ohio, which experienced a blowout event in December 2014. Asserting purported claims for declaratory, common law and equitable relief, Eclipse is seeking recovery of its proportionate share of costs to remediate the well blowout event, legal fees in the action, removal of Triad Hunter as operator, and appointment of a receiver over the business and assets of Triad Hunter. Although the matter was initially stayed upon the filing of the Chapter 11 Cases, on January 21, 2016 the Bankruptcy Court approved a stipulation agreed to by the parties pursuant to which, among other things, the automatic stay was modified to allow the parties to proceed with the state court litigation. Pursuant to the stipulation, (i) Eclipse agreed to dismiss the pending action in the Court of Common Pleas of Centre County, Pennsylvania and refile the action in state court in Ohio; (ii) Eclipse is permitted to take or receive hydrocarbons from the affected wells in kind; (iii) Eclipse is required to fund up to $2.2 million in an escrow account pending the final and non-appealable resolution of the state court litigation; and (iv) Triad Hunter agreed to discontinue netting revenue otherwise owed to Eclipse from the sale of Eclipse hydrocarbons marketed by Triad Hunter. The prevailing party in the state court litigation will be entitled to recovery of the escrowed funds. We intend to mount a vigorous defense in the state court litigation. While the outcome of this matter cannot be predicted with certainty, we do not expect this matter to have a material adverse effect on our consolidated financial condition or results of operations.

50


Item 4.
MINE SAFETY DISCLOSURES

Not applicable.

51


PART II

Item 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Common Stock Trading Summary

During 2014 and through November 30, 2015, our common stock traded on the NYSE under the symbol “MHR.” Subsequent to November 30, 2015, our common stock trades on the OTC Pink Open Marketplace under the symbol “MHRCQ.” The following table summarizes the high and low reported sales prices on days in which there were trades of our common stock for each quarterly period for the last two fiscal years. On April 29, 2016, the last reported sale price of our common stock, as reported on the OTC Pink Open Marketplace, was $0.00 per share. On the Effective Date, our common stock is expected to be canceled and removed from further trading by the Financial Industry Regulatory Authority.

 
High
 
Low
2016:
 
 
 
Second quarter (through April 29, 2016)
$
0.01

 
$
0.00

First quarter
0.02

 
0.01

2015:
 
 
 
Fourth quarter
$
0.69

 
$
0.01

Third quarter
1.81

 
0.30

Second quarter
2.88

 
1.19

First quarter
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

Holders

As of December 31, 2015, based on information from our transfer agent, American Stock Transfer and Trust Company, we had 342 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 credit facilities, 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.


52


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, 2015:

 
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
7,314,751

 
$
5.75

 
8,646,206

Equity compensation plans not approved by
security holders
—

 
—

 
—

Total   
7,314,751

 
$
5.75

 
8,646,206


Our 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.

As of the Effective Date, all shares, options, warrants, and stock appreciation rights related to our equity that existed prior to that date, including those issued under our stock incentive plan, are expected to be canceled.

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 we specifically incorporate it by reference into such filing.

The following graph illustrates changes over the five-year period ended December 31, 2015 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, 2010, and that dividends were reinvested.

53


COMPARISON OF FIVE YEAR CUMULATIVE TOTAL RETURNS
 
 
 
December 31,
 
2010
 
2011
 
2012
 
2013
 
2014
 
2015
Magnum Hunter Resources Corporation
100.00
 
74.86
 
55.42
 
101.53
 
43.61
 
0.28
S & P 500
100.00
 
102.11
 
118.45
 
156.82
 
178.28
 
180.75
Dow Jones US Expl & Production
100.00
 
97.12
 
101.79
 
133.59
 
117.64
 
88.83

54


Item 6.
SELECTED FINANCIAL DATA

The following selected consolidated financial data should be read in conjunction with our consolidated financial statements and related notes and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Our consolidated financial statements and this selected financial data reflect the results of operations for Eureka Midstream Holdings for the period from January 1, 2014 up to December 18, 2014 and for all years preceding 2014 since the formation of Eureka Midstream Holdings. We began accounting for our investment in Eureka Midstream Holdings using the equity method of accounting effective December 18, 2014, under which we record our investment in Eureka Midstream Holdings as a single financial caption in the consolidated balance sheet, and our proportionate share in earnings (loss) in Eureka Midstream Holdings is recognized as a single financial caption in the consolidated statement of operations. As a result of deconsolidation, we recorded a one-time gain on deconsolidation of approximately $510 million during the year ended December 31, 2014. See “Note 4 - Eureka Midstream Holdings” in our notes to our consolidated financial statements.
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
2012
 
2011
 
(in thousands, except per-share data)
Statement of Operations Data
 
 
 
 
 
 
 
 
 
Revenues and other
$
154,124

 
$
391,469

 
$
304,538

 
$
159,937

 
$
80,545

Loss from continuing operations, net of tax
(783,872
)
 
(137,833
)
 
(232,113
)
 
(129,357
)
 
(87,256
)
Income (loss) from discontinued operations, net of tax
—

 
4,561

 
(62,561
)
 
(9,773
)
 
10,844

Gain (loss) on disposal of discontinued operations, net of tax
—

 
(13,855
)
 
71,510

 
2,409

 
—

Net loss
(783,872
)
 
(147,127
)
 
(223,164
)
 
(136,721
)
 
(76,412
)
Dividends on preferred stock
(33,817
)
 
(54,707
)
 
(56,705
)
 
(34,706
)
 
(14,007
)
Loss on extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units
—

 
(51,692
)
 
—

 
—

 
—

Net loss attributable to common shareholders
$
(817,689
)
 
$
(249,873
)
 
$
(278,881
)
 
$
(167,414
)
 
$
(90,668
)
Basic and diluted earnings (loss) per share
 
 
 
 
 
 
 
 
 
Continuing operations
$
(3.63
)
 
$
(1.27
)
 
$
(1.69
)
 
$
(1.03
)
 
$
(0.90
)
Discontinued operations
—

 
(0.05
)
 
0.05

 
(0.04
)
 
0.10

Net loss per share
$
(3.63
)
 
$
(1.32
)
 
$
(1.64
)
 
$
(1.07
)
 
$
(0.80
)
Statement of Cash Flows Data
 
 
 
 
 
 
 
 
 
Net cash provided by (used in)
 
 
 
 
 
 
 
 
 
Operating activities
$
25,026

 
$
(18,665
)
 
$
111,711

 
$
58,011

 
$
33,838

Investing activities
(165,941
)
 
(318,119
)
 
(127,860
)
 
(1,009,207
)
 
(361,715
)
Financing activities
128,634

 
348,195

 
656

 
996,442

 
342,193

Balance Sheet Data
 
 
 
 
 
 
 
 
 
Total assets
$
1,060,158

 
$
1,677,955

 
$
1,856,651

 
$
2,198,632

 
$
1,168,760

Debtor-in-possession financing
40,000

 
—

 
—

 
—

 
—

Current portion of long-term debt
83,682

 
10,770

 
3,804

 
3,991

 
4,565

Long-term debt, net of current portion (1)
—

 
937,963

 
876,106

 
886,769

 
285,824

Other long-term obligations
30,671

 
31,566

 
109,275

 
155,677

 
124,609

Liabilities subject to compromise (2)
1,096,071

 
—

 
—

 
—

 
—

Redeemable preferred stock
100,000

 
100,000

 
236,675

 
200,878

 
100,000

Shareholders’ equity (deficit)
$
(312,484
)
 
$
431,855

 
$
450,730

 
$
711,652

 
$
490,652

_________________________________
(1)  
As of December 31, 2015, all unsecured or under-secured long-term debt has been reclassified to “Liabilities Subject to Compromise”. Due to events of default as a result of the Chapter 11 Cases, all remaining debt has been reclassified to “Current portion of long-term debt”.

(2) 
Liabilities subject to compromise as of December 31, 2015 represents liabilities incurred prior to the Petition Date which may be affected by the bankruptcy process. These amounts represent the Debtors’ allowed claims and their best estimate to be allowed which will be resolved as part of the bankruptcy proceedings.

55



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 two 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 primarily non-operated oil and gas properties in the Williston Basin/Bakken Shale in Divide County, North Dakota and operated natural gas properties in Kentucky. Through our substantial equity investment in Eureka Midstream 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 as well as to provide drilling services to third parties.

Chapter 11 Bankruptcy Filings

On December 15, 2015 (the “Petition Date”), Magnum Hunter Resources Corporation and certain of its wholly owned subsidiaries, namely, Alpha Hunter Drilling, LLC, Bakken Hunter Canada, Inc., Bakken Hunter, LLC, Energy Hunter Securities, Inc. (“Energy Hunter Securities”), Hunter Aviation, LLC, Hunter Real Estate, LLC, Magnum Hunter Marketing, LLC, Magnum Hunter Production, Inc. (“MHP”), Magnum Hunter Resources GP, LLC, Magnum Hunter Resources, LP, Magnum Hunter Services, LLC, NGAS Gathering, LLC, NGAS Hunter, LLC, PRC Williston LLC (“PRC Williston”), Shale Hunter, LLC, Triad Holdings, LLC, Triad Hunter, LLC, Viking International Resources Co., Inc., and Williston Hunter ND, LLC (collectively, the “Filing Subsidiaries” and, together with the Company, the “Debtors”), filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Chapter 11 cases (the “Chapter 11 Cases”) were jointly administered by the Bankruptcy Court under the caption In re Magnum Hunter Resources Corporation, et al., Case No. 15-12533.

Our subsidiaries and affiliates excluded from the filing include wholly owned subsidiaries Magnum Hunter Management, LLC, Sentra Corporation, 54NG, LLC, and our 44.53% owned affiliate, Eureka Midstream Holdings (collectively, the “Non-Debtors”).

On April 18, 2016, the Bankruptcy Court approved our Chapter 11 plan of reorganization (the “Plan”), which, among other things, resolved the Debtors’ pre-petition obligations, set forth the revised capital structure of the newly reorganized entity, and provided for corporate governance subsequent to exit from bankruptcy. The effective date of the Plan is expected to be May 6, 2016 (the “Effective Date”). Upon emergence from bankruptcy, we expect to apply fresh start accounting. Accordingly, we expect to make adjustments to the carrying values and classification of our assets and liabilities, and such adjustments could be material.

Prior to filing the Chapter 11 Cases, on December 15, 2015, the Company and the other Debtors entered into a Restructuring Support Agreement (as amended, the “RSA”) with the following parties:

•
Substantially all of the Second Lien Lenders and Noteholders (each as defined herein) party to the Senior Secured Bridge Financing Facility (as defined in note “Note 11 - Long-Term Debt”);

•
Lenders holding approximately 66.5% in principal amount outstanding under the Second Lien Term Loan Agreement (as described in “Note 11 - Long-Term Debt”) (the “Second Lien Lenders”); and

•
Holders, in the aggregate, of approximately 79.0% in principal amount outstanding of our unsecured 9.750% Senior Notes due 2020 (the “Senior Notes”) (collectively, the “Noteholders”).

The agreed terms of the restructuring of the Debtors, as contemplated in the RSA, were memorialized in the Plan and include the following key elements:

•
DIP Facility: A $200 million multi-draw debtor-in-possession financing facility (the “DIP Facility”) entered into with certain Second Lien Lenders and Noteholders.

56




•
Substantial Deleveraging of Balance Sheet: Our funded debt is expected to be restructured as follows:
◦
The Senior Secured Bridge Facility was repaid in full from the proceeds of the DIP Facility upon entry of an order by the Bankruptcy Court on January 11, 2016 approving, on a final basis, the debtor-in-possession financing.
◦
On the Effective Date, the Second Lien Term Loan is expected to be converted into new common equity of the reorganized Company, receiving 36.87% of the new common equity.
◦
On the Effective Date, the Senior Notes are expected to be converted into new common equity of the reorganized Company, receiving 31.33% of the new common equity.
◦
On the Effective Date, the DIP Facility is expected to be converted into 28.80% of the new common equity.
◦
Our general unsecured claims are projected to receive a blended recovery as specified in the RSA and the Plan, to be paid in cash, through a combination of payments to be made pursuant to Bankruptcy Court orders (lien claimant motion, taxes, etc.) and a cash pool of approximately $23.0 million included in the Plan. Holders of certain of our general unsecured claims elected to receive new common equity instead of cash, which is expected to dilute the new common equity issued to the holders of the Senior Notes and the lenders of the Second Lien Term Loan as described in the Plan.
◦
Holders of our preferred stock and common equity are expected to receive no recovery under the RSA and the Plan.
◦
The Other Secured Debt (as defined in the RSA and the Plan) is expected to be reinstated.

•
Business Plan: A business plan (the “Business Plan”) was developed jointly with the Debtors, the Second Lien Lenders that have backstopped the DIP Facility (the “Second Lien Backstoppers”) and the Noteholders that have backstopped the DIP Facility (the “Noteholder Backstoppers,” and together with the Second Lien Backstoppers, the “Backstoppers”).

•
Valuation for Settlement Purposes: For settlement purposes only, the Plan reflects a total enterprise value of the Company of $900 million. Such settlement value is not indicative of any party’s views regarding total enterprise value, but rather is a settled value for the purpose of determining equity splits and conversion rates for the various claimants.

•
Eureka Midstream Holdings: The Debtors restructured certain key agreements between Eureka Midstream Holdings and its subsidiaries, on the one hand, and the Debtors, on the other, with the consent of the Backstoppers.

•
Reorganized Company Status: The reorganized Company is expected to be a private company upon emergence from the Chapter 11 Cases and is expected to seek public listing of its new common equity when market conditions warrant and as determined by the New Board (as defined below) as informed by input from the Backstoppers.

•
Releases: The Plan provided for release, exculpation, and injunction provisions, including customary carve-outs, to the fullest extent permitted by applicable law and consistent with the terms of the RSA, and the Backstoppers have agreed not to “opt-out” of the consensual “third-party” releases granted to, among others, the Debtors’ current and former directors and officers.

•
Incentive Plans: the new board of directors of the reorganized Company is authorized to adopt management incentive programs to be paid exclusively with the funds of the reorganized Company. The management incentive plan will not give rise to any claims against the debtors or their estates.

•
Governance: The reorganized Company has a seven-person board of directors (the “New Board”), consisting of (i) the Chief Executive Officer, (ii) two directors selected by the Noteholder Backstoppers, (iii) two directors selected by the Second Lien Backstoppers, (iv) one director jointly selected by the Noteholder Backstoppers and the Second Lien Backstoppers, who serves as the non-executive chairman, and (v) one director selected by the Noteholder Backstoppers, based upon a slate of three candidates jointly determined by the Noteholder Backstoppers and the Second Lien Backstoppers. Members of the current management team of the Debtors have remained in place during the pendency of the Chapter 11 Cases and are expected to remain in place until the Company’s emergence from bankruptcy; however, on May 6, 2016, Mr. Evans tendered his voluntary resignation as our Chief Executive Officer and Chairman of the Board of Directors, which resignation is expected to be effective following the filing of this Annual Report on Form 10-K.

Additionally, on the Effective Date the Debtors expect to enter into an exit financing facility.


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Under the Bankruptcy Code, debtors have the right to assume or reject certain contracts, subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the assumption of a contract requires a debtor to satisfy pre-petition obligations under the contract, which may include payment of pre-petition liabilities in whole or in part. Rejection of a contract is typically treated as a breach occurring as of the moment immediately preceding the Chapter 11 filing. Subject to certain exceptions, this rejection relieves the debtor from performing its future obligations under the contract but entitles the counterparty to assert a pre-petition general unsecured claim for damages. Parties to contracts rejected by a debtor may file proofs of claim against that debtor’s estate for damages.

On January 7, 2016, the Debtors filed the “Contract Procedures Motion”. The court entered an order approving the Contract Procedures Motion on February 26, 2016. On March 14, 2016, the Debtors filed the plan supplement, which included a schedule of assumed contracts and a schedule of rejected contracts, and since then have filed two amended plan supplements and additional motions with respect to assumed and rejected contracts. Through the contract assumption and rejection process, the Debtors were able to successfully renegotiate approximately a dozen midstream and downstream contracts.

The Debtors continue to review and analyze their contractual obligations and retain the right, until eight days following the Effective Date, to move contracts from the schedule of assumed contracts to the schedule of rejected contracts or from the schedule of rejected contracts to the schedule of assumed contracts.

Liquidity and Capital Resources

Overview

We have historically relied on cash flows from operating activities, borrowings under our credit facilities, proceeds from sales of assets, including liquidation of derivative positions, and proceeds from the sale of securities in the capital markets to fund our operations. We define liquidity as funds available under our credit facilities plus 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, 2015 compared to December 31, 2014:

 
December 31, 2015
 
December 31, 2014
 
(in thousands)
Borrowing base under MHR Senior Revolving Credit Facility
$
—

 
$
50,000

Cash and cash equivalents
40,871

 
53,180

Borrowings under MHR Senior Revolving Credit Facility
—

 
—

Letters of credit issued
—

 
(39,261
)
Liquidity
$
40,871

 
$
63,919


Declines in oil, natural gas, and NGLs prices have negatively impacted our results of operations and operating cash flows. Further, our cash receipts from sales of production from non-operated oil and natural gas properties have been reduced as certain operators have begun netting our revenues against lease operating expenses. Due to an event of default under our credit facilities and cross-default provisions in other debt agreements and instruments, we classified our then-outstanding balances under our Credit Facility, Second Lien Term Loan Agreement and certain equipment notes payable as current liabilities on our consolidated balance sheets as of September 30, 2015. On October 9, 2015, we announced the suspension of monthly cash dividends on all of our outstanding series of preferred stock, and became ineligible to issue securities under our universal shelf Form S-3 Registration Statement. On November 11, 2015 our common and preferred stock was delisted from the NYSE. On November 15, 2015, we failed to make the interest payment of approximately $29.3 million due on our Senior Notes. On December 15, 2015, we and certain of our wholly owned subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code. Additional discussion of these factors and our plans for improving our overall liquidity position follow below.

Oil, Natural Gas, and NGLs Prices

Prices for oil and natural gas are primarily 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. During the fourth quarter of 2014 and throughout 2015, spot and future market prices for oil, natural gas, and natural gas liquids 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. A continued decline in prices as a result of increased supply and volumes of natural gas in storage

58



without sufficient takeaway capacity for this region could impact the amount of natural gas that companies are willing to produce until additional takeaway capacity becomes available.

Our realized prices for oil, natural gas, and NGLs continue to be affected by market conditions. Our average realized prices for oil, from which we derived over 13.4% of our oil and natural gas production for the year ended December 31, 2015, declined $44.40 per barrel, or 53.2% from the year ended December 31, 2014. While we still have exposure to crude oil market prices, our properties now produce predominantly natural gas and NGLs. Average realized prices for natural gas and NGLs experienced price declines of 52.3% and 65.2%, respectively, during the year ended December 31, 2015 compared to the year ended December 31, 2014. The declines in our realized prices are the result of overall declines observed in commodity markets in the United States and the effects of regional pricing differentials in the Williston and Appalachian Basins. 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, 2014

March 31, 2015
June 30, 2015
September 30, 2015
December 31, 2015
December 31, 2015
Oil (per Bbl)
$
83.53

$
30.16

$
52.31

$
43.13

$
31.86

$
39.13

Natural gas (per Mcf)
$
4.19

$
2.91

$
1.67

$
1.62

$
1.43

$
2.00

NGLs (per BOE)
$
48.04

$
25.48

$
16.51

$
9.23

$
16.88

$
16.71


The decreases in market prices for commodities directly reduce our operating cash flows and indirectly impact our other sources of liquidity. Significant declines in prices and/or prolonged periods of low market prices may 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. 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. Sustained declines in commodity prices may result in substantial downward estimates of our proved reserves. Low commodities prices may also impact our ability to negotiate asset sales at acceptable prices.

Debt Obligations and Debt Covenant Violations

We have historically utilized a revolving credit facility to fund a portion of our operating and capital needs, which facility was subject to periodic changes in the borrowing base based upon fluctuations in our proved reserves. Throughout the first seven months of 2015, our revolving credit facility agreement was amended five times to, among other things, waive or amend certain financial covenants, limit certain capital expenditures, increase the interest rate, limit dividends on preferred stock, and terminate our open commodity derivatives positions. On November 3, 2015, we entered into a Senior Secured Bridge Financing Facility, which replaced our revolving credit facility as further discussed below.

In addition, at December 31, 2014 and 2015 we maintained a second lien term loan. During 2015, we entered into two amendments to the second lien term loan agreement in order to waive or amend certain financial covenants, provide for forbearance by the lenders with respect to our failure to make the October 30, 2015 interest payment, and to permit the Senior Secured Bridge Financing Facility.

We also have outstanding obligations related to our Senior Notes, as well as certain other equipment and real estate notes payable.

Defaults and Cross-Defaults

On July 27, 2015, we became aware of a default under our revolving credit facility and our second lien term loan relating to the aging of our accounts payable. In accordance with the terms of the related debt agreements, we were not permitted to have accounts payable outstanding (subject to certain permissible amounts) in excess of 180 days from the invoice date for any day on or prior to the earlier of (a) December 31, 2015 or (b) the date that is ten business days following the date on which we consummate the sale of all or substantially all of our equity ownership interest in Eureka Midstream Holdings, after which earlier date the restriction will revert back to 90 days. We cured the default on August 26, 2015.

On September 8, 2015, we became aware of an additional default under our revolving credit facility and second lien term loan because we had approximately $1.4 million in accounts payable outstanding (in excess of permissible amounts) in excess of 180 days from the invoice date. Under the related debt agreements, we had 30 days to cure this default. As of October 8, 2015, we

59



continued to have accounts payable outstanding (in excess of permissible amounts) in excess of 180 days from the invoice date, resulting in an event of default. Due to the event of default, the lenders under our revolving credit facility and our second lien term loan were permitted to, but did not, declare the outstanding loan amounts immediately due and payable.

The events of default described above under revolving credit facility and the second lien term loan resulted in cross-defaults between the two agreements, and also a cross-default with one of our equipment notes payable. The event of default under our revolving credit facility also resulted in a cross-default under our then-outstanding derivatives contracts with Bank of Montreal. However, we did not receive any notice of cross-default from Bank of Montreal with respect to such derivatives contracts. In addition, on November 2, 2015, we chose to terminate all of our open commodity derivative positions with Bank of Montreal and received approximately $0.9 million in cash proceeds.

We did not make the interest payment of approximately $29.3 million which was due on November 15, 2015 on our Senior Notes. Our failure to make the interest payment within 30 days following the due date constituted an event of default under the Senior Notes; however, at such time, payments under the Senior Notes were the subject of certain forbearance agreements entered into on November 3, 2015.

The filing of the Chapter 11 Cases constituted an event of default under all of our then-existing debt agreements, and therefore all of our outstanding obligations were accelerated and became immediately due and payable. Our outstanding balances under the second lien term loan and our outstanding obligations related to the Senior Notes are reflected as “Liabilities subject to compromise” on our consolidated balance sheet as of December 31, 2015. Our equipment and real estate notes payable are reflected as “Current portion of notes payable” on our consolidated balance sheet as of December 31, 2015. Under the Bankruptcy Code, our creditors are stayed from taking any action against the Debtors as a result of any default or event of default, including the bankruptcy filing.

Senior Secured Bridge Financing Facility

On and effective as of November 3, 2015, we entered into a Senior Secured Bridge Financing Facility for an aggregate amount of $60.0 million with certain holders of our Senior Notes and lenders under the second lien term loan (the “New First Lien Lenders”). We used the proceeds from this borrowing to pay approximately $5.0 million of outstanding borrowings outstanding under our revolving credit facility discussed above, to cash collateralize approximately $39.0 million of outstanding letters of credit, and to pay expenses associated with the borrowing and other general needs of approximately $16.0 million. As a result, our revolving credit facility was effectively paid off and replaced with the Senior Secured Bridge Financing Facility. Effective as of November 30, 2015, we entered into an amendment in order to obtain an additional $10.0 million of new borrowings, and as of December 31, 2015, we had total outstanding borrowings under the Senior Secured Bridge Financing Facility of $70.0 million which was reflected as “Current portion of notes payable” on our consolidated balance sheet as of that date.

Borrowings under the Senior Secured Bridge Financing Facility were due and payable on the earlier of: (a) December 30, 2015, (b) in the case of an event of default under the Senior Secured Bridge Financing Facility, the acceleration of the payment of the term loans, as determined by the requisite percentage of the New First Lien Lenders, or (c) the filing of a Chapter 11 case (or cases) by us or any of our subsidiaries. The Senior Secured Bridge Financing Facility bore interest, at our option, at either the London Interbank Offered Rate, plus an applicable margin of 4.0%, or a specified prime rate of interest, plus an applicable margin of 3.0%.

The Senior Secured Bridge Financing Facility removed all financial covenants in effect under the revolving credit facility it replaced, including the removal of restrictions related to the aging of our accounts payable. The Senior Secured Bridge Financing Facility also contained restrictions on the sale of assets, which, among other things, prohibited us from selling our equity ownership interests in Eureka Midstream Holdings and from engaging in certain farm-outs of undeveloped acreage without obtaining requisite consent from the New First Lien Lenders. Furthermore, we were required to cease marketing the sale of our equity interests in Eureka Midstream Holdings, other than with bidders that contacted us without prior solicitation and other than bidders that had already been engaged in such marketing efforts with us as of the closing date of the Senior Secured Bridge Financing Facility.

On January 14, 2016, the Senior Secured Bridge Financing Facility and outstanding interest was paid in full with proceeds from borrowings under the Debtor-in-Possession Credit Facility.


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Debtor-in-Possession Credit Facility

In connection with the Chapter 11 Cases, on the Petition Date we filed a motion seeking Bankruptcy Court approval of debtor-in-possession financing on the terms set forth in a Debtor-in-Possession Credit Agreement (as amended from time to time, the “DIP Credit Agreement”). On December 16, 2015, the Bankruptcy Court entered an order approving, on an interim basis, the financing to be provided pursuant to the DIP Credit Agreement (i.e., the Interim DIP Order) and, on December 17, 2015, the DIP Credit Agreement was entered into by and among us, as borrower, the Filing Subsidiaries, as guarantors, the DIP Lenders (as defined below) and Cantor Fitzgerald Securities, as administrative agent and as collateral agent for the DIP Lenders.

The DIP Credit Agreement provides for senior secured term loans in the aggregate principal amount of up to $200 million (the “DIP Facility”), which consists of:

i.
a term loan in the principal amount of $40 million (the “First DIP Draw”);
ii.
a term loan in the principal amount of $100 million (the “Second DIP Draw”); and
iii.
a term loan in the principal amount of $60 million (the “Third DIP Draw”).

The First DIP Draw was funded, net of certain fees and expenses, on December 17, 2015. The net proceeds from the First DIP Draw were used to fund (a) payments in accordance with the orders approved on the Petition Date, (b) adequate protection payments, and (c) working capital, in each case, in accordance with the budget variance financial covenant.

The Second DIP Draw was fully funded on January 14, 2016 following the Bankruptcy Court’s entry of an order approving, on a final basis, the financing provided pursuant to the DIP Credit Agreement (i.e., the Final DIP Order). Approximately $70.2 million of the net proceeds from the Second DIP Draw was used to repay in full all loans outstanding under our Senior Secured Bridge Financing Facility and approximately $25.5 million was made available to be used for general corporate purposes, subject to the DIP Facility budget.

The Third DIP Draw was fully funded on April 21, 2016, following the satisfaction of certain conditions pursuant to the DIP Credit Agreement.

Subject to certain conditions, the maturity date of the DIP Facility is the earlier of:

i.
Nine months from the closing date of the DIP Facility;
ii.
31 days after entry of the Interim DIP Order if the Final DIP Order had not been entered into by the Bankruptcy Court;
iii.
The effective date of the Plan;
iv.
The consummation of a sale of all or substantially all of our assets and the assets of our subsidiaries pursuant to Section 363 of the Bankruptcy Code; and
v.
The date of termination of the DIP Lenders’ Commitments (as defined in the DIP Credit Agreement) and the acceleration of any outstanding extensions of credit, in each case, under the DIP Facility in accordance with the terms of the Loan Documents (as defined in the DIP Credit Agreement).

Interest on the outstanding principal amount of the term loans under the DIP Facility will be payable monthly in arrears and on the maturity date at a per annum rate equal to LIBOR plus 8.00%, subject to a 1.00% floor. Upon an event of default under the DIP Facility, all obligations under the DIP Credit Agreement will bear interest at a rate equal to the then current interest rate plus an additional 2% per annum. The principal amount of the term loans under the DIP Facility is payable in full at maturity. We paid to the lenders under the DIP Credit Agreement a commitment fee equal to 2% of the lenders’ respective commitments thereunder upon entry of the Final DIP Order. Additionally, if the Plan is consummated, the Debtors will pay a backstop fee equal to 3% of the lenders’ respective commitments in the form of new common equity of the reorganized Company, and if the Plan is not consummated, we will pay such fee in cash.

We are subject to certain covenants under the DIP Facility, including, without limitation, restrictions on the incurrence of additional debt, liens, and the making of restricted payments, and compliance with certain bankruptcy-related covenants, in each case as set forth in the DIP Credit Agreement and any order of the Bankruptcy Court approving the DIP Credit Agreement. The DIP Credit Agreement contains customary representations of the Debtors, and provides for certain events of default customary for similar DIP financings. Additionally, the DIP Credit Agreement contains a specific event of default based upon the occurrence of a consecutive 15-day trading period during which natural gas prices as published by NYMEX are less than $1.65 per MMBtu.


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Other Financing Activities

On March 13, 2015, we filed a universal shelf Registration Statement on Form S-3, which was declared effective on April 22, 2015, to enable us to issue securities from time to time, including issuances of common stock in At the Market (“ATM”) offerings. During the year ended December 31, 2015, we sold an aggregate of 56,202,517 shares of our common stock and received aggregate proceeds of $58.2 million net of sales commissions and other fees of $1.3 million through our ATM offering.

On October 9, 2015, we announced that we had suspended monthly cash dividends on all of our outstanding series of preferred stock. The suspension commenced with the monthly cash dividend that would otherwise have been declared and paid for the month ending October 31, 2015 and will continue indefinitely. We accrued dividends for our preferred stock of approximately $7.3 million for the period from October 1, 2015 through the Petition Date. We ceased accruing dividends subsequent to the Petition Date. Accrued dividends payable are presented in “Liabilities subject to compromise” on our consolidated balance sheet as of December 31, 2015.

Upon the suspension of monthly cash dividends on our preferred stock issuances, we became ineligible to issue securities, including issuances of common stock in ATM offerings, under our universal shelf Registration Statement on Form S-3. On November 30, 2015, our common and preferred stock were delisted from the NYSE.

The Plan contemplates no recovery for, and cancellation of, our outstanding common and preferred stock. As a result, the shares of our existing common and preferred stock are expected to be canceled in our Chapter 11 proceedings and will be entitled to no recovery.

Management’s Plans

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, and drilling successes. 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.

Upon our emergence from the Chapter 11 Cases, we believe that our capital resources from existing cash balances, borrowings under our exit financing facility, and anticipated cash flow from operating activities will be adequate to execute our corporate strategies in 2016. However, there are certain risks and uncertainties that could negatively impact our results of operations and financial condition. Sustained declines in prices for commodities may also put downward pressure on cash provided from our operations.

Sources of Cash

For the year ended December 31, 2015, our primary sources of cash were proceeds received from the sales of assets, proceeds from issuances of common stock, and borrowings under our debt agreements. We utilized $39.2 million of proceeds from the sale of assets, $58.2 million from issuances of common stock, $76.9 million of borrowings under our revolving credit facility, and $40.0 million of borrowings under the DIP Credit Facility to fund our acquisitions and drilling program, cash collateralize our outstanding letters of credit, repay debt, and pay $26.5 million in dividends on our preferred stock.

For the year ended December 31, 2014, our primary sources of cash were from operating activities, proceeds 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 Midstream 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.


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The following table summarizes our sources and uses of cash for the periods noted:

 
 
Years Ended December 31,
 
 
2015
 
2014
 
2013
 
 
(in thousands)
Cash flows provided by (used in) operating activities
 
$
25,026

 
$
(18,665
)
 
$
111,711

Cash flows used in investing activities
 
(165,941
)
 
(318,119
)
 
(127,860
)
Cash flows provided by financing activities
 
128,634

 
348,195

 
656

Effect of foreign currency translation
 
(28
)
 
56

 
(417
)
Net increase (decrease) in cash and cash equivalents
 
$
(12,309
)
 
$
11,467

 
$
(15,910
)

Operating Activities

Net cash provided by operating activities for the years ended December 31, 2015 was $25.0 million. Net cash used in operating activities for the year ended December 31, 2014 was $18.7 million, and net cash provided by operating activities for the year ended December 31, 2013 was $111.7 million. The increase in net cash provided by operating activities during 2015 was primarily due to increased available cash from changes in accounts payable and accrued liabilities compared to 2014. Cash used in operating activities for the year ended December 31, 2014 included cash flows used by discontinued operations of $10.3 million, and cash flows provided by operating activities for the year ended December 31, 2013 included cash flows provided by discontinued operations of $73.6 million, respectively.

Investing Activities

Our cash used in investing activities for the year ended December 31, 2015 was $165.9 million, principally from completion of new wells developed during 2014 in the Marcellus and Utica Shales which began producing during 2015. This amount included the payment of expenditures previously accrued related to our 2014 capital expenditure program, as well as a purchase of net leasehold acreage of approximately $12.0 million pursuant to an asset purchase agreement entered into during 2013 with MNW Energy, LLC. These net cash outflows were partially offset by cash proceeds from the sale of assets of $39.2 million.

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 Midstream 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 Midstream 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.

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

During 2015, the significant components of financing activities included $76.9 million of borrowings under our revolving credit facility and $40.0 million of borrowings under the DIP Credit Facility, as well as proceeds from the issuance of shares of common stock. We raised $58.2 million in net proceeds from the sale of common stock under the ATM offering. These increases were partially offset by debt pay-down under our credit facilities and other debt agreements of $16.2 million. In addition, we paid preferred dividends of $26.5 million and paid deferred financing costs of $3.8 million during the year ended December 31, 2015.


63



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.

As of December 31, 2015, we had $599.3 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.

Results of Operations

Our consolidated financial statements reflect the results of operations for Eureka Midstream Holdings for the period from January 1, 2014 up to December 18, 2014 and for the year ended December 31, 2013. We began accounting for our investment in Eureka Midstream Holdings using the equity method of accounting effective December 18, 2014, under which we record our investment in Eureka Midstream Holdings as a single financial caption in the consolidated balance sheet, and our proportionate share in earnings (loss) in Eureka Midstream Holdings is recognized as a single financial caption in the consolidated statement of operations. See “Note 4 - Eureka Midstream Holdings” in our notes to our consolidated financial statements.

The following discussion pertains to our results of operations, including analysis of our 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.

Years ended December 31, 2015, 2014 and 2013

Oil and natural gas sales. Oil and natural gas sales decreased 50.3% for the year ended December 31, 2015 compared to the year ended December 31, 2014, primarily as a result of decreases in average sales prices received, and partially offset by higher production volumes from our Marcellus Shale and Utica Shale wells.
Oil and natural gas sales increased by 21.7% for the year ended December 31, 2014 compared to the year ended December 31, 2013, primarily as a result of higher production volumes from our Marcellus Shale wells and the tie-in of certain wells in the Williston/Bakken fields to the Oneok gas gathering system.

Changes in our oil and natural gas sales are reflected in the following table:
 
Years Ended December 31,
 
( in thousands)
Oil and natural gas sales - 2013
$
220,699

Changes associated with sales volumes
51,155

Changes associated with average sales prices
(3,353
)
Oil and natural gas sales - 2014
268,501

Changes associated with sales volumes
29,252

Changes associated with average sales prices
(164,305
)
Oil and natural gas sales - 2015
$
133,448


64




Oil and natural gas production. Production of oil has declined during the years ended December 31, 2015 and 2014, primarily due to decreased production in the Williston Basin as the result of our divestitures throughout 2014 of non-core properties in the Williston Basin. Production of natural gas and NGLs increased during the year ended December 31, 2015 compared to the year ended December 31, 2014 as a result of new Marcellus Shale and Utica Shale wells that began producing from the Everett Weese, Stewart Winland, WVDNR, and Stalder pads. Production of natural gas and NGLs increased during the year ended December 31, 2014 compared to the year ended December 31, 2013 as a result of new Marcellus wells that began producing from the Collins, Spencer, Ormet, Stalder, and Mills Wetzel pads/units. Changes in our oil and natural gas production are reflected in the following table:
 
Years Ended December 31,
 
2015
 
Change
 
%
 
2014
 
Change
 
%
 
2013
Oil (MBbl)
 
 
 
 
 
 
 
 
 
 
 
 
 
Appalachian Basin
353

 
(60
)
 
(14.5
)%
 
413

 
93

 
29.1
 %
 
320

Williston Basin
739

 
(413
)
 
(35.9
)%
 
1,152

 
(132
)
 
(10.3
)%
 
1,284

Other
2

 
(3
)
 
(60.0
)%
 
5

 
(32
)
 
(86.5
)%
 
37

Total oil
1,094

 
(476
)
 
(30.3
)%
 
1,570

 
(71
)
 
(4.3
)%
 
1,641

Natural gas (MMcf)
 
 
 
 
 
 
 
 
 
 
 
 
 
Appalachian Basin
34,292

 
13,077

 
61.6
 %
 
21,215

 
8,252

 
63.7
 %
 
12,963

Williston Basin
461

 
(85
)
 
(15.6
)%
 
546

 
356

 
187.4
 %
 
190

Other
24

 
(3
)
 
(11.1
)%
 
27

 
(32
)
 
(54.2
)%
 
59

Total natural gas
34,777

 
12,989

 
59.6
 %
 
21,788

 
8,576

 
64.9
 %
 
13,212

NGLs (MBbl)
 
 
 
 
 
 
 
 
 
 
 
 
 
Appalachian Basin
1,196

 
300

 
33.5
 %
 
896

 
458

 
104.6
 %
 
438

Williston Basin
67

 
3

 
4.7
 %
 
64

 
64

 
100.0
 %
 
—

Other
—

 
—

 
—
 %
 
—

 
—

 
—
 %
 
—

Total NGLs
1,263

 
303

 
31.6
 %
 
960

 
522

 
119.2
 %
 
438

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MMcfe
48,919

 
11,951

 
32.3
 %
 
36,968

 
11,282

 
43.9
 %
 
25,686

Total MMcfe/d
134

 
33

 
32.7
 %
 
101

 
31

 
44.3
 %
 
70


Our overall production mix is comprised more heavily of natural gas and NGLs during the year ended December 31, 2015 compared to the same periods in 2014 and 2013, as we have increased our focus on natural gas and NGLs exploration, development and production activities in West Virginia and Ohio. Total production for the years ending December 31, 2015, 2014 and 2013, on an Mcfe basis, was as follows:
 
Years Ended December 31,
 
2015
 
2014
 
2013
Oil
13.4
%
 
25.5
%
 
38.3
%
Natural gas
71.1
%
 
58.9
%
 
51.5
%
NGLs
15.5
%
 
15.6
%
 
10.2
%
Total
100.0
%
 
100.0
%
 
100.0
%


65



Oil and natural gas average prices. Our average sales prices received for oil and natural gas declined during the year ended December 31, 2015 compared to the years ended December 31, 2014 and 2013, which is consistent with overall declines in the commodities markets. Average sales prices received also reflect the impact of basis differentials. The price we receive for our oil and natural gas can be more or less than the average WTI and NYMEX prices for the periods because of adjustments related to delivery location, relative quality, and other factors. Average sales prices received and price differentials for years ending December 31, 2015, 2014, 2013 are shown in the following table:
 
Years Ended December 31,
 
2015
 
Change
 
%
 
2014
 
Change
 
%
 
2013
Oil (per Bbl)
$
39.13

 
$
(44.40
)
 
(53.2
)%
 
$
83.53

 
$
(6.51
)
 
(7.2
)%
 
$
90.04

Differential to WTI
$
(9.55
)
 
$
(0.05
)
 
0.5
 %
 
$
(9.50
)
 
$
(1.53
)
 
19.2
 %
 
$
(7.97
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas (per Mcf)
$
2.00

 
$
(2.19
)
 
(52.3
)%
 
$
4.19

 
$
0.12

 
2.9
 %
 
$
4.07

Differential to NYMEX
$
(0.61
)
 
$
(0.45
)
 
281.3
 %
 
$
(0.16
)
 
$
(0.50
)
 
(147.1
)%
 
$
0.34

 
 
 
 
 
 
 
 
 
 
 
 
 
 
NGLs (per Bbl)
$
16.71

 
$
(31.33
)
 
(65.2
)%
 
$
48.04

 
$
4.43

 
10.2
 %
 
$
43.61

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total average price (per Mcfe)
$
2.73

 
$
(4.53
)
 
(62.4
)%
 
$
7.26

 
$
(1.33
)
 
(15.5
)%
 
$
8.59


Midstream natural gas gathering, processing and marketing. During the year ended December 31, 2013 and up to December 18, 2014, midstream natural gas gathering, processing and marketing revenues and expenses included the revenues and expenses related to Eureka Midstream, TransTex, and Magnum Hunter Marketing. 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 Midstream Holdings, of which Eureka Midstream and TransTex are wholly owned subsidiaries. On December 18, 2014, we deconsolidated Eureka Midstream Holdings and began accounting for our retained interest as an equity method investment. From December 18, 2014 and thereafter, our proportionate share in the earnings of Eureka Midstream Holdings is recognized in “Loss from equity method investments” on the consolidated statements of operations, and our midstream natural gas gathering, processing and marketing revenues and expenses include only the revenues and expenses related to Magnum Hunter Marketing.

Midstream natural gas gathering, processing and marketing revenues decreased during the year ended December 31, 2015 compared to the year ended December 31, 2014. Approximately $30.3 million of the decrease is related to the deconsolidation of Eureka Midstream Holdings, and approximately $66.5 million of the decrease is due to decreased revenues from Magnum Hunter Marketing, primarily as a result of the decision made by a third party customer to begin marketing its own natural gas, which had previously been marketed by Magnum Hunter Marketing on this customer’s behalf. Midstream natural gas gathering, processing and marketing expenses similarly decreased during the year ended December 31, 2015 compared to the year ended December 31, 2014. Approximately $17.8 million of the decrease is related to the deconsolidation of Eureka Midstream Holdings, and approximately $66.3 million of the decrease is related to decreased expenses from Magnum Hunter Marketing.

Midstream natural gas gathering, processing and marketing revenues increased during the year ended December 31, 2014 compared to the year ended December 31, 2013 due primarily to increases in Eureka Midstream revenues 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 Midstream increased throughput volumes by 170.8% or 47.7 MMBtu, from 27.9 MMBtu for the year ended December 31, 2013 to 75.6 MMBtu for the year ended December 31, 2014. Magnum Hunter Marketing revenues also increased during the year ended December 31, 2014 compared to the year ended December 31, 2013 related to a marketing contract with a third party customer, which subsequently began marketing its own natural gas during July 2014, as well as from increased gas and NGLs revenues from the MarkWest processing plant.


66



The following table summarizes our midstream natural gas gathering, processing, and marketing activity for the periods indicated:
 
Years Ended December 31,
 
2015
 
Change
 
%
 
2014
 
Change
 
%
 
2013
 
(in thousands)
Midstream natural gas gathering, processing and marketing revenues
$
1,067

 
$
(96,849
)
 
(98.9
)%
 
$
97,916

 
$
36,738

 
60.1
%
 
61,178

Midstream natural gas gathering, processing and marketing expenses
668

 
(84,096
)
 
(99.2
)%
 
84,764

 
32,665

 
62.7
%
 
52,099

Total midstream natural gas gathering, processing and marketing, net
$
399

 
$
(12,753
)
 
(97.0
)%
 
$
13,152

 
$
4,073

 
44.9
%
 
$
9,079


Oilfield services. Drilling services revenue decreased during the year ended December 31, 2015 compared to the year ended December 31, 2014, primarily due to lower utilization of the fleet of rigs caused by the downturn in commodity prices. For the year ended December 31, 2015, the total effective equipment performance of our drilling rigs was 59% and the utilization rate of our rigs was 60%. Drilling services revenue increased during the year ended December 31, 2014 compared to the year ended December 31, 2013 primarily due to higher utilization of the fleet of rigs. During the year ended December 31, 2014, the total effective equipment performance of our drilling rigs was 97% and our rigs were 100% utilized.

