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Economically Producible: The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For this determination, the value of the products that generate revenue is determined at the terminal point of oil and natural gas producing activities.

Estimated Ultimate Recovery: Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves) but which generally has a lower risk than that associated with exploration projects.

Exploratory well:Well: A well drilled to find a new field orand produce oil and natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas or oil in another reservoir or to extend a known reservoir.

Field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

GAAP: Generally accepted accounting principles in the United States of America.

Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have a working interest.

ICE: Inter-Continental Exchange.

MBbl: One thousand Bbls.

MBbls/d: One thousand Bbls per day.

MMBbls: One million stock tank barrels.

MBoe: One thousand barrels of oil equivalent.

MBoe/d: One thousand barrels of oil equivalent per day.

MMBoe:One million barrels of oil equivalent.

Mcf: One thousand cubic feet of natural gas.

MMBtu:MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

MMcfe/d: One MMcfe per day.

Net acres:  The percentage of total acres an owner has out of a particular number ofAcres or Net Wells: Gross acres or a specified tract.wells, as the case may be, multiplied by our working interest ownership percentage.

Net Production: Production that is owned by us less royalties and production due others.

NYMEX:Net Revenue Interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

NGLs: The combination of ethane, propane, butane and natural gasolines that, when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

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NYSE: New York Stock Exchange.

Oil: Oil and condensate.

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

Plugging and abandonment: Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another stratum or to the surface. Regulations of all states require plugging of abandoned wells.

Present value of future net revenues or PV-9: The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 9% in accordance with the guidelines of the U.S. Securities Exchange Commission (the “SEC”).

Present value of future net revenues or PV-10: The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.

Probabilistic Estimate: The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrences.

Productive Well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.

Proved reserves:Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved Reserves: Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—producible, from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—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 natural 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 whichthat 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 used is the average price during the 12-monthtwelve-month period prior to the 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.

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Proved Undeveloped Reserves: Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Reasonable certainty:  A high degreeRealized Price: The cash market price less all expected quality, transportation and demand adjustments.

Recompletion: The completion for production of confidence.

Recompletion:  The process of re-entering an existing wellbore in another formation from that which the well has been previously completed.

Reliable Technology: Reliable technology is either producinga grouping of one or not producingmore technologies (including computational methods) that has been field-tested and completing new reservoirshas been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an attemptanalogous formation.

Reserve Life: A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year end by production volumes. In our calculation of reserve life, production volumes are adjusted, if necessary, to establish, re-establishing, or increase existing production.reflect property acquisitions and dispositions.

Reserves:  EstimatedReserves: Reserves are 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. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir: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.reserves.

Resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

SpudSEC: The U.S. Securities and Exchange Commission.

Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or Spudding:  The commencementstandards established by the SEC and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of drilling operationsthe date of estimation), less estimated future development, production and income tax expenses and discounted at 10% per annum to reflect the timing of future net revenue. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in our oil and natural gas properties. Standardized measure does not give effect to derivative transactions.

Undeveloped Acreage: Lease acreage on which wells have not been drilled or completed to a new well.point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

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

Working Interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and generally requires the owner to pay a share of the costs of drilling and production operations.

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

Working interest:  The right grantedWTI: West Texas Intermediate.

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All statements, other than statements of historical fact, included in this report are forward-looking statements. These forward-looking statements may be found in “Item 1. Business,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other items within this Annual Report. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “outlook,” “continue,” the negative of such terms or other comparable terminology. These statements address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as projections of results of operations, plans for growth, goals, future capital expenditures, competitive strengths, references to future intentions and other such references. These forward-looking statements involve risks and uncertainties. Important factors that could cause the Company’s actual results or financial condition to differ materially from those expressed or implied by forward-looking statements include, but are not limited to, the lesseefollowing risks and uncertainties:

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The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by the Company’s management. These estimates and assumptions reflect the Company’s best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a propertynumber of risks and uncertainties that are beyond the Company’s control. In addition, management’s assumptions about future events may prove to explore forbe inaccurate. All readers are cautioned that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events or circumstances described in any forward-looking statement will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to producefactors described in “Item 1A. Risk Factors” and own oil, natural gas,elsewhere in this report. All forward-looking statements speak only as of the date of this report. We do not intend to update or other minerals. The working interest owners bearrevise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on the exploration, development,Company’s behalf.

