Exhibit 99.4

Financial Statements

As of December 31, 2014

and For the Year Then Ended

DOUBLE EAGLE ENERGY PERMIAN LLC

INDEX TO THE FINANCIAL STATEMENTS

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INDEPENDENT AUDITOR’S REPORT

The Members

Double Eagle Energy Permian LLC

We have audited the accompanying financial statements of Double Eagle Energy Permian LLC, which comprise the balance sheet as of December 31, 2014, and the related statements of operations, changes in members’ equity, and cash flows for the year then ended, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these 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 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 financial statements based on our audit. We conducted our audit 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 financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the 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 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 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 financial statements referred to above present fairly, in all material respects, the financial position of Double Eagle Energy Permian, LLC as of December 31, 2014, and the results of its operations and its cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America.

Change in Reporting Entity

As discussed in Note 1 to the financial statements, the 2014 financial statements reflect retrospective application related to the change in reporting entity. Our opinion is not modified with respect to this matter.

WEAVER AND TIDWELL L.L.P.

Fort Worth, Texas

February 4, 2017

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Double Eagle Energy Permian LLC

Balance Sheet at

December 31, 2014

The accompanying notes are an integral part of these financial statements.

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Double Eagle Energy Permian LLC

Statement of Operations

For the Year Ended December 31, 2014

The accompanying notes are an integral part of these financial statements.

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Double Eagle Energy Permian LLC

Statement of Changes in Members’ Equity

For the Year Ended December 31, 2014

The accompanying notes are an integral part of these financial statements.

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Double Eagle Energy Permian LLC

Statement of Cash Flows

For the Year Ended December 31, 2014

The accompanying notes are an integral part of these financial statements.

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Double Eagle Energy Permian LLC

Notes to the Financial Statements

Description of the business and formation

Double Eagle Energy Permian LLC’s (the “Company,” “DEEP,” “we,” “our,” “us”), a Delaware limited liability company, was formed on September 29, 2016 (date of inception) through the conveyance of a predecessor entity, a wholly-owned subsidiary of Double Eagle Energy Operating II LLC, and additional contributed capital. See further discussion on formation and conveyance of the Company in Note 3 – Conveyance of Entities under Common Control. The Company’s principal business is crude oil and natural gas exploration, development and production with operations in the Midland Basin of West Texas in the United States. We are an independent energy company engaged in the acquisition, exploration, development and production of crude oil and natural gas properties. Currently, our strategy is to be an operator in the Midland Basin with a focus on horizontal drilling. However, for the year ended December 31, 2014, our strategy was to participate in non-operated working interests in wells and drilling projects within designated areas of operation through the acquisition of leasehold interests.

On September 29, 2016, the Company was formed by contributions from Double Eagle Energy Holdco LLC (“DEEH”), a newly formed parent of Double Eagle Energy Operating II LLC (the “Parent,” “DE”), of its wholly-owned subsidiary, Double Eagle Lone Star LLC (“Lone Star”) and a third party, Veritas Energy Partners Holdings, LLC (“Veritas”), of its wholly owned subsidiary, Veritas Energy Partners, LLC (“Veritas Sub”). DEEH and DE are also wholly owned subsidiaries of Double Eagle Energy Holdings II LLC (“DEEH II”), where all the board decisions and assets relating to Lone Star were historically managed.

Following the contribution of assets, DEEH held approximately 70% of DEEP’s equity, with Veritas holding the remaining 30%. The transactions between DEEH, DE, Lone Star and DEEH II were treated as a reorganization of entities under common control (as defined by U.S. GAAP), while Veritas’ contribution was treated as an acquisition of Veritas by DEEP. The financial statements included herein and associated notes and operations reflect the change in reporting entity and therefore are presented as if the Company existed and owned the assets since their acquisitions by the Parent. Lone Star was conveyed and recorded by the Company at DE’s respective historical carrying amounts. Certain amounts recorded and presented by the Parent that had not previously been allocated to the Company have been allocated to the Company to fairly present the financial results of the Company on a standalone basis. These allocations were performed utilizing systematic methods based on the operations of Lone Star, as explained below.

