Exhibit 99.4

PART I-FINANCIAL INFORMATION

MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

(Unaudited)

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

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MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(In thousands, except per share data)

(Unaudited)

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

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MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

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MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

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MONTAGE RESOURCES CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1-Organization and Nature of Operations

Montage Resources Corporation (the “Company”) is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale, Indian Castle/Flat Creek Shales and Marcellus Shale prospective areas.

Note 2-Basis of Presentation

The accompanying Condensed Consolidated Financial Statements are unaudited except the Consolidated Balance Sheet at December 31, 2019, which is derived from the Company’s audited financial statements, and are presented in accordance with the requirements of accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made and contained in annual financial statements. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. All such adjustments are of a normal recurring nature. These interim Condensed Consolidated Financial Statements should be read in conjunction with the audited Consolidated Financial Statements, and the notes to those statements, which are included in the Company’s Annual Report on Form 10-K, filed with the SEC on March 10, 2020.

Operating results for interim periods may not necessarily be indicative of the results of operations for the full year ending December 31, 2020 or any other future periods, due to fluctuations in demand and the prices received for natural gas, NGLs and oil, the impacts of the COVID-19 pandemic, and other factors.

Preparation in accordance with U.S. GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3-Summary of Significant Accounting Policies describes our significant accounting policies. The Company’s management believes the major estimates and assumptions impacting the Condensed Consolidated Financial Statements are the following:

Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions.

Note 3-Summary of Significant Accounting Policies

(a) Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

(b) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the counterparty. The Company had no significant accounts receivables determined to be uncollectible as of June 30, 2020 or December 31, 2019.

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The Company accrues revenue due to timing differences between the delivery of natural gas, NGLs, and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales prices and transportation and compression fees.

(c) Property and Equipment

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion, amortization and accretion expense (see “Depreciation, Depletion, Amortization and Accretion” below).

Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s Condensed Consolidated Balance Sheets. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

A summary of property and equipment including oil and natural gas properties is as follows (in thousands):

Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, and not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves.

Other Property and Equipment

Other property and equipment includes land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition.

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(d) Revenue Recognition

Product Revenue

The Company’s revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from the natural gas. Sales of natural gas, NGLs, and oil are recognized when the Company satisfies a performance obligation by transferring control of a product to a customer. Payment is generally received one month after the sale has occurred.

Natural Gas

Under the Company’s natural gas sales contracts, the Company delivers natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from the wellhead to delivery points specified under sales contracts. To deliver natural gas to these points, the Company uses third parties to gather, compress, process and transport the natural gas. The Company maintains control of the natural gas during gathering, compression, processing, and transportation. The Company’s sales contracts provide that it receives a specific index price adjusted for pricing differentials. The Company transfers control of the product at the delivery point and recognizes revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as transportation, gathering and compression expense.

NGLs

The Company sells NGLs directly to the NGLs purchaser. For these NGLs, the sales contracts provide that the Company deliver the product to the purchaser at an agreed upon delivery point and that the Company receives a specific index price adjusted for pricing differentials and certain downstream costs incurred by third parties. The Company transfers control of the product to the purchaser at the delivery point and recognizes revenue based on the contract price. The costs to process and transport NGLs prior to the delivery point are recorded as transportation, gathering and compression expense.

Oil

Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser from storage tanks at central stabilization facilities and well pads and collects a contractually agreed upon index price, net of pricing differentials and certain costs incurred by third parties. The Company transfers control of the product from the central stabilization facilities and well pads to the purchaser and recognizes revenue based on the contract price.

Marketing Revenue

Brokered natural gas and marketing revenues are derived from activities to purchase and sell third-party natural gas and to market excess firm transportation capacity to third parties. The Company retains control of the purchased natural gas prior to delivery to the purchaser. The Company has concluded that it is the principal in these arrangements and therefore the Company recognizes revenue on a gross basis, with costs to purchase and transport natural gas presented as brokered natural gas and marketing expense. Contracts to sell third-party natural gas are generally subject to similar terms as contracts to sell the Company’s produced natural gas. The Company satisfies performance obligations to the purchaser by transferring control of the product at the delivery point and recognizes revenue based on the price received from the purchaser.

Disaggregation of Revenue

The following table illustrates the revenue disaggregated by type for the three and six months ended June 30, 2020 and 2019:

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Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient allowed in the revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligations are part of a contract that has an original expected duration of one year or less.

For any product sales that have a contract term greater than one year, the Company has also utilized the practical expedient that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, any product sales that have a contractual term greater than one year have no long-term fixed considerations.

Contract Balances

Under the Company’s sales contracts, customers are invoiced once performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to the Company’s revenue contracts with customers was $47.7 million and $63.7 million as of June 30, 2020 and December 31, 2019, respectively.

(e) Concentration of Credit Risk

The Company’s principal exposures to credit risk are through the sale of its oil and natural gas production and related products and services, joint interest owner receivables and receivables resulting from derivative contracts. The inability or failure of the Company’s significant customers or counterparties to meet their obligations or their insolvency or liquidation may adversely affect the Company’s financial results. The following table summarizes the Company’s concentration of receivables, net of allowances (if any), by product or service as of June 30, 2020 and December 31, 2019 (in thousands):

Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the States of Ohio, Pennsylvania and West Virginia. As a general policy, collateral is not required for receivables, but customers’ financial condition and creditworthiness are evaluated regularly.

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to the credit risk of the counterparties to these derivative instruments. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, the Company’s policy is to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. Such counterparties are not required to provide credit support to the Company. The fair value of the Company’s unsettled derivative contracts was a net asset position of $11.9 million and $27.1 million as of June 30, 2020 and December 31, 2019, respectively. Other than as provided by its revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s derivative contracts. As of June 30, 2020 and December 31, 2019, the Company did not have past-due receivables from or payables to any of such counterparties.

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(f) Depreciation, Depletion, Amortization and Accretion

Oil and Natural Gas Properties

Depreciation, depletion, amortization and accretion (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties, including accretion expense, totaled approximately $42.4 million and $38.0 million for the three months ended June 30, 2020 and 2019, respectively, and $86.1 million and $67.5 million for the six months ended June 30, 2020 and 2019, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from five to 40 years. Depreciation totaled approximately $0.4 million and $0.6 million for the three months ended June 30, 2020 and 2019, respectively, and $0.8 million and $1.0 million for the six months ended June 30, 2020 and 2019, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

(g) Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review for impairment of the Company’s oil and gas properties is performed by determining whether the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. There were no impairments of proved properties held and used for the three months ended June 30, 2020 and 2019 or for the six months ended June 30, 2020 and 2019. The Company recorded impairment of proved properties held for sale during the six months ended June 30, 2020. See Note 5- Assets Held for Sale and Discontinued Operations.

When an impairment charge is recognized it represents a significant Level 3 measurement in the fair value hierarchy. The primary input used is the

Company’s forecasted discount net cash flows.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of approximately $8.6 million and $12.4 million for the three months ended June 30, 2020 and 2019, respectively, and $19.4 million and $22.0 million for the six months ended June 30, 2020 and 2019, respectively. These costs are included in exploration expense in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

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(h) Income Taxes

The Company accounts for income taxes under the liability method as set out in the FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes.” Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

ASC Topic 740 further provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not (i.e., a likelihood greater than 50 percent) that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date.

The Company applies ASC Topic 740’s intra-period income tax allocation rules using the with and without approach, to allocate income tax expense (benefit) among continuing operations, discontinued operations, other comprehensive income (loss), and additional paid-in capital as required.

(i) Fair Value of Financial Instruments

The Company has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1-Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2-Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

Level 3-Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

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.

(j) Derivative Financial Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells and to manage its exposure to interest rate volatility.

Derivatives are recorded at fair value and are included on the Condensed Consolidated Balance Sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty and type in the accompanying Condensed Consolidated Balance Sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities.

The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy.

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(k) Asset Retirement Obligation

The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with ASC Topic 410, “Asset Retirement and Environmental Obligations,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate.

Estimating the future ARO requires management to make estimates and judgments based on historical information regarding timing and existence of a liability, as well as what constitutes adequate restoration. 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. 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.

Approximately $2.5 million and $2.0 million, representing the current portion of ARO liability, are included in “Accrued liabilities” in the accompanying Condensed Consolidated Balance Sheets as of June 30, 2020 and December 31, 2019, respectively. The following table sets forth the changes in the Company’s ARO liability for the six months ended June 30, 2020 (in thousands):

The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement.

(l) Off-Balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements.

(m) Segment Reporting

The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

(n) Debt Issuance Costs

The expenditures related to issuing debt, such as the Company’s 8.875% senior unsecured notes, are capitalized and reported as a reduction of the Company’s debt balance in the accompanying Condensed Consolidated Balance Sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. Expenditures related to the Company’s revolving credit facility are capitalized and included in “Other assets” in the accompanying Condensed Consolidated Balance Sheets and are amortized over the term of the revolving credit facility. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.

During the three and six months ended June 30, 2020, the Company amortized $1.1 million and $2.1 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method which includes $0.2 million of unamortized deferred financing costs that the Company wrote off during the second quarter of 2020 in connection with the borrowing base redetermination of the Company’s revolving credit facility (See Note 8- Debt). During the three and six months ended June 30, 2019, the Company amortized $0.9 million and $1.9 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method.

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(o) Recent Accounting Pronouncements

Accounting Pronouncements Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments—Credit Losses: Measurement of Credit Losses on Financial Instruments”, and subsequently, the FASB issued several related ASUs to clarify the application of the credit loss standard. Among other things, these amendments require the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables and any other financial assets not excluded from its scope that have a contractual right to receive cash. The amendments are effective for smaller reporting companies for fiscal years and interim periods within the fiscal years beginning after December 15, 2022. Early adoption is permitted. The Company is assessing the impact, if any, this guidance may have on our consolidated results of operations, financial position and financial disclosures, but does not currently anticipate a material impact.

Note 4-Acquisitions

Merger with Blue Ridge Mountain Resources

On February 28, 2019, the Company completed its business combination transaction with Blue Ridge Mountain Resources, Inc. (“BRMR”) pursuant to that certain Agreement and Plan of Merger, dated as of August 25, 2018 and amended as of January 7, 2019 (the “Merger Agreement”), by and among the Company, Everest Merger Sub Inc. (“Merger Sub”), a Delaware corporation and a wholly owned subsidiary of the Company, and BRMR. Pursuant to the Merger Agreement, Merger Sub merged with and into BRMR with BRMR continuing as the surviving corporation and a wholly owned subsidiary of the Company (the “BRMR Merger”).

As a result of the BRMR Merger, each share of common stock, par value $0.01 per share, of BRMR issued and outstanding immediately prior to the effective time of the BRMR Merger, excluding certain Excluded Shares (as such term is defined in the Merger Agreement), was converted into the right to receive from the Company 0.29506 of a validly issued, fully-paid, and nonassessable share of common stock, par value $0.01 per share, of the Company. The exchange ratio reflects an adjustment to account for the 15-to-1 reverse stock split (See Note 11- Net Income (Loss) Per Share). Former stockholders of BRMR received cash for any fractional shares of the Company’s common stock to which they might otherwise have been entitled as a result of the BRMR Merger. In addition, upon completion of the BRMR Merger, all shares of BRMR restricted stock and all BRMR restricted stock units and performance interest awards were converted into the right to receive shares of common stock of the Company or cash, in each case as specified in the Merger Agreement.

In connection with the BRMR Merger, the Company incurred less than $0.1 million and $3.9 million of costs for the three months ended June 30, 2020 and 2019, respectively, and $0.2 million and $18.5 million for the six months ended June 30, 2020 and 2019, respectively, which are included in general and administrative expense on the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). Approximately $66.5 million of revenues and approximately $19.1 million of net income from continuing operations attributed to the BRMR Merger are included in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to June 30, 2019. Approximately $3.5 million of revenues and approximately $2.5 million of net income from discontinued operations attributed to the BRMR Merger are included in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to June 30, 2019.

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The following table summarizes the purchase price allocation and the values of assets acquired and liabilities assumed (in thousands):

The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of proved oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighed average cost of capital rate. The fair value of unproved properties was determined using a market approach utilizing recent transactions of a similar nature in the same basin. These inputs required significant judgements and estimates by management at the time of the valuation and are the most sensitive to possible future changes.

The following unaudited pro forma financial information represents the combined results for the Company as though the BRMR Merger had been completed on January 1, 2019. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the BRMR Merger taken place on January 1, 2019; furthermore, the financial information is not intended to be a projection of future results.

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Note 5-Assets Held for Sale and Discontinued Operations

Assets Held for Sale

As a result of the BRMR Merger, the Company acquired certain assets that met the criteria for assets held for sale at the acquisition date, comprised of the net assets of Magnum Hunter Production, Inc. (“MHP”), a wholly-owned subsidiary of BRMR. These assets are located primarily in Kentucky and Tennessee.

The following summarizes assets and liabilities held for sale as of June 30, 2020 and December 31, 2019:

Discontinued Operations

The Company determined that the planned divestiture of MHP met the assets held for sale criteria and the criteria for classification as discontinued operations as of the three and six months ended June 30, 2020 and 2019.

The Company included the results of operations for MHP for the three and six months ended June 30, 2020 and 2019 in discontinued operations as follows:

The Company had maintained an accrued liability of $3.5 million related to litigation involving MHP and a third-party regarding certain royalty and overriding royalty deductions and related payments under several farm-out agreements. The litigation concluded in April 2019 and, as a result, the Company removed the accrued liability and recognized corresponding income from discontinued operations for the three and six months ended June 30, 2019.

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During the first quarter of 2020, the Company determined that due to the depressed commodity price environment, the carrying value of MHP’s proved oil and gas properties was no longer fully recoverable. The Company recorded an impairment of $6.8 million of its proved oil and gas properties in order to present the net assets and liabilities of MHP at the lower of carrying value and fair market value less costs to sell as of June 30, 2020.

Total operating and investing cash flows of discontinued operations for the six months ended June 30, 2020 and 2019 were as follows:

Note 6-Derivative Instruments

All of the Company’s derivative instruments are used for risk management purposes and none is held for trading or speculative purposes. By using derivative instruments to hedge exposures to changes in commodity prices and interest rates, the Company is exposed to the credit risk of its counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of counterparties is subject to periodic review. As of June 30, 2020, the Company’s derivative instruments were with Bank of Montreal, BP Energy Company, Capital One N.A., Citibank, Citizens Bank N.A., East West Bank, J Aron, KeyBank N.A., Morgan Stanley, Royal Bank of Canada, and Wells Fargo. The Company has not experienced any issues of non-performance by derivative counterparties.

Commodity Derivatives

The Company is exposed to market risk from changes in energy commodity prices within its operations. The Company utilizes derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas and oil. The Company currently uses a mix of over-the-counter fixed price swaps, basis swaps, options and collars to manage its exposure to commodity price fluctuations.

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Below is a summary of the Company’s derivative instrument positions, as of June 30, 2020, for future production periods:

Natural Gas Derivatives:

Oil Derivatives:

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NGL Derivatives:

Interest Rate Swap

In April 2020, the Company entered into an interest-rate swap with a notional amount of $ 100 million to manage its exposure to interest rate volatility. The interest-rate swap has a 1-month LIBOR floating rate index at a 0.255% fixed interest rate. The change in fair value of the interest rate swap agreement is accounted for on a mark-to-market basis with the changes in fair value recorded in current period earnings. The swap will mature on February 28, 2022, at which date the counterparty may elect to further extend the contract through February 28, 2024.

Fair Values and Gains (Losses)

The following table summarizes the fair value of the Company’s derivative instruments on a gross basis and on a net basis as presented in the Condensed Consolidated Balance Sheets (in thousands). None of the derivative instruments is designated as a hedge for accounting purposes.

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The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the periods presented (in thousands):

Note 7-Fair Value Measurements

Fair Value Measurement on a Recurring Basis

The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Condensed Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. The fair value of the Company’s derivatives is based on third-party pricing models, which utilize inputs that are readily available in the public market, such as natural gas and crude oil forward curves. These values are compared to the values given by counterparties for reasonableness. Since the Company’s derivative instruments do not include optionality, and therefore, generally have no unobservable inputs, they are classified as Level 2.

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Nonfinancial Assets and Liabilities

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s ARO represent a nonrecurring Level 3 measurement. (See Note 3-Summary of Significant Accounting Policies).

The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. (See Note 3-Summary of Significant Accounting Policies).

The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due, except for long-term debt. (See Note 8-Debt).

Note 8-Debt

8.875% Senior Unsecured Notes Due 2023

On July 6, 2015, the Company issued $550 million in aggregate principal amount of 8.875% senior unsecured notes due 2023 at an issue price of 97.903% of the principal amount of the notes, plus accrued and unpaid interest, if any, to Deutsche Bank Securities Inc. and other initial purchasers. In this private offering, the senior unsecured notes were sold for cash to qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act and to persons outside the United States in compliance with Regulation S under the Securities Act. Upon closing, the Company received proceeds of approximately $525.5 million, after deducting original issue discount, the initial purchasers’ discounts and estimated offering expenses, of which the Company used approximately $510.7 million to finance the redemption of all of its outstanding senior PIK notes. The Company used the remaining net proceeds to fund its capital expenditure plan and for general corporate purposes.

The indenture governing the senior unsecured notes contains covenants that, among other things, limit the ability of the Company and its restricted subsidiaries to: (i) incur additional indebtedness, (ii) pay dividends on capital stock or redeem, repurchase or retire the Company’s capital stock or subordinated indebtedness, (iii) transfer or sell assets, (iv) make investments, (v) create certain liens, (vi) enter into agreements that restrict dividends or other payments to the Company from its restricted subsidiaries, (vii) consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries, taken as a whole, (viii) engage in transactions with affiliates, and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications set forth in the indenture. In addition, if the senior unsecured notes achieve an investment grade rating from either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services, and no default under the indenture has then occurred and is continuing, many of such covenants will be suspended. The indenture also contains events of default, which include, among others and subject in certain cases to grace and cure periods, nonpayment of principal or interest, failure by the Company to comply with its other obligations under the indenture, payment defaults and accelerations with respect to certain other indebtedness of the Company and its restricted subsidiaries, failure of any guarantee on the senior unsecured notes to be enforceable, and certain events of bankruptcy or insolvency. The Company was in compliance with all applicable covenants in the indenture as of June 30, 2020.

Based on Level 2 market data inputs, the fair value of the senior unsecured notes as of June 30, 2020 was $403.5 million.

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Revolving Credit Facility

The Company maintains an asset-based, senior secured revolving bank credit facility (“the revolving credit facility”). The borrowing base is derived from the Company’s proved properties and is subject to regular semi-annual redeterminations (April and October). The credit agreement governing the revolving credit facility (as amended and restated, the “Credit Agreement”) was entered into during the first quarter of 2014 by a subsidiary of the Company and was amended in 2015, 2016, 2017, and 2019 in order to, among other things, add the Company as a party to the revolving credit facility, extend the maturity date to February 2024, amend the borrowing base, revise certain financial covenants, and revise certain commitment fees and letter of credit participation fees. The revolving credit facility is secured by mortgages on 85% of the value of the Company’s proved reserves and guarantees from the Company’s operating subsidiaries. The revolving credit facility contains certain covenants, including restrictions on indebtedness and dividends. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. Commitment fees on the unused portion of the revolving credit facility are due quarterly at 0.375%-0.500% of the unused facility based on utilization.

On May 4, 2020, the Company entered into an additional amendment to the Credit Agreement to, among other things, confirm the scheduled redetermination of the borrowing base under the Credit Agreement, which reduced the borrowing base by $25 million from $500 million to $475 million, increase the Applicable Margin (as defined in the Credit Agreement) applicable to loans and letter of credit participation fees under the Credit Agreement by 0.25%, at all utilization levels, and establish prepayment requirements, in certain circumstances, on cash balances in excess of $40 million. In connection with the borrowing base redetermination, the Company wrote off approximately $0.2 million of unamortized deferred financing costs to interest expense.

As of June 30, 2020, the borrowing base was $475 million and the Company had $160.0 million in outstanding borrowings under the revolving credit facility. After giving effect to outstanding letters of credit issued by the Company totaling $29.2 million and the outstanding borrowings of $160.0 million, the Company had available borrowing capacity under the revolving credit facility of $285.8 million as of June 30, 2020.

The Company was in compliance with all applicable covenants under the revolving credit facility as of June 30, 2020.

Other Notes Payable

From time to time, the Company enters into other notes payable for the purchase of vehicles and equipment or to finance its insurance premiums. The Company had outstanding notes payable of $1.2 million and $0.3 million included in “Accrued liabilities” in the accompanying Condensed Consolidated Balance Sheets as of June 30, 2020 and December 31, 2019, respectively.

Note 9-Benefit Plans

Defined Contribution Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(k) of the Internal Revenue Code, as amended (the “Code”), under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(k) plan, the Company provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company recorded compensation expense related to matching contributions, classified under general and administrative, of $0.3 million for each of the three months ended June 30, 2020 and 2019 and $0.7 million and $0.5 million for the six months ended June 30, 2020 and 2019, respectively.

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Note 10-Stock-Based Compensation

The Company is authorized to grant up to 2,650,000 shares of common stock under its 2019 Long-Term Incentive Plan (the “2019 Plan”). The 2019 Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, bonus stock or other stock-based awards and performance awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 300,888 shares were available for future grants under the Plan as of June 30, 2020.

Stock-based compensation expense was as follows for the three and six months ended June 30, 2020 and 2019 (in thousands):

Restricted Stock Units

Restricted stock unit awards vest subject to the satisfaction of service requirements. The Company recognizes expense related to restricted stock unit awards on a straight-line basis over the requisite service period, which is three years. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. As of June 30, 2020, there was $3.4 million of total unrecognized compensation cost related to outstanding restricted stock units. The weighted average period for the units to vest is approximately two years. A summary of employee restricted stock unit awards activity during the six months ended June 30, 2020 is as follows:

Performance Units

Performance unit awards issued prior to May 2020 vest subject to the satisfaction of a three-year service requirement and a performance objective which generally is based on the Company’s performance compared to an industry peer group. In May 2020, the Company issued performance unit awards which will vest on December 31, 2022 and are subject to a performance objective based on the performance of the Company’s stock over the performance period. All performance unit awards are measured at the grant date fair value using a Monte Carlo valuation method.

As of June 30, 2020, there was $4.6 million of total unrecognized compensation cost related to outstanding performance units. The weighted average period for the units to vest is approximately two years. A summary of performance stock unit awards activity during the six months ended June 30, 2020 is as follows:

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The determination of the fair value of the performance unit awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of forfeitures, the risk-free interest rate and a volatility estimate tied to the Company’s stock price. The following table presents the assumptions used to determine the fair value for performance stock units granted during the six months ended June 30, 2020 and 2019:

Restricted and Unrestricted Stock

On May 16, 2018, the Company issued an aggregate of 15,476 restricted shares of common stock to its three non-employee members of its Board of Directors that were not affiliated with the Company’s then controlling stockholder, which shares became fully vested on May 16, 2019.

Effective February 28, 2019, the Company issued an aggregate of 70,409 restricted shares of common stock to two of its officers in connection with retention bonus arrangements entered into between the Company and each of these officers. Twenty-five percent of the restricted shares vested on each of August 28, 2019 and February 28, 2020. In accordance with the terms of the underlying award agreements, the remaining 50% of the restricted shares vested on June 1, 2020.

Pursuant to the Company’s Non-Employee Director Compensation Policy, on June 18, 2019, the Company awarded an aggregate of 53,328 restricted shares of common stock to eight of the non-employee members of its Board of Directors, which shares became fully vested on June 18, 2020. The other non-employee member of the Company’s Board of Directors declined to receive any compensation for his service on the Company’s Board of Directors for 2019.

Pursuant to the Company’s Non-Employee Director Compensation Policy, on August 2, 2019 and October 8, 2019, the Company issued an aggregate of 26,935 and 22,661 unrestricted shares of common stock, respectively, to four of the non-employee members of its Board of Directors who had elected to receive payment of their 2019 annual retainers in shares of the Company’s common stock.

Pursuant to the Company’s Non-Employee Director Compensation Policy, on June 19, 2020, the Company issued an aggregate of 58,335 restricted shares of common stock to five of the non-employee members of its Board of Directors, which shares are scheduled to fully vest on June 19, 2021. The other non-employee member of the Company’s Board of Directors declined to receive any compensation for his service on the Company’s Board of Directors for 2020.

As of June 30, 2020, there was $0.3 million of total unrecognized compensation cost related to restricted and unrestricted stock.

Note 11-Net Income (Loss) Per Share

Net Income (Loss) Per Share

Basic earnings (loss) per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted EPS takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with any stock awards that have been granted to directors and employees. In accordance with FASB ASC Topic 260, awards of non-vested shares shall be considered to be outstanding as of the grant date for purposes of computing diluted EPS even though the awards are contingent upon vesting. During periods in which the Company incurs a net loss, diluted weighted-average shares outstanding are equal to basic weighted-average shares outstanding because the effect of all equity awards is antidilutive.

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Reverse Stock Split

Effective immediately prior to the effective time of the BRMR Merger, on February 28, 2019 (See Note 4- Acquisitions), the Company effected a 15-to-1 reverse stock split of its common stock. Holders of shares of the Company’s common stock immediately prior to the effective time received cash for any fractional shares of the Company’s common stock to which they might otherwise have been entitled as a result of the reverse stock split. The reverse stock split lowered the aggregate par value of the common stock reflected in the Consolidated Statements of Stockholders’ Equity to reflect the reduced shares with the offset to additional paid-in-capital.

The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the three

and six months ended June 30, 2020 and 2019: