Exhibit 99.3

CASTEX ENERGY 2014, LLC AND SUBSIDIARIES

Consolidated Financial Statements

As of and For the Years Ended

December 31, 2019 and 2018

CASTEX ENERGY 2014, LLC AND SUBSIDIARIES

Contents

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Independent Auditor’s Report

To the Members of

Castex Energy 2014, LLC

Houston, Texas

We have audited the accompanying consolidated financial statements of Castex Energy 2014, LLC and Subsidiaries, which comprise the consolidated balance sheets as of December 31, 2019 and 2018, and the related consolidated statements of operations, members’ equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Castex Energy 2014, LLC and Subsidiaries as of December 31, 2019 and 2018, and the results of their operations and their cash flows for the years then ended, in accordance with accounting principles generally accepted in the United States of America.

/s/ BDO USA, LLP

August 24, 2020

Houston, Texas

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Consolidated Financial Statements

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CASTEX ENERGY 2014, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

See accompanying notes to consolidated financial statements.

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CASTEX ENERGY 2014, LLC AND SUBSIDIARIES

Consolidated Statements of Operations

See accompanying notes to consolidated financial statements.

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CASTEX ENERGY 2014, LLC AND SUBSIDIARIES

Consolidated Statements of Members’ Equity

See accompanying notes to consolidated financial statements.

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CASTEX ENERGY 2014, LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

See accompanying notes to consolidated financial statements.

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CASTEX ENERGY 2014, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Castex Energy 2014, LLC (the “Company”) was formed on April 10, 2014, as a Delaware limited liability company and is engaged in the exploration, development and production of natural gas, crude oil and natural gas liquids. GOME 1271 LLC (“GOME”) and Castex Energy Development Fund II, LLC (“CEDF II”) are wholly- owned subsidiaries of Castex Energy 2014, LLC. The majority of the exploration efforts are concentrated in southern Louisiana and within the Outer Continental Shelf of the United States in the Gulf of Mexico.

The ownership interests in Castex Energy 2014, LLC are held by the Series A members specified in the Amended and Restated Limited Liability Company Agreement of Castex Energy 2014, LLC dated September 3, 2014 (“the LLCA”) and Castex Energy 2005, L.P., the sole Series B member and holder of 100 Series B units.

Principles of Consolidation

The consolidated financial statements include the accounts of Castex Energy 2014, LLC and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Significant estimates include volumes of oil and natural gas reserves used in calculating depreciation, depletion and amortization of oil and natural gas properties, ceiling test, future net revenues, abandonment obligations, the collectability of outstanding accounts receivable and contingencies. Oil and natural gas reserve estimates, which are the basis for unit-of-production depreciation, depletion and amortization, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are sensitive to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

Cash and Cash Equivalents

Cash and cash equivalents include deposits at banks and short term highly liquid investments with original maturities of ninety days or less.

Accounts Receivable

Accounts receivable primarily represent revenues for November and December. The Company’s accounts receivable are generally not collateralized. There was no allowance for doubtful accounts for either of the years presented.

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CASTEX ENERGY 2014, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Revenue Recognition

The Company follows the sales method of accounting for revenues whereby it recognizes revenues on production as it is taken and delivered to its purchasers, and if collectability of the revenue is probable. At times, owners may take more or less gas production from a property than they are entitled based on their ownership percentages in the property, which results in a production imbalance. As the Company follows the sales method of accounting, amounts are recorded as gas imbalances when the amounts owed exceed the Company’s share of the cumulative recoverable reserves from that property. As of December 31, 2019 and 2018, the Company has not recorded any gas imbalances.

Property and Equipment

The Company accounts for its investment in oil and natural gas producing activities using the full-cost method of accounting. Under this method of accounting, all costs, including indirect costs related to exploration and development activities, are capitalized as oil and natural gas property costs. These costs, and estimated future development costs, are accumulated and are amortized on an equivalent unit-of-production basis using total estimated proved oil and natural gas reserves. The Company accounts for workovers based on the nature of the work performed. Workover costs incurred for the purpose of restoring production in the same producing horizon are expensed as incurred. Workover costs incurred to explore shallower or deeper horizons to produce reserves from a new formation are capitalized. No gains or losses are recognized on the sale or disposition of oil and natural gas properties, except for sales which include a significant portion of the total proved reserves, and significantly alter the depletion rate. The cost of unevaluated properties are excluded from the full-cost amortization base until it is determined whether or not proved reserves can be assigned to the properties or impairment has occurred.

Ceiling Test

Under the full-cost method of accounting, a ceiling test is performed quarterly. The test establishes a limit (ceiling) on the book value of oil and natural gas properties. The capitalized costs of proved oil and natural gas properties, net of accumulated depreciation, depletion and amortization and previously recognized impairment may not exceed this “ceiling.” The ceiling limitation is the estimated future net cash flows from proved oil and natural gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the consolidated balance sheets. The Company uses a twelve-month unweighted average price in the reserve report utilized for ceiling test purposes. If capitalized costs exceed this limit, the excess is charged to impairment expense. The Company recorded impairment expense of $57,927,131 during the year ended December 31, 2019. No impairment expense was recognized for the year ended December 31, 2018.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, derivative financial instruments, and long-term debt. The carrying amounts of these accounts are representative of their respective fair values due to the short-term maturity of these instruments or their interest rate reflective of current market rates except for the derivative financial instruments which are adjusted to fair value at each period end (see Notes 6 and 10).

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Notes to Consolidated Financial Statements

Debt Issue Costs

Debt issue costs consist of costs associated with obtaining credit with financial institutions. These costs are capitalized and amortized on a straight-line basis over the life of the credit agreement, which approximates the effective interest method. Amortization expense was $140,174 and $321,347 for the years ended December 31, 2019 and 2018, respectively, and is included in interest expense in the consolidated statements of operations. In September 2018, the Company expensed the remaining unamortized debt issuance costs of $119,829, and recorded $448,460 of issuance costs associated with its new credit facility (See Note 7).

Investments in Unconsolidated Entities

The Company’s investments consist of an investment in CTS-Castex, LLC (“CTS-Castex”) of 33.38% and Castex LaFourche, L.P. (“Castex LaFourche”) of 4.73%.

The investment in CTS-Castex is accounted for under the equity method of accounting as the Company has the ability to exercise significant influence, and the investment in Castex LaFourche is accounted for under the cost method. No equity income for the investment in CTS-Castex was recorded for the years ended December 31, 2019 and 2018, as the Company has not commenced business operations.

Income Taxes

As a limited liability company, the Company is not subject to federal or state income taxes as such income taxes accrue directly to the members.

The Company has adopted guidance issued by the FASB regarding accounting for uncertainty in income taxes. The guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. If management believes that an income tax position meets the more likely than not threshold, then the tax benefits of this income tax position would be recognized. There were none recognized for the years ended December 31, 2019 and 2018.

The Company has elected to record income tax related interest and penalties as a component of the provision for income tax expense. There was no interest or penalties recognized in the consolidated statements of operations for the years ended December 31, 2019 and 2018.

The Company believes that there are no income tax positions taken or expected to be taken that would significantly increase or decrease unrecognized income tax benefits within 12 months of the reporting date.

None of the Company’s federal or state income tax returns are currently under examination by the Internal Revenue Service (“IRS”) or state authorities. However, fiscal years 2015 and later remain subject to examination by the IRS or state tax authorities.

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Notes to Consolidated Financial Statements

Asset Retirement Obligations

The Company follows FASB Accounting Standards Codification (“FASB ASC”) 410-20, Asset Retirement Obligations, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirements costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.

FASB ASC 410-20 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depleted over the life of the asset. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the passage of time. If the obligation is settled for other than the carrying amount of the liability, the Company will record an adjustment to the full-cost pool. A credit-adjusted risk-free interest rate is used in our calculation of asset retirement obligations.

Concentration of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk include cash and cash equivalents and accounts receivable.

The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Company monitors the financial condition of the institutions and has not experienced any losses associated with its accounts.

The Company’s customer concentration may impact its overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and gas industry. However, the risk is low due to the industry and access to other purchasers.

The Company enters into joint operating agreements with related parties for the exploration and development of on-shore and off-shore properties. These transactions expose the Company to potential credit risk arising from the operator’s failure to adequately manage its operations.

Subsequent Events

The Company evaluated subsequent events through August 24, 2020, which is the date these financial statements were available for issuance.

On February 28, 2020, the Company closed on the Purchase and Sale Agreement with Talos Production Inc., a wholly owned subsidiary of Talos Energy Inc., whereas Talos Production Inc. purchased all of the issued and outstanding membership interests of GOME.

The Company was formed by Series A and Series B members. Series A units have a par value of $1.00 per unit. Series A members have one voting right for each Series A membership interest held while the Series B member has no voting rights. None of the members in his, her or its capacities as a Member, have any power or authority to manage the business or affairs of the Company or to bind any Members or enter into any agreements on behalf of the Company. The power and authority to manage the business or affairs of the Company is vested in the Board of Directors. The LLCA includes provisions for the purchase of additional interests and limitations on the ability of the members to transfer their interests. The LLCA also sets forth the manner of allocating income, deductions and credits for tax purposes and specifies the order for the allocation of proceeds upon dissolution.

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CASTEX ENERGY 2014, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

In March 2018, a change in control of Castex Energy 2005, L.P. occurred and ownership of the Series B units transferred to Castex Energy 2005, LLC.

