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

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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

43



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:


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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.

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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

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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