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TABLE OF CONTENTS
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

Commission File Number: 001-35467

Halcón Resources Corporation
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
  20-0700684
(I.R.S. Employer
Identification Number)

1000 Louisiana Street, Suite 6700, Houston, TX 77002
(Address of principal executive offices)

(832) 538-0300
(Registrant's telephone number)

        Securities registered pursuant to Section 12(b) of the Act:

Title of each class   Name of each exchange on which registered
Common Stock, par value $.0001 per share   New York Stock Exchange

        Securities registered pursuant to 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 o    No ý

        Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý

        Indicate by check mark whether 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 preceding 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 ý    No o

        Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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. o

        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 definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ý   Accelerated filer o   Non-accelerated filer o
(Do not check if a
smaller reporting company)
  Smaller reporting company o

        Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o    No ý

        As of February 23, 2015, there were 428,086,266 shares outstanding of registrant's $.0001 par value common stock. Based upon the closing price for the registrant's common stock on the New York Stock Exchange as of June 30, 2014, the aggregate market value of shares of common stock held by non-affiliates of the registrant was approximately $1.8 billion.

DOCUMENTS INCORPORATED BY REFERENCE

        Information required by Part III, Items 10, 11, 12, 13, and 14, is incorporated by reference to portions of the registrant's definitive proxy statement for its 2014 annual meeting of stockholders which will be filed no later than 120 days after December 31, 2014.


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TABLE OF CONTENTS

 
   
  PAGE  

PART I

 

 

       

ITEM 1.

 

Business

    6  

ITEM 1A.

 

Risk factors

    24  

ITEM 1B.

 

Unresolved staff comments

    41  

ITEM 2.

 

Properties

    41  

ITEM 3.

 

Legal proceedings

    41  

ITEM 4.

 

Mine safety disclosures

    42  

PART II

 

 

       

ITEM 5.

 

Market for registrant's common equity, related stockholder matters and issuer purchases of equity securities

    43  

ITEM 6.

 

Selected financial data

    45  

ITEM 7.

 

Management's discussion and analysis of financial condition and results of operations

    46  

ITEM 7A.

 

Quantitative and qualitative disclosures about market risk

    70  

ITEM 8.

 

Consolidated financial statements and supplementary data

    72  

ITEM 9.

 

Changes in and disagreements with accountants on accounting and financial disclosure

    150  

ITEM 9A.

 

Controls and procedures

    151  

ITEM 9B.

 

Other information

    151  

PART III

 

 

       

ITEM 10.

 

Directors, executive officers and corporate governance

    152  

ITEM 11.

 

Executive compensation

    152  

ITEM 12.

 

Security ownership of certain beneficial owners and management and related stockholder matters

    152  

ITEM 13.

 

Certain relationships and related transactions, and director independence

    153  

ITEM 14.

 

Principal accountant fees and services

    153  

PART IV

 

 

       

ITEM 15.

 

Exhibits and financial statements schedules

    154  

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Special note regarding forward-looking statements

        This Annual Report on Form 10-K contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number and location of wells to be drilled in the future, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "objective," "believe," "predict," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could" and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the "Risk Factors" section of this report and other sections of this report which describe factors that could cause our actual results to differ from those anticipated in forward-looking statements, including, but not limited to, the following factors:

    volatility in commodity prices for oil and natural gas, including continued declines in the price for oil;

    our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations and fully develop our undeveloped acreage positions;

    we have substantial indebtedness and may incur more debt; higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business;

    our ability to replace our oil and natural gas reserves;

    our ability to successfully integrate acquired oil and natural gas businesses and operations;

    the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and may divert management's time and energy, which could have an adverse effect on our financial position, results of operations, or cash flows;

    risks in connection with potential acquisitions and the integration of any such potential significant acquisitions;

    our ability to successfully develop our large inventory of undeveloped acreage in our resource plays;

    access to and availability of water and other treatment materials to carry out planned fracture stimulations in our resource plays;

    access to adequate gathering systems, processing facilities, transportation take-away capacity to move our production to market and marketing outlets to sell our production at market prices, which is necessary to fully execute our capital program;

    the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

    contractual limitations that affect our management's discretion in managing our business, including covenants that, among other things, limit our ability to incur debt, make investments and pay cash dividends;

    the potential for production decline rates for our wells to be greater than we expect;

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    our ability to retain key members of senior management, board of directors members, and key technical employees;

    competition, including competition for acreage in resource play holdings;

    environmental risks;

    drilling and operating risks;

    exploration and development risks;

    the possibility that the industry may be subject to future regulatory or legislative actions (including additional taxes and changes in environmental regulations);

    general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including the possibility that economic conditions in the United States will worsen and that capital markets are disrupted, which could adversely affect demand for oil and natural gas and make it difficult to access capital;

    social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as the Middle East, and armed conflict or acts of terrorism or sabotage;

    other economic, competitive, governmental, regulatory, legislative, including federal, state and tribal regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices;

    the insurance coverage maintained by us may not adequately cover all losses that may be sustained in connection with our business activities;

    title to the properties in which we have an interest may be impaired by title defects;

    senior management's ability to execute our plans to meet our goals;

    the cost and availability of goods and services, such as drilling rigs, fracture stimulation services and tubulars; and

    our dependency on the skill, ability and decisions of third party operators of the oil and natural gas properties in which we have a non-operated working interest.

        All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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Glossary of Oil and Natural Gas Terms

        The definitions set forth below apply to the indicated terms as used in this report. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

        Bbl.    One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

        Bcf.    One billion cubic feet of natural gas.

        Boe.    Barrels of oil equivalent in which six Mcf of natural gas equals one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

        Boe/d.    Barrels of oil equivalent per day.

        Btu.    British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

        Completion.    The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

        Developed property.    Property where wells have been drilled and production equipment has been installed.

        Development well.    A well drilled within the proved areas of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

        Dry hole or well.    A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

        Extension well.    A well drilled to extend the limits of a known reservoir.

        Exploratory well.    A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

        Field.    An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

        Gross acres or gross wells.    The total acres or wells, as the case may be, in which a working interest is owned.

        Hydraulic fracturing.    The injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production.

        MBbls.    One thousand barrels of crude oil or other liquid hydrocarbons.

        MBoe.    One thousand Boe.

        MMBoe.    One million Boe.

        Mcf.    One thousand cubic feet of natural gas.

        MMBbls.    One million barrels of crude oil or other liquid hydrocarbons.

        MMBtu.    One million Btu.

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        MMcf.    One million cubic feet of natural gas.

        Net acres or net wells.    The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

        Operator.    The individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease.

        Productive well.    A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

        Proved developed producing reserves.    Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production.

        Proved developed reserves.    Proved reserves that are expected to be recovered from existing wellbores, whether or not currently producing, without drilling additional wells. Production of such reserves may require a recompletion.

        Proved reserves.    Those quantities of oil and natural 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 estimation.

        Proved undeveloped location.    A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

        Proved undeveloped reserves.    Proved 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.

        Recompletion.    The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.

        Reserve-to-production ratio or Reserve life.    A ratio determined by dividing our estimated existing reserves determined as of the stated measurement date by production from such reserves for the prior twelve month period.

        Reservoir.    A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

        Spud.    Commencement of actual drilling operations.

        3-D seismic.    The method by which a three dimensional image of the earth's subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, exploitation and production.

        Undeveloped acreage.    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 contains proved reserves.

        Working interest.    The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

        Workover.    Operations on a producing well to restore or increase production.

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PART I

ITEM 1.    BUSINESS

Overview

        Unless the context otherwise requires, all references in this report to "Halcón," "our," "us," and "we" refer to Halcón Resources Corporation (formerly known as RAM Energy Resources, Inc.) and its subsidiaries, as a common entity.

        We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. We were incorporated in Delaware on February 5, 2004 and were recapitalized on February 8, 2012, as described more fully herein. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in selected prospect areas, providing us with an extensive drilling inventory in multiple basins that we believe allow for multiple years of production growth and broad flexibility to direct our capital resources to projects with the greatest potential returns. During 2013 and 2014, we focused on the development of acquired properties and also divested non-core assets in order to fund activities in our core resource plays.

        At December 31, 2014, our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc. (Netherland, Sewell), were approximately 189.1 MMBoe, consisting of 155.6 MMBbls of oil, 16.3 MMBbls of natural gas liquids, and 103.7 Bcf of natural gas. Approximately 41% and 40% of our proved reserves were classified as proved developed as of December 31, 2014 and 2013, respectively. We maintain operational control of approximately 93% of our proved reserves.

        Our oil and natural gas assets consist of undeveloped acreage positions in unconventional liquids-rich basins/fields. We have acquired acreage and may acquire additional acreage in the Bakken / Three Forks formations in North Dakota and the Eagle Ford formation in East Texas, as well as other areas.

        Our total operating revenues for 2014 were approximately $1.1 billion. Production for the fourth quarter of 2014 averaged 46,076 Boe/d. Full year 2014 production averaged 42,107 Boe/d compared to 33,329 Boe/d in 2013, resulting in a 26% year over year increase in our average daily production. The increase in production compared to the prior year period was driven by our operated drilling results and increased production volumes associated with the development of properties we have acquired in the Bakken / Three Forks formations and the Eagle Ford formation in East Texas (which we refer to as "El Halcón"). These areas collectively accounted for approximately 37,500 Boe/d, or 89% of our production in 2014. Our remaining production was associated with various non-core properties. In 2014, we participated in the drilling of 320 gross (98.3 net) wells, all of which were completed and capable of production.

Recent Developments

Amendments to the Senior Credit Agreement and Borrowing Base Confirmation

        On February 25, 2015, we entered into the Ninth Amendment to our Senior Credit Agreement (the Ninth Amendment). The Ninth Amendment provides additional flexibility under the interest coverage test by modifying the minimum Interest Coverage Ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before March 31, 2016. On February 25, 2015, the borrowing base under the Senior Credit Agreement was confirmed at $1.05 billion.

        On September 30, 2014, we entered into the Eighth Amendment to our Senior Credit Agreement (the Eighth Amendment). The Eighth Amendment increased the borrowing base under our Senior Credit Agreement to $1.05 billion. On March 21, 2014, we entered into the Seventh Amendment to our

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Senior Credit Agreement (the Seventh Amendment). The Seventh Amendment provided us additional flexibility under the interest coverage test by modifying the minimum Interest Coverage Ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before December 31, 2014.

HK TMS, LLC Preferred Stock Issuance

        On June 16, 2014, we entered into a transaction with funds and accounts managed by affiliates of Apollo Global Management, LLC (Apollo) pursuant to which HK TMS, LLC (HK TMS), our subsidiary which holds our acreage in Mississippi and Louisiana that we believe is prospective for the Tuscaloosa Marine Shale (TMS), initially sold 150,000 preferred shares in exchange for $150 million and the right to overriding royalty interests in future wells. HK TMS does not participate in our Senior Credit Agreement and is not a guarantor of any of our senior notes.

Divestiture of East Texas Assets

        On May 9, 2014, we completed the divestiture of certain non-core assets in East Texas (the East Texas Assets) to a privately-owned company for a total purchase price of $424.5 million after closing adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. As of December 31, 2013, estimated proved reserves associated with the East Texas Assets, were approximately 16.3 MMBoe. Production from the East Texas Assets averaged approximately 3,700 Boe/d during the first quarter of 2014. The effective date of the transaction was April 1, 2014. Proceeds from the sale were recorded as a reduction to the carrying value our full cost pool with no gain or loss recorded.

2015 Capital Budget

        We expect to spend approximately $350 million to $400 million on drilling and completion capital expenditures during 2015. In addition, we expect to spend approximately $20 million on leasehold, infrastructure, seismic and other in 2015. The significant decrease in planned capital spending for 2015, as compared to 2014 drilling and completion capital expenditures of $1.2 billion, is in response to the significant decrease in crude oil prices over the latter half of 2014 and our expectations that prices may not recover in the near term. Approximately 60-65% of our 2015 drilling and completions budget is expected to be spent in the Bakken / Three Forks formations in North Dakota, approximately 30-35% is budgeted for the El Halcón area in East Texas, and the remaining amount is planned for various other project areas. Our 2015 drilling and completion budget contemplates two operated rigs running in the Bakken / Three Forks and one operated rig running in the El Halcón area. Our drilling and completion budget for 2015 is based on our current view of market conditions and current business plans, and is subject to change.

        We expect to fund our budgeted 2015 capital expenditures with cash flows from operations and borrowings under our Senior Credit Agreement. We strive to maintain financial flexibility and may access capital markets as necessary to maintain substantial borrowing capacity under our Senior Credit Agreement, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may further curtail our capital spending.

        Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominately upon commodity prices and our related commodity price hedging

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activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves in an economical manner is critical to our long-term success.

Business Strategy

        Our primary objective is to increase stockholder value by growing reserves, production and cash flow. To accomplish this objective, we intend to execute the following business strategies:

    Develop and Grow Our Liquids Rich Resource-Style Acreage Positions Using Our Proven Development Expertise.  We plan to leverage our management team's expertise and the latest available technologies to economically develop our property portfolio with a focus on our core liquids-rich resource style plays. We expect to be the operator for the majority of our acreage, which gives us control over the timing of capital expenditures, execution and costs. It also allows us to adjust our capital spending based on drilling results and the economic environment. Our leasing strategy is to pursue long-term contracts that allow us to maintain flexible development plans and avoid short-term obligations to drill wells, as have been common in other resource plays. As operator, we are also able to evaluate industry drilling results and implement improved operating practices which may enhance our initial production rates, ultimate recovery factors and rate of return on invested capital.

    Manage Our Property Portfolio Actively.  We continually evaluate our property base to identify and divest non-core assets and higher cost or lower volume producing properties with limited development potential, which allows us to focus on a portfolio of core properties with significant potential to increase our proved reserves and production.

    Maintain Strong Balance Sheet and Financial Flexibility.  We believe our cash, internally generated cash flows, borrowing capacity, non-core asset sales and access to capital markets will provide us with sufficient liquidity to execute our current capital program and strategy. We have no near term debt maturities. Our management team has a successful track record of issuing equity and debt, and selling non-core assets to maintain a strong balance sheet. Since February 2012, we have issued in the aggregate approximately $6.2 billion of equity and debt securities. We also employ a hedging program to reduce the variability of our cash flows used to support our capital spending.

Our Competitive Strengths

        We have a number of competitive strengths that we believe will allow us to successfully execute our business strategies:

    Proven Management Team with Significant Ownership Stake.  Our management team and technical professionals, including geologists and engineers, have decades of combined experience in the industry. Our management team has successfully founded, grown, operated and sold companies in this industry sector. Floyd C. Wilson was Chairman and Chief Executive Officer of Petrohawk Energy Corporation, which was acquired by BHP Billiton in August 2011, Chairman and Chief Executive Officer of 3TEC Energy Corporation, which was acquired by Plains Exploration & Production Company in 2003, and Chairman and Chief Executive Officer of Hugoton Energy Corporation, which was acquired by Chesapeake Energy Corporation in 1998.

    Geographically and Geologically Diverse Asset Base.  Our proved reserves, production and acreage are located in concentrated positions within multiple onshore U.S. basins. These various basins provide exposure to a variety of reservoir formations, each of which has its own characteristics that impact the costs to drill, complete and operate as well as the composition (and therefore

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      value) of the hydrocarbon stream. We believe that this geographic diversity provides us with broad flexibility to direct our capital resources to projects with the greatest potential returns and access to multiple key end markets, which mitigates our exposure to temporary price dislocations in any one market.

    Extensive Experience in Resource Plays.  Our team has significant experience in all aspects of the development of resource plays. Under Mr. Wilson's leadership, Petrohawk, 3TEC and Hugoton improved drilling times and reserve recoveries through innovation, the use of new technologies and a focus on controlling costs. While at Petrohawk, in developing the early shale plays, the technical team also acquired expertise relevant in our evaluation of new resource play opportunities. In addition to their core strength in exploration and production, our personnel have experience in building midstream infrastructure and have managed oilfield service activities. For example, Petrohawk developed extensive midstream systems serving the Eagle Ford Shale and the Haynesville Shale in order to accommodate their rapid growth in production volumes.

    Strong Technical Team.  We believe that there are certain competitive advantages to be gained by employing a highly skilled technical staff. This team has significant experience and expertise in applying the most sophisticated technologies used in conventional and unconventional resource style plays, including 3-D seismic interpretation, horizontal drilling, deep onshore drilling, comprehensive multi-stage hydraulic fracture stimulation programs, and other exploration, production, and processing technologies. We believe this technical expertise is partly responsible for our management team's strong track record of successful exploration and development, including new discoveries and defining core producing areas in emerging plays.

Oil and Natural Gas Reserves

        The proved reserves estimates shown herein for the years ended December 31, 2014, 2013 and 2012 have been independently prepared by Netherland, Sewell, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. Netherland, Sewell was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within Netherland, Sewell, the technical persons primarily responsible for preparing the estimates set forth in the Netherland, Sewell reserves report incorporated herein are Mr. J. Carter Henson, Jr. and Mr. Mike K. Norton. Mr. Henson, a Licensed Professional Engineer in the State of Texas (No. 73964), has been practicing consulting petroleum engineering at Netherland, Sewell since 1989 and has over 8 years of prior industry experience. He graduated from Rice University in 1981 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Norton, a Licensed Professional Geoscientist in the State of Texas (No. 441), has been practicing consulting petroleum geoscience at Netherland, Sewell since 1989 and has over 10 years of prior industry experience. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying Securities and Exchange Commission (SEC) and other industry reserves definitions and guidelines.

        Our board of directors has established a reserves committee composed of four independent directors, all of whom have experience in energy company reserve evaluations. Our independent engineering firm reports jointly to the reserves committee and to our Senior Vice President of Corporate Reserves. The reserves committee is charged with ensuring the integrity of the process of selection and engagement of the independent engineering firm and in making a recommendation to our board of directors as to whether to accept the report prepared by our independent consulting petroleum engineers. In 2014, Ms. Tina Obut, our Senior Vice President of Corporate Reserves was the

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technical person primarily responsible for overseeing the preparation of the annual reserve report by Netherland, Sewell. She graduated from Marietta College with a Bachelor of Science degree in Petroleum Engineering, received a Master of Science degree in Petroleum and Natural Gas Engineering from Penn State University and a Master of Business Administration degree from the University of Houston.

        The reserves information in this Annual Report on Form 10-K represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve evaluation is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary significantly. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced. For additional information regarding estimates of proved reserves, the preparation of such estimates by Netherland, Sewell and other information about our oil and natural gas reserves, see Item 8. Consolidated Financial Statements and Supplementary Data—"Supplemental Oil and Gas Information (Unaudited)."

        Proved reserve estimates are based on the unweighted arithmetic average prices on the first day of each month for the 12-month period ended December 31, 2014. Average prices for the 12-month period were as follows: West Texas Intermediate (WTI) spot price of $94.99 per barrel (Bbl), adjusted by lease or field for quality, transportation fees, and market differentials and a Henry Hub spot price of $4.350 per MMBtu, as adjusted by lease or field for energy content, transportation fees, and market differentials. All prices and costs associated with operating wells were held constant in accordance with the amended SEC guidelines. The following table presents certain proved reserve information as of December 31, 2014.

 
  Total  

Proved Reserves at Year End (MBoe)(1)

       

Developed

    77,427  

Undeveloped

    111,710  

Total

    189,137  

(1)
Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

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        The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2014 and 2013. Shut-in wells currently not capable of production are excluded from producing well information.

 
  Years Ended December 31,  
 
  2014   2013  
 
  Gross   Net   Gross   Net  

Oil

    1,313     300.2     1,086     259.0  

Natural Gas

    143     85.9     149     86.5  

Total

    1,456     386.1     1,235     345.5  

Oil and Natural Gas Production

Core Resource Plays

        At December 31, 2014, we have estimated proved reserves in our core resource plays of approximately 181.7 MMBoe, of which 92% are oil and natural gas liquids and 39% are proved developed. In general, our core resource plays are characterized by high oil and liquids-rich natural gas content in thick, continuous sections of source rock that can provide repeatable drilling opportunities and significant initial production rates. Our core resource plays are as follows:

Bakken / Three Forks Formations

        We have working interests in approximately 129,000 net acres as of December 31, 2014 prospective for the Bakken / Three Forks formations in North Dakota. Multiple initiatives are underway to lower costs and improve recoveries in our operated project areas. We expect to spud 25 to 30 gross horizontal wells on our operated acreage in 2015 with an average working interest of 55-60%. In 2015, we expect to operate two rigs in the Williston Basin. As of December 31, 2014, we had approximately 225 operated wells producing in this area in addition to minor working interests in hundreds of non-operated wells. Our average daily net production from this area for the year ended December 31, 2014 was approximately 28,900 Boe/d. As of December 31, 2014, estimated proved reserves for the Bakken / Three Forks formations were approximately 140.0 MMBoe, of which approximately 43% were classified as proved developed and approximately 57% as proved undeveloped.