Cash distributions are allocated as follows:

There were no distributions to members for the years ended December 31, 2019 and 2018.

As of December 31, 2019 and 2018, there were 100 Series B units outstanding. It is intended that Series B Units will constitute Profits Interests only. As such, the Profits Interests will be considered a liability when the Company has reached the minimum internal rate of return required by the LLCA. As of December 31, 2019 and 2018, no amounts were recorded related to the Series B units as payments were not considered probable.

On November 14, 2018, the Company, through its wholly-owned subsidiary GOME, acquired a group of oil and gas properties in the Gulf of Mexico from McMoran Oil & Gas LLC in exchange for GOME assuming the i) lease abandonment obligations, ii) providing performance and umbrella bonds, and iii) assuming a contingent payment in the sum of $2,500,000, due no later than January 31, 2020, if the WTI Crude averages $72 per barrel for the trading days during calendar year 2019. As of December 31, 2018, no liability has been recorded for the contingent payment as it was not considered probable. The Company received cash of $4,578,600 and incurred $519,333 in acquisition costs, which have been recorded in the full cost pool.

During 2018, the Company also acquired interest in certain properties from third parties for a total of $1,125,762, recorded in the full cost pool.

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Notes to Consolidated Financial Statements

Capitalized costs related to the Company’s oil and natural gas producing activities and the related amounts of accumulated depreciation, depletion, amortization and impairment are as follows:

All derivative instruments are measured periodically and at year end and are recorded on the consolidated balance sheets at fair value. Derivative contracts that are not designated as part of a valid qualifying hedge or fail to meet the requirements of the pronouncement as a highly effective hedge, are accounted for by recording the changes in the fair value from period to period, through earnings. The amounts paid or received upon each monthly settlement, are recorded as derivative gain (loss) with the offset recorded to cash. These monthly settlements are recorded to the Company’s consolidated statements of operations as “(Gain) loss on derivative financial instruments.” Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets.

As of December 31, 2019, the Company had the following contracts outstanding (Asset (Liability) and fair value gain (loss)):

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CASTEX ENERGY 2014, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

The following table summarizes the fair value and classification of the Company’s derivative instruments as of December 31, 2019 and 2018, all of which have not been designated as hedging instruments under FASB ASC 815:

The following table summarizes the effect of the Company’s derivative instruments in the consolidated statements of operations:

In February 2016, the Company’s wholly owned subsidiary, GOME, entered into a credit facility with a borrowing base of $27,000,000, and subsequently borrowed $22,000,000 to finance the acquisition of on-shore and off-shore oil and natural gas interests acquired from Castex Energy Partners, LP (“CEP”), a related party.

In September 2018, the Company refinanced its credit facility with First Tennessee Bank National Association with a borrowing base of $25,000,000 and maturity of March 18, 2022. Interest on the amount draw is based on LIBOR plus an applicable margin. The interest rate at September 30, 2019 was 5.43% and December 31, 2018 was 4.70%. The credit facility is also subject to a commitment fee of .50% based on the unused commitment amount. The borrowings are collateralized by proved property of the Company. The borrowing base is also re- determined semi-annually on or around May 1st and November 1st of each year and may be reduced discretionarily by the lenders, which may require significant principal repayments. The borrowing base was re- determined and increased to $30,000,000 in November 2018.

In July 2019, the Company’s borrowing base was re-determined to $25,000,000 with availability stepping down to $21,000,000 on November 1, 2019.

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Notes to Consolidated Financial Statements

As of December 31, 2019, the outstanding balance was $21,000,000. The Company is also subject to certain affirmative and negative covenants associated with the credit facility and was in compliance with all financial covenants as of December 31, 2019.

Future maturities of long-term debt are as follows:

The details of asset retirement obligations are as follows:

The Company pays management fees to Castex Energy, Inc. (“CEI”), a related party, pursuant to a Shared Services Agreement. For the years ended December 31, 2019 and 2018, the management fees were $7,000,000 and $2,300,000, respectively. The Company capitalized $1,620,000 and $600,000 of this overhead to unproved properties during the years ended December 31, 2019 and 2018, respectively. Management fees net of capitalized amounts are included in general and administrative expenses in the consolidated statements of operations.

At December 31, 2019 the Company was due $542,134 which comprises of $2,883,310 revenues receivable and $2,341,176 joint interest billings. At December 31, 2018, the Company was due $1,240,779 from CEI which comprises of $4,035,481 revenues receivable and $2,794,702 joint interest billings.

At December 31, 2019 Castex Offshore Inc., (“COI”), a related party, was due $1,175,554 which comprises of $2,470,659 revenues receivable and $3,646,213 joint interest billings. At December 31, 2018, the COI was due $3,418,964 which comprises of $4,233,040 revenues receivable and $7,652,004 joint interest billings.

Balances with CEI and COI are presented net in accounts receivable - related party or accounts payable - related party, as applicable for the period, in the consolidated financial statements as rights of setoff exist.

In January 2019, the Company closed on the sale of certain interests in oil and gas properties to Castex Energy 2016, LP, a related party, and paid $692,860 in connection with the abandonment obligations assumed by the purchaser.

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Notes to Consolidated Financial Statements

The Company follows FASB ASC 820, Fair Value Measurements and Disclosures, which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.

FASB ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.

The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2019 and 2018, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques which utilize Company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. For the years ended December 31, 2019 and 2018, we recorded a total of $168,196 and $30,524,398, respectively, in additions to asset retirement obligations measured at fair value.

The Company determines the fair value of the assets acquired and liabilities assumed in business acquisitions using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped, probable and possible reserves are deduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements included significant unobservable inputs, making these a Level 3.

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Notes to Consolidated Financial Statements

The fair value of assets or liabilities associated with acquisitions of businesses are on a non-recurring basis and is not measured in periods after initial recognition.

The Company may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. The Company regularly analyzes current information and as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management and legal counsel, at December 31, 2019, there were no threatened or pending legal matters that would have a material impact on the Company’s consolidated financial statements.

12. Supplemental Oil and Gas Information (Unaudited)

Capitalized Costs

Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. For a summary of these costs, see below.

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Notes to Consolidated Financial Statements

Costs Incurred for Property Acquisition, Exploration, and Development Activities

The following table reflects the costs incurred for oil and natural gas property acquisition, exploration, and development activities during the year ended December 31, 2019 and 2018. Costs incurred also include new asset retirement obligations established in the current year, as well as increased or decreases to the asset retirement obligations resulting from changes to cost estimates during the year:

Estimated Quantities of Proved Oil and Natural Gas Reserves

The Company employs full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with Securities and Exchange Commission (“SEC”) guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and sub-surface information obtained from the drilling of existing wells. The Company’s VP of Reservoir Engineering, internal reservoir engineers and geologists analyzed and prepared reserve estimates on all oil and natural gas fields. All of the Company’s proved oil and natural gas reserves are located in the United States primarily southern Louisiana and offshore Gulf of Mexico.

Proved oil and natural gas reserves are the estimated quantities of oil natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis, material balance, petro physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all our fields.

Reserve estimates are often different from the quantities of oil, natural gas, and NGLs that are ultimately recovered. Estimating quantities of proved oil, natural gas and NGL reserves is a complex process that involves significant interpretations and assumptions and cannot be measured in an exact manner. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical and engineering data. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based upon, economic factors, such as oil, natural gas and NGL prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effects of governmental regulation. In addition, due to the lack of substantial, if any, production data, there are greater uncertainties in estimating PUD reserves, proved developed non-producing reserves and proved developed reserves that are early in their production life. As a result, the Company’s reserve estimates are inherently imprecise.

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Notes to Consolidated Financial Statements

The following table sets forth information for the period ended December 31, 2019 and 2018 with respect to changes in the Company’s proved (i.e. proved developed and undeveloped) reserves:

For the year ended December 31, 2019, the Company had downward revisions of previous estimates of 1,111 Mboe. These revisions are primarily a result of well performance. No extensions or acquisitions were reported during the period in 2019.

For the year ended December 31, 2018, the Company had downward revisions of previous estimates of 4,240 Mboe. These revisions are primarily a result of well performance. As a result of ongoing drilling and completion activities during the period in 2018, the Company reported extensions, discoveries, and other additions of 1,741 Mboe. Additionally, during the period in 2018, the Company purchased reserves of 5,359 Mboe.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The Company follows the guidelines prescribed in ASC Topic 932, Extractive Activities—Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil and natural gas reserve disclosures, standardized measures of discounted future net cash flows from proved oil and natural gas reserves and the reconciliations of standardized measures from year to year.

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Notes to Consolidated Financial Statements

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (1) estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions; (2) estimated future cash flows are compiled by applying the twelve month average of the first of the month prices of crude oil and natural gas relating to the Company’s proved reserves to the year-end quantities of those reserves for reserves; (3) future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred; (4) future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Company’s proved oil and natural gas reserves; and, (5) future net cash flows are discounted to present value by applying a discount rate of 10%.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The following table shows the base prices used in determining the standardized measure:

These prices were based on the 12-month arithmetic average first-of-month price for January 1, 2018 through December 31, 2018, and January 1, 2019 through December 31, 2019. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price and the natural gas pricing was based on the Henry Hub price. All prices have been adjusted for transportation, quality and basis differentials.

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Notes to Consolidated Financial Statements

The following summary sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed in ASC Topic 932:

The following are the principal sources of change in the Standardized Measure:

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