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ITEM 1.BUSINESS

References

General

Midstates Petroleum Company, Inc. is an independent exploration and production company focused onAmplify Energy Corp. (“Amplify Energy,” 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 usedor similar terms), is a publicly traded Delaware corporation, in the present tense, prospectively or for historical periods, refer to Midstates Petroleum Company, Inc. and its wholly owned subsidiary.

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 withwhich our emergence from Chapter 11, our existing common shares 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”. Our common stock began tradingis listed on the NYSE under the symbol “MPO” beginning“AMPY.”

Overview

Amplify Energy is an independent oil and natural gas company engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Our management evaluates performance based on May 4, 2017. We currently lease office spaceone reportable business segment, as the economic environments are not different within the operation of our oil and natural gas properties. Our business activities are conducted through OLLC, our wholly owned subsidiary, and its wholly owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties located in Tulsa, Oklahoma, at 321 South Boston Avenue, Suite 1000, wherethe Rockies (“Bairoil”), federal waters offshore Southern California (“Beta”), East Texas/North Louisiana, and Eagle Ford (Non-op). Most of our principal officesoil and natural gas properties are located. located in large, mature oil and natural gas reservoirs.

The lease for our Tulsa office expiresCompany’s properties consist primarily of operated and non-operated working interests in 2026. We also lease one field officeproducing and undeveloped leasehold acreage and working interests in Dacoma, Oklahoma and one in Perryton, Texas.identified producing wells. As of December 31, 2017,2023:

Industry Trends

During 2023, commodity prices generally declined when compared to the same period of 2022 and, as a result, we had 129 employees.

experienced a decrease in revenues. The Company expects continued price volatility in 2024.

We are requiredcontinue to file annual, quarterly and current reports, proxy statementsmonitor the impact of the actions of the Organization of the Petroleum Exporting Countries and other information withlarge producing nations; the SecuritiesRussia-Ukraine conflict; conflicts in the Middle East; global inventories of oil 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.

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,natural gas and the charters of our audit committee, compensation committeeuncertainty associated with recovering oil demand; inflation and nominatingfuture monetary policy; and governance committee are also available on our websitegovernmental policies aimed at transitioning towards lower carbon energy. The Russia-Ukraine conflict and conflicts in print free of chargethe Middle East continue 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 will disclose any amendments or waivers to our Code of Ethics on our website.

Business Strategy

Our goal is to grow shareholder value through optimized capital investments and generation of free cash flow. To achieve these objectives, we strive to:

·                  Operate in a safe and environmentally responsible manner;

·                  Maximize our return on capital deployed by utilizing our extensive technical and operating experience in our core areas of operations to focus on identifying opportunities to achieve the best rate of returnevolve, and the highest probability of success;

·                  Maintain a best in class cost structureextent to maximize the cash flow margin ofwhich these events may impact our production;

·                  Prioritize free cash flow generation over production growth. Strive towards the optimum balance between free cash flow generation and sustaining inventory for future investment. We will optimize free cash flow generation by focused capital investments, optimizing our base production, and maintaining a low-cost structure; and

·                  Maintain maximum optionality by maintaining low net debt, balancing shareholder cash returns with replenishing inventory, and evaluating strategic alternatives within and outside of our current asset base.

Our balance sheet and strong liquidity position provide us with significant resources to develop our multi-year drilling inventory and judiciously expand our core acreage positions. For 2018, we intend to opportunistically achieve the best return on investments by optimizing our drilling and completion design, focusing on minimizing well down time and optimizing well productivities while maintaining both capital discipline and a low-cost structure.

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 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. Further information is set forth in “—Note 2. Emergence from Voluntary Reorganization under Chapter 11 Proceedings” in the Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

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 andbusiness, results of operations, financial condition and cash flows will depend on future developments, which are highly uncertain and cannot be predicted with confidence.

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Properties

We engaged Cawley, Gillespie and Associates, Inc. (“CG&A”), our independent reserve engineers, to prepare our reserves estimates for all of our proved reserves at December 31, 2023. The following table summarizes information, based on a reserve report prepared by CG&A (which we refer to as our “reserve report”), about our proved oil and natural gas reserves by geographic region as of December 31, 2023, and our average net production for the period October 21, 2016 throughthree months ended December 31, 2016 and references to “Predecessor Period” refer to the financial position and results2023:

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Our Areas of operations of the Company from January 1, 2016 through October 20, 2016.Operation

Oklahoma

Summary of Oil and Gas Properties and Operations

Mississippian Lime

Our Mississippian Lime assets are located in Oklahoma and target the Mississippian Lime formation. At December 31, 2017, our acreage consisted of approximately 97,762 net (117,451 gross) prospective acres in the Mississippian Lime trend in Woods and Alfalfa Counties of Oklahoma, which we currently intend to develop using horizontal wells.

Our properties in this area represented 92%Approximately 30% of our totalestimated proved reserves as of December 31, 2017. As2023 and approximately 27% of December 31, 2017, we held anour average working interest and averagedaily net revenue interest of 77% and 62%, respectively, in this area.

Forproduction for the yearthree months ended December 31, 2017, the Successor Period and the Predecessor Period, our average daily production from our Mississippian Lime assets was as follows:

At December 31, 2017, we had one operated drilling rig in operation2023 were located in the Mississippian Lime horizontal well program. For 2018, we anticipate investing between $100.0 millionOklahoma region. Our Oklahoma properties include wells and $120.0 million in the area.

Anadarko Basin

Our Anadarko Basin assets areproperties primarily located in Western OklahomaAlfalfa and the Texas panhandle and target, or are prospectiveWoods counties in the Cleveland, Marmaton, Cottage Grove, Osage, Meramac and Tonkawa formations. At December 31, 2017, our acreage consistedOklahoma. Those properties collectively contained 29.5 MMBbls of approximately 76,409estimated net (92,289 gross) acres in Texas and 16,198 net (41,332 gross) acres in western Oklahoma.

Our properties in this area represented 8% of our total proved reserves as of December 31, 2017. As2023 based on our reserve report and generated average net production of 5.5 MBoe/d for the three months ended December 31, 2023.

Based on our reserve report, the Dacoma field contains more than 15% of our total estimated reserves. The following table summarizes production volumes from this field for the period presented:

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Bairoil

Approximately 24% of our estimated proved reserves as of December 31, 2017, we held an2023 and approximately 16% of our average daily net production for the three months ended December 31, 2023 were located in Bairoil. Our Bairoil properties include wells and properties primarily located in the Lost Soldier and Wertz fields in Wyoming at our Bairoil complex. Our Bairoil properties contained 23.5 MMBbls of estimated net proved oil and NGLs reserves as of December 31, 2023 based on our reserve report and generated average net production of 3.4 MBoe/d for the three months ended December 31, 2023.

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Beta

Approximately 13% of our estimated proved reserves as of December 31, 2023 were associated with the Beta field located in federal waters approximately 11 miles offshore from the Port of Long Beach, California. Our ownership in Beta consists of 100% of the working interestinterests and 75.2% average net revenue interest in three Pacific Outer Continental Shelf lease blocks (P-0300, P-0301 and P-0306) (referred to as the “Beta Unit”) in the Beta field. The Beta properties contained 12.7 MMBbls of 64% and 50%, respectively, in this area.

For the year end December 31, 2017, Successor Period and Predecessor Period, our average daily production from the Anadarko Basin area was as follows:

Other

On April 21, 2015, we closed on the sale of certain of ourestimated net proved 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 Gulf Coast (or Louisiana) as of December 31, 2017, 2016 or 2015.

During2023 based on our reserve report and generated average net production of 3.0 MBoe/d for the three months ended September 30, 2017, we closed onDecember 31, 2023. Oil and gas are produced from the Beta Unit via two production platforms, referred to as the Ellen and Eureka platforms, equipped with permanent drilling rigs and associated equipment. On a third platform, Elly, the oil, water and gas are separated, and the oil is prepared for sale, while the gas is utilized as fuel for power and the water is recycled back into the reservoir for pressure maintenance. Sales quality oil is then pumped from the Elly platform to the Beta pump station located onshore at the Port of Long Beach, California via a 16-inch diameter oil pipeline, which extends approximately 17.5 miles. Amplify Energy’s wholly owned subsidiary, San Pedro Bay Pipeline Company owns and operates the pipeline system.

For a discussion regarding the Incident, see Note 15 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information.

East Texas / North Louisiana

Approximately 30% of our oilestimated proved reserves as of December 31, 2023 and gasapproximately 38% of our average daily net production for the three months ended December 31, 2023 were located in the East Texas/ North Louisiana region. Our East Texas/ North Louisiana properties include wells and properties primarily located in Lincoln County, Oklahoma, which had approximately 12,894 net (19,888 gross) acres for $7.0 millionthe Joaquin, Carthage, Willow Springs and East Henderson fields in cash ($2.9 million, net after assumptionEast Texas. Those properties collectively contained 29.9 MMBoe of liabilities), subject to standard post-closing adjustments.

Reserves Information

Estimated Proved Reserves

The following table sets forth our estimated net proved reserves by productas of December 31, 2023 based on our reserve report and type using SEC pricing:generated average net production of 8.0 MBoe/d for the three months ended December 31, 2023.

Eagle Ford

(1)                                 We refer to PV-10 as the present valueApproximately 3% of estimated future net cash flows ofour estimated proved reserves as calculated in the respective reserves report using a discount rate of 10%. This amount includes projected revenues, estimated production costs, estimated future development costsDecember 31, 2023 and estimated cash flows related to future asset retirement obligations (“ARO”). PV-10 is a financial measure not defined under US GAAP. Accordingly, the following table reconciles total PV-10 to the standardized measure of discounted future net cash flows, which is the most directly comparable US GAAP financial measure. We believe the presentation of PV-10 provides useful information

because it is widely used by investors in evaluating oil and natural gas companies without regard to specific income tax characteristics of such entities. PV-10 is not a measure of financial or operating performance under US GAAP, nor is it intended to represent the current market valueapproximately 4% of our estimated proved reserves. PV-10 should not be considered in isolation or as a substituteaverage daily net production for the standardized measure of discounted future net cash flows as defined under US GAAP.

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

Proved Undeveloped Reserves

The following table summarizes the changes in our estimated proved undeveloped reserves during the yearthree months ended December 31, 2017 (in MBoe):2023 were located in the Eagle Ford region. Our Eagle Ford properties include wells and properties in fields located primarily in the Eagleville fields. Our Eagle Ford properties contained 2.5 MMBoe of estimated net proved reserves as of December 31, 2023 based on our reserve report. Those properties collectively generated average net production of 0.9 MBoe/d for the three months ended December 31, 2023.

Our Oil and Natural Gas Data

No less than annually, we reviewOur Reserves

Internal Controls. Our proved reserves were estimated at the well or unit level for reporting purposes by CG&A, our five-year development schedule. This review encompasses many factors, including current year drilling results, forward pricing curve, returns expectedindependent reserve engineers. We maintain internal evaluations of our drilling programreserves in a secure reserve engineering database. CG&A interacts with our internal petroleum engineers and cash available during this time period, which would include cash on hand, cash generated by operations and cash from borrowings. On November 1, 2017, David Sambrooks was appointed President and Chief Executive Officer of the Company. Upon David’s appointment, we began a strategic review of all areas of operations. This review was completed during the fourth quarter of 2017 and our strategy was refined to add further focus to optimizing free cash flows and keeping leverage to a minimum. As a result,geoscience professionals in December of 2017 we decreased our current drilling activity from two drilling rigs to one drilling rig. Further, the five-year development plan was revised from a two-rig program to a one rig program. This change in strategy (reduced 5-year drilling activity) led to a reduction in our undeveloped proved inventory under SEC guidelines from 274 locations at year end 2016 to 139 locations at year end 2017. In addition, at year end 2017 our proved undeveloped type curve was revised downward by our third-party reserves engineering firm and capital costs assumptions were revised upward, both as a result of recent drilling results. The revised type curve still generates attractive capital returns of 30.6% IRR at year-end 2017 SEC pricing, and 39.1% IRR at December 31, 2017 strip pricing. As a resulteach of our focus on optimizing free cash flow, keeping leverageoperating areas and with operating, accounting, and marketing employees to a minimum and optimizing drilling returns, all proved undeveloped reserves included inobtain the December 31, 2017 reserve report are focused on infill drilling in the Carmen and Dacoma areas. All undeveloped locations not ablenecessary data to be drilled utilizing our anticipated five-year development schedule were excluded from the December 31, 2017 reserve report but continue to meet the definition of a proved undeveloped location from an engineering standpoint.

Independent Petroleum Engineers

For our Mississippian Lime and Anadarko Basin assets, our estimated reserves and related future net revenues at December 31, 2017, 2016 and 2015 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 30 years of practical experience in petroleum engineering, with over 28 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.

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 employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation ofprepare our proved reserves include, butreport. Reserves are not limited to, electrical logs, radioactivity logs, core analyses, geologic mapsreviewed and available downholeapproved internally by our senior management on an annual basis and production data, seismic data and well test data.evaluated by our lender group on at least a semi-annual basis in connection with borrowing base redeterminations under our Revolving Credit Facility. Our reserve estimates are prepared by CG&A at least annually.

Internal Controls Over Reserves Estimation Process

We maintain anOur internal professional staff of petroleum engineers, land and geoscience professionals who workworks closely with our independent reserve engineersCG&A to ensure the integrity, accuracy and timeliness of data that is furnished to CGAthem in theirorder to prepare the reserves estimation process. The primary inputsreport. All of the reserve information maintained in our secure reserve engineering database is provided 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 meetingsexternal engineers. In addition, we provide CG&A 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 financialother pertinent data, such as commodity prices, leaseseismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating expenses, production taxesprocedures and field commodity price differentials are updated in the reserves database and then analyzed to ensure that they have been entered accurately and thatrelevant economic criteria. We make all updates are complete. Our current ownership in mineral interests and well production data are incorporated into the reserves databaserequested information, as well and verifiedas our pertinent personnel, available to ensurethe external engineers as part of their accuracy and completeness. Throughout each fiscal year, our technical team meets with representativespreparation of our independent reserve engineers to review properties and discuss methods and assumptions used in preparationreserves.

Qualifications of Responsible Technical Persons

Internal Engineers. Tony Lopez is the proved reserve estimates. Each quarter, estimated proved oil and gas reserves are presented to a committee of executives and key management for review and approval and annually, our development plan for proved undeveloped reserves are reviewed and approved by our executives.

At December 31, 2017, Jeromy Garcia, our General Manager — Mississippian Lime and Anadarko Basin Assets and Reserves, wastechnical person at the Company, primarily responsible for overseeing and providing oversight of the preparation of the reserves estimates with our third-party reserve estimates and reported directly to our Chief Executive Officer. engineers.

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Mr. GarciaLopez has more than 17over 16 years of experiencecorporate reserve reporting experience. Mr. Lopez joined the Company as Vice President of Corporate Reserves in June 2018 and currently serves as the Company’s Senior Vice President of Engineering & Exploitation. Prior to that Mr. Lopez was Vice President of Acquisitions and Engineering for EnerVest, Ltd., where he managed the corporate reserve reporting process and the financial planning & analysis department. Mr. Lopez is a graduate of West Virginia University and holds a B.S. in Petroleum and Natural Gas Engineering. Mr. Lopez is an active member of the Society of Petroleum Engineers.

Cawley, Gillespie and Associates Inc. CG&A is an independent oil and natural gas consulting firm. No director, officer, or key employee of CG&A has any financial ownership in us or any of our affiliates. CG&A’s compensation for the preparation of its report is not contingent upon the results obtained and reported. CG&A has not performed other work for us or any of our affiliates that would affect its objectivity. The estimates of our proved reserves presented in the CG&A reserve report were overseen by Todd Brooker.

Mr. Brooker is the President of CG&A and has been an employee of CG&A since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron Corporation. Mr. Brooker’s experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas industry. shale plays, coalbed methane fields, waterfloods and complex, faulted structures.

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. GarciaBrooker graduated with honors from the University of OklahomaTexas at Austin in 20001989 with a B.SBachelor of Science degree in Petroleum Engineering and obtained his MBA fromis a registered Professional Engineer in the UniversityState of Houston in 2009.

Production, RevenuesTexas. He is also a member of the Society of Petroleum Engineers and Price Historythe Society of Petroleum Evaluation Engineers.

Estimated Proved Reserves

Oil, NGLsThe following table summarizes our estimated proved oil and natural gas reserves and related standardized measure of discounted future net cash flows attributable to our properties as of December 31, 2023, which are commodities. based on the prepared reserve report by CG&A, our independent reserve engineers.

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The price that we receive fordata in the oil, NGLstable above represents estimates only. Oil and natural gas we producereserve engineering is largelyinherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of market supplythe quality of available data and demand. A decline in oil or natural gas pricesengineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from their current levels could have a material adverse effect on our financial position, results of operations, cash flows,the quantities of oil and natural gas reserves that are ultimately recovered.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate standardized measure, which is required by the SEC and FASB, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be economically produced and our ability to access capital markets.inaccurate. For additional information on these and other risks, see information set forth in “Risk Factors”.

The following table sets forth information regardingreasons, neither standardized measure nor PV-10 should be construed as the fair value of our oil NGLs and natural gas reserves.

For a discussion of risks associated with internal reserve estimates, see “Item 1A. Risk Factors — Risks Related to Our Business — Our estimated reserves and future production revenuesrates are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and realized pricespresent value of our estimated reserves.”

Development of Proved Undeveloped Reserves

As of December 31, 2023, we had 1,926 MBoe of proved undeveloped reserves (“PUDs”) comprised of 1,772 MBbls of oil, 451 MMcf of natural gas and production costs for77 MBbls of NGLs. None of our proved undeveloped reserves as of December 31, 2023 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as PUDs. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

For the year ended December 31, 2017,2023, total proved undeveloped reserves increased by 868 MBoe. The majority of this increase (1,122 MBoe) was due to the Successor Period,addition of 4 Beta PUD locations included in our 2024 budget offset by transfers (215 MBoe) to proved developed reserves from certain non-operated properties in the Predecessor PeriodEagle Ford and East Texas. Other changes (39 MBoe) included modifications to the yearnon-operated Eagle Ford development plan.

Approximately 20.3% (215 MBoe) of our PUDs recorded as of December 31, 2022 were developed during the twelve months ended December 31, 2015.2023. Total costs incurred to develop these PUDs were approximately $4.4 million, of which $1.8 million was incurred in fiscal year 2022 and $2.6 million incurred in fiscal year 2023. In total, we incurred total capital expenditures of approximately $2.6 million during fiscal year 2023 developing PUDs. Based on our current expectations of our cash flows, we believe that we can fund the drilling of our current PUD inventory and our expansions in the next five years from our cash flow from operations and borrowings under our Revolving Credit Facility. For additional details,a more detailed discussion of our liquidity position, see information set forth in “Management’s“Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Production, Revenue and Price History

For a description of our production, revenues, and average sales prices and per unit costs, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”

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The following table sets forth information regarding oil, NGLstables summarize our average net production, average unhedged sales prices by product and natural gas daily production for each of the fields that represented more than 15% of our estimated total proved reservesaverage lease operating cost expense per Boe by geographic region for the yearyears ended December 31, 2017, the Successor Period, the Predecessor Period2023 and the year ended December 31, 2015:2022, respectively:

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