The following table summarizes our oilfield services activity for the periods indicated:
 
Years Ended December 31,
 
2015
 
Change
 
%
 
2014
 
Change
 
%
 
2013
 
(in thousands, except drilling rig revenue days)
Oilfield services revenue
$
18,229

 
$
(4,905
)
 
(21.2
)%
 
$
23,134

 
$
4,703

 
25.5
%
 
$
18,431

Oilfield services expenses
13,984

 
(1,702
)
 
(10.9
)%
 
15,686

 
861

 
5.8
%
 
14,825

Total oilfield services, net
$
4,245

 
$
(3,203
)
 
(43.0
)%
 
$
7,448

 
$
3,842

 
106.5
%
 
$
3,606

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Drilling rig revenue days
1,297

 
(832
)
 
(39.1
)%
 
2,129

 
645

 
43.5
%
 
1,484


Gain (loss) on sale of assets. We recorded a gain on sale of assets in operating expenses of $31.4 million and $2.5 million during the years ended December 31, 2015 and 2014, respectively, and a loss on sale of assets of $44.6 million during the year ended December 31, 2013. The gain on sale of assets for 2015 primarily related to the sale of certain undeveloped and unproven leasehold acreage in Tyler County, West Virginia. 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 per Mcfe decreased during the years ended December 31, 2015 compared to the years ended December 31, 2014 and 2013, respectively, as shown in the following table:
 
Years Ended December 31,
 
2015
 
Change
 
%
 
2014
 
Change
 
%
 
2013
Production costs (in thousands)
$
40,074

 
$
(7,783
)
 
(16.3
)%
 
$
47,857

 
$
1,168

 
2.5
 %
 
$
46,689

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Production costs per Mcfe
$
0.82

 
$
(0.47
)
 
(36.4
)%
 
$
1.29

 
$
(0.53
)
 
(29.1
)%
 
$
1.82



67



The overall decrease in production costs during the year ended December 31, 2015 compared to the year ended December 31, 2014 was primarily due to lower costs per Mcfe, partially offset by increases due to higher production volumes. Production costs increased overall during the year ended December 31, 2014 compared to the year ended December 31, 2013 primarily due to higher production volumes, and partially offset by lower costs per Mcfe, as reflected in the following table:
 
Years Ended December 31,
 
(in thousands)
Production costs - 2013
$
46,689

Changes associated with volumes
20,761

Changes associated with costs
(19,593
)
Production costs - 2014
47,857

Changes associated with volumes
15,209

Changes associated with costs
(22,992
)
Production costs - 2015
$
40,074


Severance taxes and marketing.  Our severance taxes and marketing decreased during the year ended December 31, 2015 compared to the year ended December 31, 2014, due primarily to the decrease in our sales.  Severance taxes and marketing decreased during the year ended December 31, 2014 compared to the year ended December 31, 2013 due primarily to 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. The following table summarizes severance taxes and marketing for the periods indicated: 
 
Years Ended December 31,
 
2015
 
Change
 
%
 
2014
 
Change
 
%
 
2013
Severance taxes and marketing (in thousands)
$
6,917

 
$
(10,427
)
 
(60.1
)%
 
$
17,344

 
$
(938
)
 
(5.1
)%
 
$
18,282

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Severance taxes and marketing per Mcfe
$
0.14

 
$
(0.33
)
 
(70.2
)%
 
$
0.47

 
$
(0.24
)
 
(33.8
)%
 
$
0.71


Transportation, processing, and other related costs. The increases in our transportation, processing, and other related costs during the years ended December 31, 2015 and 2014 compared to the years ended December 31, 2014 and 2013, respectively, are due primarily to increased natural gas and NGL production from our Appalachian properties as additional wells began producing during 2015 and 2014. The following table summarizes transportation, processing, and other related costs for the periods indicated:
 
Years Ended December 31,
 
2015
 
Change
 
%
 
2014
 
Change
 
%
 
2013
Transportation, processing, and other related costs (in thousands)
$
65,606

 
$
22,314

 
51.5
%
 
$
43,292

 
$
20,743

 
92.0
%
 
$
22,549

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Transportation, processing, and other related costs per Mcfe
$
1.34

 
$
0.17

 
14.5
%
 
$
1.17

 
$
0.29

 
33.0
%
 
$
0.88



68



Exploration. We recognize exploration costs, geological and geophysical costs, and unproved property impairments and leasehold expiration as exploration expense. Leasehold impairments relate to leases that expired undrilled or are expected to expire and we do not plan to develop. Exploration expense recorded for the years ended December 31, 2015, 2014, and 2013 is reflected in the following table:
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(in thousands)
Leasehold impairments:
 
 
 
 
 
   Williston Basin
$
45,811

 
$
103,147

 
$
89,167

   Appalachian Basin
11,501

 
9,978

 
6,773

Western Kentucky
75

 
3,820

 
3,047

   South Texas
127

 
—

 
—

Leasehold impairments
57,514

 
116,945

 
98,987

Geological and geophysical costs
2,317

 
1,564

 
1,402

   Total exploration expense
$
59,831

 
$
118,509

 
$
100,389

 
 
 
 
 
 
Total exploration expense per Mcfe
$
1.22

 
$
3.21

 
$
3.91


Impairment of proved oil and natural gas properties. We review our proved oil and natural gas properties for impairment bi-annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property, based on an analysis of undiscounted future cash flows. If the carrying amount of our oil and natural gas properties exceeds the estimated undiscounted future cash flows, we write down the carrying amount of such 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. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value. The following table summarizes impairments of proved oil and natural gas properties for the periods indicated:
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(in thousands)
Williston Basin
$
64,165

 
$
261,270

 
$
8,498

Appalachian Basin
207,340

 
6,001

 
1,151

Western Kentucky
3,783

 
33,811

 
40,043

South Texas
87

 
194

 
319

Total impairment of proved oil and gas properties
$
275,375

 
$
301,276

 
$
50,011

 
 
 
 
 
 
Total impairment of proved oil and gas properties per Mcfe
$
5.63

 
$
8.15

 
$
1.95


Depletion, depreciation, amortization, and accretion. Our depletion, depreciation, amortization and accretion expense (“DD&A”), decreased during the year ended December 31, 2015 compared to the year ended December 31, 2014 primarily a result of our divestiture of our non-core properties in the Williston Basin. Our DD&A increased during the year ended December 31, 2014 compared to 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. The following table summarizes our DD&A for the periods indicated:
 
Years Ended December 31,
 
2015
 
Change
 
%
 
2014
 
Change
 
%
 
2013
DD&A (in thousands)
$
132,804

 
$
(14,064
)
 
(9.6
)%
 
$
146,868

 
$
39,483

 
36.8
 %
 
$
107,385

 
 
 
 
 
 
 
 
 
 
 
 
 
 
DD&A per Mcfe
$
2.71

 
$
(1.26
)
 
(31.7
)%
 
$
3.97

 
$
(0.21
)
 
(5.0
)%
 
$
4.18



69



General and administrative. Our general and administrative expenses (“G&A”) decreased for the year ended December 31, 2015 compared to the year ended December 31, 2014. The decrease is primarily attributable to our efforts to further reduce G&A through cutting legal costs, minimizing reliance on outside consultants and temporary staffing, and the closing of our offices in Denver, Colorado and Calgary, Alberta, among other factors. Our G&A expenses increased overall during the year ended December 31, 2014 compared to the year ended December 31, 2013 mainly due to a one-time, non cash charge related to the Letter Agreement with MSI, in which our capital account with Eureka Midstream 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 Midstream in connection with certain of its fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects. The following table reflects significant components of our general and administrative expenses for the periods indicated:
 
Years Ended December 31,
 
2015
 
Change
 
%
 
2014
 
Change
 
%
 
2013
 
(in thousands)
Professional fees
$
19,785

 
$
(4,244
)
 
(17.7
)%
 
$
24,029

 
$
(2,728
)
 
(10.2
)%
 
$
26,757

Salaries and personnel costs
9,823

 
(13,902
)
 
(58.6
)%
 
23,725

 
18

 
0.1
 %
 
23,707

Non-cash stock compensation expense
6,615

 
(6,758
)
 
(50.5
)%
 
13,373

 
(2,106
)
 
(13.6
)%
 
15,479

Non-cash reduction of capital account in Eureka Midstream Holdings
—

 
(32,569
)
 
(100.0
)%
 
32,569

 
32,569

 
100.0
 %
 
—

Other general and administrative expenses
11,037

 
(3,954
)
 
(26.4
)%
 
14,991

 
(1,527
)
 
(9.2
)%
 
16,518

Total general and administrative expenses
$
47,260

 
$
(61,427
)
 
(56.5
)%
 
$
108,687

 
$
26,226

 
31.8
 %
 
$
82,461

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total general and administrative expenses per Mcfe
$
0.97

 
$
(1.97
)
 
(67.0
)%
 
$
2.94

 
$
(0.27
)
 
(8.4
)%
 
$
3.21


Interest expense, net. Interest expense, net of interest income, increased by 15.2% compared to the year ended December 31, 2014, primarily due to our higher average debt level during the year ended December 31, 2015. This increase was partially offset by lower amortization and write-off of deferred financing costs during the year ended December 31, 2015. The 19.3% increase in net interest expense during the year ended December 31, 2014 compared to the year ended December 31, 2013 related to a higher average debt level, as well as higher amortization and write-off of deferred financing costs, as reflected in the following table:
 
Years Ended December 31,
 
(in thousands)
Interest expense, net 2013
$
72,356

Changes associated with higher debt levels
9,090

Changes associated with amortization and write-off of deferred financing costs
4,861

Interest expense, net 2014
86,307

Changes associated with higher debt levels
14,247

Changes associated with amortization and write-off of deferred financing costs
(1,152
)
Interest expense, net 2015
$
99,402


For the year ended December 31, 2015, interest expense includes the write-off of $1.1 million in unamortized deferred financing costs related to the July 10, 2015 amendment of the MHR Senior Revolving Credit Facility and the write-off of $0.9 million in unamortized deferred financing costs related to the November 3, 2015 replacement of the MHR Senior Revolving Credit Facility with the Senior Secured Bridge Financing Facility. On the Petition Date, the Debtors ceased accruing interest on unsecured and undersecured liabilities subject to compromise. Contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $2.8 million, representing interest expense from the Petition Date through December 31, 2015.
 
For the year ended December 31, 2014, interest expense incurred on debt includes a $2.2 million prepayment penalty incurred by Eureka Midstream as a result of its early termination of the Original Eureka Midstream 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

70



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 amendment of the MHR Senior Revolving Credit Facility.

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. No interest was capitalized during the year ended December 31, 2015. We capitalize interest on projects lasting six months or longer.

Gain (loss) on derivative contracts, net.  We do not designate our derivative instruments as hedges. 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,
 
2015
 
2014
 
2013
 
(in thousands)
Commodity derivatives
 
 
 
 
 
Realized loss on settled transactions
$
2,449

 
$
1,306

 
$
(8,216
)
Unrealized gain (loss) on open contracts
2,512

 
18,236

 
869

   Total gain (loss) on commodity derivatives
4,961

 
19,542

 
(7,347
)
Financial derivatives
 
 
 
 
 
Loss on embedded derivatives
(75
)
 
(91,796
)
 
(17,927
)
Gain (loss) on derivative contracts, net
$
4,886

 
$
(72,254
)
 
$
(25,274
)

We have no remaining open commodity derivatives contracts as of December 31, 2015.

Prior to October 3, 2014, we had preferred stock embedded derivative liabilities resulting from certain conversion features, redemption options, and other features of our Eureka Midstream Holdings Series A Preferred Units. The Eureka Midstream Holdings Series A Preferred Units were converted at fair value to a new class of equity of Eureka Midstream 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 Midstream Holdings Series A Preferred Units.

The change in expected term was the result of management’s assessment of the likely time horizon for which a liquidity event would occur resulting in conversion of the Eureka Midstream Holdings Series A Preferred Shares to Class A Common Units of Eureka Midstream 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 adoption during May 2014 of Eureka Midstream 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 interest in Eureka Midstream Holdings, and which closed in October 2014. Management considered the purchase price of that transaction in its determination of total enterprise value.

At December 31, 2014, we 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. As of December 31, 2015, we recognized no remaining fair value associated with this embedded derivative asset. An unrealized loss of $75 thousand, $4 thousand, and $185 thousand is recorded for this embedded derivative instrument during the years ended December 31, 2015, 2014, and 2013, respectively.

Gain on deconsolidation of Eureka Midstream Holdings. On October 3, 2014, MSI acquired all of the Series A Preferred Units and Class A Common Units of Eureka Midstream Holdings held by Ridgeline, which represented approximately 40.9% of the then outstanding equity units of Eureka Midstream Holdings. As a result of the New LLC Agreement becoming effective on October 3, 2014, the Eureka Midstream 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”), which we accounted for, initially at fair value, as a preferred

71



equity interest. During the fourth quarter of 2014, MSI made further capital contributions to Eureka Midstream Holdings for which it received additional Series A-2 Units from Eureka Midstream Holdings, and MSI also purchased an approximate 5.5% equity interest in Eureka Midstream Holdings from us, bringing MSI’s ownership interest in Eureka Midstream 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 Midstream Holdings. We recognized a gain of $510 million from the deconsolidation of Eureka Midstream Holdings on December 18, 2014 as a result of these transactions. See “Note 4 - Eureka Midstream Holdings” to our consolidated financial statements.

Gain on dilution of interest in Eureka Midstream Holdings. We accounted for the March 31, 2015 MSI capital contributions, the issuance of additional Series A-2 Units by Eureka Midstream Holdings, and the September 30, 2015 expiry of the MHR Contribution Deadline, in accordance with the subsequent measurement provision of ASC Topic 323, Investments - Equity Method and Joint Ventures, which requires us to recognize a gain or loss on the dilution of our equity interest as if we had sold a proportionate interest in Eureka Midstream Holdings. During the year ended December 31, 2015, we recognized a pre-tax gain of $4.6 million based on the difference between the carrying value of our Series A-1 Units and the proceeds received by Eureka Midstream Holdings for the issuance of additional Series A-2 Units to MSI which resulted in permanent dilution of our equity interest in Eureka Midstream Holdings. The gain included our proportionate decrease in the equity method basis difference which was reduced by $7.5 million based on the change in our ownership in the net assets of Eureka Midstream Holdings after giving effect to the dilution of our interest as a result of the unit issuance.

Loss from equity method investments. We record our share of the underlying net loss of our equity method investees in loss from equity method investments. For all periods presented, we held an equity method investment in GreenHunter Resources, Inc. (“GreenHunter”), a related party. During 2013 and up to December 18, 2014, we held an equity method investment in TranStar Gas Processing, LLC (“TranStar”) through our formerly consolidated subsidiary Eureka Midstream Holdings. On December 18, 2014, we deconsolidated Eureka Midstream Holdings and began accounting for our retained interest as an equity method investment.

The recognition of our interest in Eureka Midstream Holdings at fair value upon deconsolidation at December 18, 2014 resulted in a basis difference between the carrying value of our investment in Eureka Midstream Holdings and our proportionate share in net assets of Eureka Midstream Holdings. Amortization of this basis difference is included in loss from equity method investments. As of September 30, 2015, we recognized a loss related to the downward adjustment of our Series A-1 Units in Eureka Midstream Holdings as a result of not funding certain contributions to Eureka Midstream Holdings. As of November 3, 2015, we recorded impairment of our equity interest in Eureka Midstream Holdings in order to write down the carrying value of the investment to fair value as a result of our determination that the investment no longer met the criteria for classification as a discontinued operation as of that date. See “Note 4 - Eureka Midstream Holdings” to our consolidated financial statements for additional discussion of our equity method investment in Eureka Midstream Holdings.

The following table summarizes the components of loss from equity method investments for the periods indicated:

 
 
Years Ended December 31,
 
 
2015
 
2014
 
2013
 
 
(in thousands)
Equity in losses of TranStar
 
$
—

 
$
(347
)
 
$
(265
)
 
 
 
 
 
 
 
Equity in losses of GreenHunter
 
(464
)
 
(590
)
 
(729
)
 
 
 
 
 
 
 
Magnum Hunter’s interest in Eureka Midstream Holding’s net income (loss)
 
8,490

 
(101
)
 
—

Basis difference amortization
 
(6,265
)
 
—

 
—

Loss on downward adjustment of units
 
(7,664
)
 
—

 
—

Impairment upon reclassification from discontinued operations to continuing operations
 
(180,254
)
 
—

 
—

Equity in losses of Eureka Midstream Holdings
 
(185,693
)
 
(101
)
 
—

 
 
 
 
 
 
 
Total loss from equity method investments
 
$
(186,157
)
 
$
(1,038
)
 
$
(994
)



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Reorganization items, net. Reorganization items represent the direct and incremental costs of being in bankruptcy, such as professional fees, pre-petition liability claim adjustments and losses related to terminated contracts that are probable and can be estimated. Unamortized deferred financing costs, premiums, and discounts associated with debt classified as liabilities subject to compromise are expensed to reorganization items in order to reflect the expected amounts of the probable allowed claims. During the year ended December 31, 2015, reorganization items consisted of the following:
 
Year Ended December 31, 2015
 
(in thousands)
Professional fees
$
4,118

Debt issuance costs
9,036

Loss on adjustments to carrying value of Senior Notes
12,533

Loss on adjustments to carrying value of Second Lien Term Loan
15,452

Total reorganization items
$
41,139


Income tax benefit. We recorded no income tax or benefit during the years ended December 31, 2015 and 2014. We 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. We recorded less than our expected deferred tax benefit at statutory rates for all periods presented because of increases in its deferred tax asset valuation allowance. As of December 31, 2015 and 2014, we have a full valuation allowance on all deferred tax assets.

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, we adopted a plan to divest all of our interests in WHI Canada. We reflected these operations as discontinued operations, net of taxes, for all periods presented. We closed on the sale of our interests in WHI Canada during the second quarter of 2014. Tax benefit recognized as a result of discontinued operations was $11.8 million for the year ended December 31, 2013. There was no tax benefit or expense as a result of discontinued operations for the year ended December 31, 2014. The following table summarizes the 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. We recognized no gain or loss on disposal of discontinued operations for the year ended December 31, 2015. The following table summarizes the loss on disposal of discontinued operations for the years ended December 31, 2014, and 2013:
 
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 of $3.7 million and $1.0 million for the years ended December 31, 2014 and 2013, respectively, represented 12.5% of the net income or loss incurred by our subsidiary, PRC Williston, and 1.9% of the net income or loss incurred by our then majority-owned subsidiary, Eureka Midstream Holdings. 

Prior to July 24, 2014, we owned 87.5% of the equity interests in PRC Williston, LLC (“PRC Williston”), which sold substantially all of its assets on December 30, 2013. On July 24, 2014, we 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, we now own 100% of the equity interests in PRC Williston and have 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 and 2015.

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On October 3, 2014, all of the Eureka Midstream 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 Midstream Holdings in our consolidated balance sheet. As a result of the deconsolidation of Eureka Midstream Holdings in December 2014, we derecognized the non-controlling interests attributed to Eureka Midstream Holdings as part of the gain on deconsolidation during the fourth quarter of 2014.

Dividends on preferred stock. Total dividends on our preferred stock were approximately $33.8 million, $54.7 million, and $56.7 million for the years ending December 31, 2015, 2014, and 2013, respectively. The Series C Preferred Stock had a stated value of $100.0 million at both December 31, 2015 and 2014, and carries a cumulative dividend rate of 10.25% per annum. The Series D Preferred Stock had a stated value of $221.2 million at both December 31, 2015 and 2014, and carries a cumulative dividend rate of 8.0% per annum. The Series E Preferred Stock had a stated value of $95.1 million at both December 31, 2015 and 2014, and carries a cumulative dividend rate of 8.0% per annum. During 2014, all of the Eureka Midstream Holdings Series A Units were converted into a new class of equity.

On October 9, 2015, we announced that we had suspended monthly cash dividends on all of our outstanding series of preferred stock. The suspension commenced with the monthly cash dividend that would otherwise have been declared and paid for the month ending October 31, 2015 and will continue indefinitely. We accrued dividends for our preferred stock of approximately $7.3 million for the period from October 1, 2015 through the Petition Date. We ceased accruing dividends subsequent to the Petition Date. Accrued dividends payable are presented in “Liabilities subject to compromise” on our consolidated balance sheet as of December 31, 2015.


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Related Party Transactions

The following table sets forth the related party transaction activities for the years ended December 31, 2015, 2014 and 2013, respectively:
 
 
 
Years Ended 
 
 
 
December 31,
 
 
 
2015
 
2014
 
2013
 
 
 
(in thousands)
GreenHunter
 
 
 
 
 
 
 
Production costs (1)
 
$
3,675

 
$
4,973

 
$
3,315

 
Midstream natural gas gathering, processing, and marketing (1)
 
$
—

 
$
652

 
$
—

 
Oilfield services (1)
 
$
298

 
$
—

 
$
—

 
General and administrative (1)
 
$
23

 
$
44

 
$
13

 
Interest income (2)
 
$
113

 
$
154

 
$
205

 
Miscellaneous income (expense) (2)
 
$
(620
)
 
$
220

 
$
220

 
Loss from equity method investment (2)
 
$
464

 
$
590

 
$
730

 
Capitalized costs incurred (1)
 
$
508

 
$
3,149

 
$
—

Pilatus Hunter, LLC (4)
 
 
 
 
 
 
 
General and administrative
 
$
143

 
$
281

 
$
166

Eureka Midstream Holdings (3)
 
 
 
 
 
 
 
Oil and natural gas sales
 
$
347

 
$
—

 
$
—

 
Production costs
 
$
1,181

 
$
—

 
$
—

 
Transportation, processing, and other related costs
 
$
24,865

 
$
353

 
$
—

 
Oilfield services
 
$
34

 
$
—

 
$
—

 
General and administrative
 
$
8

 
$
32,569

 
$
—

 
Gain on deconsolidation of Eureka Midstream Holdings, LLC
 
$
—

 
$
509,563

 
$
—

 
Gain on dilution of interest in Eureka Midstream Holdings, LLC
 
$
4,601

 
$
—

 
$
—

 
Loss from equity method investment
 
$
185,693

 
$
448

 
$
—

 
Loss on extinguishment of Eureka Midstream Holdings Series A Preferred Units
 
$
—

 
$
51,692

 
$
—

 
Capitalized costs incurred
 
$
121

 
$
—

 
$
—

Classic Petroleum (5)
 
 
 
 
 
 
 
Capitalized costs incurred
 
$
206

 
$
1,495

 
$
—

Kirk Trosclair Enterprises, LLC (6)
 
 
 
 
 
 
 
General and administrative
 
$
169

 
$
—

 
$
—

_________________________________
(1)
GreenHunter is an entity of which Gary C. Evans, our Chairman and CEO, is the Chairman and a major shareholder. Triad Hunter and VIRCO, our wholly owned subsidiaries, receive services related to brine water and rental equipment from GreenHunter and certain affiliated companies. We had approximately $66,000 of accounts receivable from GreenHunter which was fully reserved as of December 31, 2015.

(2)
On February 17, 2012, we sold our wholly owned subsidiary, Hunter Disposal, to GreenHunter Water, LLC (“GreenHunter Water”), a wholly owned subsidiary of GreenHunter.  We 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”. We have recorded interest income as a result of the note receivable from GreenHunter. Also as a result of this transaction, we have an equity method investment in GreenHunter that is included in derivatives and investment in affiliates - equity method and an available for sale investment in GreenHunter included in investments.  Miscellaneous income (expense) includes other than temporary impairment loss on the GreenHunter available for sale security of $0.8 million for the year ended December 31, 2015. On March 1, 2016, GreenHunter and certain of its subsidiaries filed petitions for reorganization under the Bankruptcy Code. See “Note 10 - Investments and Derivatives” for additional information.

(3)
Following a sequence of transactions up to and including, December 18, 2014, we no longer held a controlling financial interest in Eureka Midstream Holdings. We deconsolidated Eureka Midstream Holdings on December 18, 2014 and account for our retained interest as of December 31, 2015 and 2014 under the equity method of accounting. See “Note 4 - Eureka Midstream Holdings” and “Note 10 - Investments and Derivatives”.

(4)    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.


75



(5)
Classic Petroleum, Inc. is an entity owned by the brother of James W. Denny, III, our former Executive Vice President and President of our Appalachian Division. Triad Hunter received land brokerage services from Classic Petroleum, Inc., including courthouse abstracting, contract negotiations, GIS mapping and leasing services.

(6)
On July 18, 2014, we entered into a consulting agreement with Kirk J. Trosclair, a former executive of Alpha Hunter Drilling, our wholly owned subsidiary. Mr. Trosclair ceased employment with us 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, 2015, we paid Mr. Trosclair $169,000, which includes reimbursement of expenses incurred on our behalf, and recognized $163,423 in stock compensation expense.

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. 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 provided a 50% credit for all services performed under the agreement until the prepayment amount was utilized in full, which occurred during the first half of 2015.

As of December 31, 2015, we had a note receivable from GreenHunter with an outstanding principal balance of approximately $680,300 which was fully reserved as of December 31, 2015.  Under the terms of the promissory note, GreenHunter is required to make quarterly payments to us  comprised of principal of $137,500 and accrued interest through the maturity of the note in February 2017. Under the terms of the note, failure to pay timely is considered an event of default. As of March 31, 2015, GreenHunter was past due on principal and interest payments in aggregate of $168,437, which were due on February 17, 2015. On May 4, 2015, GreenHunter made this past due principal and interest payment of $168,437. As of December 31, 2015, GreenHunter was current with its principal and interest payments on the promissory note; however, GreenHunter did not make the principal and interest payment due on February 17, 2016, and on March 1, 2016, GreenHunter and certain of its subsidiaries filed voluntary petitions for reorganization under the Bankruptcy Code. Amounts receivable under the promissory note have the status of a general unsecured claim in GreenHunter’s bankruptcy proceeding.

As of December 31, 2013, Mr. Evans, our Chairman and Chief Executive Officer, held 27,641 Class A Common Units of Eureka Midstream Holdings. On October 3, 2014, in connection with the New LLC Agreement, these Class A Common Units were converted into Series A-1 Units. As of December 31, 2014 and 2015, Mr. Evans also held 250,049 Class B Common Units of Eureka Midstream Holdings pursuant to the Eureka Midstream Holdings Plan, of which none were vested at December 31, 2014 and 50,009 of which were vested at December 31, 2015.

Triad Hunter and Eureka Midstream 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 Midstream Holdings for which Triad Hunter has committed to certain minimum reservation fees. As of October 31, 2015, Triad Hunter owed Eureka Midstream approximately $10.7 million in past due gathering fees under the Gas Gathering Services Agreement. On November 5, 2015, we received a demand notice from MSI, on behalf of Eureka Midstream, demanding adequate assurance of performance of security in the amount of approximately $20.8 million in connection with past due gathering fees. In accordance with the demand notice, Eureka Midstream suspended gas gathering services on November 10, 2015, requiring us to temporarily shut-in approximately 40 wells located in West Virginia. On November 19, 2015, we agreed to, among other things, pay $5.0 million to Eureka Midstream. Eureka Midstream lifted the suspension of gas gathering services and we began the process of returning all of the shut-in wells to production. In connection with the Chapter 11 Cases, we agreed to assume the gathering agreement with Eureka Midstream, subject to certain agreed upon amendments. These amendments will, among other things, modify certain of the reservation fees and commodity fees that Triad Hunter pays to Eureka Midstream and provide certain volume credits to Triad Hunter. See “Note 18 - Commitments and Contingencies” for further discussion of the gas gathering and processing agreements with Eureka Midstream.

In addition, we entered into a Services Agreement with Eureka Midstream Holdings on March 20, 2012, and amended on September 15, 2014, under which we agreed to provide administrative services to Eureka Midstream Holdings related to its operations. The terms of the Services Agreement provide that we will receive an administrative fee of $500,000 per annum and a personnel services fee equal to our 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 that perform service for Eureka Midstream Holdings and its subsidiaries and for whom we bill a personnel services fee, are expected to become employees of Eureka Midstream Holdings or a subsidiary of Eureka Midstream Holdings. Upon the deconsolidation of Eureka Midstream Holdings on December 18, 2014, Eureka Midstream Holdings and its subsidiaries became related parties of the Company.


76



Contractual Commitments

The following table summarizes our contractual commitments as of December 31, 2015 (in thousands):

Contractual Obligations
 
Total
 
2016
 
2017-2018
 
2019-2020
 
After 2020
Long-term debt (1)
 
$
1,060,640

 
$
1,060,640

 
$
—

 
$
—

 
$
—

Interest on long-term debt (2)
 
22,404

 
22,404

 
—

 
—

 
—

Gas transportation and compression contracts (3)
 
236,573

 
22,562

 
45,034

 
45,034

 
123,943

Asset retirement obligations (4)
 
28,662

 
1,464

 
9,847

 
3,420

 
13,931

Operating lease obligations
 
1,300

 
605

 
642

 
53

 
—

Total
 
$
1,349,579

 
$
1,107,675

 
$
55,523

 
$
48,507

 
$
137,874

________________________________
(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, 2015 on the debt facilities in place as of December 31, 2015. This results in a weighted average per annum interest rate of 8.89%.
(3) 
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.

No dividends on our preferred securities 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.

Upon the reorganized Company’s emergence from bankruptcy, a substantial portion of our outstanding debt as of December 31, 2015 is expected to be converted into new common equity of the reorganized Company. In addition, through the contract assumption and rejection process under the Chapter 11 Cases, the Debtors were able to successfully renegotiate approximately a dozen midstream and downstream contracts, pursuant to which the reorganized Company will be entitled to lower gas gathering rates, gas processing rates, and liquids processing rates. The Debtors continue to review and analyze their contractual obligations and retain the right, until eight days following the Effective Date, to move contracts between the schedule of assumed contracts and the schedule of rejected contracts.

MNW Lease Acquisitions

On August 12, 2013, we entered into an asset purchase agreement with MNW, referred to herein as the “MNW Purchase Agreement”. 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, we 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, 2015, 2014, and 2013, we purchased a total of 2,665, 16,456, and 5,922 net leasehold acres, respectively, from MNW for $12.0 million, $67.3 million and $24.6 million, respectively, in multiple closings, and also released $0.4 million in escrowed funds, for a total disbursement to MNW of approximately $104.3 million. As of December 31, 2015, under the asset purchase agreement, we have now acquired a total of approximately 25,044 net leasehold acres from MNW, or approximately 78.3% of the approximately 32,000 total net leasehold acres originally anticipated under the asset purchase agreement.

We listed the MNW Purchase Agreement on our Schedule of Rejected Executory Contracts that we filed with the Bankruptcy Court, as an exhibit to a supplement to the Plan, on March 14, 2016. Accordingly, on the Effective Date the MNW Purchase Agreement is expected to be terminated, and we do not expect that we will acquire any of the remaining net leasehold acres.

Commitments for Firm Transportation

Throughout 2014 and 2015, 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

77



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 Midstream. 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 Midstream and Triad Hunter were both subsidiaries of the Company. Upon the deconsolidation of Eureka Midstream Holdings on December 18, 2014, Eureka Midstream became a related party. As of December 31, 2015, Triad Hunter and Eureka Midstream were parties to seven individual transaction confirmations with terms ranging from eight to fourteen years. Triad Hunter’s maximum daily quantity committed was 260,000 MMBtu per day at an aggregate reservation fee of $1.05 per MMBtu. Triad Hunter’s remaining obligation under the individual transaction confirmations was $172.8 million as of December 31, 2015.

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 was scheduled to commence on the date the pipeline project is available for service, currently anticipated to be in early 2017, and would 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 would have had minimum annual contractual obligations for reservation charges of approximately $12.8 million over the 15 year term of the agreement.

In October 2015, Triad Hunter was 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. On February 19, 2016, however, we filed a motion with the Bankruptcy Court seeking to reject the TGT Transportation Services Agreement. On March 10, 2016, the Bankruptcy Court held a hearing on the motion. At the March 10, 2016 hearing, the Debtors and TGT announced a settlement agreement under which all executory contracts related to the TGT Transportation Services Agreement will be rejected and all other related contracts will be terminated, and TGT will be entitled to an Allowed General Unsecured Claim (as defined in the Plan) in an amount of $15 million. The Bankruptcy Court approved the related settlement motion on March 30, 2016.

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. In connection with the Chapter 11 Cases, we agreed to assume the REX Transportation Services Agreement, subject to certain agreed upon amendments. Among other things, these amendments reduced Triad Hunter’s firm transportation volume commitment from 100,000 MMBtu per day to 50,000 MMBtu per day. 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 $8.7 million over the 15 year term of the agreement.

Triad Hunter is required to provide credit support to REX under the provisions of the REX Transportation Services Agreement, which may include letters of credit or specified cash collateral. This credit support is required to demonstrate Triad Hunter’s ability to pay the monthly reservation charges to REX upon completion and the entry into service of the respective pipeline extension projects. In November 2014, Triad Hunter posted a $36.9 million letter of credit in accordance with the provisions of the REX Transportation Services Agreement. On and effective as of November 3, 2015, the letter of credit was cash collateralized in connection with the Senior Secured Bridge Financing Facility. As a result of the amendments to the REX Transportation Services Agreement entered into in connection with the Chapter 11 Cases, the amount of Triad Hunter’s posted letter of credit will be reduced by approximately $2.8 million every three months until the posted letter of credit amount is reduced to $20 million, subject to further reduction five years following the effective date of the FTA.

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, 2015, 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.


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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 2 - Summary of Significant Accounting Policies” to our consolidated financial statements.

Consolidation and Deconsolidation of Subsidiaries

The consolidated financial statements include our accounts and accounts of the entities in which we hold a controlling financial interest. All significant intercompany balances and transactions are eliminated in consolidation. We deconsolidate entities in which we no longer hold a controlling financial interest as of the date control is lost and recognize 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 our 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 we are able to exercise significant influence but not control are accounted for under the equity method of accounting. Under the equity method of accounting, our 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 our investment balance. When an investee accounted for using the equity method issues its own shares, or when we sell a portion of our interest in the investee that results in a reduction in our interest in the investee, a gain or loss is recognized equal to the proportionate change in our 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. We evaluated our investment in Eureka Midstream Holdings and determined that while the investment had declined in value, the decline was not other-than-temporary, and no impairment was required as of December 31, 2015.

Upon the deconsolidation of Eureka Midstream Holdings on December 18, 2014, we remeasured our retained interest in Eureka Midstream Holdings at fair value in accordance with the derecognition provisions of ASC Topic 810, Consolidation. See “Note 4 - Eureka Midstream Holdings” and “Note 9 - Fair Value of Financial Instruments” to our consolidated financial statements. Effective June 2015, we reclassified our equity method investment in Eureka Midstream Holdings to assets of discontinued operations. As of November 3, 2015, we determined that the planned divestiture no longer met the criteria for classification as a discontinued operation, and remeasured the carrying value of our equity method investment in Eureka Midstream Holdings at fair value. See “Note 5 - Acquisitions, Divestitures, and Discontinued Operations” and “Note 9 - Fair Value of Financial Instruments” to our consolidated financial statements.

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.


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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.

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

Asset retirement obligations (“ARO”) primarily represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the projected end of their productive lives, in accordance with applicable federal, state and local laws. We determined our 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.


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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.

Derivative Instruments and Commodity Derivative Activities

At various times, we have used commodity and financial derivative instruments, typically options and swaps, to manage the risk associated with fluctuations in oil and gas prices. 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.” 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 value 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 fair value of derivatives are currently recognized in the statement of operations unless specific commodity derivative hedge accounting criteria are met and such strategies are designated. We have historically not designated our derivative instruments as cash-flow hedges.

We also have 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 Midstream 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 9 - Fair Value of Financial Instruments”, “Note 10 - Investments and Derivatives”, and “Note 14 - Redeemable Preferred Stock” to our consolidated financial statements.

Share-Based Compensation

We estimate the fair value of share-based payment awards made to employees and directors, including stock options, restricted stock and matching contributions of stock to employees under our employee stock ownership plan, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. Awards that vest only upon achievement of performance criteria are recorded only when achievement of the performance criteria is considered probable. We 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 we have 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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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. We had no uncertain tax positions at December 31, 2015 or 2014.

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 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: (i) identify the contract(s) with a customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) 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. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the effective date of ASU 2014-09 for all entities by one year. As such, this amendment is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those reporting periods. The guidance allows for either a “full retrospective” adoption or a “modified retrospective” adoption, and earlier application is permitted as of annual reporting periods beginning after December 14, 2016, including interim reporting periods within that reporting period. We are currently evaluating the adoption methods and the impact of this ASU on our 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 adverse 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. Examples of adverse conditions and events that may raise substantial doubt about an entity’s ability to continue as a going concern include, but are not limited to, negative financial trends (such as recurring operating losses, working capital deficiencies, or insufficient liquidity), a need to restructure outstanding debt to avoid default, and industry developments (such as declining commodity prices and regulatory changes).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. We adopted this ASU during the period ended March 31, 2016.

In April 2015, the FASB issued ASU 2015-03, Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this update. This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that

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have not been previously issued. As of December 31, 2015, we had no remaining debt issuance costs on our consolidated balance sheet.

In April 2015, the FASB issued ASU 2015-04, Intangibles - Goodwill and Other - Internal-Use Software: Customer’s Accounting for Fees Paid in a Cloud Computing Agreement. This update provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. This update does not change GAAP for a customer’s accounting for service contracts. This amendment is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. Early adoption is permitted for all entities, either prospectively to all arrangements entered into or materially modified after the effective date, or retrospectively. We have several cloud computing arrangements and are currently evaluating the impact of this ASU on our consolidated financial statements and financial statement disclosures.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which amends existing guidance on income taxes to require the classification of all deferred tax assets and liabilities as non-current on the balance sheet. This amendment is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016, with early adoption permitted, and the guidance may be applied either prospectively or retrospectively. We do not expect this ASU to have a material impact on our consolidated financial statements.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The core principle of Topic 842 is that a lessee should recognize the assets and liabilities that arise from leases. The ASU will require lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee‘s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Under the new guidance, lessor accounting is largely unchanged. Certain targeted improvements were made to align, where necessary, lessor accounting with the lessee accounting model and Topic 606, Revenue from Contracts with Customers. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. The ASU is effective for public companies for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact of this ASU on our 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

Our most significant market risk relates to the market prices for natural gas, crude oil, and NGLs. Continued declines in market prices for natural gas, crude oil, and NGLs have resulted in lower realized sales prices for our production during the year ended December 31, 2015. Further declines could impact the extent to which we develop portions of our 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.

Our risk-management policies provide for the use of derivative instruments to manage commodity price risks. We may enter into, and have in the past periodically entered 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 have not historically elected to use hedge accounting for our commodity derivative instruments.

We had no remaining open commodity derivatives as of December 31, 2015. On May 7, 2015, we obtained consent under the MHR Senior Revolving Credit Facility to terminate our open commodity derivative positions. We received approximately $11.8 million in cash proceeds from the termination of the majority of our open commodity derivative positions that were terminated on May 7, 2015. On November 2, 2015, we terminated our open commodity derivative positions with Bank of Montreal and received approximately $0.9 million in cash proceeds. On December 31, 2015, our commodity derivative positions with Citibank, N.A. expired.

The following table summarizes the gains and losses on settled and open commodity derivative contracts for the years ended December 31, 2015, 2014 and 2013:

 
For the Year Ended December 31,
 
2015
 
2014
 
2013
 
(in thousands)
Gain (loss) on settled transactions
$
2,449

 
$
1,306

 
$
(8,216
)
Gain on open contracts
2,511

 
18,237

 
869

Total gain (loss), net
$
4,960

 
$
19,543

 
$
(7,347
)

See “Note 10 - Investments and Derivatives” in the accompanying consolidated financial statements for additional information on derivative instruments.

Interest Rate Risk

Borrowings under the Senior Secured Bridge Financing Facility and the Debtor-in-Possession Credit Facility are subject to variable interest rates. The balance of our long-term debt on our consolidated balance sheet is subject to fixed interest rates. A 10% increase or decrease in interest rates would increase or decrease interest expense by approximately $58,000 for the year ended December 31, 2015.


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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 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 $16,000 as of December 31, 2015.



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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
Dallas, Texas

We have audited the accompanying consolidated balance sheets of Magnum Hunter Resources Corporation (Debtor-in-Possession) as of December 31, 2015 and 2014 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, 2015. 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 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.

As discussed in Note 1 to the consolidated financial statements, on December 15, 2015 the Company filed for protection under Chapter 11 of the United States Bankruptcy Code. The Company’s plan of reorganization was confirmed on April 18, 2016.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Magnum Hunter Resources Corporation (Debtor-in-Possession) at December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Magnum Hunter Resource Corporation’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated May 6, 2016 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP
Dallas, Texas
March 30, 2016, except for Notes 1, 3, 5, 11, 17, 18, and 22 which are dated May 6, 2016



F-1



Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders
Magnum Hunter Resources Corporation
Dallas, Texas

We have audited Magnum Hunter Resources Corporation’s (Debtor-in-Possession) internal control over financial reporting as of December 31, 2015, 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 (Debtor-in-Possession) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, 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 (Debtor-in-Possession) as of December 31, 2015 and 2014, 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, 2015 and our report dated March 30, 2016, except for notes 1, 3, 5, 11, 17, 18, and 22 which are dated May 6, 2016, expressed an unqualified opinion thereon.

/s/ BDO USA, LLP
Dallas, Texas
May 6, 2016



F-2
Table of Contents
MAGNUM HUNTER RESOURCES CORPORATION
(Debtor-in-Possession)
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)

 
December 31,
 
2015
 
2014
ASSETS
 
 
 
CURRENT ASSETS
 
 
 
Cash and cash equivalents
$
40,871

 
$
53,180

Accounts receivable:
 
 
 
Oil and natural gas sales
20,578

 
21,514

Joint interests and other, net of allowance for doubtful accounts of $1,001 and $308 at December 31, 2015 and 2014, respectively
8,921

 
23,888

Related party
5,479

 
2,931

Derivative assets
—

 
16,586

Inventory
1,851

 
2,268

Investments
157

 
3,864

Prepaid expenses and other assets
5,691

 
4,091

Total current assets
83,548

 
128,322

 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
Oil and natural gas properties, successful efforts method of accounting
1,067,617

 
1,346,645

Accumulated depletion, depreciation, and accretion
(369,347
)
 
(248,410
)
Total oil and natural gas properties, net
698,270

 
1,098,235

Gas transportation, gathering and processing equipment and other, net
70,268

 
77,423

Total property, plant and equipment, net
768,538

 
1,175,658

 
 
 
 
OTHER ASSETS
 
 
 
Deferred financing costs, net of amortization of $15,099 as of December 31, 2014
—

 
22,856

Other assets
41,973

 
3,928

Investment in affiliates, equity method
166,099

 
347,191

Total assets
$
1,060,158

 
$
1,677,955


The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
F-3

Table of Contents
MAGNUM HUNTER RESOURCES CORPORATION
(Debtor-in-Possession)
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)

 
December 31,
 
2015
 
2014
LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
 
CURRENT LIABILITIES
 
 
 
Accounts payable
$
7,215

 
$
135,697

Accounts payable to related parties
1,504

 
3,021

Current portion of long-term debt
83,682

 
10,770

Debtor-in-possession financing
40,000

 
—

Accrued liabilities
12,029

 
20,277

Revenue payable
5

 
5,450

Other liabilities
1,465

 
1,356

    Total current liabilities
145,900

 
176,571

 
 
 
 
Long-term debt, net of current portion
—

 
937,963

Asset retirement obligations, net of current portion
27,198

 
26,229

Other long-term liabilities
3,473

 
5,337

Total liabilities not subject to compromise
176,571

 
1,146,100

 
 
 
 
Liabilities subject to compromise
1,079,558

 
—

Liabilities subject to compromise - related party
16,513

 
—

Total liabilities subject to compromise
1,096,071

 
—

     Total liabilities
1,272,642

 
1,146,100

 
 
 
 
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, 2015 and 2014, with a liquidation preference of $25.00 per share
100,000

 
100,000

 
 
 
 
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, 2015 and December 31, 2014, 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, 2015 and 2014, 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, 261,397,232 and 201,420,701 issued and 260,482,280 and 200,505,749 outstanding as of December 31, 2015 and 2014, respectively
2,614

 
2,014

Additional paid in capital
975,041

 
909,783

Accumulated deficit
(1,602,235
)
 
(784,546
)
Accumulated other comprehensive income (loss)
(273
)
 
(7,765
)
Treasury stock, at cost
 
 
 
Series E Preferred Stock, 81 shares as of December 31, 2015 and 2014
(2,030
)
 
(2,030
)
Common stock, 914,952 shares as of December 31, 2015 and 2014
(1,914
)
 
(1,914
)
    Total shareholders' equity (deficit)
(312,484
)
 
431,855

    Total liabilities and shareholders’ equity
$
1,060,158

 
$
1,677,955



The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
F-4

Table of Contents
MAGNUM HUNTER RESOURCES CORPORATION
(Debtor-in-Possession)
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share and per share data)

 
Year Ended December 31,
 
2015
 
2014
 
2013
 
 
REVENUES AND OTHER
 
 
 
 
 
Oil and natural gas sales
$
133,448

 
$
268,501

 
$
220,699

Midstream natural gas gathering, processing, and marketing
1,067

 
97,916

 
61,178

Oilfield services
18,229

 
23,134

 
18,431

Other revenue
1,380

 
1,918

 
4,230

Total revenue 
154,124

 
391,469

 
304,538

OPERATING EXPENSES
 
 
 
 
 
Production costs
40,074

 
47,857

 
46,689

Severance taxes and marketing
6,917

 
17,344

 
18,282

Transportation, processing, and other related costs
65,606

 
43,292

 
22,549

Exploration
59,831

 
118,509

 
100,389

Midstream natural gas gathering, processing, and marketing
668

 
84,764

 
52,099

Oilfield services
13,984

 
15,686

 
14,825

Impairment of proved oil and gas properties
275,375

 
301,276

 
50,011

Depreciation, depletion, amortization and accretion
132,804

 
146,868

 
107,385

(Gain) loss on sale of assets, net
(31,358
)
 
(2,456
)
 
44,641

Loss on abandonment of drilling rig in progress
4,049

 
—

 
—

General and administrative (1)
47,260

 
108,687

 
82,461

Total operating expenses
615,210

 
881,827

 
539,331

 
 
 
 
 
 
OPERATING LOSS
(461,086
)
 
(490,358
)
 
(234,793
)
 
 
 
 
 
 
OTHER INCOME (EXPENSE)
 
 
 
 
 
Interest income
157

 
156

 
265

Interest expense
(99,559
)
 
(86,463
)
 
(72,621
)
Gain (loss) on derivative contracts, net
4,886

 
(72,254
)
 
(25,274
)
Gain on deconsolidation of Eureka Midstream Holdings, LLC
—

 
509,563

 
—

Gain on dilution of interest in Eureka Midstream Holdings, LLC
4,601

 
—

 
—

Loss from equity method investments
(186,157
)
 
(1,038
)
 
(994
)
Other income (expense)
(5,575
)
 
2,561

 
15,897

Total other income (expense), net
(281,647
)
 
352,525

 
(82,727
)
LOSS FROM CONTINUING OPERATIONS PRIOR TO REORGANIZATION ITEMS AND INCOME TAX
(742,733
)
 
(137,833
)
 
(317,520
)
Reorganization items, net
(41,139
)
 
—

 
—

LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX
(783,872
)
 
(137,833
)
 
(317,520
)
Income tax benefit
—

 
—

 
85,407

LOSS FROM CONTINUING OPERATIONS, NET OF TAX
(783,872
)
 
(137,833
)
 
(232,113
)
Income (loss) from discontinued operations, net of tax
—

 
4,561

 
(62,561
)
Gain (loss) on disposal of discontinued operations, net of tax
—

 
(13,855
)
 
71,510

NET LOSS
(783,872
)
 
(147,127
)
 
(223,164
)
Net loss attributable to non-controlling interests
—

 
3,653

 
988

NET LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION
(783,872
)
 
(143,474
)
 
(222,176
)
Dividends on preferred stock
(33,817
)
 
(54,707
)
 
(56,705
)
Loss on extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units
—

 
(51,692
)
 
—

NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS
$
(817,689
)
 
$
(249,873
)
 
$
(278,881
)
Weighted average number of common shares outstanding, basic and diluted
225,458,301

 
189,135,500

 
170,088,108

Loss from continuing operations per share, basic and diluted
$
(3.63
)
 
$
(1.27
)
 
$
(1.69
)
Income (loss) from discontinued operations per share, basic and diluted
—

 
(0.05
)
 
0.05

NET LOSS PER COMMON SHARE, BASIC AND DILUTED
$
(3.63
)
 
$
(1.32
)
 
$
(1.64
)
 
 
 
 
 
 

(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 Midstream Holdings, LLC related to excess capital expenditures in 2014. See “Note 4 - Eureka Midstream 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
(Debtor-in-Possession)
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share and per share data)

 
Year Ended December 31,
 
2015
 
2014
 
2013
AMOUNTS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION
 
 
 
 
 
Loss from continuing operations, net of tax
$
(783,872
)
 
$
(134,180
)
 
$
(231,125
)
Income (loss) from discontinued operations, net of tax
—

 
(9,294
)
 
8,949

Net loss
$
(783,872
)
 
$
(143,474
)
 
$
(222,176
)





The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
F-6

Table of Contents
MAGNUM HUNTER RESOURCES CORPORATION
(Debtor-in-Possession)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(in thousands)

 
Year ended December 31,
 
2015
 
2014
 
2013
NET LOSS
$
(783,872
)
 
$
(147,127
)
 
$
(223,164
)
OTHER COMPREHENSIVE INCOME (LOSS)
 
 
 
 
 
Foreign currency translation gain (loss)
99

 
(1,204
)
 
(10,928
)
Unrealized gain (loss) on available for sale securities
(2,771
)
 
(7,401
)
 
8,178

Amounts reclassified for other than temporary impairment of available for sale securities
10,183

 
—

 
—

Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities
(19
)
 
—

 
(8,262
)
Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc.
—

 
20,741

 
—

Total other comprehensive income (loss)
7,492

 
12,136

 
(11,012
)
COMPREHENSIVE LOSS
(776,380
)
 
(134,991
)
 
(234,176
)
Comprehensive loss attributable to non-controlling interests
—

 
3,653

 
988

COMPREHENSIVE LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION
$
(776,380
)
 
$
(131,338
)
 
$
(233,188
)


The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
F-7

Table of Contents
MAGNUM HUNTER RESOURCES CORPORATION
(Debtor-in-Possession)
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
 
Non-controlling Interest
 
Total Shareholders' Equity
BALANCE, January 1, 2013
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 contributions
—

 
—

 
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
)
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 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 Midstream Holdings, LLC Series A Preferred Units
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(51,692
)
 
—

 
—

 
—

 
389,235

 
337,543

Forfeiture of Eureka Midstream Holdings, LLC Series A-1 Units
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
32,569

 
—

 
—

 
—

 
—

 
32,569

Issuance of Eureka Midstream Holdings, LLC Series A-2 Units
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
40,000

 
40,000

Deconsolidation of Eureka Midstream Holdings, LLC
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(436,968
)
 
(436,968
)
Net loss
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(143,474
)
 
—

 
—

 
(3,653
)
 
(147,127
)
Foreign currency translation
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(1,204
)
 
—

 
—

 
(1,204
)

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
F-8

Table of Contents
MAGNUM HUNTER RESOURCES CORPORATION
(Debtor-in-Possession)
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(in thousands)

Unrealized loss on available for sale securities, net
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(7,401
)
 
—

 
—

 
(7,401
)
Amounts reclassified from 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

Share based compensation
—

 
—

 
1,383

 
—

 
—

 
—

 
14

 
—

 
5,686

 
—

 
—

 
—

 
—

 
5,700

Shares of common stock issued for payment of 401k plan matching contribution
—

 
—

 
2,291

 
—

 
—

 
—

 
23

 
—

 
1,855

 
—

 
—

 
—

 
—

 
1,878

Sale of common stock
—

 
—

 
56,202

 
—

 
—

 
—

 
562

 
—

 
57,667

 
—

 
—

 
—

 
—

 
58,229

Dividends on preferred stock
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(33,817
)
 
—

 
—

 
—

 
(33,817
)
Shares of common stock issued upon exercise of common stock options
—

 
—

 
100

 
—

 
—

 
—

 
1

 
—

 
50

 
—

 
—

 
—

 
—

 
51

Net loss
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(783,872
)
 
—

 
—

 
—

 
(783,872
)
Foreign currency translation
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
99

 
—

 
—

 
99

Unrealized loss on available for sale securities, net
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(2,771
)
 
—

 
—

 
(2,771
)
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(19
)
 
—

 
—

 
(19
)
Amounts reclassified from accumulated other comprehensive income for other than temporary impairment of available for sale securities
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
10,183

 
—

 
—

 
10,183

BALANCE, December 31, 2015
4,425

 
4

 
261,397

 
—

 
$
221,244

 
$
95,069

 
$
2,614

 
$
—

 
$
975,041

 
$
(1,602,235
)
 
$
(273
)
 
$
(3,944
)
 
$
—

 
$
(312,484
)


The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
F-9

Table of Contents
MAGNUM HUNTER RESOURCES CORPORATION
(Debtor-in-Possession)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

 
Year Ended December 31,
 
2015
 
2014
 
2013
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
Net loss
$
(783,872
)
 
$
(147,127
)
 
$
(223,164
)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
 
 
 
 
 
Depletion, depreciation, amortization and accretion
132,804

 
146,868

 
134,867

Share-based compensation
7,578

 
12,469

 
13,624

Impairment of proved oil and gas properties
275,375

 
301,276

 
89,041

Exploration
57,521

 
116,945

 
115,069

Impairment of other assets
10,183

 
730

 
—

Loss on abandonment of drilling rig in process
4,049

 
—

 
—

Loss (gain) on sale of assets
(31,358
)
 
11,399

 
(7,318
)
Cash paid for plugging wells
(346
)
 
(107
)
 
(14
)
Gain on deconsolidation of Eureka Midstream Holdings
—

 
(509,563
)
 
—

Loss from capital account adjustment of Eureka Midstream Holdings
—

 
32,569

 
—

Gain on dilution of interest in Eureka Midstream Holdings
(4,601
)
 
—

 
—

Loss from equity method investments
186,157

 
1,038

 
994

Unrealized loss (gain) on investments
(67
)
 
—

 
(8,003
)
Loss (gain) on derivative contracts
(4,886
)
 
(19,538
)
 
25,274

Cash proceeds (payment) on settlement of derivative contracts
21,471

 
1,306

 
(8,216
)
Loss on extinguished embedded derivative
—

 
91,792

 
—

Amortization and write off of deferred financing cost and discount on Senior Notes included in interest expense
9,907

 
9,679

 
4,836

Deferred tax benefit
—

 
—

 
(84,527
)
Noncash reorganization items
27,985

 
—

 
—

Changes in operating assets and liabilities:
 
 
 
 
 
Accounts receivable, net
14,103

 
8,533

 
22,781

Inventory
427

 
4,381

 
4,658

Prepaid expenses and other current assets
(2,150
)
 
(3,071
)
 
(1,073
)
Accounts payable
64,526

 
(51,930
)
 
42,050

Revenue payable
(173
)
 
(2,953
)
 
(11,589
)
Accrued liabilities
40,393

 
(23,361
)
 
2,421

Net cash provided by (used in) operating activities
25,026

 
(18,665
)
 
111,711

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
Change in restricted cash
—

 
5,000

 
(3,500
)
Capital expenditures and advances
(167,545
)
 
(562,324
)
 
(631,511
)
Deconsolidation of the cash of Eureka Midstream Holdings
—

 
(6,380
)
 
—

Proceeds from sale of assets
39,219

 
193,139

 
506,297

Proceeds from partial sale of equity interest in Eureka Midstream Holdings
—

 
55,000

 
—

Change in deposits and other long-term assets
(37,615
)
 
(2,554
)
 
854

Net cash used in investing activities
(165,941
)
 
(318,119
)
 
(127,860
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
Proceeds from borrowings on debt
76,886

 
629,392

 
373,991

Proceeds from borrowings on debtor-in-possession financing
40,000

 
—

 
—

Principal repayments of debt
(16,192
)
 
(467,745
)
 
(380,923
)
Proceeds from sale of Series A preferred units in Eureka Midstream Holdings
—

 
11,956

 
35,280

Issue Series A Common units of Eureka Midstream Holdings, net of costs
—

 
8,180

 
—

Issue Series A-2 Units of Eureka Midstream Holdings, net of costs
—

 
40,000

 
—

Net proceeds from sale of common stock
58,229

 
178,410

 
—

Net proceeds from sale of preferred shares
—

 
—

 
10,072

Repurchase noncontrolling interest
—

 
(2,875
)
 
—

Proceeds from exercise of warrants and options
51

 
9,663

 
5,352

Change in other long-term liabilities
25

 
1,023

 
(1,222
)
Payment of deferred financing costs
(3,823
)
 
(14,208
)
 
(1,246
)
Preferred stock dividends paid
(26,542
)
 
(45,601
)
 
(40,648
)
Net cash provided by financing activities
128,634

 
348,195

 
656

Effect of foreign exchange rate changes on cash
(28
)
 
56

 
(417
)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(12,309
)
 
11,467

 
(15,910
)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR
53,180

 
41,713

 
57,623

CASH AND CASH EQUIVALENTS, END OF YEAR
$
40,871

 
$
53,180

 
$
41,713


The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
F-10



MAGNUM HUNTER RESOURCES CORPORATION
(Debtor-in-Possession)
Notes to Consolidated Financial Statements
NOTE 1 - ORGANIZATION AND NATURE OF OPERATIONS

Magnum Hunter Resources Corporation, a Delaware corporation, operating directly and indirectly through its subsidiaries (“Magnum Hunter” or the “Company”), is an Irving, 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 specific shale plays in the United States, along with certain oil field service activities and a substantial equity method investment in a midstream operation.

Chapter 11 Bankruptcy Filings

On December 15, 2015 (the “Petition Date”), Magnum Hunter Resources Corporation and certain of its wholly owned subsidiaries, namely, Alpha Hunter Drilling, LLC (“Alpha Hunter Drilling”), Bakken Hunter Canada, Inc. (“Bakken Hunter Canada”), Bakken Hunter, LLC (“Bakken Hunter”), Energy Hunter Securities, Inc., Hunter Aviation, LLC, Hunter Real Estate, LLC, Magnum Hunter Marketing, LLC (“Magnum Hunter Marketing”), Magnum Hunter Production, Inc. (“MHP”), Magnum Hunter Resources GP, LLC, Magnum Hunter Resources, LP, Magnum Hunter Services, LLC, NGAS Gathering, LLC, NGAS Hunter, LLC (“NGAS Hunter”), PRC Williston LLC (“PRC Williston”), Shale Hunter, LLC (“Shale Hunter”), Triad Holdings, LLC, Triad Hunter, LLC (“Triad Hunter”), Viking International Resources Co., Inc. (“VIRCO”), and Williston Hunter ND, LLC (collectively, the “Filing Subsidiaries” and, together with the Company, the “Debtors”), filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Chapter 11 cases (the “Chapter 11 Cases”) are being jointly administered by the Bankruptcy Court under the caption In re Magnum Hunter Resources Corporation, et al., Case No. 15-12533. The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

The Company’s subsidiaries and affiliates excluded from the Chapter 11 Cases include wholly owned subsidiaries Magnum Hunter Management, LLC, Sentra Corporation, 54NG, LLC, and the Company’s 44.53% owned affiliate, Eureka Midstream Holdings, LLC, formerly known as Eureka Hunter Holdings, LLC (“Eureka Midstream Holdings”) (collectively, the “Non-Debtors”). See “Note 3 - Voluntary Reorganization under Chapter 11” for a discussion of the Chapter 11 Cases.

The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s payment obligations under its then outstanding debt obligations. The Company has classified all such debt as “Current portion of long-term debt” or “Liabilities subject to compromise”, as applicable, in the consolidated balance sheet as of December 31, 2015. See “Note 3 - Voluntary Reorganization under Chapter 11” for a discussion of liabilities subject to compromise. For additional description of the defaults present under the Company’s debt obligations, see “Note 11 - Long-Term Debt”.

On April 18, 2016, the Bankruptcy Court approved the Company’s Chapter 11 plan of reorganization (as amended, the “Plan”), which, among other things, resolved the Debtors’ pre-petition obligations, set forth the revised capital structure of the newly reorganized entity, and provided for corporate governance subsequent to exit from bankruptcy. The effective date of the Plan is expected to be May 6, 2016. Upon emergence from bankruptcy, the Company expects to apply fresh start accounting. Accordingly, the Company expects to make adjustments to the carrying values and classification of its assets and liabilities, and such adjustments could be material.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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. The Company’s 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 consolidated financial statements have been prepared in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 852, Reorganizations. This guidance requires that transactions and events directly associated with the Chapter 11 reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting and presentation of liabilities. See “Note 3 - Voluntary Reorganization under Chapter 11”.


F-11



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 the Company’s wholly owned subsidiary, MHP, in various managed drilling partnerships. The Company accounts for the interests in these managed drilling 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 and whether declines in the value of investments are other than temporary.
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.
The determination of whether declines in the value of investments are other than temporary involves the consideration of many factors including, but not limited to, the length of time and the extent to which market value has been less than cost, the financial condition and near-term prospects of the investee, and the intent and ability of the Company to retain its investment for a period of time sufficient to allow for any anticipated recovery in market value. Evaluating these factors requires significant judgment.
Non-recurring items subject to significant estimates include the fair value of the Company’s retained financial interest in equity method investees and liabilities subject to compromise.
Actual results could differ from the estimates and assumptions utilized.
Non-Controlling Interest in Consolidated Subsidiaries

Following a series of transactions and capital contributions that occurred up to and including December 18, 2014, the Company no longer held a controlling financial interest in its previously consolidated affiliate, Eureka Midstream Holdings. Accordingly, the results of operations of Eureka Midstream Holdings were consolidated in the accompanying consolidated financial statements up to December 18, 2014. The Company held a 48.6% equity interest in Eureka Midstream Holdings at December 18, 2014 and December 31, 2014, and held a 44.5% equity interest at December 31, 2015. The Company accounts for this retained interest under the equity method of accounting with the Company’s share of Eureka Midstream Holdings’ earnings recorded in “Loss from equity method investment” in the accompanying consolidated statements of operations. See “Note 4 - Eureka Midstream Holdings” and “Note 10 - Investments and Derivatives”.

Prior to July 24, 2014, the Company owned 87.5% of the equity interests in PRC Williston, which sold substantially all of its assets on December 30, 2013. 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 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. The net loss attributable to non-controlling interest for PRC Williston is recorded through July 24, 2014.

Changes in the non-controlling interests attributable to entities in which the Company held a controlling financial interest were accounted for as equity transactions, as they were considered investments by owners and distributions to owners acting in their capacity as owners. No gains or losses were recognized as the carrying value of the non-controlling interest was adjusted to reflect the change in the Company’s ownership interest in the subsidiary.

F-12




Reclassification of Prior-Year Balances

Certain prior period balances have been reclassified to correspond with current-period presentation. The Company has reclassified approximately $5.2 million of oil and gas transportation, processing and production tax payables from “Accounts receivable: oil and natural gas sales” to “Accounts payable” as of December 31, 2014 in the accompanying consolidated balance sheets.

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, 2015 and 2014. 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, 2015, the Company had cash deposits in excess of FDIC insured limits at various financial institutions. The Company has not experienced any losses in such accounts.

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, 2015 and 2014, 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, 2015 and 2014, the Company had approximately $1.0 million and $308,000, respectively, in allowances for doubtful accounts with respect to its joint interest accounts receivable.

Commodity and Financial Derivative Instruments

At various times, the Company has used 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.

The Company may be party to contracts or purchase certain investments that contain embedded derivatives. If an 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 bifurcated derivatives in “Gain (loss) on derivative contracts, net”.

F-13




Investments in Affiliates, Equity Method

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 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. The Company evaluated its investment in Eureka Midstream Holdings and determined that while the investment had declined in value, the decline was not other-than-temporary; and no impairment was required as of December 31, 2015.

Upon the deconsolidation of Eureka Midstream Holdings on December 18, 2014, the Company remeasured its retained interest in Eureka Midstream Holdings at fair value in accordance with the derecognition provisions of ASC Topic 810, Consolidation. See “Note 4 - Eureka Midstream Holdings” and “Note 9 - Fair Value of Financial Instruments”. Effective June 2015, the Company reclassified its equity method investment in Eureka Midstream Holdings to assets of discontinued operations. As of November 3, 2015, the Company determined that the planned divestiture no longer met the criteria for classification as a discontinued operation, and remeasured the carrying value of its equity method investment in Eureka Midstream Holdings at fair value. See “Note 5 - Acquisitions, Divestitures, and Discontinued Operations” and “Note 9 - Fair Value of Financial Instruments”.

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.

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 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.


F-14



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 commodity prices, which may make it uneconomic to drill for and produce due to 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 or retirement.

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 or retirement.

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 generally recorded as an asset and 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 the Petition Date, unamortized deferred financing costs associated with debt arrangements subject to compromise of approximately $18.2 million were reclassified as a reduction of the debt obligation recorded in liabilities subject to compromise and is no longer amortized. As of December 31, 2015, the Company had no remaining net deferred financing costs relating to debt not subject to compromise, and recorded interest expense of $8.5 million related to the amortization and write-off of deferred financing costs for the year ended December 31, 2015.

The Company evaluates changes and modifications of debt instruments under the guidance provided in 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.

Intangible Assets

Intangible assets consisted primarily of acquired gas treating agreements and customer relationships of Eureka Midstream Holdings.  Such assets were being amortized over the estimated useful lives, which ranged from 2 to 13 years, up to December 18, 2014, when Eureka Midstream Holdings was 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.

There was no amortization expense for intangible assets during the year ended December 31, 2015 as all intangible assets were related to Eureka Midstream Holdings, which was deconsolidated as of December 18, 2014. Amortization expense for intangible assets was $2.0 million and $2.5 million for the years ended December 31, 2014 and 2013, respectively.

Revenue Payable

Revenue payable represents amounts collected from purchasers for oil and gas sales which are either revenues due to other working or royalty interest owners or severance taxes due to the respective state or local tax authorities. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related proceeds from the production are received. Revenue payable of approximately $5.2 million is included in “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2015. See “Note 3 - Voluntary Reorganization under Chapter 11”.

Asset Retirement Obligation

Asset retirement obligations (“ARO”) primarily represent 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.

F-15




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 the Company’s 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.
 
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 the Company’s 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 the Company’s stock price, and the assessment of whether the achievement of performance criteria is probable.


F-16



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, 2015 or 2014.

The Company applies 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 it meets 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. During the year ended December 31, 2015, net loss attributable to common shareholders does not include preferred stock dividends that accumulated subsequent to the Petition Date. See “Note 13 - Shareholders' Equity” and “Note 14 - Redeemable Preferred Stock” for additional discussion of preferred stock dividends. 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.

Other Comprehensive Income (Loss)

The functional currency of the Company’s operations in Canada is the Canadian dollar. The Company closed its Calgary, Alberta office effective January 31, 2015 due to the sales of all of its Canadian assets during 2014 (see “Note 5 - Acquisitions, Divestitures, and Discontinued Operations”), but maintained certain Canadian bank accounts through December 31, 2015. 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.

Unrealized gains and losses on changes in fair value of common and preferred stock of publicly traded companies designated as available for sale securities, except those losses that are other-than-temporary and charged to earnings, are included in accumulated other comprehensive income. Upon the sale of available for sale securities, the related gain or loss in accumulated other comprehensive income is reclassified to “Other income (expense)” in the consolidated statements of operations.

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.

Regulated Activities

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, 2015, 2014, and 2013, 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 $637,000, $718,000, and $216,000, respectively.


F-17



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 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: (i) identify the contract(s) with a customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) 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. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the effective date of ASU 2014-09 for all entities by one year. As such, this amendment is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those reporting periods. The guidance allows for either a “full retrospective” adoption or a “modified retrospective” adoption, and earlier application is permitted as of annual reporting periods beginning after December 14, 2016, including interim reporting periods within that reporting period. The Company is currently evaluating the adoption methods and 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 adverse 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. Examples of adverse conditions and events that may raise substantial doubt about an entity’s ability to continue as a going concern include, but are not limited to, negative financial trends (such as recurring operating losses, working capital deficiencies, or insufficient liquidity), a need to restructure outstanding debt to avoid default, and industry developments (such as declining commodity prices and regulatory changes).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 adopted this ASU during the period ended March 31, 2016.

In April 2015, the FASB issued ASU 2015-03, Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this update. This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been previously issued. As of December 31, 2015, the Company had no remaining debt issuance costs on its consolidated balance sheet.

In April 2015, the FASB issued ASU 2015-05, Intangibles - Goodwill and Other - Internal-Use Software: Customer’s Accounting for Fees Paid in a Cloud Computing Agreement. This update provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. This update does not change GAAP for a customer’s accounting for service contracts. This amendment is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. Early adoption is permitted for all entities, either prospectively to all arrangements entered into or materially modified after the effective date, or retrospectively. The Company has several cloud computing arrangements and is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which amends existing guidance on income taxes to require the classification of all deferred tax assets and liabilities as non-current on the balance sheet. This amendment is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016, with early adoption permitted, and the guidance may be applied either prospectively or retrospectively. The Company does not expect this ASU to have a material impact on its consolidated financial statements.


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In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The core principle of Topic 842 is that a lessee should recognize the assets and liabilities that arise from leases. The ASU will require lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Under the new guidance, lessor accounting is largely unchanged. Certain targeted improvements were made to align, where necessary, lessor accounting with the lessee accounting model and Topic 606, Revenue from Contracts with Customers. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. The ASU is effective for public companies for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.

NOTE 3 - VOLUNTARY REORGANIZATION UNDER CHAPTER 11

On the Petition Date, the Debtors filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code. Since the Petition Date, the Debtors have operated their business as “debtors-in-possession” pursuant to Sections 1107(a) and 1108 of the Bankruptcy Code, which allows the Company to continue operations in the ordinary course of business during their Chapter 11 Cases. Each Debtor remains in possession of its assets and properties, and its business and affairs will continue to be managed by its directors and officers, subject in each case to the supervision of the Bankruptcy Court.

On April 18, 2016, the Bankruptcy Court approved the Chapter 11 plan of reorganization (as amended, the “Plan”), which, among other things, resolved the Debtors’ pre-petition obligations, set forth the revised capital structure of the newly reorganized entity, and provided for corporate governance subsequent to exit from bankruptcy. The effective date of the Plan is anticipated to be May 6, 2016 (the “Effective Date”).

Subject to certain exceptions, under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the date of the Bankruptcy Petitions. Accordingly, although the filing of the Bankruptcy Petitions triggered defaults on the Debtors’ then-existing debt obligations, creditors are stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. Absent an order of the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities are subject to settlement under the Bankruptcy Code.

Restructuring Support Agreement and Plan of Reorganization

Prior to filing the Chapter 11 Cases, on December 15, 2015, the Company and the other Debtors entered into a Restructuring Support Agreement (as amended, the “RSA”) with the following parties:

•
Substantially all of the Second Lien Lenders and Noteholders (each as defined herein) party to the Senior Secured Bridge Financing Facility (as defined in note “Note 11 - Long-Term Debt”);

•
Lenders holding approximately 66.5% in principal amount outstanding under the Second Lien Term Loan Agreement (as described in “Note 11 - Long-Term Debt”) (the “Second Lien Lenders”); and

•
Holders, in the aggregate, of approximately 79.0% in principal amount outstanding of the Company’s unsecured 9.750% Senior Notes due 2020 (the “Senior Notes”) (collectively, the “Noteholders”).

The agreed terms of the restructuring of the Debtors, as contemplated in the RSA, were memorialized in the Plan. The RSA and the Plan contemplate the implementation of a restructuring of the Company through a conversion of substantially all of the Company’s funded debt into equity and also provides for a multi-draw debtor-in-possession financing facility in an aggregate principal amount of up to $200 million (the “DIP Facility”). The Plan represents a settlement of various issues, controversies, and disputes. The key terms of the restructuring, as contemplated in the RSA and the Plan, are as follows:

•
DIP Facility: A $200 million multi-draw DIP Facility entered into with certain Second Lien Lenders and Noteholders. The DIP Facility is expected to convert to new common equity of the reorganized Company at a discount to Plan value, upon the conditions in the RSA.


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•
Substantial Deleveraging of Balance Sheet: The Senior Secured Bridge Facility was repaid in full from the proceeds of the DIP Facility upon entry of an order by the Bankruptcy Court on January 11, 2016 (the “Final DIP Order”) approving, on a final basis, the debtor-in-possession financing. On the Effective Date, the Second Lien Term Loan is expected to be converted into new common equity of the reorganized Company, receiving 36.87% of the new common equity. On the Effective Date, the Senior Notes are expected to be converted into new common equity of the reorganized Company, receiving 31.33% of the new common equity. On the Effective Date, the DIP Facility is expected to be converted into 28.80% of the new common equity. The general unsecured claims of the Company are projected to receive a blended recovery as specified in the RSA and the Plan, to be paid in cash, through a combination of payments to be made pursuant to Bankruptcy Court orders (lien claimant motion, taxes, etc.) and a cash pool of approximately $23.0 million included in the Plan. Holders of certain general unsecured claims of the Company elected to receive new common equity instead of cash, which is expected to dilute the new common equity issued to the holders of the Senior Notes and the lenders of the Second Lien Term Loan as described in the Plan. Holders of the Company’s preferred stock and common equity are expected to receive no recovery under the RSA and the Plan. The Other Secured Debt (as defined in the RSA and the Plan) is expected to be reinstated.

•
Business Plan: A business plan (the “Business Plan”) was developed jointly with the Debtors, the Second Lien Lenders that have backstopped the DIP Facility (the “Second Lien Backstoppers”) and the Noteholders that have backstopped the DIP Facility (the “Noteholder Backstoppers,” and together with the Second Lien Backstoppers, the “Backstoppers”).

•
Valuation for Settlement Purposes: For settlement purposes only, the Plan reflects a total enterprise value of the Company of $900 million. Such settlement value is not indicative of any party’s views regarding total enterprise value, but rather is a settled value for the purpose of determining equity splits and conversion rates for the various claimants.

•
Eureka Midstream Holdings: The Debtors restructured certain key agreements between Eureka Midstream Holdings and its subsidiaries, on the one hand, and the Debtors, on the other, with the consent of the Backstoppers.

•
Reorganized Company Status: The reorganized Company is expected to be a private company upon emergence from the Chapter 11 Cases and is expected to seek public listing of its new common equity when market conditions warrant and as determined by the New Board (as defined below) as informed by input from the Backstoppers.

•
Conditions Precedent to Emergence: The conditions precedent to emergence include the following, among others: (i) entry of a Bankruptcy Court order confirming the Plan and approving the disclosure statement of the Plan, in both instances in form and substance satisfactory to the Company and the Backstoppers (which has occurred), (ii) total administrative expenses paid by the Debtors shall not exceed the certain thresholds enumerated in the RSA without the consent of the Backstoppers, and (iii) the Debtors shall have entered into a new exit credit facility in the committed amount contemplated by the agreed Business Plan, on terms and conditions and with lenders, satisfactory to the Backstoppers and the Debtors.

•
Releases: The Plan provided for release, exculpation, and injunction provisions, including customary carve-outs, to the fullest extent permitted by applicable law and consistent with the terms of the RSA, and the Backstoppers have agreed not to “opt-out” of the consensual “third-party” releases granted to, among others, the Debtors’ current and former directors and officers.

•
Incentive Plans: The new board of directors of the reorganized Company shall be authorized to adopt management incentive programs to be paid exclusively with the funds of the reorganized Company. The management incentive plan will not give rise to any claims against the debtors or their estates.

•
Governance: The reorganized Company shall have a seven-person board of directors (the “New Board”), consisting of (i) the Chief Executive Officer, (ii) two directors selected by the Noteholder Backstoppers, (iii) two directors selected by the Second Lien Backstoppers, (iv) one director jointly selected by the Noteholder Backstoppers and the Second Lien Backstoppers, who shall serve as the non-executive chairman, and (v) one director selected by the Noteholder Backstoppers, based upon a slate of three candidates jointly determined by the Noteholder Backstoppers and the Second Lien Backstoppers. Members of the current management team of the Debtors have remained in place during the pendency of the Chapter 11 Cases and are expected to remain in place until the Company’s emergence from bankruptcy; however, on May 6, 2016, Mr. Evans tendered his voluntary resignation as the Company’s Chief Executive Officer and Chairman of the Board of Directors, which resignation is expected to be effective following the issuance of this report.

The RSA also contains certain milestones for progress in the Bankruptcy Court proceedings (the “Milestones”), which include the following:

•
The Debtors shall have commenced the Chapter 11 Cases on December 15, 2015 (which has occurred);


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•
On the Petition Date, the Debtors shall have filed with the Bankruptcy Court a motion seeking entry of an order by the Bankruptcy Court approving, on an interim basis, the debtor-in-possession financing (the “Interim DIP Order”) and the Final DIP Order (which has occurred);

•
No later than December 17, 2015, the Bankruptcy Court shall have entered the Interim DIP Order (which has occurred);

•
No later than January 7, 2016, the Debtors shall have filed with the Bankruptcy Court a motion to reject executory contracts and set procedures regarding rejection damages (which has occurred);

•
No later than January 7, 2016, the Debtors shall have filed with the Bankruptcy Court: (i) the Plan, (ii) the disclosure statement of the Plan, (iii) a motion seeking approval of the disclosure statement of the Plan and Plan as well as certain other items, and (iv) a motion seeking to assume the RSA (which has occurred);

•
No later than January 15, 2016, the Bankruptcy Court shall have entered the Final DIP Order (which has occurred);

•
No later than February 12, 2016, the Bankruptcy Court shall have entered an order approving assumption of the RSA (which has occurred);

•
No later than February 26, 2016, (i) the Bankruptcy Court shall have entered an order approving the disclosure statement with respect to the Plan (which has occurred) and (ii) no later than February 29, 2016, the Debtors shall have commenced solicitation on the Plan (which has occurred);

•
No later than April 18, 2016, the Bankruptcy Court shall have commenced the confirmation hearing on the Plan (which has occurred), and no later than April 19, 2016, the Bankruptcy Court shall have entered the Plan confirmation order (which has occurred); and

•
No later than May 6, 2016, the Debtors shall consummate the transactions contemplated by the Plan.

The Company has met all Milestones thus far under the RSA. The remaining Milestone to be completed is the consummation of the transactions contemplated by the Plan no later than May 6, 2016. There can be no assurance that this Milestone will be achieved. The continuation of the Chapter 11 Cases, particularly if the Plan is not implemented within the timeframe currently contemplated, could adversely affect operations and relationships between the Company and its customers, suppliers, vendors, service providers, and other creditors and result in increased professional fees and similar expenses. Failure to implement the Plan could further weaken the Company’s liquidity position, which could jeopardize the Company’s exit from Chapter 11 reorganization.

All of the Company’s existing equity securities, including shares of common stock and preferred stock and warrants and options, are expected to be canceled without receiving any distribution.
 
On the Petition Date, the Company sought, and thereafter obtained, authority to take a broad range of actions, including, among others, authority to pay royalty interests and joint interest billings, certain employee obligations and pre-Petition contractor claims and taxes.  Additionally, other orders were obtained, including adequate assurance of payment to utility companies as well as continued use of cash management systems.


F-21



Liabilities Subject to Compromise

Liabilities subject to compromise represent liabilities incurred prior to the commencement of the bankruptcy proceedings which may be affected by the Chapter 11 process. These amounts represent the Company’s allowed claims and its best estimate of claims expected to be allowed which will be resolved as part of the bankruptcy proceedings. Such claims remain subject to future adjustments. Adjustments may result from negotiations, actions of the Bankruptcy Court, determination as to the value of any collateral securing claims, or other events. Differences between liability amounts estimated by the Company and claims filed by creditors are being investigated and the Bankruptcy Court will make a final determination of the allowable claims. Liabilities subject to compromise consist of the following:

 
December 31, 2015
 
(in thousands)
Debt
 
Senior Notes
$
599,305

Second Lien Term Loan
335,853

Other notes payable
1,800

Total debt
936,958

Accounts payable
78,536

Accounts payable to related parties
16,513

Dividends payable
7,275

Accrued liabilities
48,364

Revenue payable
5,198

Other liabilities
3,227

Total liabilities subject to compromise
$
1,096,071


See “Note 11 - Long-Term Debt” for detailed discussion of debt related activity.

Interest Expense

The Debtors have discontinued recording interest on unsecured or under secured liabilities subject to compromise on the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $2.8 million, representing interest expense from the Petition Date through December 31, 2015.

Contracts

Under the Bankruptcy Code, the Debtors have the right to assume or reject certain contracts, subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the assumption of a contract requires a debtor to satisfy pre-petition obligations under the contract, which may include payment of pre-petition liabilities in whole or in part. Rejection of a contract is typically treated as a breach occurring as of the moment immediately preceding the Chapter 11 filing. Subject to certain exceptions, this rejection relieves the debtor from performing its future obligations under the contract but entitles the counterparty to assert a pre-petition general unsecured claim for damages. Parties to contracts rejected by a debtor may file proofs of claim against that debtor’s estate for damages.

On January 7, 2016, the Debtors filed a motion seeking entry of an order establishing procedures for the assumption or rejection of contracts pursuant to section 365 of the Bankruptcy Code (the “Contract Procedures Motion”). The court entered an order approving the Contract Procedures Motion on February 26, 2016. On March 14, 2016, the Debtors filed the plan supplement, which included a schedule of assumed contracts and a schedule of rejected contracts, and since then have filed two amended plan supplements and additional motions with respect to assumed and rejected contracts. Through the contract assumption and rejection process, the Debtors were able to successfully negotiate approximately a dozen midstream and downstream contracts. The Debtors continue to review and analyze their contractual obligations and retain the right, until eight days following the Effective Date, to move contracts from the schedule of assumed contracts to the schedule of rejected contracts or from the schedule of rejected contracts to the schedule of amended contracts.


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Reorganization Items

Reorganization items represent the direct and incremental costs of being in bankruptcy, such as professional fees, pre-petition liability claim adjustments and losses related to terminated contracts that are probable and can be estimated. Unamortized deferred financing costs, premiums, and discounts associated with debt classified as liabilities subject to compromise are expensed to reorganization items in order to reflect the expected amounts of the probable allowed claims. Reorganization items consist of the following for the year ended December 31, 2015:

 
December 31, 2015
 
(in thousands)
Professional fees
$
4,118

Debt issuance costs
9,036

Loss on adjustments to carrying value of Senior Notes
12,533

Loss on adjustments to carrying value of Second Lien Term Loan
15,452

Total reorganization items
$
41,139



Debtors Condensed Combined Financial Statements

Condensed combined financial statements of the Debtors are set forth below. These condensed combined financial statements exclude the financial statements of the Non-Debtors, but include the Company’s equity method investment in Eureka Midstream Holdings. Transactions and balances of receivables and payables between Debtors are eliminated in consolidation. However, the Debtors’ condensed combined balance sheet includes receivables from related Non-Debtors and payables to related Non-Debtors.

Condensed Combined Balance Sheet
For the Year Ended December 31, 2015
(in thousands)
ASSETS
 
Current assets
$
83,371

Intercompany accounts receivable
137

Property and equipment (using successful efforts accounting)
766,843

Investment in subsidiaries
1,214

Investment in affiliate, equity-method
166,099

Other assets
41,973

Total Assets
$
1,059,637

 
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
Current liabilities
$
145,860

Liabilities subject to compromise
1,096,071

Long-term liabilities
30,670

Redeemable preferred stock
100,000

Shareholders' equity (deficit)
(312,964
)
Total Liabilities and Shareholders' Equity
$
1,059,637



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Condensed Statement of Operations
For the Year Ended December 31, 2015
(in thousands)
Revenues
$
153,087

Operating expenses
614,383

Operating loss
(461,296
)
 
 
Other Income (Expense)
 
Interest income
157

Interest expense
(99,559
)
Gain (loss) on derivative contracts, net
4,886

Loss from equity method investments
(181,556
)
Reorganization items
(41,139
)
Other income (expense)
(5,568
)
Total other expense
(322,779
)
Net loss
(784,075
)
Dividends on preferred stock
(33,817
)
Net loss attributable to common shareholders
$
(817,892
)


Condensed Combined Statement of Comprehensive Income (Loss)
For the Year Ended December 31, 2015
(in thousands)
 Net loss
$
(784,075
)
Other comprehensive income (loss)
 
 Foreign currency translation loss
99

 Unrealized gain (loss) on available for sale securities
(2,771
)
 Amounts reclassified for other than temporary impairment of available for sale securities
10,183

 Amounts reclassified for available for sale securities
(19
)
Total other comprehensive income (loss)
7,492

 Comprehensive loss
$
(776,583
)


Condensed Combined Statement of Cash Flows
For the Year Ended December 31, 2015
(in thousands)
Cash flow from operating activities
$
24,915

Cash flow from investing activities
(165,941
)
Cash flow from financing activities
128,634

Effect of exchange rate changes on cash
(28
)
Net increase (decrease) in cash
(12,420
)
Cash at beginning of period
53,187

Cash at end of period
$
40,767



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NOTE 4 - EUREKA MIDSTREAM HOLDINGS

As of January 1, 2013 and through December 18, 2014, the Company consolidated Eureka Midstream Holdings in which it owned a 48.6% interest as of December 18, 2014. Eureka Midstream Holdings owns, directly or indirectly, 100% of the equity interests of Eureka Midstream, LLC, formerly known as Eureka Hunter Pipeline, LLC (“Eureka Midstream”), TransTex, LLC, formerly known as TransTex Hunter, LLC (“TransTex”), and Eureka Land, LLC, formerly known as Eureka Hunter Land, LLC. Eureka Midstream 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 sells and leases gas treating and processing equipment, much of which is leased to third party operators for treating natural gas at the wellhead.

Transaction Agreement

On September 16, 2014, the Company entered into an agreement (the “Transaction Agreement”) with North Haven Infrastructure Partners II Buffalo Holdings LLC (formerly, MSIP II Buffalo Holdings LLC), an affiliate of Morgan Stanley Infrastructure, Inc. (“MSI”) and Eureka Midstream 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 Midstream 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 Midstream Holdings and the execution of the Second Amended and Restated Limited Liability Company Agreement of Eureka Midstream Holdings (the “New LLC Agreement”) (the “First Closing”); and (ii) the purchase by MSI of an additional equity interest in Eureka Midstream Holdings 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.

New LLC Agreement

Contemporaneously with the First Closing, the New LLC Agreement for Eureka Midstream Holdings became effective. In accordance with the terms of the New LLC Agreement, all of the Eureka Midstream Holdings Series A Preferred Units and Class A Common Units of Eureka Midstream Holdings acquired by MSI from Ridgeline were converted into Series A-2 Common Units, a new class of equity interests of Eureka Midstream 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 Midstream 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 Midstream 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 Midstream Holdings Series A Preferred Units and the fair value associated with the embedded derivative attached to the Eureka Midstream 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 Midstream 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 Midstream 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 Midstream Holdings, which collectively would constitute an approximate 98% equity interest in Eureka Midstream Holdings.

The Transaction Agreement and the Letter Agreement (described below) further provided that the Company had the right, under certain circumstances, to not make its portion of certain required future capital contributions to Eureka Midstream 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

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back to the level prior to the capital call. The Company refers 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.

Letter Agreement

On November 18, 2014, the Company, Eureka Midstream 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 Midstream Holdings, and MSI agreed to reduce the Company’s capital account in Eureka Midstream 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 Midstream in connection with certain of Eureka Midstream’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 Midstream Holdings and MSI also agreed to adjust the amount and timing of (i) certain capital contributions by the Company and MSI to Eureka Midstream Holdings and (ii) MSI’s purchase of a portion of the Company’s equity interests in Eureka Midstream Holdings pursuant to the Second Closing as follows:

i.
In connection with certain of Eureka Midstream’s capital projects for fiscal year 2014, on November 20, 2014, MSI made a $30 million capital contribution in cash to Eureka Midstream 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 Midstream Holdings in exchange for additional Series A-1 Units.

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 Midstream Holdings in exchange for additional Series A-2 Units.

iv.
The Second Closing was accelerated to the date of the 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 also agreed to make a $13.3 million capital contribution in cash to Eureka Midstream Holdings on or before March 31, 2015 in exchange for additional Series A-1 Units. However, the Company and MSI subsequently entered into an additional letter agreement (the “March 2015 Letter Agreement”) regarding Eureka Midstream Holdings’ 2015 capital expenditure budget, including the amount, timing and expected funding of the various anticipated capital expenditures.
 
Loss of Controlling Financial Interest in Eureka Midstream Holdings

The Transaction Agreement also provided MSI with certain substantive participation rights which allow MSI to participate in the management and operation of Eureka Midstream Holdings. As a result of MSI acquiring additional Series A-2 Units, which brought their total equity interest in Eureka Midstream Holdings to 49.84% as of December 18, 2014, the board of managers of Eureka Midstream Holdings was expanded from five to six members and MSI appointed the sixth manager, so that the board of managers of Eureka Midstream 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 Midstream 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 Midstream Holdings and, therefore, the Company deconsolidated Eureka Midstream 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 Midstream Holdings was 48.6%, 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 Midstream 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 Midstream Holdings at December 18, 2014.

F-26



Approximately $187.2 million of the pre-tax gain was 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 Midstream Holdings. Eureka Midstream Holdings is considered an affiliate and a related party subsequent to the deconsolidation as a result of the Company’s continued investment in and transactions with Eureka Midstream Holdings.

March 2015 Letter Agreement

On March 30, 2015, the Company, Eureka Midstream Holdings and MSI entered into the March 2015 Letter Agreement, pursuant to which the parties agreed that, among other things, (i) the Company is no longer required to make the MHR 2015 Contribution and (ii) MSI would make certain additional capital contributions to Eureka Midstream Holdings in exchange for additional Series A-2 Units. Pursuant to the March 2015 Letter Agreement, MSI purchased additional Series A-2 Units of Eureka Midstream Holdings as follows:

i.
On March 31, 2015, MSI made a capital contribution in cash to Eureka Midstream Holdings of approximately $27.2 million (the “2015 Growth CapEx Projects Contribution”) in exchange for additional Series A-2 Units in Eureka Midstream Holdings with the proceeds of such capital contribution to be used to fund certain of Eureka Midstream’s 2015 capital expenditures. The 2015 Growth CapEx Projects Contribution is subject to the Company’s right to make an MHR Catch-Up Contribution (as defined in the Second Amended and Restated Limited Liability Company Agreement of Eureka Midstream Holdings (the “LLC Agreement”)).

ii.
On March 31, 2015, MSI made an additional capital contribution in cash to Eureka Midstream Holdings of approximately $37.8 million (the “Additional Contribution”) in exchange for additional Series A-2 Units in Eureka Midstream Holdings with the proceeds of such Additional Contribution to be used to fund certain of Eureka Midstream’s additional capital expenditures and for certain other uses.
 
Immediately after giving effect to these transactions, the Company and MSI owned 45.53% and 53.00%, respectively, of the equity interests of Eureka Midstream Holdings, with the Company’s equity ownership consisting of Series A-1 Units and MSI’s equity ownership consisting of Series A-2 Units.

Pursuant to the March 2015 Letter Agreement, the parties further agreed that the Company had the right, in its discretion, to fund as a capital contribution to Eureka Midstream Holdings, all or a portion (in specified minimum amounts) of its pro-rata share of the Additional Contribution, which pro-rata share equaled approximately $18.7 million (the “MHR Additional Contribution Component”), before June 30, 2015 (as extended, the “MHR Contribution Deadline”), in exchange for additional Series A-1 Units in Eureka Midstream Holdings (the “MHR 2015 Make-up Contribution”). 

July 2015 Letter Agreement

On July 27, 2015, the Company entered into an additional letter agreement (the “July 2015 Letter Agreement”) with Eureka Midstream Holdings and MSI pursuant to which the parties memorialized an agreement in principle which had been reached prior to June 30, 2015, to extend the MHR Contribution Deadline to the earlier of (i) September 30, 2015 or (ii) the day immediately preceding the date on which the Company disposes, in a sale transaction or otherwise, its equity ownership interest in Eureka Midstream Holdings. The Company did not fund the MHR Additional Contribution Component, and as such, the Company’s Series A-1 Units in Eureka Midstream Holdings were adjusted downward by 529,190 units, which was an amount equivalent to the unfunded portion of the MHR Additional Contribution Component divided by the purchase price per unit paid by MSI in connection with the 2015 Growth CapEx Projects Contribution and the Additional Contribution. As a result of the downward adjustment to its Series A-1 Units, the Company recognized a loss of $7.7 million reported net of tax in “Loss from equity method investments” on the consolidated statements of operations during the year ended December 31, 2015. The loss included the Company’s proportionate decrease in its equity method basis difference which was reduced by $4.0 million during the third quarter of 2015, based on the change in the Company’s ownership in the net assets of Eureka Midstream Holdings related to the downward adjustment in its Series A-1 Units.