East Texas Eagle Ford Formation (El Halcón)

        We have working interests in approximately 101,000 net acres as of December 31, 2014 prospective for the El Halcón area in Brazos, Burleson, and Robertson Counties, Texas, with targeted depths ranging from 7,000 feet to 10,000 feet. We finished 2014 with a three rig drilling program and approximately 86 producing wells. In 2015, we plan to operate one rig and spud 12 to 15 gross horizontal wells with an average working interest of 75-80%. Our average daily net production from this area for the year ended December 31, 2014 was approximately 8,600 Boe/d. As of December 31, 2014, estimated proved reserves for the El Halcón area were approximately 41.7 MMBoe, of which approximately 29% were classified as proved developed and approximately 71% as proved undeveloped.

Non-core Areas

Tuscaloosa Marine Shale

        Through our subsidiary, HK TMS, we have working interests in approximately 306,000 net acres as of December 31, 2014 prospective for the TMS, which is located primarily in Southwest Mississippi and the Louisiana Florida Parishes. Expectations for 2015 are to complete one well in Tangipahoa Parish, Louisiana and two wells in Wilkinson County, Mississippi. We also expect to participate in several

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non-operated wells in 2015. Our average daily net production from this area for the year ended December 31, 2014 was approximately 500 Boe/d. As of December 31, 2014, estimated proved reserves for the TMS were approximately 1.5 MMBoe, 68% of which was classified as proved developed. We can provide no assurance that this exploratory area, or any wells we subsequently drill in the formations we have targeted for exploration and development, will be successful.

Utica / Point Pleasant Formations

        Our acreage is located in the northern part of the Utica / Point Pleasant play, and as of December 31, 2014, we had approximately 128,000 net acres leased in Trumbull and Mahoning Counties, Ohio, and Mercer and Venango Counties, Pennsylvania. Substantially all of our acreage in these areas is either held by shallow production or provides for five years to drill a well plus a renewal option for an additional five years. Currently, 10 operated wells are producing and three wells are shut in waiting on pipeline/market evaluation. Average daily net production from this area for the year ended December 31, 2014 was approximately 550 Boe/d. Given the recent drop in commodity prices, we do not plan to drill any new wells in this area in 2015. We continue to monitor area competitor activity and new technologies that might allow for lower cost development and increased recoveries from this hydrocarbon rich basin. As of December 31, 2014, estimated proved reserves for the Utica / Point Pleasant formations were approximately 0.2 MMBoe, all of which were classified as proved developed. We can provide no assurance that this exploratory area, or any wells we subsequently drill in the formations we have targeted for exploration and development, will be successful.

Other Non-core Areas

        We have other oil and natural gas properties with varying working interests located in the Austin Chalk Trend in East Texas. Production from these non-core areas, including any production from properties divested during the year, totaled approximately 1,300 MBoe, or 3,500 Boe/d, for the year ended December 31, 2014. As of December 31, 2014, estimated proved reserves for these other properties were approximately 5.7 MMBoe in aggregate, of which approximately 78% were classified as proved developed and approximately 22% as proved undeveloped. We may consider divesting certain of these assets over time and reinvesting the proceeds in our core resource plays.

Liquids-Rich Exploratory Plays

        In addition to the disclosed areas, we may acquire acreage in other unconventional exploratory plays as opportunities arise. Our strategy for our exploratory projects is to use our in-house geologic and engineering expertise to identify underdeveloped areas that we believe are prospective for oil or liquids-rich production. We can provide no assurance that any of these exploratory areas, or any wells we subsequently drill in the formations we have targeted for exploration and development, will be successful. Due to competitive concerns, we intend to keep the details of such plays confidential until such time as it is appropriate to disclose specifics.

Risk Management

        We have designed a risk management policy for the use of derivative instruments to provide partial protection against certain risks relating to our ongoing business operations, such as commodity price declines and interest rate increases. Derivative contracts are utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales on future oil and natural gas production. We generally hedge a varying portion of our anticipated oil and natural gas production for the next 18 to 24 months. Historically, we have also entered into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates (such as those on our Senior Credit Agreement) to fixed interest rates. Our hedge policies and objectives may change

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significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

        Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. While there are many different types of derivatives available, we typically use costless collar agreements, swap agreements and deferred put options to attempt to manage price risk more effectively. The costless collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. All costless collar agreements provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price is below the floor. The swap agreements call for payments to, or receipts from, counterparties depending on whether the index price of oil or natural gas for the period is greater or less than the fixed price established for the period contracted under the swap agreement. Under deferred put option agreements, we pay a fixed premium to lock in a specified floor price for a specified future period. If the index price of oil or natural gas falls below the contracted floor price, the counterparty pays us the difference between the index price and the floor price (netted against the fixed premium payable to the counterparty). If the index price rises above floor price, we pay the fixed premium.

        It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to our derivative contracts is a lender or an affiliate of a lender in our Senior Credit Agreement. We will continue to evaluate the benefit of employing derivatives in the future. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk and Item 8. Consolidated Financial Statements and Supplementary Data—Note 8, "Derivative and Hedging Activities" for additional information.

Oil and Natural Gas Operations

        Our principal properties consist of leasehold interests in developed and undeveloped oil and natural gas properties and the reserves associated with these properties. Generally, oil and natural gas leases remain in force as long as production in paying quantities is maintained. Leases on undeveloped oil and natural gas properties are typically for a primary term of three to five years within which we are generally required to develop the property or the lease will expire. In some cases, the primary term of leases on our undeveloped properties can be extended by option payments; the amount of any payments and time extended vary by lease.

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        The table below sets forth the results of our drilling activities for the periods indicated:

 
  Years Ended December 31,  
 
  2014   2013   2012  
 
  Gross   Net   Gross   Net   Gross   Net  

Exploratory Wells:

                                     

Productive(1)

            10     6.8     1     0.9  

Dry

            2     2.0     2     2.0  

Total Exploratory

            12     8.8     3     2.9  

Extension Wells:

                                     

Productive(1)

    207     51.1     203     56.0     101     30.1  

Dry

            1     1.0     1     0.9  

Total Extension

    207     51.1     204     57.0     102     31.0  

Development Wells:

                                     

Productive(1)

    113     47.2     68     41.6     87     54.3  

Dry

                         

Total Development

    113     47.2     68     41.6     87     54.3  

Total Wells:

                                     

Productive(1)

    320     98.3     281     104.4     189     85.3  

Dry

            3     3.0     3     2.9  

Total

    320     98.3     284     107.4     192     88.2  

(1)
Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly extension or exploratory wells where there is no production history.

        We own interests in developed and undeveloped oil and natural gas acreage in the locations set forth in the table below. These ownership interests generally take the form of working interests in oil and natural gas leases that have varying provisions. The following table presents a summary of our acreage interests as of December 31, 2014:

 
  Developed Acreage   Undeveloped Acreage   Total Acreage  
State
  Gross   Net   Gross   Net   Gross   Net  

Louisiana

    960     912     202,583     189,165     203,543     190,077  

Mississippi

    8,608     8,285     278,587     107,888     287,195     116,173  

Montana

    5,591     1,799     5,012     1,589     10,603     3,388  

North Dakota

    259,855     109,122     76,009     19,653     335,864     128,775  

Ohio

    3,127     3,111     41,731     40,006     44,858     43,117  

Pennsylvania

    748     685     88,125     84,219     88,873     84,904  

Texas

    267,172     164,729     91,520     63,038     358,692     227,767  

Total Acreage

    546,061     288,643     783,567     505,558     1,329,628     794,201  

        Due to a variety of factors, including but not limited to, current market conditions and commodity prices, drilling results of us and other operators in our plays, tract location in relation to current developmental plans, and infrastructure requirements to bring product to market; approximately 211,000 of the 505,558 net owned undeveloped acres as of December 31, 2014, pertaining to certain tracts previously recorded in "Unevaluated oil and natural gas properties" on the consolidated balance sheets have been transferred over time into the full cost pool. Of the remaining 295,000 net owned

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undeveloped acres as of December 31, 2014, approximately 58,000, 122,000 and 48,000 acres will expire in 2015, 2016 and 2017, respectively, if we do not establish production in paying quantities on the units in which such acreage is included or do not pay (to the extent we have the contractual right to pay) delay rentals or obtain other extensions to maintain the lease. The majority of the potential lease expirations during 2015, 2016 and 2017 is attributable to our TMS area, for which our current capital budget includes the renewal/extension for a limited number of acres, subject to discretion as each lease comes due for renewal.

        We review undeveloped acreage on a quarterly basis for new or changed factors that could impact the renewal decisions, as well as making an assessment for possible impairment in which case the cost of any expired, or soon to be expired acreage, would be transferred the full cost pool to be depleted. For our proved undeveloped locations that are not scheduled to be drilled until after lease expiration, we continually review our near-term lease expirations, actively pursue lease extensions and renewals and modify our drilling schedules in order to preserve the leases.

        At December 31, 2014, we had estimated proved reserves of approximately 189.1 MMBoe comprised of 155.6 MMBbls of crude oil, 16.3 MMBbls of natural gas liquids, and 103.7 Bcf of natural gas. The following table sets forth, at December 31, 2014, these reserves:

 
  Proved
Developed
  Proved
Undeveloped
  Total
Proved
 

Oil (MBbls)

    62,770     92,804     155,574  

Natural Gas Liquids (MBbls)

    6,681     9,605     16,286  

Natural Gas (MMcf)

    47,851     55,811     103,662  

Equivalent (MBoe)

    77,427     111,710     189,137  

(1)
Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

        At December 31, 2014, our estimated proved undeveloped reserves were approximately 111.7 MMBoe, a 30.3 MMBoe net increase over the previous year's estimate of 81.4 MMBoe. The following table details the changes in proved undeveloped reserves for 2014 (in MBoe):

Beginning proved undeveloped reserves at December 31, 2013

    81,362  

Undeveloped reserves transferred to developed

    (18,162 )

Revisions

    1,483  

Purchases

    401  

Divestitures

    (10,488 )

Extension and discoveries

    57,114  

Ending proved undeveloped reserves at December 31, 2014

    111,710  

        The increase in proved undeveloped reserves was primarily attributable to extensions of approximately 57 MMBoe, which were largely in the Bakken / Three Forks and El Halcón areas, where active drilling resulted in the expansion of proven areas. Approximately 47% of the operated proved undeveloped reserve extensions are associated with well locations that are more than one offset location away from existing producing wells.

        Partially offsetting the increase in proved undeveloped reserves were decreases due to transfers, divestitures, and technical revisions. Reserve transfers of approximately 18 MMBoe were associated with drilling of proved undeveloped (PUD) locations in the Bakken / Three Forks and El Halcón areas.

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Divestitures of undeveloped reserves of approximately 10 MMBoe relate primarily to the East Texas Assets divestiture completed during the first half of 2014.

        As of December 31, 2014, all of our proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2014, approximately $374.3 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells.

        Reliable technologies were used to determine areas where PUD locations are more than one offset location away from a producing well. These technologies include seismic data, wire line open hole log data, core data, log cross-sections, performance data, and statistical analysis. In such areas, these data demonstrated consistent, continuous reservoir characteristics in addition to significant quantities of economic estimated ultimate recoveries from individual producing wells. Our management team has been a leader in data gathering and evaluation in these areas and was instrumental in developing consortiums that allow various operators to exchange data. We relied only on production flow tests and historical production data, along with the reliable geologic data mentioned above to estimate proved reserves. No other alternative methods or technologies were used to estimate proved reserves.

        The estimates of quantities of proved reserves contained in this report were made in accordance with the definitions contained in SEC Release No. 33-8995, Modernization of Oil and Gas Reporting. For additional information on our oil and natural gas reserves, see Item 8. Consolidated Financial Statements and Supplementary Data—"Supplementary Oil and Gas Information (Unaudited)."

        We account for our oil and natural gas producing activities using the full cost method of accounting in accordance with SEC regulations. Accordingly, all costs incurred in the acquisition, exploration, and development of proved and unproved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs, direct internal costs and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The net capitalized costs of evaluated oil and natural gas properties are subject to a quarterly full cost ceiling test. Our net book value of oil and natural gas properties at December 31, 2014 and March 31, 2014 exceeded the ceiling amount. We recorded a full cost ceiling test impairment before income taxes of $178.5 million ($112.4 million after taxes) for the three months ended December 31, 2014 and $61.2 million ($39.0 million after taxes) for the three months ended March 31, 2014. See further discussion in Item 8. Consolidated Financial Statements and Supplementary Data—Note 5, "Oil and Natural Gas Properties."

        Capitalized costs of our evaluated and unevaluated properties at December 31, 2014, 2013 and 2012 are summarized as follows:

 
  December 31,  
 
  2014   2013   2012  
 
  (In thousands)
 

Oil and natural gas properties (full cost method):

                   

Evaluated

  $ 6,390,820   $ 4,960,467   $ 2,669,245  

Unevaluated

    1,829,786     2,028,044     2,326,598  

Gross oil and natural gas properties

    8,220,606     6,988,511     4,995,843  

Less—accumulated depletion

    (2,953,038 )   (2,189,515 )   (588,207 )

Net oil and natural gas properties

  $ 5,267,568   $ 4,798,996   $ 4,407,636  

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        The following table summarizes our oil, natural gas and natural gas liquids production volumes, average sales price per unit and average costs per unit. In addition, this table summarizes our production for each field that contains 15% or more of our total proved reserves:

 
  Years Ended December 31,  
 
  2014   2013   2012  

Production:

                   

Crude oil—MBbl

                   

Bakken / Three Forks

    9,316     6,232     650  

El Halcón

    2,708     1,194     2  

Woodbine(1)

    390     1,171     372  

Other(2)

    373     1,551     1,391  

Total

    12,787     10,148     2,415  

Natural gas—MMcf

                   

Bakken / Three Forks

    3,861     1,615     224  

El Halcón

    976     282     1  

Woodbine(1)

    260     506     129  

Other(2)

    3,715     5,600     4,200  

Total

    8,812     8,003     4,554  

Natural gas liquids—MBbl

                   

Bakken / Three Forks

    591     227     13  

El Halcón

    278     92      

Woodbine(1)

    49     87     26  

Other(2)

    195     277     229  

Total

    1,113     683     268  

Production:

                   

Total MBoe(3)

    15,369     12,165     3,442  

Average daily production—Boe(3)

    42,107     33,329     9,404  

Average price per unit:(4)

   
 
   
 
   
 
 

Crude oil price—Bbl

  $ 83.78   $ 93.08   $ 92.36  

Natural gas price—Mcf

    4.21     3.41     2.80  

Natural gas liquids price—Bbl

    33.66     35.96     41.72  

Barrel of oil equivalent price—Boe(3)

    74.56     81.91     71.75  

Average cost per Boe:

   
 
   
 
   
 
 

Production:

                   

Lease operating

  $ 8.47   $ 11.44   $ 14.49  

Workover and other

    1.05     0.52     1.29  

Taxes other than income

    6.92     7.28     5.59  

Gathering and other

    1.74     0.97     0.13  

(1)
On May 9, 2014, we completed the divestiture of certain non-core assets in East Texas. The effective date of the transaction was April 1, 2014.

(2)
During the fourth quarter of 2013, we completed three separate divestitures of non-core properties located in the United States. The effective date of the transactions was July 1, 2013. Additionally, on July 19, 2013, we completed the divestiture of our Eagle Ford assets located in Fayette and Gonzales Counties, Texas. The transaction had an effective date of January 1, 2013.

(3)
Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

(4)
Amounts exclude the impact of cash paid or received on settled commodities derivative contracts as we did not elect to apply hedge accounting.

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        The average crude oil and natural gas sales prices above do not reflect the impact of cash paid on, or cash received from, settled derivative contracts as these amounts are reflected as "Net gain (loss) on derivative contracts" in the consolidated statements of operations, consistent with our decision not to elect hedge accounting. Including this impact 2014, 2013 and 2012 average crude oil sales prices were $84.72, $90.66 and $93.25 per Bbl and average natural gas sales prices were $4.06, $3.66 and $3.62 per Mcf, respectively.

Competitive Conditions in the Business

        The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater financial and other resources. Many of these companies explore for, produce and market oil and natural gas, as well as carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties, obtaining sufficient availability of drilling and completion equipment and services, obtaining purchasers and transporters of the oil and natural gas we produce and hiring and retaining key employees. There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States, the states in which our properties are located and tribal regulations in North Dakota. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation.

Other Business Matters

Markets and Major Customers

        The purchasers of our oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. Historically, we have not experienced any significant losses from uncollectible accounts. In 2014, three individual purchasers, Crestwood Midstream Partners, formerly Arrow Field Services LLC (Crestwood), Sunoco Partners Marketing & Terminals, L.P. (Sunoco) and Suncor Energy Marketing Inc. (Suncor), each accounted for more than 10% of our total sales, collectively representing 66% of our total sales for the year.

        In 2013, four individual purchasers of our production, Shell Trading US Co., Sunoco, Crestwood and Suncor, each accounted for more than 10% of our total sales, collectively representing 63% of our total sales for the year.

Seasonality of Business

        Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth fiscal quarters. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.

Operational Risks

        Oil and natural gas exploration and development involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that we will discover or acquire additional oil and natural gas in commercial quantities. Oil

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and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other events may cause accidental leakage or spills of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment, or cause significant injury to persons or property. In such event, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce available cash and possibly result in loss of oil and natural gas properties. Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities.

        As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a material effect on our operating results, financial position or cash flows. For further discussion on risks see Item 1A. Risk Factors.

Regulations

        All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the plugging and abandonment of wells. Our operations are also subject to various conservation laws and regulations. These laws and regulations govern the size of drilling and spacing units, the density of wells that may be drilled in oil and natural gas properties and the unitization or pooling of oil and natural gas properties. In this regard, some states allow the forced pooling or integration of land and leases to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of land and leases. In areas where pooling is primarily or exclusively voluntary, it may be difficult to form spacing units and therefore difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose specified requirements regarding the ratability of production. On some occasions, tribal and local authorities have imposed moratoria or other restrictions on exploration and production activities pending investigations and studies addressing potential local impacts of these activities before allowing oil and natural gas exploration and production to proceed.

        The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Environmental Regulations

        Our operations are subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the United States Environmental Protection Agency, commonly referred to as the EPA, issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures. Among other things, environmental regulatory programs typically regulate the permitting, construction and operation of a facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Failure to comply with environmental laws and regulations may result

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in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, which could result in liability for environmental damages and cleanup costs without regard to negligence or fault on our part.

        New programs and changes in existing programs, however, may address various aspects of our business including natural occurring radioactive materials, oil and natural gas exploration and production, air emissions, waste management, and underground injection of waste material. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition and results of operations. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance in the future may have a material adverse impact on our capital expenditures, earnings and competitive position.

Hazardous Substances and Wastes

        The federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons may include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances that have been released at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of some health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

        Under the federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as RCRA, most wastes generated by the exploration and production of oil and natural gas are not regulated as hazardous waste. Periodically, however, there are proposals to lift the existing exemption for oil and gas wastes and reclassify them as hazardous wastes. If such proposals were to be enacted, they could have a significant impact on our operating costs and on these of all the industry in general. In the ordinary course of our operations moreover, some wastes generated in connection with our exploration and production activities may be regulated as solid waste under RCRA, as hazardous waste under existing RCRA regulations or as hazardous substances under CERCLA. From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. These properties and the materials or wastes released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we have been and may be required to remove or remediate such materials or wastes.

Water Discharges

        Our operations are also subject to the federal Clean Water Act and analogous state laws. Under the Clean Water Act, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, or seek coverage under a general permit. Some of our properties may require permits for discharges of storm water runoff and, as part of our overall evaluation of our current operations, we are upgrading storm water management practices at some facilities. We believe that we will be able to obtain, or be included under, these permits, where necessary, and will need to make only minor modifications to existing facilities and operations that would not have a material effect on us. The Clean Water Act and similar state acts

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regulate other discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages. These laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in connection with on-site storage of significant quantities of oil.

        Our oil and natural gas production also generates salt water, which we dispose of by underground injection. The federal Safe Drinking Water Act (SDWA), the Underground Injection Control (UIC) regulations promulgated under the SDWA and related state programs regulate the drilling and operation of salt water disposal wells. The EPA directly administers the UIC program in some states, and in others it is delegated to the state for administering. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking salt water to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

Hydraulic Fracturing

        Our completion operations are subject to regulation, which may increase in the short- or long-term. The well completion technique known as hydraulic fracturing, which is used to stimulate production of oil and natural gas, has come under increased scrutiny by the environmental community, and many local, state and federal regulators. Hydraulic fracturing involves the injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate oil and natural gas production. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with substantially all of the wells for which we are the operator.

        Under the direction of Congress, the EPA has undertaken a study of the effect of hydraulic fracturing on drinking water and groundwater. The EPA has also announced its plan to propose pre-treatment standards under the Clean Water Act for wastewater discharges from shale hydraulic fracturing operations. Congress may consider legislation to amend the Federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Certain states, including Colorado, Utah and Wyoming, have issued similar disclosure rules. Several environmental groups have also petitioned the EPA to extend toxic release reporting requirements under the Emergency Planning and Community Right-to-Know Act to the oil and natural gas extraction industry. Additional disclosure requirements could result in increased regulation, operational delays, and increased operating costs that could make it more difficult to perform hydraulic fracturing.

        In addition, the Department of the Interior has proposed new regulations concerning the use of hydraulic fracturing on lands under its jurisdiction, which includes lands on which we conduct or plan to conduct operations. A number of other jurisdictions likewise have sought to impose restrictions or bans on hydraulic fracturing. On December 19, 2013, the Supreme Court of Pennsylvania overturned several portions of Pennsylvania's law regulating hydraulic fracturing, allowing local governments in Pennsylvania to regulate hydraulic fracturing through local land use regulations. Other local jurisdictions, including Denton, Texas and several cities in Colorado have adopted regulations restricting hydraulic fracturing. The proliferation of regulations may limit our ability to operate.

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Air Emissions

        The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources, including oil and natural gas production. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Our operations, or the operations of service companies engaged by us, may in certain circumstances and locations be subject to permits and restrictions under these statutes for emissions of air pollutants.

        Recently, the EPA issued four new regulations for the oil and natural gas industry, including: a new source performance standard for volatile organic compounds (VOCs); a new source performance standard for sulfur dioxide; an air toxics standard for oil and natural gas production; and an air toxics standard for natural gas transmission and storage. The final rule includes the first federal air standards for natural gas wells that are hydraulically fractured, or refractured, as well as requirements for several sources, such as storage tanks and other equipment, and has the effect of limiting methane emissions from these sources. Compliance with these regulations will impose additional requirements and costs on our operations.

        In December 2014, the EPA proposed to lower the existing 75 parts per billion (ppb) national ambient air quality standard (NAAQS) for ozone under the federal Clean Air Act to a range within 65-70 ppb. The EPA is also taking public comment on whether the ozone NAAQS should be revised to as low as 60 ppb. A lowered ozone NAAQS in a range of 60-70 ppb could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.

Climate Change

        Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth's atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that require reporting and reductions of the emission of such greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol address greenhouse gas emissions, and several countries, including those comprising the European Union, have established greenhouse gas regulatory systems. In the United States, at the state level, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through emission inventories, emissions targets, greenhouse gas cap and trade programs or incentives for renewable energy generation, while others have considered adopting such greenhouse gas programs.

        At the federal level, the EPA has issued regulations requiring us and other companies to annually report certain greenhouse gas emissions from our oil and natural gas facilities. Beyond its measuring and reporting rules, the EPA has issued an "Endangerment Finding" under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities.

        In addition, President Obama released a Strategy to Reduce Methane Emissions in March 2014. Consistent with that strategy, the EPA has announced that it intends to issue a proposed rule in 2015 to set standards for methane and VOC emissions from new and modified oil and gas production

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sources and natural gas processing and transmission sources. The EPA intends to issue a final rule in 2016. As another prong of the President's strategy, the federal Bureau of Land Management (BLM) is expected to propose standards in 2015 to reduce venting and flaring on public lands. The EPA and BLM actions are part of a series of steps by the Administration that are intended to result by 2025 in a 40-45% decrease in methane emissions from the oil and gas industry as compared to 2012 levels. In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

        Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions control systems or other compliance costs, and reduce demand for our products.

The National Environmental Policy Act

        Oil and natural gas exploration and production activities may be subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

Threatened and endangered species, migratory birds, and natural resources

        Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. The United States Fish and Wildlife Service may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat designation could result in further material restrictions on federal land use or on private land use and could delay or prohibit land access or development. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent or restrict oil and gas exploration activities or seek damages for any injury, whether resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and in some cases, criminal penalties.

Hazard communications and community right to know

        We are subject to federal and state hazard communication and community right to know statutes and regulations. These regulations govern record keeping and reporting of the use and release of hazardous substances, including, but not limited to, the federal Emergency Planning and Community Right-to-Know Act and may require that information be provided to state and local government authorities and the public.

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Occupational Safety and Health Act

        We are subject to the requirements of the federal Occupational Safety and Health Act and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration's hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees.

Employees and Principal Office

        As of December 31, 2014, we had 419 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.

        As of December 31, 2014, we leased corporate office space in Houston, Texas at 1000 Louisiana Street, where our principal offices are located. We also lease corporate offices in Denver, Colorado as well as a number of other field office locations.

Access to Company Reports

        We file periodic reports, proxy statements and other information with the SEC in accordance with the requirements of the Securities Exchange Act of 1934, as amended. We make our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Forms 3, 4 and 5 filed on behalf of directors and officers, and any amendments to such reports, available free of charge through our corporate website at www.halconresources.com as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. In addition, our insider trading policy, regulation FD policy, equity-based incentive grant policy, corporate governance guidelines, code of conduct, code of ethics, audit committee charter, compensation committee charter, nominating and corporate governance committee charter and reserves committee charter are available on our website under the heading "Investor Relations—Corporate Governance". Within the time period required by the SEC and the New York Stock Exchange (NYSE), as applicable, we will post on our website any modifications to the code of conduct and the code of ethics for our Chief Executive Officer and senior financial officers and any waivers applicable to senior officers as defined in the applicable code, as required by the Sarbanes-Oxley Act of 2002. You may also read and copy any document we file with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, our reports, proxy and information statements, and our other filings are also available to the public over the internet at the SEC's website at www.sec.gov. Unless specifically incorporated by reference in this Annual Report on Form 10-K, information that you may find on our website is not part of this report.

ITEM 1A.    RISK FACTORS

We may have difficulty financing our planned capital expenditures which could adversely affect our growth.

        We have experienced, and expect to continue to experience, substantial capital expenditure and working capital needs, primarily as a result of our drilling program. We intend to continue to selectively increase our acreage position, which would require capital in addition to the capital necessary to drill on our existing acreage. In addition, it is possible that we will acquire acreage in other areas that we believe are prospective for oil and natural gas production and expend capital to develop such acreage. We expect to use borrowings under our Senior Credit Agreement and proceeds from potential future capital markets transactions, if necessary, to fund capital expenditures that are in excess of our cash flow and cash on hand.

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        Our Senior Credit Agreement limits our borrowings to the lesser of the borrowing base and the total commitments. As of December 31, 2014, our Senior Credit Agreement was a $1.5 billion facility with a borrowing base of $1.05 billion. As of December 31, 2014, we had $557.0 million of indebtedness outstanding, $1.1 million of letters of credit outstanding and $491.9 million of borrowing capacity available under our Senior Credit Agreement. Our borrowing base is determined semi-annually, and may also be redetermined periodically at the discretion of our lenders. Lower oil and natural gas prices may result in a reduction in our borrowing base at the next redetermination. A reduction in our borrowing base could require us to repay any indebtedness in excess of the borrowing base. Additionally, the indentures governing our senior unsecured debt contain covenants limiting our ability to incur additional indebtedness, including borrowings under our Senior Credit Agreement, unless we meet one of two alternative tests. The first test applies to all indebtedness and requires that, after giving effect to the incurrence of additional debt, our fixed charge coverage ratio (which is the ratio of our adjusted consolidated EBITDA (as defined in our indentures) to our adjusted consolidated interest expense over the trailing four fiscal quarters) will be at least 2.0 to 1.0. The second test applies only to borrowings under our credit agreements, including indentures and our Senior Credit Agreement that do not meet the first test and it limits these borrowings to the greater of a fixed sum of $750 million and 30% of our adjusted consolidated net tangible assets (or ACNTA, as defined in our indentures), which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves. Currently, we are permitted to incur additional indebtedness under these incurrence tests, but may be limited in the future. Lower oil and natural gas prices in the future could reduce our adjusted consolidated EBITDA, as well as our adjusted consolidated net tangible assets, and thus could reduce our ability to incur additional indebtedness.

        On March 21, 2014, we entered into the Seventh Amendment to our Senior Credit Agreement (the Seventh Amendment). The Seventh Amendment provides us flexibility under our interest coverage test by modifying the minimum interest coverage ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before December 31, 2014. Additionally, on February 25, 2015, we entered into the Ninth Amendment to our Senior Credit Agreement (the Ninth Amendment). The Ninth Amendment provides us additional flexibility under our interest coverage test by modifying the minimum interest coverage ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before March 31, 2016. In the event we have difficulty in meeting these tests or the current ratio test in the future, we would be required to seek additional relief, and there is no assurance that it would be granted.

        Additionally, our ability to complete future equity offerings is limited by general market conditions. If we are not able to borrow sufficient amounts under our Senior Credit Agreement and/or are unable to raise sufficient capital to fund our capital expenditures, we may be required to curtail our drilling, development, land acquisition and other activities, which could result in a decrease in our production of oil and natural gas, forfeiture of leasehold interests if we are unable or unwilling to renew them, and could force us to sell some of our assets on an untimely or unfavorable basis, each of which could have a material adverse effect on our results and future operations.

Oil and natural gas prices are volatile, and low prices could have a material adverse impact on our business.

        Our revenues, profitability and future growth and the carrying value of our properties depend substantially on prevailing oil and natural gas prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. For example, due to the significant decrease in crude oil prices over the latter half of 2014, we have significantly reduced our planned drilling and completion capital expenditures for 2015 and expect to spend approximately $350 million to $400 million. The amount we will be able to borrow under our Senior Credit Agreement will be subject to periodic redetermination based in part on current oil and natural gas prices and on changing expectations of future prices. Lower prices may also reduce the amount of

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oil and natural gas that we can economically produce and have an adverse effect on the value of our properties.

        Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause volatility are:

    the domestic and foreign supply of oil and natural gas;

    the ability of members of the Organization of Petroleum Exporting Countries and other producing countries to agree upon and maintain oil prices and production levels;

    social unrest and political instability, particularly in major oil and natural gas producing regions outside the United States, such as the Middle East, and armed conflict or terrorist attacks, whether or not in oil or natural gas producing regions;

    the level of consumer product demand;

    the growth of consumer product demand in emerging markets, such as China;

    labor unrest in oil and natural gas producing regions;

    weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand of oil and natural gas;

    the price and availability of alternative fuels;

    the price of foreign imports;

    worldwide economic conditions; and

    the availability of liquid natural gas imports.

        These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and natural gas.

We are subject to various contractual limitations that affect the discretion of our management in operating our business.

        The indentures governing our senior unsecured debt and our Senior Credit Agreement and the certificate of designations governing our Series A convertible preferred stock contain various provisions that may limit our management's discretion in certain respects. In particular, these agreements limit our and our subsidiaries' ability to, among other things:

    pay dividends on, redeem or repurchase shares of our common stock and, under certain circumstances, our convertible preferred stock, and redeem or repurchase our subordinated debt;

    make loans to others;

    make investments;

    incur additional indebtedness or issue preferred stock that is senior to our convertible preferred stock as to dividends or rights upon liquidation, winding-up or dissolution;

    create certain liens;

    sell assets;

    enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;

    consolidate, merge or transfer all or substantially all of our assets and those of our restricted subsidiaries taken as a whole;

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    engage in transactions with affiliates;

    enter into hedging contracts;

    create unrestricted subsidiaries; and

    enter into sale and leaseback transactions.

        Additionally, if dividends on our Series A convertible preferred stock are in arrears and unpaid for six or more quarterly periods, the holders (voting as a single class) of our outstanding Series A convertible preferred stock will be entitled to elect two additional directors to our Board of Directors until paid in full.

        As part of HK TMS's transaction with Apollo, there are certain restrictions on the transfer of assets, including cash, to us from HK TMS. HK TMS is required to maintain a minimum cash balance equal to two quarterly dividend payments, of approximately $3.0 million each, plus $10.0 million. Additionally, the quarterly 8% dividends paid to holders of the HK TMS preferred shares have priority over other cash distributions. No dividends shall be paid to us from HK TMS prior to December 31, 2016. HK TMS is restricted from transferring more than 20% of its maximum net acres and from transferring any assets exceeding 20% of HK TMS's proved reserves at any one time. Finally, proceeds from any such transfers of acres or other assets must be used for HK TMS's capital or operating expenditures, or to redeem the preferred shares.

        Compliance with these and other limitations may limit our ability to operate and finance our business and engage in certain transactions in the manner we might otherwise. In addition, if we fail to comply with the limitations under our indentures or Senior Credit Agreement, our creditors, if the agreements so provide, may accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders may be able to terminate any commitments they had made to make further funds available to us.

We have substantial indebtedness and may incur substantially more debt. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.

        We have incurred substantial debt amounting to approximately $3.7 billion as of December 31, 2014. As a result of our indebtedness, we will need to use a substantial portion of our cash flow to pay interest, which will reduce the amount we will have available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate. Our indebtedness under our Senior Credit Agreement is at a variable interest rate, and so a rise in interest rates will generate greater interest expense to the extent we do not have hedging arrangements that are effective in mitigating interest rate fluctuations. The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business.

        We may incur substantially more debt in the future. The indentures governing our outstanding senior notes contain restrictions on our incurrence of additional indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances, we could incur substantial additional indebtedness in compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring obligations that do not constitute "indebtedness" as defined under the indentures. At December 31, 2014, our Senior Credit Agreement was a $1.5 billion facility with a borrowing base of $1.05 billion. At December 31, 2014, we had $557.0 million of indebtedness outstanding, $1.1 million of letters of credit outstanding and $491.9 million of borrowing capacity available under our Senior Credit Agreement.

        Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many

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of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance debt, sell assets or sell additional shares of common or preferred stock on terms that we may not find attractive if it may be done at all. Further, our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default under that indebtedness, which could adversely affect our business, financial condition and results of operations.

Offers or sales of a substantial number of shares of our common stock by our shareholders may cause the market price of our common stock to decline.

        In satisfaction of pre-existing contractual obligations, we filed with the SEC a shelf registration statement on Form S-3 in September 2013 covering the potential resale by certain selling stockholders of approximately 158.0 million shares of our common stock, and have previously filed similar resale registration statements in lesser amounts for other shareholders. The ability of our shareholders to sell significant numbers of shares of our common stock in the public market pursuant to such registration statements or upon the expiration of lock up agreements or statutory holding periods under Rule 144 of the Securities Act of 1933, as amended, together with any actual sales of our common stock they may choose to make, could cause the market price of our common stock to fall and could make it more difficult for us to raise additional financing through future sales of equity or equity-related securities at a time and price that we deem reasonable or appropriate.

If we were to experience an ownership change, we could be limited in our ability to use net operating losses arising prior to the ownership change to offset future taxable income.

        If we were to experience an "ownership change," as determined under section 382 of the Internal Revenue Code, our ability to offset taxable income arising after the ownership change with net operating losses (NOLs) arising prior to the ownership change would be limited, possibly substantially. An ownership change would establish an annual limitation on the amount of our pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate.

We depend on computer and telecommunications systems and failures in our systems or cyber security attacks could significantly disrupt our business operations.

        We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business. In addition, we have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. It is possible we could incur interruptions from cyber security attacks, computer viruses or malware. We believe that we have positive relations with our related vendors and maintain adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties to our computing and communications infrastructure or our information systems could significantly disrupt our business operations.

We will be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.

        Our business plan contemplates significant acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy, which may include the acquisition of asset packages of producing properties or existing companies or businesses operating in our industry. The successful acquisition of producing properties requires an assessment of several factors, including:

    recoverable reserves;

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    future oil, natural gas and natural gas liquids prices and their appropriate differentials;

    development and operating costs; and

    potential environmental and other liabilities.

        The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We are generally not able to obtain contractual indemnification for environmental liabilities and normally acquire properties on an "as is" basis.

        Significant acquisitions of existing companies or businesses and other strategic transactions may involve additional risks, including:

    diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

    the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with our own while carrying on our ongoing business;

    difficulty associated with coordinating geographically separate organizations;

    the challenge of integrating environmental compliance systems to meet requirements of rapidly changing regulations;

    the challenge of attracting and retaining personnel associated with acquired operations; and

    failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within our expected time frame.

        The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior 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 business. If our senior management is not able to manage the integration process effectively, or if any significant business activities are interrupted as a result of the integration process, our business could be materially and adversely affected.

Assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.

        Our recent growth is due significantly to acquisitions of exploration and production companies, producing properties and undeveloped and unevaluated leaseholds. We expect acquisitions may also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating and capital costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled

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to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an "as is" basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.

A downgrade in our credit rating could negatively impact our cost of and ability to access capital.

        As of the date of this filing, our corporate credit rating was "B" with a negative outlook by Standard and Poor's (S&P) and "Caa1" with a stable outlook by Moody's Investors Service (Moody's). Although we are not aware of any current plans of these or other rating agencies to lower their respective ratings on us or our senior debt, we cannot be assured that our credit ratings will not be downgraded. A downgrade in our credit ratings could negatively impact our cost of capital and our ability to effectively execute aspects of our strategy. If our credit rating were downgraded, it could be difficult for us to raise debt in the public debt markets and the cost of that new debt could be higher than debt we could raise with our current ratings. In addition, a downgrade could impact requirements for us to provide financial assurance of performance under contractual arrangements or derivative agreements.

We may not be able to drill wells on a substantial portion of our acreage.

        We may not be able to drill on a substantial portion of our acreage for various reasons. We may not generate or be able to raise sufficient capital to do so. Future deterioration in commodities pricing may also make drilling some acreage uneconomic. Our actual drilling activities and future drilling budget will depend on drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, lease expirations, gathering system and pipeline transportation constraints, regulatory approvals and other factors. In addition, any drilling activities we are able to conduct may not be successful or add additional proved reserves to our overall proved reserves, which could have a material adverse effect on our future business, financial condition and results of operations.

Part of our strategy involves drilling in shale formations, some of which are new and emerging, using horizontal drilling and completion techniques. The results of our drilling program using these techniques may be subject to more uncertainties than conventional drilling programs, especially in areas that are new and emerging. These uncertainties could result in an inability to meet our expectations for reserves and production.

        The results of our drilling in new or emerging formations, such as the Bakken / Three Forks formations, Tuscaloosa Marine Shale formation, the El Halcón area, and Utica / Point Pleasant formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and consequently we are less able to predict drilling results in these areas. In addition, the use of horizontal drilling and completion techniques used in all of our shale formations involve certain risks and complexities that do not exist in conventional wells. The ultimate success of our drilling and completion strategies and techniques will be better evaluated over time as more wells are drilled and production profiles are better established.