For the year ended December 31, 2014, the balance sheet includes all specific oil and gas assets, current assets, current liabilities and asset retirement obligations of Lone Star, and those assets that were specifically tracked within the entity. In addition to the specific assets of Lone Star, management allocated income statement and balance sheet items accounted for, by the Parent. These allocations were based on a ratio of oil and gas assets at Lone Star to the total oil and gas assets of the Parent. Management deemed this allocation method appropriate given the capital intensive nature of its business, and the correlation of the capital expenditures to the reserve-based borrowing facility. Accounts payable balances held by the Parent specifically associated with the Company, related to general and administrative expenses as noted below, were allocated from the Parent based on specific identification of payables related to the Company.

The statement of operations for the year ended December 31, 2014 also includes allocations for certain general and administrative expenses incurred by the Parent on behalf of the Company. The allocation method selected by management was based on the ratio of oil and gas assets held by Lone Star to the total oil and gas of the Parent; DEEP’s allocation based on oil and gas assets was 54.78%. No revenue was allocated to the Company, from the Parent or otherwise. All other costs and expenses were tracked at the individual asset level, and no allocations were necessary.

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Basis of Presentation – The accompanying financial statements and related notes present the balance sheet as of December 31, 2014, and the statement of operations, changes in members’ equity and cash flows for the year ended December 31, 2014. All intracompany transactions occurring between the Company and related entities have been eliminated. Certain transactions between the Company and DEEH, as well as DE, together referred to collectively as the Parent, have been included in these financial statement and are considered to be effectively settled at the time each transaction is recorded. The total net effect of the settlement of these transactions is reflected in the statement of members’ equity and Parent company net investment as net transfers (to)/from Parent, in the statement of cash flows as a financing activity and in the Company’s balance sheet as Parent company net investment. Unless otherwise stated, all amounts contained within the financial statement and accompanying notes are the responsibility of the Company, either as they were incurred by the Company through normal operations or were allocated to the Company from the Parent. As discussed in Note 3 – Conveyance of Entities under Common Control, the operations of the predecessor entity have been included from January 1, 2014.

The accompanying financial statements were prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). Our financial statements include the accounts of the Company.

The Company’s financial statements include allocations of certain historically incurred amounts at DEEH and DE, including equity-based compensation and other general and administrative expenses incurred by the Parent on behalf of its wholly owned subsidiaries, of which the Company is included.

Use of Estimates – The preparation of financial statements under GAAP 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. Estimates and judgments are based on information available at the time such estimates and judgments are made. Although management believes the estimates are appropriate, actual results may differ from those estimates.

The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, estimates relating to certain oil and natural gas revenues and expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates.

Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depreciation, depletion and amortization (“DD&A”) expense, abandonment costs, and impairment expense.

Cash and Cash Equivalents – As of December 31, 2014, we consider all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash or cash equivalents. Cash equivalents consist of cash in a short-term money market account.

Accounts Receivable – Accounts receivable are carried on a gross basis, with no discounting. The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual customer balances. As the Company has not experienced any credit losses, no allowance for doubtful accounts was recorded as of December 31, 2014.

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Advances to Operators – The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Currently, the majority of the wells in which the Company participates are operated by unrelated third parties. Due to the capital intensive nature of crude oil and natural gas drilling activities, the operator of the well may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by the operator against future development costs.

Oil and gas properties – The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred.

The capitalized costs of proved properties are depleted using the unit-of-production method based on proved developed or total proved reserves, as applicable. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited to the net book value of the amortization group, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.

The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In these circumstances, the Company recognizes an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Estimating future cash flows involves the use of judgments, including estimation of the proved and unproved oil and gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. We consider the inputs utilized in determining the fair value related to the impairment of long-lives assets to be Level 3 measurements in the fair value hierarchy. Since 2014, the Company has not realized any impairments of its proved properties.

Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment loss at that time. As of December 31, 2014, the Company had not realized any impairments of its unproved property. However, for the year ended December 31, 2014, the Company recognized approximately $346,000, related to costs for a prospect area that was abandoned without acquiring any oil and gas properties, which are included in abandonment and dry hole costs on the statement of operations.

The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. For the year ended December 31, 2014, the Company has not capitalized any interest as projects generally lasted less than six months.

Asset Retirement Obligations – Asset retirement obligations relate to future costs associated with the plugging and abandonment of crude oil and natural gas wells, removal of equipment and facilities from leased acreage and returning the land to its original condition. Estimates are based on estimated remaining lives of those wells based on reserve estimates, external estimates to plug and abandon the wells in the future, inflation, credit adjusted discount rates and federal and state regulatory requirements. We record the fair value of a liability for an asset retirement

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obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Accretion expense is included in “Depreciation, depletion and amortization” on our statements of operations.