The Company continues to have the right to make MHR Catch-Up Contributions (as defined in the LLC Agreement) in accordance with the LLC Agreement (as modified by the November 2014 Letter Agreement as to the applicable time and amount limitations) in respect of any MHR Shortfall Amounts (as defined in the LLC Agreement) that are eligible to be funded by the Company under the LLC Agreement. As of December 31, 2015, the Company had deferred capital contributions of approximately $27.2 million, for which it had the right to make future catch-up contributions. During the pendency of the Chapter 11 Cases, the payment of any such capital contributions is subject to the approval of the Bankruptcy Court.

The Company accounted for the March 31, 2015 MSI capital contributions, the issuance of additional Series A-2 Units by Eureka Midstream Holdings, and the September 30, 2015 expiration of the MHR Contribution Deadline in accordance with the subsequent

F-27



measurement provision of ASC Topic 323, Investments - Equity Method and Joint Ventures, which requires the Company to recognize a gain or loss on the dilution of its equity interest as if the Company had sold a proportionate interest in Eureka Midstream Holdings. During the year ended December 31, 2015, the Company recognized a gain of $4.6 million reported net of tax in “Gain on dilution of interest in Eureka Midstream Holdings, LLC, net of tax” in the consolidated statements of operations based on the difference between the carrying value of the Company’s Series A-1 Units and the proceeds received by Eureka Midstream Holdings for the issuance of additional Series A-2 Units to MSI which resulted in permanent dilution of the Company’s equity interest in Eureka Midstream Holdings. The gain included the Company’s proportionate decrease in its equity method basis difference which was reduced by $7.5 million during the year ended December 31, 2015, based on the change in the Company’s ownership in the net assets of Eureka Midstream Holdings after giving effect to the dilution of the Company’s interest as a result of the unit issuance.

As of November 3, 2015, the Company recorded impairment of $180.3 million included in “Loss from equity method investments” in the consolidated statements of operations in order to write down the carrying value of its equity interest in Eureka Midstream Holdings to fair value as a result of the Company’s determination that the investment no longer met the criteria for classification as a discontinued operation as of that date. See “Note 5 - Acquisitions, Divestitures, and Discontinued Operations”. Accordingly, the Company reduced its equity method basis difference by $180.3 million as of November 3, 2015.

As of December 31, 2015, the Company and MSI owned 44.53% and 53.98%, respectively, of the Class A Common Units of Eureka Midstream Holdings. As of December 31, 2014, the Company and MSI owned 48.60% and 49.84%, respectively, of the equity interests of Eureka Midstream Holdings. The carrying value of the Company’s equity interest in Eureka Midstream Holdings was $166.1 million and $347.2 million at December 31, 2015 and 2014, respectively.

The recognition of the Company’s retained interest in Eureka Midstream Holdings at fair value upon deconsolidation resulted in a basis difference between the carrying value of the Company’s investment in Eureka Midstream Holdings and its proportionate share in net assets of Eureka Midstream 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 Midstream Holdings was accounted for using the acquisition method of accounting, which requires that the basis difference be allocated to the identifiable assets and liabilities of Eureka Midstream Holdings at fair value and based upon the Company’s proportionate ownership.  Determining the fair value of assets and liabilities is judgmental in nature and involves the use of significant estimates and assumptions. The Company estimated that the amortization of the basis difference allocable to the 14 day period from December 18, 2014 to December 31, 2014 was not material. During the second quarter of 2015, the Company completed its valuation of the identifiable assets to which the basis is attributable and recorded amortization based on this valuation for the year ended December 31, 2015. The Company initially recognized a basis difference of $201.9 million upon deconsolidation related to its investment in Eureka Midstream Holdings which has been allocated to the following identifiable assets of Eureka Midstream Holdings:

 
Identifiable Assets
 
Ending Basis December 31, 2014
 
Basis Amortization
 
Basis Reduction
 
Ending Basis December 31, 2015
 
(in thousands)
Fixed assets
$
5,088

 
$
(208
)
 
$
(4,785
)
 
$
95

Intangible assets
155,189

 
(6,057
)
 
(146,252
)
 
2,880

Goodwill
41,597

 
—

 
(40,750
)
 
847

Total basis difference
$
201,874

 
$
(6,265
)
 
$
(191,787
)
 
$
3,822


The components of the Company’s basis difference, excluding goodwill, are being amortized over their estimated useful lives ranging from 3 to 39 years. Amortization of the basis difference is reflected as a component of “Income (loss) from equity method investment” in the accompanying consolidated statements of operations. 


F-28



Summarized balance sheet information for Eureka Midstream Holdings as of December 31, 2015 and 2014 is as follows:

 
December 31, 2015
 
December 31, 2014
 
(in thousands)
Current assets
$
86,910

 
$
17,113

Non-current assets
$
507,201

 
$
445,450

Current liabilities
$
20,683

 
$
63,313

Non-current liabilities
$
182,561

 
$
100,037


Summarized income information for Eureka Midstream Holdings for the year ended December 31, 2015 and the period from December 18, 2014 through December 31, 2014 is as follows:

 
Year Ended December 31, 2015
 
Fourteen Days Ended December 31, 2014
 
(in thousands)
Operating revenues
$
77,022

 
$
2,124

Operating income
$
23,250

 
$
74

Net income (loss)
$
18,979

 
$
(207
)
 
 
 
 
Magnum Hunter’s interest in Eureka Midstream Holdings net income (loss)
$
8,490

 
$
(101
)
Basis difference amortization
(6,265
)
 
—

Loss on downward adjustment of units
(7,664
)
 
—

Impairment upon reclassification from discontinued operations to continuing operations
(180,254
)
 
—

Magnum Hunter’s equity in earnings (loss), net
$
(185,693
)
 
$
(101
)

 
NOTE 5 - ACQUISITIONS, DIVESTITURES, AND DISCONTINUED OPERATIONS

Acquisitions

The Company recognized $2.8 million of transaction expenses related to acquisitions in its general and administrative expenses for the year ended December 31, 2013. The Company’s transaction expenses related to acquisitions were insignificant for the years ended December 31, 2015 and 2014. Substantially all of the Company’s acquisitions contained a significant amount of unproved acreage, as is consistent with the Company’s business strategy.

Agreements to Purchase Utica Shale Acreage
 
On August 12, 2013, Triad Hunter entered into an asset purchase agreement (the “MNW 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, 2015, 2014, and 2013, Triad Hunter purchased 2,665, 16,456 and 5,922 net leasehold acres, respectively, from MNW for an aggregate purchase price of $12.0 million, $67.3 million, and $24.6 million, respectively.

The Company listed the MNW Purchase Agreement on its Schedule of Rejected Executory Contracts that it filed with the Bankruptcy Court, as an exhibit to a supplement to the Plan, on March 14, 2016. Accordingly, on the Effective Date the MNW Purchase Agreement is expected to be terminated, and the Company does not expect that any of the remaining net leasehold acres will be acquired by Triad Hunter. See “Note 18 - Commitments and Contingencies”.

F-29




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

Withdrawn Plan for the Divestiture of Eureka Midstream Holdings

In June 2015, the Company announced its decision to pursue the sale of all of its equity ownership interest in Eureka Midstream Holdings in order to improve the Company’s liquidity position. The Company determined that the planned divestiture met the criteria for assets held for sale and classification as a discontinued operation. Effective June 30, 2015, the Company reclassified its equity method investment in Eureka Midstream Holdings to assets of discontinued operations.

On November 3, 2015, the Company entered into the Senior Secured Bridge Financing Facility with certain lenders, certain holders of the Company’s Senior Notes, and certain holders of the loans outstanding under the Second Lien Term Loan Agreement. Under the Senior Secured Bridge Financing Facility, the Company has restrictions on sales of assets, including among other things, restrictions on the sale of the Company’s equity ownership interests in Eureka Midstream Holdings. The Company was required to cease marketing the sale of its equity ownership interests in Eureka Midstream Holdings, other than with bidders that contact the Company without prior solicitation and other than any bidders that were already engaged in such marketing efforts with the Company as of November 3, 2015. See “Note 11 - Long-Term Debt” for further discussion of the Senior Secured Bridge Financing Facility. As the Company was prohibited from actively marketing its equity ownership interests in Eureka Midstream Holdings, the Company determined as of November 3, 2015 that the planned divestiture no longer met the criteria for classification as a discontinued operation.

Furthermore, under the RSA, the Company may not market its interest in Eureka Midstream Holdings without the consent of the Backstoppers.

As of November 3, 2015, the Company measured the carrying value of its equity method investment in Eureka Midstream Holdings at the lesser of its carrying value and its fair value at the date the planned divestiture no longer met the criteria for classification as a discontinued operation. As a result of this assessment, the Company recorded impairment of $180.3 million to the carrying value of its equity method investment in Eureka Midstream Holdings, which is included in “Loss from equity method investments” in the consolidated statements of operations.

The Company reclassified the results of Eureka Midstream Holdings’ operations related to periods prior to December 18, 2014, and all subsequent equity method losses through December 31, 2015, are reflected in continuing operations for all periods presented in these consolidated financial statements. The Company’s equity method investment in Eureka Midstream Holdings is included in “Investments in affiliates, equity method” as of December 31, 2015 and 2014.

Withdrawn Plan for the Divestiture of Magnum Hunter Production

In September 2013, the Company adopted a plan to divest all of its interests in MHP, whose oil and natural gas operations are located primarily in the southern Appalachian Basin in Kentucky and Tennessee, and 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 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 and assessed impairment of MHP based on the discontinued operations classification.

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.

F-30




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.

Williston Hunter Canada, Inc.

In September 2013, the Company adopted a plan to divest all of its interests in the Canadian operations of Williston Hunter Canada, Inc. (“WHI Canada”), which was a wholly owned subsidiary of the Company.

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 the Company’s foreign operation.

Sale of Eagle Ford Hunter

On April 24, 2013, the Company closed on the sale of all of its ownership interest in its wholly owned subsidiary, Eagle Ford Hunter, to an affiliate of Penn Virginia for a total purchase price of approximately $422.1 million paid to the Company in the form of $379.8 million in cash (after estimated customary initial purchase price adjustments) and 10.0 million shares of common stock of Penn Virginia valued at approximately $42.3 million (based on the closing market price of the stock of $4.23 as of April 24, 2013). The effective date of the sale was January 1, 2013. Upon closing of the sale, $325.0 million of sale proceeds were used to pay down outstanding borrowings under 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.


F-31



The Company included the results of operations of WHI Canada, which has historically been the only member of the Company’s Canadian Upstream segment, through May 12, 2014, and Eagle Ford Hunter, which has historically been included as part of the U.S. Upstream segment, through April 24, 2013 in discontinued operations as follows:
 
Year Ended December 31,
 
2014
 
2013
 
(in thousands)
Revenues
$
8,533

 
$
67,490

Expenses (1)
(3,975
)
 
(130,331
)
Other income (expense)
3

 
186

Income (loss) from discontinued operations before tax
4,561

 
(62,655
)
Income tax benefit (expense) (2)
—

 
94

Income (loss) from discontinued operations, net of tax
4,561

 
(62,561
)
Gain (loss) on disposal of discontinued operations, net of taxes (3)(4)
(13,855
)
 
71,510

Income (loss) from discontinued operations, net of tax
$
(9,294
)
 
$
8,949

_____________________
(1)
Includes impairment expense of $65.4 million for the year ended December 31, 2013 and exploration expense of $0.1 million and $19.9 million for the years ended December 31, 2014 and 2013, 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 and $11.9 million for the years ended December 31, 2014 and 2013, 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.

There were no assets or liabilities held for sale at December 31, 2015 or 2014.

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.

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.

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 $3.1 million.


F-32



Sale of Certain Other Eagle Ford Shale Assets

On January 28, 2014, the Company, through its wholly owned subsidiary 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 were designated as available for sale securities (see “Note 10 - Investments and Derivatives”). The Company recognized a loss on the sale of the Shale Hunter assets of $4.5 million during the first quarter of 2014.

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 $0.8 million.

On May 22, 2015, Triad Hunter entered into a Purchase and Sale Agreement with Antero Resources Corporation (“Antero”) pursuant to which Triad Hunter agreed to sell to Antero all of Triad Hunter’s right, title and interest in certain undeveloped and unproven leasehold acreage located in Tyler County, West Virginia. The sale transaction closed on June 18, 2015 and Triad Hunter received cash consideration of $33.6 million, subject to post-closing adjustments for any title defects and for remediation of asserted title defects. During the third quarter of 2015, the Company received $4.2 million of additional consideration for title defects cured or removed. The properties sold consisted of ownership interests in approximately 5,210 net leasehold acres. The Company recognized a gain on the sale of approximately $31.7 million.

NOTE 6 - OIL & NATURAL GAS SALES

During the years ended December 31, 2015, 2014, and 2013, the Company recognized sales from oil, natural gas, and natural gas liquids (“NGLs”) as follows:

 
Year Ended December 31,
 
2015
 
2014
 
2013
 
 
 
(in thousands)
 
 
Oil
$
42,805

 
$
131,109

 
$
147,798

Natural gas
69,533

 
91,277

 
53,821

NGLs
21,110

 
46,115

 
19,080

     Total oil and natural gas sales
$
133,448

 
$
268,501

 
$
220,699




F-33



NOTE 7 - 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,
 
2015
 
2014
 
(in thousands)
Mineral interests in properties:
 
 
 
Unproved leasehold costs
$
398,302

 
$
481,643

Proved leasehold costs
198,458

 
257,185

Wells and related equipment and facilities
469,578

 
560,060

Uncompleted wells, equipment and facilities
—

 
46,346

Advances to operators for wells in progress
1,279

 
1,411

Total costs
1,067,617

 
1,346,645

Less accumulated depreciation, depletion, and amortization
(369,347
)
 
(248,410
)
Net capitalized costs
$
698,270

 
$
1,098,235


Depreciation, depletion, and amortization expense for proved oil and natural gas properties was $122.2 million, $121.9 million, and $69.0 million for the years ended December 31, 2015, 2014, and 2013, respectively.

During the years ended December 31, 2015, 2014 and 2013, the Company recorded proved property impairments as follows:

 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(in thousands)
Williston Basin
$
64,165

 
$
261,270

 
$
8,498

Appalachian Basin
$
207,340

 
6,001

 
1,151

Western Kentucky
$
3,783

 
33,811

 
40,043

South Texas
$
87

 
194

 
319

 
$
275,375

 
$
301,276

 
$
50,011


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 2015, 2014 and 2013:
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(in thousands)
Geological and geophysical
$
2,317

 
$
1,564

 
$
1,402

Leasehold impairments:
 
 
 
 
 
   Williston Basin
45,811

 
103,147

 
89,167

   Appalachian Basin
11,501

 
9,978

 
6,773

Western Kentucky
75

 
3,820

 
3,047

   South Texas
127

 
—

 
—

 
$
59,831

 
$
118,509

 
$
100,389



F-34



The Company did not drill any dry holes during the years ended December 31, 2015, 2014, or 2013. All wells drilled were completed as commercially productive wells.

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, 2015 and 2014, is summarized as follows:

 
December 31,
 
2015
 
2014
 
(in thousands)
Gas transportation, gathering and processing equipment and other
$
100,916

 
$
100,436

Less accumulated depreciation
(30,648
)
 
(23,013
)
Net capitalized costs
$
70,268

 
$
77,423


Depreciation expense for other property and equipment was $8.0 million, $22.1 million, and $15.6 million, for the years ended December 31, 2015, 2014, and 2013, respectively. Depreciation expense for the years ended December 31, 2014 and 2013 includes depreciation expense relating to Eureka Midstream Holdings of $14.4 million and $9.9 million, respectively.

NOTE 8 - ASSET RETIREMENT OBLIGATIONS

The Company’s 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 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 $28.7 million and $26.5 million at December 31, 2015 and 2014, respectively.

The following table summarizes the changes in the Company’s ARO balances during the years ended December 31, 2015 and 2014:
 
December 31,
 
2015
 
2014
 
(in thousands)
Asset retirement obligation at beginning of period
$
26,524

 
$
16,216

Liabilities incurred
40

 
218

Liabilities settled
(346
)
 
(107
)
Liabilities sold
(254
)
 
(2,598
)
Accretion expense
2,597

 
1,478

Revisions in estimated liabilities
101

 
3,208

Reclassified from liabilities associated with assets held for sale
—

 
8,109

Asset retirement obligation at end of period
28,662

 
26,524

Less: current portion
(1,464
)
 
(295
)
Asset retirement obligation at end of period
$
27,198

 
$
26,229


NOTE 9 - FAIR VALUE OF FINANCIAL INSTRUMENTS

GAAP defines 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. GAAP also establishes 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:

F-35



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 of the fair value hierarchy 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 2015 and 2014.

The Company used the following fair value measurements for certain of its assets and liabilities at December 31, 2015 and 2014: 

Level 1 Classification:

Available for Sale Securities

At December 31, 2015 and 2014, 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 

The Company had commodity derivative financial derivatives in place at December 31, 2014, but no open contracts remaining at December 31, 2015.  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 value amounts 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”. 

Level 3 Classification: 

Convertible Security Embedded Derivative 

At December 31, 2014, the Company recognized an embedded derivative asset resulting from the fair value of the bifurcated conversion feature associated with a convertible note from GreenHunter Resources, Inc. (“GreenHunter”), a related party. The convertible security embedded derivative was valued using a Black-Scholes model valuation of the conversion option. At December 31, 2015, the embedded derivative had no remaining fair value.

The following tables present financial assets and liabilities which are adjusted to fair value on a recurring basis at December 31, 2015 and 2014:
 
 
Fair Value Measurements on a Recurring Basis
 
December 31, 2015
 
(in thousands)
 
Level 1
 
Level 2
 
Level 3
Available for sale securities
$
157

 
$
—

 
$
—

Total assets at fair value
$
157

 
$
—

 
$
—



F-36



 
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


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, 2015, 2014 and 2013:
 
Embedded Derivatives
 
Series A Preferred Units
 
Convertible Security
 
(in thousands)
Fair value at December 31, 2012
$
(43,548
)
 
$
264

Issuance of embedded liability
(14,645
)
 
—

Change 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
)
 
—

Change in fair value recognized in loss on derivative contracts, net
(91,792
)
 
(4
)
Conversion of Eureka Midstream Holdings Series A Preferred Units to Series A-2 Units
173,205

 
—

Fair value at December 31, 2014
$
—

 
$
75

Change in fair value recognized in loss on derivative contracts, net
—

 
(75
)
Fair value at December 31, 2015
$
—

 
$
—


During the year ended December 31, 2014, the valuation of the conversion feature embedded in the Eureka Midstream 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 Midstream 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 Midstream Holdings.

F-37




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, 2015
 
December 31, 2014
 
 
Hierarchy Level
 
Carrying Amount
 
Estimated Fair Value
 
Carrying Amount
 
Estimated Fair Value
 
 
 
 
(in thousands)
Senior Notes
 
Level 2
 
$
599,305

 
$
161,520

 
$
597,355

 
$
498,000

Second Lien Term Loan
 
Level 3
 
355,853

 
211,588

 
329,140

 
329,140

Equipment notes payable
 
Level 3
 
15,482

 
15,482

 
22,238

 
22,150

Senior Secured Bridge Financing Facility
 
Level 3
 
70,000

 
70,000

 
—

 
—

Debtor-in-Possession Credit Facility
 
Level 3
 
40,000

 
40,000

 
—

 
—

    
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 fair value of the Company’s Second Lien Term Loan as of December 31, 2015 is based upon the anticipated recovery value of the loan per the RSA. The carrying value of the Company’s Second Lien Term Loan as of December 31, 2014 approximated fair value based upon 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 carrying value of the Senior Secured Bridge Financing Facility approximates fair value as of December 31, 2015 due to the limited passage of time since entering into the agreement on November 3, 2015 and the subsequent payment in full of the outstanding balance on January 14, 2016. The carrying value of the Debtor-in-Possession Credit Facility approximates fair value as of December 31, 2015 due to the limited passage of time since entering into the agreement on December 17, 2015.

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.


F-38



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, 2015, 2014, and 2013 consist of the following:
 
Fair Value Measurements on a Non-recurring Basis
 
 
(Level 1)
 
(Level 2)
 
(Level 3)
 
 
(in thousands)
Year ended December 31, 2015
 
 
 
 
 
 
Fair value of proved properties impaired
 
$
—

 
$
—

 
$
298,689

Fair value of interest in Eureka Midstream Holdings
 
—

 
—

 
163,362

 
 
 
 
 
 
 
Year ended December 31, 2014
 
 
 
 
 
 
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 Midstream Holdings
 
—

 
—

 
347,291

 
 
 
 
 
 
 
Year ended December 31, 2013
 
 
 
 
 
 
Fair value of proved properties impaired
 
$
—

 
$
—

 
$
329,409

Fair value of acquisitions
 
—

 
—

 
87,149


Proved Properties Impairment

The Company recorded impairment charges from continuing operations of $275.4 million, $301.3 million, and $50.0 million during the years ended December 31, 2015, 2014 and 2013, respectively, as a result of writing down the carrying value of certain properties to fair value. See “Note 7 - Property, Plant, & Equipment” for a summary of impairment charges by region. 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, risk-adjusted probable, and risk-adjusted 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 market-based discount rate. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with 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

During 2014, the Company 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 5 - 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 Midstream Holdings

On December 18, 2014, the Company sold to MSI a common equity interest in Eureka Midstream Holdings comprising approximately 5.5% of the total common equity interests in Eureka Midstream 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 Midstream Holdings changing from a controlling financial interest in a consolidated subsidiary to an equity method investment in Eureka Midstream Holdings. As a result, the Company remeasured its retained interest in Eureka Midstream Holdings at fair value. See “Note 4 - Eureka Midstream 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 were as follows: (i) the pricing to be achieved upon a liquidating event or

F-39



initial public offering, (ii) the cost of equity for Eureka Midstream Holdings, (iii) the timing and probability of an initial public offering as contemplated in the New LLC Agreement of Eureka Midstream Holdings at discreet points in time, and (iv) the expected volatility of the equity of Eureka Midstream Holdings.

On November 3, 2015, the Company measured the carrying value of its interest in Eureka Midstream Holdings previously classified as assets of discontinued operations at fair value. See “Note 5 - Acquisitions, Divestitures, and Discontinued Operations”. The fair value was determined by utilizing a combination of income and market approaches, as well as an option pricing model considering the differing rights and preferences of the various securities having a claim on value. Key assumptions used in the model to determine fair value included the cost of capital of Eureka Midstream Holdings and the expected volatility of the equity of Eureka Midstream Holdings.

NOTE 10 - INVESTMENTS AND DERIVATIVES

Investment Holdings - Available for Sale Securities

The Company owns 2,619,981 shares of common stock of Redstar Gold Corp., which is publicly traded on the TSX Venture Exchange. During the third quarter of 2015, the Company reviewed the business outlook and market conditions for this investment and recorded an other-than-temporary impairment of $0.4 million which was reclassified from accumulated other comprehensive income into Other income (expense) on the consolidated statements of operations. The investment in common stock of Redstar Gold Corp. had a fair value of $75,581 and $90,120 at December 31, 2015 and 2014, respectively.

The Company owns 88,000 shares of GreenHunter 10% Series C Preferred Stock, which is publicly traded. During the third quarter of 2015, the Company reviewed the business outlook and market conditions for this investment and recorded an other-than-temporary impairment of $0.8 million which was reclassified from accumulated other comprehensive income into Other income (expense)on the consolidated statements of operations. The Series C Preferred Stock had a fair value of $80,961 and $1.3 million at December 31, 2015 and 2014, respectively.

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 its 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 from accumulated other comprehensive income into “Other income (expense)” on the consolidated statements of operations.

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. During the first quarter of 2015, the Company reviewed its investment for impairment and considered such factors as NSE’s future business outlook, the prevailing economic environment and the overall market condition for the Company’s investment. As a result of its review, the Company recorded an other-than-temporary impairment of $9.0 million which was reclassified from accumulated other comprehensive income into “Other income (expense)” on the consolidated statements of operations, related to the decline in value of its investment in NSE. Effective October 20, 2015, the Company sold its entire investment in NSE for cash consideration of approximately AUD $0.7 million (approximately $0.5 million USD). The Company recognized a gain on the sale of approximately $0.1 million.

Investment Holdings - Equity Method Investments

GreenHunter

The Company holds an equity method investment in 1,846,722 restricted common shares of GreenHunter. The GreenHunter common stock investment is accounted for under the equity method and had no carrying value as of December 31, 2015 or 2014. The GreenHunter common shares are publicly traded and have a fair value of $0.2 million and $1.3 million at December 31, 2015 and 2014, respectively, which is not reflected in the carrying value since the Company’s investment is accounted for using the equity method.


F-40



Eureka Midstream Holdings

As discussed in “Note 4 - Eureka Midstream Holdings”, on December 18, 2014, the Company no longer held a controlling financial interest in Eureka Midstream Holdings as a result of capital contributions made by MSI to Eureka Midstream Holdings and a subsequent sale by the Company of a portion of its equity interest in Eureka Midstream Holdings to MSI. The Company continues to exercise significant influence through its retained equity interest of 44.53% as of December 31, 2015 and through representation on Eureka Midstream Holdings’ board of managers. As a result, the Company uses the equity method to account for its retained interest. The carrying value of the Company’s equity interest in Eureka Midstream Holdings was $166.1 million and $347.2 million as of December 31, 2015 and 2014, respectively.

Below is a summary of changes in investments for the years ended December 31, 2015, 2014, and 2013:
 
Available for Sale Securities
 
Equity Method Investments
 
(in thousands)
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

 
—

Fair value of retained interest in Eureka Midstream 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 at December 31, 2014
$
3,864

 
$
347,191

Sales of securities
(472
)
 
—

Gain on dilution of interest in Eureka Midstream Holdings
—

 
4,601

Loss from equity method investment (1)
(464
)
 
(185,693
)
Other adjustments
—

 
—

Change in fair value recognized in other comprehensive loss
(2,771
)
 
—

Carrying value at December 31, 2015
$
157

 
$
166,099

_________________ 
(1) As a result of the carrying value of the Company’s investment in common stock of GreenHunter being reduced to zero from equity method losses, the Company is required to allocate any additional losses to its investment in the Series C preferred stock of GreenHunter. The Company recorded additional equity method loss against the carrying value of its investment in the Series C preferred stock of GreenHunter before recording any mark-to-market adjustments.

The Company’s investments have been presented in the consolidated balance sheet as of December 31, 2015 and December 31, 2014 as follows:

 
December 31, 2015
 
(in thousands)
 
Available for Sale Securities
 
Equity Method Investments
 
Total
Investments - Current
$
157

 
$
—

 
$
157

Investments - Non-current
—

 
166,099

 
166,099

Carrying value as of December 31, 2015
$
157

 
$
166,099

 
$
166,256



F-41



 
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



The cost for equity securities and their respective fair values as of December 31, 2015 and 2014 are as follows:

 
December 31, 2015
 
Cost
 
Gross Unrealized Gains
 
Gross Unrealized Losses
 
Fair Value
 
(in thousands)
Securities available for sale, carried at fair value:
 
 
 
 
 
 
 
Equity securities
$
78

 
$
—

 
$
(2
)
 
$
76

Equity securities - related party (see “Note 17 - Related Party Transactions”)
465

 
—

 
(384
)
 
81

Total Securities available for sale
$
543

 
$
—

 
$
(386
)
 
$
157


 
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



Commodity and Financial Derivative Instruments

The Company has no remaining open commodity derivative contracts as of December 31, 2015. On May 7, 2015, the Company obtained consent under the MHR Senior Revolving Credit Facility to terminate the Company’s open commodity derivative positions. The Company received approximately $11.8 million in cash proceeds from the termination of the majority of its open commodity derivative positions that were terminated on May 7, 2015. On November 2, 2015, the Company terminated its open commodity derivative positions with Bank of Montreal and received approximately $0.9 million in cash proceeds. On December 31, 2015, the Company’s commodity derivative positions with Citibank, N.A. expired.

The Company has in the past periodically entered 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 past commodity derivatives as hedges.


F-42



In a commodities swap agreement, the Company has in the past traded 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 has in the past also entered into three-way collars with third parties. These instruments typically establish two floors and one ceiling. Upon settlement, if the index price is below the lowest floor, the Company receives the difference between the two floors. If the index price is between the two floors, the Company receives the difference between the higher of the two floors and the index price. If the index price is between the higher floor and the ceiling, the Company does not receive or pay any amounts. If the index price is above the ceiling, the Company pays the excess over the ceiling price. The advantage to the Company of the three-way collar is that the proceeds from the second floor allow us to lower the total cost of the collar.

As further discussed in “Note 11 - Long-Term Debt”, as of October 8, 2015, the Company had an event of default under the MHR Senior Revolving Credit Facility and its Second Lien Term Loan Agreement which resulted in a cross-default under the Company’s derivative contracts with Bank of Montreal, and which could have resulted in a cross-default under the Company’s derivative contracts with Citibank, N.A. if the outstanding loan obligations under the related credit agreements had been accelerated. Under the Company’s derivative contracts, upon a cross-default the non-defaulting party may designate an early termination date for all outstanding transactions. The counterparties to the Company’s derivative contracts did not designate early termination dates for any of the Company’s outstanding commodities derivatives.

At December 31, 2014, the Company had 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. As of December 31, 2015 the Company recognized no remaining fair value associated with this embedded derivative asset. See “Note 9 - Fair Value of Financial Instruments” and “Note 17 - Related Party Transactions”.

The following table summarizes the fair value of the Company’s derivative contracts as of December 31, 2014:
 
 
Derivatives not designated as hedging instruments
 
 
December 31, 2014
Commodity
(in thousands)
Derivative assets
 
$
16,511

Total commodity
 
$
16,511

 
 
 
Financial
 
 
Derivative assets
 
$
75

Total financial
 
$
75

Total derivatives
 
$
16,586


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 Company had no remaining open commodity derivatives contracts as of December 31, 2015. The table below summarizes 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.
 
December 31, 2014
 
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        
$
18,146

 
$
(1,635
)
 
$
16,511

Current liabilities:  Fair value of derivative contracts        
(1,635
)
 
1,635

 
—

Total fair value of derivative contracts
$
16,511

 
$
—

 
$
16,511



F-43



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, 2015, 2014 and 2013:
 
For the Year Ended December 31,
 
2015
 
2014
 
2013
 
(in thousands)
Gain (loss) on settled transactions
$
2,449

 
$
1,306

 
$
(8,216
)
Gain (loss) on open contracts
2,437

 
18,232

 
(17,058
)
Loss on extinguished embedded derivative
—

 
(91,792
)
 
—

Total gain (loss), net
$
4,886

 
$
(72,254
)
 
$
(25,274
)

NOTE 11 - LONG-TERM DEBT

Notes payable at December 31, 2015 and 2014 consisted of the following:
 
As of December 31,
 
2015
 
2014
 
(in thousands)
MHR Senior Revolving Credit Facility
$
—

 
$
—

Senior Secured Bridge Financing Facility, interest rate of 4.2% at December 31, 2015
70,000

 
—

Debtor-in-Possession Credit Facility, interest rate of 9.00% at December 31, 2015
40,000

 
—

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
335,853

 
329,140

Senior Notes Payable due May 15, 2020, interest rate of 9.75%, net of unamortized discount of $2.6 million at December 31, 2014
599,305

 
597,355

Various equipment and real estate notes payable with maturity dates April 2016 - November 2017, interest rates of 4.25% - 8.70%
15,482

 
22,238

 
$
1,060,640

 
$
948,733

Less: current portion
(83,682
)
 
(10,770
)
Less: debtor-in-possession financing
(40,000
)
 
—

Less: liabilities subject to compromise (see “Note 3 - Voluntary Reorganization under Chapter 11”)
(936,958
)
 
—

Total long-term debt obligations not subject to compromise, net of current portion
$
—

 
$
937,963



The following table presents the approximate annual maturities of debt:
 
(in thousands)
2016
$
1,060,640

2017
—

2018
—

2019
—

2020
—

Thereafter
—

 
$
1,060,640


MHR Senior Revolving Credit Facility

At various times, the Company maintained an asset-based, senior secured revolving credit facility (the “MHR Senior Revolving Credit Facility”) by and among the Company, Bank of Montreal, as Administrative Agent, the lenders party thereto and the agents party thereto. The borrowing base was generally derived from the Company’s proved crude oil and natural gas reserves and was subject to regular semi-annual redeterminations. The MHR Senior Revolving Credit Facility was amended in 2013 and 2014 to, among other things, amend the borrowing base, include letters of credit in the facility, and amend financial covenants. On October 22, 2014 all amounts outstanding under the MHR Senior Revolving Credit Facility were converted to a $340 million Second Lien

F-44

Term Loan and the MHR Senior Revolving Credit Facility was reduced to an initial borrowing base of $50 million subject to semi-annual borrowing base redeterminations derived from the Company’s proved crude oil and natural gas reserves, and based on such redeterminations, the borrowing base could be decreased or increased up to a maximum commitment level of $250 million.

The terms of the October 22, 2014 amendment provided that the MHR Senior Revolving Credit Facility could be used for loans, and subject to a $50 million sublimit, letters of credit. The October 22, 2014 amendment provided for a commitment fee of 0.5% of the unused portion of the borrowing base.

Borrowings under the MHR Senior Revolving Credit Facility, at the Company’s election, bore 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 was payable in arrears on the last day of each March, June, September and December and accrued interest on each adjusted LIBO Rate loan was payable in arrears on the last day of the interest period.

The October 22, 2014 amendment contained various negative covenants, as well as financial covenants relating to the Company’s current ratio, leverage ratio, and the proved reserves based asset coverage ratios contained in the Second Lien Term Loan Agreement described below.

Subject to certain exceptions, the MHR Senior Revolving Credit Facility was 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) was required to be pledged as security for the MHR Senior Revolving Credit Facility. On February 24, 2015, April 17, 2015, May 28, 2015, June 19, 2015 and July 10, 2015 the MHR Senior Revolving Credit Facility was amended to, among other things, waive or amend certain financial covenants, limit certain capital expenditures, increase the interest rate, limit dividends on preferred stock, and terminate the Company’s open commodity derivatives positions.

Defaults under the MHR Senior Revolving Credit Facility

On July 27, 2015, the Company became aware of a default under the MHR Senior Revolving Credit Facility relating to the aging of the Company’s accounts payable. In accordance with the terms of the MHR Senior Revolving Credit Facility agreement, the Company was not permitted to have accounts payable outstanding (subject to certain permissible amounts) in excess of 180 days from the invoice date for any day on or prior to the earlier of (a) December 31, 2015 or (b) the date that is ten business days following the date on which the Company consummates the sale of all or substantially all of the Company’s equity ownership interest in Eureka Midstream Holdings, after which earlier date the restriction reverted back to 90 days. The Company cured the default on August 26, 2015.

On September 8, 2015, the Company became aware of an additional default under the MHR Senior Revolving Credit Facility because the Company had approximately $1.4 million in accounts payable outstanding (in excess of permissible amounts) in excess of 180 days from the invoice date. Under the MHR Senior Revolving Credit Facility, the Company had 30 days to cure this default. As of October 8, 2015, the Company continued to have accounts payable outstanding (in excess of permissible amounts) in excess of 180 days from the invoice date, resulting in an event of default. Due to the event of default, the lenders under the MHR Senior Revolving Credit Facility were permitted to, but did not, declare the outstanding loan amounts immediately due and payable.

The event of default described above under the MHR Senior Revolving Credit Facility resulted in an event of default under the Second Lien Term Loan Agreement and the Equipment Note Payable (as defined below). Furthermore, the event of default regarding accounts payable under the Second Lien Term Loan Agreement, as described below, resulted in a cross-default under the MHR Senior Revolving Credit Facility. The event of default under the MHR Senior Revolving Credit Facility also resulted in a cross-default under the Company’s then-outstanding derivatives contracts with Bank of Montreal. However, the Company did not receive any notice of cross-default from Bank of Montreal with respect to such derivatives contracts. In addition, on November 2, 2015, the Company chose to terminate all of its open commodity derivative positions with Bank of Montreal and received approximately $0.9 million in cash proceeds. See “Note 10 - Investments and Derivatives”.

On and effective as of November 3, 2015, the Company entered into a Senior Secured Bridge Financing Facility which replaced the MHR Senior Revolving Credit Facility.


F-45

Senior Secured Bridge Financing Facility

On and effective as of November 3, 2015, the Company entered into a Senior Secured Bridge Financing Facility with certain holders of its Senior Notes and lenders under its Second Lien Term Loan (the “New First Lien Lenders”). The Senior Secured Bridge Financing Facility, among other things, replaced the MHR Senior Revolving Credit Facility and provided the Company with additional capital as follows:

i.
All borrowings outstanding under the MHR Senior Revolving Credit Facility, which were approximately $5.0 million, were effectively paid off;
ii.
Certain outstanding letters of credit in an aggregate amount of approximately $39.0 million issued under the MHR Senior Revolving Credit Facility were cash collateralized (and are included in “Other assets” in the accompanying consolidated balance sheet as of December 31, 2015); and
iii.
The Company was provided with cash proceeds of approximately $16 million, which was used to pay for expenses associated with the Senior Secured Bridge Financing Facility as well as for general corporate purposes.

As a result, the MHR Senior Revolving Credit Facility with Bank of Montreal was effectively paid off and canceled and replaced with the Senior Secured Bridge Loan Financing Facility with the New First Lien Lenders as creditors. The aggregate amounts outstanding under the Senior Secured Bridge Loan Facility as of November 3, 2015 totaled approximately $60 million. In addition, the Senior Secured Bridge Financing Facility included an uncommitted incremental credit facility for up to an additional $10.0 million aggregate principal amount of term loans to be provided to the Company, if and to the extent requested by the Company and agreed to by a specified percentage of the New First Lien Lenders. Effective as of November 30, 2015, the Company entered into the Seventh Amendment to Credit Agreement whereby the Company requested and received an aggregate principal amount of $10 million in new borrowings under the Senior Secured Bridge Financing Facility.

Borrowings under the Senior Secured Bridge Financing Facility were due and payable on the earlier of: (a) December 30, 2015, (b) in the case of an event of default under the Senior Secured Bridge Financing Facility, the acceleration of the payment of the term loans, as determined by the requisite percentage of the New First Lien Lenders, or (c) the filing of a Chapter 11 case (or cases) by the Company or any of its subsidiaries. The Senior Secured Bridge Financing Facility bore interest, at the Company’s option, at either the London Interbank Offered Rate, plus an applicable margin of 4.0%, or a specified prime rate of interest, plus an applicable margin of 3.0%.

The Senior Secured Bridge Financing Facility contained the same covenants as the amended MHR Senior Revolving Credit Facility, subject to customary adjustments consistent with financings of this type and duration and subject to the following additional changes:

i.
Removal of all financial covenants in effect under the amended MHR Senior Revolving Credit Facility (including the current ratio, leverage ratio, proved reserves coverage ratio and proved developed producing reserves coverage ratio covenants);
ii.
Removal of restrictions against trade payables being outstanding for more than 180 days from the date of invoice; and
iii.
Inclusion of budgetary and reporting requirements consistent with financings of this type and duration, including a cumulative budget variance covenant tested every other week, in accordance with the terms of the Senior Secured Bridge Financing Facility.

The Senior Secured Bridge Financing Facility also contained restrictions on the sale of assets by the Company and its restricted subsidiaries, which restrictions, among other things, prohibited (i) the Company from selling its equity ownership interests in Eureka Midstream Holdings (the “EHH Interests”) and (ii) the Company and its restricted subsidiaries from engaging in certain farm-outs of undeveloped acreage, without, in each case, first obtaining the requisite consent of the New First Lien Lenders. Additionally, the Senior Secured Bridge Financing Facility contained a standstill on any marketing by the Company of the sale of the EHH Interests, other than with bidders that contacted the Company without prior solicitation and other than any bidders that had already been engaged in such marketing efforts with the Company as of the closing date of the Senior Secured Bridge Financing Facility.

As of December 31, 2015, the balance outstanding under the Senior Secured Bridge Financing Facility was $70.0 million and is included in “Current portion of long-term debt” in the accompanying consolidated balance sheet.

On January 14, 2016, the Senior Secured Bridge Financing Facility and outstanding interest was paid in full with proceeds from borrowings under the Debtor-in-Possession Credit Facility.


F-46

Debtor-in-Possession Credit Facility

In connection with the Chapter 11 Cases, on the Petition Date the Company filed a motion seeking Bankruptcy Court approval of debtor-in-possession financing on the terms set forth in a Debtor-in-Possession Credit Agreement (as amended from time to time, the “DIP Credit Agreement”). On December 16, 2015, the Bankruptcy Court entered an order approving, on an interim basis, the financing to be provided pursuant to the DIP Credit Agreement (i.e., the Interim DIP Order) and, on December 17, 2015, the DIP Credit Agreement was entered into by and among the Company, as borrower, the Filing Subsidiaries, as guarantors, the DIP Lenders (as defined below) and Cantor Fitzgerald Securities, as administrative agent and as collateral agent for the DIP Lenders.

The DIP Credit Agreement provides for senior secured term loans in the aggregate principal amount of up to $200 million (the “DIP Facility”), which consists of:

i.
a term loan in the principal amount of $40 million (the “First DIP Draw”);
ii.
a term loan in the principal amount of $100 million (the “Second DIP Draw”); and
iii.
a term loan in the principal amount of $60 million (the “Third DIP Draw”).

The First DIP Draw was funded, net of certain fees and expenses, on December 17, 2015. The net proceeds from the First DIP Draw were used to fund (a) payments in accordance with the orders approved on the Petition Date, (b) adequate protection payments, and (c) working capital, in each case, in accordance with the budget variance financial covenant.

The Second DIP Draw was fully funded on January 14, 2016 following the Bankruptcy Court’s entry of an order approving, on a final basis, the financing provided pursuant to the DIP Credit Agreement (i.e., the Final DIP Order). Approximately $70.2 million of the net proceeds from the Second DIP Draw was used to repay in full all loans outstanding under the Company’s Senior Secured Bridge Financing Facility and approximately $25.5 million was made available to the Company to be used for general corporate purposes, subject to the DIP Facility budget.

The Third DIP Draw was fully funded on April 21, 2016, following the satisfaction of certain conditions pursuant to the DIP Credit Agreement.

Subject to certain conditions, the maturity date of the DIP Facility is the earlier of:

i.
Nine months from the closing date of the DIP Facility;
ii.
31 days after entry of the Interim DIP Order if the Final DIP Order had not been entered into by the Bankruptcy Court;
iii.
The effective date of the Plan;
iv.
The consummation of a sale of all or substantially all of the assets of the Company and its subsidiaries pursuant to Section 363 of the Bankruptcy Code; and
v.
The date of termination of the DIP Lenders’ Commitments (as defined in the DIP Credit Agreement) and the acceleration of any outstanding extensions of credit, in each case, under the DIP Facility in accordance with the terms of the Loan Documents (as defined in the DIP Credit Agreement).

Interest on the outstanding principal amount of the term loans under the DIP Facility will be payable monthly in arrears and on the maturity date at a per annum rate equal to LIBOR plus 8.00%, subject to a 1.00% floor. Upon an event of default under the DIP Facility, all obligations under the DIP Credit Agreement will bear interest at a rate equal to the then current interest rate plus an additional 2% per annum. The principal amount of the term loans under the DIP Facility is payable in full at maturity. The Company paid to the lenders under the DIP Credit Agreement a commitment fee equal to 2% of the lenders’ respective commitments thereunder upon entry of the Final DIP Order. Additionally, if the Plan is consummated, the Debtors will pay a backstop fee equal to 3% of the lenders’ respective commitments in the form of new common equity of the reorganized Company, and if the Plan is not consummated, the Company will pay such fee in cash, which shall not take into account the Third DIP Draw amount unless such Third DIP Draw is actually funded.

Pursuant to the terms of the DIP Credit Agreement and related guaranty, the Filing Subsidiaries have guaranteed the obligations of the Company, as borrower under the DIP Facility.


F-47

The obligations under the DIP Credit Agreement are secured by liens on substantially all of the Company’s assets as follows:

i.
(a) up to $70 million of obligations under the DIP Facility are secured by perfected first priority “priming liens” on the Company’s prepetition liens (including prepetition liens securing the Second Lien Term Loan), and (b) other obligations under the DIP Facility are secured by perfected junior liens on the Company’s prepetition liens (including liens securing the Second Lien Term Loan), subject to certain exceptions and intercreditor arrangements; and
ii.
the obligations under the DIP Facility are secured by perfected first priority liens on the Company’s unencumbered assets, subject to certain exceptions, including an exception for the Company’s equity interest in Eureka Midstream Holdings as noted below.

The DIP Credit Agreement is not secured by the Company’s equity interest in Eureka Midstream Holdings. However, the DIP Credit Agreement is secured by the Company’s economic interest in Eureka Midstream Holdings. The DIP Lenders can take ownership of such economic interest in Eureka Midstream Holdings in the event of a liquidation of the Debtors, but will not have the ability to foreclose on such economic interest solely as a result of an event of default occurring under the DIP Credit Agreement. Upon an event of default under the DIP Credit Agreement, the DIP Lenders shall be entitled to require the Debtors to sell such equity interest at a price and on terms as the DIP Lenders deem commercially reasonable, and the DIP Lenders shall be entitled to credit bid all or a portion of the outstanding DIP Credit Agreement obligations in such sale. The security interests and liens under the DIP Credit Agreement are subject to certain carve-outs and permitted liens, as set forth in the DIP Credit Agreement.

The Debtors are subject to certain covenants under the DIP Facility, including, without limitation, restrictions on the incurrence of additional debt, liens, and the making of restricted payments, and compliance with certain bankruptcy-related covenants, in each case as set forth in the DIP Credit Agreement and any order of the Bankruptcy Court approving the DIP Credit Agreement. The DIP Credit Agreement contains customary representations of the Debtors, and provides for certain events of default customary for similar DIP financings. Additionally, the DIP Credit Agreement contains a specific event of default based upon the occurrence of a consecutive 15-day trading period during which natural gas prices as published by NYMEX are less than $1.65 per MMBtu. Furthermore, each of the following Milestones is included in the DIP Credit Agreement, and any failure to comply with these Milestones will constitute an event of default:

i.
No later than December 17, 2015, the Bankruptcy Court shall have entered the Interim DIP Order (which has occurred);
ii.
No later than January 7, 2016, the Debtors shall have filed with the Bankruptcy Court a motion to reject executory contracts and set procedures regarding rejection damages (which has occurred);
iii.
No later than January 7, 2016, the Debtors shall have filed with the Bankruptcy Court: (i) the Plan, (ii) the disclosure statement of the Plan, (iii) a motion seeking approval of the disclosure statement of the Plan and the Plan as well as certain other items, and (iv) a motion seeking to assume the RSA (which has occurred);
iv.
No later than January 15, 2016, the Bankruptcy Court shall have entered the Final DIP Order (which has occurred);
v.
No later than February 12, 2016, the Bankruptcy Court shall have entered an order approving assumption of the RSA (which has occurred);
vi.
No later than February 26, 2016, (i) the Bankruptcy Court shall have entered an order approving the disclosure statement with respect to the Plan (which has occurred) and (ii) no later than February 29, 2016, the Debtors shall have commenced solicitation on the Plan (which has occurred);
vii.
No later than April 18, 2016, the Bankruptcy Court shall have commenced the confirmation hearing on the Plan (which has occurred), and no later than April 19, 2016, the Bankruptcy Court shall have entered the Plan confirmation order (which has occurred); and
viii.
No later than May 6, 2016, the Debtors shall consummate the transactions contemplated by the Plan.

The Company has met all Milestones thus far. The remaining Milestone to be completed is the consummation of the transactions contemplated by the Plan no later than May 6, 2016. There can be no assurance that this Milestone will be achieved. The continuation of the Chapter 11 Cases, particularly if the Plan is not implemented within the timeframe currently contemplated, could adversely affect operations and relationships between the Company and its customers, suppliers, vendors, service providers, and other creditors and result in increased professional fees and similar expenses. Failure to implement the Plan could further weaken the Company’s liquidity position, which could jeopardize the Company’s exit from Chapter 11 reorganization.


F-48

The DIP Facility is subject to certain prepayment events, including, upon the receipt of proceeds from certain asset sales, insurance and condemnation events and the issuance of post-petition debt or equity, subject in each case to customary exceptions as set forth in the DIP Credit Agreement and any order of the Bankruptcy Court approving the DIP Credit Agreement. The DIP Credit Agreement also provides for the payment of certain adequate protection payments with respect to the Bridge Financing Facility and Second Lien Facility, and includes a budget variance financial covenant which permits a variance of up to 20% on receipts (excluding royalties), disbursements (subject to certain adjustments) and capital expenditures.

Upon any termination of the RSA, the Tranche A Lenders have the right to buy from the Tranche B Lenders up to 15% of such Tranche B Lenders’ portion of the funded and unfunded DIP Facility by delivering an irrevocable notice of intent to purchase within 10 days of the date of termination (provided that the purchase is complete within 5 business days). Pursuant to the terms of the RSA, the DIP Facility converts into new common equity of the reorganized Company at a 25% discount to Plan value.

Second Lien Term Loan

In conjunction with the October 22, 2014 amendment to the MHR Senior Revolving Facility, 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 (the “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 the MHR Senior Revolving Facility, to pay transaction expenses related to the MHR Senior Revolving Facility 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, at the Company’s election, bore 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 and financial covenants substantially similar to those in the MHR Senior Revolving Facility 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 MHR Senior Revolving Facility. The Second Lien Term Loan Agreement limited the amount of indebtedness that the Company could have incurred under the MHR Senior Revolving Facility 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.


F-49

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.

On and effective as of April 17, 2015, the Company entered into a First Amendment to Credit Agreement and Limited Waiver (the “First Amendment”), by and among the Company, as borrower, Credit Suisse AG Cayman Islands Branch, as administrative agent and collateral agent, and the several lenders and guarantors party thereto. The First Amendment amended the Second Lien Term Loan Agreement by permanently extending the amount of time the Company and its Restricted Subsidiaries (as defined in the Second Lien Term Loan Agreement) may have accounts payable outstanding after the invoice date from 90 days to 180 days. In addition, pursuant to the First Amendment, the lenders waived any default or event of default that may have occurred in connection with any non-compliance with the accounts payable aging limitation in effect prior to the effective date of the First Amendment.

On November 3, 2015, the Company entered into a Forbearance Agreement and Second Amendment (the “Second Amendment”) to the Second Lien Credit Agreement. The Second Amendment provided for a forbearance by the lenders under the Second Lien Term Loan Agreement that entered into the Senior Secured Bridge Financing Facility with respect to exercising remedies regarding any default or event of default that results from the failure of the Company to make any interest payment under the Second Lien Term Loan Agreement, the failure to meet certain financial covenants thereunder, and certain other matters (including the default that arose on account of  trade payables being outstanding for more than 180 days). The Second Amendment also amends certain other terms of the Second Lien Term Loan Agreement as necessary to permit the Senior Secured Bridge Financing Facility and to make certain covenants in the Second Lien Term Loan Agreement consistent with the revised covenants in the Senior Secured Bridge Financing Facility. The covenants under the Second Lien Term Loan Agreement otherwise remain substantially the same, subject to customary adjustments for such financings described herein.

Under the Second Amendment, the lenders under the Second Lien Term Loan Agreement that entered into the Senior Secured Bridge Financing Facility agreed to forbear from exercising remedies under the Second Lien Term Loan Agreement with respect to any failure by the Company to make the October 30, 2015 interest payment under the Second Lien Term Loan Agreement and certain other defaults and events of default (including the default that arose on account of  trade payables being outstanding for more than 180 days). The forbearance included in the Second Amendment terminated upon the filing of the Chapter 11 cases by the Debtors.

Defaults under the Second Lien Term Loan Agreement

On July 27, 2015, the Company became aware of a default under the Second Lien Term Loan Agreement relating to the aging of the Company’s accounts payable. In accordance with the terms of the Second Lien Term Loan Agreement the Company may not have accounts payable outstanding (subject to certain permissible amounts) in excess of 180 days from the invoice date. The Company cured the default in accordance with the Second Lien Term Loan Agreement on August 26, 2015.

On September 8, 2015, the Company became aware of an additional default under the Second Lien Term Loan Agreement because the Company had approximately $1.4 million in accounts payable outstanding (in excess of permissible amounts) in excess of 180 days from the invoice date. Under the Second Lien Term Loan Agreement, the Company had 30 days to cure this default. As of October 8, 2015, the Company continued to have accounts payable outstanding (in excess of permissible amounts) in excess of 180 days from the invoice date, resulting in an event of default. Due to the event of default, the lenders under the Second Lien Term Loan Agreement were permitted to, but did not, declare the outstanding loan amounts immediately due and payable.

As described above, under the Second Amendment, the lenders under the Second Lien Term Loan Agreement that entered into the Senior Secured Bridge Financing Facility agreed to forbear from exercising remedies under the Second Lien Term Loan Agreement with respect to any failure by the Company to make the October 30, 2015 interest payment under the Second Lien Term Loan Agreement and certain other defaults (including the default that arose on account of  trade payables being outstanding for more than 180 days). The forbearance included in the Second Amendment terminated upon the filing of the Chapter 11 cases by the Debtors.

As of December 31, 2015, the balance outstanding under the Second Lien Term Loan Agreement was $335.9 million and is included in “Liabilities subject to compromise” in the accompanying consolidated balance sheet. See “Note 3 - Voluntary Reorganization under Chapter 11”. Under the Bankruptcy Code, the creditors under the Second Lien Term Loan Agreement are stayed from taking any action against the Debtors as a result of any default or event of default.


F-50

Senior Notes
 
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 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 Company has not paid the interest payment which was due on November 15, 2015 on its Senior Notes. Interest on the Senior Notes accrues at an annual rate of 9.75% and is payable semi-annually on May 15 and November 15. The total interest payment due on November 15, 2015 was approximately $29.3 million. The failure by the Company to make the interest payment on the Senior Notes within 30 days following the due date constituted an event of default under the Senior Notes, and the Senior Notes have been declared immediately due and payable. However, at such time, payments under the Senior Notes were the subject of forbearance agreements described below and in “- Second Lien Term Loan”.

On November 3, 2015, the Company and the New Senior Notes Lenders entered into a Forbearance Agreement (the “Forbearance Agreement”) whereby the New Senior Notes Lenders agreed to forbear during the forbearance period from exercising any remedies as a result of any default, Default or Event of Default under (as such terms are defined in) the Indenture that is present as a result of (i) the failure of the Company to make any interest payment otherwise due under the Senior Notes, (ii) a breach of the debt incurrence covenant under the Indenture, or (iii) the failure of the Company to make any interest payment otherwise due pursuant to the Second Lien Term Loan Agreement (collectively, the “Anticipated Defaults”). The Forbearance Agreement terminated upon the filing of the Chapter 11 cases by the Debtors. Additionally, the New Senior Notes Lenders consented to an amendment to the Indenture, pursuant to a supplemental indenture, which amended the incurrence of indebtedness covenant in the Indenture to permit the borrowings under the Senior Secured Bridge Financing Facility.

Upon the occurrence of the event of default arising from the bankruptcy filings, the Senior Notes were accelerated and became immediately due and payable. Under the Bankruptcy Code, the holders of the Senior Notes are stayed from taking any action against the Debtors as a result of any default or event of default, including the bankruptcy filing.

The Company’s outstanding Senior Notes of $599.3 million are included in “Liabilities subject to compromise” in the accompanying consolidated balance sheet as of December 31, 2015. See “Note 3 - Voluntary Reorganization under Chapter 11”.
 
Equipment Note Payable

On January 23, 2014, the Company’s wholly owned subsidiary, Alpha Hunter Drilling, 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.

Under the related master loan and security agreement, an event of default includes a default or event of default by any guarantor of the loan under any financial obligation to any person or entity other than CIT Finance, LLC, resulting in a claim by such person or entity in an amount greater than $1.0 million, which default or event of default entitles such person or entity to accelerate, or otherwise exercise its remedies under, such financial obligation. As such, a cross-default arose under Alpha Hunter Drilling’s master loan and security agreement on October 8, 2015 when the obligations under the MHR Senior Revolving Facility and Second Lien Term Loan Agreement became callable. In addition, the filing of the Chapter 11 Cases constituted an event of default under the master loan and security agreement, causing the principal and interest thereunder to be immediately due and payable.

As of December 31, 2015, the outstanding balance of this loan was approximately $2.8 million and is included in “Current portion of long-term debt” in the accompanying consolidated balance sheet as of that date.

Building Note Payable

Effective September 30, 2014, MHP refinanced its 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.

F-51


The filing of the Chapter 11 Cases constituted an event of default under the term loan agreement with Traditional Bank, Inc., which caused the principal and interest thereunder to be immediately due and payable. As of December 31, 2015, the outstanding balance of this loan was approximately $3.6 million and is included in “Current portion of long-term debt” in the accompanying consolidated balance sheet as of that date.

Interest Expense

The following table sets forth interest expense for the years ended December 31, 2015, 2014 and 2013:

 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(in thousands)
Interest expense incurred on debt, net of amounts capitalized
$
91,032

 
$
76,784

 
$
67,803

Amortization and write-off of deferred financing costs
8,527

 
9,679

 
4,818

Total interest expense
$
99,559

 
$
86,463

 
$
72,621

 
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. No interest was capitalized during the year ended December 31, 2015. Interest of $2 million was capitalized as part of the construction of Eureka Midstream Holdings’ gas gathering system during the year ended December 31, 2014, prior to deconsolidation on December 18, 2014, and $2.6 million was capitalized during the year ended December 31, 2013.

For the year ended December 31, 2015, interest expense includes the write-off of $1.1 million in unamortized deferred financing costs related to the July 10, 2015 amendment of the MHR Senior Revolving Credit Facility and the write-off of $0.9 million in unamortized deferred financing costs related to the November 3, 2015 replacement of the MHR Senior Revolving Credit Facility with the Senior Secured Bridge Financing Facility. On the Petition Date, the Debtors ceased accruing interest on unsecured and undersecured debt obligations. See “Note 3 - Voluntary Reorganization under Chapter 11”.
 
For the year ended December 31, 2014, interest expense incurred on debt includes a $2.2 million prepayment penalty incurred by Eureka Midstream as a result of its early termination of the Original Eureka Midstream 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 October 22, 2014 amendment of the MHR Senior Revolving Credit Facility.

NOTE 12 - SHARE-BASED COMPENSATION

Employees, officers, directors and certain other persons 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, 2015, 27,500,000 shares of the Company’s common stock are authorized to be issued under the plan, and 11,539,043 shares have been issued as of December 31, 2015, of which 3,389,896 shares remained unvested at December 31, 2015. Additionally, 7,314,751 options to purchase shares were outstanding as of December 31, 2015, of which 592,801 remained unvested at December 31, 2015.

The Company recognized share-based compensation expense of $6.0 million, $11.4 million, and $13.6 million for the years ended December 31, 2015, 2014, and 2013 respectively.


F-52



A summary of stock option and stock appreciation rights activity for the years ended December 31, 2015, 2014, and 2013 is presented below:
 
2015
 
2014
 
2013
 
 
 
Weighted-Average Exercise Price
 
 
 
Weighted-Average Exercise Price
 
 
 
Weighted-Average Exercise Price
 
Shares
 
 
Shares
 
 
Shares
 
Outstanding at beginning of the year
13,194,956

 
$
5.91

 
16,891,419

 
$
5.69

 
14,846,994

 
$
6.01

Granted
—

 
$
—

 
—

 
$
—

 
4,937,575

 
$
4.11

Exercised
(100,000
)
 
$
0.51

 
(2,375,273
)
 
$
4.09

 
(1,466,025
)
 
$
3.66

Forfeited or expired
(5,780,205
)
 
$
6.24

 
(1,321,190
)
 
$
6.27

 
(1,427,125
)
 
$
5.51

Outstanding at end of the year
7,314,751

 
$
5.75

 
13,194,956

 
$
5.91

 
16,891,419

 
$
5.69

Exercisable at end of the year
6,721,950

 
$
5.89

 
9,140,323

 
$
6.22

 
9,983,743

 
$
5.96


A summary of the Company’s non-vested common stock options and stock appreciation rights for the years ended December 31, 2015, 2014, and 2013 is presented below:
Non-vested Options
2015
 
2014
 
2013
Non-vested at beginning of the year
4,054,633

 
6,907,476

 
6,163,372

Granted
—

 
—

 
4,937,575

Vested
(1,635,365
)
 
(1,915,526
)
 
(3,133,700
)
Forfeited
(1,826,467
)
 
(937,317
)
 
(1,059,771
)
Non-vested at end of the year
592,801

 
4,054,633

 
6,907,476



Total unrecognized compensation cost related to the non-vested common stock options and stock appreciation rights was $0.2 million, $3.2 million, and $14.1 million as of December 31, 2015, 2014, and 2013, respectively. The unrecognized compensation cost at December 31, 2015 is expected to be recognized over a weighted-average period of 0.13 years. At December 31, 2015, there was no aggregate intrinsic value for the outstanding options and stock appreciation rights; and the weighted average remaining contract life of the outstanding options was 5.33 years.

No options or stock appreciation rights were granted during the years ended December 31, 2015 or 2014. The assumptions used in the fair value method calculations for the year ended December 31, 2013 are disclosed in the following table:
 
 
Year Ended December 31,
 
 
2013
Weighted average fair value per option granted during the period (1)
$2.52
Assumptions (2) :
 
Weighted average stock price volatility (3)
80.61%
Weighted average risk free rate of return
0.78%
Weighted average estimated forfeiture rate
2.45%
Weighted average expected term
4.65 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.    

During the years ended December 31, 2015, 2014, and 2013, the Company granted 128,559, 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.

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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 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.

On March 30, 2015, the Company granted 535,274 shares of common stock for 2014 bonuses to executives and officers of the Company. The shares had a fair value at the time of grant of $1.4 million based on the Company’s stock price on the grant date. On June 18, 2015, the Company granted 600,000 restricted shares of common stock to non-employee members of the board of directors of the Company which vest two years from the date of grant, or if earlier, (i) upon the death or disability of the director or (ii) upon a change in control of the Company that occurs at least six months following the date of grant. The shares had a fair value of $0.7 million based on the Company’s stock price on the grant date and an estimated forfeiture rate of 5.6%. On September 1, 2015, the Company granted 2,000,000 restricted shares of common stock outside of the Company’s Amended and Restated Stock Incentive Plan to a newly hired executive officer. These restricted shares will vest in equal amounts on March 31, 2016, September 1, 2017, and September 1, 2018. The shares had a fair value of $1.5 million based on the Company’s stock price on the grant date and an estimated forfeiture rate of 5.6%. During the year ended December 31, 2015, the Company also granted an additional 205,000 restricted shares of common stock to certain newly hired officers. These 205,000 shares will vest over a 3-year period and had a fair value of $0.3 million based on the Company’s stock price on the grant date and an estimated forfeiture rate of 5.6%.

A summary of the Company’s non-vested common shares granted under the Stock Incentive Plan as of December 31, 2015, 2014, and 2013 is presented below:
 
2015
 
2014
 
2013
 
 
 
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
2,352,013

 
$
5.99

 
27,500

 
$
7.24

 
65,025

 
$
6.09

Granted
3,468,833

 
$
1.24

 
3,239,796

 
$
5.66

 
210,494

 
$
4.66

Forfeited
(847,514
)
 
$
5.92

 
(135,000
)
 
$
7.26

 
—

 
$
—

Vested
(1,583,436
)
 
$
4.51

 
(780,283
)
 
$
4.48

 
(248,019
)
 
$
4.75

Non-vested at end of the year
3,389,896

 
$
2.92

 
2,352,013

 
$
5.99

 
27,500

 
$
7.24

 
Total unrecognized compensation cost related to the above non-vested shares amounted to $5.2 million, $9.7 million, and $0.2 million as of December 31, 2015, 2014, and 2013, respectively. The unrecognized compensation cost at December 31, 2015 is expected to be recognized over a weighted-average period of 2.03 years.

Eureka Midstream Holdings, LLC Management Incentive Compensation Plan

On May 12, 2014, the Board of Directors of Eureka Midstream Holdings approved the Eureka Midstream Holdings, LLC Management Incentive Compensation Plan (the “Eureka Midstream Holdings Plan”) to provide long-term incentive compensation to attract and retain officers and employees of Eureka Midstream Holdings and its affiliates and allow such individuals to participate in the economic success of Eureka Midstream Holdings and its affiliates.
  
The Eureka Midstream Holdings Plan consists of (i) 2,336,905 Class B Common Units representing membership interests in Eureka Midstream 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 Midstream Holdings Plan is administered by the board of managers of Eureka Midstream Holdings, and, as administrator of the Eureka Midstream Holdings Plan, the board may from time to time make awards under the

F-54



Eureka Midstream Holdings Plan to selected officers and employees of Eureka Midstream Holdings or its affiliates (“Award Recipients”).

Upon approval of the plan on May 12, 2014, the board of managers of Eureka Midstream Holdings granted 894,102 Class B Common Units and 894,102 Incentive Plan Units to key employees and officers of Eureka Midstream 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 and officers of Eureka Midstream 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 Midstream Holdings and concluded that as of December 18, 2014, a liquidity event, as defined, was not probable, and therefore, no compensation cost was recognized.

NOTE 13 - SHAREHOLDERS' EQUITY

Common Stock

During the years ended December 31, 2015, 2014, and 2013, the Company issued:

i.
1,383,449, 657,317, and 182,994 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.
100,000, 2,375,273, and 1,466,025 shares, respectively, of the Company’s common stock upon the exercise of warrants and options for total proceeds of approximately $0.1 million, $9.7 million, and $5.4 million, respectively.


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.

On March 13, 2015, the Company filed a universal shelf Form S-3 Registration Statement to register the sale by the Company of a maximum aggregate amount of up to $500.0 million of debt and equity securities. The Company filed amendments to this Form S-3 Registration Statement on April 15, 2015 and April 20, 2015 and the Form S-3 Registration Statement became effective on April 22, 2015. On April 23, 2015, the Company entered into an “At the Market” Sales Agreement with a sales agent to conduct ATM offerings of its equity securities. As of December 31, 2015, the Company had sold an aggregate of 56,202,517 shares of its common stock for aggregate proceeds of $58.2 million, net of $1.3 million in sales commissions and other fees, through this ATM offering under the Form S-3 Registration Statement.

As a result of the suspension of monthly cash dividends on its preferred stock issuances and the bankruptcy filing, the Company became ineligible to issue securities, including issuances of common stock in ATM offerings, under its universal shelf Registration Statement on Form S-3, which was declared effective on April 22, 2015. See further discussion below related to each series of preferred stock for additional information regarding the Company’s suspension of monthly cash dividends.

The Plan contemplates no recovery for, and cancellation of, the Company’s outstanding common stock. As a result, the Company believes that it is highly likely that the shares of its existing common stock will be canceled in its Chapter 11 proceedings and will be entitled to no recovery.


F-55



Magnum Hunter Resources Corporation 401(k) Employee Stock Ownership Plan

During the years ended December 31, 2015, 2014, and 2013, the Company issued an aggregate of 2,290,565, 249,531, and 221,170 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, 2015, except for statutorily required “safe harbor” matching contributions. Shares issued to and held by the Plan are included in the Company’s EPS calculation.

During the years ended December 31, 2015, 2014, and 2013, the Company recognized $1.9 million, $1.6 million and $1.2 million, respectively, in compensation attributable to its KSOP. As of December 31, 2015 the KSOP held 2,797,554 shares of the Company’s common stock.
 
Exchangeable Common Stock

On May 3, 2011, in connection with a previous acquisition, the Company issued 4,275,998 exchangeable shares of MHR Exchangeco Corporation, which are exchangeable for shares of the Company at a one for one ratio. The shares of MHR Exchangeco Corporation were valued at approximately $31.6 million. Each exchangeable share was exchangeable for one share of the Company’s common stock at any time after issuance at the option of the holder and was redeemable at the option of the Company, through Exchangeco, after one year or upon the earlier of certain specified events. During the year ended December 31, 2013, the remaining 505,835 of the exchangeable shares were exchanged for common shares of the Company. As of December 31, 2015 and 2014, there were no exchangeable shares outstanding.

Common Stock Warrants

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 are not currently exercisable. 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, 2013, 13,237,889 of the Company’s $10.50 common stock warrants expired. During the year ended December 31, 2014, 97,780 of the Company’s $15.13 common stock warrants and 40,608 of the Company’s $19.04 common stock warrants expired.

F-56




 A summary of warrant activity for the years ended December 31, 2015, 2014, and 2013 is presented below:
 
 
2015
 
2014
 
2013
 
 
Weighted -
 
 
Weighted -
 
 
Weighted -
 
 
Average
 
 
Average
 
 
Average
 
Shares
Exercise Price
 
Shares
Exercise Price
 
Shares
Exercise Price
Outstanding at beginning of year
19,173,480

$
8.50

 
17,169,010

$
8.56

 
13,376,277

$
10.56

Granted
—

$
—

 
2,142,858

$
8.50

 
17,030,622

$
8.50

Exercised, forfeited, or expired
—

$
—

 
(138,388
)
$
16.28

 
(13,237,889
)
$
10.50

Outstanding at end of year
19,173,480

$
8.50

 
19,173,480

$
8.50

 
17,169,010

$
8.56

Exercisable at end of year
2,142,858

$
8.50

 
2,142,858

$
8.50

 
138,388

$
16.28


At December 31, 2015, the warrants had no aggregate intrinsic value; and the weighted average remaining contract life was 0.3 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 and a dividend rate of 8.0% per annum (based on stated liquidation preference). The Series D Preferred Stock is not convertible 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.

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. 

On October 9, 2015, the Company announced that it had suspended monthly cash dividends on all of its outstanding series of preferred stock. The suspension commenced with the monthly cash dividend that would otherwise have been declared and paid for the month ending October 31, 2015 and will continue indefinitely. The Company accrued dividends for its Series D Preferred Stock of approximately $3.6 million for the period from October 1, 2015 through the Petition Date. The Company ceased accruing dividends subsequent to the Petition Date. Accrued dividends payable are presented in “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2015.

The Plan contemplates no recovery for, and cancellation of, the Company’s existing preferred stock. As a result, the Company believes that it is highly likely that the shares of its existing preferred stock will be canceled in its Chapter 11 proceedings and will be entitled to no recovery.

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. 

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.

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.


F-57



On October 9, 2015, the Company announced that it had suspended monthly cash dividends on all of its outstanding series of preferred stock. The suspension commenced with the monthly cash dividend that would otherwise have been declared and paid for the month ending October 31, 2015 and will continue indefinitely. The Company accrued dividends for its Series E Preferred Stock of approximately $1.5 million for the period from October 1, 2015 through the Petition Date. The Company ceased accruing dividends subsequent to the Petition Date. Accrued dividends payable are presented in “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2015.

The Plan contemplates no recovery for, and cancellation of, the Company’s existing preferred stock. As a result, the Company believes that it is highly likely that the shares of its existing preferred stock will be canceled in its Chapter 11 proceedings and will be entitled to no recovery.

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 Midstream Holdings, then a majority owned subsidiary, issued 622,641 Class A Common Units representing membership interests in Eureka Midstream 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 Midstream 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 Midstream Holdings in the Company’s consolidated balance sheet. As a result of the deconsolidation of Eureka Midstream Holdings, the Company derecognized the non-controlling interests attributed to Eureka Midstream Holdings as part of the gain on deconsolidation (see “Note 4 - Eureka Midstream Holdings”).

Preferred Dividends Incurred

A summary of dividends incurred by the Company for the years ended December 31, 2015, 2014, and 2013 is presented below:
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(in thousands)
Dividend on Eureka Midstream Holdings Series A Preferred Units
$
—

 
$
12,760

 
$
14,323

Eureka MidstreamAccretion of the carrying value of the Eureka Midstream Holdings Series A Preferred Units
—

 
6,583

 
6,918

Dividend on Series C Preferred Stock
9,792

 
10,248

 
10,248

Dividend on Series D Preferred Stock
16,911

 
17,698

 
17,655

Dividend on Series E Preferred Stock
7,114

 
7,418

 
7,561

 Total dividends on Preferred Stock
$
33,817

 
$
54,707

 
$
56,705


Net Income or Loss per Share Data

The Company has issued potentially dilutive instruments in the form of its restricted common stock granted and not yet issued, common stock warrants, common stock options granted to the Company’s employees and directors, and the Company’s Series E Cumulative Convertible Preferred Stock. The Company did not include any of these instruments in its calculation of diluted loss

F-58



per share during the years ended December 31, 2015, 2014, and 2013 because to include them would be anti-dilutive due to the Company’s loss from continuing operations during such periods.

The following table summarizes the types of potentially dilutive securities outstanding as of December 31, 2015, 2014 and 2013:

 
December 31,
 
2015
 
2014
 
2013
 
(in thousands of shares)
Series E Preferred Stock
11,126

 
10,946

 
10,946

Warrants
19,173

 
19,173

 
17,169

Restricted shares granted, not yet issued
3,643

 
2,369

 
28

Common stock options
7,315

 
13,195

 
16,891

Total
41,257

 
45,683

 
45,034



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 and a dividend rate of 10.25% per annum (based on stated liquidation preference). The Series C Preferred Stock is not convertible 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.

On October 9, 2015, the Company announced that it had suspended monthly cash dividends on all of its outstanding series of preferred stock. The suspension commenced with the monthly cash dividend that would otherwise have been declared and paid for the month ending October 31, 2015 and will continue indefinitely. The Company accrued dividends for its Series C Preferred Stock of approximately $2.1 million for the period from October 1, 2015 through the Petition Date. The Company ceased accruing dividends subsequent to the Petition Date. Accrued dividends payable are presented in “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2015.

The Plan contemplates no recovery for, and cancellation of, the Company’s existing preferred stock. As a result, the Company believes that it is highly likely that the shares of its existing preferred stock will be canceled in its Chapter 11 proceedings and will be entitled to no recovery.

Eureka Midstream Holdings Series A Preferred Units
 
On March 21, 2012, Eureka Midstream 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 Midstream Holdings Series A Preferred Units, of which $200 million were purchased through September 16, 2014.

During the years ended December 31, 2014 and 2013, Eureka Midstream Holdings issued 610,000 and 1,800,000 Eureka Midstream Holdings Series A Preferred Units, respectively, to Ridgeline for net proceeds of $12.0 million and $35.3 million, respectively, net of transaction costs. Eureka Midstream Holdings paid cumulative distributions quarterly on the Eureka Midstream 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 Midstream 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 Midstream Holdings Series A Preferred Units were convertible into Class A Common Units of Eureka Midstream Holdings upon demand by Ridgeline or by Eureka Midstream 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 Midstream Holdings was allowed to redeem all outstanding Eureka Midstream 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 Midstream Holdings

F-59



Series A Preferred Units could force the redemption of all outstanding Eureka Midstream Holdings Series A Preferred Units any time after March 21, 2020. The Eureka Midstream 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 Midstream Holdings. 

During the years ended December 31, 2014 and 2013, the Company paid cash distributions of $10.2 million and $5.2 million, respectively. The Company accrued distributions not yet paid of $3.9 million during the year ended December 31, 2013 to the holder of the Eureka Midstream Holdings Series A Preferred Units. During such years, distributions in the amount of $1.9 million and $8.2 million, respectively, were paid-in-kind to the holder of the Eureka Midstream Holdings Series A Preferred Units, and the Company issued 97,492 and 412,157 Eureka Midstream Holdings Series A Preferred Units, respectively, as payment.

The Company evaluated the Eureka Midstream 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 Midstream Holdings Series A Preferred Units and presented in long term liabilities. The fair value of this embedded feature was $173.2 million at October 3, 2014. The embedded derivative associated with the Eureka Midstream Holdings Series A Preferred Units was extinguished upon conversion as discussed in “Note 4 - Eureka Midstream Holdings”.

On October 3, 2014, the outstanding Eureka Midstream Holdings Series A Preferred Units were purchased from Ridgeline by MSI and converted into Series A-2 Units of Eureka Midstream Holdings.

As a result of the conversion of the Eureka Midstream 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 Midstream Holdings. The Series A-2 Units non-controlling interest was derecognized upon deconsolidation and included as part of the gain on deconsolidation. See “Note 4 - Eureka Midstream Holdings”.

Extinguishment of Eureka Midstream 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 Midstream 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 Midstream 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 $389.0 million and recognized a loss on extinguishment of the Eureka Midstream 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 Midstream 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.

NOTE 15 - INCOME TAXES

The total provision for income taxes applicable to continuing operations consists of the following:
 
 
Year Ended December 31,
 
 
2015
 
2014
 
2013
 
 
(in thousands)
Deferred income tax benefit
 
 
 
 
 
 
Federal
 
$
—

 
$
—

 
$
(78,743
)
State
 
—

 
—

 
(6,664
)
Total deferred tax benefit
 
$
—

 
$
—

 
$
(85,407
)
Total income tax benefit
 
$
—

 
$
—

 
$
(85,407
)


F-60



At December 31, 2015, the Company had net operating loss carry forwards (“NOLs”) available for U.S. federal income tax purposes of approximately $1,031 million, which expire in varying amounts during the tax years 2018 through 2035. 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, 2015, the Company was not under examination by any federal taxing jurisdiction. The Company has various state audits in the initial stages of examination which the Company does not believe will have a material impact to its financial condition or results of operations.

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 $509.1 million against the net deferred tax assets of the Company at December 31, 2015. 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, 2015, 2014, and 2013 to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income:
 
 
Year Ended December 31,
 
 
2015
 
2014
 
2013
 
 
(in thousands)
Income tax benefit at statutory U.S. rate
 
$
(274,355
)
 
$
(48,242
)
 
$
(111,132
)
State income taxes (net of federal benefit)
 
(28,930
)
 
(3,616
)
 
(4,331
)
Tax effect of permanent differences
 
224

 
(498
)
 
750

Provision to return adjustment
 
—

 
(11,736
)
 
—

Foreign statutory tax rate differences
 
(9
)
 
297

 
—

Tax effect of loss attributable to non-controlled interest
 
—

 
1,279

 
346

Tax benefit recognized as tax expense in discontinued operations
 
—

 
—

 
(28,989
)
Change in valuation allowance
 
302,373

 
63,341

 
58,341

Other
 
697

 
(825
)
 
(392
)
Total continuing operations
 
—

 
—

 
(85,407
)
Discontinued operations
 
—

 
—

 
11,773

Total tax benefit
 
$
—

 
$
—

 
$
(73,634
)

Income (loss) before income taxes was as follows:
 
 
Year Ended December 31,
 
 
2015
 
2014
 
2013
 
 
(in thousands)
Domestic
 
$
(783,963
)
 
$
(134,853
)
 
$
(317,520
)
Foreign
 
91

 
(2,980
)
 
—

Loss from continuing operations
 
(783,872
)
 
(137,833
)
 
(317,520
)
Gain (loss) from discontinued operations
 
—

 
4,561

 
(62,655
)
Gain (loss) on disposal of discontinued operations
 
—

 
(13,855
)
 
83,378

Loss before income tax
 
$
(783,872
)
 
$
(147,127
)
 
$
(296,797
)


F-61



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,
 
 
2015
 
2014
 
2013
 
 
(in thousands)
Deferred tax assets:
 
 
 
 
 
 
  Net operating loss carry forwards
 
$
371,531

 
$
263,452

 
$
155,507

Property and equipment
 
162,236

 
63,823

 
—

Capital loss carry forward
 
76,955

 
38,401

 
—

Share-based compensation
 
17,293

 
15,035

 
10,156

Depletion carry forwards
 
1,047

 
1,047

 
1,047

Tax credits
 
53

 
53

 
53

US investment in Canada
 
—

 
—

 
74,148

Other
 
15,354

 
1,562

 
561

Deferred tax liabilities:
 
 
 
 
 
 
Property and equipment
 
—

 
—

 
(90,950
)
Investment in Eureka Midstream Holdings
 
(135,331
)
 
(176,606
)
 
—

Valuation allowance
 
 
 
 
 
 
Tax credits
 
(53
)
 
(53
)
 
(53
)
Depletion carry forwards
 
(1,047
)
 
(1,047
)
 
(1,047
)
Capital loss carry forward
 
(76,955
)
 
(38,401
)
 
—

Net operating losses
 
(371,531
)
 
(263,452
)
 
(155,507
)
Other
 
(59,552
)
 
96,186

 
80,233

US investment in Canada
 
—

 
—

 
(74,148
)
Net deferred tax asset (liability)
 
$
—

 
$
—

 
$
—



As of December 31, 2015, 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, 2015, the Company has accrued no amounts for potential payment of interest and penalties.

Following is a reconciliation of the total amounts of unrecognized tax benefits during the years ended December 31, 2015, 2014 and 2013:
 
 
Year Ended December 31,
 
 
2015
 
2014
 
2013
 
 
(in thousands)
Unrecognized tax benefits at January 1
$
3,879

 
$
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)
—

 
—

 
—

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

 
 
 
 
 
 
 

F-62



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, 2015, 2014 and 2013. The loss of any one significant purchaser could have a material, adverse effect on the ability of the Company to sell its oil and gas production. In September 2015, one of the Company’s purchasers, Samson Resources Company, filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code.

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,
 
2015
 
2014
 
2013
Samson Resources Company (1)
22
%
 
24
%
 
31
%
Markwest Liberty Midstream
14
%
 
15
%
 
6
%
Tenaska Marketing Ventures
11
%
 
17
%
 
10
%
Baytex Energy USA LTD
—
%
 
7
%
 
11
%
_________________
(1) See “Note 18 - Commitments and Contingencies - Samson Matter”

NOTE 17 - RELATED PARTY TRANSACTIONS

The following table sets forth the related party balances as of December 31, 2015 and 2014:

 
As of December 31,
 
2015
 
2014
 
(in thousands)
GreenHunter (1)
 
 
 
     Accounts receivable, net of reserve
$
—

 
$
21

     Accounts payable
$
(24
)
 
$
(249
)
Liabilities subject to compromise
$
(635
)
 
$
—

     Derivative assets (2)
$
—

 
$
75

     Investments (2)
$
81

 
$
1,311

     Notes receivable, net of reserve (2)
$
—

 
$
1,224

     Prepaid expenses
$
5

 
$
1,000

Eureka Midstream Holdings (3)
 
 
 
Accounts receivable
$
5,467

 
$
2,898

     Accounts payable
$
(1,480
)
 
$
(2,776
)
Liabilities subject to compromise
$
(15,827
)
 
$
—

Equity method investment
$
166,099

 
$
347,191

Pilatus Hunter (4)
 
 
 
Accounts receivable
$
12

 
$
12

Classic Petroleum, Inc. (5)
 
 
 
Liabilities subject to compromise
$
(51
)
 
$
—



F-63



The following table sets forth the related party transaction activities for the years ended December 31, 2015, 2014 and 2013:
 
 
Years Ended 
 
 
December 31,
 
 
2015
 
2014
 
2013
 
 
(in thousands)
GreenHunter
 
 
 
 
 
 
Production costs (1)
 
$
3,675

 
$
4,973

 
$
3,315

Midstream natural gas gathering, processing, and marketing (1)
 
$
—

 
$
652

 
$
—

Oilfield services (1)
 
$
298

 
$
—

 
$
—

General and administrative (1)
 
$
23

 
$
44

 
$
13

Interest income (2)
 
$
113

 
$
154

 
$
205

Miscellaneous income (expense) (2)
 
$
(620
)
 
$
220

 
$
220

Loss from equity method investment (2)
 
$
464

 
$
590

 
$
730

Capitalized costs incurred (1)
 
$
508

 
$
3,149

 
$
—

Pilatus Hunter, LLC (4)
 
 
 
 
 
 
General and administrative
 
$
143

 
$
281

 
$
166

Eureka Midstream Holdings (3)
 
 
 
 
 
 
Oil and natural gas sales
 
$
347

 
$
—

 
$
—

Production costs
 
$
1,181

 
$
—

 
$
—

Transportation, processing, and other related costs
 
$
24,865

 
$
353

 
$
—

Oilfield services
 
$
34

 
$
—

 
$
—

General and administrative
 
$
8

 
$
32,569

 
$
—

Gain on deconsolidation of Eureka Midstream Holdings, LLC
 
$
—

 
$
509,563

 
$
—

Gain on dilution of interest in Eureka Midstream Holdings, LLC
 
$
4,601

 
$
—

 
$
—

Loss from equity method investment
 
$
185,693

 
$
448

 
$
—

Loss on extinguishment of Eureka Midstream Holdings Series A Preferred Units
 
$
—

 
$
51,692

 
$
—

Capitalized costs incurred
 
$
121

 
$
—

 
$
—

Classic Petroleum (5)
 
 
 
 
 
 
Capitalized costs incurred
 
$
206

 
$
1,495

 
$
—

Kirk Trosclair Enterprises, LLC (6)
 
 
 
 
 
 
General and administrative
 
$
169

 
$
—

 
$
—

_________________________________
(1)  
GreenHunter is an entity of which Gary C. Evans, the Company’s Chairman and CEO, is the Chairman and a major shareholder. Triad Hunter and VIRCO, wholly owned subsidiaries of the Company, receive services related to brine water and rental equipment from GreenHunter and certain affiliated companies. The Company had approximately $66,000 of accounts receivable from GreenHunter which was fully reserved as of December 31, 2015.

(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 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 investment in affiliates - equity method and an available for sale investment in GreenHunter included in investments.  Miscellaneous income (expense) includes other than temporary impairment loss on the GreenHunter available for sale security of $0.8 million for the year ended December 31, 2015. See “Note 10 - Investments and Derivatives” for additional information.

(3) 
Following a sequence of transactions up to and including, December 18, 2014, the Company no longer held a controlling financial interest in Eureka Midstream Holdings. The Company deconsolidated Eureka Midstream Holdings and accounts for its retained interest as of December 31, 2015 and 2014 under the equity method of accounting. See “Note 4 - Eureka Midstream 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) 
Classic Petroleum, Inc. is an entity owned by the brother of James W. Denny, III, the Company’s former Executive Vice President and President of the Company’s Appalachian Division. Triad Hunter received land brokerage services from Classic Petroleum, Inc., including courthouse abstracting, contract negotiations, GIS mapping and leasing services.

F-64




(6) 
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, 2015, the Company paid Mr. Trosclair $169,000, which includes reimbursement of expenses incurred on behalf of the Company, and recognized $163,423 in stock compensation expense.

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.  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 provided a 50% credit for all services performed under the agreement until the prepayment amount was utilized in full, which occurred during the first half of 2015.

As of December 31, 2015, the Company had a note receivable from GreenHunter with an outstanding principal balance of approximately $680,300 which was fully reserved as of December 31, 2015.  Under the terms of the promissory note, GreenHunter is required to make quarterly payments to the Company comprised of principal of $137,500 and accrued interest through the maturity of the note in February 2017. Under the terms of the note, failure to pay timely is considered an event of default. As of March 31, 2015, GreenHunter was past due on principal and interest payments in aggregate of $168,437, which were due on February 17, 2015. On May 4, 2015, GreenHunter made this past due principal and interest payment of $168,437. As of December 31, 2015, GreenHunter was current with its principal and interest payments on the promissory note; however, GreenHunter did not make the principal and interest payment due on February 17, 2016, and on March 1, 2016, GreenHunter and certain of its subsidiaries filed voluntary petitions for reorganization under the Bankruptcy Code. Amounts receivable under the promissory note have the status of a general unsecured claim in GreenHunter’s bankruptcy proceeding.

As of December 31, 2013, Mr. Evans, the Company’s Chairman and Chief Executive Officer, held 27,641 Class A Common Units of Eureka Midstream Holdings. On October 3, 2014, in connection with the New LLC Agreement, these Class A Common Units were converted into Series A-1 Units. As of December 31, 2014 and 2015, Mr. Evans also held 250,049 Class B Common Units of Eureka Midstream Holdings pursuant to the Eureka Midstream Holdings Plan, of which none were vested at December 31, 2014 and 50,009 of which were vested at December 31, 2015.

Triad Hunter and Eureka Midstream 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 Midstream Holdings for which Triad Hunter has committed to minimum reservation fees of approximately $1.05 per MMBtu. As of October 31, 2015, Triad Hunter owed Eureka Midstream approximately $10.7 million in past due gathering fees under the Gas Gathering Services Agreement. On November 5, 2015, the Company received a demand notice from MSI, on behalf of Eureka Midstream, demanding adequate assurance of performance of security in the amount of approximately $20.8 million in connection with past due gathering fees. In accordance with the demand notice, Eureka Midstream suspended gas gathering services on November 10, 2015, requiring the Company to temporarily shut-in approximately 40 wells located in West Virginia. On November 19, 2015, the Company agreed to, among other things, pay $5.0 million to Eureka Midstream. Eureka Midstream lifted the suspension of gas gathering services and the Company began the process of returning all of the shut-in wells to production. In connection with the Chapter 11 Cases, the Company agreed to assume the gathering agreement with Eureka Midstream, subject to certain agreed upon amendments. These amendments will, among other things, modify certain of the reservation fees and commodity fees that Triad Hunter pays to Eureka Midstream and provide certain volume credits to Triad Hunter. See “Note 18 - Commitments and Contingencies” for further discussion of the gas gathering and processing agreements with Eureka Midstream.

In addition, the Company and Eureka Midstream 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 Midstream 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 that perform service for Eureka Midstream Holdings and its subsidiaries and for whom the Company bills a personnel services fee, are expected to become employees of Eureka Midstream Holdings or a subsidiary of Eureka Midstream Holdings. Upon the deconsolidation of Eureka Midstream Holdings on December 18, 2014, Eureka Midstream Holdings and its subsidiaries became related parties of the Company.


F-65



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 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 subsequently appealed the decision dismissing the Securities Cases to the U.S. Court of Appeals for the Second Circuit. On June 23, 2015, the U.S. Court of Appeals for the Second Circuit entered a Summary Order unanimously affirming the Southern District of New York’s dismissal of the Securities Cases in favor of the Company and the individual defendants. 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. On July 22, 2014, the 125th District Court of Harris County, Texas issued an Order and Final Judgment granting the Company’s and the individual defendants’ motion for summary judgment in its entirety and entering a final judgment dismissing the suit filed by Richard Harveth. The plaintiffs may file an appeal. All of the Derivative Cases have now been dismissed. It is possible that additional stockholder derivative suits could be filed over these events.

In addition, the Company 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 General Corporation Law of the State of Delaware. On September 17, 2013, Anthony Scavo, who is one of the stockholders that made a demand, filed a books and records action in the

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Delaware Court of Chancery pursuant to Section 220 of the Delaware General Corporation Law (“Scavo Action”). The Scavo Action sought 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 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.

SEC Wells Notice

In April 2013, the Company received a letter from the staff of the SEC’s Division of Enforcement (the “Staff”) stating that the Staff 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. In connection with the Staff’s inquiry, on March 24, 2015, the Company received a “Wells Notice” from the Staff, stating that the Staff had made a preliminary determination to recommend that the SEC file an enforcement action against the Company. On that date, the Staff issued similar Wells Notices to (i) Gary C. Evans, the Company’s current Chairman and Chief Executive Officer, (ii) J. Raleigh Bailes, Sr., a former director of the Company and former Chairman of the Company’s Audit Committee, (iii) the former chief financial officer of the Company who was in office at the time of the Company’s decision to dismiss its prior independent registered public accounting firm and (iv) the former chief accounting officer of the Company who had resigned from that position with the Company in October 2012.

The Wells Notice issued to the Company stated that the proposed action against the Company would allege violations of Sections 17(a)(2) and 17(a)(3) of the Securities Act of 1933 and Sections 13(a), 13(b)(2)(A), and 13(b)(2)(B) of the Securities Exchange Act of 1934 and Rules 13a-l, 13a-13, and 13a-15(a) thereunder. The proposed actions against the individuals would allege violations of those same provisions, as well as violations of Section 13(b)(5) of the Securities Exchange Act of 1934 and Rules 13a-14 and 13a-15(c) thereunder. The proposed actions described in the Wells Notices did not include any claims for securities fraud under Section 10(b) of the Securities Exchange Act of 1934 or Rule 10b-5 thereunder or under Section 17(a)(1) of the Securities Act of 1933.

The Company and certain of the individual respondents (other than Mr. Evans and Mr. Bailes) thereafter negotiated a settlement with the SEC, which the SEC Commissioners approved on March 10, 2016. Pursuant to the settlement, without admitting or denying the SEC’s findings, the Company agreed to pay a civil penalty of $250,000 to the SEC (the “Civil Penalty”), subject to Bankruptcy Court approval, and was ordered to cease and desist from violating Sections 13(a), 13(b)(2)(A) and 13(b)(2)(B) of the Securities Exchange Act and Rules 13a-1, 13a-13 and 13-15(a) thereunder. The two former officers referred to above, who oversaw the Company’s accounting department at the relevant times, as well as two former outside accounting professionals, were ordered to cease and desist from violating these provisions and were subjected to additional financial penalties or administrative suspensions in their individual capacities.

On March 23, 2016, Mr. Evans, the Company’s current Chairman and Chief Executive Officer, and Mr. Bailes, a former director of the Company and former Chairman of the Company’s Audit Committee, received letters from the Staff stating that the Staff had concluded its investigations of Mr. Evans and Mr. Bailes and that, based on the information the Staff possessed as of that date, the Staff did not intend to recommend an enforcement action by the SEC against either of them. Furthermore, no other current officers or directors of the Company were required to pay any penalties or were subjected to any sanctions in their individual capacity pursuant to the settlement.

On March 11, 2016, the Company filed a motion with the Bankruptcy Court seeking approval of the Company’s settlement with the SEC and authority to pay the Civil Penalty to the SEC. On March 29, 2016, the Bankruptcy Court entered an order approving the Company’s motion.

Twin Hickory Matter

On April 11, 2013, a flash fire occurred at Eureka Midstream’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 Midstream 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 Midstream seeking a declaratory judgment that Eureka Midstream 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 Midstream 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 alleged that Eureka Midstream 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 demanded judgments for an

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unspecified amount of compensatory, general and punitive damages. Various cross-claims were asserted. In May 2014, the injured third-party contractor employee sued Magnum Hunter 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 dismissed. A portion of the settlement was paid by an insurer of Eureka Midstream, and the remainder paid by unrelated third party co-defendants or their insurers. The cross-claims among the defendants in the Whisenhunt litigation have been resolved. In addition, the claims filed by Antoinette M. Miller and Karen S. Phipps have been successfully mediated and have been resolved and dismissed. Insurers providing coverage to Eureka Midstream, Magnum Hunter and other affiliated or related entities paid a portion of the settlements, with the remainder being paid by unrelated third party co-defendants or their insurers. Accordingly, all lawsuits relating to this matter have been resolved.

Samson Matter

In June 2015, Samson Resources Company (“Samson”) executed and filed ten oil and gas well liens in Divide County, North Dakota (the “Samson Liens”) to secure payments it contends were owed by Bakken Hunter. In July 2015, Bakken Hunter filed a complaint against Samson in a case styled Bakken Hunter, LLC v. Samson Resources Company, Case No. 4:15-cv-0008, in the United States District Court for the District of North Dakota, Northwestern Division. In its complaint, Bakken Hunter alleges that Samson breached certain agreements by, among other things, failing to promptly pay and discharge certain expenses resulting in third party liens, failing to keep accurate records, failing to make its accounts available to Bakken Hunter for audit and failing to respond to Bakken Hunter’s concerns about Samson’s billing and accounting practices. Bakken Hunter is seeking equitable relief and damages in an unliquidated amount and seeking a declaration that the Samson Liens are void. In August 2015, Samson filed and served its answer and counterclaims against Bakken Hunter, generally denying Bakken Hunter’s allegations and asserting its own claims for breach of contract, contending that Bakken Hunter failed to pay its proportionate share of certain expenses as a non-operator of certain oil and gas properties. In its counterclaims, among other relief, Samson sought a declaration that the Samson Liens were valid and sought in its counterclaims to foreclose on the Samson Liens. This matter has been stayed as a result of Samson’s bankruptcy filing in the United States Bankruptcy Court for the District of Delaware, Case No. 15-11942 (CSS). In November 2015, Bakken Hunter filed a Proof of Claim against Samson in the Samson bankruptcy; the Proof of Claim is based on the same facts alleged in Bakken Hunter’s complaint against Samson. During the pendency of these matters, Samson has continued to withhold all revenues owed to Bakken Hunter with respect to Bakken Hunter’s non-operated working interests in the oil and gas properties in Divide County, North Dakota as to which Samson is an operator under a theory of recoupment applicable to the expenses Samson claims Bakken Hunter, as a non-operated working interest owner, has failed to pay. Our Plan includes an agreed stipulation (the “Samson Stipulation”) between Bakken Hunter and Samson. Pursuant to the Samson Stipulation, among other things, (i) the joint operating agreement (the “Samson JOA”) between the parties will be assumed by Bakken Hunter in its bankruptcy proceeding, consistent with the terms of the Samson Stipulation; (ii) both parties reserved all rights of their respective claims against each other; (iii) the parties agreed to cooperate to complete Bakken Hunter’s ongoing audits under the Samson JOA for years 2013, 2014 and 2015; and (iv) so long as Bakken Hunter is not in default under the Samson JOA (including the current payment of joint interest billings), Samson shall cease offsetting Bakken Hunter’s revenue and timely remit such revenue to Bakken Hunter in the following manner: (a) each month, Samson shall remit all revenue due to Bakken under the Samson JOA up to the amount paid by Bakken Hunter to Samson in respect of the prior month’s joint interest billings plus any amounts for which Bakken Hunter properly reduced payment in accordance with the Samson JOA (such total, the “Prior Month’s Reimbursement”) and (b) any revenue in excess of the Prior Month’s Reimbursement will be placed into an escrow account pending resolution of the parties’ various claims. The Bankruptcy Court has not yet adjudicated the various claims asserted by Samson and Bakken Hunter against one another. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these lawsuits to have a material adverse effect on the Company’s consolidated financial condition or results of operations.

Eclipse Matter

In November 2015, Eclipse Resources I, LP (“Eclipse”) filed a complaint against Triad Hunter in a case styled Eclipse Resources I, LP v. Triad Hunter, LLC, Civil Action G.D. No. 2015-4589, in the Court of Common Pleas of Centre County, Pennsylvania. In its complaint, Eclipse alleged that Triad Hunter failed to honor its obligations under an Operating Agreement in constructing and operating a well located in Monroe County, Ohio, which experienced a blowout event in December 2014. Asserting purported claims for declaratory, common law and equitable relief, Eclipse is seeking recovery of its proportionate share of costs to remediate the well blowout event, legal fees in the action, removal of Triad Hunter as operator, and appointment of a receiver over the business and assets of Triad Hunter. Although the matter was initially stayed upon the filing of the Chapter 11 Cases, on January 21, 2016 the Bankruptcy Court approved a stipulation agreed to by the parties pursuant to which, among other things, the automatic stay was modified to allow the parties to proceed with the state court litigation. Pursuant to the stipulation, (i) Eclipse agreed to dismiss the pending action in the Court of Common Pleas of Centre County, Pennsylvania and refile the action in state court in Ohio; (ii) Eclipse is permitted to take or receive hydrocarbons from the affected wells in kind; (iii) Eclipse is required to fund up to $2.2 million in an escrow account pending the final and non-appealable resolution of the state court litigation; and (iv) Triad Hunter agreed to discontinue

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netting revenue otherwise owed to Eclipse from the sale of Eclipse hydrocarbons marketed by Triad Hunter. The prevailing party in the state court litigation will be entitled to recovery of the escrowed funds. The Company intends to mount a vigorous defense in the state court litigation. While the outcome of this matter cannot be predicted with certainty, management does not expect this matter to have a material adverse effect on the Company’s consolidated financial condition or results of operations.

General

The Company is 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 the Company’s consolidated financial condition or results of operations.

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, 2015 and 2014 was $640,695 and is included in “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2015.

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 $16.8 million as of December 31, 2015. 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 $2.7 million as of December 31, 2015. Effective October 3, 2014, the Company entered into a 15-year gas transportation contract with Equitrans, L.P. which expires on October 31, 2029. The Company’s remaining obligation under the contract was $44.2 million as of December 31, 2015.

Eureka Midstream Gas Gathering Agreement

On March 21, 2012, Triad Hunter entered into the Amended and Restated Gas Gathering Services Agreement (as amended, the “Gathering Agreement”) with Eureka Midstream. 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 Midstream and Triad Hunter were both wholly owned subsidiaries of the Company. Upon the deconsolidation of Eureka Midstream Holdings on December 18, 2014, Eureka Midstream became a related party (see “Note 4 - Eureka Midstream Holdings” and “Note 17 - Related Party Transactions”). As of December 31, 2015, Triad Hunter and Eureka Midstream were parties to seven individual transaction confirmations with terms ranging from eight to fourteen years. Triad Hunter’s maximum daily quantity committed was 260,000 MMBtu per day at an aggregate reservation fee of $1.05 per MMBtu. Triad Hunter’s remaining obligation under the individual transaction confirmations was $172.8 million as of December 31, 2015.

As of October 31, 2015, Triad Hunter owed Eureka Midstream approximately $10.7 million in past due gathering fees under the Gathering Agreement. On November 5, 2015, the Company received a demand notice (the “Demand Notice”) from MSI on behalf of Eureka Midstream, demanding, in connection with past due amounts, adequate assurance of performance of security in the amount of approximately $20.8 million on or before November 10, 2015. MSI further advised in the Demand Notice that it would suspend services under and terminate the Gathering Agreement if the Company had not provided the adequate assurance of performance and/or paid in full all amounts past due by November 20, 2015 (the “Deadline”).

In accordance with the Demand Notice, on November 10, 2015, Eureka Midstream suspended gas gathering services under the Gathering Agreement requiring Triad Hunter to temporarily shut-in approximately 40 of Triad Hunter’s operated wells located in West Virginia.  The shut-in wells were producing approximately 66,000 Mcfe/d of natural gas production (approximately 55,000 Mcfe/d net to Triad Hunter).  Upon execution and delivery of the November 2015 Letter Agreement (as defined and described below), on November 19, 2015, Eureka Midstream lifted the suspension of gas gathering services under the Gathering Agreement, and Eureka Midstream and Triad Hunter collectively began the process of returning all of the shut-in back to production.  All of the shut-in wells were returned to production and flowing to sales on or before November 21, 2015.
 

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In response to the Demand Notice, North Haven Infrastructure Partners II Buffalo Holdings LLC (formerly, MSIP II Buffalo Holdings LLC) (“NHIP II”) (on its behalf and on behalf of Eureka Midstream Holdings and its subsidiaries, including Eureka Midstream (collectively the “EHH Group”)), Triad Hunter and the Company (collectively, the “Parties”) entered into a new letter agreement, dated November 19, 2015 (the “November 2015 Letter Agreement”), in connection with the Demand Notice, pursuant to which the Parties agreed, among other things, to the following:
 
i.
Triad Hunter agreed to, and the Company agreed to cause Triad Hunter to, pay Eureka Midstream an aggregate amount of $5,000,000 in immediately available funds, on the following schedule: (i) $3,000,000 (the “First Payment”) promptly upon execution of the November 2015 Letter Agreement by NHIP II (which payment was made on November 19, 2015), and (ii) $2,000,000 on or before December 4, 2015 (the “Second Payment” and, collectively with the First Payment, the “Payments”);

ii.
Triad Hunter agreed to pay all amounts then currently owed by Triad Hunter to or billed to Triad Hunter by Eureka Midstream (after giving effect to the application of the Payments) under and in accordance with the Gathering Agreement upon the occurrence of (a) any comprehensive recapitalization or restructuring of the Company’s secured and unsecured indebtedness and/or any transaction or series of related transactions involving any business combination pursuant to which a majority of the Company’s equity or core assets are sold, other than under the circumstances described in clause (b) below; or (b) in the event of the commencement of a case under Chapter 11 of the Bankruptcy Code, the date that is no later than 30 days after the Petition Date, to the extent approved by the bankruptcy court (each, a “Liquidity Event”);

iii.
The Company and Triad Hunter agreed that in the event either entity commences a voluntary case under Chapter 11 of the Bankruptcy Code, the Company and Triad Hunter would file a motion seeking, and use commercially reasonable efforts to obtain, on an interim basis as part of the “first day orders” and on a final basis to be entered no later than 30 days following the Petition Date, entry of an order(s) in form and substance reasonably acceptable to NHIP II authorizing the Company and Triad Hunter to timely honor as allowed administrative expenses and otherwise perform all their respective obligations arising under the Gathering Agreement in accordance with the Gathering Agreement during the period beginning on the Petition Date and ending on the earlier of (a) the end of the Chapter 11 case, (b) rejection of the Gathering Agreement, and (c) as otherwise agreed to in writing among the Company, Triad Hunter, and NHIP II;

iv.
Eureka Midstream agreed to, and NHIP II agreed to instruct the EHH Group to, prior to the Forbearance End Date (as defined below), (a) commencing upon the receipt of the First Payment, forbear (and as immediately as practicable restore service in connection with any prior exercise) from the exercise and/or enforcement of any rights and/or remedies with respect to Triad Hunter and the Company under the Gathering Agreement in relation to the payment of any arrearages under the Gathering Agreement including, without limitation, termination, suspense of service and demands for adequate assurance of future performance and pursuing any remedies related thereto under Section 8.4(d)(ii) of the New LLC Agreement; (b) not commence any action at law or in equity or otherwise against Triad Hunter or the Company in relation to the payment of any arrearages under the Gathering Agreement; and (c) not commence an involuntary bankruptcy proceeding against Triad Hunter or the Company. Section 8.4(d)(ii) of the New LLC Agreement permits NHIP II, on behalf of Eureka Midstream Holdings and the other members of the EHH Group, to take any and all actions relating to the exercise and/or enforcement of any rights and/or remedies under any agreement between any member of the EHH Group, on the one hand, and the Company or any of its subsidiaries, including Triad Hunter, on the other hand, including the Gathering Agreement;

v.
NHIP II agreed to, prior to the Forbearance End Date, (i) commencing upon the receipt of the First Payment, forbear from the exercise and/or enforcement of any rights and/or remedies with respect to the Company under the New LLC Agreement or otherwise, including, without limitation, under Section 8.4(d)(ii) of the New LLC Agreement, in respect of any arrearages under the Gathering Agreement, and (ii) not commence any action at law or in equity or otherwise against the Company or Triad Hunter in respect of such arrearages, including an involuntary bankruptcy proceeding; and

vi.
Eureka Midstream agreed to, and NHIP II agreed to instruct the EHH Group to, amend the Demand Notice to extend the Deadline until the earlier to occur of (a) December 31, 2015; (b) the date on which the Company and Triad Hunter breaches any of its obligations under the November 2015 Letter Agreement; (c) the taking of any action by the Company or Triad Hunter that is materially inconsistent with the November 2015 Letter Agreement; (d) upon the filing of a voluntary petition for relief under the Bankruptcy Code by the Company or Triad Hunter; (e) upon the latter of an entry of an order for relief entered or 45 days after the filing of an involuntary case under the Bankruptcy Code against the Company or Triad Hunter; (f) after the effective date of the November 2015 Letter Agreement, any Default or Event of Default (as defined in the Gathering Agreement) of the Gathering Agreement by the Company or Triad Hunter, other than a Default or Event of Default arising from the Company’s or Triad Hunter’s failure to pay amounts due under the Gathering Agreement or a Default or Event of Default arising from an involuntary or voluntary bankruptcy filing; and (g) the occurrence of a Liquidity Event (the “Forbearance End Date”).


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In connection with the Company’s bankruptcy proceeding, the Company agreed to assume the gathering agreement with Eureka Midstream subject to certain agreed upon amendments. These amendments will, among other things, modify certain of the reservation fees and commodity fees that Triad Hunter pays to Eureka Midstream and provide certain volume credits to Triad Hunter.

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.

On February 19, 2016, the Company filed a motion with the Bankruptcy Court seeking to reject the TGT Transportation Services Agreement, the Credit Support Agreement, and certain ancillary contracts. On March 10, 2016, the Bankruptcy Court held a hearing on the motion. At the March 10, 2016 hearing, the Debtors and TGT announced a settlement agreement under which all executory contracts related to the TGT Transportation Services Agreement will be rejected and all other related contracts will be terminated, and TGT will be entitled to an Allowed General Unsecured Claim (as defined in the Plan) in an amount of $15 million. The Bankruptcy Court approved the related settlement motion on March 30, 2016.

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. In connection with the Chapter 11 Cases, the Company agreed to assume the REX Transportation Services Agreement, subject to certain agreed upon amendments. Among other things, these amendments reduced Triad Hunter’s firm transportation volume commitment from 100,000 MMBtu per day to 50,000 MMBtu per day. 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 $8.7 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 MHR Senior Revolving Credit Facility. On and effective as of November 3, 2015, the letter of credit was cash collateralized in connection with the Senior Secured Bridge Financing Facility. See “Note 11 - Long-Term Debt”. No amounts have been drawn against the letter of credit as of December 31, 2015. As a result of the amendments to the REX Transportation Services Agreement

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entered into in connection with the Chapter 11 Cases, the amount of Triad Hunter’s posted letter of credit will be reduced by approximately $2.8 million every three months until the posted letter of credit amount is reduced to $20.0 million, subject to further reduction five years following the effective date of the FTA.

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. Furthermore, the Company is seeking Bankruptcy Court approval of a settlement agreement related to the TGT Transportation Services Agreement as discussed above. Future minimum gathering, processing, and transportation commitments at December 31, 2015, are as follows (in thousands):

2016
$
22,562

2017
$
22,517

2018
$
22,517

2019
$
22,517

2020
$
22,517

Thereafter
$
123,943


Agreement to Purchase Utica Shale Acreage

On August 12, 2013, Triad Hunter entered into an asset purchase agreement with MNW, referred to herein as the “MNW Purchase Agreement”. Pursuant to the MNW 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.

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 MNW Purchase Agreement. 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 MNW Purchase Agreement 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 MNW 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 MNW Purchase Agreement to end further withholdings of escrow funds from the purchase price at future closings.

During the years ended December 31, 2015, 2014, and 2013, Triad Hunter purchased a total of 2,665, 16,456, and 5,922 net leasehold acres, respectively, from MNW for $12.0 million, $67.3 million and $24.6 million, respectively, in multiple closings, and also released $0.4 million in escrowed funds, for a total disbursement to MNW of approximately $104.3 million. As of December 31, 2015, under the asset purchase agreement, Triad Hunter has now acquired a total of approximately 25,044 net leasehold acres from MNW, or approximately 78.3% of the approximately 32,000 total net leasehold acres originally anticipated under the asset purchase agreement.

The Company listed the MNW Purchase Agreement on its Schedule of Rejected Executory Contracts that it filed with the Bankruptcy Court, as an exhibit to a supplement to the Plan, on March 14, 2016. Accordingly, on the Effective Date the MNW Purchase Agreement is expected to be terminated, and the Company does not expect that any of the remaining net leasehold acres will be acquired by Triad Hunter.

Drilling Rig Purchase

During June 2014, the Company, through its wholly owned subsidiary, Alpha Hunter Drilling, entered into an agreement to purchase a new drilling rig. The purchase price for the rig was approximately $6.5 million, including a $1.3 million deposit that was paid in July 2014 with the remainder due upon delivery. In February 2015, the Company was notified that the rig was complete and available for delivery. However, the Company refused to take delivery of the rig primarily because of quality concerns that were based on mechanical issues experienced with a different rig acquired by the Company from the same supplier. During the fourth quarter of

F-72



2015, the Company wrote off the deposit, along with approximately $2.7 million of other deposits and equipment related to the new drilling rig, which is included in “Loss on abandonment of drilling rig in progress” in the consolidated statement of operations.

The Company listed the agreement to purchase the drilling rig on its Schedule of Rejected Executory Contracts that it filed with the Bankruptcy Court, as an exhibit to a supplement to the Plan, on March 14, 2016. Accordingly, on the Effective Date the agreement to purchase the drilling rig is expected to be terminated.

Operating Leases

As of December 31, 2015, office space rentals with terms of 12 months or greater include office spaces in Houston, Texas, at a monthly cost of $34,000, and office spaces in Irving, Texas, with monthly payments of approximately $30,500. On December 31, 2015, the Company vacated its office space in Houston, Texas and on January 11, 2016 the Bankruptcy Court approved the Company’s motion to reject the Houston, Texas office lease.

Future minimum lease commitments under non-cancelable operating leases at December 31, 2015, are as follows (in thousands):

2016
$
605

2017
$
488

2018
$
154

2019
$
53

2020
$
—

Thereafter
$
—


Services Agreement

On March 21, 2012, Triad Hunter entered into the Amended and Restated Gas Gathering Services Agreement with Eureka Midstream. Further, on March 20, 2012, and amended on March 21, 2012, the Company and Eureka Midstream 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 Midstream Holdings on December 18, 2014, Eureka Midstream 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, 2015, 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’s control of well insurance covered its proportionate share of losses incurred by it in connection with the blowout of the Stalder 3UH well.

During 2015, the Company received notifications from certain non-operators, including Eclipse, under its operating agreement for the Stalder 3UH well indicating that such non-operators believed the Company should be responsible for all costs related to the December 2014 blowout. On November 18, 2015, the Company notified Eclipse that it had breached the operating agreement by failing to remit payment for its proportionate share of the costs of the blowout, and on December 18, 2015, the Company effectively suspended all revenue payments to Eclipse related to the Stalder 3UH well. On December 23, 2015, Eclipse filed an emergency motion with the Bankruptcy Court seeking equitable relief. The Company and Eclipse agreed to a stipulation that was approved by the Bankruptcy Court on January 21, 2016. Among other things, the stipulation requires an escrow account, beyond the control of

F-73



the Company and Eclipse, to be funded by Eclipse up to an amount of $2.2 million, to be released based on court order once the lawsuit is settled. The Company does not believe that a material loss is probable as a result of these proceedings.

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,
 
2015
 
2014
 
2013
 
(in thousands)
Cash paid for interest
$
55,531

 
$
73,192

 
$
67,736

Cash paid for taxes
$
—

 
$
—

 
$
1,200

Non-cash transactions
 

 
 
 
 
Change in accrued capital expenditures - increase (decrease)
$
(100,774
)
 
$
127,068

 
$
(65,634
)
Reclassification of deposit from field equipment to other assets
$
2,125

 
$
—

 
$
—

Eureka Midstream Holdings, LLC Series A convertible preferred unit dividends paid in kind
$
—

 
$
1,950

 
$
8,243

Non-cash additions to asset retirement obligation
$
141

 
$
3,426

 
$
2,132

Common stock issued for 401k matching contributions
$
1,878

 
$
1,593

 
$
1,192

Non-cash consideration received from sale of assets
$
—

 
$
9,447

 
$
42,300

Loss on extinguishment of Eureka Midstream Holdings Series A Preferred Units
$
—

 
$
(51,692
)
 
$
—


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

Upstream, Midstream and Oilfield Services represent the operating segments of the Company. The Upstream segment is organized and operated to explore for and produce crude oil and natural gas within the geographic boundaries of the U.S. and Canada. All Canadian operations were divested during the year ended December 31, 2014 as discussed in “Note 5 - Acquisitions, Divestitures, and Discontinued Operations”, and are classified as discontinued operations. The Midstream segment consists primarily of Eureka Midstream Holdings, which 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. During the year ended December 31, 2013 and through December 18, 2014, Eureka Midstream Holdings was a consolidated subsidiary of the Company. Subsequent to December 18, 2014, the Company accounts for its interest in Eureka Midstream Holdings using the equity method of accounting. See “Note 4 - Eureka Midstream Holdings”. 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, 2015, 2014, and 2013.
 
For the Year Ended December 31, 2015
 
Upstream
 
Midstream (1)
 
Oilfield Services
 
Corporate Unallocated
 
Intersegment Eliminations
 
Total
 
(in thousands)
Total revenue
$
134,812

 
$
867

 
$
18,973

 
$
—

 
$
(528
)
 
$
154,124

Depreciation, depletion, and amortization
128,973

 
—

 
3,926

 
—

 
(95
)
 
132,804

(Gain) loss on sale of assets
(31,409
)
 
—

 
51

 
—

 
—

 
(31,358
)
Other operating expenses
454,984

 
736

 
19,637

 
38,794

 
(387
)
 
513,764

Other income (expense)
(10,091
)
 
(181,092
)
 
(577
)
 
(89,887
)
 
—

 
(281,647
)
Reorganization items, net
—

 
—

 
—

 
(41,139
)
 
—

 
(41,139
)
Net income (loss)
$
(427,827
)
 
$
(180,961
)
 
$
(5,218
)
 
$
(169,820
)
 
$
(46
)
 
$
(783,872
)
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$
756,265

 
$
166,107

 
$
37,787

 
$
100,040

 
$
(41
)
 
$
1,060,158

 
 
 
 
 
 
 
 
 
 
 
 
Total capital expenditures
$
63,981

 
$
—

 
$
650

 
$
2,247

 
$
—

 
$
66,878



F-74



 
For the Year Ended December 31, 2014
 
Upstream
 
Midstream (1)
 
Oilfield Services
 
Corporate Unallocated (1)
 
Intersegment Eliminations
 
Total
 
(in thousands)
Total revenue
$
270,615

 
$
109,658

 
$
31,392

 
$
—

 
$
(20,196
)
 
$
391,469

Depreciation, depletion, and amortization
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
3,481

 
—

 
—

 
(12,775
)
 
—

 
(9,294
)
Net income (loss)
$
(406,181
)
 
$
(98,426
)
 
$
782

 
$
360,400

 
$
(3,702
)
 
$
(147,127
)
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$
1,168,829

 
$
347,645

 
$
47,009

 
$
116,849

 
$
(2,377
)
 
$
1,677,955

 
 
 
 
 
 
 
 
 
 
 
 
Total capital expenditures
$
470,843

 
$
221,455

 
$
8,079

 
$
231

 
$
—

 
$
700,608


 
For the Year Ended December 31, 2013
 
Upstream
 
Midstream (1)
 
Oilfield Services
 
Corporate Unallocated
 
Intersegment Eliminations
 
Total
 
(in thousands)
Total revenue
$
225,498

 
$
69,306

 
$
21,527

 
$
—

 
$
(11,793
)
 
$
304,538

Depreciation, depletion, and amortization
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
9,018

 
—

 
—

 
—

 
(69
)
 
8,949

Net income (loss)
$
(114,999
)
 
$
(25,875
)
 
$
(590
)
 
$
(81,698
)
 
$
(2
)
 
$
(223,164
)
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$
1,441,408

 
$
296,739

 
$
44,193

 
$
77,684

 
$
(3,373
)
 
$
1,856,651

 
 
 
 
 
 
 
 
 
 
 
 
Total capital expenditures
$
459,737

 
$
87,498

 
$
22,440

 
$
1,037

 
$
—

 
$
570,712

______________
(1) 
For the years ended December 31, 2014 and 2013, the Midstream segment includes operations of Eureka Midstream Holdings, which represents approximately 38.6% and 40.7% of Midstream revenues for the years ended December 31, 2014 and 2013, respectively, and which was deconsolidated as of December 18, 2014. See “Note 4 - Eureka Midstream Holdings”. For the year ended December 31, 2015, other expense of the Midstream segment represents loss from the Company’s equity method investment in Eureka Midstream Holdings.


F-75



NOTE 21 - CONDENSED COMBINED GUARANTOR FINANCIAL STATEMENTS

Guarantor Subsidiaries

Certain of the Company’s wholly owned subsidiaries, including Alpha Hunter Drilling, Bakken Hunter, Shale Hunter, Magnum Hunter Marketing, MHP, NGAS Hunter, Triad Hunter, VIRCO, and Bakken Hunter Canada, (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.

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, 2015 and 2014 and for the years ended December 31, 2015, 2014, and 2013 is as follows:

Magnum Hunter Resources Corporation and Subsidiaries
(Debtor-in-Possession)
Condensed Consolidating Balance Sheets
(in thousands)
 
 
As of December 31, 2015
 
 
Magnum Hunter
Resources
Corporation
 
100% Owned Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating / Eliminating Adjustments
 
Magnum Hunter
Resources
Corporation
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
 
Current assets
 
$
52,010

 
$
31,359

 
$
177

 
$
2

 
$
83,548

Intercompany accounts receivable
 
1,159,346

 
—

 
—

 
(1,159,346
)
 
—

Property and equipment (using successful efforts accounting)
 
6,221

 
762,361

 
—

 
(44
)
 
768,538

Investment in subsidiaries
 
(516,241
)
 
91,759

 
—

 
424,482

 
—

Investment in affiliate, equity-method
 
166,099

 
—

 
—

 
—

 
166,099

Other assets
 
41,809

 
164

 
—

 
—

 
41,973

Total Assets
 
$
909,244

 
$
885,643

 
$
177

 
$
(734,906
)
 
$
1,060,158

 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
$
127,469

 
$
18,390

 
$
39

 
$
2

 
$
145,900

Intercompany accounts payable
 
—

 
1,120,148

 
41,434

 
(1,161,582
)
 
—

Liabilities subject to compromise
 
994,120

 
101,951

 
—

 
—

 
1,096,071

Long-term liabilities
 
139

 
30,532

 
—

 
—

 
30,671

Redeemable preferred stock
 
100,000

 
—

 
—

 
—

 
100,000

Shareholders' equity (deficit)
 
(312,484
)
 
(385,378
)
 
(41,296
)
 
426,674

 
(312,484
)
Total Liabilities and Shareholders' Equity
 
$
909,244

 
$
885,643

 
$
177

 
$
(734,906
)
 
$
1,060,158







F-76



Magnum Hunter Resources Corporation and Subsidiaries
(Debtor-in-Possession)
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
 
$
88,542

 
$
41,569

 
$
589

 
$
(2,378
)
 
$
128,322

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
 
$
1,485,865

 
$
1,309,805

 
$
619

 
$
(1,118,334
)
 
$
1,677,955

 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
$
28,242

 
$
148,145

 
$
2,567

 
$
(2,383
)
 
$
176,571

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
 
$
1,485,865

 
$
1,309,805

 
$
619

 
$
(1,118,334
)
 
$
1,677,955


F-77



Magnum Hunter Resources Corporation and Subsidiaries
(Debtor-in-Possession)
Condensed Consolidating Statements of Operations
(in thousands)
 
 
For the Year Ended December 31, 2015
 
 
Magnum Hunter
Resources
Corporation
 
100% Owned Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating / Eliminating Adjustments
 
Magnum Hunter
Resources
Corporation
Consolidated
Revenues
 
$
16

 
$
155,270

 
$
1,036

 
$
(2,198
)
 
$
154,124

Expenses
 
351,749

 
587,612

 
789

 
(2,154
)
 
937,996

Income (loss) from continuing operations before equity in net income of subsidiaries
 
(351,733
)
 
(432,342
)
 
247

 
(44
)
 
(783,872
)
Equity in net income of subsidiaries
 
(432,139
)
 
(2,374
)
 
—

 
434,513

 
—

Income (loss) from continuing operations before income tax
 
(783,872
)
 
(434,716
)
 
247

 
434,469

 
(783,872
)
Income tax benefit
 
—

 
—

 
—

 
—

 
—

Net income (loss)
 
(783,872
)
 
(434,716
)
 
247

 
434,469

 
(783,872
)
Dividends on preferred stock
 
(33,817
)
 
—

 
—

 
—

 
(33,817
)
Net income (loss) attributable to common shareholders
 
$
(817,689
)
 
$
(434,716
)
 
$
247

 
$
434,469

 
$
(817,689
)

 
 
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 income 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 Midstream Holdings
 
(51,692
)
 
—

 
—

 
—

 
(51,692
)
Net income (loss) attributable to common shareholders
 
$
(249,875
)
 
$
(411,902
)
 
$
(109,810
)
 
$
521,714

 
$
(249,873
)

F-78



Magnum Hunter Resources Corporation and Subsidiaries
(Debtor-in-Possession)
Condensed Consolidating Statements of Operations
(in thousands)

 
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 (expense)
 
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-79




Magnum Hunter Resources Corporation and Subsidiaries
(Debtor-in-Possession)
Condensed Consolidating Statements of Comprehensive Income (Loss)
(in thousands)

 
For the Year Ended December 31, 2015
 
Magnum Hunter
Resources
Corporation
 
100% Owned Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating / Eliminating Adjustments
 
Magnum Hunter
Resources
Corporation
Consolidated
 Net income (loss)
$
(783,872
)
 
$
(434,716
)
 
$
247

 
$
434,469

 
$
(783,872
)
 Foreign currency translation gain
—

 
99

 
—

 
—

 
99

 Unrealized loss on available for sale securities
—

 
(2,771
)
 
—

 
—

 
(2,771
)
Amounts reclassified for other than temporary impairment of available for sale securities
—

 
10,183

 
—

 
—

 
10,183

Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities
—

 
(19
)
 
—

 
—

 
(19
)
 Comprehensive income (loss)
$
(783,872
)
 
$
(427,224
)
 
$
247

 
$
434,469

 
$
(776,380
)

 
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 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
)


F-80



Magnum Hunter Resources Corporation and Subsidiaries
(Debtor-in-Possession)
Condensed Consolidating Statements of Cash Flows
(in thousands)
 
 
For the Year Ended December 31, 2015
 
 
Magnum Hunter
Resources
Corporation
 
100% Owned Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating / Eliminating Adjustments
 
Magnum Hunter
Resources
Corporation
Consolidated
Cash flow from operating activities
 
$
(113,263
)
 
$
138,429

 
$
—

 
$
(140
)
 
$
25,026

Cash flow from investing activities
 
(43,305
)
 
(122,776
)
 
—

 
140

 
(165,941
)
Cash flow from financing activities
 
134,733

 
(6,099
)
 
—

 
—

 
128,634

Effect of exchange rate changes on cash
 
—

 
(28
)
 
—

 
—

 
(28
)
Net increase (decrease) in cash
 
(21,835
)
 
9,526

 
—

 
—

 
(12,309
)
Cash at beginning of period
 
64,165

 
(10,985
)
 
—

 
—

 
53,180

Cash at end of period
 
$
42,330

 
$
(1,459
)
 
$
—

 
$
—

 
$
40,871


 
 
For the Year Ended December 31, 2014
 
 
Magnum Hunter
Resources
Corporation
 
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
 
100% Owned 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


NOTE 22 - SUBSEQUENT EVENTS

Consummation of Second and Third DIP Draws under the DIP Facility

The Second DIP Draw was fully funded on January 14, 2016 following the Bankruptcy Court’s entry of the Final DIP Order on January 11, 2016 approving, on a final basis, the financing provided pursuant to the DIP Credit Agreement. Approximately $70.2 million of the net proceeds from the Second DIP Draw was used to repay in full all loans outstanding under the Company’s Senior Secured Bridge Financing Facility. The Third DIP Draw was fully funded on April 21, 2016, following the satisfaction of certain conditions pursuant to the DIP Credit Agreement. See “Note 3 - Voluntary Reorganization under Chapter 11” and “Note 11 - Long-Term Debt”.

F-81




Rejection or Amendment of Certain Agreements through the Bankruptcy Proceedings

TGT Transportation Agreement and Related Contracts

On February 19, 2016, the Company and the other Debtors filed a motion with the Bankruptcy Court seeking to reject the TGT Transportation Services Agreement, the Credit Support Agreement, and certain ancillary contracts. On March 10, 2016, the Bankruptcy Court held a hearing on the motion. At the March 10, 2016 hearing, the Debtors and TGT announced a settlement agreement under which all executory contracts related to the TGT Transportation Services Agreement will be rejected and all other related contracts will be terminated, and TGT will be entitled to an Allowed General Unsecured Claim (as defined in the Plan) in an amount of $15 million. The Bankruptcy Court approved the related settlement motion on March 30, 2016. See “Note 18 - Commitments and Contingencies”.

Eureka Midstream Amended and Restated Gas Gathering Services Agreement

In connection with the bankruptcy proceedings, Triad Hunter agreed to assume the Amended and Restated Gas Gathering Services Agreement with Eureka Midstream, subject to certain agreed upon amendments. These amendments will, among other things, modify certain of the reservation fees and commodity fees that Triad Hunter pays to Eureka Midstream and provide certain volume credits to Triad Hunter. See “Note 18 - Commitments and Contingencies”.

Continuum Energy

Natural gas production from MHP’s southern Appalachian Basin properties is delivered and sold through gas gathering facilities owned by Continuum Energy Services, L.L.C. and certain of its affiliates (collectively, “Continuum Energy”). MHP operates these gathering facilities, which are located in southeastern Kentucky, northeastern Tennessee and western Virginia. MHP has gas gathering and gas gathering facilities operating agreements with Continuum Energy. In connection with the bankruptcy proceeding, MHP agreed to assume its agreements with Continuum Energy, subject to certain agreed upon amendments. These amendments will, among other things, provide MHP with lower gas gathering rates, gas processing rates and liquids processing rates. In addition, MHP will continue to operate these gathering facilities.

Rockies Express Pipeline LLC (“REX”) Transportation Services Agreement

In connection with the bankruptcy proceeding, Triad Hunter agreed to assume the REX Transportation Services Agreement, subject to certain agreed upon amendments. Among other things, these amendments reduced Triad Hunter’s firm transportation volume commitment from 100,000 MMBtu per day to 50,000 MMBtu per day. In addition, the amount of Triad Hunter’s posted letter of credit will be reduced by approximately $2.8 million every three months until the posted letter of credit amount is reduced to $20.0 million, subject to further reduction five years following the effective date of the FTA. “Note 18 - Commitments and Contingencies”.

Amendments to Restructuring Support Agreement

On February 25, 2016, April 1, 2016, April 13, 2016 and May 5, 2016, the Company and the other Debtors entered into the First Amendment to RSA, the Second Amendment to RSA, the Third Amendment to RSA, and the Fourth Amendment to RSA, respectively, with certain Second Lien Lenders and certain Noteholders as further described in “Note 3 - Voluntary Reorganization under Chapter 11”.

Amendments to the Plan of Reorganization

On January 7, 2016, the Company and the other Debtors filed the Original Plan with the Bankruptcy Court. On February 19, 2016, February 25, 2016, and April 14, 2016, the Company and the other Debtors filed the First Amended Plan, the Second Amended Plan, and the Third Amended Plan, respectively, with the Bankruptcy Court as further described in “Note 3 - Voluntary Reorganization under Chapter 11”.

Settlement of SEC Wells Notice

On March 10, 2016, the SEC Commissioners approved a settlement negotiated with the Company. Without admitting or denying the SEC’s findings, the Company agreed to pay a civil penalty of $250,000 to the SEC, subject to Bankruptcy Court approval. On March 11, 2016, the Company filed a motion with the Bankruptcy Court seeking approval of the Company’s settlement with the SEC and authority to pay the civil penalty. The Bankruptcy Court approved the motion on March 29, 2016. See additional discussion in “Note 18 - Commitments and Contingencies”.


F-82



Confirmation Hearing

On March 27, 2016, the Company and the other Debtors filed a motion with the Bankruptcy Court seeking to adjourn the confirmation hearing that was previously scheduled for March 31, 2016. On March 29, 2016, a Notice of Adjournment was filed with the Bankruptcy Court to adjourn the confirmation hearing until April 8, 2016. On April 4, 2016, a Second Notice of Adjournment was filed with the Bankruptcy Court in order to further adjourn the confirmation hearing until April 18, 2016. The confirmation hearing was held, and the Bankruptcy Court approved the Plan, on April 18, 2016. See “Note 3 - Voluntary Reorganization under Chapter 11”.

NOTE 23 - OTHER INFORMATION

Quarterly Data (Unaudited)

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
 
2015
 
(in thousands)
Total revenue (1)
$
55,396

$
39,526

$
33,664

$
25,538

$
154,124

Operating income (loss) (2)
$
(77,488
)
$
4,529

$
(84,652
)
$
(303,475
)
$
(461,086
)
Net loss attributable to Magnum Hunter Resources Corporation (3)
$
(105,919
)
$
(21,676
)
$
(113,181
)
$
(543,096
)
$
(783,872
)
Net loss attributable to common shareholders
$
(114,767
)
$
(30,523
)
$
(122,029
)
$
(550,370
)
$
(817,689
)
Basic and diluted loss per common share
$
(0.57
)
$
(0.15
)
$
(0.53
)
$
(2.11
)
$
(3.63
)
 
 
 
 
 
 
 
2014
Total revenue (4)
$
113,482

$
138,463

$
79,670

$
59,854

$
391,469

Operating income (loss) (5)
$
(32,762
)
$
1,555

$
(57,576
)
$
(401,575
)
$
(490,358
)
Income (loss) from continuing operations (6)
$
(56,557
)
$
(61,407
)
$
(123,189
)
$
103,320

$
(137,833
)
Income 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
)
______________
(1)  
Total revenues decreased during each consecutive quarter throughout the year ended December 31, 2015 primarily due to decreases in realized prices for oil, gas and NGLs.

(2) 
Fluctuations in operating income (loss) throughout the year ended December 31, 2015 were impacted by decreases in revenues as discussed above, as well as by changes in depreciation, depletion, amortization and accretion expense, impairment of proved oil and gas properties, and exploration expense. During the quarter ended March 31, 2015, depreciation, depletion, amortization and accretion expense was $57.8 million, impairment of proved oil and gas properties was $13.9 million, and exploration expense was $8.5 million. In contrast, depreciation, depletion, amortization and accretion expense was $22.3 million, impairment of proved oil and gas properties was $0.1 million, and exploration expense was $1.5 million during the quarter ended June 30, 2015. During the quarter ended September 30, 2015, the Company recorded exploration expense of $4.4 million and impairment of proved oil and natural gas properties of $49.8 million primarily related to the Williston Basin, and during the quarter ended December 31, 2015, the Company recorded exploration expense of $45.5 million and impairment of proved oil and natural gas properties of $211.6 million related to both the Appalachian and Williston Basins.


F-83



(3) 
Net loss attributable to Magnum Hunter Resources Corporation during the quarter ended December 31, 2015 includes impairment of $180.3 million in order to write down the carrying value of its equity interest in Eureka Midstream Holdings to fair value as a result of the Company’s determination that the investment no longer met the criteria for classification as a discontinued operation as of that date. See “Note 5 - Acquisitions, Divestitures, and Discontinued Operations”.
    
(4) 
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.

(5)  
Income from operations during the quarter-ended June 30, 2014 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 Midstream Holdings was adjusted down in order to take into account certain excess capital expenditures incurred by Eureka Midstream in connection with certain of Eureka Midstream’s fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects.

(6)  
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 Midstream 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 $509.6 million from the deconsolidation of Eureka Midstream Holdings. See “Note 4 - Eureka Midstream Holdings”.


F-84



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,
 
2015
 
2014
 
2013
Purchase of non-producing leases
$
18,906

 
$
124,411

 
$
149,592

Purchase of producing properties
—

 
12,246

 
1,358

Exploration costs
—

 
9,907

 
11,531

Development costs
45,075

 
327,138

 
276,130

 
$
63,981

 
$
473,702

 
$
438,611


Oil and Gas Reserve Information

Proved oil and gas reserve quantities are based on estimates prepared by Magnum Hunter’s third party reservoir engineering firm Cawley, Gillespie, & Associates, Inc. in 2015, 2014, and 2013. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data only represent estimates and should not be construed as being exact.
Total Proved Reserves
 
Crude Oil
 
NGLs
 
Natural Gas
 
 
(MBbl)
 
(MBbl)
 
(MMcf)
Balance December 31, 2012
 
36,827

 
9,125

 
162,620

Revisions of previous estimates (1)
 
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

Revisions of previous estimates (1)
 
(6,540
)
 
2,149

 
(511
)
Extensions, discoveries, and other additions
 
1,705

 
3,226

 
132,345

Sale 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

Revisions of previous estimates (1)
 
(6,075
)
 
(6,959
)
 
(162,147
)
Extensions, discoveries and other additions
 
—

 
—

 
25,309

Production
 
(1,016
)
 
(1,263
)
 
(34,778
)
Balance December 31, 2015
 
3,430

 
6,181

 
181,385

 
 
 
 
 
 
 
Developed reserves, included above
 
 
 
 
 
 
December 31, 2013
 
12,085

 
6,990

 
176,585

December 31, 2014
 
6,938

 
10,587

 
251,628

December 31, 2015
 
3,430

 
6,181

 
156,076

Proved undeveloped reserves, included above:
 
 
 
 
 
 
December 31, 2013
 
12,250

 
3,432

 
70,197

December 31, 2014
 
3,583

 
3,816

 
101,373

December 31, 2015
 
—

 
—

 
25,309

______________
(1) 
See discussion of revisions of previous estimates under “Changes in Standardized Measure of Discounted Future Net Cash Flows” below.


F-85



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 5 - 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 the Company’s Marcellus Shale and Utica Shale development program which included the wells completed on the Stewart Winland, Stalder, WVDNR and Ormet pads. Extensions and discoveries of 25,309 MMcf (4,218 MBoe) in 2015 were related to activity on the Company’s Stalder 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, 2015, 2014, and 2013 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, 2015, 2014, and 2013 to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carry forwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of the Company’s oil and natural gas properties.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

 
 
Years Ended December 31,
 
 
2015
 
2014
 
2013
 
 
(in thousands)
Future cash inflows
 
$
598,161

 
$
3,282,768

 
$
3,711,260

Future production costs
 
(369,478
)
 
(1,443,121
)
 
(1,423,306
)
Future development costs
 
(16,712
)
 
(219,509
)
 
(421,797
)
Future income tax expense
 
—

 
—

 
(149,367
)
Future net cash flows
 
211,971

 
1,620,138

 
1,716,790

10% annual discount for estimated timing of cash flows
 
(101,382
)
 
(710,875
)
 
(872,280
)
Standardized measure of discounted future net cash flows
 
$
110,589

 
$
909,263

 
$
844,510

 
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, 2015 and 2014, as a result of the Company’s net operating loss carryforwards of $1,031 million and $710 million, respectively, and other future expected tax deductions. See “Note 15 - Income Taxes”.


F-86



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,
 
 
2015
 
2014
 
2013
 
 
(in thousands)
Balance, beginning of period
 
$
909,263

 
$
844,510

 
$
847,653

Net changes in prices and production costs
 
(640,645
)
 
(281,352
)
 
(7,355
)
Changes in estimated future development costs
 
137,578

 
(57,348
)
 
(261,591
)
Sales and transfers of oil and gas produced during the period
 
(20,851
)
 
(166,611
)
 
(190,151
)
Net changes due to extensions, discoveries, and improved recovery
 
12,630

 
332,684

 
12,829

Net changes due to revisions of previous quantity estimates (1)
 
(458,945
)
 
(55,176
)
 
341,003

Previously estimated development costs incurred during the period
 
44,976

 
269,017

 
283,736

Accretion of discount
 
77,077

 
95,547

 
90,153

Purchase of minerals in place
 
—

 
—

 
218

Sale of minerals in place
 
—

 
(141,847
)
 
(236,885
)
Changes in timing and other
 
49,506

 
(7,720
)
 
(91,088
)
Net change in income taxes
 
—

 
77,559

 
55,988

Standardized measure of discounted future net cash flows
 
$
110,589

 
$
909,263

 
$
844,510

______________
(1) 
For the year ended December 31, 2015, the Company made downward revisions of 6,075 MBbl of oil, 162,147 MMcf of natural gas, and 6,959 MBbl of natural gas liquids due to additional information gathered from continued production, lower pricing levels, and liquidity constraints. For the year ended December 31, 2014, the Company made downward revisions of 6,540 MBbls 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 due to continued production from the shale areas and increases in EURs.

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:
 
 
2015
 
2014
 
2013
Oil (per Bbl)
 
$
41.83

 
$
85.21

 
$
93.13

Natural gas liquids (per Bbl)
 
$
16.90

 
$
50.64

 
$
43.79

Gas (per Mcf)
 
$
1.93

 
$
4.69

 
$
4.14


In accordance with SEC requirements, the pricing used in the Company’s 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 for each period presented 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.


F-87


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, 2015. Based upon that evaluation, the CEO and CFO concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2015.

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, 2015 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, 2015, 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, 2015 as stated in their report, dated May 6, 2016, which appears herein.

Changes in Internal Control Over Financial Reporting

There were no material changes in our internal control over financial reporting that occurred during the year ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.
OTHER INFORMATION

None.

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PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Upon the reorganized Company’s emergence from bankruptcy (the date of such emergence, the “Effective Date”), the board of directors will consist of a new seven-member board. Members of the current management team of the Debtors have remained in place during the pendency of the Chapter 11 Cases and are expected to remain in place until the Company’s emergence from bankruptcy; however, on May 6, 2016, Mr. Evans tendered his voluntary resignation as our Chief Executive Officer and Chairman of the Board of Directors, which resignation is expected to be effective following the filing of this Annual Report on Form 10-K.

Corporate Governance Guidelines

The business, property and affairs of Magnum Hunter are managed by our Chief Executive Officer under the direction of our Board of Directors. The Board is responsible for establishing broad corporate policies and for overall performance and direction of Magnum Hunter, but is not involved in day-to-day operations. Members of the Board keep informed of Magnum Hunter’s business by participating in Board and committee meetings, by reviewing analyses and reports sent to them regularly and through discussions with the Chief Executive Officer and other executive officers.

We have adopted Corporate Governance Guidelines that address significant issues of corporate governance and set forth the procedures by which the Board carries out its responsibilities. Among the areas addressed by the guidelines are director qualifications and responsibilities, Board committee responsibilities, selection and election of directors, director compensation and tenure, Board meeting requirements and Board and committee performance evaluations. The Governance Committee is responsible for assessing and periodically reviewing the adequacy of these guidelines. Our Corporate Governance Guidelines are available on the Company’s website under the “Corporate Governance” link under the “Investors” tab at www.mhr.energy.

Biographical Information of Our Directors

The following is a brief biography of each of our directors. The biographies include information regarding each individual’s service as a director of Magnum Hunter, business experience, director positions at public companies held currently or at any time during the last five years, and the experience, qualifications, attributes or skills that caused our Board and the Governance Committee to determine that the person should serve as a director of Magnum Hunter.

Victor G. Carrillo, age 51, has been a director of Magnum Hunter since January 2011. Mr. Carrillo currently serves as Chief Executive Officer (a position he has held since June 2015) and a director of Zion Oil & Gas, Inc. (“Zion”), a company engaged in onshore oil and gas exploration in Israel. Mr. Carrillo has served as a director of Zion since September 2010, and he served as President and Chief Operating Officer from October 2011 through June 2015 and as executive vice president Zion from January 2011 to October 2011. From 2003 to 2010, Mr. Carrillo served as a commissioner on the Texas Railroad Commission, overseeing the Texas oil and gas sector. Currently, Mr. Carrillo serves on the Advisory Board of the Maguire Energy Institute at Southern Methodist University and on the board of directors of the Texas-Israel Chamber of Commerce. He is also Chairman Emeritus of the West Texas Energy Consortium. During his time of service on the Texas Railroad Commission, Mr. Carrillo served as Chairman of the Governor’s Texas Energy Planning Council, Chairman of the Outer Continental Shelf Advisory Committee to the U.S. Secretary of the Interior, and Vice Chairman of the Interstate Oil and Gas Compact Commission. Mr. Carrillo received a B.S. in geology from Hardin-Simmons University, an M.S. in geology from Baylor University, a Juris Doctorate with emphasis in both environmental and oil and gas law from the University of Houston Law Center and an honorary Doctorate from Hardin-Simmons University. The Board has concluded that the Company benefits from Mr. Carrillo’s vast educational and professional experience related to the crude oil and natural gas exploration and production segment of the energy industry.

Gary C. Evans, age 58, has been a director of Magnum Hunter since 2009. Mr. Evans was appointed as Chairman of the Board and Chief Executive Officer of the Company in May 2009. Mr. Evans previously founded and served as the Chairman and Chief Executive Officer of Magnum Hunter Resources, Inc., or MHRI, an unrelated NYSE-listed company of similar name, for twenty years before selling MHRI to Cimarex Energy for approximately $2.2 billion in June 2005. Mr. Evans serves as an individual trustee of TEL Offshore Trust, a publicly-listed oil and gas trust, and is a director of Novavax Inc., a NASDAQ-listed clinical-stage vaccine biotechnology company. Mr. Evans was recognized by Ernst & Young LLP as the Southwest Area 2004 Entrepreneur of the Year for the Energy Sector and was subsequently inducted into the World Hall of Fame for Ernst & Young Entrepreneurs. Mr. Evans was also recognized as the Energy Industry Leader of the year in 2013 and chosen by Finance Monthly in 2013 as one of the most respected CEO’s. Mr. Evans was recently chosen as the Best CEO in the “Large Company” category by Texas Top Producers in 2013. He additionally won the Deal Maker of the Year Award in 2013 by Finance Monthly. Mr. Evans serves on the Board of the Maguire Energy Institute at Southern Methodist University and speaks regularly at energy industry conferences around the world on the current affairs of the oil and gas business.


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Stephen C. Hurley, age 66, has been a director of Magnum Hunter since October 2011. Mr. Hurley has 41 years of experience in the oil and gas industry. He also serves on the board of directors of Brigham Resources, LLC, a privately held oil and gas company. He is a former member of the board of directors of Brigham Exploration Company, serving from December 2002 to December 2011 when the company was sold to Statoil ASA for $4.6 billion. He also served on the audit and compensation committees of Brigham Exploration Company. Mr. Hurley is a former President and board member of Hunt Oil Company, having been associated with Hunt Oil Company from August 2001 to February 2012. Prior to joining Hunt Oil Company, Mr. Hurley served as Chief Operating Officer, Executive Vice President and a member of the board of directors for Chieftain International, Inc. from August 1995 to August 2001, when Hunt Oil Company bought Chieftain International, Inc. Prior to joining Chieftain International, Inc., Mr. Hurley was Executive Vice President of worldwide Exploration and Production for Murphy Exploration and Production Company. During his 16 year tenure at Murphy Exploration and Production Company, he held the positions of Senior Geologist, Exploration Manager, Vice President and Executive Vice President. From 1975 to 1980, Mr. Hurley was a geologist with Exxon Company USA, having been recruited out of college. Mr. Hurley holds both Bachelor of Science and Master of Science degrees in geology from the University of Arkansas and an advanced degree in business studies from Harvard University. He is a past President of both the Dallas Petroleum Club and Dallas Wildcatters Committee. The Board has concluded that the Company benefits from Mr. Hurley’s extensive executive-level experience in the energy industry.

Joe L. McClaugherty, age 64, has been a director of Magnum Hunter since 2006. Mr. McClaugherty is a senior partner of McClaugherty & Silver, P.C., a full service firm engaged in the practice of civil law located in Santa Fe, New Mexico. He has practiced law for 39 years and has a Martindale-Hubbell rating of AV Preeminent and is a Fellow of the International Academy of Trial Lawyers. Prior to founding McClaugherty & Silver, P.C. in 1992, he was the Managing Partner of the Santa Fe office of Kemp, Smith, Duncan & Hammond, and, earlier, of Rodey, Dickason, Sloan, Akin & Robb. Mr. McClaugherty has served on numerous boards of both international and domestic companies. He received a BBA with Honors from the University of Texas in 1973 and a JD with Honors from the University of Texas School of Law in 1976. He is admitted to the Bars of the State of New Mexico, State of Texas, State of Colorado, United States Federal District Court for the State of New Mexico, United States Federal District Court for the State of Colorado, United States Court of Appeals for the Tenth Circuit and the United States Supreme Court. The Board has concluded that the Company benefits from Mr. McClaugherty’s business and law degrees from the University of Texas at Austin, his approximately 39 years of legal experience in a broad-based civil practice and his extensive experience on boards of both international and domestic companies.

Jeff Swanson, age 60, has been a director of Magnum Hunter since 2009. Mr. Swanson currently serves as the President and Chief Executive Officer of GrailQuest Corp., a privately held company providing software and services to the oil and gas industry, a position he has held since January 1999. Mr. Swanson is also the President and Chief Executive Officer of Durango Resources Corp., an oil and gas producer operating in Texas. He has been actively engaged in the exploration and production sectors of the oil and gas industry for over 30 years. Mr. Swanson co-founded Stratamodel, Inc., which developed the first commercially available 3-D geocellular technology, now a standard workflow tool in the oil and gas industry. He is co-author of two patents including ReservoirGrail, an increasingly used reservoir volumetric material balancing simulator and SandGrail, a clastics modeling program. Mr. Swanson received his B.B.A. from Southern Methodist University and is a member of the Society of Petroleum Engineers (SPE), Association of Petroleum Geologists (AAPG), Houston Geological Society (HGS), Independent Petroleum Association of America (IPAA) and the National Stripper Well Association (NSWA). He is an individual trustee of TEL Offshore Trust, a publicly-listed oil and gas trust. He also serves on the Board of Directors of New Standard Energy, a public Australian company. The Board has concluded that the Company benefits from Mr. Swanson’s experience as a chief executive officer and his oil and gas industry expertise, particularly his technical expertise with respect to oil field and reserve estimation technology.

Director Resignations

On or about May 2, 2016, each of Messrs. Carrillo, Hurley, McClaugherty and Swanson submitted a letter of resignation to the Board resigning as a member of the Board effective as of the Effective Date. On May 6, 2016, Mr. Evans tendered his voluntary resignation as our Chief Executive Officer and Chairman of the Board of Directors, which resignation is expected to be effective following the filing of this Annual Report on Form 10-K.

Biographical Information of Our Executive Officers

The following is a brief biography of each of our executive officers other than Mr. Evans, whose biographical information is included above.

Joseph C. Daches, age 49, has been Chief Financial Officer and Senior Vice President of the Company since July 2013. Mr. Daches has more than 25 years’ experience in management and working with boards of directors, banks and attorneys, primarily within the energy industry. Prior to joining the Company, Mr. Daches had served as Executive Vice President and Chief Accounting Officer of Energy & Exploration Partners, Inc. since September 2012 and as a director of that company since April 2013. He previously served as a partner and Managing Director of the Willis Consulting Group, LLC, from January 2012 to September 2012. From October

90


2003 to December 2011, Mr. Daches served as the Director of E&P Advisory Services at Sirius Solutions, LLC, where he was primarily responsible for financial reporting, technical, and oil and gas accounting and the overall management of the E&P advisory services practice. Mr. Daches earned a Bachelor of Science in Accounting from Wilkes University in Pennsylvania, and he is a certified public accountant in good standing with the Texas State Board of Public Accountancy.

Richard S. Farrell, age 58, has served as Senior Vice President of Business Development and Land for Triad Hunter, LLC, a wholly owned subsidiary of the Company, since April 2010. Prior to joining the Company, Mr. Farrell served as president of JR Farrell Enterprises, LLC, a firm active in oil and gas exploration, production, land and legal consulting, as well as real estate and agricultural investments. From 1999 to 2005, Mr. Farrell served as Vice President Land - Onshore for Magnum Hunter Resources, Inc., an unrelated company of similar name, and its wholly owned subsidiaries Prize Energy Corporation, Gruy Petroleum Management Co. and Magnum Hunter Production, Inc. Mr. Farrell is a member of the Independent Oil and Gas Association of West Virginia and the Kentucky Oil & Gas Association. Mr. Farrell earned his Bachelor’s degree in marketing from the University of Richmond in 1979.

H.C. “Kip” Ferguson, III, age 51, currently serves as Executive Vice President - Exploration. Those duties include business development, natural gas management, asset acquisition and divestiture, project planning, capital expenditures analysis, and the management of the reserves department for the Company. Mr. Ferguson has served as an Executive Vice President of the Company since October 2009 and was President of our Eagle Ford Shale Division from 2011 until April 2013. Mr. Ferguson was formerly the President of Sharon Resources, Inc. from September 1999 until the company was acquired by Magnum Hunter in October 2009 and subsequently renamed Eagle Ford Hunter, Inc. As President of Eagle Ford Hunter, Inc., Mr. Ferguson’s responsibilities included supervision of the day-to-day activities of that company, budget planning for operations, managing the reserves group, supervision of the development of exploratory projects within numerous basins and involvement in extensive field studies and trend analysis, using advanced drilling and completion technology. Mr. Ferguson brings more than 28 years of exploration and development experience in several major U.S. basins to the Company. Mr. Ferguson served on the board of Sharon Resources, Inc. and Sharon Energy Ltd. from September 1999 to October 2009. Mr. Ferguson served on the board for Diaz Resources, Inc. from 2005 to 2009. Mr. Ferguson is a third-generation geologist with a degree in Geology from the University of Texas at Austin.

Paul M. Johnston, age 61, has served as Senior Vice President and General Counsel of the Company since June 2010. Mr. Johnston has over 30 years of increasing responsibility and management experience in all facets of general corporate, finance, securities and regulatory related legal matters. He is a former partner with the Dallas-based law firm, Thompson & Knight, LLP, representing both private and publicly held companies during his twenty-year career with the firm. Mr. Johnston also had ten years of in-house counsel experience before joining Magnum Hunter, including his service as Vice President and Corporate Counsel for an NYSE-listed Fortune 250 company from 2000 to 2007, and his service as General Counsel for Links Business Capital, LP, the manager for an SEC-registered investment advisor involved in the management of onshore and offshore hedge funds, from 2007 to 2010. A 1977 graduate of Texas Tech University, Mr. Johnston received his Juris Doctorate from Texas Tech University in 1980.

Keith Yankowsky, age 51, has more than 29 years of engineering experience, including operations, drilling and completions, within large independent oil and natural gas companies focused on both conventional and unconventional resource plays. Prior to joining Magnum Hunter, Mr. Yankowsky served as Vice President of Appalachia South Business Unit at Chesapeake Energy Corporation since 2013. During his nine year tenure at Chesapeake Energy Corporation, Mr. Yankowsky also held the title of Vice President of Engineering Technology and Special Projects between 2009 and 2013 and was involved in overseeing a variety of engineering and operational functions specifically related to horizontal drilling and fracture stimulation techniques within the Marcellus and Utica Shale plays. Mr. Yankowsky earned a Bachelor of Science degree in Petroleum Engineering from Marietta College, Marietta, Ohio.

Director Nomination Process

In assessing the qualifications of candidates for nomination as director, our Governance Committee and our Board consider, in addition to qualifications set forth in our bylaws, each potential nominee’s:

•
Personal and professional integrity, experience, reputation and skills;
•
Ability and willingness to devote the time and effort necessary to be an effective Board member; and
•
Commitment to act in the best interests of Magnum Hunter and its stockholders.

In addition, the Board looks for nominees who possess a broad range of business experience, diversity (“diversity” being broadly construed to mean a variety of opinions, perspectives, experiences and backgrounds, such as gender, race and ethnicity differences, as well as other differentiating characteristics, all in the context of the requirements of our Board at that point in time), professional skills, geographic representation and other qualities it considers important in light of our business plan. The Board evaluates the makeup of its membership in the context of the Board as a whole, with the objective of recommending a group that can effectively work together using its diversity of experience to see that Magnum Hunter is well managed and represents the interests of the Company and its stockholders.

91



Our common stockholders may submit the names and other information regarding individuals they wish to be considered for nomination as directors by writing to our Corporate Secretary at 909 Lake Carolyn Parkway, Suite 600, Irving, Texas 75039.

Board’s Role in Risk Oversight

Our Board of Directors is responsible for the Company’s risk-oversight function and is actively involved in the oversight of risks that could affect our Company. Management is responsible for the day-to-day management of risks we face, while the Board, as a whole and through its committees, has responsibility for the oversight of risk management.

The Audit Committee of our Board is charged by its charter with, among other duties, reviewing the significant accounting principles, policies and practices followed by the Company; reviewing financial, investment and risk management policies followed by Magnum Hunter in operating its business activities; reviewing the Company’s annual audited financial statements; reviewing the effectiveness of our independent audits, including approval of the scope of and fees charged in connection with our annual audit and quarterly reviews; appointing and overseeing the work of the Company’s independent auditor; and reviewing and discussing audit-related and independence matters with management, the Board and the Company’s independent auditors. The Audit Committee must regularly update the Board and make appropriate recommendations. Additionally, at Audit Committee meetings, our management may present a particular area of risk, either independently as a result of its assessment of materiality or at the request of the Audit Committee. The Audit Committee works with management to address the strengths and weaknesses of the policies in each area presented or separately assessed. In addition to the formal compliance program, the Board and the Audit Committee encourage management to promote a corporate culture that understands risk management and incorporates it into the overall corporate strategy and day-to-day business operations.

Board of Directors’ Leadership Structure

Gary C. Evans currently serves as Chairman of the Board in addition to his role as our Chief Executive Officer. The Board believes that our Chief Executive Officer is currently best situated to serve as Chairman because he is the director most familiar with our business and most capable of effectively identifying strategic priorities and leading the discussion and execution of strategy. Our independent directors bring experience, oversight and expertise from outside the Company, while the Chief Executive Officer brings company-specific experience and expertise. The Board believes that the combined role of Chairman and Chief Executive Officer facilitates information flow between management and the Board.

The Board appointed Mr. McClaugherty as the Company’s lead independent director on April 13, 2013, and Mr. McClaugherty continues to serve as the Company’s lead independent director. The Board intends to continue to maintain a lead independent director on the Board. The additional responsibilities of the lead independent director include: (i) chairing executive sessions where independent directors meet either before or after regularly scheduled Board meetings and, as appropriate, providing prompt feedback to the Chairman of the Board and the CEO, (ii) calling, setting the agenda for and chairing periodic executive sessions and meetings of the independent directors and reporting accordingly to the full Board, (iii) chairing Board meetings in the absence of the Chairman of the Board, (iv) providing feedback to the Chairman of the Board and CEO on corporate and Board policies and strategies and acting as a liaison between the Board and the CEO, (v) facilitating one-on-one communication between directors and committee chairs and the Chairman of the Board and CEO and other senior managers to keep abreast of their perspectives, (vi) in concert with the Chairman of the Board and CEO, advising on the agenda and schedule for Board meetings and strategic planning sessions based on input from directors, (vii) providing advance feedback on background materials and resources necessary or desirable to assist the directors in carrying out their responsibilities, and reviewing Board materials and background papers in advance of Board meetings, (viii) interviewing potential candidates for election to the Board, (ix) holding one-on-one discussions with individual directors when deemed appropriate by the Chairman of the Board or the lead independent director, (x) overseeing the evaluation of individual members of the Board and of the CEO and (xi) carrying out such other duties as are requested by the Board from time to time.

Code of Conduct and Ethics

We have adopted a Code of Conduct and Ethics that applies to our directors, officers and employees, including our principal executive officer and principal financial and accounting officers. This code assists employees in resolving ethical issues that may arise in complying with its policies. The purpose of this code is to promote, among other things:

•
Honest and ethical conduct, including ethical handling of actual or apparent conflicts of interest;
•
Full, fair, accurate and timely disclosure in filings with the SEC and other public disclosures;
•
Compliance with the law and other regulations;
•
Protection of our assets;

92


•
Insider trading policies; and
•
Prompt internal reporting of any violation of the code.

This code is available on our website at www.mhr.energy. We will provide this code free of charge to stockholders who request it. We will post information regarding any amendments to, or waivers from, the provisions of this code that apply to our principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions, on our website.

The Company maintains a third-party managed whistleblower hotline whereby employees can submit complaints or concerns regarding financial statement disclosures, accounting matters, internal accounting controls, auditing matters, compliance with applicable laws, rules and regulations and compliance with the Company’s policies and procedures, including matters arising under our Code of Conduct and Ethics.

Stockholder Communications with the Board of Directors

Stockholders and other interested parties who wish to communicate with our non-management directors or the entire Board may do so by making a submission in writing to “Board of Directors (independent members)” or “Board,” respectively, in care of our Corporate Secretary at 909 Lake Carolyn Parkway, Suite 600, Irving, Texas 75039. Our Corporate Secretary will then forward all such communications (excluding routine advertisements and business solicitations) to each member of our Board, or the applicable individual directors.

We reserve the right to screen materials sent to our directors for potential security risks and/or harassment purposes. Stockholders also have an opportunity to communicate with our Board at our annual meetings of stockholders.

Attendance at Meetings of Stockholders

All directors are expected to attend annual meetings of our stockholders, subject to occasional excused absences due to illness or unavoidable conflicts. All of our directors attended our 2015 annual meeting of stockholders, except for Mr. J. Raleigh Bailes, Sr., who was not standing for reelection to the Board.

Our Board Committees

The Board of Directors oversees the management of the business and affairs of our Company. The Board has three standing committees: the Audit Committee, the Compensation Committee and the Governance Committee, each of which is described below. Each committee operates under a written charter adopted by the Board.

In 2015, the Board met 24 times and acted by unanimous written consent 5 times; the Audit Committee met 7 times; the Compensation Committee met 17 times; and the Governance Committee met 16 times. Each director attended more than 98% of the meetings of the Board and the committees on which he served. The following table sets forth the committees of the Board and their members as of the date of the filing of this Annual Report on Form 10-K:
Director
Audit Committee
Compensation
Committee
Governance Committee
Victor G. Carrillo
 
 
*Ÿ
Gary C. Evans
 
 
 
Stephen C. Hurley
*Ÿ
Ÿ
Ÿ
Joe L. McClaugherty
Ÿ
*Ÿ
 
Jeff Swanson
Ÿ
Ÿ
Ÿ
                        
(*) Denotes Chair

From time to time, the Board also establishes special committees to address specific matters.

Website Availability of Documents

This Annual Report on Form 10-K for the fiscal year ended December 31, 2015, all of our other SEC filings, the charters of the Audit Committee, Compensation Committee and Governance Committee, our Code of Conduct and Ethics and our Corporate Governance Guidelines can be found on our website at www.mhr.energy. The committee charters, Code of Conduct and Ethics and Corporate

93


Governance Guidelines are located under the “Corporate Governance” link under the “Investors” tab. Unless specifically stated herein, documents and information on our website are not incorporated by reference in this annual report.

Audit Committee

Our Audit Committee assists the Board in fulfilling its oversight responsibilities by, among other things, reviewing the financial information that will be provided to the stockholders and others; reviewing the internal controls over financial reporting that management has established; appointing, retaining and overseeing the performance of our independent registered public accounting firm; and overseeing our accounting and financial reporting processes and the audits of our financial statements. Our Audit Committee also consults with our management and our independent registered public accounting firm prior to the presentation of financial statements to stockholders and, as appropriate, initiates inquiries into aspects of our financial affairs. Our Audit Committee, along with our Governance Committee, are responsible for establishing procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls or auditing matters, and for the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters. In addition, our Audit Committee is directly responsible for the appointment, retention, compensation and oversight of the work of our independent auditors, including approving services and fee arrangements.

The current members of our Audit Committee are Messrs. Hurley, McClaugherty, and Swanson. Mr. Rocky Duckworth served as Chairman of the Audit Committee during 2014 and through his resignation effective May 31, 2015. Mr. Hurley assumed the duties of interim Chairman of the Audit Committee on June 1, 2015.

Our Board has determined that all of the members of our Audit Committee meet the SEC’s independence and other requirements for audit committee membership of the NYSE listing standards and SEC requirements. Mr. Duckworth resigned from the Board effective May 31, 2015 and Mr. Bailes did not stand for reelection to the Board at our 2015 annual meeting of stockholders. Following the departure of Messrs. Duckworth and Bailes from the Board, our Audit Committee no longer has a member that meets the qualifications of an audit committee financial expert in accordance with SEC rules. The Board has determined that Messrs. Hurley and McClaugherty have a fundamental understanding of financial statements.

Since its formation in April 2006, the Audit Committee has approved all audit fees, audit-related fees, tax fees and special engagement fees of the Company’s independent public accounting firm. The Audit Committee approved 100% of such fees for the year ended December 31, 2015.

Based on the Audit Committee’s review and discussions noted above, the Audit Committee recommended to our Board of Directors that Magnum Hunter’s audited financial statements for the year ended December 31, 2015 be included in our annual report on Form 10-K for the year ended December 31, 2015.

Compensation Committee

Our Board’s Compensation Committee discharges the Board’s responsibilities relating to the compensation of our directors and officers. The Compensation Committee has the overall responsibility for, among other things, establishing the compensation levels and direct and indirect benefits of our officers and directors; making recommendations to the Board with respect to the establishment and terms of incentive compensation plans and equity-based plans and administering such plans; reviewing and evaluating the Company’s compensation program and such program’s coordination and execution; establishing and reviewing policies with respect to management and director perquisites; engaging any outside consultant to assist in determining appropriate compensation levels for our officers and directors; and reviewing and discussing with management the Compensation Discussion and Analysis included in the Company’s annual report on Form 10-K or proxy statement. In addition, our Compensation Committee administers our Stock Incentive Plan, including reviewing and granting restricted stock and other share-based awards, with respect to our directors, officers and employees.

The current members of our Compensation Committee are Messrs. Hurley, McClaugherty, and Swanson. Mr. McClaugherty serves as Chairman of the Compensation Committee. Each member of our Compensation Committee meets the SEC’s independence standards for compensation committee membership.

Governance Committee

Our Governance Committee’s responsibilities include identifying individuals qualified to become Board members consistent with criteria approved by the Board and recommending candidates for election to our Board; reviewing and recommending changes, when necessary, to the Board regarding the Corporate Governance Guidelines of the Company; overseeing the director nomination process and the evaluation of the Board and management; reviewing the independence of each Board member and making recommendations

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to the Board regarding director independence; reviewing and resolving issues pertaining to related-party transactions and conflicts of interests; and evaluating and, if necessary, recommending changes to the Board regarding Board processes and policies.

The Governance Committee has established procedures for the nomination process and leads the searches for, selects and recommends candidates for election to our Board, subject to legal rights, if any, of third parties to nominate or appoint directors. Consideration of new director candidates typically involves a series of committee discussions, review of information concerning candidates and interviews with selected candidates. Candidates for nomination to our Board typically have been suggested by other members of our Board or by our executive officers. From time to time, our Governance Committee may engage the services of a third-party search firm to identify director candidates. Our Governance Committee recommends candidates for election to our Board. Candidates proposed by common stockholders will be evaluated by our Governance Committee using the same criteria as for all other candidates.

The Board will consider recommendations of director nominees from common stockholders that are submitted in accordance with the advance notice provisions of the Company’s bylaws. Such recommendations should be accompanied by the candidate’s name, biographical data, qualifications and a written statement from the individual evidencing his or her consent to be named as a candidate and, if nominated and elected, to serve as a director. Other than as stated herein, we do not have a formal policy with respect to consideration of director candidates recommended by stockholders, as the Board believes that each candidate, regardless of the source of the recommendation, should be evaluated in light of all relevant facts and circumstances.

Nominees for director are selected on the basis of, among other things, independence, experience, knowledge, skills, expertise, integrity, ability to make independent analytical inquiries, understanding of the Company’s business environment, ability to devote adequate time and effort to Board responsibilities and commitments to other public company boards. Other criteria for director candidates considered by the Governance Committee and by the full Board include age, diversity (“diversity” being broadly construed to mean a variety of opinions, perspectives, experiences and backgrounds, such as gender, race and ethnicity differences, as well as other differentiating characteristics, all in the context of the requirements of our Board at that point in time), whether the candidate has any conflicts of interest, whether the candidate has the requisite independence and skills for Board and committee service under applicable SEC rules, how the candidate’s skills and experience enhance the overall competency of the Board, and whether the candidate has any special background relevant to Magnum Hunter’s business.

The current members of our Governance Committee are Messrs. Carrillo, Hurley and Swanson. Mr. Carrillo serves as Chairman of the Governance Committee.

Director and Officer Indemnification

Our bylaws permit the Company to indemnify the Company’s directors and officers to the fullest extent permitted by law. We also maintain directors’ and officers’ liability insurance.  Additionally, we have, from time to time, entered into separate indemnification agreements with persons who were in service as directors and executive officers of the Company at such time (some of whom are no longer serving in such capacities) that provide broader indemnification than that required under the General Corporation Law of the State of Delaware. These agreements, among other things, require us to indemnify our directors and executive officers to the fullest extent permitted by applicable law for certain expenses, including attorneys’ fees, judgments, penalties, fines and settlement amounts actually and reasonably incurred by a director or executive officer in any action or proceeding arising out of his service as one of our directors or executive officers, or any of our subsidiaries, or any other company or enterprise to which the person provides services at our request, including liability arising out of negligence or active or passive wrongdoing by the officer or director.  We believe that these agreements are necessary to attract and retain qualified directors and executives.

The limitation of liability and indemnification provisions in our restated certificate of incorporation and bylaws and the indemnification agreements may discourage stockholders from bringing a lawsuit against our directors and officers for breach of their fiduciary duty. They may also reduce the likelihood of derivative litigation against our directors and officers, even though an action, if successful, might benefit us and other stockholders. Further, a stockholder’s investment may be adversely affected to the extent that we pay the costs of settlement and damage awards against directors and officers as required by these indemnification provisions.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our directors, executive officers and beneficial holders of more than 10% of our common stock to file reports with the SEC regarding their ownership and changes in ownership of our stock. Based solely upon a review of Forms 3 and 4 and amendments thereto furnished to us during the year ended December 31, 2015 and Forms 5 and amendments thereto furnished to us with respect to the year ended December 31, 2015, and any written representations provided to us, we believe that all of our directors, executive officers and beneficial holders of more than 10% of the outstanding shares of our common stock complied with Section 16(a) of the Exchange Act for the year ended December 31, 2015.


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Item 11. EXECUTIVE COMPENSATION

Upon the reorganized Company’s emergence from bankruptcy, the board of directors will consist of a new seven-member board. Members of the current management team of the Debtors have remained in place during the pendency of the Chapter 11 Cases and are expected to remain in place until the Company’s emergence from bankruptcy; however, on May 6, 2016, Mr. Evans tendered his voluntary resignation as our Chief Executive Officer and Chairman of the Board of Directors, which resignation is expected to be effective following the filing of this Annual Report on Form 10-K. Upon the Company’s emergence from bankruptcy, the new board of directors will develop and implement its own compensation policies in accordance with the confirmed Plan, which may differ from the the below descriptions.

Director Compensation

Our Compensation Committee reviews, not less frequently than bi-annually, and recommends to our Board for approval, fees and other compensation and benefits for our non-employee directors. Also, our Compensation Committee frequently consults with Longnecker and Associates (“Longnecker”), an independent compensation consultant, on the competitiveness of our director and executive compensation. Longnecker assists our Compensation Committee in evaluating the appropriateness of our non-employee directors’ compensation program, including the mix of meeting fees and annual chairperson retainers, to ensure that the program compensates our non-employee directors for the level of responsibility the Board has assumed in today’s corporate governance environment and to remain competitive relative to companies in our peer group. Longnecker’s most recent formal peer group review for the Compensation Committee on overall director compensation was performed in December 2013. That review looked at the following companies in our peer group:

Approach Resources Inc.
Gulfport Energy Corporation
Resolute Energy Corporation
Carrizo Oil & Gas, Inc.
Halcon Resources Corporation
Rex Energy Corporation
Comstock Resources, Inc.
Kodiak Oil & Gas Corp. (which has since been acquired by Whiting Petroleum Corporation)
Rosetta Resources Inc.
EXCO Resources, Inc.
Northern Oil & Gas, Inc.
Swift Energy Company
Forest Oil Corporation (which has since merged with Sabine Oil & Gas LLC to form Sabine Oil & Gas Corp.)
Oasis Petroleum Inc.
 
Goodrich Petroleum Corporation
PDC Energy, Inc.
 

In addition, following the departure of Messrs. Duckworth and Bailes from the Board during 2015, the Compensation Committee obtained a recommendation from Longnecker as to recruitment and retention equity grants in order to attract and retain qualified and motivated independent directors. Based on Longnecker’s recommendation, in June 2015, each independent director received a retention grant of 150,000 shares of restricted common stock, as further described below.

Other than the Retention Grant, the Company’s non-employee directors’ compensation program remained fundamentally unchanged in 2015. Each of our non-employee directors received a $50,000 annual retainer. In addition to the general annual retainer, supplemental retainers were paid for the following positions: $15,000 to the chair of the Audit Committee, $10,000 to the chair of each other committee, and $30,000 to the lead independent director. Fees for attending meetings of the Board and its standing committees were set at $1,500 per Board meeting and $1,000 per standing committee meeting. Fees for attending meetings of special committees were set at $1,000 per meeting for meetings up to two hours in duration, with an additional $1,000 for each additional two hour block, or portion thereof, in excess of the initial two hours. The Company’s Reserves Committee, the members of which are officers of the Company appointed by the Company’s Chief Executive Officer, reports to the Governance Committee and members of the Governance Committee periodically participate in meetings of the Reserves Committee. Beginning in 2015, the members of the Governance Committee receive fees for their participation in meetings of the Reserves Committee as if participating in a meeting of a special committee of the Board. Meeting fees and retainers are paid on a quarterly basis.

In August 2012, the Board adopted a non-employee director compensation policy that allowed each non-employee director to elect to receive ordinary director compensation described above in cash, in shares of our common stock, or a combination thereof. Each director’s election would remain in effect until a new election was made, and new elections could be made on an annual basis. For 2015, each non-employee director had elected to receive his compensation in shares of the Company’s common stock, except for Mr. Duckworth who had elected to receive his compensation in cash. The number of shares paid in lieu of cash compensation was based on the volume weighted average price of our common stock for the calendar quarter in which the meetings were held or the retainer accrued. Effective January 1, 2016, the Board adopted an amended and restated non-employee director compensation policy that provides that all ordinary non-employee director compensation will be paid in cash.

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Our non-employee directors also receive an annual long-term incentive award under our Stock Incentive Plan in the form of restricted common stock of the Company. This grant ensures that the most significant component of our non-employee directors’ compensation is directly linked to the investment by the Company’s stockholders.

The 2015 long-term incentive award grant to non-employee directors was made in November 2014 at the same time as long-term incentive awards were granted to many of the Company’s employees. Each non-employee director received shares of restricted common stock of the Company valued at approximately $150,000 on the date of the grant. When granted, the 2015 long-term incentive award restrictions were scheduled to lapse one year from the date of grant or, if earlier, upon the death of the recipient or a change in control of the Company, subject to the recipient’s continued service as a director through the date the restrictions lapse. In December 2014, the Compensation Committee considered the Company’s employee and director retention needs in light of the challenging market and commodity price environment. To incentivize and retain the Company’s employees and non-employee directors, the Compensation Committee accelerated the lapse of restrictions on certain awards to December 2014, including the restrictions on the full amount of the 2015 long-term incentive award grant to non-employee directors.

In addition, in June 2015, each non-employee director received a Retention Grant of 150,000 shares of restricted common stock of the Company, which shares are scheduled to vest two years from the date of grant or, if earlier, upon the death or disability of the recipient or a change in control of the Company that occurs at least six months following the date of grant.

As of the date of this filing, none of our current non-employee directors has sold his Company stock received as compensation for 2015 meeting fees and retainers, for the 2015 long-term incentive award grant or for the Retention Grants.

The following table presents compensation earned by each non-employee director for 2015. Compensation information for Mr. Evans, a director, is contained in the 2015 Summary Compensation Table below. Mr. Evans did not receive any compensation in his capacity as a director of the Company.

 Name
Fees
Paid in Cash
Option Awards (2)
Restricted Stock Awards (1) (3)
Fees Paid in Stock (1)
All Other Compensation (4)
Total
J. Raleigh Bailes, Sr. (5)
$
—

$
—

$
—

$
32,000

$
—

$
32,000

Victor G. Carrillo
$
—

$
—

$
195,000

$
48,001

$
—

$
243,001

Rocky L. Duckworth (6)
$
36,583

$
—

$
—

$
—

$
—

$
36,583

Stephen C. Hurley
$
—

$
—

$
195,000

$
67,252

$
—

$
262,252

Joe L. McClaugherty
$
—

$
—

$
195,000

$
67,002

$
—

$
262,002

Jeff Swanson
$
—

$
—

$
195,000

$
61,001

$
—

$
256,001

(1)
Represents the aggregate grant date fair value, in accordance with Accounting Standards Codification 718, “Stock Compensation”, referred to in this annual report as ASC 718 (except no assumptions for forfeitures were included), with respect to (a) shares of common stock (under the Fees Paid in Stock column), and (b) shares of restricted common stock (under the Restricted Stock Awards column). See “Note 12 - Share-Based Compensation” in the notes to our consolidated financial statements for information regarding the assumptions made in determining these values.
(2)
As of December 31, 2015, the aggregate number of outstanding option awards held by our current non-employee directors was: 175,000 for Mr. Carillo, 136,000 for Mr. Hurley, 140,000 for Mr. McClaugherty, and 175,000 for Mr. Swanson.
(3) 
As of December 31, 2015, Messrs. Carillo, Hurley, McClaugherty, and Swanson each held 150,000 shares of unvested restricted common stock.
(4) 
We reimburse the reasonable travel and accommodation expenses of directors to attend meetings and other corporate functions. In 2015, the incremental cost to the Company to provide these perquisites was less than $10,000 per director.
(5) 
Mr. Bailes did not stand for reelection at the Company’s 2015 annual meeting of stockholders and departed the Board effective June 12, 2015.
(6) 
Mr. Duckworth resigned from the Board effective May 31, 2015.

Executive Compensation Discussion and Analysis

This compensation discussion and analysis provides information regarding our executive compensation program in 2015 for the following executive officers of the Company, collectively referred to as our Named Executive Officers, or NEOs:

•
Gary C. Evans, Chairman and Chief Executive Officer

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•
Joseph C. Daches, Senior Vice President and Chief Financial Officer
•
James W. Denny III, former Executive Vice President and President, Appalachian Division
•
H.C. “Kip” Ferguson, Executive Vice President - Exploration
•
Paul M. Johnston, Senior Vice President and General Counsel
•
Keith Yankowsky, Executive Vice President and Chief Operating Officer

2014 Stockholder Advisory Vote on Executive Compensation

At our 2014 annual meeting of stockholders, we held an advisory vote on executive compensation. Over 89% of the votes cast were in favor of the compensation of the NEOs. The Compensation Committee considered this favorable outcome and believed it conveyed our stockholders’ support of the Compensation Committee’s decisions and the existing executive compensation programs. The Compensation Committee continues to look for ways to attract and retain top executive talent whose interests are aligned with those of the Company’s stockholders. At the 2017 annual meeting of stockholders, we will again hold an advisory vote to approve executive compensation, as a vote every three years was supported by the common stockholders in 2011 in accordance with the Company’s recommendation. The Compensation Committee will continue to consider the results from the 2014 vote and future advisory votes on executive compensation.

Our Compensation Philosophy

The objective of the Company’s executive compensation program is to enable us to recruit and retain a highly qualified management team by providing competitive levels of compensation in a competitive market for executive talent. We also seek to motivate our executives to achieve individual and business performance objectives by varying their compensation in accordance with the success of our business.

We believe compensation programs can drive the behavior of employees covered by the programs, and accordingly we seek to design our executive compensation program to align compensation with current and desired corporate performance and stockholder interests. Actual compensation in a given year will vary based on the Company’s performance and on subjective appraisals of individual performance. In other words, actual compensation generally will reflect the Company’s financial and operational performance.

We maintain competitive benefit programs for our employees, including our NEOs, with the objective of retaining their services. Our benefits reflect competitive practices at the time the benefit programs were implemented and, in some cases, reflect our desire to maintain similar benefits treatment for all employees in similar positions. To the extent possible, we structure these programs to deliver benefits in a manner that is tax efficient to both the recipient and the Company.

We seek to provide compensation that is competitive with the companies we believe are our peers and other likely competitors for executive talent. Competitive compensation is normally sufficient to attract executive talent to the Company. Competitive compensation also makes it less likely that executive talent will be lured away by higher compensation to perform a similar role with a similarly-sized competitor. We also believe that a significant portion of compensation for executives should be “at risk,” meaning that the executives will receive a significant portion of their total compensation only to the extent the Company and the executive accomplish goals established by our Compensation Committee.

We frequently consult with Longnecker on the competitiveness of our executive compensation. In December 2013, Longnecker performed a formal peer group review on the compensation of our senior executives. That review looked at the following companies in our peer group:
Approach Resources Inc.
Gulfport Energy Corporation
Resolute Energy Corporation
Carrizo Oil & Gas, Inc.
Halcon Resources Corporation
Rex Energy Corporation
Comstock Resources, Inc.
Kodiak Oil & Gas Corp. (which has since been acquired by Whiting Petroleum Corporation)
Rosetta Resources Inc.
EXCO Resources, Inc.
Northern Oil & Gas, Inc.
Swift Energy Company
Forest Oil Corporation (which has since merged with Sabine Oil & Gas LLC to form Sabine Oil & Gas Corp.)
Oasis Petroleum Inc.
 
Goodrich Petroleum Corporation
PDC Energy, Inc.
 


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We historically have targeted direct cash compensation (salary and bonus) at or around the 50th percentile of our peer group and long-term incentive compensation at or around the 75th percentile of our peer group, for a total compensation package that falls between the 50th and 75th percentiles of our peer group. We believe this approach best serves our objectives described above.

Ordinary Elements of Compensation

Base Salary

Base salary is the foundation of total compensation. Base salary recognizes the job being performed and the value of that job in the competitive market. Base salary must be sufficient to attract and retain the talent necessary for our continued success and provides an element of compensation that is not at risk in order to avoid fluctuations in compensation that could distract the executives from the performance of their responsibilities.

Adjustments to base salary primarily reflect either changes or responses to changes in market data or increased experience and individual contribution of the employee. Working with Longnecker, we noted in 2010 that our base salaries were, in many cases, significantly below market. Through 2014, we instituted salary increases each year to address the disparity in base compensation with our peer group, but continued to place more emphasis on incentive compensation because of its link to the creation of stockholder value. Given the substantial decline in prices for natural gas and oil and the effects of this decline on the oil and gas industry, the Compensation Committee determined that base salaries for the Company’s NEOs for 2015 would generally remain consistent with 2014 base salaries.

Short-Term Incentives

Historically, we have generally provided short-term incentives in the form of annual cash performance bonuses. These bonuses are designed to reward, where earned, short-term performance and the achievement of the Company’s short-term goals. For 2014, however, the Compensation Committee determined that bonuses would be paid to our NEOs 60% in Company stock and 40% in cash. The cash component of 2014 bonuses paid to our NEOs was used primarily to satisfy federal, state and local tax withholding obligations.

On December 15, 2015, the Company and certain of its subsidiaries (collectively, the “Debtors”) each filed a voluntary petition for relief under Chapter 11 of title 11 of the United States Code (“Chapter 11”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) under the caption In re Magnum Hunter Resources Corporation, et al., Case No. 15-12533. In connection with the Chapter 11 cases, the Third Amended Joint Chapter 11 Plan of Reorganization of Magnum Hunter Resources Corporation and its Debtor Affiliates (the “Plan”) was filed by the Debtors with the Bankruptcy Court on April 14, 2016. On April 18, 2016, the Plan was confirmed by the Bankruptcy Court.

Primarily as a result of the Debtors’ bankruptcy proceedings, the Company did not provide any short-term incentive bonuses to any of our executive officers, including each of our NEOs, for 2015.

Long-Term Incentives

The Company’s Stock Incentive Plan

Our Stock Incentive Plan, in which each of our executive officers, including each of our NEOs, and certain other employees participate, is designed to reward participants for sustained improvements in the Company’s financial performance and increases in the value of our common stock over an extended period. Long-term incentives are a key component of the Company’s overall compensation structure.

The Compensation Committee may authorize grants throughout the year depending upon the Company’s activities during that time period. Grants can be made from a variety of award types authorized under our Stock Incentive Plan.

Currently, the vesting criteria for most awards is service based to ensure that equity compensation awards have the effect of retaining our employees. The 2015 long-term incentive award grant to our executive officers, including each of our NEOs, was made in November 2014. When granted, the 2015 long-term incentive award restrictions were scheduled to lapse equally on the first, second and third anniversaries of the date of grant. In December 2014, the Compensation Committee considered the Company’s employee retention needs in light of the challenging market and commodity price environment. To incentivize and retain the Company’s employees, the Compensation Committee accelerated the lapse of restrictions on one-third of the awards to December 2014.
 
The number of shares of restricted stock granted to our NEOs during 2015 was targeted at the 75th percentile in long-term incentive compensation of our peer group.

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Eureka Midstream Holdings, LLC Management Incentive Compensation Plan

The Eureka Midstream Holdings, LLC Management Incentive Compensation Plan (“Eureka Midstream Holdings Plan”) provides long-term incentive compensation to attract and retain officers and employees of Eureka Midstream Holdings and its affiliates and allow those individuals to participate in the economic success of Eureka Midstream Holdings and its affiliates. The Eureka Midstream Holdings Plan is sponsored and administered by Eureka Midstream Holdings.

Eureka Midstream Holdings made awards under the Eureka Midstream Holdings Plan in 2014 to certain officers and employees of Eureka Midstream Holdings and its affiliates (“Award Recipients”), including Mr. Evans, who serves as the Chief Executive Officer of Eureka Midstream Holdings. These awards consisted of Class B Common Units representing membership interests in Eureka Midstream Holdings (“Class B Common Units”) and Incentive Plan Units in Eureka Midstream Holdings (“Incentive Plan Units”). Class B Common Units and Incentive Plan Units have been awarded in tandem, with each award consisting of an equal number of Class B Common Units and Incentive Plan Units.

The Class B Common Units are profits interest awards that carry the right to share in the appreciation in the value of a common unit in Eureka Midstream Holdings over and above a baseline value (the “Baseline Value”) that is determined on the date of grant of the Class B Common Units. The Incentive Plan Units represent the right to receive, upon the occurrence of specified events, a dollar amount equal to the lesser of (1) the Baseline Value of the corresponding Class B Common Units and (2) the amount received by holders of Class A Common Units in Eureka Midstream Holdings upon the occurrence of the specified event in respect of each Class A Common Unit. Class A Common Units represent all of the common equity interests in Eureka Midstream Holdings other than the profits interests represented by the Class B Common Units.

The Class B Common Units vest in five substantially equal annual installments on each of the first five anniversaries of the date of grant, subject to the Award Recipient’s continued employment, and automatically vest in full upon the occurrence of a liquidity event (as defined in the Eureka Midstream Holdings Plan) (including if the Award Recipient’s employment is terminated by Eureka Midstream Holdings or an affiliate without cause or due to the Award Recipient’s death or disability, in each case, within six months prior to the occurrence of a liquidity event). Subject to the Award Recipient’s continued employment, the Incentive Plan Units become fully vested upon the occurrence of a liquidity event (including if the Award Recipient’s employment is terminated by Eureka Midstream Holdings or an affiliate without cause or due to the Award Recipient’s death or disability, in each case, within six months prior to the occurrence of a liquidity event). If an Award Recipient’s employment is terminated under any other circumstances, all unvested Class B Common Units and Incentive Plan Units will be forfeited immediately upon the Award Recipient’s termination of employment. In addition, vested Class B Common Units will be forfeited if an Award Recipient’s employment is terminated prior to the occurrence of a liquidity event by Eureka Midstream Holdings or an affiliate for cause or due to the Award Recipient’s resignation. If, following a termination of his or her employment by Eureka Midstream Holdings or an affiliate without cause or due to the Award Recipient’s death or disability, an Award Recipient retains vested Class B Common Units, Eureka Midstream Holdings will have the right, but not the obligation, to repurchase such vested Class B Common Units at fair market value.

Payment by Eureka Midstream Holdings in respect of vested Class B Common Units and Incentive Plan Units will become due upon the occurrence of a liquidity event and are expected to be settled in cash upon the occurrence of a liquidity event, except in the case of a qualified public offering (as defined in the Eureka Midstream Holdings Plan), in which case settlement will occur partially in cash and partially in shares of the resulting public entity, with the cash portion not to exceed the amount necessary to cover minimum statutory tax withholdings.

The Class B Common Units and Incentive Plan Units are not classified as equity for accounting purposes and were accounted for in accordance with ASC 718, Compensation - Stock Compensation (“ASC 718”). In accordance with ASC 718, compensation cost is accrued when the performance condition (i.e. the 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 Midstream Holdings and concluded that a liquidity event, as defined, was not probable, and therefore, no compensation cost was recognized in 2014 related to awards of Class B Common Units and Incentive Plan Units.

No awards under the Eureka Midstream Holdings Plan were granted during 2015.

Change in Control Payments

In 2011, the Company approved a change in control program that provides the Company’s executives with certain specified severance payments following a change in control of the Company, provided that the severance occurs either without cause or by the executive for good reason within 24 months following the change in control. The definition of what constitutes a change in control tracks the language of the Company’s Stock Incentive Plan.


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Immediately prior to a change in control, all outstanding equity awards will vest and any performance targets will be deemed to have been met at 100%. This occurs without regard to whether a termination of employment occurs.

For the 24 months following a change in control, an executive who is terminated without cause or who terminates employment for good reason will be entitled to the severance payments. Generally, senior executives, including the NEOs, would receive a severance payment equal to two times base salary plus two times targeted bonus and 24 months of continued medical coverage. The “targeted bonus” is defined as the highest of (1) the maximum bonus opportunity established by the Compensation Committee for the executive or, if the Compensation Committee has not established the executive’s bonus opportunity for the year in which the executive’s termination occurs, 100% of the executive’s base salary, (2) the maximum bonus opportunity established by the Compensation Committee for the executive for the immediately preceding year or (3) the maximum bonus opportunity established by the Compensation Committee for the executive immediately prior to the change in control.

As a condition to receiving severance payments, an executive must sign a release and waiver of claims that includes non-disparagement and confidentiality provisions. In most circumstances, the executive will, by statute, have 21 days to consider the release and seven days following execution of the release where the executive can revoke it. The executive will receive health coverage during this consideration period even if the executive does not ultimately execute the release.

Severance benefits paid to an executive will be reduced to the extent necessary to avoid the imposition of any excise tax associated with parachute payments.

In developing the change in control program, the Compensation Committee engaged the services of Longnecker as compensation consultants. As part of their analysis, Longnecker used the following peer group of companies for benchmarking purposes:

Oasis Petroleum Inc.
Comstock Resources, Inc.
Penn Virginia Corporation
Swift Energy Company
Kodiak Oil & Gas Corp. (which has since been acquired by Whiting Petroleum Corporation)
GeoResources, Inc.
Stone Energy Corporation
Northern Oil & Gas, Inc.
Rex Energy Corporation
Carrizo Oil & Gas, Inc.
Resolute Energy Corporation
Endeavour International Corporation
Gulfport Energy Corporation
Goodrich Petroleum Corporation
GMX Resources, Inc.
In connection with the Company’s bankruptcy proceeding, each of the change in control agreements with our executive officers, including each of our NEOs, was “rejected.” Rejection of a contract is typically treated as a breach occurring as of the moment immediately preceding the Chapter 11 filing. Subject to certain exceptions, this rejection relieves the debtor from performing its future obligations under the contract but entitles the counterparty to assert a pre-petition general unsecured claim for damages. Parties to contracts rejected by a debtor may file proofs of claim against that debtor’s estate for damages.

Employment Agreements

We do not have employment agreements with any of our NEOs or other executive officers.

Risk Assessment

As part of its oversight of the Company’s executive and non-executive compensation programs, the Compensation Committee considers the impact of the Company’s compensation programs, and the incentives created by the compensation awards that it administers, on the Company’s risk profile. In addition, the Company reviews all of its compensation policies and procedures, including the incentives that they create and factors that may reduce the likelihood of excessive risk taking, to determine whether they present a significant risk to the Company. Based on this review, the Company has concluded that its compensation policies and procedures are not reasonably likely to have a material adverse effect on the Company. As a result of this analysis, the Compensation Committee identified the following risk mitigating factors:

•
use of long-term incentive compensation;
•
vesting periods for equity compensation awards that encourage executives and other key employees to focus on sustained stock price appreciation and to provide a long-term retention incentive for our key employees;
•
the Compensation Committee’s discretionary authority to adjust annual incentive awards, which helps mitigate any business risks associated with such awards;

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•
the Company’s internal controls over financial reporting and other financial, operational and compliance policies and practices currently in place;
•
base salaries consistent with executives’ responsibilities so that they are not motivated to take excessive risks to achieve a reasonable level of financial security; and
•
design of long-term compensation to reward executives and other key employees for driving sustainable and/or profitable growth for stockholders.

As a result of the above assessment, the Compensation Committee determined that the Company’s policies and procedures largely achieve a proper balance between competitive compensation and prudent business risk.

Executive Compensation Tables

The following tables include compensation information for our NEOs for the last three years. For a discussion of 2015 NEO compensation, please read the Executive Compensation Discussion and Analysis above.

The 2015 Summary Compensation Table below sets forth compensation information for our NEOs relating to 2015, 2014 and 2013. Pursuant to SEC rules, the 2015 Summary Compensation Table is required to include for a particular fiscal year only those restricted stock awards, stock appreciation rights and options to purchase common stock granted during that year, rather than awards granted after year-end, even if awarded for services in that year. SEC rules require disclosure of cash variable compensation to be included in the year earned, even if payment is made after year-end. Generally, we pay any cash variable compensation for a particular year after the Compensation Committee has had an opportunity to review the Company’s and each individual’s performance for that year. As a result, cash variable compensation reported in the “Bonus” column was paid in the year following the year in which it is reported in the table.
        
2015 Summary Compensation Table
Name and Principal Position
Year
Salary (1)
Bonus (2)
Stock Awards (3), (4)
Option Awards (3)
All Other Compensation (5)
Total
Gary C. Evans
Chairman and CEO
2015
$
510,000

$
—

$
—

$
—

$
467,244

$
977,244

2014
$
505,385

$
442,000

$
4,261,000

$
—

$
148,661

$
5,357,046

2013
$
485,289

$
500,000

$
—

$
1,982,925

$
186,701

$
3,154,915

Joseph C. Daches (6)
Senior V.P. and CFO
2015
$
300,000

$
—

$
—

$
—

$
31,074

$
331,074

2014
$
300,000

$
152,000

$
571,500

$
—

$
31,016

$
1,054,516

2013
$
126,923

$
350,000

$
—

$
1,184,560

$
16,504

$
1,677,987

James W. Denny, III (7)
Executive V.P. and
President, Appalachian
Division
2015
$
210,349

$
—

$
—

$
—

$
116,991

$
327,340

2014
$
318,077

$
265,000

$
1,247,000

$
—

$
57,395

$
1,887,472

2013
$
291,334

$
300,000

$
—

$
660,975

$
88,479

$
1,340,788

H.C. “Kip” Ferguson
Executive V.P. - Exploration
2015
$
275,000

$
—

$
—

$
—

$
31,501

$
306,501

2014
$
275,000

$
160,000

$
680,550

$
—

$
31,630

$
1,147,180

2013
$
275,000

$
200,000

$
—

$
660,975

$
29,234

$
1,165,209

Paul Johnston
Senior V.P. and General Counsel
2015
$
233,192

$
—

$
—

$
—

$
27,857

$
261,049

2014
$
231,538

$
160,000

$
784,550

$
—

$
28,815

$
1,204,903

2013
$
217,172

$
200,000

$
—

$
260,865

$
27,225

$
705,262

Keith Yankowsky (8)     Executive V.P. and Chief Operating Officer
2015
$
123,077

$
—

$
1,540,000

$
—

$
6,082

$
1,669,159

________________________________
(1) 
The amounts reflected in this column show each NEO’s salary earned in the corresponding year.
(2)  
For a discussion of the 2015 executive bonuses, refer to “Executive Compensation Discussion and Analysis - Elements of Compensation - Short-Term Incentives” above. Bonuses for 2014 were paid in March 2015 and were paid 60% in Company common stock and 40% in cash. The bonus reflected for Mr. Daches in 2013 includes a sign-on bonus of $150,000 paid when he joined the Company.

102


(3) 
Represents the aggregate grant date fair value in accordance with ASC 718 (except no assumptions for forfeitures were included). For a discussion of the assumptions made in the valuation of stock and option awards, please refer to “Note 12 - Share-Based Compensation” in the notes to our consolidated financial statements.
(4) 
During the year ended December, 31 2014, Mr. Evans was granted 250,049 Class B Common Units and 250,049 Incentive Plan Units under the Eureka Midstream Holdings Plan. In accordance with ASC 718, the Class B Common Units and Incentive Plan Units had no value on their grant date. As discussed above under “Long-Term Incentives - Eureka Midstream Holdings, LLC Management Incentive Compensation Plan,” the Class B Common Units and Incentive Plan Units were not classified as equity for accounting purposes.
(5) 
Amounts in this column are detailed in the following All Other Compensation Table.
(6) 
Mr. Daches joined the Company on July 22, 2013, with an annualized base salary of $300,000. The amount shown for 2013 reflects the amount paid to Mr. Daches from his hire date through the last payroll period in 2013.
(7) 
Mr. Denny retired from his position as Executive Vice President and President, Appalachian Basin Division, of the Company and as an employee of Triad Hunter, LLC on August 12, 2015.
(8) 
Mr. Yankowsky joined the Company on September 1, 2015, with an annualized base salary of $400,000. The amount shown for 2015 reflects the amount paid to Mr. Yankowsky from his hire date through the last payroll period in 2015.

All Other Compensation Table

The charts and narrative below describe the benefits and perquisites for 2015 contained in the “All Other Compensation” column of the 2015 Summary Compensation Table.

 
401(k) Matching Contribution (1)
Health, Dental, Vision, and Executive Illness Premiums
Life Insurance Premiums
Disability Insurance Premiums
Other
 
Mr. Evans
$
9,275

$
15,332

$
1,332

$
6,836

$
434,469

(2), (3) 
Mr. Daches
$
9,275

$
15,332

$
1,332

$
5,135

$
—

 
Mr. Denny (4)
$
9,275

$
7,287

$
577

$
3,356

$
96,496

(3) 
Mr. Ferguson
$
9,275

$
15,332

$
1,221

$
5,673

$
—

 
Mr. Johnston
$
9,275

$
11,035

$
1,044

$
6,503

$
—

 
Mr. Yankowsky (5)
$
—

$
5,178

$
444

$
460

$
—

 
(1) 
The Company’s “safe harbor” matching contributions to its 401(k) plan for 2015 have not yet been made. The amount of this contribution will change if the Company chooses to make a discretionary matching contribution for 2015.
(2) 
We provide Mr. Evans with memberships to certain private country and city clubs to facilitate business meetings and initiate and strengthen business relationships. Mr. Evans uses one country club for business and non-business purposes. The cost of membership in that club is included in this total.
(3) 
Because of extensive business travel requirements, we make corporate apartments available to certain employees. In 2015, Mr. Evans did not maintain a residence near the Company’s Houston offices and the Company incurred an incremental cost of $60,017 associated with Mr. Evans’ use of a Houston apartment along with other executives who also reside at the same premises. In 2015, Mr. Denny used a corporate apartment near the Company’s operations in Marietta, Ohio with incremental costs to the Company of $9,724. We also provide vehicles at various locations. The amount shown for Mr. Evans includes the incremental cost of Mr. Evans’ use of Company vehicles.
(4) 
Mr. Denny retired from his position as Executive Vice President and President, Appalachian Basin Division, of the Company and as an employee of Triad Hunter, LLC on August 12, 2015.
(5) 
Mr. Yankowsky joined the Company on September 1, 2015.


103


2015 Grants of Plan-Based Awards

The following table sets forth plan-based awards made in 2015. Each of our NEOs was granted restricted shares of the Company’s common stock. The restrictions on the shares lapse over a 3-year period with restrictions lapsing on 33% of the restricted shares one year from the date of the grant. These restricted shares will be canceled upon the Company’s emergence from bankruptcy.
 
Grant Date
Number of Restricted Shares
Grant Date Fair Value of Restricted Shares
Mr. Evans
3/30/2015
104,823

$
265,202

Mr. Daches
3/30/2015
36,048

$
91,201

Mr. Denny (1)
3/30/2015
56,918

$
144,003

Mr. Ferguson
3/30/2015
37,945

$
96,001

Mr. Johnston
3/30/2015
37,945

$
96,001

Mr. Yankowsky (2)
9/1/2015
2,000,000

$
1,540,000

________________________________
(1) 
Mr. Denny retired from his position as Executive Vice President and President, Appalachian Basin Division, of the Company and as an employee of Triad Hunter, LLC on August 12, 2015.
(2) 
Mr. Yankowsky joined the Company on September 1, 2015.

2015 Outstanding Equity Awards at Year-End

The following table identifies the outstanding equity-based awards held by the NEOs as of December 31, 2015. For all unvested awards, continued employment through the vesting date is required. These outstanding equity-based awards will be canceled upon the Company’s emergence from bankruptcy.

 
Option and Stock Appreciation Right Awards
Stock Awards (4)
 
Award Year
Number of Securities Underlying Unexercised Options/SARs (Exercisable)
Number of Securities Underlying Unexercised Options/SARs
(Unexercisable)
Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned SARs
Option Exercise Price/ SAR Base Price
Option Expiration Date
Number of Shares of Stock That Have Not Vested
Market Value of Shares of Stock That Have Not Vested
Mr. Evans
2014
—
 
—
—
—
—
367,650 (2)
$7,353
2013
562,500
 
187,500 (1)
—
$4.16
1/17/2023
—
—
2012
750,000
 
—
—
$6.08
4/13/2022
—
—
2011
601,250
 
—
—
$7.95
5/2/2021
—
—
Mr. Daches
2014
—
 
—
—
—
—
50,165 (2)
$1,003
2013
—
 
100,000 (1)
—
$3.82
7/26/2023
—
—
Mr. Ferguson
2014
—
 
—
—
—
—
60,215 (2)
$1,204
2013
187,500
 
62,500 (1)
—
$4.16
1/17/2023
—
—
2012
250,000
 
—
—
$6.08
4/13/2022
—
—
2011
231,250
 
—
—
$7.95
5/2/2021
—
—
2010
70,000
 
—
—
$2.25
2/11/2020
—
—
Mr. Johnston
2014
—
 
—
—
—
—
68,547 (2)
$1,371
2013
112,500
 
37,500 (1)
—
$4.16
1/17/2023
—
—
2012
125,000
 
—
—
$6.08
4/13/2022
—
—
2011
138,750
 
—
—
$7.95
5/2/2021
—
—
2010
125,000
 
—
—
$4.56
8/3/2020
—
—
Mr. Yankowsky (5)
2015
—
 
—
—
—
—
2,000,000 (3)
40,000
(1)
All 2013, 2012, and 2011 grants featured 25% immediate vesting and 25% additional vesting on the first three anniversaries of the grant dates, which were January 17, 2013, April 13, 2012, and May 2, 2011, respectively.

104


(2) 
The restrictions on the shares from the 2014 grants lapse over a 3-year period with restrictions lapsing on 33% of the restricted shares one year from the date of the grant. During December 2014 the Compensation Committee modified the November 2014 restricted stock grant. The modification was to fully accelerate the lapse of restrictions on the third tranche of the award which originally would have occurred on November 6, 2017. Under the modified terms, the restrictions lapsed with respect to the first two tranches of the stock award on December 19, 2014 and November 6, 2015, and the remaining restrictions will lapse on November 6, 2016.
(3) 
The restrictions on the shares granted to Mr. Yankowsky lapse in three equal installments. The restrictions on one-third of the restricted shares lapse on March 31, 2016, and the restrictions on the remaining two installments lapse on September 1, 2017 and September 1, 2018, respectively.
(4) 
Mr. Evans holds awards in the form of profits interests at Eureka Midstream Holdings that are not included in this table but that are discussed in footnote (4) to the 2015 Summary Compensation Table above. As a result of the Company’s reduction in equity interest in Eureka Midstream Holdings and the subsequent deconsolidation of Eureka Midstream Holdings, which occurred on December 18, 2014, the Company had no obligation associated with the Eureka Midstream Holdings Plan as of December 31, 2014 or December 31, 2015.
(5) 
Mr. Yankowsky joined the Company on September 1, 2015.

2015 Option Exercises and Stock Vested

The following table summarizes the options exercised and restricted stock vested in 2015 for our NEOs. For awards of Company stock that vested in 2015, the value that the NEO realized on the date the restrictions on the award lapsed is provided.

 
 
Option Awards
Stock Awards
 
Grant Date
Number of Shares
Acquired on Exercise
Value Realized
on Exercise
Number of Shares
With Lapse of Restrictions
Value Realized
on Lapse of Restrictions
Mr. Evans
3/30/2015
—

$
—

104,823

$
276,733

11/6/2014
—

$
—

166,650

$
46,662

1/8/2014
—

$
—

99,000

$
289,080

Mr. Daches
3/30/2015
—

$
—

36,048

$
95,167

11/6/2014
—

$
—

16,665

$
4,666

1/8/2014
—

$
—

16,500

$
48,180

Mr. Denny (1)
3/30/2015
—

$
—

56,918

$
150,264

1/8/2014
—

$
—

33,000

$
96,360

Mr. Ferguson
3/30/2015
—

$
—

37,945

$
100,175

11/6/2014
—

$
—

16,665

$
6,999

1/8/2014
—

$
—

21,450

$
62,634

Mr. Johnston
3/30/2015
—

$
—

37,945

$
100,175

11/6/2014
—

$
—

24,997

$
6,999

1/8/2014
—

$
—

21,450

$
62,634

________________________________
(1) 
Mr. Denny retired from his position as Executive Vice President and President, Appalachian Basin Division, of the Company and as an employee of Triad Hunter, LLC on August 12, 2015.

Potential Payments Upon Termination or Change in Control

In connection with the Company’s bankruptcy proceeding, each of the change in control agreements with our executive officers, including each of our NEOs, was “rejected.” Rejection of a contract is typically treated as a breach occurring as of the moment immediately preceding the Chapter 11 filing. Subject to certain exceptions, this rejection relieves the debtor from performing its future obligations under the contract but entitles the counterparty to assert a pre-petition general unsecured claim for damages. Parties to contracts rejected by a debtor may file proofs of claim against that debtor’s estate for damages.

105



The following table identifies the payments that would have been required to be made to our NEOs following a change in control of the Company. For a detailed discussion of these payments, please see the Executive Compensation Discussion and Analysis above. These calculations assume a change in control of the Company on December 31, 2015, and a closing stock price on that date of $0.02.
 
Cash (1)
 
Equity (2)
Perquisites / Benefits (3)
Total
Mr. Evans
$
2,040,000

(4) 
$
7,353

$
45,532

$
2,092,885

Mr. Daches
$
1,200,000

(5) 
$
1,003

$
39,289

$
1,240,292

Mr. Ferguson
$
1,100,000

(6) 
$
1,204

$
44,794

$
1,145,998

Mr. Johnston
$
940,000

(7) 
$
1,371

$
30,712

$
972,083

Mr. Yankowsky (9)
$
1,600,000

(8) 
$
40,000

$
45,177

$
1,685,177

(1)
Cash compensation is subject to each NEO’s severance from employment without cause or by the NEO with good reason within 24 months following a change in control.
(2) 
The 2015 Outstanding Equity Awards at Year-End table details the unvested awards that would have been subject to accelerated vesting on December 31, 2015. All outstanding equity awards are immediately vested upon a change in control.
(3) 
The benefits identified in the third column consist of 24 months of continued Company contributions towards the cost of coverage for medical, dental and vision plans. The amounts were calculated by taking each NEO’s actual coverage elections for 2015 and assuming that the cost of coverage would not change in 2016. Accordingly, these amounts are only estimates.
(4) 
This consists of 2x base salary of $510,000 plus 2x targeted bonus with the bonus set at 100% of base salary.
(5) 
This consists of 2x base salary of $300,000 plus 2x targeted bonus with the bonus set at 100% of base salary.
(6)
This consists of 2x base salary of $275,000 plus 2x targeted bonus with the bonus set at 100% of base salary.
(7)
This consists of 2x base salary of $235,000 plus 2x targeted bonus with the bonus set at 100% of base salary.
(8)
This consists of 2x base salary of $400,000 plus 2x targeted bonus with the bonus set at 100% of base salary.
(9)
Mr. Yankowsky joined the Company on September 1, 2015.

We are not obligated to make any payments to any of our NEOs upon a termination of the NEO’s employment, except as described above in connection with a change in control. Upon termination of employment, other than in connection with a change in control, for any reason, including by reason of death or disability and with or without cause, all unvested options and restricted stock awards will be terminated and forfeited. Vested options may be exercised for a period of six months after termination by reason of death or disability and for a period of three months after termination for any other reason or, in either case, until the earlier expiration of the options.

Unvested Eureka Midstream Holdings Class B Common Units and Incentive Plan Units vest in full automatically upon the occurrence of a liquidity event (as defined in the Eureka Midstream Holdings Plan) if the award recipient continues to be employed by Eureka Midstream Holdings or an affiliate at the time of the liquidity event or if the award recipient’s employment was terminated by Eureka Midstream Holdings or an affiliate without cause or due to the award recipient’s death or disability, in each case, within six months prior to the occurrence of the liquidity event.

Compensation Committee Interlocks and Insider Participation

Only one of our directors, Gary C. Evans, also serves as an executive officer of Magnum Hunter. Mr. Evans does not serve on any of our standing committees, and no other member of our Board is employed by Magnum Hunter or its subsidiaries.

Mr. Evans also serves as Chairman of the board of directors of GreenHunter and is a major stockholder of GreenHunter. In addition, Mr. Evans currently serves as the interim Chief Executive Officer of GreenHunter. Other than as described above, none of our executive officers serves on the board of directors of another entity whose executive officers serve on our Board. No officer or employee of Magnum Hunter, other than Mr. Evans, participated in the deliberations of our Board or our Compensation Committee concerning executive officer or director compensation.

106



Compensation Committee Report

Our Compensation Committee reviewed the Executive Compensation Discussion and Analysis, or CD&A, as prepared by management of the Company, and discussed the CD&A with the Company’s management. Based on the Committee’s review and discussions, the Committee recommended to the Board that the CD&A be included in this annual report.

The Compensation Committee
Joe L. McClaugherty, Chair
Stephen C. Hurley
Jeff Swanson

Item 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth information regarding beneficial ownership of Magnum Hunter’s common stock and preferred stock as of April 15, 2016 held by (i) each of our current directors and our named executive officers; (ii) all current directors and our executive officers as a group; and (iii) any person (or group) who is known to us to be the beneficial owner of more than 5% of any class of our stock. Beneficial ownership is determined in accordance with Rule 13d-3 under the Exchange Act and, except as otherwise indicated, the respective holders have sole voting and investment power over such shares. To our knowledge, there are no single holders of 5% or more of any series of our preferred stock.

Unless otherwise specified, the address of each of the persons set forth below is in care of Magnum Hunter Resources Corporation, 909 Lake Carolyn Parkway, Suite 600, Irving, Texas 75039.

Title of Class
Name of Beneficial Owner
Amount and Nature of Beneficial Ownership (1)
Percent of Class (%)
Common Stock
Gary C. Evans (a)
5,881,829

 
2.24%
Common Stock
Joseph C. Daches (b)
587,416

 
*
Common Stock
H.C. “Kip” Ferguson, III (c)
1,087,084

 
*
Common Stock
Paul M. Johnston (d)
709,835

 
*
Common Stock
Keith Yankowsky (e)
1,333,334

 
*
Common Stock
Victor G. Carrillo (f)
469,073

 
*
Common Stock
Stephen C. Hurley (g)
488,921

 
*
Common Stock
Joe L. McClaugherty (h)
1,363,714

 
*
Common Stock
Jeff Swanson (i)
538,091

 
*
Common Stock
State Street Corporation (j)
21,741,193

 
8.35%
Common Stock
Directors and executive officers as a group (10 persons)
13,223,686

 
4.98%
 
 
 
 
Series C Preferred Stock
Gruss Capital Management LP (k)
430,000

 
10.75%
Series C Preferred Stock
Directors and executive officers as a group
—

 
—
 
 
 
 
Series D Preferred Stock
Gruss Capital Management LP (l)
365,000

 
8.25%
Series D Preferred Stock
Directors and executive officers as a group (1 person named above)
—

 
—
 
 
 
 
Series E Preferred Stock (represented by depositary shares)
Directors and executive officers as a group
—
—
        
*Less than 1%.

107


(1) Each beneficial owner has sole voting and investment power with respect to all shares, unless otherwise indicated below.
(a) Includes 268,650 shares of restricted common stock; 52,022 shares of common stock held in Mr. Evans' individual retirement account; 35,000 shares of common stock held by Investment Hunter, LLC, a company wholly owned by Mr. Evans; 1,500 shares of common stock held by Mr. Evans' daughter; an option to purchase 2,101,250 shares of common stock; and an indirect interest in 35,271 shares of common stock held by the Company's 401(k) plan.
(b) Includes 50,330 shares of restricted common stock and an indirect interest in 25,874 shares of common stock held by the Company's 401(k) plan.
(c) Includes 55,430 shares of restricted common stock; an option to purchase 801,250 shares of common stock which has vested; and an indirect interest in 35,271 shares of common stock held by the Company's 401(k) plan.
(d) Includes 55,430 shares of restricted common stock; an option to purchase 538,750 shares of common stock which has vested; and an indirect interest in 35,271 shares of common stock held by the Company's 401(k) plan.
(e) Includes 1,333,334 shares of restricted common stock.
(f) Includes 150,000 shares of restricted common stock and an option to purchase 175,000 shares of common stock.
(g) Includes 150,000 shares of restricted common stock and an option to purchase 136,000 shares of common stock.
(h) Includes 150,000 shares of restricted common stock; an option to purchase 140,000 shares of common stock; an indirect interest in 43,000 shares of common stock held by Mr. McClaugherty's 401(k) plan; and an indirect interest in 9,000 shares of common stock held in a custodial account for Mr. McClaugherty's children.
(i) Includes 150,000 shares of restricted common stock and an option to purchase 175,000 shares of common stock.
(j) Includes sole voting and shared dispositive power over 21,741,193 shares of common stock. State Street Corporation's principal business office address is One Lincoln Street, Boston, Massachusets 02111. Information relating to this reporting stockholder is based on the stockholder's Schedule 13G/A filed with the SEC on August 10, 2015.
(k) Includes sole and shared dispositive voting power over 430,000 shares of Series C Preferred Stock. Gruss Capital Management LP's principal business office address is 510 Madison Avenue, 16th Floor, New York, New York 10022. Information relating to this reporting stockholder is based on the stockholder's Form 3 filed with the SEC on April 7, 2016.
(l) Includes sole and shared dispositive voting power over 365,000 shares of Series D Preferred Stock. Gruss Capital Management LP’s principal business office address is 510 Madison Avenue, 16th Floor, New York, New York 10022. Information relating to this reporting stockholder is based on the stockholder's Form 3 filed with the SEC on April 7, 2016.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Under SEC rules, public companies, such as Magnum Hunter, must disclose certain “Related Person Transactions.” These are transactions in which the Company is a participant; the amount involved exceeds $120,000; and a director, executive officer or holder of more than 5% of our common stock has a direct or indirect material interest.

Review, Approval or Ratification of Transactions with Related Persons

Our Governance Committee charter requires, among other things, that (i) our Governance Committee will be comprised exclusively of members of our Board who satisfy the independence requirements of the NYSE and (ii) our Governance Committee is responsible for approving all related party transactions, as defined by the rules of the SEC, to which we are a party. In February 2014 we adopted a related party transactions policy to assist us in identifying related parties under applicable rules and potential related party transactions. The Governance Committee’s review procedures under this policy include evaluating the following:

•
Whether the terms of the related party transaction are fair to the Company and on the same basis as would apply if the transaction did not involve a related party;
•
Whether there are business reasons for the Company to enter into the related party transaction;
•
Whether the related party transaction would impair the independence of an outside director; and
•
Whether the related party transaction would present an improper conflict of interest for any director or executive officer of the Company, taking into account the size of the transaction, the overall financial position of the director, executive officer, or related party, and the nature of the director’s, executive officer’s, or related party’s interest in the transaction and the ongoing nature of any proposed relationship, and any other factors the Governance Committee deems relevant.

Additionally, in cases of transactions in which a director or executive officer may have an interest, the Governance Committee also evaluates the effect of the transaction on such individual’s willingness or ability to properly perform his or her duties at Magnum Hunter.

108



Certain Relationships and Related Transactions

See “Note 17 - Related Party Transactions” in the notes to our consolidated financial statements for information regarding transactions with related persons.

Director Independence

In accordance with applicable SEC rules and guidelines, our Board and our Governance Committee assess the independence of its members from time to time. Applying the applicable SEC rules for independence, our Board, upon the recommendation of our Governance Committee, determined that Messrs. Victor G. Carrillo, Stephen C. Hurley, Joe L. McClaugherty, and Jeff Swanson are independent directors.

Our Audit, Compensation and Governance Committees are each required to be composed solely of independent directors. The standards for Audit Committee membership include additional requirements under rules of the SEC. The Board has determined that all of the members of our Audit, Compensation and Governance Committees meet the applicable independence requirements.

Item 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES

Aggregate fees for professional services rendered by BDO USA, LLP for the fiscal years ended December 31, 2015 and 2014 are set forth below.
 
2015
 
2014
 
(In thousands)
Audit Fees
$
1,925

 
$
2,337

Audit Related Fees
41

 
28

Total Fees
$
1,966

 
$
2,365


Audit Fees

The audit fees for the years ended December 31, 2015 and 2014 were for professional services rendered by BDO USA, LLP. Audit fees relate to professional services rendered in connection with the audits of the Company’s consolidated annual financial statements and internal control over financial reporting, quarterly reviews of consolidated financial statements included in the Company’s Quarterly Reports on Form 10-Q and audit services provided in connection with other statutory and regulatory filings, including the filing of registration statements and audited and reviewed financial statements filed on certain Current Reports on Form 8-K. Also included in audit fees are assurance and related services that are traditionally performed by the independent auditor, including consultation regarding accounting and reporting matters and the issuance of comfort letters in connection with offerings by Magnum Hunter of common stock and preferred stock.

Audit Related Fees

Audit related fees for the year ended December 31, 2015 and 2014 included fees for professional services rendered by BDO USA, LLP in connection with their audit of the Company’s employee benefit plan.

Audit Committee Pre-Approval Policy

The Audit Committee is responsible for appointing, setting the compensation for and overseeing the work of Magnum Hunter’s independent auditor. In recognition of this responsibility, the Audit Committee is required to approve all audit and non-audit services performed by the Company’s independent registered public accounting firm in order to assure that the provision of these services does not impair the independent auditor’s independence; except that the Chairman of the Audit Committee has discretion to unilaterally engage accounting professionals previously approved by the Audit Committee to perform additional services,provided that the cost of such services does not exceed certain predetermined amounts. For 2015, the cost of pre-approved services could not exceed $15,000. The Chairman of the Audit Committee must report any such engagement at the next Audit Committee meeting.

The Audit Committee specifically approved all audit and non-audit services performed by our independent accountants in 2015.

109


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, 2015 and 2014
F-3
Consolidated Statements of Operations for the years ended December 31, 2015, 2014, and 2013
F-5
Consolidated Statements of Comprehensive Loss for the years ended December 31, 2015, 2014, and 2013
F-6
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2015, 2014, and 2013
F-7
Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014, and 2013
F-9
Notes to the Consolidated Financial Statements
F-10
        
2.
Financial Statement Schedules: Except for the consolidated financial statements of Eureka Midstream Holdings, LLC listed below, all financial statement schedules are omitted as inapplicable or because the required information is contained in the financial statements or the notes thereto.

The following consolidated financial statements of Eureka Midstream Holdings, LLC required by Rule 3-09 of Regulation S-X are provided as Exhibit 99.2 to this Amendment:
        
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2015 and 2014
Consolidated Statements of Operations for the years ended December 31, 2015 and 2014
Consolidated Statements of Changes in Members’ Equity (Deficit) for the years ended December 31, 2015 and 2014
Consolidated Statements of Cash Flows for the years ended December 31, 2015 and 2014
Notes to Consolidated Financial Statements


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.


110




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: May 6, 2016

Signature
Title
Date
 
 
 
/s/ Gary C. Evans
Chairman of the Board and
May 6, 2016
Gary C. Evans
Chief Executive Officer
(Principal Executive Officer)
 
 
 
 
/s/ Joseph C. Daches
Senior Vice President,
May 6, 2016
Joseph C. Daches
Chief Financial Officer
(Principal Financial Officer and Principal Accounting Officer)
 
 
 
 
/s/ Victor G. Carrillo
Director
May 6, 2016
Victor G. Carrillo
 
 
 
 
 
/s/ Stephen C. Hurley
Director
May 6, 2016
Stephen C. Hurley
 
 
 
 
 
/s/ Joe L. McClaugherty
Lead Director
May 6, 2016
Joe L. McClaugherty
 
 
 
 
 
/s/ Jeff Swanson
Director
May 6, 2016
Jeff Swanson
 
 

112


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).
 
 
 
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).
 
 
 

113


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).
 
 
 
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).
 
 
 
2.14.2+
 
Letter Agreement, dated March 30, 2015, 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 April 3, 2015).
 
 
 
2.14.3+
 
Letter Agreement, dated July 27, 2015, 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 July 28, 2015).
 
 
 
2.14.4
 
Letter Agreement, dated November 19, 2015, by and among North Haven Infrastructure Partners II Buffalo Holdings LLC, Triad Hunter, LLC and the Registrant (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on November 20, 2015).
 
 
 
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).
 
 
 
2.17+
 
Purchase and Sale Agreement, dated May 22, 2015, by and between Triad Hunter, LLC and Antero Resources Corporation (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on May 29, 2015).
 
 
 
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).
 
 
 

114


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).
 
 
 
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 (incorporated by reference from the Registrant’s Annual Report on Form 10-K filed on March 2, 2015).
 
 
 
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 (incorporated by reference from the Registrant’s Annual Report on Form 10-K filed on March 2, 2015).
 
 
 
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 (incorporated by reference from the Registrant’s Annual Report on Form 10-K filed on March 2, 2015).
 
 
 

115


4.4.8
 
Eighth Supplemental Indenture, dated November 13, 2015, by and among the Registrant, the guarantors party thereto, Wilmington Trust, National Association, as trustee, and Citibank, N.A., as paying agent, registrar and authenticating agent (incorporated by reference to the Registrant’s Current Report on Form 8-K filed on November 16, 2015).
 
 
 
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).
 
 
 
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).

116


 
 
 
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 (incorporated by reference from the Registrant’s Annual Report on Form 10-K filed on March 2, 2015).
 
 
 
10.17.2
 
Second Amendment to Credit Agreement and Limited Waiver, dated April 17, 2015, by and among the Registrant, as borrower, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on April 20, 2015).
 
 
 
10.17.3
 
Third Amendment to Credit Agreement and Limited Consent, dated May 28, 2015, by and among the Registrant, as borrower, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on May 29, 2015).
 
 
 
10.17.4
 
Fourth Amendment to Credit Agreement and Limited Consent, dated June 19, 2015, by and among the Registrant, as borrower, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on June 24, 2015).
 
 
 
10.17.5
 
Fifth Amendment to Credit Agreement and Limited Waiver, dated July 10, 2015, by and among the Registrant, as borrower, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on July 16, 2015).
 
 
 
10.17.6
 
Sixth Amendment to Credit Agreement, dated as of November 3, 2015, by and among the Registrant, as borrower, the lenders and guarantors party thereto, and Bank of Montreal, as administrative agent (incorporated by reference from the Registrant's Current Report on Form 8-K filed on November 5, 2015).
 
 
 
10.17.7
 
Seventh Amendment to Credit Agreement and Increase Joinder, effective as of November 30, 2015, by and among the Registrant, as borrower, the lenders and guarantors party thereto, Bank of Montreal, as administrative agent, and Cantor Fitzgerald Securities, as loan administrator (incorporated by reference from the Registrant's Current Report on Form 8-K filed on December 2, 2015).
 
 
 

117


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).
 
 
 
10.18.1
 
First Amendment to Credit Agreement and Limited Waiver, dated April 17, 2015, by and among the Registrant, as borrower, Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent, and the several lenders and guarantors party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on April 20, 2015).
 
 
 
10.18.2
 
Forbearance Agreement and Second Amendment, dated as of November 3, 2015, by and among the Registrant, as borrower, Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent, the lenders party thereto and the agents party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on November 5, 2015).
 
 
 
10.19*
 
Letter Agreement, dated January 29, 2015, by and between the Registrant and R. Glenn Dawson (incorporated by reference from the Registrant’s Annual Report on Form 10-K filed on March 2, 2015).
 
 
 
10.20*
 
Release and Confidentiality Agreement, dated January 29, 2015, by and between the Registrant and R. Glenn Dawson (incorporated by reference from the Registrant’s Annual Report on Form 10-K filed on March 2, 2015).
 
 
 
10.21*
 
Restricted Stock Award Agreement, entered into on September 11, 2015, by and between the Registrant and Keith Yankowsky (incorporated by reference from the Registrant’s Quarterly Report on Form 10-Q filed on November 9, 2015).
 
 
 
10.22*
 
Letter agreement, effective September 7, 2015, by and between the Registrant and James W. Denny, III (incorporated by reference from the Registrant’s Quarterly Report on Form 10-Q filed on November 9, 2015).
 
 
 
10.23
 
Forbearance Agreement, dated as of November 3, 2015, by and among the Registrant and certain holders of the Registrant’s unsecured bonds party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on November 5, 2015).
 
 
 
10.24
 
Restructuring Support Agreement, dated as of December 15, 2015, by and among the Registrant and the supporting parties thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on December 15, 2015).
 
 
 
10.24.1
 
First Amendment to Restructuring Support Agreement, dated as of February 25, 2016, by and among the Registrant and the supporting parties thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on March 2, 2016).
 
 
 
10.24.2#
 
Second Amendment to Restructuring Support Agreement, dated as of April 1, 2016, by and among the Registrant and the supporting parties thereto.
 
 
 
10.24.3
 
Third Amendment to Restructuring Support Agreement, dated as of April 13, 2016, by and among the Registrant and the supporting parties thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on April 18, 2016).
 
 
 
10.24.4#
 
Fourth Amendment to Restructuring Support Agreement, dated as of May 5, 2016, by and among the Registrant and the supporting parties thereto.
 
 
 
10.25
 
Debtor in Possession Credit Agreement, dated as of December 17, 2015, by and among the Registrant and the lenders party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on December 21, 2015).
 
 
 
10.25.1#
 
Second Amendment to Debtor in Possession Credit Agreement, dated as of February 12, 2016, by and among the Registrant, the lenders party thereto and Cantor Fitzgerald Securities, as administrative agent and collateral agent.
 
 
 
10.25.2#
 
Third Amendment to Debtor in Possession Credit Agreement, dated as of April 1, 2016, by and among the Registrant, the lenders party thereto and Cantor Fitzgerald Securities, as administrative agent and collateral agent.
 
 
 

118


10.25.3
 
Fourth Amendment to Debtor in Possession Credit Agreement, dated as of April 8, 2016, by and among the Registrant, the lenders party thereto and Cantor Fitzgerald Securities, as administrative agent and collateral agent (incorporated by reference from the Registrant's Current Report on Form 8-K filed on April 18, 2016).
 
 
 
10.25.4#
 
Fifth Amendment to Debtor in Possession Credit Agreement, dated as of May 4, 2016, by and among the Registrant, the lenders party thereto and Cantor Fitzgerald Securities, as administrative agent and collateral agent.
 
 
 
12.1#
 
Computation of Ratio of Earnings to Fixed Charges.
 
 
 
21.1#
 
List of Subsidiaries.
 
 
 
23.1#
 
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, 2015 prepared by Cawley Gillespie & Associates, Inc.
 
 
 
99.2#
 
Consolidated financial statements of Eureka Hunter Holdings, LLC as of and for the years ended December 31, 2015 and 2014.
 
 
 
99.3
 
Syndication Procedures, dated December 21, 2015 (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on December 21, 2015).
 
 
 
99.4
 
Order Instituting Cease-and-Desist Proceedings Pursuant to Section 21C of the Securities Exchange Act of 1934, Making Findings, and Imposing a Cease-and-Desist Order, dated March 10, 2016 (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on April 4, 2016).
 
 
 
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.


119


*
 
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.

120