Exhibit 99.3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Montage Resources Corporation

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Montage Resources Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of comprehensive income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Change in accounting principle

As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting for leases as of January 1, 2019, due to the adoption of Accounting Standards Codification Topic 842, Leases.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2011

Pittsburgh, Pennsylvania

March 10, 2020

1

MONTAGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)

	December 31, 2019			December 31, 2018
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	12,056		$	5,959
Accounts receivable		77,402			119,332
Assets held for sale		1,047			—
Other current assets		35,509			8,639
Total current assets		126,014			133,930
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method:
Unproved properties		508,576			482,475
Proved oil and gas properties, net		1,251,105			807,583
Other property and equipment, net		11,226			6,300
Total property and equipment, net		1,770,907			1,296,358
OTHER NONCURRENT ASSETS
Other assets		7,616			3,481
Operating lease right-of-use assets		36,975			—
Assets held for sale		9,665			—
TOTAL ASSETS	$	1,951,177		$	1,433,769
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	119,907		$	116,735
Accrued capital expenditures		43,500			12,979
Accrued liabilities		53,866			56,909
Accrued interest payable		21,308			21,661
Liabilities associated with assets held for sale		2,815			—
Operating lease liability		12,666			—
Total current liabilities		254,062			208,284
NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs		500,541			497,778
Revolving credit facility		130,000			32,500
Asset retirement obligations		29,877			7,110
Other liabilities		8,029			611
Operating lease liability		24,569			—
Liabilities associated with assets held for sale		7,013			—
Total liabilities		954,091			746,283
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Preferred stock, 50,000,000 authorized, no shares issued and outstanding		—			—
Common stock, $0.01 par value, 1,000,000,000 authorized, 35,770,934 and 20,169,063 shares issued and outstanding, respectively		383			3,043
Additional paid in capital		2,352,309			2,065,119
Treasury stock, shares at cost; 2,508,485 and 1,747,624 shares, respectively		(10,049	)		(3,357	)
Accumulated deficit		(1,345,557	)		(1,377,319	)
Total stockholders’ equity		997,086			687,486
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,951,177		$	1,433,769

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

2

MONTAGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

( in thousands except per share data)

	For the Year Ended December 31,
	2019			2018			2017
REVENUES
Natural gas, oil and natural gas liquids sales	$	591,699		$	498,593		$	380,178
Brokered natural gas and marketing revenue		42,274			16,552			3,481
Other revenue		468			—			—
Total revenues		634,441			515,145			383,659
OPERATING EXPENSES
Lease operating		43,359			28,289			20,525
Transportation, gathering and compression		208,826			138,766			124,839
Production and ad valorem taxes		12,141			10,141			8,490
Brokered natural gas and marketing expense		42,700			16,886			3,191
Depreciation, depletion, amortization and accretion		156,003			134,940			119,362
Exploration		58,917			49,563			50,208
General and administrative		70,941			44,389			44,553
Rig termination and standby		1,081			—			1
Gain on sale of assets		(476	)		(1,815	)		(179	)
Other expense		60			—			—
Total operating expenses		593,552			421,159			370,990
OPERATING INCOME		40,889			93,986			12,669
OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments		48,596			(21,169	)		45,365
Interest expense, net		(59,055	)		(53,990	)		(49,490	)
Other income (expense)		16			(1	)		(19	)
Total other expense, net		(10,443	)		(75,160	)		(4,144	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		30,446			18,826			8,525
Income tax benefit (expense)		—			—			—
INCOME FROM CONTINUING OPERATIONS		30,446			18,826			8,525
Income from discontinued operations, net of income tax		1,316			—			—
NET INCOME	$	31,762		$	18,826		$	8,525
EARNINGS PER SHARE OF COMMON STOCK
Basic:
Weighted average common stock outstanding		33,211			19,999			17,479
Income from continuing operations	$	0.92		$	0.94		$	0.49
Income from discontinued operations		0.04			—			—
Net income	$	0.96		$	0.94		$	0.49
Diluted:
Weighted average common stock outstanding		33,324			20,087			17,679
Income from continuing operations	$	0.91		$	0.94		$	0.48
Income from discontinued operations		0.04			—			—
Net income	$	0.95		$	0.94		$	0.48

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

3

MONTAGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, and 2017

(in thousands, except share and per share data)

	Number of Shares		Common Stock ($0.01 Par)			Additional Paid-in- Capital			Treasury Stock			Accumulated Deficit			Total
Balances, December 31, 2016		17,372,793	$	2,607		$	1,958,731		$	(61	)	$	(1,404,670	)	$	556,607
Stock-based compensation		—		—			9,301			—			—			9,301
Equity issuance costs		—		—			(44	)		—			—			(44	)
Issuance of restricted stock		10,213		2			(2	)		—			—			—
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings		133,018		28			(28	)		(2,035	)		—			(2,035	)
Net income		—		—			—			—			8,525			8,525
Balances, December 31, 2017		17,516,024	$	2,637		$	1,967,958		$	(2,096	)	$	(1,396,145	)	$	572,354
Stock-based compensation		—		—			7,891			—			—			7,891
Equity issuance costs		—		—			(344	)		—			—			(344	)
Shares of common stock issued in asset acquisition, net of equity issuance costs		2,521,573		378			89,642			—			—			90,020
Issuance of restricted stock		15,476		2			(2	)		—			—			—
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings		115,990		26			(26	)		(1,261	)		—			(1,261	)
Net income		—		—			—			—			18,826			18,826
Balances, December 31, 2018		20,169,063	$	3,043		$	2,065,119		$	(3,357	)	$	(1,377,319	)	$	687,486
Stock-based compensation		—		—			8,784			—			—			8,784
Equity issuance costs		—		—			(30	)		—			—			(30	)
Shares of common stock issued in merger, net of equity issuance costs		15,013,520		150			275,609			—			—			275,759
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings		588,351		23			(6	)		(6,692	)		—			(6,675	)
Reverse split 1:15		—		(2,833	)		2,833			—			—			—
Net income		—		—			—			—			31,762			31,762
Balances, December 31, 2019		35,770,934	$	383		$	2,352,309		$	(10,049	)	$	(1,345,557	)	$	997,086

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

4

MONTAGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	For the Year Ended December 31,
	2019			2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	31,762		$	18,826		$	8,525
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion, amortization and accretion		156,552			134,940			119,362
Exploration expense		47,775			28,324			31,417
Stock-based compensation		8,784			7,891			9,301
Net cash for plugging wells		(1,044	)		—			—
(Gain) loss on derivative instruments		(48,596	)		21,169			(45,365	)
Net cash receipts (payments) on settled derivatives		20,323			(26,985	)		(2,224	)
Gain on sale of assets		(601	)		(1,815	)		(179	)
Amortization of deferred financing costs		2,781			2,256			2,098
Amortization of debt discount		1,330			1,327			1,324
Changes in operating assets and liabilities:
Accounts receivable		67,652			(42,879	)		(31,780	)
Other assets		1,893			(2,192	)		1,863
Accounts payable and accrued liabilities		(33,182	)		84,231			18,404
Net cash provided by operating activities		255,429			225,093			112,746
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for oil and gas properties		(349,710	)		(275,601	)		(291,779	)
Capital expenditures for other property and equipment		(632	)		(1,007	)		(2,007	)
Proceeds from sale of assets		1,959			10,358			1,317
Cash acquired in merger		12,894			—			—
Change in deposits and other long-term assets		(53	)		—			—
Net cash used in investing activities		(335,542	)		(266,250	)		(292,469	)
CASH FLOWS FROM FINANCING ACTIVITIES
Debt issuance costs		(4,264	)		(497	)		(1,750	)
Repayments of long-term debt		(321	)		(506	)		(453	)
Proceeds from revolving credit facility		97,500			32,500			—
Equity issuance costs		(30	)		(344	)		(44	)
Employee tax withholding for settlement of equity compensation awards		(6,675	)		(1,261	)		(2,035	)
Net cash provided by (used in) financing activities		86,210			29,892			(4,282	)
Net increase (decrease) in cash and cash equivalents		6,097			(11,265	)		(184,005	)
Cash and cash equivalents at beginning of period		5,959			17,224			201,229
Cash and cash equivalents at end of period	$	12,056		$	5,959		$	17,224
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest	$	59,552		$	51,101		$	47,362
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES
Asset retirement obligations incurred, including changes in estimate	$	2,898		$	418		$	679
Additions of other property through debt financing	$	—		$	173		$	183
Additions to oil and natural gas properties - changes in accounts payable, accrued liabilities, and accrued capital expenditures	$	17,725		$	(15,269	)	$	22,264
Assets held for sale	$	—		$	—		$	(262	)
Asset acquisition through stock issuance	$	—		$	90,020		$	—
BRMR Merger consideration	$	275,759		$	—		$	—

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

5

MONTAGE RESOURCES CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, and 2017

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-Summary of Significant Accounting Policies

(a) Basis of Presentation

The accompanying Consolidated Financial Statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). In the opinion of management, the accompanying Consolidated Financial Statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, 2019 and 2018, and the results of its operations, comprehensive income (loss) and its cash flows for the years ended December 31, 2019, 2018, and 2017.

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. The Company’s management believes the major estimates and assumptions impacting the Consolidated Financial Statements are the following:

• estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion, amortization and accretion and impairment of capitalized costs of oil and natural gas properties;

• estimates of asset retirement obligations;

• estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells;

• impairment of undeveloped properties and other assets; and

• depreciation and depletion of property and equipment.

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.

(b) 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.

(c) 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 party. The Company had no significant accounts receivables determined to be uncollectable as of December 31, 2019 or December 31, 2018.

6

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 and transportation and compression fees, which are, in turn, based upon applicable product prices.

(d) 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 Consolidated Statements of Operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s 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 Consolidated Statements of Operations. 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 Consolidated Statements of Operations 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):

	December 31, 2019			December 31, 2018
Oil and natural gas properties:
Unproved	$	508,576		$	482,475
Proved		2,783,232			2,188,233
Gross oil and natural gas properties		3,291,808			2,670,708
Less accumulated depreciation, depletion and amortization		(1,532,127	)		(1,380,650	)
Oil and natural gas properties, net		1,759,681			1,290,058
Other property and equipment		20,000			14,460
Less accumulated depreciation		(8,774	)		(8,160	)
Other property and equipment, net		11,226			6,300
Property and equipment, net	$	1,770,907		$	1,296,358

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, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves.

7

Other Property and Equipment

Other property and equipment include 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.

(e) Accounts Payable and Accrued Liabilities

A summary of accounts payable is as follows (in thousands):

	December 31, 2019		December 31, 2018
Trade payables	$	20,232	$	27,481
Royalty payables		76,642		70,019
Production & ad valorem taxes		1,025		1,811
Derivative payable		112		4,736
Other payables		21,896		12,688
Total accounts payable	$	119,907	$	116,735

A summary of accrued liabilities is as follows (in thousands):

	December 31, 2019		December 31, 2018
Ad valorem and production taxes	$	9,830	$	6,193
Employee compensation		9,375		6,595
Royalties		23,311		39,969
Short term derivatives		1,362		—
Other		9,988		4,152
Total accrued liabilities	$	53,866	$	56,909

(f) 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. 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 further process and transport NGLs are recorded as transportation, gathering and compression expense.

8

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 and NGLs 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 and NGLs. 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 periods indicated:

	For the Year Ended December 31,
	2019		2018		2017
Revenues (in thousands)
Natural gas sales	$	361,318	$	274,239	$	241,379
NGL sales		84,552		86,152		64,109
Oil sales		145,829		138,202		74,690
Brokered natural gas and marketing revenue		42,274		16,552		3,481
Other revenue		468		—		—
Total revenues	$	634,441	$	515,145	$	383,659

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 $63.7 million and $94.1 million at December 31, 2019 and December 31, 2018, respectively.

9

(g) Major Customers

The Company sells production volumes to various purchasers. For the years ended December 31, 2019, 2018, and 2017, there were two, one and two customers, respectively, that accounted for 10% or more of the total natural gas, NGLs and oil sales. The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated:

	For the Year Ended December 31,
	2019			2018			2017
Purchaser
BP Energy Company		23	%		—			—
Emera Energy Services		—			—			17	%
Marathon Petroleum		20	%		25	%		10	%
Total		43	%		25	%		27	%

Management believes that the loss of any one customer would not have a material adverse effect on the Company’s ability to sell natural gas, NGLs and oil production because it believes that there are potential alternative purchasers although it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Company can establish such relationships or that those relationships will result in an increased number of purchasers.

(h) Concentration of Credit Risk

The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2019 and December 31, 2018 (in thousands):

	December 31, 2019		December 31, 2018
Receivables by product or service:
Sale of oil and natural gas and related products and services	$	63,730	$	94,107
Joint interest owners		12,156		24,830
Derivatives		210		372
Other		1,306		23
Total	$	77,402	$	119,332

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

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of 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. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. The fair value of the Company’s commodity unsettled derivative contracts was a net asset position of $27.1 million and $5.7 million at December 31, 2019 and 2018, respectively. Other than as provided by the revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s contracts, nor are they required to provide credit support to the Company. As of December 31, 2019, the Company did not have past-due receivables from or payables to any of the counterparties.

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(i) 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 for the years ended December 31, 2019, 2018, and 2017 totaled approximately $153.8 million, $133.2 million and $117.3 million, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Consolidated Financial Statements.

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 5 to 40 years. Depreciation for the years ended December 31, 2019, 2018, and 2017 totaled approximately $2.2 million, $1.8 million and $2.0 million, respectively. This amount is included in depreciation, depletion, amortization and accretion expense in the Consolidated Statements of Operations.

(j) 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 of the Company’s oil and gas properties is done by determining if 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 for the years ended December 31, 2019, 2018, and 2017.

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 $45.8 million, $27.6 million, and $28.3 million for the years ended December 31, 2019, 2018, and 2017, respectively. These costs are included in exploration expense in the Consolidated Statements of Operations.

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(k) Income Taxes

The Company accounts for income taxes, as required, under the liability method. 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 bases 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 “Income Taxes” provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not 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.

(l) 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 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 date 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.

(m) Derivative Financial Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells.

Derivatives are recorded at fair value and are included on the 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 in the accompanying 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 Consolidated Statements of Operations 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.

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

(n) Asset Retirement Obligation

The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with Topic ASC 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 estimates 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.

The following table sets forth the changes in the Company’s ARO liability for the periods indicated (in thousands):

	For the Year Ended December 31,
	2019			2018		2017
Asset retirement obligations, beginning of period	$	7,110		$	6,029	$	4,806
Accretion		2,368			663		544
Additional liabilities incurred		2,379			418		679
Obligation for wells acquired		20,188			—		—
Obligation for wells drilled		519			—		—
Liabilities settled via plugging		(723	)		—		—
Less: current ARO portion (accrued liabilities)		(1,964	)		—		—
Asset retirement obligations, end of period	$	29,877		$	7,110	$	6,029

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.

(o) Off-Balance Sheet Arrangements

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

(p) 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.

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(q) Debt Issuance Costs

The expenditures related to issuing debt are capitalized and reported as a reduction of the Company’s debt balance in the accompanying Consolidated Balance Sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.

During the years ended December 31, 2019, 2018, and 2017, the Company amortized $4.1 million, $3.6 million and $3.4 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method.

(r) Recent Accounting Pronouncements

Recently Adopted

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” The new standard provides guidance to increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Entities are required to recognize all leases in the statement of financial position as assets and liabilities regardless of the leases’ classification. These requirements are effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period with early adoption permitted. In July 2018, the FASB issued ASU 2018-11, “Leases: Targeted Improvements.” The update provided an optional transition method of adoption that permitted entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Under the optional transition method, comparative financial information and disclosures are not required. The update also provided transition practical expedients. The standard required disclosures of the nature, maturity and value of an entity’s lease liabilities and elections made by the entity. In March 2019, the FASB issued ASU 2019-01, “Leases: Codification Improvements,” which, among other things, clarified interim disclosure requirements in the year of ASU 2016-02 adoption.

The Company adopted these standards effective January 1, 2019 using the optional transition method of adoption. The Company implemented a third-party-sponsored lease accounting information system to facilitate the accounting and financial reporting requirements and implemented processes and controls to review new contracts and modifications to existing contracts that contain lease components for appropriate accounting treatment. See Note 6 - Leases for the disclosures required by the standards.

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, 2020. 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 3-Acquisition

Eclipse Resources-PA, LP Acquisition

On January 18, 2018, Eclipse Resources-PA, LP, a wholly owned subsidiary of the Company, completed its acquisition of certain oil and gas leases, one producing well and other oil and gas rights and interests covering approximately 44,500 net acres located in Tioga and Potter Counties, Pennsylvania from Travis Peak Resources, LLC for an aggregate adjusted purchase price of $90 million, which was paid entirely with approximately 2.5

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million shares of the Company’s common stock (the “Flat Castle Acquisition”). The transaction was accounted for as an asset acquisition. Approximately $86 million of the purchase price was allocated to unproved oil and natural gas properties and approximately $4 million was allocated to proved oil and gas properties associated with the producing well acquired. In addition, the Company capitalized approximately $1 million of transaction costs related to the acquisition.

During the year ended December 31, 2018, the Company assigned its option to purchase all of the outstanding equity interests of Cardinal NE Holdings, LLC (“Cardinal”), a wholly owned subsidiary of Cardinal Midstream II, LLC, which owns midstream infrastructure with associated gathering rights on acreage in the Indian Castle and Flat Creek Shales, to a third party. The third party exercised its option to purchase all of the outstanding equity interests of Cardinal in July 2018.

Merger with Blue Ridge Mountain Resources

On February 28, 2019, the Company completed its previously announced 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., a Delaware corporation and a wholly owned subsidiary of the Company (“Merger Sub”), 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 (the “Effective Time”), 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 (See Note 12-Net Income (Loss) Per Share). Former stockholders of BRMR will receive cash for any fractional shares of the Company’s common stock to which they might otherwise be 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 approximately $25.5 million and $4.0 million of costs for the years ended December 31, 2019 and 2018, respectively, which are included in General and administrative expense on the Consolidated Statements of Operations and Comprehensive Income (Loss). Approximately $131.7 million of revenues and approximately $14.0 million of net income from continuing operations are attributed to the BRMR Merger are included in the Company’s Consolidated Statement of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to December 31, 2019. Approximately $7.2 million of revenues and approximately $1.3 million of net income from discontinued operations are attributed to the BRMR Merger are included in the Company’s Consolidated Statement of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to December 31, 2019.

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

Purchase Price	February 28, 2019
Fair value of the Company’s common stock issued	$	263,487
Fair value of BRMR share-based and other compensation		12,272
Total Fair Value of Consideration	$	275,759
Cash and cash equivalents		12,894
Accounts receivable		25,884
Assets held for sale - current		2,296
Other current assets		1,702
Unproved properties		80,843
Proved oil and gas properties		218,866
Other property and equipment		7,059
Other assets		2,461
Operating lease right-of-use asset		7,900
Assets held for sale - long-term		9,611
Total assets acquired	$	369,516
Accounts payable		(16,571	)
Accrued capital expenditures		(5,807	)
Accrued liabilities		(28,824	)
Operating lease liability - current		(1,979	)
Liabilities associated with assets held for sale - current		(7,683	)
Asset retirement obligations		(20,188	)
Operating lease liability - noncurrent		(5,923	)
Liabilities associated with assets held for sale -long-term		(6,782	)
Total liabilities assumed	$	(93,757	)
Net identifiable assets	$	275,759

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.

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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, 2018. 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, 2018; furthermore, the financial information is not intended to be a projection of future results.

	For the Year Ended December 31,
(in thousands, except per share data) (unaudited)	2019		2018
Pro forma total revenues	$	677,099	$	698,850
Pro forma net income	$	44,536	$	5,919
Pro forma net income per share (basic)	$	1.25	$	0.17
Pro forma net income per share (diluted)	$	1.24	$	0.16

Note 4-Sale of Oil and Natural Gas Property Interests

Asset Sales

During the year ended December 31, 2017, the Company received approximately $0.5 million from a completed asset sale with a third party totaling approximately 100 acres. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

During the year ended December 31, 2017, the Company received approximately $0.8 million from a completed asset sale with a third party totaling approximately 150 acres. As a result of this sale, the Company recognized a gain of approximately $0.2 million.

During the year ended December 31, 2018, the Company received approximately $6.0 million from a completed asset sale of approximately 1,000 acres to a third party. As a result of this sale, the Company recognized a gain of approximately $1.5 million.

During the year ended December 31, 2018, the Company received approximately $3.8 million from a completed asset sale of approximately 400 acres to a third party. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

During the year ended December 31, 2018, the Company received approximately $0.3 million from a completed asset sale of approximately 50 acres to a third party. As a result of this sale, the Company recognized a gain of approximately $0.3 million.

During the year ended December 31, 2018, the Company sold the $0.2 million of pipeline assets. As a result of this sale, the Company recognized a loss of less than approximately $0.1 million. These pipeline assets were classified as held for sale on the Consolidated Balance Sheets as of December 31, 2015.

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.

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The following summarizes assets and liabilities held for sale at December 31, 2019:

(in thousands)	December 31, 2019
Accounts receivable	$	343
Other current assets		704
Total current assets held for sale	$	1,047
Proved oil and gas properties, net	$	9,528
Other noncurrent assets		137
Total noncurrent assets held for sale	$	9,665
Accounts payable	$	2,067
Accrued liabilities		570
Other current liabilities		178
Total current liabilities associated with assets held for sale	$	2,815
Asset retirement obligations	$	6,488
Other liabilities		525
Total noncurrent liabilities associated with assets held for sale	$	7,013

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 December 31, 2019. The Company included the results of operations for MHP for the year ended December 31, 2019 in discontinued operations as follows:

(in thousands)	For the Year Ended December 31, 2019
Revenues	$	7,160
Depreciation, depletion, amortization and accretion		(550	)
Other operating expenses		(5,296	)
Other income		2
Income from discontinued operations, net of tax		1,316
Gain on disposal of discontinued operations, net of tax		—
Income from discontinued operations, net of tax	$	1,316

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 result, the Company removed the accrued liability and recognized corresponding income from discontinued operations for the year ended December 31, 2019.

Total operating and investing cash flows of discontinued operations for the year ended December 31, 2019 were as follows:

(in thousands)	For the Year Ended December 31, 2019
Net cash provided by operating activities	$	425
Net cash provided by investing activities	$	26

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Note 6-Leases

The Company leases drilling rigs, compressors, vehicles, office space, and other equipment under non-cancelable operating leases expiring through 2036. Certain lease agreements may include options to renew the lease, terminate the lease early, or purchase the underlying asset(s). The Company determines the lease term at the lease commencement date as the non-cancelable period of the lease, including the options to extend or terminate the lease when such an option is reasonably certain to be exercised.

As discussed in Note 2-Summary of Significant Accounting Policies, the Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 “Leases (Topic 842)” on January 1, 2019 using the optional transition method of adoption. The Company elected a package of practical expedients that together allows an entity to not reassess (i) whether a contract is or contains a lease, (ii) lease classification, and (iii) initial direct costs. In addition, the Company elected the following practical expedients for all asset classes: (i) to not reassess certain land easements, (ii) to not apply the recognition requirements under the standard to short-term leases, and (iii) to combine and account for lease and nonlease contract components as a lease, which requires the capitalization of fixed nonlease payments on January 1, 2019 or lease effective date and recognition of variable nonlease payments as variable lease expense.

On January 1, 2019, the Company recorded a total of $10.4 million in right-of-use assets and corresponding new lease liabilities on its Consolidated Balance Sheets representing the present value of its future operating lease payments. Adoption of the standards did not require an adjustment to the opening balance of retained earnings. The discount rate used to determine present value was based on the rate of interest that the Company estimated it would have to pay to borrow (on a collateralized-basis over a similar term) an amount equal to the lease payments in a similar economic environment as of January 1, 2019. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date.

The right-of-use assets and lease liabilities recognized upon adoption of ASU 2016-02 were based on the lease classifications, lease commitment amounts, and terms recognized under the prior lease accounting guidance. Leases with an initial term of 12 months or less, taking into account extensions if reasonably certain to be exercised, are considered short-term leases and are not recorded on the Consolidated Balance Sheet.

The Company incurred $16.0 million in operating lease cost during the year ended December 31, 2019. The operating lease right-of-use assets were reported in other noncurrent assets and the current and noncurrent portions of the operating lease liabilities were reported in current liabilities and noncurrent liabilities, respectively, on the Consolidated Balance Sheets. As of December 31, 2019, the operating right-of-use assets were $37.0 million and operating lease liabilities were $37.2 million, of which $12.7 million was classified as current. As of December 31, 2019, the weighted average remaining lease term was 3.7 years and the weighted average discount rate was 5.4% .

Supplemental cash flow information related to the Company’s operating leases is included in the table below (in thousands):

	For the Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	5,542
Investing cash flows for operating leases	$	10,489
ROU assets added in exchange for lease obligations (upon adoption)	$	10,434
ROU assets and lease obligations acquired in BRMR Merger	$	7,900
ROU assets added in exchange for lease obligations, net of terminations (since adoption)	$	31,714

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The Company’s lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands):

	Operating Leases
2020	$	14,424
2021		13,004
2022		5,524
2023		3,611
2024		2,110
Thereafter		2,631
Total lease payments	$	41,304
Less imputed interest		(4,069	)
Total lease liability	$	37,235

As discussed in Note 2-Summary of Significant Accounting Policies, the Company elected a transition method to recognize the effects of applying the new standard as a cumulative-effect adjustment to the opening balance of retained earnings. Per ASU 2016-02, the entity electing this transition method should provide the required disclosures under Topic 840 for all periods that continue to be in accordance with Topic 840. As such, the Company included the future minimum lease commitments table below as of December 31, 2018. Future minimum lease commitments under non-cancellable leases at December 31, 2018 were as follows:

2019		1,360
2020		1,060
2021		929
2022		755
2023		755
Thereafter		1,619
Total minimum lease payments	$	6,478

Note 7-Derivative Instruments

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 and put options spreads and collars to manage its exposure to commodity price fluctuations. All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes.

By using derivative instruments to hedge exposures to changes in commodity prices, 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 December 31, 2019, the Company’s derivative instruments were with Bank of Montreal, BP Energy Company, Capital One N.A., Citibank, Citizens Bank N.A., EDF Energy, 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. Below is a summary of the Company’s derivative instrument positions, as of December 31, 2019, for future production periods:

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Natural Gas Derivatives:

Description	Volume (MMBtu/d)		Production Period		Weighted Average Price ($ /MMBtu)
Natural Gas Swaps:
		50,000		January 2020 - December 2020	$	2.67
		20,000		January 2020 - March 2020	$	2.80
		80,000		January 2020 - June 2020	$	2.67
		20,000		April 2020 - June 2020	$	2.75
		30,000		July 2020 - December 2020	$	2.60
		25,000		January 2020 - March 2021	$	2.60
		20,000		July 2020 - March 2021	$	2.58
Natural Gas Collars:
Floor purchase price (put)		50,000		January 2020 - December 2020	$	2.49
Ceiling sold price (call)		50,000		January 2020 - December 2020	$	2.88
Floor purchase price (put)		30,000		January 2020 - March 2020	$	2.65
Ceiling sold price (call)		30,000		January 2020 - March 2020	$	2.98
Floor purchase price (put)		15,000		April 2020 - June 2020	$	2.50
Ceiling sold price (call)		15,000		April 2020 - June 2020	$	2.80
Natural Gas Three-way Collars:
Floor purchase price (put)		30,000		January 2020 - December 2020	$	2.70
Floor sold price (put)		30,000		January 2020 - December 2020	$	2.40
Ceiling sold price (call)		30,000		January 2020 - December 2020	$	3.05
Floor purchase price (put)		30,000		January 2020 - March 2020	$	2.72
Floor sold price (put)		30,000		January 2020 - March 2020	$	2.25
Ceiling sold price (call)		30,000		January 2020 - March 2020	$	3.15
Floor purchase price (put)		50,000		January 2020 - June 2020	$	2.82
Floor sold price (put)		50,000		January 2020 - June 2020	$	2.40
Ceiling sold price (call)		50,000		January 2020 - June 2020	$	3.11
Floor purchase price (put)		45,000		January 2021 - December 2021	$	2.55
Floor sold price (put)		45,000		January 2021 - December 2021	$	2.25
Ceiling sold price (call)		45,000		January 2021 - December 2021	$	2.81
Natural Gas Call/Put Options:
Floor sold price (put)		50,000		January 2020 - December 2020	$	2.30
Floor sold price (put)		50,000		January 2020 - June 2020	$	2.25
Swaption sold price (call)		50,000		January 2021 - December 2021	$	2.75
Swaption sold price (call)		50,000		January 2022 - December 2022	$	3.00
Basis Swaps:
Appalachia - Dominion		12,500		April 2020 - October 2020	$	(0.52	)
Appalachia - Dominion		20,000		January 2020 - December 2020	$	(0.59	)
Appalachia - Dominion		20,000		January 2020 - March 2020	$	(0.39	)

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Oil Derivatives:

Description	Volume (Bbls/d)		Production Period		Weighted Average Price ($/Bbl)
Oil Swaps:
		1,500		January 2020 - December 2020	$	57.07
		1,000		July 2020 - December 2020	$	56.53
		250		July 2020 - March 2021	$	53.20
		250		January 2021 - March 2021	$	53.00
Oil Collars:
Floor purchase price (put)		500		January 2020 - December 2020	$	50.00
Ceiling sold price (call)		500		January 2020 - December 2020	$	64.00
Floor purchase price (put)		500		July 2020 - December 2020	$	52.00
Ceiling sold price (call)		500		July 2020 - December 2020	$	60.00
Floor purchase price (put)		500		January 2020 - March 2020	$	60.00
Ceiling sold price (call)		500		January 2020 - March 2020	$	67.00
Oil Three-way Collars:
Floor purchase price (put)		2,000		January 2020 - June 2020	$	62.50
Floor sold price (put)		2,000		January 2020 - June 2020	$	55.00
Ceiling sold price (call)		2,000		January 2020 - June 2020	$	74.00
Oil Call/Put Options:
Swaption sold price (call)		500		January 2021 - December 2021	$	56.80
Floor sold price (put)		500		July 2020 - December 2020	$	45.00

NGL Derivatives:

Description	Volume (Bbls/d)		Production Period		Weighted Average Price ($/Bbl)
Propane Swaps:
		750		January 2020 - December 2020	$	21.46

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 Consolidated Balance Sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes.

As of December 31, 2019	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	33,762		$	(3,719	)		30,043			Other current assets
Commodity derivatives - noncurrent		833			(45	)		788			Other assets
Total assets	$	34,595		$	(3,764	)	$	30,831
Liabilities
Commodity derivatives - current	$	(5,081	)	$	3,719		$	(1,362	)		Accrued liabilities
Commodity derivatives - noncurrent		(2,397	)		45			(2,352	)		Other liabilities
Total liabilities	$	(7,478	)	$	3,764		$	(3,714	)

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As of December 31, 2018	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	4,960		$	(845	)	$	4,115			Other current assets
Commodity derivatives - noncurrent		1,910			—			1,910			Other assets
Total assets	$	6,870		$	(845	)	$	6,025
Liabilities
Commodity derivatives - current	$	(845	)	$	845		$	—			Accrued liabilities
Commodity derivatives - noncurrent		(326	)		—			(326	)		Other liabilities
Total liabilities	$	(1,171	)	$	845		$	(326	)

(a) The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

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

		For the Year Ended December 31,
	Location of Gain (Loss)	2019		2018			2017
Commodity derivatives	Gain (loss) on derivative instruments	$	48,596	$	(21,169	)	$	45,365

Note 8-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 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 forward curves. These values are compared to the values given by counterparties for reasonableness. Since natural gas swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2.

	Level 1		Level 2		Level 3		Total Fair Value
As of December 31, 2019: (in thousands)
Commodity derivative instruments	$	—	$	27,117	$	—	$	27,117
Total	$	—	$	27,117	$	—	$	27,117
As of December 31, 2018: (in thousands)
Commodity derivative instruments	$	—	$	5,699	$	—	$	5,699
Total	$	—	$	5,699	$	—	$	5,699

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. (See Note 3- Acquisition).

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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 2- 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 2- 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 9- Debt).

Note 9-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 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 of the Securities Act and to persons outside of the United States in compliance with Rule 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 offering expenses, of which the Company used approximately $510.7 million to finance the redemption of all of its outstanding 12.0% Senior PIK notes. The Company used the remaining 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 at December 31, 2019.

Based on Level 2 market data inputs, the fair value of the senior unsecured notes at December 31, 2019 was approximately $471.1 million.

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Revolving Credit Facility

During the first quarter of 2014, Eclipse Resources I, LP, a wholly owned subsidiary of the Company (“Eclipse I”) entered into a $500 million senior secured revolving bank credit facility (the “revolving credit facility”) that was scheduled to mature in 2018. Borrowings under the revolving credit facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to semiannual redeterminations (April and October).

The credit agreement governing the revolving credit facility (as amended and restated, the “Credit Agreement”) was amended on January 12, 2015. The primary change effected by such amendment was to add the Company as a party to the revolving credit facility and thereby subject the Company to the representations, warranties, covenants and events of default provisions thereof. Relative to the Eclipse I’s previous credit agreement, the Credit Agreement also (i) requires financial reporting regarding, and tests financial covenants with respect to, the Company rather than Eclipse I, (ii) increases the basket sizes under certain of the negative covenants, and (iii) includes certain other changes favorable to Eclipse I. Other terms of the Credit Agreement remain generally consistent with Eclipse I’s previous credit agreement.

On February 24, 2016, the Company amended its revolving credit facility to, among other things, adjust the quarterly minimum interest coverage ratio, which is the ratio of EBITDAX to Cash Interest Expense (as such terms are defined in the Credit Agreement), and to permit the sale of certain conventional properties. The amendment to the Credit Agreement also increased the Applicable Margin (as defined in the Credit Agreement) applicable to loans and letter of credit participation fees under the Credit Agreement by 0.5% .

On February 24, 2017, the Company entered into an additional amendment that increased the borrowing base from $125 million to $175 million, while extending the maturity of the revolving credit facility to February 2020. In addition, the amendment modified the minimum interest coverage ratio covenant to a net leverage covenant of Net Debt (as defined in the Credit Agreement) to EBITDAX. On August 1, 2017, the Company entered into an additional amendment to the Credit Agreement that increased the borrowing base from $175 million to $225 million.

On February 28, 2019, the Company amended and restated the Credit Agreement to increase its revolving credit facility from $500 million to $1 billion. Further, the amended and restated Credit Agreement, among other things, increased the borrowing base from $225 million to $375 million (subject to scheduled and interim redeterminations based on the Company’s oil and natural gas reserves and other adjustments described therein) and extended the maturity date thereof to February 2024 (subject to earlier maturity in certain circumstances specified therein). The amended and restated Credit Agreement also adjusted the ratio of Consolidated Total Funded Net Debt to EBITDAX to provide that the Company will not, as of the last day of any fiscal quarter (commencing with the fiscal quarter ending March 31, 2019), permit its ratio of Consolidated Total Funded Net Debt to EBITDAX for the four previous fiscal quarters to be greater than 4.00 to 1.00.

On May 6, 2019, the borrowing base under the Credit Agreement was redetermined, which increased the borrowing base from $375 million to $400 million.

On September 19, 2019, the Company entered into an additional amendment to the Credit Agreement to, among other things, confirm the redetermination of the borrowing base under the Credit Agreement, which increased the borrowing base from $400 million to $500 million.

On November 11, 2019, the Company entered into an additional amendment to the Credit Agreement to, among other things, (a) provide that the Company, may under certain circumstances, voluntarily repurchase, prepay or otherwise redeem the Company’s outstanding 8.875% senior unsecured notes due 2023 and any Permitted Refinancing Debt thereof (as such term is defined in the Credit Agreement), provided that the aggregate amount spent for such repurchase, prepayment or redemption since November 11, 2019 does not exceed $50 million; and (b) reduce the ratio of Consolidated Total Funded Net Debt to EBITDAX that the Company is required to maintain in order to make certain Restricted Payments (as such terms are defined in the Credit Agreement) from 3:1 to 2.75:1.

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At December 31, 2019, the borrowing base under the revolving credit facility was $500 million and the Company had $130.0 million in outstanding borrowings thereunder. After giving effect to outstanding letters of credit issued by the Company totaling $29.2 million, the Company had available borrowing capacity under the revolving credit facility of $340.8 million.

The revolving credit facility is secured by mortgages on 85% of the value of the Company’s properties and guarantees from the Company’s operating subsidiaries. The revolving credit facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and leverage coverage ratios. 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. The Company was in compliance with all applicable covenants under the revolving credit facility as of December 31, 2019. 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.

Note 10-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 of $1.0 million, $0.9 million and $0.7 million related to matching contributions, classified under general and administrative, for the years ended December 31, 2019, 2018, and 2017, respectively.

Note 11-Stock-Based Compensation

At the Company’s 2019 Annual Meeting of Stockholders held on June 14, 2019, the Company’s stockholders approved the Company’s 2019 Long-Term Incentive Plan (the “2019 Plan”), which was previously approved by the Company’s Board of Directors. The 2019 Plan replaces the Company’s 2014 Long-Term Incentive Plan, as amended (the “Prior Plan”). Upon stockholder approval, (i) the 2019 Plan became effective, and (ii) the Prior Plan terminated, and no additional awards will be granted under the Prior Plan; provided that awards outstanding under the Prior Plan as of the date the 2019 Plan became effective will remain in full force and effect under the Prior Plan according to their respective terms.

The Company is authorized to grant up to 2,650,000 shares of common stock under 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, performance-based awards and other types of 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 1,745,810 shares were available for future grants under the Plan as of December 31, 2019.

Stock-based compensation expense was as follows for the years ended December 31, 2019, 2018, and 2017 (in thousands):

	Year Ended December 31,
	2019		2018		2017
Restricted stock units	$	4,141	$	4,014	$	5,301
Performance units		3,706		3,497		3,622
Restricted and unrestricted stock		937		380		378
Total expense	$	8,784	$	7,891	$	9,301

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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 December 31, 2019, there was $2.4 million of total unrecognized compensation cost related to restricted stock units. The weighted average period for the units to vest is approximately one year.

A summary of employee restricted stock unit awards activity during the year ended December 31, 2019 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2018		233,960		$	29.27	$	3,685
Granted		417,584			6.46
Vested		(212,140	)		28.71
Forfeited		(1,845	)		13.11
Total awarded and unvested, December 31, 2019		437,559		$	7.83	$	3,474

Performance Units

Performance unit awards vest subject to the satisfaction of a three-year service requirement and based on Total Shareholder Return (“TSR”), as compared to an industry peer group over that same period. The performance unit awards are measured at the grant date at fair value using a Monte Carlo valuation method. As of December 31, 2019, there was $1.7 million of total unrecognized compensation cost related to 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 year ended December 31, 2019 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2018		346,589		$	27.68	$	716
Granted		261,139			7.25
Vested		(270,068	)		27.57
Forfeited		(17,540	)		24.86
Total awarded and unvested, December 31, 2019		320,120		$	11.26	$	2,522

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 rate and a volatility estimate tied to the Company’s public peer group. The following table presents the assumptions used to determine the fair value for performance stock units granted during the years ended December 31, 2019, 2018, and 2017:

	Year Ended December 31,
	2019			2018			2017
Volatility		65.10	%		89.70	%		50.41	%
Risk-free interest rate		1.83	%		2.37	%		1.34	%

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The fair value of the performance stock units vested during the years ended December 31, 2019 and December 31, 2017 was approximately $3.7 million and $0.8 million, respectively.

Restricted Stock Issued to Directors

On May 18, 2016, the Company issued an aggregate of 9,963 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 became fully vested on May 18, 2017.

On May 17, 2017, the Company issued an aggregate of 10,212 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 became fully vested on May 17, 2018.

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 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 August 28, 2019, and the remaining 75% of the restricted shares vest in substantially equal installments on February 28, 2020, August 28, 2020 and February 28, 2021.

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 are scheduled to fully vest 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, which vested immediately to four of the non-employee members of its Board of Directors.

As of December 31, 2019, there was $0.9 million of total unrecognized compensation cost related to restricted stock units issued to Directors.

Note 12-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 their exercise is 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 on February 28, 2019 (See Note 3- Acquisition), 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 table below retroactively reflects, in accordance with ASC 505 “Equity”, the stock split that occurred on February 28, 2019 for the years ended December 31, 2018 and 2017, respectively. The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the years ended December 31, 2019, 2018, and 2017:

	Year Ended December 31,
(in thousands, except per share data)	2019						2018						2017
	Income		Shares		Per Share		Income		Shares		Per Share		Income		Shares		Per Share
Basic:
Net income, shares, basic	$	31,762		33,211	$	0.96	$	18,826		19,999	$	0.94	$	8,525		17,479	$	0.49
Weighted-average number of shares of common stock-diluted:
Restricted stock and performance unit awards		—		113				—		88				—		200
Diluted:
Net income, shares, diluted	$	31,762		33,324	$	0.95	$	18,826		20,087	$	0.94	$	8,525		17,679	$	0.48

Note 13-Related Party Transactions

During the years ended December 31, 2018 and 2017, the Company incurred approximately $0.6 million, respectively, related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which were owned by the Company’s former Chairman, President and Chief Executive Officer. The Company incurred less than $0.1 million for these services for the year ended December 31, 2019. The fees were paid in accordance with a standard service contract that did not obligate the Company to any minimum terms. The Company no longer utilizes any flight charter services under this arrangement.

Travis Peak Resources, LLC, the seller from whom the Company acquired assets in the Flat Castle Acquisition, is an affiliate of EnCap Investments L.P. (“EnCap”). EnCap has representatives on the Company’s Board of Directors, and affiliates of EnCap collectively beneficially own approximately 40% of the outstanding shares of the Company’s common stock. (See Note 3- Acquisition).

Note 14-Commitments and Contingencies

(a) Legal Matters

From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings.

During the year ended December 31, 2019, the Company removed an accrued liability related to certain litigation involving MHP (See Note 5- Assets Held for Sale and Discontinued Operations).

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(b) Environmental Matters

The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.

(c) Other Commitments (in thousands)

	Firm transportation(i)		Gas processing, gathering, and compression services(ii)		Total
Year Ending December 31:
2020	$	100,101	$	40,811	$	140,912
2021		99,828		41,383		141,211
2022		99,828		43,399		143,227
2023		99,828		41,260		141,088
2024		100,101		39,498		139,599
Thereafter		722,369		211,001		933,370
Total	$	1,222,055	$	417,352	$	1,639,407

(i) Firm transportation - The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent the minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its Consolidated Financial Statements the Company’s proportionate share of costs based on its working interest.

(ii) Gas processing, gathering, and compression services - Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing and gathering agreements as well as various gas compression agreements. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its Consolidated Financial Statements its proportionate share of costs based on the Company’s working interest.

See Note 6- Leases for a summary of undiscounted future cash flows owed by the Company as lessee to lessors pursuant to contractual agreements in effect as of December 31, 2019.

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Note 15-Income Tax

The components of the Company’s income tax expense from continuing operations are as follows (in thousands):

	For the Year Ended December 31,
	2019		2018		2017
Current
Federal	$	—	$	—	$	—
State		—		—		—
Total current		—		—		—
Deferred
Federal		—		—		—
State		—		—		—
Total deferred		—		—		—
Total income tax expense (benefit)	$	—	$	—	$	—

The Company’s income tax expense from continuing operations differs from the amount derived by applying the statutory federal rate to pretax loss principally due the effect of the following items (in thousands):

	For the Year Ended December 31,
	2019			2018			2017
Income from continuing operations	$	30,446		$	18,826		$	8,525
Statutory rate		21	%		21	%		35	%
Income tax benefit computed at statutory rate		6,394			3,953			2,984
Reconciling items:
State income taxes		200			—			—
Deferred true-up		(6,686	)		—			—
Share-based compensation		—			1,201			(576	)
Other permanent differences		2,376			54			50
Executive compensation limitation		1,263			268			496
Change in valuation allowance		7,959			(5,476	)		(145,449	)
Change in State tax rate		(11,506	)		—			142,495
Income tax expense (benefit)	$	—		$	—		$	—

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Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Company’s deferred taxes are detailed in the table below (in thousands):

	For the Year Ended December 31,
	2019			2018			2017
Deferred tax asset:
Oil and gas properties and equipment	$	11,613		$	62,616		$	93,854
Federal tax loss carryforwards		306,743			140,059			114,652
Derivative instruments and other		—			—			1,064
Interest expense limitation carryforward		25,932			—			—
Operating lease right-of-use liabilities		8,278			—			—
Other, net		5,240			7,398			4,639
Deferred tax asset		357,806			210,073			214,209
Valuation allowance		(343,577	)		(208,324	)		(213,800	)
Net deferred tax assets	$	14,229		$	1,749		$	409
Deferred tax liability:
Derivative instruments and other	$	6,009		$	1,197		$	—
Other, net		—			552			409
Operating lease right-of-use assets		8,220			—			—
Net deferred tax liability	$	14,229		$	1,749		$	409
Reflected in the accompanying Consolidated Balance Sheets as:
Net deferred tax asset	$	—		$	—		$	—
Net deferred tax liability	$	—		$	—		$	—

Deferred tax assets and liabilities are recognized for the estimated future tax effects of temporary differences between the tax basis of an asset or liability and its reported amount in the Consolidated Financial Statements. The measurement of deferred tax assets and liabilities is based on enacted tax laws and rates currently in effect in each of the jurisdictions in which we have operations.

In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income of the appropriate character during the periods in which those deferred income tax assets would be deductible. The Company considers the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. Due to the history of losses in recent years, management believes that it is more likely than not that the Company will not be able to realize our net deferred tax assets, and therefore a valuation allowance on the entire net deferred tax asset is maintained.

The Company has U.S. federal tax loss carryforwards (“NOL”) of approximately $1.4 billion as of December 31, 2019 of which $386 million could be permanently lost. The NOL carryforwards will begin to expire in 2034. In connection with the BRMR Merger (See Note 3- Acquisition), the Company experienced an ownership change as described in IRC Section 382. As a result, the Company’s net operating losses as of December 31, 2019 as well as certain tax deductions are subject to an annual limitation imposed by Section 382 limitation. If a subsequent ownership change were to occur as a result of future transactions in the Company’s stock, the Company’s use of remaining U.S. tax attributes may be further limited.

The tax years ended December 31, 2016 through 2019 will remain open to examination under the applicable statute of limitations in the U.S. and other jurisdictions in which the Company and its subsidiaries file income tax returns. However, the statute of limitations for examination of NOLs and other similar attribute carryforwards does not commence until the year the attribute is utilized. In some instances, state statutes of limitations are longer than those under U.S. federal tax law.

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As of December 31, 2019, 2018, and 2017 the Company has not recorded a reserve for any uncertain tax positions. No federal income tax payments are expected in the upcoming four quarterly reporting periods. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. In the Company’s major tax jurisdictions, the earliest year open to examination is 2007.

Note 16-Subsidiary Guarantors

Each subsidiary of the Company that guarantees the Company’s revolving credit facility is required to fully and unconditionally, joint and severally, guarantee the Company’s 8.875% senior unsecured notes. Each such subsidiary of the Company in existence immediately prior to the BRMR Merger guaranteed the Company’s 8.875% senior unsecured notes. As a result of the BRMR Merger, and within the timeframe required by the indenture governing the Company’s 8.875% senior unsecured notes, the Company caused BRMR and each of its subsidiaries that guaranteed the Company’s revolving credit facility to guarantee the Company’s 8.875% senior unsecured notes (See Note 9- Debt ). Montage Resources Corporation, standing alone, has no independent operations or (other than its equity interests in its subsidiaries) material assets. The Company’s wholly owned subsidiary guarantors are not restricted from transferring funds to Montage Resources Corporation or other wholly owned subsidiary guarantors. The Company’s wholly owned subsidiaries do not have any restricted net assets.

A subsidiary guarantor may be released from its obligations under the guarantee:

• in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person by way of merger, consolidation, or otherwise; or

• if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture governing the senior unsecured notes.

Note 17-Subsequent Events

Management has evaluated subsequent events and believes that there are no events that would have a material impact on the aforementioned financial statements and related disclosures in the accompanying notes to the Consolidated Financial Statements.

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Note 18-Quarterly Financial Information (unaudited)

Summarized quarterly financial data for the years ended December 31, 2019 and 2018 are presented in the following table. Quarterly financial data for the year ended December 31, 2018 retroactively reflects the 15-to-1 reverse stock split at the close the BRMR Merger on February 28, 2019. In the following table, the sum of basic and diluted “Income (loss) per common share” for the four quarters may differ from the annual amounts due to the required method of computing weighted average number of shares in the respective periods. Additionally, due to the effect of rounding, the sum of the individual quarterly loss per share amounts may not equal the calculated year loss per share amount (in thousands, except per share data).

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2019
Total operating revenues	$	141,497		$	155,540		$	163,295		$	174,109
Total operating expenses		136,642			145,370			158,394			153,146
Operating income		4,855			10,170			4,901			20,963
Income (loss) from continuing operations		(13,916	)		24,807			5,521			14,034
Income (loss) from discontinued operations		(182	)		2,705			(1,237	)		30
Net income (loss)		(14,098	)		27,512			4,284			14,064
Income (loss) per common share:
Basic and diluted from continuing operations	$	(0.54)		$	0.69		$	0.15		$	0.39
Basic and diluted from discontinued operations	$	(0.01)		$	0.08		$	(0.03	)	$	—
Basic and diluted	$	(0.55)		$	0.77		$	0.12		$	0.39
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2018
Total operating revenues	$	110,192		$	103,622		$	130,123		$	171,208
Total operating expenses		95,651			92,989			108,929			123,590
Operating income		14,541			10,633			21,194			47,618
Net income (loss)		(2,626	)		(19,036	)		3,998			36,490
Income (loss) per common share:
Basic	$	(0.13)		$	(0.95	)	$	0.20		$	1.81
Diluted	$	(0.13)		$	(0.95	)	$	0.20		$	1.80

Note 19-Supplemental Oil and Natural Gas Information (unaudited)

(a) Capitalized Costs

A summary of the Company’s capitalized costs are contained in the table below (in thousands):

	December 31,
	2019			2018
Oil and natural gas properties:
Unproved properties	$	508,576		$	482,475
Proved properties		2,783,232			2,188,233
Total oil and natural gas properties		3,291,808			2,670,708
Less accumulated depreciation, depletion and amortization		(1,532,127	)		(1,380,650	)
Net oil and natural gas properties	$	1,759,681		$	1,290,058

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(b) Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities

A summary of the Company’s cost incurred in oil and natural gas property acquisition and development activities is set forth below (in thousands):

	December 31,
	2019		2018		2017
Acquisition costs:
Unproved properties	$	106,758	$	107,862	$	57,498
Proved properties		201,884		4,072		—
Development cost		339,628		239,467		257,119
Exploration cost		11,142		20,957		18,791
Asset retirement obligations		29,346		—		—
Total acquisition, development and exploration costs	$	688,758	$	372,358	$	333,408

(c) Reserve Quantity Information

The following information represents estimates of the Company’s proved reserves as of December 31, 2019 and December 31, 2018, which have been prepared and presented under SEC rules. These rules require companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2019, 2018, and 2017 was based on an unweighted average 12-month average West Texas Intermediate posted price per Bbl for oil and NGLs and a Henry Hub spot natural gas price per MMBtu for natural gas.

Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement may limit the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program, particularly as it develops its significant acreage primarily in the Appalachian Basin of Ohio, Pennsylvania and West Virginia. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves within the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more.

The Company’s proved oil and natural gas reserves are all located in the United States, primarily within the States of Ohio, Pennsylvania and West Virginia. All of the estimates of the proved reserves at December 31, 2019 and 2018 and December 31, 2017, were prepared by SIS and NSAI, our independent petroleum engineers, respectively. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates.

Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

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The following table provides a roll-forward of the total proved reserves for the year ended December 31, 2019, 2018, and 2017 as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:

	Natural Gas (Bcf)			Natural Gas Liquids (MBbl)			Oil (MBbl)			TOTAL (Bcfe)
End of year, December 31, 2016		386.4			8,675.5			5,157.7			469.4
Revisions		515.1			20,327.3			9,746.8			695.6
Extensions and discoveries		274.4			15,598.8			6,192.9			405.1
Acquisitions		1.6			42.6			5.8			1.9
Production		(87.4	)		(2,713.6	)		(1,622.4	)		(113.4	)
End of year, December 31, 2017		1,090.1			41,930.6			19,480.8			1,458.6
Revisions		5.6			(8,307.5	)		231.2			(42.8	)
Extensions and discoveries		515.8			4,059.4			2,995.7			558.1
Acquisitions		9.9			551.4			522.2			16.3
Divestitures		(0.2	)		—			—			(0.2	)
Production		(90.0	)		(3,503.0	)		(2,377.8	)		(125.3	)
End of year, December 31, 2018		1,531.2			34,730.9			20,852.1			1,864.7
Revisions		(77.0	)		4,454.5			(1,569.8	)		(59.6	)
Extensions and discoveries		418.7			19,016.3			11,078.1			599.2
Acquisitions		418.9			14,844.0			2,915.2			525.5
Production		(154.1	)		(4,686.3	)		(2,950.8	)		(200.0	)
End of year, December 31, 2019		2,137.7			68,359.4			30,324.8			2,729.8
Proved developed reserves:
December 31, 2016		226.1			7,520.0			4,439.5			297.8
December 31, 2017		334.6			13,782.9			6,449.6			456.0
December 31, 2018		501.0			20,213.8			8,058.7			670.7
December 31, 2019		1,183.2			39,316.3			12,512.6			1,494.2
Proved undeveloped reserves:
December 31, 2016		160.4			1,155.5			718.1			171.6
December 31, 2017		755.5			28,147.7			13,031.2			1,002.6
December 31, 2018		1,030.2			14,517.2			12,793.4			1,194.1
December 31, 2019		954.5			29,043.2			17,812.2			1,235.6

2017 Changes in Reserves

• Extensions of 405.1 Bcfe primarily from 361.0 Bcfe of development of the Company’s operated Utica asset. The Company also added 0.3 Bcfe from one non-operated Utica well through development. In addition, the Company proved 43.8 Bcfe from 3 Ohio Marcellus wells due to development in the Ohio Marcellus asset.

• Positive revisions of 695.6 Bcfe as a result of a positive revision of 607.2 Bcfe due to improvements in SEC pricing, a positive revision of 61.4 Bcfe due to changes in pricing differentials, and a positive revision of 69.6 Bcfe primarily driven by proved developed producing wells in aggregate outperforming the previous estimate. This was offset by a negative revision of 42.6 Bcfe due a decision to not develop certain proved, undeveloped reserves within five years.

2018 Changes in Reserves

• Extensions of 558.1 Bcfe from the development of 148.3 Bcfe of unproved wells to proved developed, 398.2 Bcfe from the development of the Company’s operated Utica asset and 11.6 Bcfe from the Company’s operated Marcellus asset.

• 16.3 Bcfe related to acquiring proved developed leasehold acreage in the Indian Castle/Flat Creek and Utica Shales.

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• 0.2 Bcfe related to divesting a non-operated proved developed well in the Utica Shale.

• Negative revisions of 42.8 Bcfe as a result of a positive revision of 15.0 Bcfe due to improvements in SEC pricing, a positive revision of 6.8 Bcfe due to changes in pricing differentials and a positive revision of 67.5 Bcfe primarily driven by proved developed producing wells outperforming the previous estimate. This was offset by a negative revision of 98.0 Bcfe due to changes in well spacing and 34.1 Bcfe due to changes in the five year development plan.

2019 Changes in Reserves

• Extensions of 599.2 Bcfe from the development of 100.5 Bcfe of unproved wells to proved developed, of which 70.2 Bcfe is from the development of the Company’s operated Marcellus asset, 23.3 Bcfe is from the Company’s operated Utica asset and 7.0 Bcfe was added from participation in non-operated wells. Extensions of 498.7 Bcfe from the development of unproved wells to proved undeveloped, of which 269.4 Bcfe is from the Company’s operated Utica asset and 229.3 Bcfe is from the Company’s operated Marcellus asset.

• 525.5 Bcfe related to acquiring proved assets from the merger with BRMR.

• Revisions to previous estimates are comprised of 59.6 Bcfe of negative revisions primarily due to a negative adjustment of 277.3 due to downward SEC pricing and differentials and 44.2 Bcfe due adjustments in the drilling schedule. The negative revisions have been offset by a positive revision of 261.9 Bcfe due to well performance, capital allocation, and lease operating expense.

(d) Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2019 and 2018 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31, 2019, 2018, and 2017 (in thousands):

	December 31,
	2019			2018			2017
Future cash inflows (total revenues)	$	8,212,521		$	6,730,000		$	4,750,238
Future production costs		(3,867,182	)		(2,964,098	)		(2,332,310	)
Future development costs (capital costs)		(982,321	)		(855,932	)		(879,399	)
Future income tax expense		(633,086	)		(136,472	)		—
Future net cash flows		2,729,932			2,773,498			1,538,529
10% annual discount for estimated timing of cash flows		(1,534,108	)		(1,444,188	)		(808,843	)
Standardized measure of Discounted Future Net Cash Flow	$	1,195,824		$	1,329,310		$	729,686

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

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(e) Changes in the Standardized Measure of Discounted Future Net Cash Flows

A summary of the changes in the standardized measure of discounted future net cash flows are contained in the table below (in thousands):

	December 31,
	2019			2018			2017
Standardized Measure, beginning of the year	$	1,329,310		$	729,686		$	205,981
Net change in prices and production costs		(531,056	)		369,578			653,347
Net change in future development costs		28,481			87,466			(385,042	)
Sales, less production costs		(327,373	)		(321,802	)		(226,324	)
Extensions		251,343			363,708			135,734
Acquisitions		387,117			7,468			2,365
Divestitures		—			(20	)		—
Revisions of previous quantity estimates		7,345			19,910			322,917
Previously estimated development costs incurred		245,931			65,035			34,102
Net changes in taxes		(237,482	)		(37,345	)		—
Accretion of discount		132,931			72,969			20,598
Changes in timing and other		(90,723	)		(27,343	)		(33,992	)
Standardized Measure, end of year	$	1,195,824		$	1,329,310		$	729,686

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