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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the Predecessor Credit Agreement was refinanced and replaced with the DIP Facility, which was subsequently converted into the Senior Credit Agreement;



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the Second Lien Notes (consisting of $700.0 million in aggregate principal amount outstanding of 8.625% senior secured notes due 2020 and $112.8 million in aggregate principal amount outstanding of 12% senior secured notes due 2022) were unimpaired and reinstated;



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the Third Lien Notes were cancelled and the Third Lien Noteholders received their pro rata share of 76.5% of the common stock of reorganized Halcón, together with a cash payment of $33.8 million, and accrued and unpaid interest on their notes through May 15, 2016, which was paid prior to the chapter 11 bankruptcy filing, in full and final satisfaction of their claims;

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the Unsecured Notes were cancelled and the Unsecured Noteholders received their pro rata share of 15.5% of the common stock of reorganized Halcón, together with a cash payment of $37.6 million and warrants to purchase 4% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), and accrued and unpaid interest on their notes through May 15, 2016, which was paid prior to the chapter 11 bankruptcy filing, in full and final satisfaction of their claims;



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the Convertible Note was cancelled and the Convertible Noteholder received 4% of the common stock of reorganized Halcón, together with a cash payment of $15.0 million and warrants to 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;



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the general unsecured claims were unimpaired and paid in full in the ordinary course;



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all outstanding shares of the preferred stock were cancelled and the Preferred Holders received their pro rata share of $11.1 million in cash, in full and final satisfaction of their interests; and



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all of the outstanding shares of common stock were cancelled and the common stockholders received their pro rata share of 4% of the common stock of reorganized Halcón, in full and final satisfaction of their interests.

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



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

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Maintain Strong Balance Sheet and Financial Flexibility.   We believe our cash, internally generated cash flows, borrowing capacity, non-core asset sales and access to capital markets will provide us with sufficient liquidity to execute our current capital program and strategy. We have no near term debt maturities. Our management team is focused on maintaining a strong balance sheet. We also employ a hedging program to reduce the variability of our cash flows used to support our capital spending.

Our Competitive Strengths

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

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Proven Management Team.   Our management team and technical professionals, including geologists and engineers, have decades of combined experience in the industry and a track record for creating shareholder value.



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Premier Asset Base.   Our proved reserves, production and acreage are located in concentrated positions in two premier onshore U.S. basins. These basins provide exposure to a variety of reservoir formations, each of which has its own characteristics that impact the costs to drill, complete and operate as well as the composition (and therefore value) of the hydrocarbon stream. We believe that this geographic diversity provides us with broad flexibility to direct our capital resources to projects with the greatest potential returns and access to multiple key end markets, which mitigates our exposure to temporary price dislocations in any one market.



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Extensive Experience in Resource Plays.   Our team has significant experience in all aspects of the development of resource plays. We have been successful in consistently improving drilling times and reserve recoveries through innovation, the use of new technologies and a focus on controlling costs. In addition to our core strength in exploration and production, our personnel have experience in building midstream infrastructure and have managed oilfield service activities.



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

Oil and Natural Gas Reserves

        The proved reserves estimates shown herein for the years ended December 31, 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).

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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:

        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: