Exhibit 99.4

CASTEX ENERGY 2016, LP AND SUBSIDIARY

Consolidated Financial Statements

As of and For the Years Ended

December 31, 2019 and 2018

CASTEX ENERGY 2016, LP AND SUBSIDIARY

Contents

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Independent Auditor’s Report

To the Partners of

Castex Energy 2016, LP

Houston, Texas

We have audited the accompanying consolidated financial statements of Castex Energy 2016, LP and Subsidiary, which comprise the consolidated balance sheets as of December 31, 2019 and 2018, and the related consolidated statements of operations, changes in partners’ capital, and cash flows for the years then ended, and the related notes to the consolidated financial statements.

Management’s Responsibility for the 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 2016, LP and Subsidiary 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 2016, LP AND SUBSIDIARY

Consolidated Balance Sheets

See accompanying notes to consolidated financial statements.

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CASTEX ENERGY 2016, LP AND SUBSIDIARY

Consolidated Statements of Operations

See accompanying notes to consolidated financial statements.

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Consolidated Statements of Changes in Partners’ Capital

See accompanying notes to consolidated financial statements.

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Consolidated Statements of Cash Flows

See accompanying notes to consolidated financial statements.

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CASTEX ENERGY 2016, LP AND SUBSIDIARY

Notes to Consolidated Financial Statements

Castex Energy 2016, LP was formed on March 22, 2016 (date of inception), as a Texas limited partnership and is engaged in the exploration, development and production of natural gas, crude oil and natural gas liquids. 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 general partner of Castex Energy 2016, LP is Castex Energy 2016 GP, LLC, a Delaware limited liability company.

On May 2, 2017, Castex Energy, Inc. assigned 100% equity interest in Dorado Deep GP, LLC (“Dorado Deep”), a Delaware limited liability company, to Castex Energy 2016, LP. Dorado Deep is an entity qualified to hold offshore leases. Castex Energy 2016, LP is the sole member of Dorado Deep and, as such, Dorado Deep is considered a wholly-owned subsidiary of Castex Energy 2016, LP (Dorado Deep and Castex Energy 2016, LP are hereinafter collectively referred to as the “Partnership”).

Principles of Consolidation

The consolidated financial statements include the accounts of Castex Energy 2016, LP and its wholly-owned subsidiary. 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 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 depletion 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 depletion and annual ceiling test, 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 are 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 estimated revenues of oil and natural gas for the prior two months. The Partnership’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 2016, LP AND SUBSIDIARY

Notes to Consolidated Financial Statements

Revenue Recognition

The Partnership 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 of an oil and natural gas property may take more or less production from a property than they are entitled based on their ownership percentages in the property, which results in a production imbalance. As the Partnership follows the sales method of accounting, amounts are recorded as natural gas imbalances when the amounts owed exceed the Partnership’s share of the cumulative recoverable reserves from that property. As of December 31, 2019 and 2018, the Partnership has not recorded any natural gas imbalances.

Property and Equipment

The Partnership 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 Partnership 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 typically 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 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 balance sheet. The Partnership 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. No impairment expense was recognized for the years ended December 31, 2019 and 2018.

Fair Value of Financial Instruments

The Partnership’s consolidated financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities. The carrying amounts of these accounts are representative of their respective fair values due to the short-term nature of these instruments. The fair value of the Partnership’s debt with affiliate can’t be reasonably estimated due to the related party nature.

Investment in Unconsolidated Entity

The Partnership’s investment consists of an investment in Castex LaFourche, LP (“Castex LaFourche”), an affiliated entity, of 0.525%. The investment is accounted for under the cost method as the Partnership has no influence.

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CASTEX ENERGY 2016, LP AND SUBSIDIARY

Notes to Consolidated Financial Statements

Income Taxes

The Partnership is not a taxpaying entity. No provision for federal income taxes has been made for the Partnership as these taxes are the responsibility of the individual partners.

A margin tax applies to legal entities conducting business in Texas, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The margin tax is based on the Partnership’s Texas sourced taxable margin. The tax is calculated by applying a tax rate to a base rate that considers both revenue and expenses and therefore has the characteristics of an income tax. As the Partnership has its primary operations in Southern Louisiana and in Federal waters, the impact of the Texas margin tax is immaterial to the consolidated financial statements.

The Partnership follows FASB Accounting Standards Codification (“ASC”) 740, Income Taxes, for accounting for uncertainty in income taxes. This 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 first 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 fifty percent likely to be realized upon its ultimate settlement. The Partnership had no uncertain tax positions as of December 31, 2019 nor any of the periods presented.

The Partnership records income tax related interest and penalties, if applicable, as a component of the provision for income tax expense. However, there were no amounts recognized relating to interest and penalties in the consolidated statements of operations for the years ended December 31, 2019 and 2018.

None of the Partnership’s federal or state income tax returns are currently under examination by the Internal Revenue Service (“IRS”) or state authorities. However, all periods since inception (March 22, 2016) remain subject to examination by the IRS or the State of Texas.

The Partnership also files a state tax return in Louisiana; however, the resulting income flows through to the partners’ individual state tax return.

Asset Retirement Obligations

The Partnership 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 Partnership will record an adjustment to the full-cost pool.

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CASTEX ENERGY 2016, LP AND SUBSIDIARY

Notes to Consolidated Financial Statements

Concentration of Credit Risk

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

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

The Partnership’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 natural gas industry.

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

Subsequent Events

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

On February 28, 2020, the Partnership 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 Dorado Deep.

On January 30, 2019, the Partnership, through its wholly-owned subsidiary Dorado Deep, acquired a group of oil and natural gas properties in the Gulf of Mexico from Castex Energy 2014, LLC, a related party, in exchange for Dorado Deep assuming the i) lease abandonment obligations, ii) providing performance and umbrella bonds, and iii) assuming a contingent payment in the sum of $250,000, 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, 2019 no liability has been recorded for the contingent payment as it was not considered probable. The Partnership received cash of $692,860, which was recorded as a reduction in the full cost pool as it was treated as an asset acquisition.

Capitalized costs related to the Partnership’s oil and natural gas producing activities and the related amounts of accumulated depreciation, depletion, and amortization as of December 31, 2019 and 2018 are as follows:

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Notes to Consolidated Financial Statements

On June 1, 2018, the Partnership entered into a promissory note with Castex Management Partners, LP (“CMP”), an affiliated party, in the amount of $500,000. The note bears interest at a rate of 7% based on a 365 day year, to be paid monthly no later than the first day of the month. Principal, along with interest accrued, is due on or before June 1, 2020.

On August 1, 2018, the Partnership entered into a second promissory note with CMP in the amount of $400,000. The note carries the same interest terms as the first promissory note, but matures on August 1, 2020. Interest expense of $67,203 and $29,631 is recorded in the consolidated statements of operations in 2019 and 2018, respectively.

The details of asset retirement obligations are as follows:

The Partnership pays management fees to Castex Energy, Inc. (“CEI”), an affiliate. For the years ended December 31, 2019 and 2018, the management fees were $250,000 and $250,000, respectively. The Partnership capitalized $57,600 during the twelve months ended December 31, 2019 of this overhead to unproved properties. No overhead was capitalized during the year ended December 31, 2018. Management fees net of capitalized amounts are included in general and administrative expenses on the consolidated statements of operations.

At December 31, 2019 CEI was due $995,413 which comprises of $353.335 revenues receivable and $1,348,748 joint interest billings associated with prior two months. At December 31, 2018, CEI was due $1,008,582 from the Partnership which comprises of $461,904 revenues receivable and $1,470,486 joint interest billings for November and December.

At December 31, 2019, Castex Offshore Inc. (“COI”), a related party, was due $245,319 which comprises of $287,697 in revenues receivable and $533,016 of joint interest billings associated with prior two months. At December 31, 2018, COI was due $174,530 which comprises of $35,477 in revenues receivable and $210,007 joint interest billings for November and December.

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

The Partnership also has a note payable with CMP, an affiliated party, and interest expense related to this note. See Note 5.

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CASTEX ENERGY 2016, LP AND SUBSIDIARY

Notes to Consolidated Financial Statements

The Partnership 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 Partnership’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.

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 Partnership-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, the Partnership recorded a total of $3,859,851 and $35,506, respectively, in additions to asset retirement obligations measured at fair value.

The Partnership 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.

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 Partnership may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. The Partnership 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 Partnership’s consolidated financial statements.

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Notes to Consolidated Financial Statements

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.

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 Partnership 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 Partnership’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 Partnership’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 of our fields.

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Notes to Consolidated Financial Statements

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 Partnership’s reserve estimates are inherently imprecise.

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

For the year ended December 31, 2019, the Partnership had upward revisions of previous estimates of 194 Mboe. These revisions are primarily the result of better well performance from new wells that exceeded previous estimates. During the period in 2019, the Partnership purchased reserves of 276 Mboe.

For the year ended December 31, 2018, the Partnership had upward revisions of previous estimates of 14 Mboe. These revisions are primarily the result of better well performance from new wells that exceeded previous estimates. As a result of ongoing drilling and completion activities during the period in 2018, the Partnership reported extensions, discoveries, and other additions of 172 Mboe. Additionally, during the period in 2018, the Partnership purchased reserves of 68 Mboe.

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Notes to Consolidated Financial Statements

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

The Partnership 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.

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 Partnership’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 Partnership 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 Partnership’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 Partnership’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 Partnership 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 Partnership’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 Partnership’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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