The estimated fair value of the Company’s asset retirement obligations at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy.

Deferred Financing Costs – Deferred financing costs include origination, legal and other fees to obtain or issue debt. These costs are deferred and reported on the balance sheet at cost, net of amortization. Total deferred financing costs are amortized on a straight line basis, which approximates the effective interest method, to interest expense over the term of the associated debt. The Company did not have any outstanding debt at the end of 2014.

Revenue Recognition – The Company recognizes crude oil, natural gas and natural gas liquids (“NGLs”) revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for natural gas balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of December 31, 2014, the Company’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest was materially consistent with its entitled interests in natural gas production from wells.

Concentrations of Credit Risk – As of December 31, 2014, the Company’s primary market consists of operations in the Midland Basin of West Texas in the United States. The Company has concentration of oil and gas production revenues and receivables due from the operators of wells in which we hold non-operated working interests. Our exposure to non-payment or non-performance by the operators, our customers and counterparties presents a credit risk. Generally, non-payment or nonperformance results from a customer’s or counterparty’s inability to satisfy obligations. We monitor the creditworthiness of our customers and counterparties and established credit limits according to our credit policies and guidelines, but cannot assure that any losses will be consistent with our expectations.

Furthermore, the concentration of our customers in the energy industry may impact our overall exposure to credit risk as customers may be similarly affected by prolonged changes in economic and industry conditions. The Company actively pursues to invest in non-operated wells with financially stable and experienced operators in the respective areas of exploration, development and production.

For the year ended December 31, 2014, the following third-party operators of properties the Company has interest in accounted for a significant portion of total revenue:

Equity-Based Compensation – Prior to the formation and inception of DEEP, the Parent had issued its own Series B Units (the “Parent Incentive Units”) to certain employees of the Parent. The expense associated with the Parent Incentive Unit’s recorded at the Parent has been allocated to the Company and included in general and administrative expense in the accompanying statement of operations. See further discussion regarding the Parent’s B Units and the allocated $82,000 of expense in Note 5 – Member’s Equity and Equity-Based Compensation.

Fair Value Hierarchy – Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants at the reporting date. The Company’s assets and

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liabilities that are measured at fair value at each reporting date are classified according to a hierarchy that prioritizes inputs and assumptions underlying the valuation techniques. This fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs, and consists of three broad levels:

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Recently Issued Accounting Standards

Leases. In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842), which revises the accounting for leases by requiring certain leases to be recognized as assets and liabilities in the balance sheet, and requiring companies to disclose additional information about their leasing arrangements. We expect to adopt the provisions of this standard effective January 1, 2019. The Company is currently evaluating the new guidance and has not determined the impact, if any, this standard may have on our financial statements.

Revenue recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2014, the FASB issued Accounting Standards Update No. 2014-14, Deferral of the Effective Date (“ASU 2014-14”). ASU 2014-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. The Company is currently evaluating the method of adoption as well as the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Going concern. In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 codifies in GAAP management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual reporting period ending after December 15, 2016 and for annual periods and interim periods thereafter. The Company adopted this guidance in fiscal year 2016.

Income Taxes. In November 2014, FASB issued ASU 2014-17, Income Taxes (“ASU 2014-17”). ASU 2014-17 simplifies the presentation of deferred income taxes and requires deferred tax assets and liabilities be classified as noncurrent in the balance sheet. The amendments in this ASU are effective for fiscal years beginning after

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December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or prospectively. As the Company is only subject to the Texas Margin Tax, as discussed in Note 7 – Income Taxes, the Company is currently evaluating the new guidance and has not determined the impact, if any, this standard may have on our financial statements.

Imputation of Interest. In April 2014, FASB issued ASU 2014-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2014-03”). ASU 2014-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction of the carrying amount of that debt in the balance sheet, consistent with the presentation of debt discounts. The amendments in this ASU are effective for fiscal years beginning after December 15, 2014, and interim periods within those fiscal years, and early adoption is permitted. Entities will be required to apply the guidance on a retrospective basis to each period presented as a change in accounting principle. In August 2014, the FASB issued ASU 2014-15, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2014-15”) which amends ASU 2014-03 to clarify the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements, such that entities may continue to apply current practice. The Company adopted this guidance in fiscal year 2016.