        If our drilling results are less than anticipated our investment in these areas may not be as attractive as we anticipate and we could incur material write downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

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Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

        As of December 31, 2014, we owned leasehold interests in approximately 129,000 net acres in areas we believe are prospective for the Bakken / Three Forks formations, approximately 101,000 net acres in areas we believe are prospective for the El Halcón area, approximately 306,000 net acres in areas we believe are prospective for the Tuscaloosa Marine Shale formation and 128,000 net acres in areas we believe are prospective for the Utica / Point Pleasant formations. A large portion of our acreage is not currently held by production. Unless production in paying quantities is established on units containing these leases during their terms, these leases will expire. If our leases expire, we will lose our right to develop the related properties.

        Our drilling plans for these areas are subject to change based upon various factors, many of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. Further, some of our acreage is located in sections where we do not hold the majority of the acreage and therefore it is likely that we will not be named operator of these sections. As a non-operating leaseholder we have less control over the timing of drilling and are therefore subject to additional risk of expirations.

Our ability to sell our production and/or receive market prices for our production may be adversely affected by transportation capacity constraints and interruptions.

        If the amount of natural gas, condensate or oil being produced by us and others exceeds the capacity of the various transportation pipelines and gathering systems available in our operating areas, it will be necessary for new transportation pipelines and gathering systems to be built. Or, in the case of oil and condensate, it will be necessary for us to rely more heavily on trucks to transport our production, which is more expensive and less efficient than transportation via pipeline. The construction of new pipelines and gathering systems is capital intensive and construction may be postponed, interrupted or cancelled in response to changing economic conditions and the availability and cost of capital. In addition, capital constraints could limit our ability to build gathering systems to transport our production to transportation pipelines. In such event, costs to transport our production may increase materially or we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell our production at much lower prices than market or than we currently project, which would adversely affect our results of operations.

        A portion of our production may also be interrupted, or shut in, from time to time for numerous other 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 adversely affect our cash flow.

Unless we replace our reserves, our reserves and production will decline, which would adversely affect our financial condition, results of operations and cash flows.

        Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Decline rates are typically greatest early in the productive life of a well. Estimates of the decline rate of an oil or natural gas well are inherently imprecise, and are less precise with respect to new or emerging oil and natural gas formations with limited production histories than for more developed formations with established production histories. Our production levels and the reserves that we currently expect to recover from our wells will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future oil and natural gas reserves and

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production and, therefore, our cash flow and results of operations are highly dependent upon our success in efficiently developing and exploiting our current properties 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. If we are unable to replace our current and future production, our cash flows and the value of our reserves may decrease, adversely affecting our business, financial condition and results of operations.

Estimates of proved oil and natural gas reserves involve assumptions and any material inaccuracies in these assumptions will materially affect the quantities and the value of our reserves.

        This Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

        Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance could materially affect the estimated quantities and the value of our reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

        At December 31, 2014, approximately 59% of our estimated reserves were classified as proved undeveloped. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. The estimates of these oil and natural gas reserves and the costs associated with development of these reserves have been prepared in accordance with SEC regulations, however, actual capital expenditures will likely vary from estimated capital expenditures, development may not occur as scheduled and actual results may not be as estimated.

We depend substantially on the continued presence of key personnel for critical management decisions and industry contacts.

        Our success depends upon the continued contributions of our executive officers and key employees, particularly with respect to providing the critical management decisions and contacts necessary to manage and maintain growth within a highly competitive industry. Competition for qualified personnel can be intense, particularly in the oil and natural gas industry, and there are a limited number of people with the requisite knowledge and experience. Under these conditions, we could be unable to attract and retain these personnel. The loss of the services of any of our executive officers or other key employees for any reason could have a material adverse effect on our business, operating results, financial condition and cash flows.

Our business is highly competitive.

        The oil and natural gas industry is highly competitive in many respects, including identification of attractive oil and natural gas properties for acquisition, drilling and development, securing financing for such activities and obtaining the necessary equipment and personnel to conduct such operations and activities. In seeking suitable opportunities, we compete with a number of other companies, including large oil and natural gas companies and other independent operators with greater financial resources, larger numbers of personnel and facilities, and, in some cases, with more expertise. There can be no assurance that we will be able to compete effectively with these entities.

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Our oil and natural gas activities are subject to various risks which are beyond our control.

        Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling oil and natural gas. Although we may take precautionary measures, many of these risks and hazards are beyond our control and unavoidable under the circumstances. Many of these risks or hazards could materially and adversely affect our revenues and expenses, the ability of certain of our wells to produce oil and natural gas in commercial quantities, the rate of production and the economics of the development of, and our investment in the prospects in which we have or will acquire an interest. Any of these risks and hazards could materially and adversely affect our financial condition, results of operations and cash flows. Such risks and hazards include:

    human error, accidents, labor force and other factors beyond our control that may cause personal injuries or death to persons and destruction or damage to equipment and facilities;

    blowouts, fires, hurricanes, pollution and equipment failures that may result in damage to or destruction of wells, producing formations, production facilities and equipment;

    unavailability of materials and equipment;

    engineering and construction delays;

    unanticipated transportation costs and delays;

    unfavorable weather conditions;

    hazards resulting from unusual or unexpected geological or environmental conditions;

    environmental regulations and requirements;

    accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or salt water, into the environment;

    hazards resulting from the presence of hydrogen sulfide (H2S) or other contaminants in gas we produce;

    changes in laws and regulations, including laws and regulations applicable to oil and natural gas activities or markets for the oil and natural gas produced;

    fluctuations in supply and demand for oil and natural gas causing variations of the prices we receive for our oil and natural gas production; and

    the availability of alternative fuels and the price at which they become available.

        As a result of these risks, expenditures, quantities and rates of production, revenues and operating costs may be materially affected and may differ materially from those anticipated by us.

Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns.

        We require significant amounts of undeveloped leasehold acreage to further our development efforts. Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that our leasehold acreage will be profitably developed, that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target results are dependent upon the

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current and future market prices for oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.

        In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. The cost of drilling, completing and operating a well is often uncertain and cost factors can adversely affect the economics of a project. We cannot predict the cost of drilling and completing a well, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including:

    unexpected drilling conditions;

    pressure or irregularities in formations;

    equipment failures or accidents and shortages or delays in the availability of drilling and completion equipment and services;

    adverse weather conditions, including hurricanes; and

    compliance with governmental requirements.

We are subject to complex federal, state, local and other laws and regulations that frequently are amended to impose more stringent requirements that could adversely affect the cost, manner or feasibility of doing business.

        Companies that explore for and develop, produce, sell and transport oil and natural gas in the United States are subject to extensive federal, state and local laws and regulations, including complex tax and environmental, health and safety laws and the corresponding regulations, and are required to obtain various permits and approvals from federal, state and local agencies. If these permits are not issued or unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:

    water discharge and disposal permits for drilling operations;

    drilling bonds;

    drilling permits;

    reports concerning operations;

    air quality, air emissions, noise levels and related permits;

    spacing of wells;

    rights-of-way and easements;

    unitization and pooling of properties;

    pipeline construction;

    gathering, transportation and marketing of oil and natural gas;

    taxation; and

    waste transport and disposal permits and requirements.

        Failure to comply with these laws may result in the suspension or termination of operations and subject us to liabilities under administrative, civil and criminal penalties. Compliance costs can be significant. Moreover, these laws or the enforcement thereof could change in ways that substantially increase the costs of doing business. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our business, financial condition and results of

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operations. Under these laws and other environmental, health and safety laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages including the assessment of natural resource damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Some laws and regulations may impose strict as well as joint and several liability for environmental contamination, which could subject us to liability for the conduct of others or for our own actions that were in compliance with all applicable laws at the time such actions were taken. Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects. Part of the regulatory environment in which we operate includes, in some cases, federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to regulation by oil and natural gas producing states relating to conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. Delays in obtaining regulatory approvals or necessary permits, the failure to obtain a permit or the receipt of a permit with excessive conditions or costs could have a material adverse effect on our ability to explore on, develop or produce our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

        We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. Federal, state, tribal and local governments have been adopting or considering restrictions on or prohibitions of fracturing in areas where we currently conduct operations, or in the future plan to conduct operations. Consequently, we could be subject to additional levels of regulation, operational delays or increased operating costs and could have additional regulatory burdens imposed upon us that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

        From time to time, for example, legislation has been proposed in Congress to amend the federal Safe Drinking Water Act to require federal permitting of hydraulic fracturing and the disclosure of chemicals used in the hydraulic fracturing process. Further, the Environmental Protection Agency (EPA) is conducting a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. In December 2012, the EPA issued a progress report describing its ongoing study, and announcing its expectation that a final draft report will be released for public comment and peer review in 2014. Other governmental reviews have also been recently conducted or are under way that focus on environmental aspects of hydraulic fracturing, including, for example, a federal Bureau of Land Management rulemaking for hydraulic fracturing practices on federal and Indian lands that has resulted in a May 2013 proposal that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that the wells used in fracturing operations meet proper construction standards and development of plans for managing related flowback water. These activities could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

        Certain states, including North Dakota, Ohio, Pennsylvania, and Texas where we conduct operations, likewise are considering or have adopted more stringent requirements for various aspects of hydraulic fracturing operations, such as permitting, disclosure, air emissions, well construction, seismic

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monitoring, waste disposal and water use. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. Such efforts have extended to bans on hydraulic fracturing. On December 19, 2013, the Pennsylvania Supreme Court overturned several portions of Pennsylvania's law regulating hydraulic fracturing, allowing local governments in Pennsylvania to regulate hydraulic fracturing through local land use regulations. Other local jurisdictions, including Dallas, Texas and several cities in Colorado, have adopted restrictions on hydraulic fracturing, and anti-hydraulic fracturing activists are seeking more such controls.

        The proliferation of regulations may limit our ability to operate. If the use of hydraulic fracturing is limited, prohibited or subjected to further regulation, these requirements could delay or effectively prevent the extraction of oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

        Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth's atmosphere. In response to these studies, governments have been adopting domestic and international climate change regulations that require reporting and reductions of the emission of such greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol address greenhouse gas emissions, and international negotiations over climate change and greenhouse gases are continuing. Meanwhile, several countries, including those comprising the European Union, have established greenhouse gas regulatory systems.

        In the United States, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through emission inventories, emission targets, greenhouse gas cap and trade programs or incentives for renewable energy generation, while others have considered adopting such greenhouse gas programs.

        At the federal level, the Obama Administration is attempting to address climate change through a variety of administrative actions. The EPA has issued greenhouse gas monitoring and reporting regulations that cover oil and natural gas facilities, among other industries. Beyond measuring and reporting, the EPA issued an "Endangerment Finding" under section 202(a) of the Clean Air Act, concluding certain greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities. In March 2014, moreover, the President released a Strategy to Reduce Methane Emissions that included consideration of both voluntary programs and targeted regulations for the oil and gas sector. Towards that end, the EPA has released five draft white papers on methane and volatile organic compound emissions and mitigation measures for natural gas compressors, hydraulically fractured oil wells, pneumatic devices, well liquids unloading facilities and natural gas production and transmission facilities. Building on its white papers and the public input on those documents, the EPA has announced that it intends to issue a proposed rule in the summer of 2015 to set standards for methane and VOC emissions from new and modified oil and gas production sources and natural gas processing and transmission sources. The EPA intends to issue a final rule in 2016. Also as part of the President's strategy, the federal Bureau of Land Management (BLM) is expected to propose standards for reducing venting and flaring on public lands. The EPA and BLM actions are part of a series of steps by the Administration that are intended to result by 2025 in a 40-45% decrease in methane emissions from the oil and gas industry as compared to 2012 levels.

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        In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

        Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions controls or other compliance costs, and reduce demand for our products.

Requirements to reduce gas flaring in North Dakota could have an adverse effect on our operations.

        Wells in the Bakken / Three Forks formations in North Dakota, where we have significant operations, yield natural gas as a byproduct of oil production. Bottlenecks in the gas gathering network in certain areas resulted in some of that natural gas being flared instead of processed. The North Dakota Industrial Commission (NDIC), the State's chief energy regulator, recently issued an order to reduce the volume of natural gas flared from oil wells in the Bakken / Three Forks formations. The State's objectives are to cause operators to capture 74% of the natural gas by the fourth quarter 2014, 77% by the first quarter 2015, 85% by the first quarter 2016, and 90%, with the potential for 95%, by the fourth quarter 2020. In addition, the NDIC is requiring operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals. These capture requirements and any similar future obligations in North Dakota or our other locations, may increase our operational costs or restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.

Crude oil from the Bakken / Three Forks formations may pose unique hazards that may have an adverse effect on our operations.

        The U.S. Department of Transportation (USDOT) recently concluded that crude oil from the Bakken / Three Forks formations has a higher volatility than most other U.S. crude oil and thus is more ignitable and flammable. Based on that information, and several fires involving rail transportation of crude oil, USDOT has started a rulemaking to develop new requirements for shipping crude oil by rail. In addition, the rail industry has adopted increased precautions for crude shipments. Any new restrictions that significantly affect transportation of crude oil production could materially and adversely affect our financial condition, results of operations and cash flows.

Operations on the Fort Berthold Indian Reservation of the Three Affiliated Tribes in North Dakota are subject to various federal and tribal regulations and laws, any of which may increase our costs and delay our operations.

        Various federal agencies within the U.S. Department of the Interior, particularly the Office of Natural Resources Revenue (formerly the Minerals Management Service) and the Bureau of Indian Affairs, along with the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation on which we hold approximately 29,000 net acres. In addition, the Three Affiliated Tribes is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands can be subject to the Native American tribal court system. One or more of these factors may increase our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.

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Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner.

        Water is an essential component of our drilling and hydraulic fracturing processes. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, NGLs and natural gas, which could have an adverse effect on our business, financial condition and results of operations. Wastewaters from our operations typically are disposed of via underground injection. Some studies have linked earthquakes in certain areas to underground injection, which is leading to greater public scrutiny of disposal wells. Any new environmental initiatives or regulations that restrict injection of fluids, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas, or that limit the withdrawal, storage or use of surface water or ground water necessary for hydraulic fracturing of our wells, could increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations and cash flows.

The ongoing implementation of federal legislation enacted in 2010 could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.

        Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our oil and natural gas production and, periodically, interest expense. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which requires the SEC and the Commodity Futures Trading Commission (or CFTC), along with other federal agencies, to promulgate regulations implementing the new legislation. The CFTC, in coordination with the SEC and various US federal banking regulators, has issued regulations to implement the so-called "Volcker Rule" under which banking entities are generally prohibited from proprietary trading of derivatives. Although conditional exemptions from this general prohibition are available, the Volcker Rule may limit the trading activities of banking entities that have been counterparties to our derivatives trades in the past. Also, a provision of the Dodd-Frank Act known as the "swaps push-out rule" may require some of the banking counterparties to our commodity derivative contracts to "push out" some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

        The CFTC also has finalized other regulations implementing the Dodd-Frank Act's provisions regarding trade reporting, margin and position limits; however, some regulations remain to be finalized and it is not possible at this time to predict when the CFTC will adopt final rules. For example, the Dodd-Frank Act and the CFTC regulations may require compliance with margin requirements and with certain clearing and trade-execution requirements in connection with certain of our derivative activities. Also, the CFTC has re-proposed regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are expected to be made exempt from these limits. It is possible that the CFTC, in conjunction with the US federal banking regulators, may mandate that financial counterparties entering into swap transactions with end-users must do so with credit support agreements in place, which could result in negotiated credit thresholds above which we would be required to post collateral.

        The Dodd-Frank Act and any additional implementing regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, limit our ability to trade some derivatives to hedge risks, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our

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existing commodity derivative contracts, and potentially increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a consequence, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the implementing regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.

We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses that may be sustained in connection with all oil and natural gas activities.

        We maintain general and excess liability policies, which we consider to be reasonable and consistent with industry standards. These policies generally cover:

    personal injury;

    bodily injury;

    third party property damage;

    medical expenses;

    legal defense costs;

    pollution in some cases;

    well blowouts in some cases; and

    workers compensation.

        As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a material effect on our financial position, results of operations and cash flows. There can be no assurance that the insurance coverage that we maintain will be sufficient to cover claims made against us in the future.

Title to the properties in which we have an interest may be impaired by title defects.

        We generally obtain title opinions on significant properties that we drill or acquire. However, there is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. Generally, under the terms of the operating agreements affecting our properties, any monetary loss is to be borne by all parties to any such agreement in proportion to their interests in such property. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

        Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production may increase the demand for oilfield services and equipment, and the costs

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of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies or qualified personnel can materially and adversely affect our operations and profitability. In order to secure drilling rigs and pressure pumping equipment, we have entered into certain contracts that extend over several months and or years. If demand for drilling rigs and pressure pumping equipment subside during the period covered by these contracts, the price we are required to pay may be significantly more than the market rate for similar services.

We depend on the skill, ability and decisions of third-party operators of the oil and natural gas properties in which we have a non-operated working interest.

        The success of the drilling, development and production of the oil and natural gas properties in which we have or expect to have a non-operating working interest is substantially dependent upon the decisions of such third-party operators and their diligence to comply with various laws, rules and regulations affecting such properties. The failure of any third-party operator to make decisions, perform their services, discharge their obligations, deal with regulatory agencies, and comply with laws, rules and regulations, including environmental laws and regulations, in a proper manner with respect to properties in which we have an interest could result in material adverse consequences to our interest in such properties, including substantial penalties and compliance costs. Such adverse consequences could result in substantial liabilities to us or reduce the value of our properties, which could materially affect our results of operations.

Hedging transactions may limit our potential gains and increase our potential losses.

        In order to manage our exposure to price risks in the marketing of our oil, natural gas, and natural gas liquids production, we have entered into oil, natural gas, and natural gas liquids price hedging arrangements with respect to a portion of our anticipated production and we may enter into additional hedging transactions in the future. While intended to reduce the effects of volatile oil, natural gas and natural gas liquids prices, such transactions may limit our potential gains and increase our potential losses if oil, natural gas and natural gas liquids prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

    our production is less than expected;

    there is a widening of price differentials between delivery points for our production; or

    the counterparties to our hedging agreements fail to perform under the contracts.

We may be required to take non-cash asset write downs.

        We may be required under full cost accounting rules to write down the carrying value of oil and natural gas properties if oil and natural gas prices decline or if there are substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration results. We utilize the full cost method of accounting for oil and natural gas exploration and development activities. Under full cost accounting, we are required by SEC regulations to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or "ceiling," of the book value of oil and natural gas properties that is equal to the expected after tax present value (discounted at 10%) of the future net cash flows from proved reserves, including the effect of cash flow hedges when hedge accounting is applied, calculated using the unweighted arithmetic average of the first day of each month for the 12-month period ending at the balance sheet date. If the net book value of oil and natural gas properties (reduced by any related net deferred income tax liability and asset retirement obligation) exceeds the ceiling limitation, SEC regulations require us to impair or "write down" the book value of our oil and natural gas properties.

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        As of December 31, 2014 and March 31, 2014, the net book value of our oil and natural gas properties exceeded our ceiling amount by $178.5 million and $61.2 million before income taxes using the WTI unweighted 12-month average price $94.99 per Bbl and $98.46 per Bbl and the Henry Hub unweighted 12-month average of $4.350 per MMBtu and $3.99 per MMBtu, respectively, resulting in a write-down of our oil and natural gas properties. As ceiling test computations depend upon the calculated unweighted arithmetic average prices and oil and natural gas prices are inherently volatile, it is impossible to predict the likelihood, timing and magnitude of any future impairments. For example, oil and natural gas prices have decreased significantly over the latter half of 2014 and into the beginning of 2015, the first day of the month oil and natural gas prices for January and February 2015 were $53.27 per Bbl and $48.24 per Bbl for oil and $3.00 per MMBtu and $2.68 per MMBtu for natural gas, respectively. If commodity prices remain at decreased levels, the average prices used in the ceiling calculation will decline and will likely cause write downs of our oil and natural gas properties. Continued write downs of oil and natural gas properties may occur until such time as commodity prices have recovered, and remained at recovered levels, so as to meaningfully increase the 12-month average price used in the ceiling calculation. Depending on the magnitude, a ceiling test write down could materially affect our results of operations.

