Amplify Energy Corp. - Annual Report: 2016 (Form 10-K)

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MIDSTATES PETROLEUM COMPANY, INC. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

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

Form 10-K

Commission File Number: 001-35512

MIDSTATES PETROLEUM COMPANY, INC.
(Exact name of registrant as specified in its charter)

          Registrant's telephone number, including area code: (918) 974-8550

          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 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 or any amendment to the 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 definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. Check one:

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

          The aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant was approximately $1.2 million based upon the closing price of such stock on June 30, 2016, the last business day of the registrant's most recently completed second fiscal quarter, of $0.15 per share.

          The number of shares outstanding of our stock at March 27, 2017 is shown below:

DOCUMENTS INCORPORATED BY REFERENCE

None.

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MIDSTATES PETROLEUM COMPANY, INC.
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

        This Annual Report on Form 10-K contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements other than statements of historical fact included in this annual report are forward-looking statements, including, without limitation, statements regarding our strategy, future operations, financial position, estimated revenues and income/loss, projected costs, prospects, plans and objectives of management. When used in this annual report, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "may," "continue," "predict," "potential," "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

        Forward-looking statements may include statements about our:

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business strategy, including our business strategy post-emergence from our Chapter 11 cases (the "Chapter 11 Cases");



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estimated future net reserves and present value thereof;



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technology;



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financial condition, revenues, cash flows and expenses;



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levels of indebtedness, liquidity, borrowing capacity and compliance with debt covenants;



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financial strategy, budget, projections and operating results;



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oil and natural gas realized prices;



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timing and amount of future production of oil and natural gas;



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availability of drilling and production equipment;



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the amount, nature and timing of capital expenditures, including future development costs;



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availability of oilfield labor;



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availability of third party natural gas gathering and processing capacity;



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availability and terms of capital;



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drilling of wells, including our identified drilling locations;



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successful results from our identified drilling locations;



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marketing of oil and natural gas;



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the integration and benefits of asset and property acquisitions or the effects of asset and property acquisitions or dispositions on our cash position and levels of indebtedness;



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infrastructure for salt water disposal and electricity;



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current and future ability to dispose of salt water;



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sources of electricity utilized in operations and the related infrastructures;



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costs of developing our properties and conducting other operations;



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general economic conditions;



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effectiveness of our risk management activities;



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environmental liabilities;



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counterparty credit risk;

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the outcome of pending and future litigation;



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governmental regulation and taxation of the oil and natural gas industry;



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developments in oil and natural gas producing countries;



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new capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors used in estimating enterprise value vary significantly from the current estimates in connection with the application of fresh start accounting;



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uncertainty regarding our future operating results; and



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plans, objectives, expectations and intentions contained in this annual report that are not historical.

        All forward-looking statements speak only as of the date of this annual report. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this annual report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk Factors" and elsewhere in this annual report.

        These factors include:

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variations in the market demand for, and prices of, oil, natural gas liquids and natural gas;



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uncertainties about our estimated quantities of oil and natural gas reserves;



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the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our reserves based revolving credit facility (the "Exit Facility");



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access to capital and general economic and business conditions;



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uncertainties about our ability to replace reserves and economically develop our current reserves;



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risks in connection with acquisitions;



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risks related to the concentration of our operations onshore in Oklahoma and Texas;



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drilling results;



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the potential adoption of new governmental regulations, including future regulations regarding the disposal of salt water; and



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our ability to satisfy future cash obligations and environmental costs.

        These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

        Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserves estimate depends on the quality of available data (including geoscience and engineering data), the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any future production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

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GLOSSARY OF OIL AND NATURAL GAS TERMS

        Bbl:    One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to oil, condensate or natural gas liquids.

        Boe:    Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

        Boe/day:    Barrels of oil equivalent per day.

        Completion:    The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

        Dry hole:    A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production do not exceed production expenses and taxes.

        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 natural gas or oil in another reservoir.

        MMBoe:    One million barrels of oil equivalent.

        MMBtu:    One million British thermal units.