On November 12, 2014, the Parent was formed pursuant to a Master Reorganization Agreement whereas certain subsidiaries, including a predecessor entity which formed the Company, from Double Eagle Holdings, which is also owned by the private equity financial sponsor (the “PE Sponsor”) and the certain members of the Company’s management (“Management Group”), were conveyed to the Parent. In exchange for the subsidiaries conveyed, Series A Units of the Parent were issued to the PE Sponsor, the Management Group and other employees which had profit interests in Double Energy Holdings.

In addition to the subsidiaries conveyed, capital contributions from the PE Sponsor and the Management Group were contributed at inception to form the Parent. The conveyance constituted a transaction between entities under common control (as defined by GAAP), whereas the operations of a predecessor entity are presented as if the Company existed and owned the assets since their initial acquisition. The assets and obligations were conveyed and recorded by the Company at the predecessor entity’s respective carrying amounts.

The carrying amount of the Company’s ARO on the Company’s balance sheet at December 31, 2014 was approximately $6,800. At the inception of drilling activities, the Company determines the ARO by calculating the present value of estimated future cash flows related to the liability if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

The following table provides a reconciliation of the changes in the asset retirement obligations generally associated with future costs associated with the plugging and abandonment of crude oil and natural gas wells, removal of equipment and facilities from leased acreage and returning the land to its original condition for the period indicated:

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As of December 31, 2014, no assets are legally restricted for use in settling asset retirement obligations, and all obligations are classified as long-term in the balance sheet as we do not expect to incur any of these charges within the next year.

On November 12, 2014, the Parent entered into a limited liability company agreement (“LLC Agreement”) with its Management Group and the PE Sponsor with an initial capital commitment of $165.0 million. The Parent was formed with a conveyance of subsidiaries from Double Eagle Holdings and cash contributions from the PE Sponsor and the Management Group. Certain employees of Double Eagle Holdings (“Other Management Members”) who held profit interests were distributed Series A Units in the Parent which constituted their respective distributed value of the assets transferred. The Other Management Members that obtained Series A Units in the Parent through their profit interest in Double Eagle Holdings will not participate in future contributions.

As of December 31, 2014, the PE Sponsor and the Management Group have contributed $33.0 million to the Parent for Permian asset operations. As of December 31, 2014, DEEO II had remaining capital commitments of $132.0 million from the PE Sponsor and the Management Group.

Prior to the formation and inception of DEEP on September 29, 2016, the Parent had issued Series B Units (the “Parent Incentive Units”) to certain employees of the Parent. As of December 31, 2014, the Parent had issued 875 Series B Units of which 859 were unvested. The weighted average grant date fair value per Series B Unit is $10,300. These Parent Incentive Units are tied to certain performance metrics and return hurdles of the Parent and its wholly owned subsidiaries including, but not limited to, DEEP. Eighty percent of the Parent Incentive Units vest monthly over a four-year period, with the remaining twenty percent only vesting upon a liquidity event, as defined in the Parent’s Limited Liability Company Agreement. The Parent accounts for these units as equity awards in accordance with ASC 718 and records expense related to these awards based on the grant date fair value of the awards. These units are unrelated to the ownership of DEEP. The financial obligation or payout requirements of the Parent Incentive Units belongs to the Parent.

As the employees who were awarded Parent Incentive Units provided services to the assets associated with the Company during 2014, a portion of the cost associated with the Parent Incentive Units has been allocated to the Company, as discussed below.

For the year ending December 31, 2014, approximately $82,000 of the expense associated with the Parent Incentive Unit’s recorded at the Parent has been allocated to the Company and included in general and administrative expense in the accompanying statement of operations. The expense was allocated during the year based on the allocation of total capitalized oil and gas properties between Lone Star and Rockies at the end of the year. This methodology is consistent with the treatment of other statement of operation items from the Parent that were identified to be allocated to the Company for standalone presentation. The offset to the allocated expense will be included in Parent Company Net Investment, a members’ equity account of the Parent reflecting their invested balance in the Company.

In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The book value of the Company’s current assets and liabilities approximate their fair value due to the short-term nature of the instruments. The Company recognizes its non-financial assets and liabilities, such as ARO and proved oil and natural gas properties upon impairment, at fair value on a non-recurring basis. See Note 4 – Asset Retirement Obligations for further discussion.

Income Taxes – The Company is not subject to federal or state income taxes, except as noted below, as we are organized as a partnership for income tax purposes and the results of operations are taxable directly to the members. Accordingly, each member is responsible for its share of federal and state income tax.

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Texas Margin Tax – The Company is subject to the Texas Margin Tax that requires tax payments at a maximum statutory effective rate of 0.75% on the taxable margin of each taxable entity that does business in Texas. The margin tax qualifies as an income tax under Accounting Standards Codification 740, Income Taxes (FAS 109/FIN 48) (“ASC 740”), which requires us to recognize currently the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax. For the year ended December 31, 2014, the Company has a greater apportionment rate in Texas as well as greater temporary differences between GAAP and taxable income. As such, as of December 31, 2014, the Company recognized a deferred tax liability in the amount of approximately $58,000 related to the Texas Margin Tax which is included in the accompanying balance sheet.

Uncertain Tax Positions – We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing our financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. Tax positions with respect to tax at the partnership level deemed not to meet the more likely than not threshold would be recorded as a tax benefit or expense in the current year. We believe that there are no uncertain tax positions that would impact our operations for the year ended December 31, 2014, and that no provision for income tax is required for these financial statements. However, our conclusions regarding the evaluation are subject to review and may change based on factors including, but not limited to, ongoing analyses of tax laws, regulations and interpretations thereof. With all tax positions meeting the “more likely than not” threshold under ASC 740, the Company determined that there is no current effect on the financial statements from a lapse of the statute of limitations as it relates to unrecognized tax benefits. Additionally, the Company’s tax years 2013 and 2014 remain open for examination. As of December 31, 2014, the Company has no amounts related to accrued interest and penalties.

The PE Sponsor, a leading global alternative investment manager, has a substantial equity investment in us and has three individuals on our Board of Directors, when formed on September 29, 2016. The PE Sponsor’s investment in and relationship with us qualifies them as a related party. The Parent of the Company is party to several agreements with the PE Sponsor.

Transaction Fee

The Parent is party to a Transaction Fee Agreement, dated November 12, 2014 with an affiliate of the PE Sponsor which requires us to pay 1% of the total equity contributed to DEEO II by the PE Sponsor pursuant to a merger or acquisition of equity or assets if such contribution by the PE Sponsor is $25.0 million or greater (“Transaction Fee”). For the year ended December 31, 2014, Parent did not incur any Transaction Fees.

Services Agreement

The Parent is party to an consulting and advisory services agreement(“Services Agreement”) which requires us to compensate the PE Sponsor equal to the greater of (i) 1% of earnings before interest, income taxes, depletion, depreciation, amortization and exploration expense per quarter, and (ii) approximately $34,250 per quarter (the “Consulting Fee”). The Services Agreement also provides for reimbursement to the PE Sponsor for any reasonable out-of-pocket. As of December 31, 2015, approximately $18,700 was allocated to the Company and included in accounts payable to related parties in the accompanying balance sheet. The Consulting Fee to the Company is pro-rated from November 12 to December 31, 2014 combined with the allocation percentage in Note 1 – Basis of Presentation.

Certain members of management and entities owned and controlled by those members of management have certain agreements with the Parent, whereas consideration is paid to those members or their controlled entities for services performed or use of commonly owned assets, as follows:

Shared Services Agreement

The Parent is party to an agreement with a management member’s entity whereas this entity provides certain general and administrative services to Double Eagle Energy Holdings II LLC (“Shared Services Agreement”) for a monthly fee of approximately $14,500 (“Shared Services Expense”). For the year ended December 31, 2014, the

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Parent incurred approximately $23,700 in Shared Services Expense, of which approximately $13,000 was allocated to the Company, which is included in general and administrative expense in the accompanying statement of income. As of December 31, 2014, no expenses related to the Shared Services Agreement were included in accounts payable to related parties in the accompanying balance sheet.

Management Services Agreement

For the year ended December 31, 2014, the Parent billed a total of $379,000 related to the services performed for the related affiliate, of which approximately $207,700 was allocated to the Company and included as an offset to general and administrative expense in the accompanying statement of income. As of December 31, 2014, $379,000 was included in accounts receivable by the Parent, of which approximately $207,700 was allocated to the Company and included as an offset to accounts payable to related parties in the accompanying balance sheet.

Acquisitions / Contributions of oil and gas properties

From time to time, the Company acquires oil and gas properties from other management members’ controlled entities. These transactions are based on the fair value of the assets that are purchased which supports an arms-length transaction between the Company and a related party. In certain instances, the Company reimburses service costs incurred that related to the acquisition of these assets. For the year ended December 31, 2014, the Company paid management members’ controlled entities approximately $547,000 for oil and gas properties and associated service costs.