        Costs associated with unevaluated properties, which were approximately $1.8 billion at December 31, 2014, are not initially subject to the ceiling test limitation. Rather, we assess all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value based upon our intentions with respect to drilling on such properties, the remaining lease term, geological and geophysical evaluations, drilling results, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. These factors are significantly influenced by our expectations regarding future commodity prices, development costs, and access to capital at acceptable cost. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the ceiling test limitation. Accordingly, a significant change in these factors, many of which are beyond our control, may shift a significant amount of cost from unevaluated properties into the full cost pool that is subject to depletion and the ceiling test limitation.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

        None.

ITEM 2.    PROPERTIES

        A description of our properties is included in Item 1. Business and is incorporated herein by reference.

        We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our business. We believe that our properties are adequate and suitable for us to conduct business in the future.

ITEM 3.    LEGAL PROCEEDINGS

        A description of our legal proceedings is included in Item 8. Consolidated Financial Statements and Supplementary Data—Note 10, "Commitments and Contingencies," and is incorporated herein by reference.

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        From time to time, we are a party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. We are not currently involved in any legal proceedings, nor are we a party to any pending or threatened claims, that could reasonably be expected to have a material adverse effect on our financial condition or results of operations.

ITEM 4.    MINE SAFETY DISCLOSURES

        Not Applicable.

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PART II

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

        Our common stock trades on the New York Stock Exchange (NYSE) under the symbol HK. The following table sets forth the quarterly high and low sales prices per share of our common stock as reported on the NYSE from January 1, 2013 through December 31, 2014.

 
  High   Low  

2014

             

First Quarter

  $ 4.34   $ 3.16  

Second Quarter

    7.29     4.15  

Third Quarter

    7.50     3.96  

Fourth Quarter

    4.14     1.55  

2013

   
 
   
 
 

First Quarter

  $ 8.23   $ 6.36  

Second Quarter

    7.97     5.13  

Third Quarter

    6.37     4.43  

Fourth Quarter

    5.55     3.63  

        We intend to retain earnings for use in the operation and expansion of our business and therefore do not anticipate declaring cash dividends on our common stock in the foreseeable future. Any future determination to pay dividends on common stock will be at the discretion of the board of directors and will be dependent upon then existing conditions, including our prospects, and such other factors, as the board of directors deems relevant. We are also restricted from paying cash dividends on common stock under our Senior Credit Agreement and under the terms of the indentures governing our other long-term debt.

        Approximately 921 registered stockholders of record as of February 23, 2015 held our common stock. In many instances, a stockholder can hold shares through a broker or other entity holding shares in street name for one or more customers who beneficially own the shares.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

        The following table sets forth certain information with respect to the surrender of our common stock by employees in exchange for the payment of certain tax withholding obligations during the three months ended December 31, 2014.

 
  Total Number
of Shares
Purchased
(1)
  Average Price
Paid Per Share
  Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs
  Maximum Number (or
Approximate Dollar
Value) of Shares that
May Yet Be Purchased
Under the Plans or
Programs
 

October 2014

    1,109   $ 3.26          

November 2014

    1,698     3.11          

December 2014

                 

(1)
All of the shares were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards. The acquisition of the surrendered shares was not part of a publicly announced program to repurchase shares of our common stock, nor were they considered as or accounted for as treasury stock.

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Five-Year Stock Performance Graph

        The following graph and table compare the cumulative 5-year total return provided to our stockholders on our common stock beginning December 31, 2009 through December 31, 2014, relative to the cumulative total returns of the NYSE Composite Index and the S&P Midcap Oil & Gas Exploration & Production Index. The comparison assumes an investment of $100 (with reinvestment of all dividends at the average of the closing stock prices at the beginning and end of the quarter) was made in our common stock on December 31, 2009, and in each of the indexes, and relative performance is tracked through December 31, 2014. The identity of the companies included in the S&P Midcap Oil & Gas Exploration & Production Index will be provided upon request.


COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN
Among Halcón Resources Corporation, the NYSE Composite Index,
and the S&P Midcap Oil & Gas Exploration & Production Index

GRAPHIC

Value of Initial $100 Investment (End of Year)

 
  Years Ended December 31,  
 
  2009   2010   2011   2012   2013   2014  

Halcón Resources Corporation

  $ 100   $ 90   $ 153   $ 113   $ 63   $ 29  

NYSE Composite

    100     113     109     126     160     170  

S&P Midcap Oil & Gas Exploration & Production Index

    100     151     144     128     203     152  

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ITEM 6.    SELECTED FINANCIAL DATA

        The following table presents selected historical financial data derived from our consolidated financial statements. The following data is only a summary and should be read with our historical consolidated financial statements and related notes contained in this document. Refer to Item 1. Business—Recent Developments, for details regarding recent acquisitions, and business combinations and dispositions that could impact the comparability of the following data.

 
  Years Ended December 31,  
 
  2014(7)   2013(8)   2012   2011   2010  
 
  (In thousands, except per share data)
 

Income Statement Data:

                               

Total operating revenues

  $ 1,148,261   $ 999,506   $ 248,322   $ 104,574   $ 112,621  

Income (loss) from operations

    (58,387 )   (1,290,947 )   (29,717 )   19,799     24,526  

Net income (loss)

    315,956     (1,222,662 )   (53,885 )   (1,403 )   2,417  

Net income (loss) available to common stockholders

    282,942     (1,233,407 )   (142,330 )   (1,403 )   2,417  

Net income (loss) per share of common stock(1):

                               

Basic

  $ 0.68   $ (3.25 ) $ (0.91 ) $ (0.05 ) $ 0.09  

Diluted

  $ 0.59   $ (3.25 ) $ (0.91 ) $ (0.05 ) $ 0.09  

 

 
  As of December 31,  
 
  2014   2013   2012   2011   2010  
 
  (In thousands)
 

Balance sheet data:

                               

Working capital (deficit)

  $ (41,977 ) $ (325,756 ) $ (390,111 ) $ (7,620 ) $ (13,878 )

Total assets

    6,434,475     5,356,491     5,041,025     267,174     260,733  

Total long-term debt(2)(3)

    3,746,736     3,183,823     2,034,498     202,000     196,965  

Redeemable noncontrolling interest(4)

    117,166                  

Preferred stock(5)

            695,238          

Stockholders' equity (deficit)(5)(6)

    1,772,169     1,447,610     1,397,982     1,680     (101 )

(1)
No cash dividends on our common stock were declared or paid for any periods presented.

(2)
Excludes current portion of long-term debt for all periods presented.

(3)
On December 21, 2011, we entered into a Securities Purchase Agreement with HALRES LLC, formerly Halcón Resources, LLC (HALRES), in which HALRES purchased and we sold 73.3 million shares of our common stock for a purchase price of $275 million and HALRES purchased and we issued a senior convertible promissory note in the principal amount of $275 million, together with five year warrants to purchase 36.7 million shares of our common stock at an exercise price of $4.50 per share, subject to adjustment under certain circumstances. For additional information regarding this recapitalization, see Item 8. Consolidated Financial Statements and Supplementary Data—Note 2, "Recapitalization."

(4)
On June 16, 2014, our subsidiary, HK TMS, LLC (HK TMS) entered into a transaction with funds and accounts managed by Apollo Global Management, LLC, by initially selling 150,000 preferred shares in HK TMS, which holds all of our acreage in Mississippi and Louisiana believed to be prospective for the TMS. For additional information regarding this transaction, see Item 8. Consolidated Financial Statements and Supplementary Data—Note 11, "Mezzanine Equity."

(5)
Preferred stock outstanding at December 31, 2012 converted into 108.8 million shares of Halcón common stock on January 18, 2013, following stockholder approval.

(6)
On March 5, 2012, we sold in a private placement 4,444.4511 shares of 8% automatically convertible preferred stock (Preferred Stock), par value $0.0001 per share, each share of which automatically

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    converted into 10,000 shares of our common stock on April 17, 2012. We received gross proceeds of approximately $400.0 million, or $9.00 per share of common stock, before offering expenses. No cash dividends were paid on the Preferred Stock as it converted into common stock before May 31, 2012. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 12, "Stockholders' Equity," for additional information regarding the offering and subsequent conversion.

(7)
For the year ended December 31, 2014, we incurred the following charges, a $239.7 million full cost ceiling impairment on the carrying value of oil and natural gas properties and a $35.6 million impairment on other operating property and equipment. Refer to the footnotes included in Item 8. Consolidated Financial Statements and Supplementary Data, for additional information regarding these impairments.

(8)
For the year ended December 31, 2013, we incurred the following charges which contributed to our net loss for the year, a $1.1 billion full cost ceiling impairment on the carrying value of our oil and natural gas properties, a $228.9 million goodwill impairment, and a $67.5 million impairment of other operating property and equipment. Refer to the footnotes included in Item 8. Consolidated Financial Statements and Supplementary Data, for additional information regarding these impairments.

ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The following discussion is intended to assist in understanding our results of operations and our current financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K 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, including those discussed below, which could cause actual results to differ from those expressed.

Overview

        We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. We were incorporated in Delaware on February 5, 2004 and were recapitalized on February 8, 2012. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in selected prospect areas, providing us with an extensive drilling inventory in multiple basins that we believe allow for multiple years of production growth and broad flexibility to direct our capital resources to projects with the greatest potential returns. During 2013 and 2014, we focused on the development of acquired properties and also divested non-core assets in order to fund activities in our core resource plays.

        At December 31, 2014, our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc. (Netherland, Sewell), were approximately 189.1 MMBoe, consisting of 155.6 MMBbls of oil, 16.3 MMBbls of natural gas liquids, and 103.7 Bcf of natural gas. Approximately 41% and 40% of our proved reserves were classified as proved developed as of December 31, 2014 and 2013, respectively. We maintain operational control of approximately 93% of our proved reserves. Production for the fourth quarter of 2014 averaged 46,076 Boe/d. Full year 2014 production averaged 42,107 Boe/d compared to 33,329 Boe/d in 2013. Our total operating revenues for 2014 were approximately $1.1 billion compared to $999.5 million in 2013.

        Our oil and natural gas assets consist of undeveloped acreage positions in unconventional liquids-rich basins/fields. We have acquired acreage and may acquire additional acreage in the Bakken / Three Forks formations in North Dakota and the Eagle Ford formation in East Texas, as well as several other areas.

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        Our average daily production increased 26% year over year. The increase in production compared to the prior year period was driven by our operated drilling results and increased production volumes associated with the development of properties we have acquired in the Bakken / Three Forks and the Eagle Ford formation in East Texas (which we refer to as "El Halcón"). These areas collectively accounted for approximately 37,500 Boe/d in 2014, or 89% of our production. In 2014, we participated in the drilling of 320 gross (98.3 net) wells all of which were completed and capable of production.

        Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

        For the twelve months ended December 31, 2014 we incurred capital expenditures for drilling and completions of approximately $1.2 billion. We expect to spend approximately $350 million to $400 million on drilling and completion capital expenditures during 2015. In addition, we expect to spend approximately $20 million on leasehold, infrastructure, seismic and other in 2015. The significant decrease in planned capital spending for 2015, as compared to actual 2014 drilling and completion capital expenditures, is in response to the significant decrease in crude oil prices over the latter half of 2014 and our expectations that prices may not recover in the near term. Approximately 60 - 65% of our 2015 drilling and completions budget is expected to be spent in the Bakken / Three Forks formations in North Dakota, approximately 30 - 35% is budgeted for the El Halcón area in East Texas, and the remaining amount is planned for various other project areas. Our 2015 drilling and completion budget contemplates two operated rigs running in the Bakken / Three Forks and one operated rig running in the El Halcón area. Our drilling and completion budget for 2015 is based on our current view of market conditions and current business plans, and is subject to change.

        We expect to fund our budgeted 2015 capital expenditures with cash flows from operations, proceeds from potential capital market transactions, and borrowings under our Senior Credit Agreement. We strive to maintain financial flexibility and may access capital markets as necessary to maintain substantial borrowing capacity under our Senior Credit Agreement, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position and infrastructure projects. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may further curtail our capital spending.

        Oil and natural gas prices are inherently volatile and, as mentioned above, decreased significantly over the latter half of 2014. Sustained lower commodity prices will likely have a material impact upon our full cost ceiling test calculation. The ceiling calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. For the year ended December 31, 2014, those prices were $94.99 per Bbl for oil and $4.350 per MMBtu for natural gas, while first day of the month oil and natural gas prices for January and February 2015 were $53.27 per Bbl and $48.24 per Bbl for oil and $3.00 per MMBtu and $2.68 per MMBtu for natural gas, respectively. If commodity prices remain at decreased levels, the average prices used in the ceiling calculation will decline and will likely cause write downs of our oil and natural gas properties. Continued write downs of oil and natural gas properties may occur until such time as commodity prices have recovered, and remained at recovered levels, so as to meaningfully increase the 12-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

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Recent Developments

Amendments to the Senior Credit Agreement and Borrowing Base Confirmation

        On February 25, 2015, we entered into the Ninth Amendment to our Senior Credit Agreement (the Ninth Amendment). The Ninth Amendment provides additional flexibility under the interest coverage test by modifying the minimum Interest Coverage Ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before March 31, 2016. On February 25, 2015, the borrowing base under the Senior Credit Agreement was confirmed at $1.05 billion.

        On September 30, 2014, we entered into the Eighth Amendment to our Senior Credit Agreement (the Eighth Amendment). The Eighth Amendment increased the borrowing base under our Senior Credit Agreement to $1.05 billion. On March 21, 2014, we entered into the Seventh Amendment to our Senior Credit Agreement (the Seventh Amendment). The Seventh Amendment provided us additional flexibility under the interest coverage test by modifying the minimum Interest Coverage Ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before December 31, 2014.

HK TMS, LLC Preferred Stock Issuance

        On June 16, 2014, we entered into a transaction with funds and accounts managed by affiliates of Apollo Global Management, LLC (Apollo) pursuant to which HK TMS, LLC (HK TMS), our subsidiary which holds our acreage in Mississippi and Louisiana that we believe is prospective for the Tuscaloosa Marine Shale (TMS), initially sold 150,000 preferred shares in exchange for $150 million and the right to overriding royalty interests in future wells. HK TMS does not participate in our Senior Credit Agreement and is not a guarantor of any of our senior notes.

Divestiture of East Texas Assets

        On May 9, 2014, we completed the divestiture of certain non-core assets in East Texas (the East Texas Assets) to a privately-owned company for a total purchase price of $424.5 million after closing adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. As of December 31, 2013, estimated proved reserves associated with the East Texas Assets, were approximately 16.3 MMBoe. Production from the East Texas Assets averaged approximately 3,700 Boe/d during the first quarter of 2014. The effective date of the transaction was April 1, 2014. Proceeds from the sale were recorded as a reduction to the carrying value our full cost pool with no gain or loss recorded.

Capital Resources and Liquidity

        Our near-term capital spending requirements are expected to be funded with cash flows from operations, proceeds from potential capital market transactions and borrowings under our Senior Credit Agreement, which has a current borrowing base of $1.05 billion. Our borrowing base is redetermined on a semi-annual basis (with us and the lenders each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations) and adjusted based on the estimated value of our oil and natural gas reserves, the amount and cost of our other indebtedness and other relevant factors. Our ability to utilize the full amount of our borrowing capacity is influenced by a variety of factors, including redeterminations of our borrowing base, and covenants under our Senior Credit Agreement and our senior unsecured debt indentures. Our Senior Credit Agreement contains customary financial and other covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and minimum coverage of interest expenses (as defined in the Senior Credit Agreement) of i) not less than 2.0 to 1.0 through March 31, 2016 (pursuant to the Ninth Amendment), and ii) not less than 2.5 to 1.0 for subsequent periods. We are subject to additional

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covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. Additionally, the indentures governing our senior unsecured debt contain covenants limiting our ability to incur additional indebtedness, including borrowings under our Senior Credit Agreement, unless we meet one of two alternative tests. The first test, the fixed charge coverage ratio test, applies to all indebtedness and requires that after giving effect to the incurrence of additional debt the ratio of our adjusted consolidated EBITDA (as defined in our indentures) to our adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0. The second test allows us to incur additional indebtedness, beyond the limitations of the fixed charge coverage ratio test, as long as this additional debt is incurred under Credit Facilities (as defined in our indentures) and the amount of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of our adjusted consolidated net tangible assets (as defined in all of our indentures), which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves as of the date of such determination. At December 31, 2014, we had $557.0 million of indebtedness outstanding, $1.1 million of letters of credit outstanding and $491.9 million of borrowing capacity available under our Senior Credit Agreement.

        Our ability to meet our debt covenants and our capacity to incur additional indebtedness will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. For example, lower oil and natural gas prices could result in a redetermination of the borrowing base under our Senior Credit Agreement at a lower level and reduce our adjusted consolidated EBITDA, as well as our adjusted consolidated net tangible assets as determined under our indentures, and thus could reduce our ability to incur indebtedness. Our strategic divestitures of non-core producing properties in favor of investing in undeveloped acreage, coupled with our aggressive drilling plans have also impacted our near-term ability to comply with our debt covenants, particularly the interest coverage test under our Senior Credit Agreement and the fixed charge coverage ratio under our indentures by reducing our production and reserves on a current and, for purposes of covenant calculations, a pro forma historical basis, while drilling takes time to replace these losses. Of course, over the longer term, we expect that our strategy and our investments will result in increased production and reserves, lower lease operating costs and more abundant drilling opportunities. As a consequence, we constantly monitor our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues and work with the lenders under our Senior Credit Agreement to address any such issues ahead of time.

        We have in the past obtained amendments to the covenants under our Senior Credit Agreement under circumstances where we anticipated that it might be challenging for us to comply with our financial covenants for a particular period of time. During 2013, we obtained amendments to the calculation of the interest coverage ratio covenant under our Senior Credit Agreement allowing us to annualize our quarterly EBITDA because, among other things, we anticipated that our strategic decision to divest various non-core producing properties and invest in the acquisition and drilling of undeveloped acreage would have caused us to fall below the interest coverage ratio. We requested reductions in the minimum required interest coverage ratio of 2.0 to 1.0 for 2014 and 2015 and those requests were granted on March 21, 2014 and again on February 25, 2015, respectively. The basis for the amendment request is similar to previously requested waivers described above, i.e., the potential for us to fall out of compliance primarily as a result of our strategic decision to divest producing properties, invest extensively in undeveloped acreage and the long lead times associated with replacing lost production through our drilling program. As part of our plan to manage liquidity risks and in recognition of lower oil prices, we have scaled back our capital expenditures budget, focused our drilling program on our highest return projects, entered into a transaction with funds and accounts managed by the affiliates of Apollo Global Management, LLC, to finance the development of our TMS assets, and we continue to explore opportunities to divest non-core properties.

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        If, in the future, the lenders under our Senior Credit Agreement are unwilling to provide us with the covenant flexibility we seek, and we are unable to comply with those covenants, we may be forced to repay or refinance amounts then outstanding under the Senior Credit Agreement and seek alternative sources of capital to fund our business and anticipated capital expenditures. In the event that we are unable to access sufficient capital to fund our business and planned capital expenditures, we may be required to curtail our drilling, development, land acquisition and other activities, which could result in a decrease in our production of oil and natural gas, may be subject to forfeitures of leasehold interests to the extent we are unable or unwilling to renew them, and may be forced to sell some of our assets on an untimely or unfavorable basis, each of which could adversely affect our results of operations and financial condition. Further, the failure to comply with the restrictive covenants relating to our indebtedness could result in the declaration of a default and cross default under the instruments governing our indebtedness, potentially resulting in acceleration of our obligations and adversely impacting our financial condition.

        Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing reserves and production and finding additional reserves. Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves, which is typical in the capital-intensive oil and natural gas industry. We therefore continuously monitor our liquidity and the capital markets and evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources, acquisition opportunities and drilling success.

        We strive to maintain financial flexibility while pursuing our drilling plans and evaluating potential acquisitions, and will therefore likely continue to access capital markets (if on acceptable terms) as necessary to, among other things, maintain substantial borrowing capacity under our Senior Credit Agreement, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position and infrastructure projects while sustaining sufficient operating cash levels. Our ability to complete future debt and equity offerings and maintain or increase our borrowing base is subject to a number of variables, including our level of oil and natural gas production, reserves and commodity prices, as well as various economic and market conditions that have historically affected the oil and natural gas industry. Even if we are otherwise successful in growing our reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.

        We are exposed to various risks including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly, as they have in the latter half of 2014, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include costless collars, swaps, and deferred put options. The total volumes which we hedge through the use of our derivative instruments varies from period to period, however, generally our objective is to hedge approximately 70% to 80% of our current and anticipated production for the next 18 to 24 months. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

Cash Flow

        Our primary sources of cash in 2014 were from operating and financing activities. In 2013 and 2012, our primary source of cash was from financing activities. In 2014, cash provided by operations

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was driven by increased revenues and cash provided by financing activities was attributable to net borrowings on our Senior Credit Agreement and the sale of HK TMS preferred stock to Apollo.

        Operating cash flow fluctuations were substantially driven by changes in commodity prices and changes in our production volumes. Working capital was substantially influenced by these variables. Fluctuation in commodity prices and our overall cash flow may result in an increase or decrease in our future capital expenditures. Prices for oil and natural gas have historically been subject to seasonal fluctuations characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout recent years. See Results of Operations below for a review of the impact of prices and volumes on sales.

 
  Years Ended December 31,  
 
  2014   2013   2012  
 
  (In thousands)
 

Cash flows provided by (used in) operating activities

  $ 667,934   $ 493,924   $ 84,360  

Cash flows provided by (used in) investing activities

    (1,271,093 )   (2,100,699 )   (2,832,466 )

Cash flows provided by (used in) financing activities

    644,038     1,607,103     2,750,563  

Net increase (decrease) in cash

  $ 40,879   $ 328   $ 2,457  

        Operating Activities.    Net cash flows provided by operating activities were $667.9 million, $493.9 million and $84.4 million for the years ended December 31, 2014, 2013 and 2012, respectively. Key drivers of net operating cash flows are commodity prices, production volumes, operating costs and realized settlements on our derivative contracts.

        For the year ended December 31, 2014, net cash provided by operating activities increased $174.0 million over the prior year. The improvement in operating cash flows primarily reflects the impact of the 26% increase in our average daily production compared to the 2013 period, which drove the increase in operating revenues. Production for 2014 averaged 42,107 Boe/d compared to 33,329 Boe/d in 2013.

        Net loss for the year ended December 31, 2013 was $1.2 billion. Non-cash items, including a $1.1 billion full cost ceiling impairment, $228.9 million goodwill impairment, $67.5 million other operating property and equipment impairment and $463.7 million depreciation, depletion and accretion served to more than offset this net loss. The improvement in operating cash flows primarily reflects the impact of the 254% increase in our average daily production compared to the 2012 period, which drove the significant increase in operating revenues.

        Net loss for the year ended December 31, 2012 was $53.9 million. Non-cash items, including $90.3 million of depreciation, depletion and accretion, $9.4 million of non-cash interest and amortization and $6.2 million of amortization and write-off of deferred loan costs served to offset this net loss. Our Recapitalization, including change in control and related activities which occurred during February 2012, our acquisition of GeoResources, Inc. and transaction costs, and the impact of additional personnel and facilities in support of our expanding business base, drove a significant increase in general and administrative expenditures, which adversely affected our operating cash flows. The remaining improvement in operating cash flows is largely attributable to a favorable mix in working capital changes.

        Investing Activities.    The primary driver of cash used in investing activities is capital spending on our oil and natural gas properties. Net cash used in investing activities was $1.3 billion, $2.1 billion and $2.8 billion for the years ended December 31, 2014, 2013 and 2012, respectively.

        In 2014, we incurred cash expenditures of $1.5 billion on oil and natural gas capital expenditures, of which $1.2 billion related to drilling and completion costs and the remainder was primarily

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associated with leasing, acquisitions and seismic data. We participated in the drilling of 320 gross (98.3 net) wells, all of which were completed and capable of production. These expenditures were offset by $484.2 million in proceeds received from the divestitures of various non-core assets, including the East Texas Assets. As part of HK TMS's transaction with Apollo, discussed in further detail below, as well as in Item 8. Consolidated Financial Statements and Supplementary Data—Note 11, "Mezzanine Equity," we received proceeds of approximately $33.8 million from the conveyance of an overriding royalty interest to Apollo.

        On December 20, 2013, we entered into a carry and earning agreement, as amended (the Agreement) with an independent third party (the Seller) associated with the acquisition of certain properties believed to be prospective for the TMS, primarily in Wilkinson County, Mississippi and in West Feliciana and East Feliciana Parishes, Louisiana. The agreement required us to fund up to $189.4 million (the Carry Amount) in exchange for approximately 117,870 net acres. We paid $62.5 million of the Carry Amount at closing on February 28, 2014 and the remaining $126.9 million during the three months ended June 30, 2014, reflected as "Advance on carried interest" in the accompanying consolidated statements of cash flows. The Carry Amount is to be used by the Seller to fund wells prospective for the TMS to be drilled by the Seller (the Carry Wells) on the Seller's retained acreage. As part of the transaction, we will also receive a 5% working interest in the Carry Wells. As of December 31, 2014, approximately $71.9 million of the Carry Amount remained in escrow to be spent by the Seller. Any portion of the Carry Amount not spent by the Seller, in accordance with the Agreement, on or before August 31, 2017, will be returned to us.

        In 2013, we incurred cash expenditures of $2.4 billion on oil and natural gas capital expenditures, of which $1.5 billion related to drilling and completion costs and the remainder was primarily associated with leasing, acquisitions and seismic data. These expenditures were offset by $448.3 million in proceeds received from the sale of our Eagle Ford properties and other non-core asset divestitures. We participated in the drilling of 284 gross (107.4 net) wells of which 281 gross (104.4 net) wells were completed and capable of production and 3 gross (3.0 net) wells were dry holes. We spent an additional $139.3 million on other operating property and equipment capital expenditures primarily related to gathering and transportation systems.

        In 2012, we incurred cash expenditures of $579.5 million, net of cash acquired, on our acquisition of GeoResources, Inc., $756.1 million on the acquisition of the Williston Basin Assets, and $296.1 million on our acquisition of the East Texas Assets. Additionally, we spent $1.2 billion on drilling and completion wells, infrastructure projects and other leasehold acquisitions. We participated in the drilling of 192 gross (88.2 net) wells of which 189 gross (85.3 net) wells were completed and capable of production and 3 gross (2.9 net) wells were dry holes. We also drilled and completed 6 gross (5.0 net) salt water disposal wells. We spent an additional $38.5 million on other operating property and equipment capital expenditures primarily related to gathering and transportation systems. Proceeds from sales of oil and natural gas properties were $22.0 million.

        Financing Activities.    Net cash flows provided by financing activities were $644.0 million, $1.6 billion and $2.8 billion for the years ended December 31, 2014, 2013 and 2012, respectively. The primary drivers of cash provided by financing activities are proceeds from the issuance of our senior notes, common stock and preferred stock, and borrowings under our Senior Credit Agreement.

        Cash flows provided by financing activities include net borrowings under our Senior Credit Agreement of $557.0 million for the year ended December 31, 2014, primarily used to fund drilling and completion activities.

        On June 16, 2014, our subsidiary, HK TMS, entered into a transaction with Apollo by initially selling 150,000 preferred shares in HK TMS, which holds all of our acreage in Mississippi and Louisiana believed to be prospective for the TMS. Apollo contributed $150 million to HK TMS, and we contributed all our assets related to the TMS as well as $50 million in cash. The proceeds from

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Apollo were allocated as follows: $110.1 million of proceeds associated with the issuance of HK TMS preferred stock and approximately $4.5 million associated with Apollo's rights to additional preferred shares within cash flows from financing activities and the aforementioned $33.8 million investing cash flows related to the overriding royalty conveyance. The proceeds are being used to develop the TMS.

        On December 19, 2013, we issued an additional $400.0 million aggregate principal amount of our 9.75% senior notes due 2020 at a price to the initial purchasers of 102.750% of par. The net proceeds from the sale of the additional 2020 Notes of approximately $406.3 million, after deducting offering fees and expenses, were used to repay a portion of the then outstanding borrowings under our Senior Credit Agreement.

        On August 13, 2013, we completed the issuance of $400.0 million aggregate principal amount of our 2022 Notes. The net proceeds to us from the offering were approximately $392.1 million after deducting commissions and offering expenses and were used to repay a portion of the then outstanding borrowings under our Senior Credit Agreement.

        On August 13, 2013, we also issued of 43.7 million shares of common stock in an underwritten public offering. The net proceeds from the offering of our common stock were approximately $215.2 million, after deducting the underwriting discount and estimated offering expenses. We used the net proceeds from the offering to repay a portion of the then outstanding borrowings on our Senior Credit Agreement.

        On June 18, 2013, we issued 345,000 shares of our Series A Preferred Stock in a public offering at a price of $1,000 per share. The net proceeds to us from the offering of the Series A Preferred Stock were approximately $335.2 million, after deducting the underwriting discount and offering expenses. We used the net proceeds from the offering to repay a portion of the then outstanding borrowings under our Senior Credit Agreement.

        On January 14, 2013, we issued an additional $600.0 million aggregate principal amount of our 2021 Notes at a price to the initial purchasers of 105% of par. The net proceeds from the sale of the additional 2021 Notes were approximately $619.5 million, after deducting offering fees and expenses. We used the net proceeds from the offering to repay all of the then outstanding borrowings under our Senior Credit Agreement and for general corporate purposes, including funding a portion of our 2013 capital expenditures program.

        On December 6, 2012, in conjunction with the closing of the Williston Basin Assets acquisition, we received net proceeds of approximately $294.0 million from the private placement of 41.9 million shares of our common stock with CPP Investment Board PMI-2, Inc., which acquired the shares for a purchase price of approximately $7.16 per share.

        On November 6, 2012, we issued $750.0 million aggregate principal amount of our 8.875% senior notes due 2021. Net proceeds of $725.6 million from the offering were placed into escrow pending the acquisition of the Williston Basin Assets and were subsequently released upon closing and used to fund a portion of the cash consideration paid in the acquisition.

        On July 16, 2012, we issued $750.0 million aggregate principal amount of 9.75% senior notes due 2020. Net proceeds of $723.1 million from the offering were placed into escrow pending our acquisition of GeoResources, Inc. and subsequently released from escrow on August 1, 2012 and utilized to fund our acquisition of GeoResources, Inc. and the East Texas Assets.

        On March 5, 2012, we issued shares of automatically convertible preferred stock that subsequently converted into approximately 44.4 million shares of common stock for gross proceeds of $400.0 million. We used the proceeds for general corporate purposes.

        On February 8, 2012, HALRES LLC recapitalized us with a $550.0 million investment structured as the purchase of $275.0 million in new common stock, a $275.0 million five-year 8.0% convertible

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note and warrants for the purchase of an additional 36.7 million shares of our common stock at an exercise price of $4.50 per share. The convertible note provided $231.4 million cash flow from borrowings and $43.6 million cash flow from warrants issued. In connection with the closing of the Recapitalization, we entered into our Senior Credit Agreement and terminated our prior credit facilities with the payoff of the $210.8 million balance.

        Cash flows provided by financing activities include net borrowings under our Senior Credit Agreement of $298.0 million for the year ended December 31, 2012, primarily used to fund our acquisition activities and our ongoing drilling activities.

Contractual Obligations

        We have a significant degree of flexibility to adjust the level of our future capital expenditures as circumstances warrant. Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, developmental and exploration activities, oil and natural gas price conditions, our access to capital and liquidity and other related economic factors. We currently have no material off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities. The following table summarizes our contractual obligations and commitments by payment periods as of December 31, 2014.

 
  Payments Due by Period  
Contractual Obligations
  Total   2015   2016 - 2017   2018 - 2019   2020 and
Beyond
 
 
  (In thousands)
 

Senior revolving credit facility

  $ 557,000   $   $ 557,000   $   $  

9.25% senior notes due 2022

    400,000                 400,000  

8.875% senior notes due 2021(1)

    1,350,000                   1,350,000  

9.75% senior notes due 2020(2)

    1,150,000                 1,150,000  

8.0% convertible note(3)

    289,669         289,669            

Interest expense on long-term debt(4)

    1,730,300     307,616     580,706     537,876     304,102  

Operating leases

    59,993     8,959     17,928     18,311     14,795  

Drilling rig commitments

    75,456     31,400     40,696     3,360      

Other commitments

    10,518     10,518              

Total contractual obligations

  $ 5,622,936   $ 358,493   $ 1,485,999   $ 559,547   $ 3,218,897  

(1)
Excludes $4.6 million unamortized discount recorded in conjunction with the issuance of the original 2021 Notes and a $24.6 million unamortized premium recorded in conjunction with the issuance of the additional 2021 Notes.

(2)
Excludes $7.9 million unamortized discount recorded in conjunction with the issuance of the original 2020 notes and a $9.7 million unamortized premium recorded in conjunction with the issuance of the additional 2020 Notes.

(3)
Excludes $21.8 million unamortized discount recorded in conjunction with the issuance of the note.

(4)
Future interest expense was calculated based on interest rates and amounts outstanding at December 31, 2014 less required annual repayments.

        In January 2015, we made the decision to early terminate a drilling rig contract in response to the recent decline in crude oil prices, and as such, will incur an early termination fee of $6.0 million, payable over the first half of 2015. If certain requirements are not met during the period ending January 2020, we may incur up to an additional $3.0 million in connection with this drilling rig contract. In addition, we have a new drilling rig commitment, scheduled to begin in the second quarter of 2015, for which we expect to incur a stacking fee of $17,000 per day. The current rig contract term extends through the second quarter of 2018. These obligations are not included in the table above and will be reflected as expense when incurred.

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        We also have various long-term gathering, transportation and sales contracts in the Bakken / Three Forks formations in North Dakota which are not included in the table above. As of December 31, 2014, we had in place nine long-term crude oil contracts and two long-term natural gas contracts in this area and the sales prices under these contracts are based on posted market rates. Under the terms of these contracts we have committed a substantial portion of our Bakken / Three Forks production for periods ranging from five to ten years from the date of first production. We believe that there are sufficient available reserves and supplies in the Bakken / Three Forks formations to meet our commitments, as the proved reserves from this area represent approximately 74% of our total proved reserves. Historically, we have been able to meet our delivery commitments.

        On December 20, 2013, we entered into a carry and earning agreement, as amended with an independent third party associated with the acquisition of certain properties believed to be prospective for the TMS, primarily in Wilkinson County, Mississippi and in West Feliciana and East Feliciana Parishes, Louisiana. The Agreement required us to fund up to $189.4 million in exchange for approximately 117,870 net acres. We paid $62.5 million of the Carry Amount at closing on February 28, 2014 and the remaining $126.9 million during the three months ended June 30, 2014, reflected as "Advance on carried interest" in the accompanying consolidated statements of cash flows. The Carry Amount is to be used by the Seller to fund wells prospective for the TMS to be drilled by the Seller on the Seller's retained acreage. As part of the transaction, we will also receive a 5% working interest in the Carry Wells. As of December 31, 2014, approximately $71.9 million of the Carry Amount remained in escrow to be spent by the Seller. Any portion of the Carry Amount not spent by the Seller, in accordance with the Agreement, on or before August 31, 2017, will be returned to us.

        On June 16, 2014, we entered into a transaction to develop our TMS assets with funds and accounts managed by affiliates of Apollo Global Management, LLC. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 11, "Mezzanine Equity," for a discussion of the drilling obligation associated with the transaction.

        The contractual obligations table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. In addition, amounts related to our asset retirement obligations are not included in the table above given the uncertainty regarding the actual timing of such expenditures. The total estimated amount of our asset retirement obligations at December 31, 2014 was $38.5 million.

Senior Revolving Credit Facility

        In connection with the closing of the Recapitalization, discussed in Item 8. Consolidated Financial Statements and Supplementary Data—Note 2, "Recapitalization," we entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto on February 8, 2012. The Senior Credit Agreement provides for a $1.5 billion facility with a current borrowing base of $1.05 billion. Amounts borrowed under the Senior Credit Agreement will mature on February 8, 2017. The borrowing base will be redetermined semi-annually, with the lenders and us each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of our oil and natural gas reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The borrowing base is subject to a reduction equal to the product of 0.25 multiplied by the stated principal amount (without regard to any initial issue discount) of any future notes or other long-term debt securities that we may issue. Funds advanced under the Senior Credit Agreement may be paid down and re-borrowed during the five-year term of the revolver. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 0.50% to 1.50% for ABR-based loans or at specified margins over LIBOR of 1.50% to 2.50% for Eurodollar-based loans. These margins fluctuate based on our utilization of the facility. Advances under the Senior Credit

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Agreement are secured by liens on substantially all of our properties and assets. The Senior Credit Agreement contains customary representations, warranties and covenants including, among others, restrictions on the payment of dividends on our capital stock and financial covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and minimum coverage of interest expenses (as defined in the Senior Credit Agreement) of i) not less than 2.0 to 1.0 through March 31, 2016 (pursuant to the Ninth Amendment, discussed below) and ii) not less than 2.5 to 1.0 for subsequent periods.

        At December 31, 2014, we had $557.0 million of indebtedness outstanding under our Senior Credit Agreement, $1.1 million of letters of credit outstanding and $491.9 million of borrowing capacity available under our Senior Credit Agreement.

Amendments to the Senior Credit Agreement and Borrowing Base Confirmation

        On February 25, 2015, we entered into the Ninth Amendment to our Senior Credit Agreement. The Ninth Amendment provides additional flexibility under the interest coverage test by modifying the minimum Interest Coverage Ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before March 31, 2016. On February 25, 2015, the borrowing base under the Senior Credit Agreement was confirmed at $1.05 billion.

        On September 30, 2014, we entered into the Eighth Amendment to our Senior Credit Agreement. The Eighth Amendment increased the borrowing base under our Senior Credit Agreement to $1.05 billion. On March 21, 2014, we entered into the Seventh Amendment to our Senior Credit Agreement. The Seventh Amendment provided us additional flexibility under the interest coverage test by modifying the minimum Interest Coverage Ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before December 31, 2014.

March 2011 Credit Facilities

        Our March 2011 credit facilities included a $250.0 million revolving credit facility and a $75.0 million second lien term loan facility, replacing the November 2007 facility. SunTrust Bank was the administrative agent for the revolving credit facility, and Guggenheim Corporate Funding, LLC was the administrative agent for the second lien term loan facility. The revolving credit facility allowed for funds advanced to be paid down and re-borrowed during the five-year term of the revolver, and bore interest at LIBOR plus a margin ranging from 2.5% to 3.25% based on a percentage of usage. The second lien term loan facility provided for payments of interest only during its 5.5 year term, and bore interest at LIBOR plus 9.0% with a 2.0% LIBOR floor, or if any period we elected to pay a portion of the interest "in kind," then the interest rate would have been LIBOR plus 10.0% with a 2.0% LIBOR floor, and with 7.0% of the interest amount paid in cash and the remaining 3.0% paid-in-kind by being added to principal. At December 31, 2011, $127.0 million was outstanding under the revolving credit facility and $75.0 million was outstanding under the second lien term loan facility. On February 8, 2012, we paid in full the outstanding balances under the revolving credit facility and the second lien term loan facility and both facilities were terminated, resulting in a $1.5 million charge to interest expense related to an early termination penalty.

9.25% Senior Notes

        On August 13, 2013, we issued at par $400.0 million aggregate principal amount of 9.25% senior notes due 2022 (the 2022 Notes). The net proceeds from the offering of approximately $392.1 million (after deducting commissions and offering expenses) were used to repay a portion of the then outstanding borrowings under our Senior Credit Agreement.

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        The 2022 Notes bear interest at a rate of 9.25% per annum, payable semi-annually on February 15 and August 15 of each year, beginning on February 15, 2014. The 2022 Notes will mature on February 15, 2022. The 2022 Notes are senior unsecured obligations of ours, rank equally with all of our current and future senior indebtedness and are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by our existing 100% owned subsidiaries, except for one subsidiary, HK TMS, LLC. We, the issuer of the 2022 Notes, have no material independent assets or operations apart from the assets and operations of our subsidiaries.

8.875% Senior Notes

        On November 6, 2012, we completed a private offering of $750.0 million aggregate principal amount of 8.875% senior notes due 2021, issued at 99.247% of par (the 2021 Notes). The net proceeds from the offering were approximately $725.6 million after deducting the initial purchasers' discounts, commissions and offering expenses and were used to fund a portion of the cash consideration paid in the Williston Basin Assets acquisition. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 4, "Acquisitions and Divestitures," for additional information regarding the Williston Basin Assets acquisition.