        Net acres:    The percentage of total acres an owner has out of a particular number of acres, or a specified tract.

        NYMEX:    The New York Mercantile Exchange.

        Proved reserves:    Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to drill or operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to the

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ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

        Reasonable certainty:    A high degree of confidence.

        Recompletion:    The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish, re-establishing, or increase existing production.

        Reserves:    Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development projects to known accumulations.

        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 or Spudding:    The commencement of drilling operations of a new well.

        Wellbore:    The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

        Working interest:    The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on a cash, penalty, or carried basis.

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PART I

ITEM 1.    BUSINESS

General

        Midstates Petroleum Company, Inc. is an independent exploration and production company focused on the application of modern drilling and completion techniques in oil and liquids-rich basins in the onshore United States. Our operations are concentrated in Oklahoma and Texas, with our corporate headquarters located in Tulsa, Oklahoma. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC ("Midstates Sub" or "Debtor Affiliate"). In this Annual Report, references to "Company," "we," "us," "our," and "Midstates" when used in the present tense, prospectively or for historical periods, refer to Midstates Petroleum Company, Inc. and its wholly owned subsidiary.

        Our common stock was listed on the New York Stock Exchange (the "NYSE") on April 25, 2012 through February 3, 2016 under the symbol "MPO". On February 3, 2016, our stock was delisted by the NYSE and began trading on the OTC Pink market under the symbol "MPOY". On April 30, 2016, we filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code. On October 21, 2016, in connection with our emergence from Chapter 11, our existing common shares traded under the symbol MPOY were cancelled and on October 24, 2016, our new common shares issued in connection with our successful reorganization and emergence from Chapter 11 were listed and began trading on the NYSE MKT under the symbol "MPO". We currently lease office space in Tulsa, Oklahoma at 321 South Boston Avenue, Suite 1000, where our principal offices are located. The lease for our Tulsa office expires in 2026. We also lease one field office in Dacoma, Oklahoma and one in Perryton, Texas. As of December 31, 2016, we had 124 employees.

        We are required to file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission ("SEC"). You may read and copy any documents filed by us 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. Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC's website at http://www.sec.gov. Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

        We also make available on our website (http://www.midstatespetroleum.com) all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Financial Code of Ethics, and the charters of our audit committee, compensation committee and nominating and governance committee are also available on our website and in print free of charge to any stockholder who requests them. Requests should be sent by mail to 321 South Boston Avenue, Suite 1000; Tulsa, Oklahoma 74103, attention Vice President—General Counsel. Information contained on our website is not incorporated by reference into this Annual Report on Form 10-K. We intend to disclose on our website any amendments or waivers to our Code of Ethics that are required to be disclosed pursuant to Item 5.05 of Form 8-K.

Chapter 11 Plan of Reorganization

        On April 30, 2016 (the "Petition Date"), we filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the "Bankruptcy Code") in the United States Bankruptcy Court for the Southern District of Texas (the "Bankruptcy Court"). Our Chapter 11 cases (the "Chapter 11 Cases") were jointly administered under the case styled In re Midstates Petroleum

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Company, Inc., et al., Case No. 16-32237. On September 28, 2016, the Bankruptcy Court entered the Findings of Fact, Conclusions of Law, and Order Confirming Debtors' First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate (the "Confirmation Order"), which approved and confirmed the First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate as filed on the same date (the "Plan"). On October 21, 2016 (the "Effective Date"), we satisfied the conditions to effectiveness set forth in the Confirmation Order and in the Plan, the Plan became effective in accordance with its terms and we emerged from the Chapter 11 Cases. Pursuant to the confirmed Plan, the significant transactions that occurred upon the Effective Date were as follows:

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Substantial Deleveraging of the Balance Sheet: The permanent pay-down of $81.3 million of our revolving credit facility ("RBL"), with a $170.0 million Exit Facility established upon the Effective Date, (ii) the pay-down of $60.0 million of our Second Lien Notes in cash, and (iii) the conversion into equity of all of our remaining debt junior to the RBL;



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Credit Facility Claims: Holders of allowed claims arising under the RBL (the "Credit Facility Claims") received their pro rata share of approximately $81.3 million in cash and the RBL was superseded, pursuant to the Plan, by the Exit Facility, as further described below;



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Second Lien Notes Claims: Holders of allowed claims arising under the Second Lien Notes (the "Second Lien Notes Claims") received their pro rata share of (i) 96.25% of the reorganized equity in the form of common stock and (ii) a cash payment of $60.0 million;



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Third Lien Notes Claims: Holders of allowed claims arising under the Third Lien Notes (the "Third Lien Notes Claims"), pursuant to a settlement with holders of Second Lien Notes Claims on terms more fully set forth in the Plan (the "Second/Third Lien Plan Settlement"), received their pro rata share of 2.5% of the reorganized equity in the form of common stock and warrants to acquire 4,411,765 shares of common stock at a strike price of $24.00 per common share with an expiration date 42 months after the Effective Date;



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Unsecured Claims: Holders (the "Unsecured Noteholders") of allowed claims arising under the Debtors' 10.75% Senior Unsecured Notes due 2020 (the "2020 Notes Claims"), the holders of allowed claims arising under the 9.25% Senior Unsecured Notes due 2021 (the "2021 Notes Claims" and together with the 2020 Notes Claims, the "Unsecured Notes Claims"), and the Holders of other general unsecured claims received their pro rata share of 1.25% of reorganized equity in the form of common stock and warrants to acquire 2,213,789 shares of common stock (the "Unencumbered Assets Equity Distribution") at a strike price of $46.00 per common share with an expiration date 42 months after the Effective Date;



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Existing Equity: All existing equity interests prior to the Effective Date were extinguished, and existing equity holders did not receive any consideration in respect of their equity interests;



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New Equity: On the Effective Date, we issued 24,687,500 shares of common stock of the reorganized equity. On November 9, 2016, we issued an additional 294,967 shares of common stock of the reorganized equity pursuant to the Plan. We will issue 17,533 additional common shares, with respect to general unsecured claims, pursuant to the Plan in a future distribution. The total authorized reorganized capital stock consists of 250,000,000 shares of common stock and 50,000,000 shares of preferred stock;



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Exit Facility: Our RBL, which was redetermined with a borrowing base of $170.0 million in April 2016, was superseded, pursuant to the Plan, by the Exit Facility. The Exit Facility has an initial borrowing base of $170.0 million with no borrowing base redeterminations to occur until April 2018 (provided certain conditions are met) and semiannual borrowing base redeterminations each year on April 1 and October 1 thereafter. Until April 2018, unless the borrowing base is redetermined earlier, the amount available to be drawn under the Exit Facility is reduced by

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$40.0 million, and thereafter, we must maintain liquidity (as defined in the Exit Facility) equal to at least 20.0% of the effective borrowing base. In connection therewith, on the Effective Date, we made an additional payment of $40.0 million to lenders under our Exit Facility; and

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Long-Term Incentive Plan: A management equity incentive plan (the "2016 LTIP") was established under which 10.0% of the reorganized equity (on a fully-diluted/fully-distributed basis) was reserved for grants to be made from time to time to the directors, officers, and other members of our management.

        As a result of our restructuring, we estimate cash paid for interest will decrease from approximately $173.7 million per year to approximately $7.0 million per year, a cash interest savings of approximately $166.7 million per year.

        The following table provides adjustments that reflect the consummation of transactions contemplated by the Plan, as of the Effective Date (excluding the Exit Facility):

        Upon our emergence on the Effective Date, we adopted fresh start accounting as required by United States generally accepted accounting principles ("US GAAP"). We qualified for fresh start accounting because (i) the holders of existing voting shares of the pre-emergence debtor-in-possession received less than 50% of the voting shares of the post-emergence successor entity and (ii) the reorganization value of our assets immediately prior to confirmation was less than the post-petition liabilities and allowed claims. We applied fresh start accounting as of October 21, 2016. Adopting fresh start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit. The cancellation of all existing shares outstanding on the Effective Date and issuance of new shares in the reorganized Company caused a related change of control under US GAAP. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, our consolidated financial statements on or after October 21, 2016, are not comparable with our consolidated financial statements prior to that date. References to "Successor Period" relate to the financial position and results of operations for the period October 21, 2016 through December 31, 2016 and references to "Predecessor Period" refer to the financial position and results of operations of the Company from January 1, 2016 through October 20, 2016.

Business Strategy

        Our goal is to grow our reserves, production and cash flows to generate an attractive rate of return on invested capital. To achieve these objectives, we strive to:

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Operate in a safe and environmentally responsible manner;

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Capitalize on our extensive technical and operating experience in our core areas of operation to strategically grow our production, increase our acreage position and enhance returns;



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Build contiguous acreage positions that drive operating and infrastructure efficiencies;



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Be the operator of our assets, whenever possible; and



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Be the low cost driller and producer in the areas where we operate.

        As a result of our recent restructuring, our significantly deleveraged balance sheet and improved liquidity position provides us with additional resources to develop our multi-year drilling inventory and expand our core acreage positions. Our focus will continue to be on controlling development and production costs and general and administrative expenses. For 2017, we intend to opportunistically increase our development activity while maintaining capital discipline and protecting our operating cash flows, including through the use of derivatives to protect our commodity price realizations.

        With respect to the Mississippian Lime, we believe our team's early experience operating in this trend gives us a competitive advantage with respect to geological understanding, drilling and completion techniques and infrastructure development. We plan to leverage our advantages to cost effectively develop our Mississippian position and further expand our acreage through direct leasing, farm in arrangements and acreage swaps. During 2016, we earned approximately 24,248 net (45,440 gross) prospective acres through various farm-in agreements and plan to continue to utilize such agreements in the future. With respect to the Anadarko Basin, we believe our substantial acreage position largely held by production, the stacked pay characteristics of the trend and its long production history provide significant optionality with continued improvement in commodity prices and geologic understanding.

        For 2017, we plan to allocate substantially all of our drilling and completions capital budget to development activities in the Mississippian Lime area based on the stronger economic returns expected from these assets in the current commodity price environment.

Summary of Oil and Gas Properties and Operations

Mississippian Lime

        Our Mississippian Lime assets are located in Oklahoma and target the Mississippian Lime and Hunton formations. At December 31, 2016, our acreage consisted of approximately 103,093 net (142,773 gross) prospective acres in the Mississippian Lime trend in Woods and Alfalfa Counties of Oklahoma, which we currently intend to develop using horizontal wells, and approximately 12,894 net (19,888 gross) acres in Lincoln County, Oklahoma, which produces from, and is prospective in, the Hunton formation.

        Our properties in this area represented 96% of our total proved reserves as of December 31, 2016. As of December 31, 2016, we held an average working interest and average net revenue interest of 82% and 66%, respectively, in this area.

        For the Successor Period and Predecessor Period, our average daily production from our Mississippian Lime assets was as follows:

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        At December 31, 2016, we had one operated drilling rig in operation in the Mississippian Lime. For 2017, subject to the terms of our Exit Facility, we anticipate investing between $90.0 million and $100.0 million in the area while drilling between 24 and 26 gross operated wells.

Anadarko Basin

        Our Anadarko Basin assets are located in Western Oklahoma and the Texas panhandle and target, or are prospective in, the Cleveland, Marmaton, Cottage Grove, Osage, Meramac and Tonkawa formations. At December 31, 2016, our acreage consisted of approximately 80,298 net (96,753 gross) acres in Texas and 24,627 net (43,671 gross) acres in western Oklahoma.

        Our properties in this area represented 4% of our total proved reserves as of December 31, 2016. As of December 31, 2016, we held an average working interest and average net revenue interest of 64% and 51%, respectively, in this area.

        For the Successor Period and Predecessor Period, our average daily production from the Anadarko Basin area was as follows:

        As of December 31, 2016, we did not operate any drilling rigs in this area and we do not expect to operate any drilling rigs in 2017. As a result, leasehold rights on acreage not held by production may expire during 2017, which could reduce our future drilling opportunities in this area. During 2016, we entered into a farm out agreement covering our acreage in Dewey County, Oklahoma which may be prospective for the NW Stack extension. To the extent commercially feasible, we will continue to pursue farm out arrangements with other operators to cost effectively preserve a portion of our leasehold rights with optionality to participate in any future development. During 2017, we will continue our efforts to reduce well maintenance and operating costs and production downtime. These efforts alone have not been and will not be sufficient to arrest the natural decline in production that occurs as we deplete our developed reserves.

Other

        On April 21, 2015, we closed on the sale of certain of our oil and gas properties in Beauregard and Calcasieu Parishes, Louisiana (the "Dequincy Divestiture"), for approximately $44.0 million, before customary post-closing adjustments. We have no proved reserves in the Gulf Coast (or Louisiana) as of December 31, 2016 or 2015.

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Reserves Information

Estimated Proved Reserves

        The following table sets forth our estimated net proved reserves by product and type as of December 31, 2016 using SEC pricing:

The following table provides a reconciliation of PV-10 to the standardized measure of discounted cash flows (in thousands):

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Proved Undeveloped Reserves

        The following table summarizes the changes in our estimated proved undeveloped reserves during the Successor Period and Predecessor Period (in MBoe):

        Due to uncertainty during the Predecessor Period regarding our ability to finance the development of our proved undeveloped reserves over a five year period, our proved undeveloped reserves were limited to only those locations that were undergoing drilling activity. Upon our emergence on the Effective Date, we undertook a process to review our five year development schedule in light of improved commodity pricing and the significant improvement in the Company's liquidity and outstanding long-term debt. In developing the Company's updated five year development schedule, the Company considered the forward pricing curve, the returns expected of our drilling program and cash available during this time period, which would include cash on hand, cash generated by operations and cash from borrowings. Based upon these factors, the Company developed an updated five year development plan and booked proved undeveloped reserves based upon this expected development plan. Proved undeveloped reserves that were removed from the proved category in prior years but subsequently reinstated after this review were classified as a revision in the above table. Proved undeveloped reserves that were not included in any proved category in prior years but included in our updated five-year development schedule were classified as an extension in the above tables. At December 31, 2016, 21,103 net MBoe of proved undeveloped reserves, comprising $34.1 million of PV-10 value were excluded from our five year development plan.

Independent Petroleum Engineers

        For our Mississippian Lime and Anadarko Basin assets, our estimated reserves and related future net revenues at December 31, 2016, 2015 and 2014 are based on reports prepared by our independent third-party reserves engineering firm Cawley, Gillespie & Associates, Inc. ("CGA"), in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines in effect during such period as established by the SEC.

        The reserve estimates shown herein for the periods indicated above have been independently evaluated by CGA, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. CGA was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the reserves report incorporated herein was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 29 years of practical experience in petroleum engineering, with over

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27 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds 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; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

        Our estimated reserves and related future net revenues for our Gulf Coast (or Louisiana) assets at December 31, 2014 were based on reports prepared by an independent third-party reserves engineering firm, Netherland, Sewell & Associates, Inc. ("NSAI"), in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines in effect during such period established by the SEC.

        The reserve estimates shown herein for the periods indicated above were independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Robert C. Barg and Mr. Philip R. Hodgson. Mr. Barg, a Licensed Professional Engineer in the State of Texas (No. 71658), has been practicing consulting petroleum engineering at NSAI since 1989 and has over 6 years of prior industry experience. He graduated from Purdue University in 1983 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Hodgson, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 1314), has been practicing consulting petroleum geoscience at NSAI since 1998 and has over 14 years of prior industry experience. He graduated from University of Illinois in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. 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.

Technology Used to Establish Proved Reserves

        Under Rule 4-10(a)(22) of Regulation S-X, as promulgated by the SEC, proved reserves are 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. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

        In order to establish reasonable certainty with respect to our estimated proved reserves, CGA and NSAI employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data.

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Internal Controls Over Reserves Estimation Process

        We maintain an internal staff of petroleum engineers, land and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to CGA and NSAI in their reserves estimation process. The primary inputs to the reserves estimation process are comprised of technical information, financial data, ownership interests and production data. All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land personnel to discuss field performance and to validate future development plans. Current revenue and expense information is obtained from our accounting records, which are subject to their own set of internal controls over financial reporting. All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserves database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Our current ownership in mineral interests and well production data are incorporated into the reserves database as well and verified to ensure their accuracy and completeness. Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserve estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, the reserves report is reviewed by our senior management with representatives of our independent reserve engineers and internal technical staff.

        At December 31, 2016, Jeromy Garcia, our General Manager—Mississippian Lime and Anadarko Basin Assets and Reserves, was primarily responsible for overseeing the preparation of our reserve estimates and reported directly to our Chief Executive Officer. Mr. Garcia has more than 16 years of experience in the oil and gas industry. Mr. Garcia spent the first portion of his career working for El Paso Production Company—primarily working assets in the Gulf of Mexico. While at El Paso, Mr. Garcia served in multiple roles including reservoir and operational engineering. Mr. Garcia has also worked for small independents such as Whittier Energy and J&S Oil & Gas where he served as a reservoir engineer and Manager of Engineering. Mr. Garcia graduated from the University of Oklahoma in 2000 with a B.S degree in Petroleum Engineering and obtained his MBA from the University of Houston in 2009.

Production, Revenues and Price History

        Oil, natural gas liquids ("NGLs") and natural gas are commodities. The price that we receive for the oil, NGLs and natural gas we produce is largely a function of market supply and demand. The price of oil substantially declined in the fourth quarter of 2014 and remained depressed throughout 2015 due to a variety of macro-economic factors. While oil, natural gas and NGL prices increased throughout 2016, they remain substantially below the price levels realized during the majority of 2014. A decline in oil or natural gas prices from their current levels could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets. For additional information on these and other risks, see information set forth in "Risk Factors".

        The following table sets forth information regarding our oil, NGLs and natural gas production, revenues and realized prices and production costs for the Successor Period, the Predecessor Period and

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the years ended December 31, 2015 and 2014. For additional details, see information set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operations."

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        The following table sets forth information regarding oil, NGLs and natural gas daily production for each of the fields that represented more than 15% of our estimated total proved reserves for the Successor Period, Predecessor Period and the years ended December 31, 2015 and 2014:

Productive Wells

        The following table presents our total gross and net productive wells as of December 31, 2016:

        Productive wells consist of producing wells and wells capable of producing. Gross wells are the total number of productive wells in which we have working interests, and net wells are the sum of our fractional working interests owned in gross wells. Each gross well completed in more than one producing zone is counted as a single well.

Acreage

        The following table sets forth certain information regarding the developed and undeveloped acreage in which we have a controlling interest as of December 31, 2016 for each of our operating areas. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary:

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Undeveloped Acreage Expirations

        The following table sets forth the number of gross and net undeveloped acres as of December 31, 2016 that will expire over the next three years by operating area unless operations are commenced upon or production is established upon the acreage (or upon lands spaced or pooled therewith) or we make additional lease rental payments prior to the expiration dates:

        Approximately 15.6% of our net acreage, including acreage under option, was acquired in 2016, with the majority of such leases under three year primary term leases. In addition, our typical lease terms along with unit regulatory rules generally provide us flexibility to continue lease ownership through either establishing production or actively drilling prospects. Because of our reduced activity levels in the Anadarko Basin and divestitures in Louisiana, we may allow leasehold rights on acreage not held by production to expire in these areas, which could reduce our future drilling opportunities. Additionally, to the extent we cannot commence drilling operations upon or establish production from certain leases in the Mississippian Lime asset, certain of the leases within that asset area will expire, unless extended or renewed.

Drilling Activity

        The following table summarizes our drilling activity for the Successor Period, the Predecessor Period and the years ended December 31, 2015 and 2014. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells: