Halcon Resources Corp (HK) SEC Annual Report (10-K) for 2016

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ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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, 2016

Commission File Number: 001-35467

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

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:

        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.  ý

        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.

        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, 2017, there were 92,986,173 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, 2016, the aggregate market value of shares of common stock held by non-affiliates of the registrant was approximately $37.0 million.

DOCUMENTS INCORPORATED BY REFERENCE

None.

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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 or divestiture 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:

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        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 and its subsidiaries, as a common entity.

Prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh-start accounting. References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized Company subsequent to September 9, 2016. References to "Predecessor" or "Predecessor Company" relate to the financial position and results of operations of the Company prior to, and including, September 9, 2016.

        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, recapitalized on February 8, 2012 and reorganized on September 9, 2016. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in select prospect areas. In the years since, we have primarily focused on the development of acquired properties and also divested non-core assets in order to fund activities in our core resource plays. Our oil and natural gas assets consist of proved reserves and undeveloped acreage positions in unconventional liquids-rich basins/fields, providing us with an extensive drilling inventory in multiple basins that we believe allow for multiple years of production and broad flexibility to direct our capital resources to projects with the greatest potential returns. As discussed below in more detail under "Recent Developments," we have recently acquired certain properties in the Southern Delaware Basin for $705.0 million and entered into an agreement to sell our assets located in the El Halcón area of East Texas for $500.0 million, which is expected to close by early March 2017.

        At December 31, 2016 (Successor), our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc. (Netherland, Sewell) using Securities and Exchange Commission (SEC) prices of $42.75 per Bbl of oil and $2.481 per MMBtu of natural gas, were approximately 148.6 MMBoe, consisting of 119.6 MMBbls of oil, 15.6 MMBbls of natural gas liquids, and 80.2 Bcf of natural gas. Approximately 58% of our proved reserves were classified as proved developed as of December 31, 2016 (Successor). We maintain operational control of approximately 95% of our proved reserves.

        Our total operating revenues for the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) were approximately $153.4 million and $266.8 million, respectively, or $420.2 million combined, compared to total operating revenues for 2015 of $550.3 million. The decrease in total operating revenues year over year was driven by the sustained decline in the prices of crude oil and natural gas along with a decrease in our average daily production year over year. During the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), production averaged 37,637 Boe/d and 36,787 Boe/d, respectively, or 37,049 Boe/d combined, compared to average daily production of 41,542 Boe/d during 2015 (Predecessor). In response to the sustained decline in commodity prices we reduced our drilling and completion activities in 2016 running only one rig on average in our most economic drilling area. In 2016 (for the combined Successor and Predecessor periods), we participated in the drilling of 90 gross (30.6 net) wells, all of which were completed and capable of production.

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Recent Developments

Issuance of 2025 Senior Notes and Repurchase of 2020 Second Lien Notes

        On February 16, 2017 (Successor), we issued $850.0 million aggregate principal amount of our new 6.75% senior unsecured notes due 2025 (the 2025 Notes) in a private placement exempt from registration under the Securities Act of 1933, as amended (Securities Act), afforded by Rule 144A and Regulation S, and applicable state securities laws. The 2025 Notes were issued at par and bear interest at a rate of 6.75% per annum, payable semi-annually on February 15 and August 15 of each year, beginning on August 15, 2017. Proceeds from the private placement were approximately $835.1 million after deducting initial purchasers' discounts and commissions and offering expenses. We utilized a portion of the net proceeds from the private placement to fund the repurchase of the outstanding 2020 Second Lien Notes and will use an additional amount of the net proceeds to redeem the remaining amount of such notes, discussed further below, and for general corporate purposes.

        On February 9, 2017 (Successor), we commenced a cash tender offer for any and all of our outstanding 2020 Second Lien Notes and on February 15, 2017, we received approximately $289.2 million or 41% of the outstanding aggregate principal amount of the 2020 Second Lien Notes which were validly tendered (and not validly withdrawn). As a result, on February 16, 2017 (Successor), we paid approximately $303.5 million for approximately $289.2 million principal amount of 2020 Second Lien Notes, a make-whole premium of $13.2 million plus accrued and unpaid interest of approximately $1.1 million to purchase such notes pursuant to the tender offer and issued a redemption notice to redeem the remaining 2020 Second Lien Notes. The remaining $410.8 million of 2020 Second Lien Notes will be repurchased through the guaranteed delivery procedures or redeemed at a price of 104.313% of the principal amount thereof, plus accrued and unpaid interest to, but not including, the redemption date. The redemption date is expected to be March 20, 2017.

Pending Divestiture of East Texas Eagle Ford Assets

        On January 24, 2017 (Successor), certain of our subsidiaries entered into an Agreement of Sale and Purchase with a subsidiary of Hawkwood Energy, LLC (Hawkwood) for the sale of all of our oil and natural gas properties and related assets located in the Eagle Ford formation of East Texas (the El Halcón Assets) for a total sales price of $500.0 million (the El Halcón Divestiture). The effective date of the proposed sale is January 1, 2017, and we expect to close the transaction in early March 2017. The sale properties include approximately 80,500 net acres prospective for the Eagle Ford formation in East Texas. As of December 31, 2016, estimated proved reserves from these properties were approximately 35.1 MMBoe, or 24% of our estimated year-end 2016 proved reserves. The sale includes approximately 191 gross (135 net) wells that produced approximately 7,600 Boe/d (80% oil) for the year ended December 31, 2016.

        The sales price is subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. Pursuant to the terms of the agreement, Hawkwood paid into escrow a deposit of $32.5 million at signing, which amount will be applied to the sales price if the transaction closes.

        The completion of the El Halcón Divestiture is subject to customary closing conditions. The parties may terminate the sale agreement if certain closing conditions have not been satisfied, if total adjustments to the sales price exceed 20% of the sales price, or $100.0 million, or the transaction has not closed on or before March 20, 2017. If one or more of the closing conditions are not satisfied, or if the transaction is otherwise terminated, the divestiture may not be completed. There can be no assurance that we will sell the El Halcón Assets on the terms or timing described or at all. If the El Halcón Divestiture closes, we intend to use the net proceeds to repay amounts outstanding under our Senior Credit Agreement and for general corporate purposes.

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Private Placement of Automatically Convertible Preferred Stock

        On January 24, 2017 (Successor), we entered into a stock purchase agreement with certain accredited investors to sell, in a private placement exempt from the registration requirements of the Securities Act pursuant to Section 4(a)(2), approximately 5,518 shares of 8% automatically convertible preferred stock, par value $0.0001 per share, each share of which will be convertible into 10,000 shares of common stock, par value $0.0001 per share (or a proportionate number of shares of common stock with respect to any fractional shares of preferred stock issued), for gross proceeds of approximately $400.1 million, equivalent to a placement at $7.25 per common share. We used the net proceeds from the sale of the preferred stock to partially fund the Pecos County Acquisition.

        The preferred stock will convert automatically into common stock on the 20th calendar day after we mail a definitive information statement to holders of our common stock notifying them that holders of a majority of our outstanding common stock consented to the issuance of common stock upon conversion of the preferred stock on January 24, 2017 (Successor). The initial conversion price is subject to adjustment in certain circumstances, including stock splits, stock dividends, rights offerings, or combinations of our common stock. No dividends will be due on the convertible preferred stock if it converts into common stock on or before June 1, 2017. The common stock issuable upon a conversion of the preferred stock represents approximately 37% of our outstanding common stock as of December 31, 2016 on an as-converted basis.

        We have agreed to file a registration statement to register the resale of the shares of common stock issuable upon conversion of the preferred stock and to pay penalties in the event such registration is not effective by June 27, 2017.

Acquisition of Southern Delaware Basin Assets (Pecos and Reeves Counties, Texas)

        On January 18, 2017 (Successor), we entered into a Purchase and Sale Agreement with Samson Exploration, LLC (Samson), pursuant to which we agreed to acquire a total of 20,901 net acres and related assets in the Southern Delaware Basin located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets), for a total purchase price of $705.0 million (the Pecos County Acquisition). The effective date of the acquisition is November 1, 2016, and we closed the transaction on February 28, 2017.

        Based on information provided by Samson, we estimate that current net production from the Pecos County Assets is approximately 2,600 Boe/d (72% oil, 15% NGLs, 13% natural gas). We estimate that the Pecos County Assets include a 75% average working interest, with approximately 44% held by production. After closing, we plan to operate two rigs.

        The purchase price is subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. We funded the Pecos County Acquisition with the net proceeds from the private placement of our preferred stock and borrowings under our Senior Credit Agreement.

        Following the agreement with Samson, we have agreed to acquire additional interests in the acreage from a non-operating owner for approximately $22.3 million. This incremental acquisition includes 594 additional net acres and approximately 160 Boe/d of current production and is expected to close in early March 2017.

Option Agreement to Acquire Southern Delaware Basin Assets (Ward County, Texas)

        On December 9, 2016 (Successor), we entered into an agreement with a private company, pursuant to which we have acquired the rights to purchase up to 15,040 net acres located in Ward and Winkler Counties, Texas (the Ward County Assets) prospective for the Wolfcamp and Bone Spring formations.

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The Ward County Assets are divided into two tracts: the Southern Tract, comprising 6,720 net acres, and the Northern Tract, comprising 8,320 net acres, with separate options for each tract. We paid $5.0 million for the option for the Southern Tract and are currently drilling a commitment well on the Southern Tract. We have until June 15, 2017 to exercise the option on either the Southern Tract acreage or on all 15,040 net acres, in each case for $11,000 per acre. If we initially elect only to exercise our option on the Southern Tract, we would need to pay $5.0 million on or before June 15, 2017 and drill a commitment well on the Northern Tract by September 1, 2017 to earn an option to acquire the Northern Tract acreage for $11,000 per acre by December 31, 2017.

Reorganization

        The prices of crude oil and natural gas declined dramatically from mid-year 2014 through 2016, reaching multi-year lows in late 2015 and early 2016, as a result of robust non-Organization of the Petroleum Exporting Countries' (OPEC) supply growth led by unconventional production in the United States, weak demand in emerging markets, and OPEC's decision to sustain high production levels during this period. In response to these developments, among other things, in 2015 and 2016 we reduced our spending and completed a series of transactions that resulted in the reduction of our debt by approximately $1.1 billion and reduced our annual interest burden by approximately $61.5 million. We also extended the maturity date and amended other provisions of certain of our debt agreements.

        These efforts proved insufficient in light of continued low commodity prices to ensure our ability to weather the downturn or position us to take advantage of opportunities that might arise. Accordingly, on July 27, 2016, we and certain of our subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware (the Bankruptcy Court) to pursue a prepackaged plan of reorganization in accordance with the terms of the Restructuring Support Agreement discussed below. Prior to filing the chapter 11 bankruptcy petitions, on June 9, 2016, the Halcón Entities entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of our 13% senior secured third lien notes due 2022 (the Third Lien Noteholders), our 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020 (collectively, the Unsecured Noteholders), the holder of our 8% senior unsecured convertible note due 2020 (the Convertible Noteholder), and certain holders of our 5.75% Series A Convertible Perpetual Preferred Stock (the Preferred Holders), to support a restructuring in accordance with the terms of a plan of reorganization as described therein (the Plan). On September 8, 2016, the Halcón Entities received confirmation of their joint prepackaged plan of reorganization from the Bankruptcy Court and subsequently emerged from chapter 11 bankruptcy on September 9, 2016 (the Effective Date).

        Upon emergence, pursuant to the terms of the Plan, the following significant transactions occurred:

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        Each of the foregoing percentages of equity in the reorganized company were as of September 9, 2016 and subject to dilution from the exercise of the new warrants described above, a management incentive plan and other future issuances of equity securities.

Fresh-start Accounting

        Upon our emergence from chapter 11 bankruptcy, on September 9, 2016, we adopted fresh-start accounting in accordance with the provisions set forth in Accounting Standards Codification (ASC) 852, Reorganizations, as (i) the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity.

        Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we have a new basis in our assets and liabilities. As a result of the adoption of fresh-start reporting and the effects of the implementation of the Plan, our consolidated financial statements subsequent to September 9, 2016 are not comparable to our consolidated financial statements prior to September 9, 2016. References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized Company subsequent to September 9, 2016. References to "Predecessor" or "Predecessor Company" related to the financial position and results of operations of the Company prior to, and including, September 9, 2016, as such, "black-line" financial statements are presented to distinguish between the Predecessor and Successor companies. Refer to Item 8. Consolidated Financial Statements and Supplementary Data - Note 3, "Fresh-start Accounting," for further details.

HK TMS Divestiture

        On September 30, 2016 (Successor), certain of our wholly-owned subsidiaries executed an Assignment and Assumption Agreement with an affiliate of Apollo Global Management (Apollo) pursuant to which Apollo acquired one hundred percent (100%) of the common shares (the Membership Interests) of HK TMS, LLC (HK TMS), which the transaction is referred to as the HK

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TMS Divestiture. HK TMS was previously a wholly-owned subsidiary of ours and held all of our oil and natural gas properties in the Tuscaloosa Marine Shale. In exchange for the assignment of the Membership Interests, Apollo assumed all obligations relating to the Membership Interests, which were previously classified as "Mezzanine Equity" on the consolidated balance sheets of HK TMS, from and after such date. The Tuscaloosa Marine Shale properties generated net production of approximately 530 Boe/d during the nine months ended September 30, 2016 and had 1.1 MMBoe of proved reserves at December 31, 2015 (Predecessor).

Successor Senior Revolving Credit Facility

        On the Effective Date, we entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP Facility, discussed below. The Senior Credit Agreement provides for a $1.5 billion senior secured reserve-based revolving credit facility with a current borrowing base of $600.0 million. The maturity date of the Senior Credit Agreement is the earlier of (i) July 28, 2021 and (ii) the 120th day prior to the February 1, 2020 stated maturity date of our 2020 Second Lien Notes (defined below), if such notes have not been refinanced, redeemed or repaid in full on or prior to such 120 th  day. The first borrowing base redetermination will be on May 1, 2017 and redeterminations will occur semi-annually thereafter, with us and the lenders 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 properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuate based on our utilization of the facility. We may elect, at our option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement). Additionally, if we have outstanding borrowings or letters of credit or reimbursement obligations in respect of letters of credit and the Consolidated Cash Balance (as defined in the Senior Credit Agreement) exceeds $100.0 million as of the close of business on the most recently ended business day, we may also be required to make mandatory prepayments.

        The Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) not to exceed 4.75:1.00 initially, determined as of each four fiscal quarter period and commencing with the fiscal quarter ending September 30, 2016, stepping down to 4.50:1.00 and 4.00:1.00 on September 30, 2017 and March 31, 2019, respectively, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00, commencing with the fiscal quarter ending December 31, 2016.

DIP Facility

        In connection with the chapter 11 bankruptcy proceedings, we entered into a commitment letter pursuant to which the lenders party thereto committed to provide, subject to certain conditions, a $600.0 million debtor-in-possession senior secured, super-priority revolving credit facility (the DIP Facility) and to replace it upon emergence with a $600.0 million senior secured reserve-based revolving credit facility, discussed above. Proceeds from the DIP Facility were used to refinance borrowings under our Predecessor Credit Agreement. Availability under the DIP Facility was $500.0 million upon interim approval by the Bankruptcy Court, and rose to $600.0 million upon entry of a final order. The DIP Facility was refinanced by the Senior Credit Agreement on the Effective Date. Loans under the DIP Facility bore interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or

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at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuated based on the utilization of the DIP Facility.

2017 Capital Budget

        We expect to spend approximately $300 million on drilling and completion capital expenditures during 2017. In addition, we expect to spend approximately $15 million on infrastructure, seismic and other in 2017. Approximately 65% of our 2017 drilling and completion budget is expected to be spent in the Bakken/Three Forks formations in North Dakota and approximately 35% is budgeted for the Southern Delaware Basin. Our 2017 drilling and completion budget currently contemplates running two to three operated rigs during the year, is based on our current view of market conditions and current business plans, and is subject to change.

        We expect to fund our budgeted 2017 capital expenditures with cash flows from operations and, to a lesser extent, with 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 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 long-term 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:

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Our Competitive Strengths

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

Oil and Natural Gas Reserves

        The proved reserves estimates shown herein for the years ended December 31, 2016 (Successor), 2015 and 2014 (Predecessor) have been independently evaluated 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 a practicing petroleum geoscience consultant at Netherland, Sewell since 1989 and has over ten years of prior industry experience. He graduated from Texas A&M University in 1978 with

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a Bachelor of Science Degree in Geology. Netherland, Sewell has reported to us that 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 SEC and other industry reserves definitions and guidelines.

        Our board of directors has established a reserves committee composed of three 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 approve the report prepared by our independent engineering firm. Ms. Tina Obut, our Senior Vice President of Corporate Reserves, is 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, 2016 (Successor). Average prices for the 12-month period were as follows: West Texas Intermediate (WTI) crude oil spot price of $42.75 per Bbl, adjusted by lease or field for quality, transportation fees, and market differentials and a Henry Hub natural gas spot price of $2.481 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 SEC guidelines.

        The following table presents certain proved reserve information as of December 31, 2016 (Successor).

(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, 2016 (Successor) and 2015 (Predecessor). Shut-in wells currently not capable of production are excluded from the well information below.

Oil and Natural Gas Production

Core Resource Plays

        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 116,000 net acres as of December 31, 2016 (Successor) prospective in 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 45 to 50 gross horizontal wells on our operated acreage in 2017 with an average working interest of 72%. In 2017, we expect to operate on average two rigs in the Williston Basin. As of December 31, 2016 (Successor), we had approximately 300 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, 2016 (Successor) was approximately 27,600 Boe/d. As of December 31, 2016 (Successor), estimated proved reserves for the Bakken/Three Forks formations were approximately 112.3 MMBoe, of which approximately 64% were classified as proved developed and approximately 36% as proved undeveloped.

Delaware Basin

        On February 28, 2017, we acquired 20,901 net acres in the Southern Delaware Basin in Pecos and Reeves Counties, Texas and we also have the option to acquire up to 15,040 net acres in Ward and Winkler Counties, Texas. If we exercise the options in full, we will have working interests in 35,941 net acres prospective for the Wolfcamp, Bone Spring and other formations in West Texas.

        Based on information provided by Samson, we estimate that current net production from the Pecos County Assets is approximately 2,600 Boe/d. We estimate that the Pecos County Assets include a 75% average working interest, with approximately 44% held by production.

Non-core Areas

East Texas Eagle Ford Formation (El Halcón)

        We have working interests in approximately 80,500 net acres as of December 31, 2016 (Successor) prospective for the Eagle Ford formation in Brazos, Burleson, and Robertson Counties, Texas, with targeted depths ranging from 7,000 feet to 10,000 feet. We finished 2016 with no operated rigs and approximately 191 gross (135 net) producing wells in this area. As of December 31, 2016 (Successor), estimated proved reserves for the El Halcón area were approximately 35.1 MMBoe, of which

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approximately 36% were classified as proved developed and approximately 64% as proved undeveloped. Our average daily net production from this area for the year ended December 31, 2016 (Successor) was approximately 7,600 Boe/d. On January 24, 2017 (Successor), we entered into an Agreement of Sale and Purchase with a subsidiary of Hawkwood Energy, LLC for the sale of the El Halcón Assets for a total sales price of $500.0 million. The transaction is expected to close in early March 2017.

Other Non-core Areas

        We have other oil and natural gas properties with varying working interests located in the Utica/Point Pleasant formations in Ohio and Pennsylvania and the Austin Chalk Trend in East Texas. Production from these other non-core areas totaled approximately 1,500 Boe/d for the year ended December 31, 2016 (Successor). As of December 31, 2016 (Successor), estimated proved reserves for these properties were approximately 1.2 MMBoe in aggregate, of which all were classified as proved developed. We may consider divesting certain of these assets over time.

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.

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. 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. Our objective generally is to hedge 70-80% of our anticipated oil and natural gas production for the next 18 to 24 months. However, 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. Our hedge policies and objectives change as our operational profile changes and/or commodity prices. Our future performance is subject to commodity price risks and our future cash flows from operations may be subject to greater volatility than historically. We do not enter into derivative contracts for speculative trading purposes.

        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.

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        It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. We did not post collateral under any of our derivative contracts as they are secured under our Senior Credit Agreement or are uncollateralized trades. 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 9 , "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.

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

(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

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and natural gas leases that have varying provisions. The following table presents a summary of our acreage interests as of December 31, 2016:

        The table below reflects the percentage of our total net undeveloped and mineral acreage as of December 31, 2016 that will expire each year 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.

        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, 2016 (Successor), we had estimated proved reserves of approximately 148.6 MMBoe comprised of 119.6 MMBbls of crude oil, 15.6 MMBbls of natural gas liquids, and 80.2 Bcf of natural gas. The following table sets forth, at December 31, 2016 (Successor), these reserves:

(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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        At December 31, 2016 (Successor), our estimated proved undeveloped (PUD) reserves were approximately 62.7 MMBoe, a 2.2 MMBoe net decrease over the previous year's estimate of 64.9 MMBoe. The following table details the changes in PUD reserves for 2016 (in MBoe):

        The decrease in PUD reserves was due to a negative revision associated with the decline in the unweighted 12-month average prices of oil and natural gas during 2016. Negative revisions of approximately 9 MMBoe were largely associated with PUD locations in the Bakken/Three Forks and El Halcón areas that became uneconomic at the lower unweighted 12-month average prices of oil and natural gas as of December 31, 2016 (Successor), or were removed because they no longer met the SEC five year development requirement as we have reduced our capital spending since the prior year as a result of the sustained decline in oil and natural gas prices. Further reductions of approximately 8 MMBoe in PUD reserves were the direct result of development through our drilling program and the associated transfer of those reserves to proved developed reserves, primarily in the Bakken/Three Forks and El Halcón areas.

        As of December 31, 2016 (Successor), all of our PUD reserves are planned to be developed within five years from the date they were initially recorded. During 2016, approximately $181.7 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-"Supplemental 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

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natural gas properties at March 31, June 30, and September 30, 2016 exceeded the respective ceiling amounts for each quarter end. As a result, we recorded full cost ceiling test impairments before income taxes of $754.8 million and $420.9 million for the period from January 1, 2016 through September 9, 2016 (Predecessor), and the period from September 10, 2016 through December 31, 2016 (Successor), respectively. See further discussion in Item 8. Consolidated Financial Statements and Supplementary Data -Note 6, "Oil and Natural Gas Properties."

        Capitalized costs of our evaluated and unevaluated properties at December 31, 2016 (Successor), 2015 and 2014 (Predecessor) are summarized as follows (in thousands):

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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:

(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 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, during the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), average crude oil sales prices were $68.99 and $69.25 per Bbl and average natural gas sales prices were $2.33 and $1.58 per Mcf, respectively. For the year ended December 31, 2015 and 2014 (Predecessor), including the impact of our settled derivative contracts, average crude oil sales prices were $78.50 and $84.72 per Bbl and average natural gas sales prices were $3.06 and $4.06 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. For the combined periods of September 10, 2016 through December 31, 2016 (Successor), and January 1, 2016 through September 9, 2016 (Predecessor), two individual purchasers of our production, Crestwood Midstream Partners, formerly Arrow Field Services LLC (Crestwood), and Suncor Energy Marketing Inc. (Suncor), each accounted for more than 10% of our total sales, collectively representing 58% of our total sales. In 2015 and 2014, three individual purchasers, Crestwood, Sunoco Inc. and Suncor, each accounted for more than 10% of our total sales, collectively representing 57% and 66% of our total sales for the year, respectively.

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.

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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 and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other events may cause accidental releases 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, tribal 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

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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 govern 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 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.

        Beyond existing requirements, new programs and changes in existing programs, 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 or to subject them to enhanced solid waste regulation. If such proposals were to be enacted, they could have a significant impact on our operating costs and on those 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.

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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 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. In the event of a discharge of oil into U.S. waters we could be liable under the Oil Pollution Act for clean up costs, damages and economic losses.

        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. In particular, 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 depths 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.

        Working at the direction of Congress, the EPA has completed a study finding that hydraulic fracturing could potentially harm drinking water resources under adverse circumstances such as injection directly into groundwater or into production wells lacking mechanical integrity. The EPA has also finalized pre-treatment standards under the Clean Water Act for wastewater discharges from shale hydraulic fracturing operations to municipal sewage treatment plants. Beyond that, several environmental groups have 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 and to require disclosure under the Toxic Substances Control Act of chemicals used in fracturing. Congress might likewise consider legislation to amend the federal SDWA 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, already have issued similar disclosure rules.

        In addition, the Department of the Interior has promulgated regulations concerning the use of hydraulic fracturing on lands under its jurisdiction, which includes lands on which we conduct or plan to conduct operations. States similarly have been imposing new restrictions or bans on hydraulic fracturing. Even local jurisdictions, such as Denton, Texas and several cities in Colorado, have adopted,

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or tried to adopt, regulations restricting hydraulic fracturing. Additional hydraulic fracturing requirements at the federal, state, tribal or local level may limit our ability to operate or increase our operating costs.

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.

        In 2012 and 2016, the EPA issued air regulations for the oil and natural gas industry that address emissions from certain new sources of volatile organic compounds, sulfur dioxide, air toxics, and methane. The rules include the first federal air standards for natural gas and oil wells that are hydraulically fractured, or refractured, as well as requirements for other processes and equipment, including storage tanks. Compliance with these regulations has imposed additional requirements and costs on our operations. The EPA also has started to consider whether to extend such regulations to existing wells.

        In October 2015, the EPA announced that it was lowering the primary national ambient air quality standard for ozone from 75 parts per billion to 70 parts per billion. Implementation will take place over several years; however, the new standard 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 increasingly 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, the Kyoto Protocol and the Paris Agreement 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 been 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 in issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities.

        In addition, the Obama Administration developed a Strategy to Reduce Methane Emissions that was intended to result by 2025 in a 40-45% decrease in methane emissions from the oil and gas

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industry as compared to 2012 levels. Consistent with that strategy, the EPA issued its air rules for oil and gas production sources, and the federal Bureau of Land Management (BLM) promulgated standards for reducing venting and flaring on public lands.

        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 and the Clean Water Act. 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, may result.

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, 2016 (Successor), we had 245 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, 2016 (Successor), we leased corporate office space in Houston, Texas at 1000 Louisiana Street, where our principal offices are located. We also lease corporate office space in Denver, Colorado as well as a number of other field office locations.

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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 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

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. The amount we will be able to borrow under our Senior Credit Agreement will be subject to periodic redeterminations 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 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:

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

Our actual financial results may vary materially from the projections that we filed with the bankruptcy court in connection with the confirmation of our plan of reorganization.

        In connection with the disclosure statement we filed with the bankruptcy court, and the hearing to consider confirmation of our plan of reorganization, we prepared projected financial information to demonstrate to the bankruptcy court the feasibility of the plan of reorganization and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

Our historical financial information may not be indicative of our future financial performance.

        On the effective date of our emergence from bankruptcy on September 9, 2016 we adopted fresh-start accounting, as a consequence of which our assets and liabilities were adjusted to fair values and we have no beginning or ending retained earnings or deficit balances. Accordingly, our financial condition and results of operations following our emergence from chapter 11 bankruptcy will not be comparable to the financial condition and results of operations reflected in our historical financial statements. Further, as a result of the implementation of our plan of reorganization and the transactions contemplated thereby, our historical financial information may not be indicative of our future financial performance.

Upon our emergence from bankruptcy, the composition of our Board of Directors changed significantly.

        Under the plan of reorganization, the composition of our Board of Directors (the Board) changed significantly from an eleven member Board with terms of one year to, upon emergence, a nine member Board, structured into three tiers and classified into staggered three year terms. Only three of our current directors served on our Board previously and a total of six of our directors were designated by Franklin Advisors, Inc. and Ares Management LLC. Our new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine our future.

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

        As of December 31, 2016, funds advised by Franklin Advisors, Inc. and Ares Management LLC held approximately 36% and 19%, respectively, of our post-reorganization common stock. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that,

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in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.

Future sales of our common stock in the public market or the issuance of securities senior to our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and our ability to raise funds in stock offerings.

        A large percentage of our shares of common stock are held by a relatively small number of investors. Further, we entered into registration rights agreements with certain of those investors pursuant to which we have agreed to file a registration statement with the SEC to facilitate potential future sales of such shares by them. Sales by us or our stockholders of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur (such as upon the filing of the aforementioned registration statement), could cause the market price of our common stock to decline or could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.

        We are currently authorized to issue 1.0 billion shares of common stock and 1.0 million shares of preferred stock, with such designations, rights, preferences, privileges and restrictions as determined by the Board. As of December 31, 2016, we had outstanding approximately 93.0 million shares of common stock and warrants and options to purchase an aggregate of 10.1 million shares of our common stock. On February 27, 2017 (Successor), we issued in a private placement, 5,518 shares of new 8% automatically convertible preferred stock, each share of which is convertible into 10,000 shares of common stock. The common stock issuable upon a conversion of the preferred stock represents approximately 37% of our outstanding common stock as of December 31, 2016 on an as-converted basis, or approximately 55.2 million shares of common stock.

        As of December 31, 2016, we have also reserved an additional 1.7 million shares for future issuance to our directors, officers and employees as restricted stock or stock option awards pursuant to our 2016 Long-Term Incentive Plan. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock.

        We may issue common stock or other equity securities senior to our common stock in the future for a number of reasons, including to finance acquisitions, to adjust our leverage ratio, and to satisfy our obligations upon the exercise of warrants and options, or for other reasons. We cannot predict the effect, if any, that future sales or issuances of shares of our common stock or other equity securities, or the availability of shares of common stock or such other equity securities for future sale or issuance, will have on the trading price of our common stock.

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

        Our business requires substantial capital expenditures primarily to fund our drilling program. We may also 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 operating cash flow and cash on hand.

        Our Senior Credit Agreement limits our borrowings to the lesser of the borrowing base and the total commitments. As of December 31, 2016, our Senior Credit Agreement had a borrowing base of approximately $600.0 million. As of December 31, 2016, we had $186.0 million of indebtedness

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outstanding, $6.7 million of letters of credit outstanding and $407.3 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. A reduction in our borrowing base could require us to repay any indebtedness in excess of the borrowing base. Our Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) not to exceed 4.75:1.00 initially, determined as of each four fiscal quarter periods and commencing with the fiscal quarter ending September 30, 2016, stepping down to 4.50:1.00 and 4.00:1.00 on September 30, 2017 and March 31, 2019, respectively, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00, commencing with the fiscal quarter ending December 31, 2016. In the event we have difficulty meeting the total net indebtedness leverage ratio test 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, the indentures governing our senior 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 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 generally, the amount thereof is not more than, subject to certain exceptions, the greater of (i) $900 million, (ii) the borrowing base in effect under our Senior Credit Agreement, and (iii) 30% of our adjusted consolidated net tangible assets, or ACNTA. ACNTA is defined in all of our indentures and is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves plus the capitalized cost attributable to our unevaluated properties. 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 ACNTA, and thus could reduce our ability to incur additional indebtedness.

        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.

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 do not improve 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

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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.

        In the past, due to the sustained decline in the unweighted 12-month average price of oil and natural gas used in the ceiling test calculations, we recorded full cost ceiling test impairments. During 2015, the net book value of our oil and natural gas properties at March 31, June 30, September 30, and December 31, 2015 exceeded the respective ceiling amounts for each quarter end. As a result, we recorded full cost ceiling test impairments before income taxes totaling $2.6 billion for the year ended December 31, 2015 (Predecessor). The ceiling test impairments in 2015 were driven by decreases in the first-day-of-the-month average prices for crude oil from $94.99 per Bbl at December 31, 2014 (Predecessor) to $50.28 per Bbl at December 31, 2015 (Predecessor).

        During 2016, the net book value of our oil and natural gas properties at March 31, June 30, and September 30, 2016 exceeded the respective ceiling amounts for each quarter end. As a result, we recorded full cost ceiling test impairments before income taxes of $420.9 million for the period of September 10, 2016 through September 30, 2016 (Successor) and $754.8 million for the period January 1, 2016 through September 9, 2016 (Predecessor). The impairment at September 30, 2016 primarily reflects the pricing differences between the first-day-of-the-month average price for the preceding twelve months required by Regulation S-X, Rule 4-10 and ASC 932 used in calculating the ceiling test and the forward-looking prices required by ASC 852 to estimate the fair value of the Company's oil and natural gas properties on the fresh-start reporting date, September 9, 2016. The ceiling test impairments at March 31 and June 30, 2016 were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2015. As ceiling test computations depend in part upon the calculated unweighted arithmetic average prices and oil and natural gas prices are inherently volatile, sustained lower commodity prices will continue to have a material impact upon our full cost ceiling test calculation. 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 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 $316.4 million at December 31, 2016 (Successor), 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.

Historically, we have had substantial indebtedness and we may incur substantially more debt in the future. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.

        We have incurred debt amounting to approximately $964.7 million as of December 31, 2016 (Successor). In addition, on February 16, 2017 (Successor), we issued $850.0 million aggregate principal amount of new 6.75% senior unsecured notes due 2025 in a private placement exempt from registration under the Securities Act of 1933, as amended, afforded by Rule 144A and Regulation S, and applicable

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state securities laws. The net proceeds from the private placement will fund the repurchase and redemption of all $700 million of our outstanding 2020 Second Lien Notes. As a result of our indebtedness, we will need to use a 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, 2016 (Successor), our Senior Credit Agreement had a borrowing base of approximately $600.0 million. At December 31, 2016 (Successor), we had $186.0 million of indebtedness outstanding, $6.7 million of letters of credit outstanding and $407.3 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 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.

Our ability to use net operating loss carryforwards to offset future taxable income for U.S. federal income tax purposes is subject to limitation.

        In general, under Section 382 of the Internal Revenue Code of 1986, as amended, a corporation that undergoes an "ownership change" is subject to limitations on its ability to utilize its pre-change net operating losses (NOLs), to offset future taxable income. In general, an ownership change occurs if the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years).

        We believe we experienced an ownership change in September 2016 as a result of the consummation of our plan of reorganization under chapter 11 of the U.S. Bankruptcy Code. Limitations imposed on our ability to use NOLs to offset future taxable income may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect and could cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. Similar rules and limitations may apply for state income tax purposes.

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

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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.

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 stable outlook by Standard and Poor's (S&P) and "B3" 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. 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.

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, 2016 (Successor), we owned leasehold interests in approximately 113,000 net acres in the Utica/Point Pleasant formation (Utica). Our current drilling plans for 2017 do not include any drilling or completion activities on our Utica acreage. Unless production in paying quantities is established on units containing these leases during their terms or unless we pay (to the extent we have the contractual right to pay) delay rentals or obtain other extensions to maintain the lease, these leases will expire. If our leases expire, we will lose our right to develop the related properties.

        Our drilling plans 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.

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

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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 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 (which may worsen due to climate changes), 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 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, results of operations, cash flows and potentially the borrowing capacity under our Senior Credit Agreement.

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

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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, 2016 (Successor), approximately 42% of our estimated proved 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.

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:

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        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 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:

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

        The indentures governing our debt and our Senior Credit Agreement 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:

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        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.

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.

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 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.

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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:

        Failure to comply with applicable laws may result in the suspension or termination of operations and subject us to liabilities, including administrative, civil and criminal penalties. Compliance costs can be significant. Moreover, the laws governing our operations 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 operations.

        Under environmental, health and safety laws and regulations, we also 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. Such laws 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. The North Dakota Industrial Commission (NDIC), the State's chief energy regulator, for example, approved comprehensive rules in 2016 for the conservation of crude oil and natural gas that address site

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construction, gathering pipelines and spill containment. Such 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. By way of example, in 2015 the EPA lowered the primary national ambient air quality standard for ozone from 75 parts per billion to 70 parts per billion. Implementation will take place over several years; however, the new standard eventually could result in more stringent emissions controls and additional permitting obligations for our operations.

Part of our strategy involves drilling in shale formations, 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 shale 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; consequently our predictions of drilling results in these areas are more uncertain. 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 could result in material write downs of unevaluated properties and future declines in the value of our undeveloped acreage.

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 SDWA to require federal permitting of hydraulic fracturing and the disclosure of chemicals used in the hydraulic fracturing process. Further, the EPA completed a study finding that hydraulic fracturing could potentially harm drinking water resources under adverse circumstances such as injection directly into groundwater or into production wells lacking mechanical integrity. Other governmental reviews have also been recently conducted or are under way that focus on environmental aspects of hydraulic fracturing. For example, a federal BLM rulemaking for hydraulic fracturing practices on federal and Indian lands resulted in a 2015 final rule that requires 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.

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        Certain states, including North Dakota and Texas where we conduct a majority of our 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 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.

        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, increasingly 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, the Kyoto Protocol and the Paris Agreement 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 pledged for the Paris Agreement to meet an economy-wide target in 2025 of reducing greenhouse gas emissions by 26-28% below the 2005 level. To help achieve these reductions, federal agencies have been addressing climate change through a variety of administrative actions. The EPA thus 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, then President Obama released a Strategy to Reduce Methane Emissions that included consideration of both voluntary programs and targeted regulations for the oil and gas sector. Consistent with that strategy, the EPA issued final rules in 2016 for new and modified oil and gas production sources (including hydraulically fractured oil wells, natural gas well sites, natural gas processing plants, natural gas gathering and boosting stations and natural gas transmission sources) to reduce emissions of methane as well as volatile organic compound and toxic pollutants. In addition, the BLM has promulgated standards for reducing venting and flaring on public lands. The EPA and BLM actions are part of a series of steps by the Obama Administration that were 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

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force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

        The direction of future U.S. climate change regulation is difficult to predict given the current uncertainties surrounding the policies of the Trump Administration. The EPA may or may not continue developing regulations to reduce greenhouse gas emissions from the oil and gas industry. Even if federal efforts in this area slow, states may continue pursuing climate regulations. 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, to obtain emission allowances or to pay emission taxes, 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. In 2014, the NDIC, the State's chief energy regulator, issued an order to reduce the volume of natural gas flared from oil wells in the Bakken / Three Forks formations. The State's current objectives are to cause operators to capture 85% of the natural gas by November 1, 2016, 88% by November 1, 2018 and 91-93% by November 1, 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 United States Department of Transportation (USDOT) has concluded that crude oil from the Bakken / Three Forks formations has a higher volatility than most other crude oil from the United States and thus is more ignitable and flammable. Based on that information, and several fires involving rail transportation of crude oil, USDOT imposed additional requirements for shipping crude oil by rail. Beyond that, the rail industry has adopted increased precautions for crude shipments. Any 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 28,500 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, natural gas liquids 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. On July 21, 2010, then 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 has finalized other regulations implementing the Dodd-Frank Act's provisions regarding trade reporting, margin, clearing, and trade execution; 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 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. Also, it is possible that under recently adopted margin rules, some registered swap dealers may require us to post initial and variation margins in connection with certain swaps not subject to central clearing.

        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, and reduce our ability to monetize or restructure our existing commodity derivative contracts. 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.

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We will be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult and may involve unexpected costs or delays.

        We have completed in the past and may complete in the future 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:

        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 or well site, 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:

        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.

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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:

        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.

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

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additional hedging transactions in the future. While intended to reduce the effects of volatile commodity prices, such transactions may limit our potential gains and increase our potential losses if commodity 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:

We are currently out of compliance with the New York Stock Exchange's average market capitalization requirement and are at risk of the NYSE delisting our common stock, which could materially impair the liquidity and value of our common stock.

        Our common stock is currently listed on the New York Stock Exchange (NYSE). On August 12, 2016, we were notified by the NYSE that the average market capitalization of our common stock was less than $50 million over a 30 trading day period, at the same time as our stockholders' equity was less than $50 million. In accordance with NYSE rules, we timely submitted a plan to regain compliance with the average market capitalization requirement, which we successfully executed as a consequence of our emergence from chapter 11 bankruptcy effective September 9, 2016. However, the NYSE has indicated it may take up to two calendar quarters for notice from the NYSE that compliance has been regained.

        A delisting of our common stock, either as result of a failure to regain compliance with the NYSE's average market capitalization requirement or the Company's failure to satisfy other qualitative or quantitative standards for continued listing on the NYSE, could reduce the liquidity and market price of our common stock.

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 11 , "Commitments and Contingencies," and is incorporated herein by reference.

        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 Successor common stock trades on the New York Stock Exchange (NYSE) under the symbol HK. On September 9, 2016, upon emergence from chapter 11 bankruptcy, all existing shares of our Predecessor common stock were cancelled and the Successor Company issued approximately 90.0 million shares of new common stock which began trading on the NYSE on September 12, 2016. The following table sets forth the quarterly high and low sales prices per share of our Successor common stock as reported on the NYSE from September 12, 2016 through December 31, 2016. Refer to Item 8. Consolidated Financial Statements and Supplementary Data- Note 2, " Reorganization, " for further details.

        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 and will be dependent upon then existing conditions, including our prospects, and such other factors, as the Board 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 727 registered stockholders of record as of February 23, 2017 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

        There were no purchases of equity securities during the three months ended December 31, 2016 (Successor).

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Stock Performance Graph

        The following graph and table compare the cumulative total return to our stockholders on our Successor common stock beginning September 12, 2016 through December 31, 2016, relative to the cumulative total returns of the NYSE Composite Index and the S&P Oil & Gas Exploration & Production Index for the same period. 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 Successor common stock on September 12, 2016, and in each of the indexes, and relative performance is tracked through December 31, 2016. The identity of the companies included in the S&P Oil & Gas Exploration & Production Index will be provided upon request.

COMPARISON OF 4 MONTH CUMULATIVE TOTAL RETURN*
Among Halcón Resources Corporation, the NYSE Composite Index,
and S&P Oil & Gas Exploration & Production index

Value of Initial $100 Investment

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ITEM 6.    SELECTED FINANCIAL DATA

        Prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh-start accounting. References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized Company subsequent to September 9, 2016. References to "Predecessor" or "Predecessor Company" relate to the financial position and results of operations of the Company prior to, and including, September 9, 2016.

        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 the footnotes in Item 8. Consolidated Financial Statements and Supplementary Data, for details regarding our recent reorganization and adoption of fresh-start accounting, as well as other transactions that could impact the comparability of the following data (in thousands, except per share data):

(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 September 9, 2016, upon emergence from chapter 11 bankruptcy, approximately $1.9 billion of our senior notes were cancelled. Refer to Item 8. Consolidated Financial Statements and Supplementary Data-Note 2, "Reorganization," for additional information.
(4) On June 16, 2014, HK TMS, LLC (HK TMS), which was then a wholly owned subsidiary of the Company, entered into a transaction with funds and accounts managed by Apollo Global Management, LLC (Apollo), by initially selling 150,000 preferred shares in HK TMS (Membership Interests), which then held all of our acreage in the Tuscaloosa Marine Shale, located in Mississippi and Louisiana. On September 30, 2016, Apollo acquired one hundred percent of the common shares of HK TMS and assumed all obligations relating to the Membership Interests. For additional information regarding these transactions, see Item 8. Consolidated Financial Statements and Supplementary Data-Note 5, "Divestitures" and Note 12, "Mezzanine Equity."

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(5) Predecessor preferred stock outstanding at December 31, 2012 converted into 21.8 million shares of our Predecessor common stock on January 18, 2013, following stockholder approval.
(6) On September 9, 2016, upon emergence from chapter 11 bankruptcy, all existing shares of Predecessor common stock were cancelled and the Successor Company issued approximately 90.0 million shares of new common stock in total to the Predecessor Company's existing common stockholders, Third Lien Noteholders, Unsecured Noteholders, and the Convertible Noteholder. Refer to Item 8. Consolidated Financial Statements and Supplementary Data-Note 2, "Reorganization," for further details.
(7) For the period from September 10, 2016 through December 31, 2016 (Successor), we incurred a $420.9 million full cost ceiling impairment on the carrying value of our oil and natural gas properties. Refer to Item 8. Consolidated Financial Statements and Supplementary Data-Note 6, "Oil and Natural Gas Properties," for additional information.
(8) For the period from January 1, 2016 through September 9, 2016 (Successor), we incurred a $754.8 million full cost ceiling impairment on the carrying value of our oil and natural gas properties, a $28.1 million impairment on other operating property and equipment, an $81.4 million gain on extinguishment of debt, and a $913.7 million gain on reorganization items due to fresh-start accounting. Refer to the footnotes in Item 8. Consolidated Financial Statements and Supplementary Data, for additional information regarding these events.
(9) For the year ended December 31, 2015 (Predecessor), we incurred a $2.6 billion full cost ceiling impairment on the carrying value of our oil and natural gas properties. Refer to Item 8. Consolidated Financial Statements and Supplementary Data-Note 6,"Oil and Natural Gas Properties," for additional information regarding this impairment.
(10) For the year ended December 31, 2014 (Predecessor), 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.
(11) For the year ended December 31, 2013 (Predecessor), 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.

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

        The following discussion is intended to assist 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.

        Prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh-start accounting. References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized Company subsequent to September 9, 2016. References to "Predecessor" or "Predecessor Company" relate to the financial position and results of operations of the Company prior to, and including, September 9, 2016.

        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, recapitalized on February 8, 2012 and reorganized on September 9, 2016. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in select prospect areas. In the years since, we have primarily focused on the development of acquired properties and also divested non-core assets in order to fund activities in our core resource plays. Our oil and natural gas assets consist of proved reserves and undeveloped acreage positions in unconventional liquids-rich basins/fields, providing us with an extensive drilling inventory in multiple basins that we believe allow for multiple years of production and broad flexibility to direct our capital resources to projects with the greatest potential returns. As discussed below in more detail under "Recent Developments," we have recently acquired certain properties in the Southern Delaware Basin for $705.0 million and entered into an agreement to sell our assets located in the El Halcón area of East Texas for $500.0 million, which is expected to close by early March 2017.

        At December 31, 2016 (Successor), our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc. (Netherland, Sewell), using Securities and Exchange Commission (SEC) prices of $42.75 per Bbl of oil and $2.481 per MMBtu of natural gas, were approximately 148.6 MMBoe, consisting of 119.6 MMBbls of oil, 15.6 MMBbls of natural gas liquids, and 80.2 Bcf of natural gas. Approximately 58% of our proved reserves were classified as proved developed as of December 31, 2016 (Successor). We maintain operational control of approximately 95% of our proved reserves.

        Our total operating revenues for the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) were approximately $153.4 million and $266.8 million, respectively, or $420.2 million combined, compared to total operating revenues for 2015 of $550.3 million. The decrease in total operating revenues year over year was driven by the sustained decline in the prices of crude oil and, to a lesser extent, natural gas along with a decrease in our average daily production year over year. During the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), production averaged 37,637 Boe/d and 36,787 Boe/d, respectively, or 37,049 Boe/d combined, compared to average daily production of 41,542 Boe/d during 2015 (Predecessor). In response to the sustained decline in commodity prices we reduced our drilling and completion activities in 2016, running only one rig on average in our most economic drilling area. In

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2016 (for the combined Successor and Predecessor periods), we participated in the drilling of 90 gross (30.6 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.

        In 2016, (for the combined Successor and Predecessor periods) we incurred capital expenditures for drilling and completions of approximately $183.9 million. We expect to spend approximately $300 million on drilling and completion capital expenditures during 2017. In addition, we expect to spend approximately $15 million on infrastructure, seismic and other in 2017. Approximately 65% of our 2017 drilling and completion budget is expected to be spent in the Bakken/Three Forks formations in North Dakota and approximately 35% is budgeted for the Southern Delaware Basin. Our 2017 drilling and completion budget currently contemplates growing to four (on average) operated rigs during the second quarter of 2017, is based on our current view of market conditions and current business plans, and is subject to change.

        We expect to fund our budgeted 2017 capital expenditures with cash flows from operations and, to a lesser extent, 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 have declined dramatically since mid-year 2014. In response to this we have significantly curtailed our capital spending, reduced operating costs, and have incurred substantial asset impairments, primarily as a result of the full cost ceiling test calculation. The ceiling test 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. Using the crude oil price for February 2017 of $53.88 per Bbl, and holding it constant for one month to create a trailing 12-month period of average prices that is more reflective of recent price trends, our ceiling test limitation would not have generated an impairment at December 31, 2016 holding all other inputs and factors constant. Sustained lower commodity prices would have a material impact upon our full cost ceiling test calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Recent Developments

Issuance of 2025 Senior Notes and Repurchase of 2020 Second Lien Notes

        On February 16, 2017 (Successor), we issued $850.0 million aggregate principal amount of our new 6.75% senior unsecured notes due 2025 (the 2025 Notes) in a private placement exempt from registration under the Securities Act of 1933, as amended (Securities Act), afforded by Rule 144A and Regulation S, and applicable state securities laws. The 2025 Notes were issued at par and bear interest at a rate of 6.75% per annum, payable semi-annually on February 15 and August 15 of each year,

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beginning on August 15, 2017. Proceeds from the private placement were approximately $835.1 million after deducting initial purchasers' discounts and commissions and offering expenses. We utilized a portion of the net proceeds from the private placement to fund the repurchase of the outstanding 2020 Second Lien Notes and will use an additional amount of the net proceeds to redeem the remaining amount of such notes, discussed further below, and for general corporate purposes.

        On February 9, 2017 (Successor), we commenced a cash tender offer for any and all of our 2020 Second Lien Notes and on February 15, 2017, we received approximately $289.2 million or 41% of the outstanding aggregate principal amount of the 2020 Second Lien Notes which were validly tendered (and not validly withdrawn). As a result, on February 16, 2017 (Successor), we paid approximately $303.5 million for approximately $289.2 million principal amount of 2020 Second Lien Notes, a make-whole premium of $13.2 million plus accrued and unpaid interest of approximately $1.1 million to repurchase such notes pursuant to the tender offer and issued a redemption notice to redeem the remaining 2020 Second Lien Notes. The remaining $410.8 million aggregate principal amount of outstanding 2020 Second Lien Notes will be repurchased through the guaranteed delivery procedures or redeemed at a price of 104.313% of the principal amount thereof, plus accrued and unpaid interest to, but not including, the redemption date. The redemption date is expected to be March 20, 2017.

Pending Divestiture of East Texas Eagle Ford Assets

        On January 24, 2017 (Successor), certain of our subsidiaries entered into an Agreement of Sale and Purchase with a subsidiary of Hawkwood Energy, LLC (Hawkwood) for the sale of all of our oil and natural gas properties and related assets located in the Eagle Ford formation of East Texas (the El Halcón Assets) for a total sales price of $500.0 million (the El Halcón Divestiture). The effective date of the proposed sale is January 1, 2017, and we expect to close the transaction in early March 2017. The sale properties include approximately 80,500 net acres prospective for the Eagle Ford formation in East Texas. As of December 31, 2016, estimated proved reserves from these properties were approximately 35.1 MMBoe, or 24% of our estimated year-end 2016 proved reserves. The sale includes approximately 191 gross (135 net) wells that produced approximately 7,600 Boe/d (80% oil) for the year ended December 31, 2016.

        The sales price is subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. Pursuant to the terms of the agreement, Hawkwood paid into escrow a deposit of $32.5 million at signing, which amount will be applied to the sales price if the transaction closes.

        The completion of the El Halcón Divestiture is subject to customary closing conditions. The parties may terminate the sale agreement if certain closing conditions have not been satisfied, if total adjustments to the sales price exceed 20% of the sales price, or $100.0 million, or the transaction has not closed on or before March 20, 2017. If one or more of the closing conditions are not satisfied, or if the transaction is otherwise terminated, the divestiture may not be completed. There can be no assurance that we will sell the El Halcón Assets on the terms or timing described or at all. If the El Halcón Divestiture closes, we intend to use the net proceeds to repay amounts outstanding under our Senior Credit Agreement and for general corporate purposes.

Private Placement of Automatically Convertible Preferred Stock

        On January 24, 2017 (Successor), we entered into a stock purchase agreement with certain accredited investors to sell, in a private placement exempt from the registration requirements of the Securities Act pursuant to Section 4(a)(2), approximately 5,518 shares of 8% automatically convertible preferred stock, par value $0.0001 per share, each share of which will be convertible into 10,000 shares of common stock, par value $0.0001 per share (or a proportionate number of shares of common stock with respect to any fractional shares of preferred stock issued), for gross proceeds of approximately

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$400.1 million, equivalent to a placement at $7.25 per common share. We used the net proceeds from the sale of the preferred stock to partially fund the Pecos County Acquisition.

        The preferred stock will convert automatically into common stock on the 20th calendar day after we mail a definitive information statement to holders of our common stock notifying them that holders of a majority of our outstanding common stock consented to the issuance of common stock upon conversion of the preferred stock on January 24, 2017 (Successor). The initial conversion price is subject to adjustment in certain circumstances, including stock splits, stock dividends, rights offerings, or combinations of our common stock. No dividends will be due on the convertible preferred stock if it converts into common stock on or before June 1, 2017. The common stock issuable upon a conversion of the preferred stock represents approximately 37% of our outstanding common stock as of December 31, 2016 on an as-converted basis.

        We have agreed to file a registration statement to register the resale of the shares of common stock issuable upon conversion of the preferred stock and to pay penalties in the event such registration is not effective by June 27, 2017.

Acquisition of Southern Delaware Basin Assets (Pecos and Reeves Counties, Texas)

        On January 18, 2017 (Successor), we entered into a Purchase and Sale Agreement with Samson Exploration, LLC (Samson), pursuant to which we agreed to acquire a total of 20,901 net acres and related assets in the Southern Delaware Basin located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets), for a total purchase price of $705.0 million (the Pecos County Acquisition). The effective date of the acquisition was November 1, 2016, and we closed the transaction on February 28, 2017.

        Based on information provided by Samson, we estimate that current net production from the Pecos County Assets is approximately 2,600 Boe/d (72% oil, 15% NGLs, 13% natural gas). We estimate that the Pecos County Assets include a 75% average working interest, with approximately 44% held by production. After closing, we plan to operate two rigs.

        The purchase price was subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. We funded the Pecos County Acquisition with the net proceeds from the private placement of our preferred stock and borrowings under our Senior Credit Agreement.

        Following the agreement with Samson, we have agreed to acquire additional interests in the acreage from a non-operating owner for approximately $22.3 million. This incremental acquisition includes 594 additional net acres and approximately 160 Boe/d of current production and is expected to close in early March 2017.

Option Agreement to Acquire Southern Delaware Basin Assets (Ward County, Texas)

        On December 9, 2016 (Successor), we entered into an agreement with a private company, pursuant to which we have acquired the rights to purchase up to 15,040 net acres located in Ward and Winkler Counties, Texas (the Ward County Assets) prospective for the Wolfcamp and Bone Spring formations. The Ward County Assets are divided into two tracts: the Southern Tract, comprising 6,720 net acres, and the Northern Tract, comprising 8,320 net acres, with separate options for each tract. We paid $5.0 million for the option for the Southern Tract and are currently drilling a commitment well on the Southern Tract. We have until June 15, 2017 to exercise the option on either the Southern Tract acreage or on all 15,040 net acres, in each case for $11,000 per acre. If we initially elect only to exercise our option on the Southern Tract, we would need to pay $5.0 million on or before June 15, 2017 and drill a commitment well on the Northern Tract by September 1, 2017 to earn an option to acquire the Northern Tract acreage for $11,000 per acre by December 31, 2017.

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Reorganization

        The prices of crude oil and natural gas declined dramatically from mid-year 2014 through 2016, reaching multi-year lows, as a result of robust non-Organization of the Petroleum Exporting Countries' (OPEC) supply growth led by unconventional production in the United States, weak demand in emerging markets, and OPEC's decision to sustain high production levels during this period. In response to these developments, among other things, in 2015 and 2016 we reduced our spending and completed a series of transactions that resulted in the reduction of our debt by approximately $1.1 billion and reduced our annual interest burden by approximately $61.5 million. We also extended the maturity date and amended other provisions of certain of our debt agreements.

        These efforts proved insufficient in light of continued low commodity prices to ensure our ability to weather the current downturn or position us to take advantage of opportunities that might arise. Accordingly, on July 27, 2016, we and certain of our subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware (the Bankruptcy Court) to pursue a prepackaged plan of reorganization in accordance with the terms of the Restructuring Support Agreement discussed below. Prior to filing the chapter 11 bankruptcy petitions, on June 9, 2016, the Halcón Entities entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of our 13% senior secured third lien notes due 2022 (the Third Lien Noteholders), our 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020 (collectively, the Unsecured Noteholders), the holder of our 8% senior unsecured convertible note due 2020 (the Convertible Noteholder), and certain holders of our 5.75% Series A Convertible Perpetual Preferred Stock (the Preferred Holders), to support a restructuring in accordance with the terms of a plan of reorganization as described therein (the Plan). On September 8, 2016, the Halcón Entities received confirmation of their joint prepackaged plan of reorganization from the Bankruptcy Court and subsequently emerged from chapter 11 bankruptcy on September 9, 2016 (the Effective Date).

        Upon emergence, pursuant to the terms of the Plan, the following significant transactions occurred:

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purchase 1% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), in full and final satisfaction of their claims;

        Each of the foregoing percentages of equity in the reorganized company were as of September 9, 2016 and subject to dilution from the exercise of the new warrants described above, a management incentive plan and other future issuances of equity securities.

Fresh-start Accounting

        Upon our emergence from chapter 11 bankruptcy, on September 9, 2016, we adopted fresh-start accounting in accordance with the provisions set forth in Accounting Standards Codification (ASC) 852, Reorganizations, as (i) the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity.

        Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we have a new basis in our assets and liabilities. As a result of the adoption of fresh-start reporting and the effects of the implementation of the Plan, our consolidated financial statements subsequent to September 9, 2016 are not comparable to our consolidated financial statements prior to September 9, 2016, as such, "black-line" financial statements are presented to distinguish between the Predecessor and Successor companies. Refer to Item 8. Consolidated Financial Statements and Supplementary Data-Note 3, "Fresh-start Accounting," for more details.

HK TMS Divestiture

        On September 30, 2016 (Successor), certain of our wholly-owned subsidiaries executed an Assignment and Assumption Agreement with an affiliate of Apollo Global Management (Apollo) pursuant to which Apollo acquired one hundred percent (100%) of the common shares (the Membership Interests) of HK TMS, LLC (HK TMS), which the transaction is referred to as the HK TMS Divestiture. HK TMS was previously a wholly-owned subsidiary of ours and held all of our oil and natural gas properties in the Tuscaloosa Marine Shale (TMS). In exchange for the assignment of the Membership Interests, Apollo assumed all obligations relating to the Membership Interests, which were previously classified as "Mezzanine Equity" on the consolidated balance sheets of HK TMS, from and after such date. The TMS properties generated net production of approximately 530 Boe/d during the nine months ended September 30, 2016 and had 1.1 MMBoe of proved reserves at December 31, 2015 (Predecessor).

Successor Senior Revolving Credit Facility

        On the Effective Date, we entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and certain other

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financial institutions party thereto, as lenders, which refinanced the DIP Facility, discussed below. The Senior Credit Agreement provides for a $1.5 billion senior secured reserve-based revolving credit facility with a current borrowing base of $600.0 million. The maturity date of the Senior Credit Agreement is the earlier of (i) July 28, 2021 and (ii) the 120th day prior to the February 1, 2020 stated maturity date of our 2020 Second Lien Notes (defined below), if such notes have not been refinanced, redeemed or repaid in full on or prior to such 120 th  day. The first borrowing base redetermination will be on May 1, 2017 and redeterminations will occur semi-annually thereafter, with us and the lenders 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 properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuate based on our utilization of the facility. We may elect, at our option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement). Additionally, if we have outstanding borrowings or letters of credit or reimbursement obligations in respect of letters of credit and the Consolidated Cash Balance (as defined in the Senior Credit Agreement) exceeds $100.0 million as of the close of business on the most recently ended business day, we may also be required to make mandatory prepayments.

        The Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) not to exceed 4.75:1.00 initially, determined as of each four fiscal quarter period and commencing with the fiscal quarter ending September 30, 2016, stepping down to 4.50:1.00 and 4.00:1.00 on September 30, 2017 and March 31, 2019, respectively, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00, commencing with the fiscal quarter ending December 31, 2016.

DIP Facility

        In connection with the chapter 11 bankruptcy proceedings, we entered into a commitment letter pursuant to which the lenders party thereto committed to provide, subject to certain conditions, a $600.0 million debtor-in-possession senior secured, super-priority revolving credit facility (the DIP Facility) and to replace it upon emergence with a $600.0 million senior secured reserve-based revolving credit facility, discussed above. Proceeds from the DIP Facility were used to refinance borrowings under our Predecessor Credit Agreement. Availability under the DIP Facility was $500.0 million upon interim approval by the Bankruptcy Court, and rose to $600.0 million upon entry of a final order. The DIP Facility was refinanced by the Senior Credit Agreement on the Effective Date. Loans under the DIP Facility bore interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuated based on the utilization of the DIP Facility.

Capital Resources and Liquidity

        Our near-term capital spending requirements are expected to be funded with cash flows from operations and borrowings under our Senior Credit Agreement, the terms of which are discussed above.

        The Senior Credit Agreement contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) not to exceed 4.75:1.00 initially, determined as of each four fiscal quarter period and commencing with the fiscal quarter ending September 30, 2016, stepping down to 4.50:1.00 and 4.00:1.00 on September 30, 2017

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and March 31, 2019, respectively, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00, commencing with the fiscal quarter ending December 31, 2016. At December 31, 2016, we had approximately $186.0 million of indebtedness outstanding, $6.7 million letters of credit outstanding and approximately $407.3 million of borrowing capacity available under our Senior Credit Agreement. At December 31, 2016, we were in compliance with the financial covenants under the Senior Credit Agreement.

        We have in the past obtained amendments to the covenants under our financing agreements under circumstances where we anticipated that it might be challenging for us to comply with our financial covenants for a particular period of time. For example, under the Predecessor Credit Agreement, we received a reduction in the minimum required interest coverage ratio of 2.0 to 1.0 on March 21, 2014 and again on February 25, 2015. The basis for these amendment and waiver requests was the potential for us to fall out of compliance as a result of our strategic decisions. Declining commodity prices also adversely impacted our ability to comply with these covenants. As part of our plan to manage liquidity risks, we scaled back our capital expenditures budget, focused our drilling program on our highest return projects, continued to explore opportunities to divest non-core properties and completed our reorganization (as described above). Upon consummation of the Plan and emergence from chapter 11 bankruptcy, approximately $2.0 billion of our debt obligations were cancelled, reducing our ongoing interest obligations by more than $200 million annually.

        In the event that we are unable to access sufficient capital to fund our business and planned capital expenditures, we may be required to further curtail our drilling, development, land acquisition and other activities, which could result in a decrease in our production of oil and natural gas, subject us to forfeitures of leasehold interests to the extent we are unable or unwilling to renew them, and force us 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.

        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 proved 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 successes.

        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 since mid-year 2014, our ability to finance our capital budget and operations may be adversely impacted. While we use derivative instruments to provide partial protection against declines in oil and natural gas prices, the total volumes we hedge varies from period to period based on our view of current and future market conditions. Our hedge

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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

        Historically, our primary sources of cash were from operating and financing activities. For the period of January 1, 2016 through September 9, 2016 (Predecessor), cash generated by operating and financing activities was used to fund our drilling and completion program and to support our reorganization plan. For the period of September 10, 2016 through December 31, 2016 (Successor), cash generated by operating activities was used to fund our drilling and completion program and make repayments on our Senior Credit Agreement. See "Results of Operations" for a review of the impact of prices and volumes on sales. The period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) are distinct reporting periods as a result of our emergence from chapter 11 bankruptcy on September 9, 2016 and are not comparable to prior periods.

        Net increase (decrease) in cash is summarized as follows (in thousands):

        Operating Activities.     Net cash provided by operating activities for the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) were $103.1 million and $175.3 million, respectively. Net cash provided by operating activities were $467.0 million and $667.9 million for the years ended December 31, 2015 and 2014 (Predecessor), respectively. Key drivers of net operating cash flows are commodity prices, production volumes, operating costs, and in 2016 and 2015, realized settlements on our derivative contracts.

        For the period September 10, 2016 through December 31, 2016 (Successor), cash flows were modestly impacted by changes in our working capital. For the period January 1, 2016 through September 9, 2016 (Predecessor) our net operating cash flows were $175.3 million, which resulted primarily from realized settlements on our derivative contracts that were partially offset by transaction costs related to our chapter 11 bankruptcy and reorganization activities.

        For the year ended December 31, 2015, the $467.0 million of net cash provided by operating activities primarily reflects the impact of realized settlements on our derivative contracts of $418.4 million, which largely mitigated the decrease in revenues due to lower commodity prices, as compared to the prior year period. Cash operating expenses also decreased over the prior year period.

        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.

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        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 for the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) were $63.0 million and $227.8 million, respectively. Net cash used in investing activities was $667.1 million and $1.3 billion for the years ended December 31, 2015 and 2014 (Predecessor), respectively.

        During the period of September 10, 2016 through December 31, 2016 (Successor), we spent $61.5 million on oil and natural gas capital expenditures, of which $54.4 million related to drilling and completion costs. During the period of January 1, 2016 through September 9, 2016 (Predecessor), we spent $226.6 million on oil and natural gas capital expenditures, of which $129.5 million related to drilling and completion costs and the remainder was primarily associated with capitalized interest, and to a lesser extent, leasing and seismic data. In 2016 (for the combined Successor and Predecessor periods), we participated in the drilling of 90 gross (30.6 net) wells, all of which were completed and capable of production.

        In 2015, we used $659.4 million of cash on oil and natural gas capital expenditures, of which $508.4 million related to drilling and completion costs and the remainder was primarily associated with capitalized interest, leasing and seismic data. We participated in the drilling of 184 gross (49.0 net) wells, all of which were completed and capable of production. We significantly decreased our capital spending for 2015, as compared to capital expenditure levels in prior years, in response to the significant decrease in crude oil prices over the latter of 2014 and throughout 2015, and our expectation that prices may not recover in the near term. Cash paid for drilling and completion costs during the year were attributable to both costs incurred before we slowed our drilling and completion program and costs related to wells spud or drilled during the period.

        In 2014, we used $1.5 billion of cash on oil and natural gas capital expenditures, of which $1.2 billion related to drilling and completion costs and the remainder was primarily 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, we received proceeds of approximately $33.8 million from the conveyance of an overriding royalty interest to Apollo.

        Financing Activities.     Net cash flows used in financing activities for the period of September 10, 2016 through December 31, 2016 (Successor) were $54.0 million and net cash flows provided by financing activities for the period of January 1, 2016 through September 9, 2016 (Predecessor) were $58.3 million. Net cash flows provided by financing activities were $164.4 million and $644.0 million for the years ended December 31, 2015 and 2014 (Predecessor), respectively.

        During the period of September 10, 2016 through December 31, 2016 (Successor), we paid a consent fee of approximately $10.0 million to holders of our Second Lien Notes and made net repayments of $44.0 million on our Senior Credit Agreement. The primary drivers of cash provided by financing activities for the period of January 1, 2016 through September 9, 2016 (Predecessor) were net borrowings on our Predecessor Credit Agreement, offset by cash payments totaling $97.5 million made to the Third Lien Noteholders, Unsecured Noteholders, Convertible Noteholder and Preferred Holders in accordance with the Plan.

        During the first quarter of 2016 (Predecessor), we repurchased approximately $24.5 million principal amount of our 9.75% senior notes due 2020, $51.8 million principal amount of our 8.875% senior notes due 2021, and $15.5 million principal amount of our 9.25% senior notes due 2022. The net cash used to make these repurchases was approximately $9.7 million and we recognized an $81.4 million net gain on the extinguishment of debt, as an $82.1 million gain on the repurchase was partially offset by the write-down of $0.7 million associated with related issuance costs and discounts and premiums for the respective senior unsecured notes. Upon settlement of the repurchases, we paid all accrued and unpaid interest since the respective interest payment dates of the senior unsecured notes repurchased.

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        During the fourth quarter of 2015 (Predecessor), we repurchased approximately $6.2 million principal amount of our 9.75% senior notes due 2020, $28.0 million principal amount of our 8.875% senior notes due 2021, and $10.3 million principal amount of our 9.25% senior notes due 2022. The net cash used to make these repurchases was approximately $14.8 million and we recognized a $29.4 million net gain on the extinguishment of debt, as a $29.7 million gain on the repurchase was partially offset by the write-down of $0.3 million associated with related issuance costs and discounts and premiums for the respective unsecured notes. Upon settlement of the repurchases, we paid all accrued and unpaid interest since the respective interest payment dates of the notes repurchased.

        On May 1, 2015 (Predecessor), we completed the issuance of $700.0 million aggregate principal amount of our 2020 Second Lien Notes. The net proceeds from the offering were approximately $686.2 million after deducting commissions and offering expenses and were used to repay a majority of the then outstanding borrowings under our Predecessor Credit Agreement.

        Cash flows provided by financing activities include net borrowings under our Predecessor Credit Agreement of $62.0 million for the year ended December 31, 2015 (Predecessor), primarily used to fund drilling and completion activities and other general corporate purposes.

        During the year ended December 31, 2015, cash flows from financing activities were modestly impacted by sales of our Predecessor common stock. For the year ended December 31, 2015 (Predecessor), we sold approximately 1.9 million shares for net proceeds of approximately $15.0 million, after deducting offering expenses.

        On June 16, 2014 (Predecessor), our subsidiary, HK TMS, entered into a transaction with Apollo by initially selling 150,000 preferred shares in HK TMS, which held all of our acreage in the TMS, located in Mississippi and Louisiana. 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 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 were used to develop the TMS.

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

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entities. The following table summarizes our contractual obligations and commitments by payment periods as of December 31, 2016 (Successor).

(1) Excludes a $27.4 million unamortized discount.
(2) On February 16, 2017, we issued $850.0 million aggregate principal amount of new 6.75% senior unsecured notes due 2025. We utilized a portion of the net proceeds from the issuance of the new 6.75% senior unsecured notes to repurchase approximately $289.2 million aggregate principal amount of the 2020 Second Lien Notes and will use the remaining net proceeds to redeem the remaining $410.8 million aggregate principal amount of 2020 Second Lien Notes and for general corporate purposes. These transactions are not included in the table above. See "6.75% Senior Notes" below and Item 8. Consolidated Financial Statements and Supplementary Data-Note 17, "Subsequent Events," for more details.
(3) Excludes a $6.8 million unamortized discount.
(4) Future interest expense was calculated based on interest rates and debt amounts outstanding at December 31, 2016 less required annual repayments.

        We lease corporate office space in Houston, Texas and Denver, Colorado as well as a number of other field office locations. Rent expense was approximately $1.4 million for the period of September 10, 2016 through December 31, 2016 (Successor) and $5.9 million for the period January 1, 2016 through September 30, 2016 (Predecessor). Rent expense was approximately $8.6 million and $8.1 million for the years ended December 31, 2015 and 2014 (Predecessor), respectively. In connection with the chapter 11 bankruptcy, we modified and rejected certain office lease arrangements and paid approximately $3.4 million for these modifications and rejections subsequent to the emergence from chapter 11 bankruptcy. Future obligations associated with our operating leases are presented in the table above.

        On December 9, 2016, we entered into an agreement with a private operator for the right to purchase the Ward County Assets. The Ward County Assets are divided into two tracts: the Southern Tract (6,720 net acres) and the Northern Tract (8,320 net acres) with separate options for each tract. Pursuant to the terms of the agreement, in January 2017, we paid $5.0 million and began drilling a commitment well on the Southern Tract. We have until June 15, 2017 to exercise the option on either the Southern Tract acreage or on all 15,040 net acres, in each case for $11,000 per acre. If we initially elect only to exercise our option on the Southern Tract, we would need to pay $5.0 million on or before June 15, 2017 and drill a commitment well on the Northern Tract by September 1, 2017 to earn an option to acquire the Northern Tract acreage for $11,000 per acre by December 31, 2017. This option purchase is not included in the table above.

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        We also have various long-term gathering, transportation and sales contracts in the Bakken / Three Forks formations in North Dakota that are not included in the table above. As of December 31, 2016 (Successor), we had in place eight long-term crude oil contracts and five long-term natural gas contracts in this area, with sales prices 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 one to ten years from the date of first production. We believe that there are sufficient available reserves and production in the Bakken/Three Forks formations to meet our commitments, as the proved reserves from this area represent approximately 76% of our total proved reserves. Historically, we have been able to meet our delivery commitments.

        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, 2016 (Successor) was $32.4 million.

Successor Senior Revolving Credit Facility

        On the Effective Date, we entered into a senior secured revolving credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP facility, discussed below. The Senior Credit Agreement provides for a $1.5 billion senior secured reserve-based revolving credit facility with a current borrowing base of $600.0 million. The maturity date of the Senior Credit Agreement is the earlier of (i) July 28, 2021 and (ii) the 120th day prior to the February 1, 2020 stated maturity date of our 2020 Second Lien Notes (defined below), if such notes have not been refinanced, redeemed or repaid in full on or prior to such 120th day. The first borrowing base redetermination will be on May 1, 2017 and redeterminations will occur semi-annually thereafter, 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 properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuate based on the utilization of the facility. We may elect, at our option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement). Additionally, if we have outstanding borrowings or letters of credit or reimbursement obligations in respect of letters of credit and the Consolidated Cash Balance (as defined in the Senior Credit Agreement) exceeds $100.0 million as of the close of business on the most recently ended business day, we may also be required to make mandatory prepayments.

        Amounts outstanding under the Senior Credit Agreement are guaranteed by certain of our direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of us and our subsidiaries.

        The Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) not to exceed 4.75:1.00 initially, determined as of each four fiscal quarter periods and commencing with the fiscal quarter ending September 30, 2016, stepping down to 4.50:1.00 and 4.00:1.00 on September 30, 2017 and March 31, 2019, respectively, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00, commencing with the fiscal quarter ending December 31, 2016. At December 31, 2016, we were in compliance with the financial covenants under the Senior Credit Agreement.

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        The Senior Credit Agreement also contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.

        At December 31, 2016, we had approximately $186.0 million of indebtedness outstanding, approximately $6.7 million letters of credit outstanding and approximately $407.3 million of borrowing capacity available under the Senior Credit Agreement.

8.625% Senior Secured Second Lien Notes

        On May 1, 2015 (Predecessor), we issued $700.0 million aggregate principal amount of our 8.625% senior secured second lien notes due 2020 (the 2020 Second Lien Notes) in a private placement. The 2020 Second Lien Notes were issued at par. The net proceeds from the sale of the 2020 Second Lien Notes were approximately $686.2 million (after deducting offering fees and expenses).

        The 2020 Second Lien Notes bear interest at a rate of 8.625% per annum, payable semi-annually on February 1 and August 1 of each year. The 2020 Second Lien Notes will mature on February 1, 2020. The 2020 Second Lien Notes are secured by second-priority liens on substantially all of our and our subsidiaries' assets to the extent such assets secure our Senior Credit Agreement and our 2022 Second Lien Notes (defined below) (the Collateral). Pursuant to the terms of an Intercreditor Agreement, dated May 1, 2015, as amended by those certain Priority Confirmation Joinders, dated September 10, 2015 and December 21, 2015, in connection with the issuance of the Third Lien Notes and the 2022 Second Lien Notes (discussed below), respectively (the Intercreditor Agreement), the security interest in those assets that secure the 2020 Second Lien Notes and the guarantees are contractually subordinated to liens that secure the Senior Credit Agreement and certain other permitted indebtedness. Consequently, the 2020 Second Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement and such other indebtedness to the extent of the value of such assets. The Collateral does not include any of the assets of our future unrestricted subsidiaries. In accordance with the terms of the Plan, the 2020 Second Lien Notes were unimpaired and reinstated upon our emergence from the chapter 11 bankruptcy.

        On September 9, 2016, in connection with fresh-start accounting, we adjusted the 2020 Second Lien Notes to fair value of $679.0 million by recording a discount of $21.0 million to be amortized over the remaining life of the 2020 Second Lien Notes, using the effective interest method.

        In addition, on September 28, 2016 (Successor), us and each of our guarantors and U.S. Bank National Association, as trustee, entered into a supplemental indenture (the 2020 Second Lien Note Supplemental Indenture) to the Indenture dated as of May 1, 2015 with respect to the 2020 Second Lien Notes (the 2020 Second Lien Note Indenture). The 2020 Second Lien Note Supplemental Indenture amended the 2020 Second Lien Note Indenture to modify the incurrence of indebtedness, lien and restricted payments covenants. The 2020 Second Lien Note Supplemental Indenture became operative upon the consummation of the consent solicitation on September 30, 2016 (Successor). We paid an aggregate consent fee of approximately $8.6 million to holders of the 2020 Second Lien Notes and recorded an additional discount of approximately $8.6 million. The remaining unamortized discount was $27.4 million at December 31, 2016.

        On February 16, 2017 (Successor), we paid approximately $303.5 million for approximately $289.2 million principal amount of 2020 Second Lien Notes, a make-whole premium of $13.2 million plus accrued and unpaid interest of approximately $1.1 million to repurchase such notes pursuant to a tender offer and issued a redemption notice to redeem the remaining 2020 Second Lien Notes. The remaining $410.8 million aggregate principal amount of 2020 Second Lien Notes will be repurchased through the guaranteed delivery procedures or redeemed at a price of 104.313% of the principal amount thereof, plus accrued and unpaid interest to, but not including, the redemption date. The redemption date is expected to be March 20, 2017. The repurchase and redemption of the 2020 Second

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Lien Notes will be funded with proceeds from the issuance of $850.0 million in new 6.75% senior unsecured notes due 2025. See "Recent Developments" for further details.

12.0% Senior Secured Second Lien Notes

        On December 21, 2015 (Predecessor), we completed the issuance in a private placement of approximately $112.8 million aggregate principal amount of new 12.0% senior secured second lien notes due 2022 (the 2022 Second Lien Notes) in exchange for approximately $289.6 million principal amount of our then outstanding senior unsecured notes, consisting of $116.6 million principal amount of 9.75% senior notes due 2020, $137.7 million principal amount of 8.875% senior notes due 2021 and $35.3 million principal amount of 9.25% senior notes due 2022. At closing, we paid all accrued and unpaid interest since the respective interest payment dates of the unsecured notes surrendered in the exchange. We recorded the issuance of the 2022 Second Lien Notes at par.

        Interest on the 2022 Second Lien Notes accrues at a rate of 12.0% per annum, payable semi-annually on February 15 and August 15 of each year. The 2022 Second Lien Notes will mature on February 15, 2022. The 2022 Second Lien Notes are secured by second-priority liens on the Collateral. Pursuant to the terms of the Intercreditor Agreement, dated December 21, 2015, the security interest in the Collateral securing the 2022 Second Lien Notes and the guarantees are contractually equal with the liens that secure the 2020 Second Lien Notes and contractually subordinated to liens that secure the Senior Credit Agreement and certain other permitted indebtedness. Consequently, the 2022 Second Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement and such other indebtedness and effectively equal to the 2020 Second Lien Notes, in each case to the extent of the value of the Collateral. In accordance with the terms of the Plan, the 2022 Second Lien Notes were unimpaired and reinstated upon our emergence from chapter 11 bankruptcy.

        On September 9, 2016, in connection with fresh-start accounting, we adjusted the 2022 Second Lien Notes to fair value of $107.2 million by recording a discount of $5.7 million to be amortized over the remaining life of the 2022 Second Lien Notes, using the effective interest method.

        In addition, on September 28, 2016 (Successor), us and each of our guarantors and U.S. Bank National Association, as trustee, entered into a supplemental indenture (the 2022 Second Lien Note Supplemental Indenture) to the Indenture dated as of December 21, 2015 with respect to the 2022 Second Lien Notes (the 2022 Second Lien Note Indenture). The 2022 Second Lien Note Supplemental Indenture amended the 2022 Second Lien Note Indenture to modify the incurrence of indebtedness, lien and restricted payments covenants. The 2022 Second Lien Note Supplemental Indenture became operative upon the consummation of the consent solicitation on September 30, 2016 (Successor). We paid an aggregate consent fee of approximately $1.4 million to holders of the 2022 Second Lien Notes and recorded an additional discount of approximately $1.4 million.

        The remaining unamortized discount was $6.8 million at December 31, 2016.

Off-Balance Sheet Arrangements

        At December 31, 2016 (Successor), 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

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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.

Fresh-start Accounting

        Upon our emergence from chapter 11 bankruptcy, on September 9, 2016, we adopted fresh-start accounting in accordance with the provisions set forth in ASC 852, Reorganizations, as (i) the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date.

        Fresh-start accounting requires an entity to present its assets, liabilities, and equity as if it were a new entity upon emergence from bankruptcy. The new entity is referred to as "Successor" or "Successor Company." However, we will continue to present financial information for any periods before adoption of fresh-start accounting for the Predecessor Company. The Predecessor and Successor companies may lack comparability, as required in ASC Topic 205, Presentation of Financial Statements (ASC 205). ASC 205 states financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed. Therefore, "black-line" financial statements are presented to distinguish between the Predecessor and Successor Companies. Refer to Item 1. Condensed Consolidated Financial Statements (Unaudited) -Note 3, "Fresh-start Accounting," for further details.

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 used 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 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, 2016 (Successor), 2015 and 2014 (Predecessor) 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, 2016 (Successor), a five percent positive revision to proved reserves would decrease the DD&A rate by approximately $0.48 per Boe and a five percent negative revision to proved reserves would increase the DD&A rate by approximately $0.52 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 ceiling calculation and represents the component that requires the most subjective judgments. However,

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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, 2016 (Successor) 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 $238.4 million and would have generated a full cost ceiling impairment.

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. At December 31, 2016 (Successor), a five percent increase in future development and abandonment costs would increase the DD&A rate by approximately $0.23 per Boe and a five percent decrease in future development and abandonment costs would decrease the DD&A rate by $0.24 per Boe.

Accounting for Derivative Instruments and Hedging Activities

        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. From time to time, when derivative contracts are available at terms (or prices) acceptable to us, 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.

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 basis. 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.

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        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, 2016 (Successor) driven primarily by the full cost ceiling impairments over that period which limits the ability to consider other subjective evidence such as the Company's anticipated future growth. Based upon the evaluation of the available evidence we recorded an increase of $60.4 million to our valuation allowance resulting in a valuation allowance of $821.9 million being applied against our deferred tax assets as of December 31, 2016 (Successor).

        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.

        In November 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-17, Balance Sheet Classification of Deferred Taxes (ASU 2015-17) to simplify the presentation of deferred income taxes. Under ASU 2015-17, all deferred tax assets and liabilities, along with any related valuation allowance, are required to be classified as noncurrent on the balance sheet. Effective December 31, 2015, we early adopted ASU 2015-17, on a prospective basis, which resulted in the reclassification of our current deferred tax assets and liabilities as a non-current deferred tax assets and liabilities, net of the valuation allowance, on our consolidated balance sheets. No prior periods were retrospectively adjusted.

Comparison of Results of Operations

Year Ended December 31, 2016 (Successor) Compared to Year Ended December 31, 2015 (Predecessor)

        The table included below sets forth financial information for the periods presented. The period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) are distinct reporting periods as a result of our application of fresh-start accounting upon our emergence from chapter 11 bankruptcy on September 9, 2016 and are not

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comparable to prior periods. Refer to the paragraphs following the table below for a discussion around our results of operations.

(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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        Oil, natural gas and natural gas liquids revenues were $152.6 million, $265.5 million and $548.5 million for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. The decrease in revenues year over year was driven by the sustained decline in the prices of crude oil and natural gas along with a decrease in our average daily production. Oil and natural gas prices are inherently volatile and have decreased significantly since mid-year 2014 and have remained relatively low throughout 2016. We curtailed our drilling and shut in some production in 2016 in response to the decline in commodity prices, which resulted in a decrease in our average daily production. During the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), production averaged 37,637 Boe/d and 36,787 Boe/d, respectively, compared to average daily production of 41,542 Boe/d during 2015 (Predecessor).

        Lease operating expenses on a per Boe basis were $5.26 per Boe, $5.38 per Boe and $6.83 per Boe for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. The decrease in lease operating expense per Boe from 2015 levels is primarily due to price decreases from our vendors in light of the commodity price environment.

        Workover and other expenses on a per Boe basis were $2.47 per Boe, $2.42 per Boe and $1.38 per Boe for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. The increased costs per Boe in 2016 relate primarily to workovers in our Bakken/Three Forks area, specifically costs spent to restore production on wells.

        Taxes other than income on a per Boe basis were $2.91 per Boe, $2.63 per Boe and $3.22 per Boe for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. 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.

        Gathering and other expenses on a per Boe basis were $3.45 per Boe, $3.15 per Boe and $2.66 per Boe for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. Gathering and other expenses include gathering fees paid on our oil and natural gas production as well as rig termination or stacking charges incurred. Throughout 2016 (for the Successor and Predecessor periods combined), we stacked two rigs in response to the sustained decline in commodity prices, whereas in 2015, we stacked only one rig.

        In 2016, we had reductions in our workforce due to the decrease in our drilling and developmental activities planned for the year. For the period of January 1, 2016 through September 9, 2016 (Predecessor), we incurred $5.2 million in severance costs and accelerated stock-based compensation expense related to reductions in our workforce recorded in "Restructuring" on the consolidated statements of operations. For the year ended December 31, 2015 (Predecessor), in conjunction with our divestitures of certain non-core properties, we incurred approximately $2.9 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 was $19.9 million, $78.8 million and $73.2 million, for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. General and administrative expenses increased from 2015 levels due to costs incurred in connection with efforts to restructure our indebtedness.

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        Share-based compensation expense was $21.5 million, $4.9 million and $14.5 million, for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. Share-based compensation expense decreased in the Predecessor periods due to a reduction in our workforce and increased in the Successor period due to equity awards made in conjunction with our emergence from chapter 11 bankruptcy. A portion of these awards vested immediately on the day of the grant.

        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 for the current period to total reserve volumes of evaluated properties as of the beginning of the period. On a per unit basis, depletion expense was $10.63 per Boe, $12.33 per Boe and $23.37 per Boe, for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. The decrease in depletion expense and the depletion rate per Boe from 2015 levels is attributable to decreases in the amortizable base due to our full cost ceiling test impairments.

        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. During 2016, the net book value of our oil and gas properties at March 31, June 30, and September 30, 2016 exceeded the respective ceiling amounts for each period. We recorded a full cost ceiling test impairment before income taxes of $420.9 million for the period of September 10, 2016 through September 30, 2016 (Successor). The impairment at September 30, 2016 primarily reflects the pricing differences between the first-day-of-the-month average price for the preceding twelve months required by Regulation S-X, Rule 4-10 and ASC 932 used in calculating the ceiling test and the forward-looking prices required by ASC 852 to estimate the fair value of the Company's oil and natural gas properties on the fresh-start reporting date, September 9, 2016. We recorded full cost ceiling test impairments before income taxes totaling $754.8 million for the period January 1, 2016 through September 9, 2016 (Predecessor). The ceiling test impairments were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2015. We recorded full cost ceiling test impairments before income taxes totaling $2.6 billion for the year ended December 31, 2015 (Predecessor). The ceiling test impairments in 2015 were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2014. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. See " Overview " for a discussion of potential future ceiling impairments in an environment of sustained lower commodity prices.

        We review our gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360. For the period of January 1, 2016 through September 9, 2016 (Predecessor), we recorded a non-cash impairment charge of $28.1 million. The impairment relates to our gross investments of $32.8 million in gas gathering infrastructure that will not likely be economically recoverable due to our shift in exploration, drilling and developmental plans to our most economic areas as a result of the low commodity price environment.

        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, 2016 (Successor), we had a $5.9 million derivative asset, $5.9 million of which was classified as current, and we had a $16.9 million derivative liability, $16.4 million of which was classified as current. We recorded a net derivative loss of $27.7 million ($112.4 million net unrealized loss and $84.7 million net realized gain on settled contracts) and $18.0 million ($263.7 million net unrealized loss and $245.7 million net realized gain on settled contracts) for the period of September 10, 2016 through December 31, 2016 (Successor) and for the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively, compared to a net derivative gain of $310.3 million ($129.2 million net unrealized loss offset by a $439.5 million net realized gain on settled contracts) for the year ended December 31, 2015 (Predecessor).

        Interest expense and other was $28.9 million, $122.2 million and $232.9 million for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. Capitalized interest for the period of January 1, 2016 through September 9, 2016 (Successor) and the year ended December 31, 2015 (Predecessor) was $68.2 million and $113.0 million, respectively. The Successor Company's accounting policy on the capitalization of interest establishes thresholds for the determination of a development project for the purpose of interest capitalization. Gross interest expense was $28.6 million, $195.7 million and $337.6 million for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. The decrease in gross interest expense from 2015 levels was primarily due to the discontinuance of interest expense on our senior notes that were cancelled as part of our chapter 11 bankruptcy proceedings.

        Reorganization items represent (i) expenses or income incurred subsequent to July 27, 2016 (when we filed voluntary petitions for relief under chapter 11) as a direct result of the reorganization Plan, (ii) gains or losses from liabilities settled, and (iii) fresh-start accounting adjustments and are recorded in "Reorganization items" in the consolidated statements of operations. The following table summarizes the net reorganization items (in thousands):

        During the three months ended March 31, 2016 (Predecessor), we repurchased approximately $91.8 million principal amount of our senior unsecured notes, consisting of $24.5 million principal amount of our 9.75% senior notes due 2020, $51.8 million principal amount of our 8.875% senior notes due 2021, and $15.5 million principal amount of our 9.25% senior notes due 2022 for cash at prevailing market prices at the time of the transactions. The net cash used to make these repurchases was approximately $9.7 million. Upon settlement of the repurchases, we paid all accrued and unpaid interest since the respective interest payment dates of the notes repurchased and we recorded a net gain on the extinguishment of debt of approximately $81.4 million, which included the write-down of $0.7 million associated with related issuance costs and discounts and premiums for the respective notes. During the year ended December 31, 2015 (Predecessor), we entered into several transactions intended

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to reduce our long-term debt. The table below denotes the transaction description, the reduction of the principal amount of long-term debt, the write-down of associated issuance costs and discounts and premiums, and the net gain on extinguishment of debt that was recorded for each transaction:

        During the year ended December 31, 2015 (Predecessor), we entered into an amendment to our Convertible Note and to the February 2012 Warrants, in which we recorded a net gain on the extinguishment of the Convertible Note of $5.9 million and a net loss on the modification of the February 2012 Warrants of $14.1 million.

        We recorded an income tax provision of $4.7 million for the period of September 10, 2016 through December 31, 2016 (Successor) and an income tax benefit of $8.7 million for the period January 1, 2016 through September 9, 2016 (Predecessor) relating to our estimated 2016 alternative minimum tax liability and the reversal of the Predecessor estimated 2015 alternative minimum tax liability, respectively. We recorded an income tax provision of $9.1 million on a loss before income taxes of $1.9 billion for the year ended December 31, 2015 (Predecessor), related to projected alternative minimum tax.

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Year Ended December 31, 2015 (Predecessor) Compared to Year Ended December 31, 2014 (Predecessor)

        We reported a net loss of $1.9 billion for the year ended December 31, 2015 (Predecessor) compared to net income of $316.0 million for the comparable period in 2014 (Predecessor). The following table summarizes key items of comparison and their related change for the periods indicated. Refer to the paragraphs following the table below for a discussion around our results of operations.

(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, 2015 (Predecessor), oil, natural gas and natural gas liquids revenues decreased $597.4 million from the same period in 2014 due to lower average realized prices and a slight decrease in our production volumes. Average realized prices (excluding effects of hedging arrangements) decreased from $74.56 per Boe to $36.17 per Boe, representing a 51% decrease from the prior year period. Oil and natural gas prices are inherently volatile and decreased significantly since mid-year 2014. Production slightly decreased year over year, as we curtailed our drilling in response to the decline in commodity prices. However, production volumes associated with our core properties in the Bakken/Three Forks and El Halcón areas have remained flat or increased slightly year over year, as we have focused our drilling efforts on our most economic areas due to the current price environment. Sustained lower commodity prices will continue to impact our oil, natural gas and natural gas liquids revenues.

        Lease operating expenses decreased $26.6 million for the year ended December 31, 2015 (Predecessor). On a per unit basis, lease operating expenses were $6.83 per Boe in 2015 compared to $8.47 per Boe in 2014. The decrease per Boe is primarily due to lower relative operating expenses on our core properties due, in part, to operational improvements and efficiencies as well as cost decreases from our vendors in light of the commodity price environment.

        Workover and other expenses increased $4.7 million for the year ended December 31, 2015 (Predecessor) as compared to the same period in 2014 primarily due to $8.6 million of expenses associated with increased activity in our core areas as we continued to develop these areas.

        Taxes other than income decreased $57.4 million for the year ended December 31, 2015 (Predecessor) as compared to the same period in 2014 primarily due to lower oil, natural gas and natural gas liquids revenues attributable to significantly lower commodity prices. 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. On a per unit basis, taxes other than income were $3.22 per Boe and $6.92 per Boe, for the years ended 2015 and 2014 (Predecessor), respectively. The decrease on a per Boe basis in 2015 is driven by a decrease in our realized average prices.

        Gathering and other expenses for the year ended December 31, 2015 and 2014 (Predecessor) were $40.3 million and $26.7 million, respectively. Approximately, $29.2 million of expenses incurred in 2015 relate to gathering and other fees paid on our oil and natural gas production. Also included is a $6.0 million termination fee paid to early terminate one of our drilling rig contacts and $3.8 million of rig stacking fees. The decision to early terminate one drilling rig contract and stack another drilling rig was in response to the decline in crude oil prices.

        For the year ended December 31, 2015 (Predecessor), we had reductions in our workforce due to the decrease in our drilling and developmental activities planned for the year. We incurred approximately $2.9 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees during the year. For the year ended December 31, 2014 (Predecessor), in conjunction with our divestitures of certain non-core properties, we incurred approximately $1.0 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, 2015 (Predecessor) decreased $24.6 million to $73.2 million as compared to the same period in 2014. The decrease was primarily due to decreases in professional fees, payroll and employee related benefit costs, and transaction expenses amounting to $9.9 million, $9.3 million and $1.8 million, respectively. On a per unit basis, general and administrative expenses were $4.83 per Boe and $6.36 per Boe, for the years ended December 31, 2015 and 2014 (Predecessor), respectively.

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        Share-based compensation expense for the year ended December 31, 2015 (Predecessor) was $14.5 million, a decrease of $4.2 million compared to the same period in 2014. The decrease in share-based compensation expense results from forfeitures and lower fair market value for new awards granted to employees and directors during 2015.

        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 volumes for evaluated properties as of the beginning of the period. Depletion expense decreased $169.5 million to $354.3 million for the year ended December 31, 2015 (Predecessor) compared to the same period in 2014, primarily attributable to decreases in the amortizable base due to the full cost ceiling impairments since the prior year period. On a per unit basis, depletion expense was $23.37 per Boe for the year ended December 31, 2015 (Predecessor) compared to $34.09 per Boe for the year ended December 31, 2014 (Predecessor).

        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," established by 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 $2.6 billion for the year ended December 31, 2015 (Predecessor), compared to a full cost ceiling test impairment before income taxes of $239.7 million for the year ended December 31, 2014 (Predecessor). The ceiling test impairments in 2015 were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations from $94.99 per Bbl at December 31, 2014 (Predecessor) to $50.28 per Bbl at December 31, 2015 (Predecessor). Changes in commodity prices, production rates, reserve volumes, future development costs, transfers of unevaluated properties, capital spending, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. See "Overview" for a discussion and quantification of potential future ceiling impairments in an environment of sustained lower commodity prices.

        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 (Predecessor), 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, at the time of evaluation for impairment in December 2014 (Predecessor), we did not plan to develop in light of the recent downtrend in oil prices, which rendered certain areas to be deemed uneconomical and/or non-strategic.

        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, 2015 (Predecessor), we had a $365.5 million derivative asset, $348.9 million of which was classified as current, and we had a $0.3 million derivative liability, none of which was classified as current. We recorded a net derivative gain of $310.3 million ($129.2 million net unrealized loss offset by a $439.5 million net realized gain on settled contracts) for the year ended December 31, 2015 (Predecessor) compared to a net derivative gain of $518.9 million ($506.5 million net unrealized gain and $12.4 million net realized gain on settled contracts) in the prior year.

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        Interest expense and other increased $87.2 million for the year ended December 31, 2015 (Predecessor) from the same period in 2014. Capitalized interest for the years ended December 31, 2015 and 2014 (Predecessor) was $113.0 million and $168.9 million, respectively. The decrease in capitalized interest was driven by decreases in our unevaluated properties since 2014, which is the basis of our capitalized interest calculation. Interest expense subject to capitalization increased $19.9 million, over the prior year period, from $317.7 million in 2014 to $337.6 million in 2015. The increase in interest subject to capitalization is primarily due to the issuance of our 2020 Second Lien Notes since the prior year period.

        During the year ended December 31, 2015 (Predecessor), we entered into several transactions intended to reduce our long-term debt. The table below denotes the transaction description, the reduction of the principal amount of long-term debt, the write-down of associated issuance costs and discounts and premiums, and the net gain on extinguishment of debt that was recorded for each transaction:

        During the year ended December 31, 2015 (Predecessor), we entered into an amendment to our Convertible Note and to the February 2012 Warrants, in which we recorded a net gain on the extinguishment of the Convertible Note of $5.9 million and a net loss on the modification of the February 2012 Warrants of $14.1 million.

        We recorded an income tax provision of $9.1 million on a loss before income taxes of $1.9 billion for the year ended December 31, 2015 (Predecessor). The provision represents projected alternative minimum tax. For the year ended December 31, 2014 (Predecessor), we recorded an income tax benefit of $1.1 million on income before income taxes of $314.9 million. The benefit reflects the impact of the change in the valuation allowance for the year of $102.0 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

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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, when derivative contracts are available at terms (or prices) acceptable to us. 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 only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. We did not post collateral under any of these contracts as they are secured under our Senior Credit Agreement or are uncollateralized trades. Please refer to Item 8. Consolidated Financial Statements and Supplementary Data -Note 9, "Derivative and Hedging Activities," for additional information.

        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 9, "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 8, " 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, 2016 (Successor), the principal amount of our total long-term debt was $998.8 million, of which approximately 81.4% bears interest at a weighted average fixed interest rate of 9.09% per year. The remaining 18.6% of our total long-term debt at December 31, 2016 (Successor) 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, 2016 (Successor), the weighted average interest rate on our variable rate debt was 3.74% per year. If the balance of our variable rate debt at December 31, 2016 (Successor) were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.7 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, 2016.

        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, 2016 which is included herein.

Houston, Texas
February 28, 2017

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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, 2016, 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, 2016, 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, 2016 (Successor Company balance sheet) and 2015 (Predecessor Company balance sheet), and the related consolidated statements of operations, stockholders' equity (deficit), and cash flows for the

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period of September 10, 2016 to December 31, 2016 (Successor Company operations), the period of January 1, 2016 to September 9, 2016, and for each of the two years in the period ended December 31, 2015 (Predecessor Company operations) and our report dated February 28, 2017 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE  LLP

Houston, Texas
February 28, 2017

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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 balance sheet of Halcón Resources Corporation and subsidiaries (the "Company") as of December 31, 2016 (Successor Company balance sheet) and 2015 (Predecessor Company balance sheet), and the related consolidated statements of operations, stockholders' equity, and cash flows for the period of September 10, 2016 to December 31, 2016 (Successor Company operations), the period of January 1, 2016 to September 9, 2016, and for each of the two years in the period ended December 31, 2015 (Predecessor Company operations). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

        As discussed in Note 2 to the financial statements, on September 8, 2016, the Bankruptcy Court entered an order confirming the plan of reorganization which became effective on September 9, 2016.

        Accordingly, the accompanying financial statements have been prepared in conformity with AICPA Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code , for the Successor Company as a new entity with assets, liabilities, and a capital structure having carrying values not comparable with prior periods as described in Note [2] to the financial statements.

        In our opinion, the Successor Company financial statements present fairly, in all material respects, the financial position of Halcón Resources Corporation and subsidiaries as of December 31, 2016, and the results of its operations and its cash flows for the period of September 10, 2016 to December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Further, in our opinion, the Predecessor Company financial statements referred to above present fairly, in all material respects, the financial position of the Predecessor Company as of December 31, 2015, and the results of its operations and its cash flows for the period of January 1, 2016 to September 9, 2016, and for each of the two years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

        We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2016, 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 28, 2017 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 28, 2017

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