        On January 14, 2013, we completed the issuance of an additional $600.0 million aggregate principal amount of 2021 Notes, issued at 105% of par. The net proceeds from the sale of the additional 2021 Notes were approximately $619.5 million (after the initial purchasers' premiums, commissions and offering expenses). The net proceeds from this offering were used to repay all of the outstanding borrowings under our Senior Credit Agreement and for general corporate purposes, including funding a portion of our 2013 capital expenditures program.

        The 2021 Notes bear interest at a rate of 8.875% per annum, payable semi-annually on May 15 and November 15 of each year, beginning on May 15, 2013. The Notes will mature on May 15, 2021. The 2021 Notes are senior unsecured obligations of ours and rank equally with all of our current and future senior indebtedness. The 2021 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by our existing 100% owned subsidiaries, except for one subsidiary, HK TMS, LLC. We, the issuer of the 2021 Notes, have no material independent assets or operations apart from the assets and operations of our subsidiaries.

        In connection with the issuance of the original 2021 Notes, we recorded a discount of approximately $5.7 million to be amortized over the remaining life of the 2021 Notes using the effective interest method. The remaining unamortized discount was $4.6 million at December 31, 2014. In connection with the issuance of the additional 2021 Notes, we recorded a premium of approximately $30.0 million to be amortized over the remaining life of the 2021 Notes using the effective interest method. The remaining unamortized premium was $24.6 million at December 31, 2014. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 6, "Long-Term Debt," for additional information regarding the 2021 Notes.

9.75% Senior Notes

        On July 16, 2012, we completed a private offering of $750.0 million aggregate principal amount of 9.75% senior notes due 2020 issued at 98.646% of par (the 2020 Notes). The net proceeds from the offering were approximately $723.1 million after deducting the initial purchasers' discounts, commissions and offering expenses and were used to fund a portion of the cash consideration paid in the merger with GeoResources, Inc. (the Merger) and the East Texas Assets acquisition. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 4, "Acquisitions and Divestitures," for additional information regarding the Merger and the East Texas Assets acquisition.

        On December 19, 2013, we issued an additional $400.0 million aggregate principal amount of the 2020 Notes at a price to the initial purchasers of 102.750% of par. The net proceeds from the sale of

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the additional 2020 Notes of approximately $406.3 million (after the initial purchasers' premiums, commissions and offering expenses) were used to repay a portion of the then outstanding borrowings under the Senior Credit Agreement and for general corporate purposes. These notes were issued as "additional notes" under the indenture governing the 2020 Notes and under the indenture are treated as a single series with substantially identical terms as the 2020 Notes previously issued.

        The 2020 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on January 15 and July 15 of each year, which began on January 15, 2013. The 2020 Notes will mature on July 15, 2020. The 2020 Notes are senior unsecured obligations of ours and rank equally with all of our current and future senior indebtedness. The 2020 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by our existing 100% owned subsidiaries, except for one subsidiary, HK TMS, LLC. We, the issuer of the 2020 Notes, have no material independent assets or operations apart from the assets and operations of our subsidiaries.

        In connection with the issuance of the 2020 Notes, we recorded a discount of approximately $10.2 million to be amortized over the remaining life of the 2020 Notes using the effective interest method. The remaining unamortized discount was $7.9 million at December 31, 2014. In connection with the issuance of the additional 2020 Notes, we recorded a premium of approximately $11.0 million to be amortized over the remaining life of the 2020 Notes using the effective interest method. The remaining unamortized premium was $9.7 million at December 31, 2014. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 6, "Long-Term Debt," for additional information regarding the 2020 Notes.

8.0% Convertible Note

        On February 8, 2012, we issued the 8.0% senior note in the principal amount of $275.0 million (the 2017 Note) together with the February 2012 Warrants for an aggregate purchase price of $275.0 million. The 2017 Note bears interest at a rate of 8% per annum, payable quarterly on March 31, June 30, September 30 and December 31 of each year and matures on February 8, 2017. Through the March 31, 2014 interest payment date, we could elect to pay-in-kind, by adding to the principal of the 2017 Note, all or any portion of the interest due on the 2017 Note. We elected to pay the interest in-kind on March 31, June 30 and September 30, 2012, and rolled $3.2 million, $5.7 million and $5.8 million of interest incurred during the first, second and third quarters of 2012, respectively, into the 2017 Note, increasing the principal amount to $289.7 million. We did not elect to pay-in-kind interest for the quarterly payments due subsequent to September 30, 2012. As of February 8, 2014, the note can be converted into common stock. Each $4.50 of principal and accrued but unpaid interest is convertible into one share of our common stock. The 2017 Note is a senior unsecured obligation of ours.

        We allocated the proceeds received for the 2017 Note and February 2012 Warrants on a relative fair value basis. Consequently, we recorded a discount of $43.6 million to be amortized over the remaining life of the 2017 Note utilizing the effective interest rate method. The remaining unamortized discount was $21.8 million at December 31, 2014.

Promissory Notes

        On December 28, 2012, we completed the acquisition of certain oil and natural gas properties in Brazos County, Texas for approximately $83.7 million, before and subject to, customary closing adjustments, consisting of approximately $8.4 million in cash and approximately $75.3 million in promissory notes. During the three months ended March 31, 2013, we completed our review of the properties and paid approximately $62.4 million during the period for properties deemed to have clear title and no defects. In addition, notice was given to the sellers of our assertion of title and environmental defects amounting to $12.9 million for the remaining properties. During the three

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months ended September 30, 2013, the title and environmental defects were cured by the sellers and we paid the remaining portion of the purchase price. The promissory notes were classified as current at December 31, 2012.

        In conjunction with the issuance of the promissory notes in December 2012, we recorded a discount of approximately $0.6 million to be amortized over the remaining life of the promissory notes using the effective interest method. We expensed the discount during the first quarter of 2013.

Off-Balance Sheet Arrangements

        At December 31, 2014, we did not have any material off-balance sheet arrangements.

Critical Accounting Policies and Estimates

        The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States. We also describe the most significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with our audit committee. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 1, "Summary of Significant Events and Accounting Policies," for a discussion of additional accounting policies and estimates made by management.

Oil and Natural Gas Activities

        Accounting for oil and natural gas activities is subject to unique rules. Two generally accepted methods of accounting for oil and natural gas activities are available—successful efforts and full cost. The most significant differences between these two methods are the treatment of unsuccessful exploration costs and the manner in which the carrying value of oil and natural gas properties are amortized and evaluated for impairment. The successful efforts method requires unsuccessful exploration costs to be expensed as they are incurred upon a determination that the well is uneconomical while the full cost method provides for the capitalization of these costs. Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities. Impairment of oil and natural gas properties under the successful efforts method is based on an evaluation of the carrying value of individual oil and natural gas properties against their estimated fair value, while impairment under the full cost method requires an evaluation of the carrying value of oil and natural gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using the unweighted arithmetic average of the first day of the month for each of the 12-month prices for oil and natural gas within the period, holding prices and costs constant and applying a 10% discount rate.

Full Cost Method

        We use the full cost method of accounting for our oil and natural gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas

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properties are capitalized into a cost center (the amortization base or full cost pool). Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. All general and administrative costs unrelated to drilling activities are expensed as incurred. The capitalized costs of our evaluated oil and natural gas properties, plus an estimate of our future development and abandonment costs are amortized on a unit-of-production method based on our estimate of total proved reserves. Our financial position and results of operations could have been significantly different had we used the successful efforts method of accounting for our oil and natural gas activities.

Proved Oil and Natural Gas Reserves

        Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States and Securities Exchange Commission (SEC) guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation and accretion expense and the full cost ceiling test limitation. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under defined economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

        Our estimated proved reserves for the years ended December 31, 2014, 2013 and 2012 were prepared by Netherland, Sewell, an independent oil and natural gas reservoir engineering consulting firm. For more information regarding reserve estimation, including historical reserve revisions, refer to Item 8. Consolidated Financial Statements and Supplementary Data—"Supplemental Oil and Gas Information (Unaudited)."

Depreciation, Depletion and Accretion

        Our rate of recording depletion, depreciation and accretion expense (DD&A) is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from calculated lower market prices, which may make it non-economic to drill for and produce higher cost reserves. At December 31, 2014, a five percent positive revision to proved reserves would decrease the DD&A rate by approximately $1.57 per Boe and a five percent negative revision to proved reserves would increase the DD&A rate by approximately $1.73 per Boe.

Full Cost Ceiling Test Limitation

        Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write down to the extent of such excess. If required, it would reduce earnings and impact stockholders' equity in the period of occurrence and result in lower amortization expense in future periods. The discounted present value of our proved reserves is a major component of the

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ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that we use the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. If average oil and natural gas prices decline, or if we have downward revisions to our estimated proved reserves, it is possible that write downs of our oil and natural gas properties could occur in the future.

        If the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ended December 31, 2014 had been 10% lower while all other factors remained constant, our ceiling amount related to our net book value of oil and natural gas properties would have been reduced by approximately $687.6 million. This reduction would have increased our full cost ceiling impairment by approximately $687.6 million before income taxes.

Future Development Costs

        Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production facilities, gathering systems and related structures and restoration costs. We develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis. A five percent decrease or increase in future development and abandonment costs would decrease or increase the DD&A rate by approximately $0.71 per Boe at December 31, 2014.

Accounting for Derivative Instruments and Hedging Activities

        We account for our derivative activities under the provisions of Accounting Standards Codification (ASC) No. 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, we may hedge a portion of our forecasted oil, natural gas, and natural gas liquids production. Derivative contracts entered into by us have consisted of transactions in which we hedge the variability of cash flow related to a forecasted transaction. We elected to not designate any of our positions for hedge accounting. Accordingly, we record the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in "Net gain (loss) on derivative contracts" on the consolidated statements of operations.

Goodwill

        We account for goodwill in accordance with ASC 350, Intangibles—Goodwill and Other (ASC 350). Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. ASC 350 requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. Our goodwill related to the merger with GeoResources in 2012.

        Accounting Standards Update (ASU) No. 2011-08, Testing for Goodwill Impairment (ASU 2011-08), simplifies testing for goodwill impairments by allowing entities to first assess qualitative factors to

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determine whether the facts or circumstances lead to the conclusion that it is more likely than not that the fair value of a reporting unit is less than the carrying value. If the entity concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then the entity does not have to perform the two-step impairment test. However, if the same conclusion is not reached, the entity is required to perform the first step of the two-step impairment test. In this step, the fair value of the reporting unit is calculated and compared to the carrying value of the reporting unit. If the carrying value exceeds the fair value, then the entity must perform the second step of the impairment test to measure the amount of impairment loss, if any. ASU 2011-08 also allows a company to bypass the qualitative assessment and proceed directly with performing the two-step goodwill impairment test.

Income Taxes

        Our provision for taxes includes both state and federal taxes. We account for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized.

        In assessing the need for a valuation allowance on our deferred tax assets, we consider possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. We consider all available evidence (both positive and negative) in determining whether a valuation allowance is required. A significant item of objective negative evidence considered was the cumulative book loss over the three-year period ended December 31, 2014 driven primarily by the full cost ceiling impairments over that period. Based upon the evaluation of the available evidence we recorded a decrease of $102.0 million to our valuation allowance resulting in a remaining valuation allowance of $163.1 million being applied against our deferred tax assets as of December 31, 2014.

        We follow ASC 740, Income Taxes (ASC 740). ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows. The evaluation of a tax position in accordance with ASC 740 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

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Comparison of Results of Operations

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

        We reported net income of $316.0 million for the year ended December 31, 2014 compared to a net loss of $1.2 billion for the comparable period in 2013. The following table summarizes key items of comparison and their related change for the periods indicated.

 
  Years Ended December 31,    
 
In thousands (except per unit and per Boe amounts)
  2014   2013   Change  

Net income (loss)

  $ 315,956   $ (1,222,662 ) $ 1,538,618  

Operating revenues:

                   

Oil

    1,071,319     944,535     126,784  

Natural gas

    37,101     27,319     9,782  

Natural gas liquids

    37,460     24,564     12,896  

Other

    2,381     3,088     (707 )

Operating expenses:

                   

Production:

                   

Lease operating

    130,239     139,182     (8,943 )

Workover and other

    16,193     6,268     9,925  

Taxes other than income

    106,331     88,622     17,709  

Gathering and other

    26,719     11,745     14,974  

Restructuring

    987     4,471     (3,484 )

General and administrative:

                   

General and administrative

    97,799     115,298     (17,499 )

Share-based compensation

    18,733     17,112     1,621  

Depletion, depreciation and accretion:

                   

Depletion—Full cost

    523,855     453,537     70,318  

Depreciation—Other

    8,744     6,522     2,222  

Accretion expense

    1,822     3,596     (1,774 )

Full cost ceiling impairment

    239,668     1,147,771     (908,103 )

Other operating property and equipment impairment

    35,558     67,454     (31,896 )

Goodwill impairment

        228,875     (228,875 )

Other income (expenses):

                   

Net gain (loss) on derivative contracts

    518,956     (31,233 )   550,189  

Interest expense and other, net

    (145,689 )   (58,198 )   (87,491 )

Income tax benefit (provision)

    1,076     157,716     (156,640 )

Production:

   
 
   
 
   
 
 

Crude oil—MBbls

    12,787     10,148     2,639  

Natural gas—MMcf

    8,812     8,003     809  

Natural gas liquids—MBbls

    1,113     683     430  

Total MBoe(1)

    15,369     12,165     3,204  

Average daily production—Boe(1)

    42,107     33,329     8,778  

Average price per unit(2):

   
 
   
 
   
 
 

Crude oil price—Bbl

  $ 83.78   $ 93.08   $ (9.30 )

Natural gas price—Mcf

    4.21     3.41     0.80  

Natural gas liquids price—Bbl

    33.66     35.96     (2.30 )

Total per Boe(1)

    74.56     81.91     (7.35 )

Average cost per Boe:

   
 
   
 
   
 
 

Production:

                   

Lease operating

  $ 8.47   $ 11.44   $ (2.97 )

Workover and other

    1.05     0.52     0.53  

Taxes other than income

    6.92     7.28     (0.36 )

Gathering and other

    1.74     0.97     0.77  

Restructuring

    0.06     0.37     (0.31 )

General and administrative:

                   

General and administrative

    6.36     9.48     (3.12 )

Share-based compensation

    1.22     1.41     (0.19 )

Depletion

    34.09     37.28     (3.19 )

(1)
Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

(2)
Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

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        For the year ended December 31, 2014, oil, natural gas and natural gas liquids revenues increased $149.5 million from the same period in 2013. The increase was due to increased production volumes associated with the development of the properties we acquired in 2013 in the Bakken / Three Forks and El Halcón areas. These areas collectively accounted for approximately 5,600 MBoe and $360.0 million of incremental revenues year over year. The increase in revenues from production volumes was offset by a decrease in our realized average prices per Boe, which decreased $7.35 per Boe to $74.56 per Boe.

        Lease operating expenses decreased $8.9 million for the year ended December 31, 2014. On a per unit basis, lease operating expenses were $8.47 per Boe in 2014 compared to $11.44 per Boe in 2013. The decrease per Boe is primarily due to lower relative operating expenses per Boe on the more recently developed core properties due, in part, to operational improvements and efficiencies.

        Workover and other expenses increased $9.9 million for the year ended December 31, 2014 as compared to the same period in 2013 primarily due to $8.0 million of expenses associated with increased activity in our core areas as we continue to develop these areas. The remaining $1.9 million of the increase is attributable to workover activity in non-core areas.

        Taxes other than income increased $17.7 million for the year ended December 31, 2014 as compared to the same period in 2013 primarily due to increased production from the development of our core properties. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease proportionately. On a per unit basis, taxes other than income were $6.92 per Boe and $7.28 per Boe, for the years ended 2014 and 2013, respectively. The decrease on a per Boe basis in 2014 is driven by a decrease in our realized average prices.

        Gathering and other expenses increased $15.0 million for the year ended December 31, 2014 as compared to the same period in 2013 primarily due to increased gathering and other fees paid on our oil and natural gas production in the Bakken / Three Forks area.

        In conjunction with our divestitures of certain non-core properties, we incurred approximately $1.0 million in severance costs and accelerated share-based compensation expenses related to the termination of certain employees for the year ended December 31, 2014. In March 2012, we announced our intention to close our Plano, Texas office and began the process of relocating key administrative functions to our corporate headquarters in Houston, Texas (the restructuring). As part of the restructuring, we offered certain severance and retention benefits to affected employees, through May 2013. Approximately $0.5 million of our restructuring expense in 2013 relates to costs from the restructuring. Additionally, in the fourth quarter of 2013, in conjunction with our divestitures of certain non-core assets, we incurred approximately $4.0 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees in these non-core areas.

        General and administrative expense for the year ended December 31, 2014 decreased $17.5 million to $97.8 million as compared to the same period in 2013. The decrease was primarily due to decreases in professional fees, specifically contract services and legal expenses, of $14.0 million and office related expenses of $3.2 million. On a per unit basis, general and administrative expenses were $6.36 per Boe and $9.48 per Boe, for the years ended 2014 and 2013, respectively.

        Share-based compensation expense for the year ended December 31, 2014 was $18.7 million, an increase of $1.6 million compared to the same period in 2013. The increase in share-based compensation expense results from additional awards granted to employees subsequent to the prior year period.

        Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production volume for the current period to total remaining reserve volume for the evaluated

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properties. Depletion expense increased $70.3 million to $523.8 million for the year ended December 31, 2014 compared to the same period in 2013 of $453.5 million, due to an increase in production volumes. On a per unit basis, depletion expense was $34.09 per Boe for the year ended December 31, 2014 compared to $37.28 per Boe for the year ended December 31, 2013.

        We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the "ceiling," based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. We recorded a full cost ceiling test impairment before income taxes of $239.7 million for the year ended December 31, 2014. The impairment for the year ended December 31, 2014 primarily relates to non-routine transfers of unevaluated properties to the full cost pool, due to our shift in drilling, away from the non-strategic areas of the Utica / Point Pleasant and TMS until economics and return on investment improve due to a combination of lower drilling and completion costs and higher commodity prices. We recorded a full cost ceiling test impairment before income taxes of $1.1 billion for the year ended December 31, 2013. During the year ended December 31, 2013, we transferred $655.7 million of unevaluated property costs to the full cost pool primarily related to Woodbine assets in East Texas where capital was reallocated to El Halcón, and certain Utica / Point Pleasant assets in Northwest Pennsylvania related to non-economical drilling results obtained in the third quarter of 2013. The combined impact of less favorable oil price differentials adversely affecting proved reserve values and the aforementioned non-routine transfers of unevaluated properties to the full cost pool primarily contributed to the ceiling impairment in 2013. Oil and natural gas prices, changes in production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

        We review our gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360. For the year ended December 31, 2014, we recorded a non-cash impairment charge for gas gathering systems and other related operating assets of $35.6 million, net of $1.9 million of accumulated depreciation. The majority of the impairment represents approximately half of our gas gathering infrastructure, right-of-way and permitting investments in the Utica / Point Pleasant area. These infrastructure related investments were related to acreage in certain non-core areas of the Utica play which we currently do not plan to develop in light of the recent downtrend in oil prices, which has rendered certain areas to be deemed uneconomical and/or non-strategic. For the year ended December 31, 2013, we recorded a non-cash impairment charge of $67.5 million. The impairment relates to our gross investments of $72.1 million in gas gathering infrastructure that will not be economically recoverable due to our shift in exploration, drilling and developmental plans from the Woodbine area to El Halcón during the third quarter of 2013.

        During the third quarter of 2013, we performed our annual goodwill impairment test, using a measurement date of July 1, and based on this review; we recorded a non-cash impairment charge of $228.9 million to reduce the carrying value of goodwill to zero. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than the carrying amount, including goodwill, primarily due to pricing deterioration in the NYMEX forward pricing curve for oil, coupled with less favorable oil price differentials in our core areas, both factors which adversely impacted the fair value of our proved reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill.

        Accretion expense is a function of changes in the discounted asset retirement obligation liability from period to period. We recorded $1.8 million for the year ended December 31, 2014, compared to

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$3.6 million for the year ended December 31, 2013. The year over year reduction in our accretion expense stems from a reduction in the number of wells we currently have a working interest in after our divestitures of non-core properties.

        We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations. At December 31, 2014, we had a $503.9 million derivative asset, $352.5 million of which was classified as current, and we had a $9.4 million derivative liability none of which was classified as current. We recorded a net derivative gain of $518.9 million ($506.5 million net unrealized gain and $12.4 million net realized gain on settled contracts and premium costs) for the year ended December 31, 2014 compared to a net derivative loss of $31.2 million ($10.1 million net unrealized loss and $21.1 million net realized loss on settled contracts and premium costs) in the prior year.

        Interest expense increased $87.5 million for the year ended December 31, 2014. Capitalized interest for the years ended December 31, 2014 and 2013 was $168.9 million and $204.0 million, respectively. The decrease in capitalized interest was driven by decreases in our unevaluated properties since 2013. Unevaluated properties are the basis of our capitalized interest calculation. Interest expense subject to capitalization increased to $317.7 million from $259.2 million in the prior year. The increase in interest subject to capitalization is primarily due to our 9.25% Senior Notes and the additional 9.75% Senior Notes outstanding for a full year in 2014.

        We recorded income tax benefit of $1.1 million on income before income taxes of $314.9 million for the year ended December 31, 2014. The benefit reflects the impact of the change in the valuation allowance for the year of $102.0 million. For the year ended December 31, 2013, we recorded an income tax benefit of $157.7 million on a loss before income taxes of $1.4 billion. The benefit reflects the impact of the change in the valuation allowance for the year of $262.8 million and the non-deductible goodwill impairment of $84.5 million.

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Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

        We reported a net loss of $1.2 billion for the year ended December 31, 2013 compared to a net loss of $53.9 million for the comparable period in 2012. The following table summarizes key items of comparison and their related change for the periods indicated.

 
  Years Ended
December 31,
   
 
In thousands (except per unit and per Boe amounts)
  2013   2012   Change  

Net income (loss)

  $ (1,222,662 ) $ (53,885 ) $ (1,168,777 )

Operating revenues:

                   

Oil

    944,535     223,056     721,479  

Natural gas

    27,319     12,735     14,584  

Natural gas liquids

    24,564     11,180     13,384  

Other

    3,088     1,351     1,737  

Operating expenses:

                   

Production:

                   

Lease operating

    139,182     49,859     89,323  

Workover and other

    6,268     4,429     1,839  

Taxes other than income

    88,622     19,253     69,369  

Gathering and other

    11,745     459     11,286  

Restructuring

    4,471     2,406     2,065  

General and administrative:

                   

General and administrative

    115,298     104,608     10,690  

Share-based compensation

    17,112     6,741     10,371  

Depletion, depreciation and accretion:

                   

Depletion—Full cost

    453,537     86,215     367,322  

Depreciation—Other

    6,522     1,763     4,759  

Accretion expense

    3,596     2,306     1,290  

Full cost ceiling impairment

    1,147,771         1,147,771  

Other operating property and equipment impairment

    67,454         67,454  

Goodwill impairment

    228,875         228,875  

Other income (expenses):

                   

Net gain (loss) on derivative contracts

    (31,233 )   (6,126 )   (25,107 )

Interest expense and other, net

    (58,198 )   (31,223 )   (26,975 )

Income tax benefit (provision)

    157,716     13,181     144,535  

Production:

   
 
   
 
   
 
 

Crude oil—MBbls

    10,148     2,415     7,733  

Natural gas—MMcf

    8,003     4,554     3,449  

Natural gas liquids—MBbls

    683     268     415  

Total MBoe(1)

    12,165     3,442     8,723  

Average daily production—Boe(1)

    33,329     9,404     23,925  

Average price per unit(2):

   
 
   
 
   
 
 

Crude oil price—Bbl

  $ 93.08   $ 92.36   $ 0.72  

Natural gas price—Mcf

    3.41     2.80     0.61  

Natural gas liquids price—Bbl

    35.96     41.72     (5.76 )

Total per Boe(1)

    81.91     71.75     10.16  

Average cost per Boe:

   
 
   
 
   
 
 

Production:

                   

Lease operating

  $ 11.44   $ 14.49   $ (3.05 )

Workover and other

    0.52     1.29     (0.77 )

Taxes other than income

    7.28     5.59     1.69  

Gathering and other

    0.97     0.13     0.84  

Restructuring

    0.37     0.70     (0.33 )

General and administrative:

                   

General and administrative

    9.48     30.39     (20.91 )

Share-based compensation

    1.41     1.96     (0.55 )

Depletion

    37.28     25.05     12.23  

(1)
Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

(2)
Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

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        For the year ended December 31, 2013, oil, natural gas and natural gas liquids revenues increased $749.4 million from the same period in 2012. The increase was primarily due to increased production volumes associated with the development of the properties we acquired in 2012 in the Bakken / Three Forks, Woodbine and El Halcón areas. These areas collectively accounted for 8,243 MBoe and $717.8 million of incremental revenues year over year. Realized average prices per Boe increased $10.16 per Boe to $81.91 per Boe.

        Lease operating expenses increased $89.3 million for the year ended December 31, 2013, primarily due to $73.4 million of expenses on properties acquired in 2012 and our development of these properties in 2013. Lease operating expenses were $11.44 per Boe in 2013 compared to $14.49 per Boe in 2012. The decrease per Boe is primarily due to lower operating expenses per Boe on the newly developed properties. As we continue to strive for operational efficiencies and divest non-core properties with higher operating costs our lease operating expense per Boe should decline.

        Workover and other expenses increased $1.8 million for the year ended December 31, 2013 compared to the same period in 2012 primarily due to $3.2 million of expenses associated with increased activity on acquired properties as we continue to develop these areas.

        Taxes other than income increased $69.4 million for the year ended December 31, 2013 as compared to the same period in 2012 primarily due to increased production from the development of the properties we acquired in 2012. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease proportionately. On a per unit basis, taxes other than income were $7.28 per Boe and $5.59 per Boe, for the years ended 2013 and 2012, respectively. The increase on a per Boe basis in 2013 is driven by increased production and revenue in our Bakken / Three Forks area which has higher production tax rates than our other areas.

        Gathering and other expenses for the year ended December 31, 2013 and 2012 were $11.7 million and $0.5 million, respectively. In 2013, approximately $3.4 million of these expenses were attributable to midstream infrastructure that we developed in our Woodbine and Utica / Point Pleasant operating areas and approximately $8.3 million relates to gathering and other fees paid on our oil and natural gas production.

        In March 2012, we announced our intention to close our Plano, Texas office and began the process of relocating key administrative functions to our corporate headquarters in Houston, Texas (the restructuring). As part of the restructuring, we offered certain severance and retention benefits to affected employees, through May 2013. Approximately $0.5 million of our restructuring expense in 2013 relates to costs from the restructuring. Additionally, in the fourth quarter of 2013, in conjunction with our divestitures of certain non-core assets, we incurred approximately $4.0 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees in these non-core areas.

        General and administrative expense for the year ended December 31, 2013 increased $10.7 million to $115.3 million as compared to the same period in 2012. The increase was primarily due to increases in payroll and related employee benefit costs of $17.9 million and office related expenses of $9.2 million, in support of our expanding employee and business base, partially offset by a decrease in transaction costs. On a per unit basis, general and administrative expenses were $9.48 per Boe and $30.39 per Boe, for the years ended 2013 and 2012, respectively.

        Share-based compensation expense for the year ended December 31, 2013 was $17.1 million, an increase of $10.4 million compared to the same period in 2012. In 2012, we incurred approximately $4.3 million for the accelerated vesting of restricted stock awards and stock appreciation rights resulting from the change in control that occurred due to our Recapitalization. The year over year increase, excluding these change in control payments, is approximately $6.1 million, reflecting our investment in additional personnel since the prior year.

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        Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production volume for the current period to total remaining reserve volume for the evaluated properties. Depletion expense increased $367.3 million to $453.5 million for the year ended December 31, 2013 compared to the same period in 2012 of $86.2 million, primarily due to a higher depletion rate per Boe and increased production. On a per unit basis, depletion expense was $37.28 per Boe for the year ended December 31, 2013 compared to $25.05 per Boe for the year ended December 31, 2012. The increase in depletion expense and the depletion rate per Boe is primarily due to the increase in production volumes and in our capital spending associated with our development of the properties we acquired in 2012. Additionally, in the third quarter of 2013, we transferred unevaluated property costs of $655.7 million to the full cost pool, which is discussed further below, which contributed to the increase in depletion expense on both an absolute dollar and per Boe basis when compared to 2012.

        We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the "ceiling," based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. We recorded a full cost ceiling test impairment before income taxes of $1.1 billion for the year ended December 31, 2013. During the year ended December 31, 2013, we transferred $655.7 million of unevaluated property costs to the full cost pool primarily related to Woodbine assets in East Texas where capital has been reallocated to El Halcón, and certain Utica / Point Pleasant assets in Northwest Pennsylvania related to non-economical drilling results obtained in the third quarter of 2013. The combined impact of less favorable oil price differentials adversely affecting proved reserve values and the aforementioned non-routine transfers of unevaluated properties to the full cost pool primarily contributed to the ceiling impairment. Oil and natural gas prices, changes in production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

        We review our gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360. For the year ended December 31, 2013, we recorded a non-cash impairment charge of $67.5 million. The impairment relates to our gross investments of $72.1 million in gas gathering infrastructure that will not be economically recoverable due to our shift in exploration, drilling and developmental plans from the Woodbine area to El Halcón during the third quarter of 2013.

        During the third quarter of 2013, we performed our annual goodwill impairment test, using a measurement date of July 1, and based on this review; we recorded a non-cash impairment charge of $228.9 million to reduce the carrying value of goodwill to zero. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than the carrying amount, including goodwill, primarily due to pricing deterioration in the NYMEX forward pricing curve for oil, coupled with less favorable oil price differentials in our core areas, both factors which adversely impacted the fair value of our proved reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill.

        Accretion expense is a function of changes in the discounted asset retirement obligation liability from period to period. We recorded $3.6 million for the year ended December 31, 2013, compared to $2.3 million for the year ended December 31, 2012.

        We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have

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elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations. At December 31, 2013, we had a $24.8 million derivative asset, $2.0 million of which was classified as current, and we had a $37.2 million derivative liability of which $17.9 million was classified as current. We recorded a net derivative loss of $31.2 million ($10.1 million net unrealized loss and $21.1 million net realized loss on settled contracts and premium costs) for the year ended December 31, 2013 compared to a net derivative loss of $6.1 million ($13.2 million net unrealized loss and $7.1 million net realized gain on settled contracts and premium costs) in the prior year.

        Interest expense increased $27.0 million for the year ended December 31, 2013. This increase was primarily due to the issuance of new long-term debt partially offset by capitalized interest expense on unevaluated properties. We incurred interest expense before capitalization of $259.2 million in 2013 compared to $85.4 million in the prior year. Due to significant costs incurred during 2012 on unevaluated properties we began capitalizing interest, resulting in $204.0 million and $53.5 million capitalized for the years ended December 31, 2013 and 2012, respectively.

        We recorded an income tax benefit of $157.7 million on a loss before income taxes of $1.4 billion for the year ended December 31, 2013. The benefit reflects the impact of the change in the valuation allowance for the year of $262.8 million and the nondeductible goodwill impairment of $84.5 million. For the year ended December 31, 2012, we recorded an income tax benefit of $13.2 million on a loss before income taxes of $67.1 million. The benefit reflects nondeductible interest expense on the convertible notes issued as part of the Recapitalization of $3.2 million and nondeductible merger related costs of $3.6 million.

Recently Issued Accounting Pronouncements

        We discuss recently adopted and issued accounting standards in Item 8. Consolidated Financial Statements and Supplementary Data—Note 1, "Summary of Significant Events and Accounting Policies."

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Derivative Instruments and Hedging Activity

        We are exposed to various risks including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include costless collars, swaps, and deferred put options. The total volumes which we hedge through the use of our derivative instruments varies from period to period, however, generally our objective is to hedge approximately 70% to 80% of our current and anticipated production for the next 18 to 24 months. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

        We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. Each of the counterparties to our derivative contracts is a lender of an affiliate of a lender in our Senior Credit Agreement. We did not post collateral under any of these contracts as they are secured under our Senior Credit Agreement. Please refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 8, "Derivative and Hedging Activities" for additional information.

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        We have also been exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Historically, we entered into interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. At December 31, 2014, we did not have any open positions that converted our variable interest rate debt to fixed interest rates. We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.

        We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 8, "Derivative and Hedging Activities" for more details.

Fair Market Value of Financial Instruments

        The estimated fair values for financial instruments under ASC 825, Financial Instruments, (ASC 825) are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 7, "Fair Value Measurements" for additional information.

Interest Rate Sensitivity

        We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and ABR based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

        At December 31, 2014, total long-term debt including related discounts and premiums was $3.7 billion, of which approximately 85% bears interest at a weighted average fixed interest rate of 9.2% per year. The remaining 15% of our total long-term debt balance at December 31, 2014 bears interest at floating or market interest rates that at our option are tied to prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At December 31, 2014, the weighted average interest rate on our variable rate debt was 2.3% per year. If the balance of our variable rate debt at December 31, 2014 were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $1.3 million per year.

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ITEM 8.    CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

        Management of Halcón Resources Corporation (the Company), including the Company's Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. The Company's internal control system was designed to provide reasonable assurance to the Company's Management and Board of Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on this evaluation, management concluded that Halcón Resources Corporation's internal control over financial reporting was effective as of December 31, 2014.

        Deloitte & Touche LLP, the Company's independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2014 which is included herein.

/s/ FLOYD C. WILSON

Floyd C. Wilson
Chairman of the Board
and Chief Executive Officer
  /s/ MARK J. MIZE

Mark J. Mize
Executive Vice President,
Chief Financial Officer and Treasurer

Houston, Texas
February 26, 2015

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Halcón Resources Corporation
Houston, Texas

        We have audited the internal control over financial reporting of Halcón Resources Corporation and subsidiaries (the "Company") as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

        A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control—Integrated Framework 2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

        We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2014 and 2013, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2014 and our report dated February 26, 2015 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 26, 2015

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Halcón Resources Corporation
Houston, Texas

        We have audited the accompanying consolidated balance sheets of Halcón Resources Corporation and subsidiaries (the "Company") as of December 31, 2014 and 2013, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

        We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2015 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP    

Houston, Texas
February 26, 2015

 

 

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HALCÓN RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

 
  Years Ended December 31,  
 
  2014   2013   2012  

Operating revenues:

                   

Oil, natural gas and natural gas liquids sales:

                   

Oil

  $ 1,071,319   $ 944,535   $ 223,056  

Natural gas

    37,101     27,319     12,735  

Natural gas liquids

    37,460     24,564     11,180  

Total oil, natural gas and natural gas liquids sales

    1,145,880     996,418     246,971  

Other

    2,381     3,088     1,351  

Total operating revenues

    1,148,261     999,506     248,322  

Operating expenses:

                   

Production:

                   

Lease operating

    130,239     139,182     49,859  

Workover and other

    16,193     6,268     4,429  

Taxes other than income

    106,331     88,622     19,253  

Gathering and other

    26,719     11,745     459  

Restructuring

    987     4,471     2,406  

General and administrative

    116,532     132,410     111,349  

Depletion, depreciation and accretion

    534,421     463,655     90,284  

Full cost ceiling impairment

    239,668     1,147,771      

Other operating property and equipment impairment

    35,558     67,454      

Goodwill impairment

        228,875      

Total operating expenses

    1,206,648     2,290,453     278,039  

Income (loss) from operations

    (58,387 )   (1,290,947 )   (29,717 )

Other income (expenses):

   
 
   
 
   
 
 

Net gain (loss) on derivative contracts

    518,956     (31,233 )   (6,126 )

Interest expense and other, net

    (145,689 )   (58,198 )   (31,223 )

Total other income (expenses)

    373,267     (89,431 )   (37,349 )

Income (loss) before income taxes

    314,880     (1,380,378 )   (67,066 )

Income tax benefit (provision)

    1,076     157,716     13,181  

Net income (loss)

    315,956     (1,222,662 )   (53,885 )

Non-cash preferred dividends

            (88,445 )

Series A preferred dividends

    (19,838 )   (10,745 )    

Preferred dividends and accretion on redeemable noncontrolling interest

    (13,176 )        

Net income (loss) available to common stockholders

  $ 282,942   $ (1,233,407 ) $ (142,330 )

Net income (loss) per share of common stock:

                   

Basic

  $ 0.68   $ (3.25 ) $ (0.91 )

Diluted

  $ 0.59   $ (3.25 ) $ (0.91 )

Weighted average common shares outstanding:

                   

Basic

    415,772     379,621     156,494  

Diluted

    542,394     379,621     156,494  

   

The accompanying notes are an integral part of these consolidated financial statements.

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HALCÓN RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

 
  December 31,  
 
  2014   2013  

Current assets:

             

Cash

  $ 43,713   $ 2,834  

Accounts receivable

    276,559     312,518  

Receivables from derivative contracts

    352,530     2,028  

Restricted cash

    16,131      

Inventory

    4,693     5,148  

Prepaids and other

    9,079     16,098  

Total current assets

    702,705     338,626  

Oil and natural gas properties (full cost method):

             

Evaluated

    6,390,820     4,960,467  

Unevaluated

    1,829,786     2,028,044  

Gross oil and natural gas properties

    8,220,606     6,988,511  

Less—accumulated depletion

    (2,953,038 )   (2,189,515 )

Net oil and natural gas properties

    5,267,568     4,798,996  

Other operating property and equipment:

             

Gas gathering and other operating assets

    126,804     125,837  

Less—accumulated depreciation

    (14,798 )   (8,461 )

Net other operating property and equipment

    112,006     117,376  

Other noncurrent assets:

             

Receivables from derivative contracts

    151,324     22,734  

Debt issuance costs, net

    55,904     64,308  

Deferred income taxes

    136,826     8,474  

Equity in oil and natural gas partnership

    4,309     4,463  

Funds in escrow and other

    3,833     1,514  

Total assets

  $ 6,434,475   $ 5,356,491  

Current liabilities:

             

Accounts payable and accrued liabilities

  $ 607,750   $ 636,589  

Liabilities from derivative contracts

        17,859  

Asset retirement obligations

    106     71  

Current portion of deferred income taxes

    136,826     8,474  

Current portion of long-term debt

        1,389  

Total current liabilities

    744,682     664,382  

Long-term debt

    3,746,736     3,183,823  

Other noncurrent liabilities:

             

Liabilities from derivative contracts

    9,387     19,333  

Asset retirement obligations

    38,371     39,186  

Other

    5,964     2,157  

Commitments and contingencies (Note 10)

             

Mezzanine equity:

             

Redeemable noncontrolling interest

    117,166      

Stockholders' equity:

             

Preferred stock: 1,000,000 shares of $0.0001 par value authorized; 345,000 shares of 5.75%
Cumulative Perpetual Convertible Series A, issued and outstanding as of December 31, 2014 and
2013

         

Common stock: 1,340,000,000 and 670,000,000 shares of $0.0001 par value authorized; 427,808,306
and 415,729,962 shares issued and outstanding at December 31, 2014 and 2013, respectively

    42     41  

Additional paid-in capital

    2,995,402     2,953,786  

Accumulated deficit

    (1,223,275 )   (1,506,217 )

Total stockholders' equity

    1,772,169     1,447,610  

Total liabilities and stockholders' equity

  $ 6,434,475   $ 5,356,491  

   

The accompanying notes are an integral part of these consolidated financial statements.

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HALCÓN RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In thousands)

 
  Preferred Stock   Common Stock    
  Treasury Stock    
   
 
 
  Additional
Paid-In
Capital
  Accumulated
Deficit
  Stockholders'
Equity
(Deficit)
 
 
  Shares   Amount   Shares   Amount   Shares   Amount  

Balances at January 1, 2012

      $     27,695   $ 3   $ 229,414   $ 1,450   $ (7,159 ) $ (220,578 ) $ 1,680  

Warrants issued

                    43,590                 43,590  

Sale of common stock

            115,232     11     568,989                 569,000  

Reverse-stock-split rounding

            4