In addition to cash purchases, management members have the ability to offset cash capital contributions with contributions of oil and gas properties. Other management members’ controlled entities have similar oil and gas operations in the Midland Basin and these entities have been in existence prior to the formation of the Company. During 2014, management identified certain assets that were directly accretive to the asset base of the Company, and thus contributed these properties alongside cash capital calls from the PE Sponsor. The value derived for the contributions were based on applicable comparable market transactions, at fair value, for similar assets in the Midland Basin. During 2014, approximately $422,000 in oil and gas properties were contributed to the Company in exchanged for equity interests.

From time-to-time we are party to certain legal litigation, regulatory or administrative proceedings that arise in the ordinary course and are incidental to our business. As of December 31, 2014, there are no such pending proceedings to which we are party to that our management believes will have a material adverse effect on our results of operations, cash flows or financial condition. However, future events or circumstances, currently unknown to management, will determine whether the resolution of any litigation or claims will ultimately have a material effect on our results of operations, cash flows or financial condition in any future reporting periods.

Casualties and Other Risks – The Company maintains coverage in various insurance programs, which provide us with property damage and other coverage which are customary for the nature and scope of our operations.

The Company believes we have adequate insurance coverage, although insurance will not cover every type of loss that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies could increase significantly, and in certain instances, insurance may become unavailable, or available at reduced coverage.

If we were to incur a significant loss for which we were not adequately insured, the loss could have a material impact on our results of operations, cash flow or financial condition. In addition, the proceeds of any available insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts our revenues, or which causes us to make a significant expenditure not covered by insurance, could reduce our ability to meet future financial obligations.

Commitments – During 2014, the Company entered into an agreement whereas a certain oil and gas lease was assigned to the Company in exchange for five equal annual installment payments of $185,000 to the assignor of the lease. Each annual payment is due by January 15th of the respective year. The Company includes the short term portion of the liability in “Accounts payable and accrued liabilities” and the long term portion in “Deferred lease acquisition costs” in the accompanying balance sheet.

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As of December 31, 2014, the Company had outstanding commitments related to deferred acquisition costs totaling $925,000.

The Company participates in a 401(k) defined contribution plan sponsored by the Parent, for the benefit of all employees at their date of hire. The plan allows eligible employees to contribute a portion of their annual compensation, not to exceed annual limits established by the federal government. The Parent makes matching contribution of up to a certain percentage of an employee’s contributions. For the year ended December 31, 2014, the Company was allocated contributions to the plan of approximately $7,800 from the Parent.

On January 1, 2015, employees of Double Eagle Operating became employed by the Parent. Due to this, the Company entered into a Service Agreement dated January 1, 2015 whereas our employees would provide employment services to Double Eagle Operating for a monthly fee of $15,000. This agreement was not extended and terminated automatically on the second anniversary, January 1, 2017.

On February 1, 2015, Double Eagle renewed their office lease with Double Eagle Offices, LLC, whereas Double Eagle leases office space for general business activity for a period of three years at a monthly rate of $13,200. Double Eagle Offices, LLC is owned and controlled by the Company’s Management Group. Due to the significant influence the Management Group has over both entities, the Company considers Double Eagle Offices, LLC a related party. Rental rates were determined based on comparable rates charged by third parties. The Company leases office buildings under operating leases.

On September 13, 2015, an Election Letter was executed pursuant to Section 5.02(g) of the LLC Agreement whereas the PE Sponsor exercised its right to increase its commitments to the Company through ANRP Double Eagle Holdings II, L.P., an affiliate of the PE Sponsor. The PE Sponsor’s commitment amount is $175.0 million to the Company. In addition on September 13, 2015, the Management Group executed an Election Letter pursuance to Section 5.02(g) of the LLC Agreement whereas the Management Group elected to increase their commitment to the Company in the amount of $39.4 million.

On September 15, 2015, the Company completed the acquisition of approximately 6,100 net acres of producing and non-producing leasehold properties for purchase price of $65.2 million, subject to customary purchase price adjustments. The Company accounted for the acquisition as a business combination in accordance with ASC 805. The transaction included $15.9 million in Proved – Producing reserves. At the time of the acquisition, the properties included 117 producing wells and two wells in development. The Company held non-significant non-operated working interest in the producing wells. The properties were located in Glasscock and Reagan County Texas in the Midland Basin. The Company also incurred $133,801 in asset retirement obligations related to this acquisition. Transaction costs of approximately $45,600 were recognized in “General and administrative” expenses in the accompanying statement of operations for the year ended December 31, 2015.

On April 21, 2016, the Company entered into a Membership Interest Purchase and Sale Agreement (“MIPSA”) with MCM Energy Partners, LLC (“MCM”), whereas the Company acquired eight-five percent (85%) of the membership interest of Novus Land Services, LLC (“Novus”). For the consideration for the sale, assignment, transfer and conveyance of the acquired interest, the Company paid MCM approximately $19.2 million in aggregate, representing 85% of the fair value of the assets and liabilities as of the closing date. The acquisition was concluded to be treated as a business combination per ASC 805, Business Combinations, under the acquisition method as noted in ASC 805-10-05-4. The assets and liabilities held by Novus, as well as the results of its operations will be

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consolidated into the financial statements issued by the Company for all periods subsequent to the acquisition date. The acquisition is expected to comprise less than 5% of the future annual pre-tax income and net assets of the Company.

On February 3, 2017, the Company entered into another MIPSA whereas the Company purchased the remaining fifteen percent (15%) non-controlling interest in Novus Land Services, LLC. The Company paid consideration in the amount of $14.6 million for the 15% ownership. The acquisition will be subject to customary due diligence and post-closing matters.

On September 29, 2016, to align its business operations with management’s revised strategy to become an operator with a focus on horizontal drilling, the Parent entered into an LLC agreement whereas the Parent contributed all of the ownership interests in a wholly owned subsidiary (“Lone Star”) to the Company in exchange for Series A-1 units representing an approximate 70% interest in DEEP. Veritas Energy Partners Holdings, LLC (“Veritas”), a third party, contributed all of the ownership interests of its wholly owned subsidiary, Veritas Energy Partners, LLC (“Veritas Energy”) to DEEP in exchange for Series A-1 units representing an approximate 30% interest in DEEP (the “Veritas Acquisition”). Following the Veritas Acquisition, Veritas Energy ceased to exist as a standalone entity. The assets, liabilities and results of operations of Veritas Energy for the period ended December 31, 2015 are not included in, or otherwise consolidated with, the accompanying financial statements, nor described in the accompanying notes, contained herein. At closing, DEEP recorded the assets and liabilities of Veritas Energy at their respective fair values. The following table summarizes the fair values of assets acquired and liabilities assumed, as of September 29, 2016. The preliminary purchase price allocation is as follows:

The final purchase price allocation is pending the completion of the valuation of the assets and liabilities contributed.

Prior to the Veritas Acquisition, for the period ended September 29, 2016, Veritas Energy generated approximated $700,000 in revenue, which resulted in a $2.5 million loss from operations for the period.

On September 30, 2016, in order to fund the Veritas Acquisition and execute on the Company’s revised business strategy, the Company entered into a credit agreement with JPMorgan Chase Bank, N.A. (“JPMorgan”), with a maximum revolving credit facility of $500.0 million with an initial borrowing base of $60.0 million (“JPM Revolver”). However, the Company’s ability to draw on the JPM Revolver is limited by an Indenture Agreement between the Company and Capital Provider, as discussed below, thereby effectively reducing the borrowing base. The JPM Revolver is secured by liens on substantially all of the Company’s properties and guarantees from the Company’s subsidiaries. The Credit Agreement of the JPM Revolver contains restrictive covenants that may limit our ability to, among other things, issue or incur additional indebtedness, enter into mergers, make investments or enter into hedging contracts. With the issuance of the JPM Revolver, the debt allocated to the Company under the Wells Fargo RBL, entered into by the Parent, was extinguished. The unamortized portion of the related deferred financing fees previously allocated to the company, approximately $187,000, were fully amortized on this date and included in the statement of operations.

Upon execution of the Credit Agreement, we were required to provide evidence satisfactory to the JPMorgan that we had entered into hedge agreements, as defined, covering at least 50% of reasonably anticipated production for each month through December 31, 2017. During the period which the Credit Agreement is in effect, hedged volumes may not exceed 85% of the reasonably anticipated production (based on forecasts from reserve reports acceptable to the Administrative Agent) for any 66 month period from the creation of the most recent Hedging Agreement. The Credit Agreement also specifies the hedge agreements may not be entered into for speculative purposes. Prior to this requirement, the Company had not participated in hedging activities.

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On November 7, 2016, DEEP entered into a Unit Subscription Agreement (the “Subscription Agreement”), with funds affiliated with Capital Provider and related affiliates (“Capital Provider”), to sell units in DEEP, representing approximately 7.5% of DEEP’s equity interests, to Capital Provider for $150 million. The Company amended the LLC Agreement to provide for the issuance of Series C Units, to be awarded by and with the approval of the Board of Directors, to create a new class of Capital Interest Members of the Company. In connection with the equity issued pursuant to the Subscription Agreement, the Capital Provider affiliates are entitled to certain liquidation preferences in the event of a liquidity event or certain asset sales, as defined in the Subscription Agreement

In conjunction with the Unit Subscription Agreement with Capital Provider, 73,876,046 of Series C Units in DEEP, representing approximately 7.5% of DEEP’s equity interests, were sold to Capital Provider for $150 million. The Series C Units entitle holders to participate in the net profits of the Company; however, holders of Series C Units do not possess voting rights or the right to consent or approve any action or matter. In the event of a liquidation of the Company, Capital Provider’s Series C Units entitle them to a preferred return, contingent on presence of certain facts. Upon the closing of the Subscription Agreement, the equity interests in DEEP held by DEEH, Veritas and Capital Provider were approximately 64.75%, 27.75% and 7.5%, respectively.

In addition to the Company’s equity offering to Capital Provider, on November 7, 2016 DEEP and Capital Provider also entered into a Senior Notes Purchase Agreement whereby DEEP may issue and sell to Capital Provider up to $300.0 million in 8.75% senior unsecured notes, due in 2022 (the “Capital Provider Notes”). The Capital Provider Notes may be issued between November 7, 2016 and December 31, 2017 (the “Commitment Period”) in series of not less than $100.0 million per issue. Borrowings, pursuant to draw down requests as defined in the Senior Note Purchase Agreement, may not be less than $100.0 million and are subject to a 1% original issue discount (“OID”), and are limited by debt covenants and an Indenture Agreement also imposing restrictions on the Company’s ability to borrow additional debt. The Capital Provider Notes are also subject to a contingent commitment fee, payable in cash, equal to the lesser of $12 million or 4.00% of any of the unfunded $300.0 million commitment that is not issued by the end of the Commitment Period. As of February 4, 2017, no amounts were drawn on the Capital Provider Notes, however no contingency was recognized for the Capital Provider Notes contingency, as the probability of incurring the cost could not be determined by Management.

We have evaluated subsequent events through February 4, 2017, the date the financial statements were available to be issued.

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DOUBLE EAGLE ENERGY PERMIAN LLC

Supplemental Information

(Unaudited)

The reserve estimates at December 31, 2014 presented in the tables below are based on reports prepared by Cawley, Gillespie & Associates, Inc., the Company’s independent reserve engineers, in accordance with the SEC rules on oil and gas reserve estimation and disclosures. In accordance with SEC requirements, the pricing used by the Company is based on the 12-month unweighted arithmetic average of the first-day-of-the-month spot price for the period January through December and adjusted by lease for quality, transportation, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The use of SEC pricing rules may not be indicative of actual prices realized by the Company in the future. The commodity prices, based on SEC pricing and inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation, are as follows:

During 2014, all of the Company’s oil and natural gas producing activities were conducted within the state of Texas.

Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves, the projection of future production rates and the timing of future development expenditures. 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 natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Proved oil and natural gas reserves are the estimated quantities of oil and 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 (i.e., prices and costs) 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.

Estimated Quantities of Proved Oil and Natural Gas Reserves

The following table sets forth the Company’s estimated net proved, proved developed and proved undeveloped reserves at December 31, 2014:

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

The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of our oil and natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.

The Company’s estimated net proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, which are held constant throughout the life of the properties. Future operating costs, production taxes and development costs were based on current costs as of each year-end.

The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net proved oil and natural gas reserves:

Future net cash flows do not include the effects of U.S. federal income taxes on future results because the Company is a limited liability company not subject to entity-level federal income taxes. Accordingly, no provision for federal corporate income taxes has been provided because taxable income was passed through to the Company’s equity holders. However, the Company’s operations are located in Texas are subject to an entity-level tax, the Texas Margin Tax, at a statutory rate of up to 0.75% of income that is apportioned to Texas.

The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved reserves for the periods presented:

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