10-Q

Cs

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2020

or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File Number: 001-36511

Montage Resources Corporation

(Exact name of registrant as specified in its charter)

Delaware	46-4812998
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
122 West John Carpenter Freeway, Suite 300 Irving, TX	75039
(Address of principal executive offices)	(Zip code)

(469) 444-1647

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, Par Value $0.01 Per Share	MR	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    ☒  Yes    ☐  No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    ☒  Yes    ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐	Smaller reporting company	☒
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ☐  Yes    ☒ No

Number of shares of the registrant’s common stock outstanding at November 2, 2020: 36,023,973 shares

MONTAGE RESOURCES CORPORATION

QUARTERLY REPORT ON FORM 10-Q

TABLE OF CONTENTS

		Page
Cautionary Statement Regarding Forward-Looking Statements		3
PART I - Financial Information		5
Item 1.	Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 4.	Controls and Procedures	49
PART II - Other Information		50
Item 1.	Legal Proceedings	50
Item 1A.	Risk Factors	50
Item 6.	Exhibits	55
Signatures		57

2

Cautionary Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q (this “Quarterly Report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and income or losses, projected costs and capital expenditures, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “will,” “plan,” “would,” “should,” “could,” “endeavor,” “believe,” “anticipate,” “intend,” “seek,” “estimate,” “expect,” “project,” “future,” “strategy,” “potential,” “continue,” “budget,” “forecast,” “assume” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are or were, when made, based on our current expectations and assumptions about future events and are or were, when made, based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described in Part II, Item 1A of this Quarterly Report and “Item 1A. Risk Factors” of our Annual Report on Form 10-K, filed with the Securities and Exchange Commission (the “SEC”) on March 10, 2020.

Forward-looking statements may include statements about, among other things:

• realized prices for natural gas, natural gas liquids (“NGLs”) and oil and the volatility of those prices;

• write-downs of our natural gas and oil asset values due to declines in commodity prices;

• our business strategy;

• our reserves, including the impact of current commodity prices on our estimated year end reserves;

• general economic conditions;

• our financial strategy, liquidity and capital required for developing our properties and the timing related thereto;

• the timing and amount of future production of natural gas, NGLs and oil;

• our hedging strategy and results;

• future drilling plans;

• competition and government regulations, including those related to hydraulic fracturing;

• the anticipated benefits under our commercial agreements;

• marketing of natural gas, NGLs and oil;

• leasehold and business acquisitions and joint ventures;

• leasehold terms expiring before production can be established and our costs to extend such terms;

• the costs, terms and availability of gathering, processing, fractionation and other midstream services;

• credit markets;

• uncertainty regarding our future operating results, including initial production rates and liquid yields in our type curve areas;

• our pending merger with Southwestern Energy Company (“Southwestern”) and the expected timing of the consummation of the merger; and

• plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.

3

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, the severity and continued duration of the COVID-19 pandemic, related economic effects and the resulting negative impact on the demand for natural gas, NGLs and oil, operational challenges relating to the COVID-19 pandemic, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of counterparty contracts and supply chain disruptions, legal and environmental risks, drilling and other operating risks, regulatory changes, including U.S. federal, state and local tax regulatory changes, commodity price volatility and declines in the price of natural gas, NGLs and oil, inflation, lack of availability of drilling, production and processing equipment and services, counterparty credit risk, the uncertainty inherent in estimating natural gas, NGLs and oil reserves and in projecting future rates of production, cash flow and access to capital, risks associated with our level of indebtedness, the timing of development expenditures, and the other risks described in Part II, Item 1A of this Quarterly Report and “Item 1A. Risk Factors” of our Annual Report on Form 10-K, filed with the SEC on March 10, 2020.

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect new information obtained or events or circumstances that occur after the date of this Quarterly Report.

4

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

(Unaudited)

	September 30, 2020			December 31, 2019
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	4,013		$	12,056
Accounts receivable		63,483			77,402
Assets held for sale		1,544			1,047
Other current assets		8,984			35,509
Total current assets		78,024			126,014
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method:
Unproved properties		478,644			508,576
Proved oil and gas properties, net		1,216,836			1,251,105
Other property and equipment, net		10,311			11,226
Total property and equipment, net		1,705,791			1,770,907
OTHER NONCURRENT ASSETS
Other assets		5,353			7,616
Operating lease right-of-use assets		30,830			36,975
Assets held for sale		3,403			9,665
TOTAL ASSETS	$	1,823,401		$	1,951,177
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	120,785		$	119,907
Accrued capital expenditures		11,933			43,500
Accrued liabilities		61,963			53,866
Accrued interest payable		9,921			21,308
Liabilities associated with assets held for sale		3,711			2,815
Operating lease liability		12,773			12,666
Total current liabilities		221,086			254,062
NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs		502,622			500,541
Revolving credit facility		170,000			130,000
Asset retirement obligations		30,336			29,877
Other liabilities		31,421			8,029
Operating lease liability		18,805			24,569
Liabilities associated with assets held for sale		7,150			7,013
Total liabilities		981,420			954,091
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, 36,034,837    and 35,770,934 shares issued and outstanding, respectively		386			383
Additional paid in capital		2,355,890			2,352,309
Treasury stock, shares at cost; 2,600,672 and 2,508,485 shares, respectively		(10,511	)		(10,049	)
Accumulated deficit		(1,503,784	)		(1,345,557	)
Total stockholders’ equity		841,981			997,086
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,823,401		$	1,951,177

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

5

MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(In thousands, except per share data)

(Unaudited)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2020			2019			2020			2019
REVENUES
Natural gas, oil and natural gas liquids sales	$	108,518		$	153,021		$	315,471		$	428,278
Brokered natural gas and marketing revenue		6,831			10,228			23,859			31,747
Other revenue		56			46			183			307
Total revenues		115,405			163,295			339,513			460,332
OPERATING EXPENSES
Lease operating		11,494			11,986			33,436			29,651
Transportation, gathering and compression		51,961			57,027			157,472			150,065
Production and ad valorem taxes		3,677			1,660			10,146			8,519
Brokered natural gas and marketing expense		7,345			10,574			24,349			32,017
Depreciation, depletion, amortization and accretion		53,153			45,456			140,058			113,950
Exploration		11,767			16,621			34,112			48,602
General and administrative		12,144			14,580			33,594			57,074
Rig termination and standby		303			1,221			303			1,221
Gain on sale of assets		(62	)		(733	)		(1,419	)		(731	)
Other expense		87			2			121			40
Total operating expenses		151,869			158,394			432,172			440,408
OPERATING INCOME (LOSS)		(36,464	)		4,901			(92,659	)		19,924
OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments		(40,535	)		15,812			(11,329	)		40,620
Interest expense, net		(14,402	)		(15,192	)		(44,166	)		(44,140	)
Other income		2			—			19			8
Total other income (expense), net		(54,935	)		620			(55,476	)		(3,512	)
INCOME (LOSS) FROM CONTINUING OPERATIONS    BEFORE INCOME TAXES		(91,399	)		5,521			(148,135	)		16,412
Income tax benefit (expense)		—			—			—			—
INCOME (LOSS) FROM CONTINUING OPERATIONS		(91,399	)		5,521			(148,135	)		16,412
Income (loss) from discontinued operations, net of income tax		(801	)		(1,237	)		(10,092	)		1,286
NET INCOME (LOSS)	$	(92,200	)	$	4,284		$	(158,227	)	$	17,698
EARNINGS (LOSS) PER SHARE OF COMMON STOCK
Basic:
Weighted average common stock outstanding		36,035			35,684			35,889			32,343
Income (loss) from continuing operations	$	(2.54	)	$	0.15		$	(4.13	)	$	0.51
Income (loss) from discontinued operations		(0.02	)		(0.03	)		(0.28	)		0.04
Net income (loss)	$	(2.56	)	$	0.12		$	(4.41	)	$	0.55
Diluted:
Weighted average common stock outstanding		36,035			35,697			35,889			32,471
Income (loss) from continuing operations	$	(2.54	)	$	0.15		$	(4.13	)	$	0.51
Income (loss) from discontinued operations		(0.02	)		(0.03	)		(0.28	)		0.04
Net income (loss)	$	(2.56	)	$	0.12		$	(4.41	)	$	0.55

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

6

MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)

	Number of Shares		Common Stock ($0.01 Par)			Additional Paid-in- Capital			Treasury Stock			Accumulated Deficit			Total
Balances, December 31, 2018		20,169,063	$	3,043		$	2,065,119		$	(3,357	)	$	(1,377,319	)	$	687,486
Stock-based compensation		—		—			6,001			—			—			6,001
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
Reverse split 1:15		—		(2,833	)		2,833			—			—			—
Issuance of common stock upon vesting of equity-    based compensation awards, net of shares    withheld for income tax withholdings		499,897		22			(5	)		(5,411	)		—			(5,394	)
Net loss		—		—			—			—			(14,098	)		(14,098	)
Balances, March 31, 2019		35,682,480	$	382		$	2,349,527		$	(8,768	)	$	(1,391,417	)	$	949,724
Stock-based compensation		—		—			552		—			—				552
Equity issuance costs		—		—			(925	)	—			—				(925	)
Issuance of common stock upon vesting of equity-    based compensation awards, net of shares    withheld for income tax withholdings		4,727		—			—			(26	)	—				(26	)
Net income		—	—			—			—				27,512			27,512
Balances, June 30, 2019		35,687,207	$	382		$	2,349,154		$	(8,794	)	$	(1,363,905	)	$	976,837
Stock-based compensation		—		—			1,061			—			—			1,061
Issuance of restricted stock		50,568		—			—			—			—			—
Issuance of common stock upon vesting of equity-    based compensation awards, net of shares    withheld for income tax withholdings		18,313		—			(143	)		(25	)		—			(168	)
Net income		—		—			—			—			4,284			4,284
Balances, September 30, 2019		35,756,088	$	382		$	2,350,072		$	(8,819	)	$	(1,359,621	)	$	982,014

	Number of Shares		Common Stock ($0.01 Par)		Additional Paid-in- Capital			Treasury Stock			Accumulated Deficit			Total
Balances, December 31, 2019		35,770,934	$	383	$	2,352,309		$	(10,049	)	$	(1,345,557	)	$	997,086
Stock-based compensation		—		—		860			—			—			860
Issuance of common stock upon vesting of equity-    based compensation awards, net of shares    withheld for income tax withholdings		33,610		—		—			(95	)		—			(95	)
Net income		—		—		—			—			2,827			2,827
Balances, March 31, 2020		35,804,544	$	383	$	2,353,169		$	(10,144	)	$	(1,342,730	)	$	1,000,678
Stock-based compensation	—		—			1,764		—			—				1,764
Issuance of common stock upon vesting of equity-    based compensation awards, net of shares    withheld for income tax withholdings		230,293		3		(4	)		(367	)		—			(368	)
Net loss	—		—		—			—				(68,854	)		(68,854	)
Balances, June 30, 2020		36,034,837	$	386	$	2,354,929		$	(10,511	)	$	(1,411,584	)	$	933,220
Stock-based compensation		—		—		961			—			—			961
Net loss		—		—		—			—			(92,200	)		(92,200	)
Balances, September 30, 2020		36,034,837	$	386	$	2,355,890		$	(10,511	)	$	(1,503,784	)	$	841,981

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

7

MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	For the Nine Months Ended September 30,
	2020			2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(158,227	)	$	17,698
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, amortization and accretion		140,579			114,331
Exploration expense		30,311			36,193
Stock-based compensation		3,585			7,614
Impairment of oil and gas properties		6,849			—
Net cash for plugging wells		(222	)		(444	)
(Gain) loss on derivative instruments		11,329			(40,620	)
Net cash receipts on settled derivatives		61,877			11,072
Gain on sale of assets		(1,478	)		(734	)
Amortization of deferred financing costs		2,041			2,160
Amortization of debt discount		1,000			998
Changes in operating assets and liabilities:
Accounts receivable		15,437			68,056
Other assets		(126	)		619
Accounts payable and accrued liabilities		(40,124	)		(40,634	)
Net cash provided by operating activities		72,831			176,309
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for oil and gas properties		(122,019	)		(268,768	)
Capital expenditures for other property and equipment		(271	)		(576	)
Proceeds from sale of assets		1,393			1,810
Cash acquired in merger		—			12,894
Change in deposits and other long-term assets		—			(53	)
Net cash used in investing activities		(120,897	)		(254,693	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from other notes payable		1,141			—
Debt issuance costs		(80	)		(4,242	)
Repayments of long-term debt		(575	)		(260	)
Proceeds from revolving credit facility		40,000			95,000
Equity issuance costs		—			(31	)
Employee tax withholding for settlement of equity    compensation awards		(463	)		(6,511	)
Net cash provided by financing activities		40,023			83,956
Net increase (decrease) in cash and cash equivalents		(8,043	)		5,572
Cash and cash equivalents at beginning of period		12,056			5,959
Cash and cash equivalents at end of period	$	4,013		$	11,531
SUPPLEMENTAL DISCLOSURE OF CASH FLOW    INFORMATION
Cash paid for interest	$	52,590		$	51,280
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES
Asset retirement obligations incurred, including changes in estimate	$	196		$	1,006
Additions to oil and natural gas properties - changes in    accounts payable, accrued liabilities, and accrued capital expenditures	$	(18,541	)	$	16,583
BRMR Merger consideration	$	—		$	275,759

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

8

MONTAGE RESOURCES CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—Organization and Nature of Operations

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

Note 2—Basis of Presentation

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

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

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

• 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.

Proposed Merger with Southwestern Energy Company

On August 12, 2020, the Company entered into an Agreement and Plan of Merger (the “Southwestern Merger Agreement”) with Southwestern, pursuant to which the Company will merge with and into Southwestern, with Southwestern continuing as the surviving corporation (the “merger”).  On the terms and subject to the conditions set forth in the Southwestern Merger Agreement, upon consummation of the merger, each issued and outstanding share of the Company’s common stock will be converted into the right to receive 1.8656 shares of Southwestern common stock.

The merger is subject to various closing conditions, including, but not limited to, (i) the adoption of the Southwestern Merger Agreement by the holders of a majority of the Company’s outstanding common stock entitled to vote, (ii) the absence of any law, order or injunction prohibiting the merger, (iii) the expiration or earlier termination of the waiting period under the Hart–Scott–Rodino Antitrust Improvements Act of 1976, as amended (which termination was received on September 9, 2020), (iv) the SEC having declared effective Southwestern’s registration statement on Form S-4 filed in connection with the merger (which the SEC declared on October 6, 2020), (v) the shares of Southwestern common stock issuable in connection with the merger having been authorized for listing on the New York Stock Exchange, upon official notice of issuance, (vi) the accuracy of each party’s representations and warranties, and (vii) each party’s compliance with its covenants and agreements contained in the Southwestern Merger Agreement.

9

The Southwestern Merger Agreement provides for certain termination rights for both the Company and Southwestern, including the right of either party to terminate the Southwestern Merger Agreement if the merger is not consummated by February 12, 2021 (provided certain conditions are met).  Upon termination of the Southwestern Merger Agreement under specified circumstances, the Company would be required to pay Southwestern a termination fee of $9.7 million.  

In connection with the merger, Southwestern filed with the SEC, on October 2, 2020, an amendment to the registration statement on Form S-4 that was originally filed on September 16, 2020, which includes a proxy statement of the Company. The proxy statement also constitutes a prospectus of Southwestern with respect to the shares of Southwestern common stock to be issued to the Company’s stockholders pursuant to the Southwestern Merger Agreement. The registration statement was declared effective by the SEC on October 6, 2020, and the Company commenced mailing the definitive proxy statement/prospectus to the Company’s stockholders on or about October 8, 2020. The Company will hold a special meeting of its stockholders on November 12, 2020 in connection with the merger. Subject to the satisfaction or waiver of the closing conditions, the merger is expected to close in the fourth quarter of 2020.

Additional information on the proposed merger is included in the Form S-4/A filed by Southwestern with the SEC on October 2, 2020, the definitive proxy statement/prospectus filed by the Company with the SEC on October 6, 2020, and this Quarterly Report, including Part II, Item 1A.

Note 3—Summary of Significant Accounting Policies

(a) Cash and Cash Equivalents

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

(b) Accounts Receivable

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

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

(c) Property and Equipment

Oil and Natural Gas Properties

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

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

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s Condensed Consolidated Balance Sheets. Upon the sale of an entire interest in an unproved property where the property had been

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assessed for impairment individually, a gain or loss is recognized in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

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

	September 30, 2020			December 31, 2019
Oil and natural gas properties:
Unproved	$	478,644		$	508,576
Proved		2,885,622			2,783,232
Gross oil and natural gas properties		3,364,266			3,291,808
Less accumulated depreciation, depletion and amortization		(1,668,786	)		(1,532,127	)
Oil and natural gas properties, net		1,695,480			1,759,681
Other property and equipment		19,596			20,000
Less accumulated depreciation		(9,285	)		(8,774	)
Other property and equipment, net		10,311			11,226
Property and equipment, net	$	1,705,791		$	1,770,907

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

Other Property and Equipment

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

(d) Revenue Recognition

Product Revenue

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

Natural Gas

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

NGLs

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

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Oil

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

Marketing Revenue

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

Disaggregation of Revenue

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Revenues (in thousands)
Natural gas sales	$	72,926	$	87,841	$	217,604	$	264,030
NGL sales		18,439		20,200		44,949		60,841
Oil sales		17,153		44,980		52,918		103,407
Brokered natural gas and marketing revenue		6,831		10,228		23,859		31,747
Other revenue		56		46		183		307
Total revenues	$	115,405	$	163,295	$	339,513	$	460,332

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 $53.5 million and $63.7 million as of September 30, 2020 and December 31, 2019, respectively.

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(e) Concentration of Credit Risk

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

	September 30, 2020		December 31, 2019
Receivables by product or service:
Sale of oil and natural gas and related products and    services	$	53,466	$	63,730
Joint interest owners		6,983		12,156
Derivatives		1,728		210
Other		1,306		1,306
Total	$	63,483	$	77,402

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

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to the credit risk of the counterparties to these derivative instruments. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, the Company’s policy is to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. Such counterparties are not required to provide credit support to the Company. The fair value of the Company’s unsettled derivative contracts was a net liability position of ($47.7) million and a net asset position of $27.1 million as of September 30, 2020 and December 31, 2019, respectively. Other than as provided by its revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s derivative contracts. As of September 30, 2020 and December 31, 2019, the Company did not have past-due receivables from or payables to any of such counterparties.

(f) Depreciation, Depletion, Amortization and Accretion

Oil and Natural Gas Properties

Depreciation, depletion, amortization and accretion (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties, including accretion expense, totaled approximately $52.8 million and $44.9 million for the three months ended September 30, 2020 and 2019, respectively, and $138.9 million and $112.4 million for the nine months ended September 30, 2020 and 2019, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from five to 40 years. Depreciation totaled approximately $0.4 million and $0.6 million for the three months ended September 30, 2020 and 2019, respectively, and $1.2 million and $1.6 million for the nine months ended September 30, 2020 and 2019, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

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(g) Impairment of Long-Lived Assets

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

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

When an impairment charge is recognized it represents a significant Level 3 measurement in the fair value hierarchy. The primary input used is the Company’s forecasted discount net cash flows.

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

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of approximately $11.0 million and $14.1 million for the three months ended September 30, 2020 and 2019, respectively, and $30.3 million and $36.2 million for the nine months ended September 30, 2020 and 2019, respectively. These costs are included in exploration expense in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

(h) Income Taxes

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

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

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(i) Fair Value of Financial Instruments

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

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

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

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

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

(j) Derivative Financial Instruments

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

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

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

(k) Asset Retirement Obligation

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

Estimating the future ARO requires management to make estimates and judgments based on historical information regarding timing and existence of a liability, as well as what constitutes adequate restoration.  Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

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Approximately $2.9 million and $2.0 million, representing the current portion of ARO liability, are included in “Accrued liabilities” in the accompanying Condensed Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019, respectively.  The following table sets forth the changes in the Company’s ARO liability for the nine months ended September 30, 2020 (in thousands):

	Nine Months Ended September 30, 2020
Asset retirement obligations, beginning of period	$	31,841
Accretion		2,245
Additional liabilities incurred		15
Obligation for wells drilled		181
Liabilities settled via plugging		(178	)
Liabilities sold/disposed		(901	)
Less: current ARO portion		(2,867	)
Asset retirement obligations, end of period	$	30,336

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

(l) Off-Balance Sheet Arrangements

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

(m) Segment Reporting

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

(n) Debt Issuance Costs

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

During the three and nine months ended September 30, 2020, the Company amortized $0.9 million and $3.0 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method which includes $0.2 million of unamortized deferred financing costs that the Company wrote off during the second quarter of 2020 in connection with the borrowing base redetermination of the Company’s revolving credit facility (See Note 8— Debt).  During the three and nine months ended September 30, 2019, the Company amortized $0.9 million and $3.2 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method. 

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(o) Recent Accounting Pronouncements

Accounting Pronouncements Not Yet Adopted

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

Note 4—Acquisitions

Merger with Blue Ridge Mountain Resources

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

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

In connection with the BRMR Merger, the Company incurred $3.3 million of costs for the three months ended September 30, 2019, and $0.2 million and $21.8 million for the nine months ended September 30, 2020 and 2019, respectively, which are included in general and administrative expense on the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).  The Company did not incur any costs during the three months ended September 30, 2020 in connection with the BRMR Merger.  Approximately $100.5 million of revenues and approximately $16.0 million of net income from continuing operations attributed to the BRMR Merger are included in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to September 30, 2019.  Approximately $5.4 million of revenues and approximately $1.3 million of net income from discontinued operations attributed to the BRMR Merger are included in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to September 30, 2019.

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

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.

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

	Three Months Ended September 30,		Nine Months Ended September 30,
(in thousands, except per share data) (unaudited)	2019		2019
Pro forma total revenues	$	163,295	$	502,989
Pro forma net income	$	4,543	$	24,834
Pro forma net income per share (basic)	$	0.13	$	0.70
Pro forma net income per share (diluted)	$	0.13	$	0.69

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Note 5—Assets Held for Sale and Discontinued Operations

Assets Held for Sale

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

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

(in thousands)	September 30, 2020		December 31, 2019
Accounts receivable	$	758	$	343
Other current assets		786		704
Total current assets held for sale	$	1,544	$	1,047
Proved oil and gas properties, net	$	3,351	$	9,528
Other noncurrent assets		52		137
Total noncurrent assets held for sale	$	3,403	$	9,665
Accounts payable	$	2,104	$	2,067
Accrued liabilities		1,576		570
Other current liabilities		31		178
Total current liabilities associated with assets held for sale	$	3,711	$	2,815
Asset retirement obligations	$	7,146	$	6,488
Other liabilities		4		525
Total noncurrent liabilities associated with assets held for sale	$	7,150	$	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 the three and nine months ended September 30, 2020 and 2019.  The Company included the results of operations for MHP for the three and nine months ended September 30, 2020 and 2019 in discontinued operations as follows:

(in thousands)	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
Revenues	$	698		$	1,874		$	2,948		$	5,402
Impairment of proved oil and natural gas properties		—			—			(6,849	)		—
Depreciation, depletion, amortization and accretion		(182	)		(168	)		(523	)		(380	)
Other operating expenses		(1,317	)		(2,943	)		(5,668	)		(3,738	)
Other income		—			—			—			2
Income (loss) from discontinued operations, net of tax	$	(801	)	$	(1,237	)	$	(10,092	)	$	1,286

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

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

19

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

(in thousands)	Nine Months Ended September 30,
	2020			2019
Net cash provided by operating activities	$	693		$	1,189
Net cash provided by (used in) investing activities	$	(82	)	$	14

Note 6—Derivative Instruments

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

Commodity Derivatives

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

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

20

Natural Gas Derivatives:

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		130,000	October 2020 – December 2020	$	2.42
		145,000	October 2020 – March 2021	$	2.58
		50,000	January 2021 – March 2022	$	2.51
		25,000	April 2021 – March 2022	$	2.47
Natural Gas Collars:
Floor purchase price (put)		25,000	January 2021 – December 2021	$	2.15
Ceiling sold price (call)		25,000	January 2021 – December 2021	$	3.03
Floor purchase price (put)		30,000	April 2021 – March 2022	$	2.40
Ceiling sold price (call)		30,000	April 2021 – March 2022	$	3.05
Floor purchase price (put)		15,000	August 2021 – December 2021	$	2.55
Ceiling sold price (call)		15,000	August 2021 – December 2021	$	3.13
Floor purchase price (put)		15,000	September 2021 – November 2021	$	2.52
Ceiling sold price (call)		15,000	September 2021 – November 2021	$	3.12
Floor purchase price (put)		5,000	August 2021	$	2.50
Ceiling sold price (call)		5,000	August 2021	$	3.05
Floor purchase price (put)		10,000	September 2021	$	2.50
Ceiling sold price (call)		10,000	September 2021	$	3.03
Natural Gas Three-way Collars:
Floor purchase price (put)		80,000	October 2020 – December 2020	$	2.60
Floor sold price (put)		80,000	October 2020 – December 2020	$	1.90
Ceiling sold price (call)		80,000	October 2020 – December 2020	$	2.94
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
Floor purchase price (put)		20,000	April 2021 – March 2022	$	2.62
Floor sold price (put)		20,000	April 2021 – March 2022	$	2.20
Ceiling sold price (call)		20,000	April 2021 – March 2022	$	3.10
Natural Gas Call/Put Options:
Floor sold price (put)		50,000	October 2020 – December 2020	$	2.30
Swaption sold price (call)		50,000	January 2021 – December 2021	$	2.75
Swaption sold price (call)		50,000	January 2022 – December 2022	$	3.00
Ceiling sold price (call)		50,000	January 2022 – December 2022	$	3.00
Floor sold price (put)		50,000	January 2021 – March 2022	$	2.00
Ceiling sold price (call)		80,000	January 2023 – December 2023	$	3.00
Basis Swaps:
Appalachia - Dominion		42,500	October 2020	$	(0.51	)
Appalachia - Dominion		20,000	October 2020 – December 2020	$	(0.59	)

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Oil Derivatives:

Description	Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)
Oil Swaps:
		2,500	October 2020 – December 2020	$	57.41
		250	October 2020 – March 2021	$	53.20
		250	January 2021 – March 2021	$	53.00
		100	January 2021	$	43.60
Oil Collars:
Floor purchase price (put)		1,000	October 2020 – December 2020	$	51.00
Ceiling sold price (call)		1,000	October 2020 – December 2020	$	62.00
Floor purchase price (put)		500	January 2021 – December 2021	$	37.50
Ceiling sold price (call)		500	January 2021 – December 2021	$	45.50
Floor purchase price (put)		300	April 2021	$	40.00
Ceiling sold price (call)		300	April 2021	$	47.25
Floor purchase price (put)		200	May 2021	$	40.00
Ceiling sold price (call)		200	May 2021	$	47.55
Floor purchase price (put)		100	June 2021	$	40.00
Ceiling sold price (call)		100	June 2021	$	47.75
Oil Three-way Collars:
Floor purchase price (put)		500	January 2021 – December 2021	$	31.25
Floor sold price (put)		500	January 2021 – December 2021	$	22.50
Ceiling sold price (call)		500	January 2021 – December 2021	$	45.00
Oil Call/Put Options:
Floor sold price (put)		500	October 2020 – December 2020	$	45.00
Swaption sold price (call)		500	January 2021 – December 2021	$	42.50

NGL Derivatives:

Description	Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)
Propane Swaps:
		2,000	October 2020 – December 2020	$	20.94
		1,000	January 2021 – December 2021	$	18.87

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Interest Rate Swap

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

Fair Values and Gains (Losses)

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

As of September 30, 2020	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	7,423		$	(4,213	)		3,210		Other current assets
Total assets	$	7,423		$	(4,213	)	$	3,210
Liabilities
Commodity derivatives - current	$	(27,338	)	$	4,213		$	(23,125	)	Accrued liabilities
Interest-rate swap - current		(103	)		—			(103	)	Accrued liabilities
Commodity derivatives - noncurrent		(27,269	)		—			(27,269	)	Other liabilities
Interest-rate swap - noncurrent		(404	)		—			(404	)	Other liabilities
Total liabilities	$	(55,114	)	$	4,213		$	(50,901	)

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	)

(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.

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

		Amount of Gain (Loss) Recognized in Income
Derivatives not designated as hedging instruments under ASC 815	Location of Gain (Loss) Recognized in Income	Three Months Ended September 30,					Nine Months Ended September 30,
		2020			2019		2020			2019
Commodity derivatives	Gain (loss) on derivative instruments	$	(40,603	)	$	15,812	$	(10,861	)	$	40,620
Interest-rate swap	Gain (loss) on derivative instruments		68			—		(468	)		—
Total		$	(40,535	)	$	15,812	$	(11,329	)	$	40,620

Note 7—Fair Value Measurements

Fair Value Measurement on a Recurring Basis

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

	Level 1		Level 2			Level 3		Total Fair Value
As of September 30, 2020: (in thousands)
Commodity derivative instruments	$	—	$	(47,184	)	$	—	$	(47,184	)
Interest-rate swap		—		(507	)		—		(507	)
Total	$	—	$	(47,691	)	$	—	$	(47,691	)
As of December 31, 2019: (in thousands)
Commodity derivative instruments	$	—	$	27,117		$	—	$	27,117
Total	$	—	$	27,117		$	—	$	27,117

Nonfinancial Assets and Liabilities

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

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

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

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Note 8—Debt

8.875% Senior Unsecured Notes Due 2023

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

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

On October 6, 2020, the Company notified the trustee under the indenture that the Company had elected to redeem, subject to certain conditions (the “Redemption”), all of its outstanding senior unsecured notes. On October 9, 2020, the Company issued a conditional notice of full redemption to redeem all of its outstanding senior unsecured notes. The anticipated redemption date is November 13, 2020 (the “Redemption Date”). The redemption price for the senior unsecured notes will be 102.219% (the “Redemption Price”) of the aggregate principal amount being redeemed, plus accrued but unpaid interest on the senior unsecured notes redeemed to, but not including, the Redemption Date. Upon the Redemption by the Company of the senior unsecured notes, none of the senior unsecured notes will remain outstanding.    

Redemption of the senior unsecured notes is conditional on the consummation of the transactions set forth in the Southwestern Merger Agreement, pursuant to which, on the terms and subject to the conditions set forth therein, among other things, (i) the Company will merge with and into Southwestern, with Southwestern continuing as the surviving company, and (ii) Southwestern will deposit cash proceeds with the trustee under the indenture in an amount at least sufficient to pay and discharge the Redemption Price, all accrued and unpaid interest on the senior unsecured notes redeemed to, but not including, the Redemption Date and all other amounts owing under the indenture. The Company may delay the Redemption Date until such time as the foregoing conditions are satisfied, or such redemption may not occur and the conditional notice of redemption may be rescinded in the event that the foregoing conditions are not satisfied by the Redemption Date, or by such later date to which the Redemption Date has been delayed.

Based on Level 2 market data inputs, the fair value of the senior unsecured notes as of September 30, 2020 was $519.0 million.

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Revolving Credit Facility

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

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

On September 28, 2020, the Company entered into a letter agreement with its lenders to, among other things, (i) postpone the scheduled redetermination of the borrowing base under the Credit Agreement from October 1, 2020 until on or about November 15, 2020, (ii) obtain the lenders’ consent to the Company’s sending of a notice of redemption to the holders of the Company’s senior unsecured notes in accordance with the terms of the Southwestern Merger Agreement, and (iii) obtain the lenders’ consent to the redemption of the senior unsecured notes in full; provided, that such redemption occurs concurrently with the date that the secured obligations under the Credit Agreement are paid in full in cash and the transactions contemplated by the Southwestern Merger Agreement are consummated.

As of September 30, 2020, the borrowing base was $475 million and the Company had $170.0 million in outstanding borrowings under the revolving credit facility. After giving effect to outstanding letters of credit issued by the Company totaling $29.2 million and the outstanding borrowings of $170.0 million, the Company had available borrowing capacity under the revolving credit facility of $275.8 million as of September 30, 2020.  

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

Other Notes Payable

From time to time, the Company enters into other notes payable for the purchase of vehicles and equipment or to finance its insurance premiums.  The Company had outstanding notes payable of $0.8 million and $0.3 million included in “Accrued liabilities” in the accompanying Condensed Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019, respectively.

Note 9—Benefit Plans

Defined Contribution Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(k) of the Internal Revenue Code, as amended (the “Code”), under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(k) plan, the Company provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company recorded compensation expense related to matching contributions, classified under general and administrative, of $0.2 million and $0.3 million for the three months ended September 30, 2020 and 2019, respectively, and $0.9 million and $0.8 million for the nine months ended September 30, 2020 and 2019, respectively.

26

Note 10—Stock-Based Compensation

The Company is authorized to grant up to 2,650,000 shares of common stock under its 2019 Long-Term Incentive Plan (the “2019 Plan”).  The 2019 Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, bonus stock or other stock-based awards and performance awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 303,911 shares were available for future grants under the Plan as of September 30, 2020.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Restricted stock units	$	357	$	445	$	1,424	$	3,773
Performance units		535		374		1,226		3,364
Restricted and unrestricted stock		69		242		935		477
Total expense	$	961	$	1,061	$	3,585	$	7,614

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 September 30, 2020, there was $3.1 million of total unrecognized compensation cost related to outstanding 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 nine months ended September 30, 2020 is as follows:

	Number of units			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2019		437,559		$	7.83	$	3,474
Granted		351,467			5.86
Vested		(214,804	)		9.14
Forfeited		(3,023	)		6.02
Total awarded and unvested, September 30, 2020		571,199		$	6.14	$	2,508

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Performance Units

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

As of September 30, 2020, there was $4.1 million of total unrecognized compensation cost related to outstanding performance units. The weighted average period for the units to vest is approximately two years. A summary of performance stock unit awards activity during the nine months ended September 30, 2020 is as follows:

	Number of units			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2019		320,120		$	11.26	$	2,522
Granted		618,483			6.21
Vested		(51,858	)		20.89
Forfeited		(55,547	)		16.69
Total awarded and unvested, September 30, 2020		831,198		$	6.54	$	932

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

	Nine Months Ended September 30,
	2020			2019
Volatility		79.70	%		65.10	%
Risk-free interest rate		0.20	%		1.83	%

Restricted and Unrestricted Stock

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

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

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

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

As of September 30, 2020, there was $0.2 million of total unrecognized compensation cost related to restricted and unrestricted stock.

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Note 11—Net Income (Loss) Per Share

Net Income (Loss) Per Share

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

Reverse Stock Split

Effective immediately prior to the effective time of the BRMR Merger, on February 28, 2019 (See Note 4— Acquisitions), the Company effected a 15-to-1 reverse stock split of its common stock.  Holders of shares of the Company’s common stock immediately prior to the effective time received cash for any fractional shares of the Company’s common stock to which they might otherwise have been entitled as a result of the reverse stock split. The reverse stock split lowered the aggregate par value of the common stock reflected in the Consolidated Statements of Stockholders’ Equity to reflect the reduced shares with the offset to additional paid-in-capital.  The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the three and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,
(in thousands, except per share data)	2020								2019
	Loss			Shares		Per Share			Income		Shares		Per Share
Basic:
Net income (loss), shares, basic	$	(92,200	)		36,035	$	(2.56	)	$	4,284		35,684	$	0.12
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—			—					—		13
Diluted:
Net income (loss), shares, diluted	$	(92,200	)		36,035	$	(2.56	)	$	4,284		35,697	$	0.12

	Nine Months Ended September 30,
(in thousands, except per share data)	2020								2019
	Loss			Shares		Per Share			Income		Shares		Per Share
Basic:
Net income (loss), shares, basic	$	(158,227	)		35,889	$	(4.41	)	$	17,698		32,343	$	0.55
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—			—					—		128
Diluted:
Net income (loss), shares, diluted	$	(158,227	)		35,889	$	(4.41	)	$	17,698		32,471	$	0.55

Note 12—Commitments and Contingencies

(a) Legal Matters

From time to time, the Company is 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 any legal proceedings to which the Company is a party.

Following the announcement of the Southwestern Merger Agreement, six complaints have been filed by purported Company stockholders challenging the merger; of those six complaints, three were filed in the United States District Court for the Southern District of New York, one in the United States District Court for the Eastern District of New York, one in the United States District Court for the District of Delaware and one in the Supreme Court of the State of New York, County of New York. The complaints are captioned as follows: Dinardo v. Montage Resources Corporation, et al., No. 1:20-cv-08416 (S.D.N.Y.); Raul v. Montage Resources Corporation, et al., No. 1:20-cv-08619 (S.D.N.Y.); Waldrop v. Montage Resources Corporation, et al., No. 1:20-cv-04995 (E.D.N.Y.); Wolf v. Montage Resources Corporation, et al., No. 1:20-cv-01324-UNA (D. Del.); Gordon v. Montage Resources

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Corporation, et al. (Supreme Court of the State of New York, County of New York); and Widrick v. Montage Resources Corporation, et al. No. 1:20-cv-09101 (S.D.N.Y.).

The complaints name as defendants the Company and the Company’s directors, and two of the six complaints also name Southwestern as defendant. The complaints generally assert claims under Sections 14(a) and 20(a) of the Exchange Act, alleging, among other things, that the registration statement on Form S-4, originally filed on September 16, 2020, omits material information with respect to the merger and/or assert claims for breach of fiduciary duty under Delaware law against the Company and its directors. The complaints generally seek to enjoin the merger and seek rescission and rescissory damages, including attorneys’ fees, among other relief. The Company and Southwestern believe the claims are meritless.

(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 March 2020, the Company completed the renegotiation of certain existing gas gathering contracts with a midstream service provider into a single new consolidated gas gathering agreement.  Revised commitments under the new consolidated gas gathering agreement (in thousands) are included in the table below:

	Firm transportation(i)		Gas processing, gathering, and compression services(ii)		Total
Year Ending December 31:
Remainder of 2020	$	25,025	$	11,132	$	36,157
2021		99,828		44,801		144,629
2022		99,828		49,404		149,232
2023		99,828		52,342		152,170
2024		100,101		52,972		153,073
Thereafter		722,369		303,890		1,026,259
Total	$	1,146,979	$	514,541	$	1,661,520

(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 rates. The values in the table represent the gross amounts that the Company is committed to pay and do not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company records in its Condensed 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 do not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company records in its Condensed Consolidated Financial Statements its proportionate share of costs based on the Company’s working interest.

Note 13—Income Tax

For the year ending December 31, 2020, the Company’s annual estimated effective tax rate is forecasted to be 0%, exclusive of discrete items.  The Company expects to incur a book loss and a tax loss in fiscal year 2020, and thus, no current federal income taxes are anticipated to be paid.  The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective tax rate to the Company’s year-to-date loss.  On December 22, 2017, Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, resulted in the reduction in the U.S. statutory rate for corporations from 35% to 21%.  The Company’s interest expense deduction has the potential to be limited as a result of the enactment of the Tax Cuts and Jobs Act and the

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federal Coronavirus Aid, Relief, and Economic Security Act; however, the impact is anticipated to be minimal as a result of its full valuation allowance.

In forecasting the 2020 annual estimated effective tax rate, management believes that it should limit any tax benefit suggested by the tax effect of the forecasted book loss such that no net deferred tax asset is recorded in 2020. Management reached this conclusion considering several factors such as: (i) the lack of carryback potential resulting in a tax refund, and (ii) in light of current commodity pricing uncertainty, there is insufficient external evidence to suggest that net tax attribute carryforwards are collectible beyond offsetting existing deferred tax liabilities inherent in the Company’s Condensed Consolidated Balance Sheet.

The Company is forecasting pre-tax book loss for the year ending December 31, 2020.  As a result, no net income tax expense or benefit is allocable to either income from continuing operations or to discontinued operations.

In connection with the BRMR Merger (See Note 4— Acquisitions), the Company experienced an ownership change as described in Section 382 of the Code.  As a result, the Company’s net operating losses as well as certain tax deductions are subject to an annual limitation imposed by the 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.

Note 14—Subsidiary Guarantors

Each subsidiary of the Company that guarantees the Company’s revolving credit facility is required to fully and unconditionally, jointly 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 8—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 senior unsecured notes 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 15—Subsequent Events

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

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2019 and our Condensed Consolidated Financial Statements and related notes appearing elsewhere in this Quarterly Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. See “Cautionary Statement Regarding Forward-Looking Statements.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview of Our Business

We are an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin.  On February 28, 2019, we completed a business combination (the “BRMR Merger”) with Blue Ridge Mountain Resources, Inc. (“BRMR”), and immediately thereafter, we changed our legal name from “Eclipse Resources Corporation” to “Montage Resources Corporation.”  Except where the context indicates otherwise, the terms “we,” “us,” “our” or the “Company” as used herein refer, for periods prior to the completion of the BRMR Merger, to Eclipse Resources Corporation and its subsidiaries and, for periods following the completion of the BRMR Merger, to Montage Resources Corporation and its subsidiaries.

As of September 30, 2020, we had assembled an acreage position approximating 233,000 net surface acres in Eastern Ohio, 33,300 net surface acres in Pennsylvania, and 54,300 net surface acres in West Virginia, which excludes any acreage currently pending title.

Approximately 178,600 of our net acres are located in the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately 58,800 net acres of stacked pay opportunity are also prospective for the highly liquids rich area of the Marcellus Shale in Eastern Ohio and West Virginia within what we refer to as our Marcellus Area. We are the operator of approximately 98% of our net acreage within the Utica Core Area and our Marcellus Area. We intend to focus on developing our substantial inventory of horizontal drilling locations during commodity price environments that will allow us to generate attractive returns and will continue to opportunistically add to this acreage position where we can acquire acreage at attractive prices.

As of September 30, 2020, we were not operating any rigs. We had average daily production for the three months ended September 30, 2020 of approximately 602.6 MMcfe comprised of approximately 82% natural gas, 12% NGLs and 6% oil.

The net assets of our subsidiary, Magnum Hunter Production, Inc. (“MHP”), are classified as assets held for sale and liabilities associated with assets held for sale as of September 30, 2020 and 2019.  All operations of MHP are reflected as discontinued operations for all periods presented.

Proposed Merger with Southwestern Energy Company

On August 12, 2020, the Company entered into an Agreement and Plan of Merger (the “Southwestern Merger Agreement”) with Southwestern Energy Company (“Southwestern”), pursuant to which the Company will merge with and into Southwestern, with Southwestern continuing as the surviving corporation (the “merger”).  On the terms and subject to the conditions set forth in the Southwestern Merger Agreement, upon consummation of the merger, each issued and outstanding share of the Company’s common stock will be converted into the right to receive 1.8656 shares of Southwestern common stock. Subject to the satisfaction or waiver of the closing conditions set forth in the Southwestern Merger Agreement, the merger is expected to close in the fourth quarter of 2020.

See Note 2—Basis of Presentation to our Condensed Consolidated Financial Statements for more information regarding the merger.

COVID-19

In March 2020, the World Health Organization declared the COVID-19 outbreak a pandemic. Governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which have caused a significant decrease in activity in the global economy and the demand for oil, and to a lesser extent, natural gas and NGLs.  Late in the second quarter of 2020, certain states and local governments began the measured process of loosening restrictions, allowing businesses to reopen on a limited basis and lifting stay-at-home orders.

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While we did not incur significant disruptions to operations during the three or nine months ended September 30, 2020 as a direct result of the COVID-19 pandemic, we are unable to predict the impact that the COVID-19 pandemic will have on us, including on our financial position, operating results, liquidity and ability to obtain financing, in future reporting periods, due to numerous uncertainties. These uncertainties include the severity of the virus, the duration of the pandemic, governmental or other actions taken to combat the virus (which could include limitations on our operations or the operations of our customers and vendors and other business partners), and the effect that the COVID-19 pandemic will have on the demand for natural gas, NGLs and oil. The health of our employees, customers, contractors and vendors, and our ability to meet staffing needs in our operations and certain critical functions, are vital to our operations, and the effect of the pandemic on these persons and our staffing needs cannot be predicted. Further, the impacts of a potential worsening of global economic conditions and the continued disruptions to, and volatility in, the credit and financial markets as well as other unanticipated consequences remain unknown. In addition, we cannot predict the impact that COVID-19 will have on our customers, vendors and contractors; however, any material effect on these parties could adversely impact us.

Due to the downward oil price movement and demand destruction from the COVID-19 pandemic, we shut-in low margin production in our Utica condensate area in April and May 2020.  We have since brought that condensate production back online with the improvement of oil prices and cash margins, and the curtailed production had a negligible impact on our cash flows.

For further information regarding the impact of COVID-19, see Part II, Item 1A of this Quarterly Report.

How We Evaluate Our Operations

In evaluating our current and future financial results, we focus on production and revenue growth, lease operating expense, general and administrative expense (both before and after non-cash stock compensation expense and other unusual or infrequent items) and operating margin per unit of production. In addition to these metrics, we use Adjusted EBITDAX, a non-GAAP measure, to evaluate our financial results. We define Adjusted EBITDAX as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; depreciation, depletion, amortization and accretion (“DD&A”); gain (loss) on derivative instruments, net cash receipts (payments) on settled commodity derivative instruments, and premiums (paid) received on options that settled during the period; non-cash compensation expense; gain or loss from sale of interest in gas properties; exploration expenses; and other unusual or infrequent items. Adjusted EBITDAX is not a measure of net income as determined by generally accepted accounting principles in United States, or “U.S. GAAP.”  See —Non-GAAP Financial Measure for more information.

In addition to the operating metrics above, as we grow our reserve base, we will assess our capital spending by calculating our operated proved developed reserves and our operated proved developed finding costs and development costs. We believe that operated proved developed finding and development costs are one of the key measurements of the performance of an oil and gas exploration and production company. We will focus on our operated properties as we control the location, spending and operations associated with drilling these properties. In determining our proved developed finding and development costs, only cash costs incurred in connection with exploration and development will be used in the calculation, while the costs of acquisitions will be excluded because our board approves each material acquisition. In evaluating our proved developed reserve additions, any reserve revisions for changes in commodity prices between years will be excluded from the assessment, but any performance related reserve revisions are included.

We also continually evaluate our rates of return on invested capital in our wells. We believe the quality of our assets combined with our technical and managerial expertise can generate attractive rates of return as we develop our acreage in the Utica Core Area and our Marcellus Area. We review changes in drilling and completion costs, lease operating costs, natural gas, NGLs and oil prices, well productivity, and other factors in order to focus our drilling on the highest rate of return areas within our acreage on a per well basis.

As a result of the closing of the BRMR Merger on February 28, 2019, BRMR’s revenues and expenses are included in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to September 30, 2019 (See Note 4— Acquisitions) and for all subsequent periods.

Overview of Results for the Three and Nine Months Ended September 30, 2020

During the three months ended September 30, 2020, we achieved the following financial and operating results:

• our average daily net production for the three months ended September 30, 2020 was 602.6 MMcfe per day representing a decrease of 3% over the comparable period of the prior year;

• commenced drilling 2 gross (1.7 net) operated wells and turned-to-sales 4 gross (2.4 net) operated wells;

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• recognized net loss of ($92.2) million for the three months ended September 30, 2020 compared to net income of $4.3 million for the three months ended September 30, 2019; and

• realized Adjusted EBITDAX of $51.0 million for the three months ended September 30, 2020 compared to $83.6 million for three months ended September 30, 2019. Adjusted EBITDAX is a non-GAAP financial measure. See —Non-GAAP Financial Measure for more information.

During the nine months ended September 30, 2020, we achieved the following financial and operating results:

• our average daily net production for the nine months ended September 30, 2020 was 588.4 MMcfe per day representing an increase of 13% over the comparable period of the prior year;

• commenced drilling 11 gross (8.7 net) operated wells, commenced completions of 11 gross (8.5 net) operated wells and turned-to-sales 14 gross (11.3 net) operated wells;

• recognized net loss of ($158.2) million for the nine months ended September 30, 2020 compared to net income of $17.7 million for the nine months ended September 30, 2019; and

• realized Adjusted EBITDAX of $151.2 million for the nine months ended September 30, 2020 compared to $223.5 million for the nine months ended September 30, 2019.  Adjusted EBITDAX is a non-GAAP financial measure. See “—Non-GAAP Financial Measure” for more information.

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Prices for commodities, such as hydrocarbons, are inherently volatile. The following table lists the high, low and average daily and monthly settled NYMEX Henry Hub prices for natural gas and the high, low and average daily NYMEX WTI prices for oil for the three and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020			2019
NYMEX Henry Hub High ($/MMBtu)	$	2.57	$	2.75	$	2.57		$	4.25
NYMEX Henry Hub Low ($/MMBtu)		1.33		2.02		1.33			2.02
Average Daily NYMEX Henry Hub ($/MMBtu)		2.00		2.38		1.87			2.62
Average Monthly Settled NYMEX Henry Hub ($/MMBtu)		1.98		2.23		1.88			2.67
NYMEX WTI High ($/Bbl)	$	43.21	$	63.10	$	63.27		$	66.24
NYMEX WTI Low ($/Bbl)		36.87		51.14		(36.98	)		46.31
Average Daily NYMEX WTI ($/Bbl)		40.89		56.34		38.04			57.04

Historically, commodity prices have been extremely volatile, and we expect this volatility to continue for the foreseeable future. A decline in commodity prices could materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and noncancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.

The Company is committed to profitably developing its natural gas, NGLs and oil reserves through an environmentally-responsible and cost-effective operational plan.  The Company’s revenues, earnings, liquidity and ability to grow are substantially dependent on the prices it receives for, and the Company’s ability to develop, its reserves.  Despite the continued low price commodity environment, the Company believes the long-term outlook for its business is favorable due to the Company’s resource base, low cost structure, risk management strategies, and disciplined investment of capital.

It is difficult to quantify the impact of changes in future commodity prices on our reported estimated net proved reserves with any degree of certainty because of the various components and assumptions used in the process.  However, to demonstrate the sensitivity of our estimates of natural gas, NGLs and oil reserves to changes in commodity prices, we provided an analysis in our Annual Report on Form 10-K for the year ended December 31, 2019.  Further, if we recalculated our reserves using the unweighted arithmetic average first-day-of-the-month price for each of the 12 months in the period ended September 30, 2020 and held all other factors constant, then our estimated net proved reserves at December 31, 2019 would have decreased by approximately 34.2% from our previously reported estimated net proved reserves at such time, including a 9.7% reduction of proved developed reserves and a 63.7% reduction of proved undeveloped reserves.  The foregoing estimate is based upon an average SEC benchmark price of $1.97

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per MMBtu for natural gas and $43.63 per Bbl for oil and NGLs. This calculation only isolates the potential impact of commodity prices on our estimated proved reserves and does not account for other factors impacting our estimated proved reserves, such as anticipated drilling and completion costs and our production results since December 31, 2019. There are also numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods. As such, this calculation is provided for illustrative purposes only and should not be construed as indicative of our final year-end reserve estimation process.

We consider future commodity prices when determining our development plan, but many other factors are also considered.  To the extent there is a significant increase or decrease in commodity prices in the future, we will assess the impact on our development plan at that time, and we may respond to such changes by altering our capital budget or our development plan. We plan to fund our development budget with a portion of the cash on hand as of September 30, 2020, cash flows from operations and borrowings under our revolving credit facility.

Results of Operations

The following discussion pertains to our results of operations, including analysis of our continuing operations regarding natural gas, NGLs and oil revenues, production, average product prices and average production costs and expenses for the three and nine months ended September 30, 2020 and 2019.  The results of operations of MHP are reflected as discontinued operations for all periods presented.  

Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

The following table illustrates the revenue attributable to our operations for the three months ended September 30, 2020 and 2019:

	Three Months Ended September 30,
	2020		2019		Change
Revenues (in thousands)
Natural gas sales	$	72,926	$	87,841	$	(14,915	)
NGL sales		18,439		20,200		(1,761	)
Oil sales		17,153		44,980		(27,827	)
Brokered natural gas and marketing revenue		6,831		10,228		(3,397	)
Other revenue		56		46		10
Total revenues	$	115,405	$	163,295	$	(47,890	)

Our production decreased by approximately 1.8 Bcfe for the three months ended September 30, 2020 over the same period in 2019 due to natural decline as we decreased drilling activity. Our production for the three months ended September 30, 2020 and 2019 is set forth in the following table:

	Three Months Ended September 30,
	2020		2019		Change
Production:
Natural gas (MMcf)		45,333.6		43,289.9		2,043.7
NGLs (Mbbls)		1,150.6		1,401.1		(250.5	)
Oil (Mbbls)		533.3		916.2		(382.9	)
Total (MMcfe)		55,437.0		57,193.7		(1,756.7	)
Average daily production volume:
Natural gas (Mcf/d)		492,757		470,542		22,215
NGLs (Bbls/d)		12,507		15,229		(2,722	)
Oil (Bbls/d)		5,797		9,959		(4,162	)
Total (Mcfe/d)		602,576		621,670		(19,094	)

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Our average realized price (including cash settled commodity derivatives and firm transportation) received during the three months ended September 30, 2020 was $1.95 per Mcfe compared to $2.56 per Mcfe during the three months ended September 30, 2019. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices of production volumes should include the total impact of firm transportation expense. Our average realized price (including all cash settled commodity derivatives and firm transportation) calculation also includes all cash settlements for commodity derivatives. Average realized price (excluding cash settled commodity derivatives and firm transportation) does not include commodity derivative settlements or firm transportation, which are reported in transportation, gathering and compression expense on the accompanying Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). Average realized price (including firm transportation and excluding cash settled commodity derivatives) does include transportation costs where we receive net revenue proceeds from purchasers. Average realized price calculations for the three months ended September 30, 2020 and 2019 are shown below:

	Three Months Ended September 30,
	2020		2019		Change
Average realized price (excluding cash settled commodity    derivatives and firm transportation)
Natural gas ($/Mcf)	$	1.61	$	2.03	$	(0.42	)
NGLs ($/Bbl)		16.03		14.42		1.61
Oil ($/Bbl)		32.16		49.09		(16.93	)
Total average prices ($/Mcfe)		1.96		2.68		(0.72	)
Average realized price (including cash settled commodity    derivatives, excluding firm transportation)
Natural gas ($/Mcf)	$	1.92	$	2.28	$	(0.36	)
NGLs ($/Bbl)		16.00		14.92		1.08
Oil ($/Bbl)		40.76		49.53		(8.77	)
Total average prices ($/Mcfe)		2.30		2.88		(0.58	)
Average realized price (including firm transportation,    excluding cash settled commodity derivatives)
Natural gas ($/Mcf)	$	1.18	$	1.60	$	(0.42	)
NGLs ($/Bbl)		16.03		14.42		1.61
Oil ($/Bbl)		32.16		49.09		(16.93	)
Total average prices ($/Mcfe)		1.61		2.35		(0.74	)
Average realized price (including cash settled commodity    derivatives and firm transportation)
Natural gas ($/Mcf)	$	1.50	$	1.85	$	(0.35	)
NGLs ($/Bbl)		16.00		14.92		1.08
Oil ($/Bbl)		40.76		49.53		(8.77	)
Total average prices ($/Mcfe)		1.95		2.56		(0.61	)

Brokered natural gas and marketing revenue was $6.8 million and $10.2 million for the three months ended September 30, 2020 and 2019, respectively.  Brokered natural gas and marketing revenue includes revenue received from selling natural gas not related to production and from the release of firm transportation capacity.  The decrease for the three months ended September 30, 2020 was due to increased utilization of our firm transportation capacity for operated production during the three months ended September 30, 2020, which resulted in a decrease in the amount of firm transportation that was available for brokered gas transactions or release to third parties.

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Costs and Expenses

We believe some of our expense fluctuations are most accurately analyzed on a unit-of-production, or per Mcfe, basis. The following table presents these expenses for the three months ended September 30, 2020 and 2019:

	Three Months Ended September 30,
	2020		2019		Change
Operating expenses (in thousands):
Lease operating	$	11,494	$	11,986	$	(492	)
Transportation, gathering and compression		51,961		57,027		(5,066	)
Production and ad valorem taxes		3,677		1,660		2,017
Depreciation, depletion, amortization and accretion		53,153		45,456		7,697
General and administrative		12,144		14,580		(2,436	)
Operating expenses per Mcfe:
Lease operating	$	0.21	$	0.21	$	—
Transportation, gathering and compression		0.93		0.99		(0.06	)
Production and ad valorem taxes		0.07		0.03		0.04
Depreciation, depletion, amortization and accretion		0.96		0.79		0.17
General and administrative		0.22		0.25		(0.03	)

Lease operating expense was $11.5 million in the three months ended September 30, 2020 compared to $12.0 million in the three months ended September 30, 2019.  Lease operating expense per Mcfe was $0.21 in each of the three months ended September 30, 2020 and 2019.  The decrease of $0.5 million was primarily attributable to a decrease in water disposal costs in the three months ended September 30, 2020.  Expenses on a per Mcfe basis were comparable for the three months ended September 30, 2020 compared to the three months ended September 30, 2019.  Lease operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repairs.  

Transportation, gathering and compression expense was $52.0 million during the three months ended September 30, 2020 compared to $57.0 million during the three months ended September 30, 2019.  Transportation, gathering and compression expense per Mcfe was $0.93 in the three months ended September 30, 2020 compared to $0.99 in the three months ended September 30, 2019.  The following table details our transportation, gathering and compression expenses for the three months ended September 30, 2020 and 2019:

	Three Months Ended September 30,
	2020		2019		Change
Transportation, gathering and compression (in thousands):
Gathering, compression and fuel	$	16,271	$	18,346	$	(2,075	)
Processing and fractionation		15,218		17,894		(2,676	)
Liquids transportation and stabilization		1,179		2,320		(1,141	)
Marketing		—		—		—
Firm transportation		19,293		18,467		826
	$	51,961	$	57,027	$	(5,066	)
Transportation, gathering and compression per Mcfe:
Gathering, compression and fuel	$	0.29	$	0.32	$	(0.03	)
Processing and fractionation		0.27		0.31		(0.04	)
Liquids transportation and stabilization		0.02		0.04		(0.02	)
Marketing		—		—		—
Firm transportation		0.35		0.32		0.03
	$	0.93	$	0.99	$	(0.06	)

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The decrease of $5.1 million to transportation, gathering and compression expenses during the three months ended September 30, 2020 was primarily due to lower contractual rates during the three months ended September 30, 2020.  The decrease of $0.06 per Mcfe was primarily due to a higher percentage of production attributable to natural gas and lower contractual rates offset by increased firm transportation expense from lower marketed production during the three months ended September 30, 2020.

Production and ad valorem taxes are paid based on market prices and applicable tax rates. Production and ad valorem taxes were $3.7 million in the three months ended September 30, 2020 compared to $1.7 million in the three months ended September 30, 2019. Production and ad valorem taxes per Mcfe was $0.07 for the three months ended September 30, 2020 compared to $0.03 per Mcfe for the three months ended September 30, 2019.  The increase of $2.0 million and $0.04 per Mcfe was primarily due to the recognition of a refund of production taxes from a state taxing authority during the three months ended September 30, 2019, as well as increased well count.

Depreciation, depletion, amortization and accretion was approximately $53.2 million in the three months ended September 30, 2020 compared to $45.5 million in the three months ended September 30, 2019. DD&A per Mcfe was $0.96 for the three months ended September 30, 2020 compared to $0.79 for the three months ended September 30, 2019. DD&A increased on an aggregate basis due to decreased production and on a per Mcfe basis due to a higher depletion rate resulting from reserves increasing at a lower rate than capital costs for the three months ended September 30, 2020.

General and administrative expense was $12.1 million for the three months ended September 30, 2020 compared to $14.6 million for the three months ended September 30, 2019.  General and administrative expense per Mcfe was $0.22 in the three months ended September 30, 2020 compared to $0.25 in the three months ended September 30, 2019.  The decrease of $2.4 million and $0.03 per Mcfe was related to a decrease in salaries and wages due to lower employee headcounts and a decrease in merger-related expenses during the three months ended September 30, 2020 compared to the three months ended September 30, 2019.  General and administrative expenses for the three months ended September 30, 2020 included $1.0 million of stock-based compensation expense and $2.5 million of merger-related expenses.  General and administrative expenses for the three months ended September 30, 2019 included $1.1 million of stock-based compensation expense and $3.3 million of merger-related expenses.

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. The following table details our other operating expenses for the three months ended September 30, 2020 and 2019:

	Three Months Ended September 30,
	2020			2019			Change
Other operating expenses (in thousands):
Brokered natural gas and marketing expense	$	7,345		$	10,574		$	(3,229	)
Exploration		11,767			16,621			(4,854	)
Rig termination and standby		303			1,221			(918	)
Gain on sale of assets		(62	)		(733	)		671

Brokered natural gas and marketing expense was $7.3 million for the three months ended September 30, 2020 compared to $10.6 million for the three months ended September 30, 2019.  Brokered natural gas and marketing expenses relate to gas that we buy and sell not relating to production and firm transportation capacity that is marketed to third parties.  The decrease for the three months ended September 30, 2020 was due to increased utilization of our firm transportation capacity for operated production during the three months ended September 30, 2020, which resulted in a decrease in the amount of firm transportation that was available for brokered gas transactions or release to third parties.

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Exploration expense was $11.8 million for the three months ended September 30, 2020 compared to $16.6 million for the three months ended September 30, 2019. The following table details our exploration-related expenses for the three months ended September 30, 2020 and 2019:

	Three Months Ended September 30,
	2020		2019		Change
Exploration expenses (in thousands):
Geological and geophysical	$	11	$	180	$	(169	)
Delay rentals		669		2,327		(1,658	)
Impairment of unproved properties		10,952		14,114		(3,162	)
Dry hole and other		135		—		135
	$	11,767	$	16,621	$	(4,854	)

Delay rentals were $0.7 million for the three months ended September 30, 2020 compared to $2.3 million for the three months ended September 30, 2019.  The decrease in delay rental expense related to the reduction in future drilling activity and concentration of lease renewals in our core acreage area during the three months ended September 30, 2020.

Impairment of unproved properties was $11.0 million for the three months ended September 30, 2020 compared to $14.1 million for the three months ended September 30, 2019. The decrease in impairment charges during the three months ended September 30, 2020 was the result of a decrease in expected leases subject to expiration.  As we continue to review our acreage positions and high grade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments may be recorded.

Rig termination and standby expense for the three months ended September 30, 2020 was $0.3 million related primarily to standby costs that we incurred for temporarily suspending our drilling operations for a portion of such period.  There was $1.2 million of rig termination and standby expense that related to the reduction in development activity for the three months ended September 30, 2019.

Gain on sale of assets was $0.1 million for the three months ended September 30, 2020 compared to $0.7 million for the three months ended September 30, 2019 due to certain sales of oil and natural gas properties and other assets during the relevant periods.

Other Income (Expense)

Gain (loss) on derivative instruments was a loss of ($40.5) million for the three months ended September 30, 2020 compared to a gain of $15.8 million for the three months ended September 30, 2019, primarily due to changes in commodity prices and interest rates during each period. Cash receipts were approximately $18.9 million and $11.8 million for derivative instruments that settled during the three months ended September 30, 2020 and 2019, respectively.

Interest expense, net was $14.4 million for the three months ended September 30, 2020 compared to $15.2 million for three months ended September 30, 2019.  Interest expense decreased primarily due to lower interest rates on borrowings under the revolving credit facility during the three months ended September 30, 2020.

Income tax benefit (expense) was not recognized for the three months ended September 30, 2020 and 2019 due to the Company recording a higher valuation allowance related to its pre-tax losses and reducing the valuation allowance to the extent of pre-tax income.

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Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

The following table illustrates the revenue attributable to our operations for the nine months ended September 30, 2020 and 2019:

	Nine Months Ended September 30,
	2020		2019		Change
Revenues (in thousands)
Natural gas sales	$	217,604	$	264,030	$	(46,426	)
NGL sales		44,949		60,841		(15,892	)
Oil sales		52,918		103,407		(50,489	)
Brokered natural gas and marketing revenue		23,859		31,747		(7,888	)
Other revenue		183		307		(124	)
Total revenues	$	339,513	$	460,332	$	(120,819	)

Our production grew by approximately 18.6 Bcfe for the nine months ended September 30, 2020 over the same period in 2019 due to drilling activity and from wells acquired as part of the BRMR Merger.  Our production for the nine months ended September 30, 2020 and 2019 is set forth in the following table:

	Nine Months Ended September 30,
	2020		2019		Change
Production:
Natural gas (MMcf)		131,353.1		109,613.9		21,739.2
NGLs (Mbbls)		3,342.7		3,414.9		(72.2	)
Oil (Mbbls)		1,635.1		2,083.3		(448.2	)
Total (MMcfe)		161,219.9		142,603.1		18,616.8
Average daily production volume:
Natural gas (Mcf/d)		479,391		401,516		77,875
NGLs (Bbls/d)		12,200		12,509		(309	)
Oil (Bbls/d)		5,968		7,631		(1,663	)
Total (Mcfe/d)		588,394		522,356		66,038

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Our average realized price (including cash settled commodity derivatives and firm transportation) received during the nine months ended September 30, 2020 was $1.97 per Mcfe compared to $2.72 per Mcfe during the nine months ended September 30, 2019. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices of production volumes should include the total impact of firm transportation expense. Our average realized price (including all cash settled commodity derivatives and firm transportation) calculation also includes all cash settlements for commodity derivatives. Average realized price (excluding cash settled commodity derivatives and firm transportation) does not include commodity derivative settlements or firm transportation, which are reported in transportation, gathering and compression expense on the accompanying Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). Average realized price (including firm transportation and excluding cash settled commodity derivatives) does include transportation costs where we receive net revenue proceeds from purchasers. Average realized price calculations for the nine months ended September 30, 2020 and 2019 are shown below:

	Nine Months Ended September 30,
	2020		2019		Change
Average realized price (excluding cash settled commodity    derivatives and firm transportation)
Natural gas ($/Mcf)	$	1.66	$	2.41	$	(0.75	)
NGLs ($/Bbl)		13.45		17.82		(4.37	)
Oil ($/Bbl)		32.36		49.64		(17.28	)
Total average prices ($/Mcfe)		1.96		3.00		(1.04	)
Average realized price (including cash settled commodity    derivatives, excluding firm transportation)
Natural gas ($/Mcf)	$	2.02	$	2.49	$	(0.47	)
NGLs ($/Bbl)		13.70		18.19		(4.49	)
Oil ($/Bbl)		40.32		50.15		(9.83	)
Total average prices ($/Mcfe)		2.34		3.08		(0.74	)
Average realized price (including firm transportation,    excluding cash settled commodity derivatives)
Natural gas ($/Mcf)	$	1.20	$	1.94	$	(0.74	)
NGLs ($/Bbl)		13.45		17.82		(4.37	)
Oil ($/Bbl)		32.36		49.64		(17.28	)
Total average prices ($/Mcfe)		1.59		2.64		(1.05	)
Average realized price (including cash settled commodity    derivatives and firm transportation)
Natural gas ($/Mcf)	$	1.57	$	2.02	$	(0.45	)
NGLs ($/Bbl)		13.70		18.19		(4.49	)
Oil ($/Bbl)		40.32		50.15		(9.83	)
Total average prices ($/Mcfe)		1.97		2.72		(0.75	)

Brokered natural gas and marketing revenue was $23.9 million and $31.7 million for the nine months ended September 30, 2020 and 2019, respectively.  Brokered natural gas and marketing revenue includes revenue received from selling natural gas not related to production and from the release of firm transportation capacity.  The decrease for the nine months ended September 30, 2020 was due to increased utilization of our firm transportation capacity for operated production during the nine months ended September 30, 2020, which resulted in a decrease in the amount of firm transportation that was available for brokered gas transactions or release to third parties.

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Costs and Expenses

We believe some of our expenses are most accurately analyzed on a unit-of-production, or per Mcfe, basis.  The following table presents these expenses for the nine months ended September 30, 2020 and 2019:

	Nine Months Ended September 30,
	2020		2019		Change
Operating expenses (in thousands)
Lease operating	$	33,436	$	29,651	$	3,785
Transportation, gathering and compression		157,472		150,065		7,407
Production and ad valorem taxes		10,146		8,519		1,627
Depreciation, depletion, amortization and accretion		140,058		113,950		26,108
General and administrative		33,594		57,074		(23,480	)
Operating expenses per Mcfe:
Lease operating	$	0.21	$	0.21	$	—
Transportation, gathering and compression		0.98		1.04		(0.06	)
Production and ad valorem taxes		0.06		0.06		—
Depreciation, depletion, amortization and accretion		0.87		0.80		0.07
General and administrative		0.21		0.40		(0.19	)

Lease operating expense was $33.4 million in the nine months ended September 30, 2020 compared to $29.7 million in the nine months ended September 30, 2019.  Lease operating expense per Mcfe was $0.21 in each of the nine months ended September 30, 2020 and 2019.  The increase of $3.8 million was primarily attributable to an increase in the number of producing wells in the nine months ended September 30, 2020.  Expenses on a per Mcfe basis were comparable for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019.  Lease operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repairs.

Transportation, gathering and compression expense was $157.5 million during the nine months ended September 30, 2020 compared to $150.1 million during the nine months ended September 30, 2019.  Transportation, gathering and compression expense per Mcfe was $0.98 in the nine months ended September 30, 2020 compared to $1.04 in the nine months ended September 30, 2019.  The following table details our transportation, gathering and compression expenses for the nine months ended September 30, 2020 and 2019:

	Nine Months Ended September 30,
	2020		2019		Change
Transportation, gathering and compression (in thousands):
Gathering, compression and fuel	$	49,255	$	48,014	$	1,241
Processing and fractionation		44,175		44,836		(661	)
Liquids transportation and stabilization		4,582		5,347		(765	)
Marketing		—		103		(103	)
Firm transportation		59,460		51,765		7,695
	$	157,472	$	150,065	$	7,407
Transportation, gathering and compression per Mcfe:
Gathering, compression and fuel	$	0.31	$	0.33	$	(0.02	)
Processing and fractionation		0.27		0.31		(0.04	)
Liquids transportation and stabilization		0.03		0.04		(0.01	)
Marketing		—		—		—
Firm transportation		0.37		0.36		0.01
	$	0.98	$	1.04	$	(0.06	)

The increase of $7.4 million to transportation, gathering and compression expenses during the nine months ended September 30, 2020 was due to increased production and increased firm transportation capacity during the nine months ended September 30, 2020.  The decrease of $0.06 per Mcfe during the nine months ended September 30, 2020 was primarily due to a higher percentage of production attributable to natural gas and lower contractual rates during the nine months ended September 30, 2020.

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Production and ad valorem taxes are paid based on market prices and applicable tax rates.  Production and ad valorem taxes were $10.1 million in the nine months ended September 30, 2020 compared to $8.5 million in the nine months ended September 30, 2019.  Production and ad valorem taxes per Mcfe were $0.06 in each of the nine months ended September 30, 2020 and 2019.  The increase of $1.6 million was primarily due to the recognition of a refund of production taxes from a state taxing authority during the nine months ended September 30, 2019, as well as increased well count.

Depreciation, depletion, amortization and accretion was approximately $140.1 million in the nine months ended September 30, 2020 compared to $114.0 million in the nine months ended September 30, 2019.  DD&A per Mcfe was $0.87 in the nine months ended September 30, 2020 compared to $0.80 in the nine months ended September 30, 2019.  DD&A increased on an aggregate basis due to increased production and a higher depletion rate in the nine months ended September 30, 2020.  DD&A increased on a per Mcfe basis due to a higher depletion rate resulting from reserves increasing at a lower rate than capital costs for the nine months ended September 30, 2020.

General and administrative expense was $33.6 million for the nine months ended September 30, 2020 compared to $57.1 million for the nine months ended September 30, 2019.  General and administrative expense per Mcfe was $0.21 in the nine months ended September 30, 2020 compared to $0.40 in the nine months ended September 30, 2019.  The decrease of $23.5 million and $0.19 per Mcfe was primarily related to a decrease in merger-related expenses, salaries and wages and stock-based compensation in the nine months ended September 30, 2020.  General and administrative expenses for the nine months ended September 30, 2020 included $3.6 million of stock-based compensation expense, $2.7 million of merger-related expenses, and $2.7 million of severance.  General and administrative expenses for the nine months ended September 30, 2019 included $7.6 million of stock-based compensation expense and $21.8 million of merger-related expenses.  

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production.  The following table details our other operating expenses for the nine months ended September 30, 2020 and 2019:

	Nine Months Ended September 30,
	2020			2019			Change
Other operating expenses (in thousands):
Brokered natural gas and marketing expense	$	24,349		$	32,017		$	(7,668	)
Exploration		34,112			48,602			(14,490	)
Rig termination and standby		303			1,221			(918	)
Gain on sale of assets		(1,419	)		(731	)		(688	)

Brokered natural gas and marketing expense was $24.3 million for the nine months ended September 30, 2020 compared to $32.0 million for the nine months ended September 30, 2019.  Brokered natural gas and marketing expenses relate to gas purchases that we buy and sell not relating to production and firm transportation capacity that is marketed to third parties.  The decrease for the nine months ended September 30, 2020 was due to increased utilization of our firm transportation capacity for operated production during the nine months ended September 30, 2020, which resulted in a decrease in the amount of firm transportation that was available for brokered gas transactions or release to third parties.

Exploration expense was $34.1 million for the nine months ended September 30, 2020 compared to $48.6 million for the nine months ended September 30, 2019.  The following table details our exploration-related expenses for the nine months ended September 30, 2020 and 2019:

	Nine Months Ended September 30,
	2020		2019		Change
Exploration expenses (in thousands):
Geological and geophysical	$	186	$	643	$	(457	)
Delay rentals		3,472		11,639		(8,167	)
Impairment of unproved properties		30,311		36,157		(5,846	)
Dry hole and other		143		163		(20	)
	$	34,112	$	48,602	$	(14,490	)

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Delay rentals were $3.5 million for the nine months ended September 30, 2020 compared to $11.6 million for the nine months ended September 30, 2019.  The decrease in delay rental expense related to the reduction in future drilling activity and concentration of lease renewals in our core acreage area during the nine months ended September 30, 2020.

Impairment of unproved properties was $30.3 million for the nine months ended September 30, 2020 compared to $36.2 million for the nine months ended September 30, 2019.  The decrease in impairment charges during the nine months ended September 30, 2020 was the result of a decrease in expected leases subject to expirations.  As we continue to review our acreage positions and high grade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments may be recorded.

Rig termination and standby expense for the nine months ended September 30, 2020 was $0.3 million related primarily to standby costs that we incurred for temporarily suspending our drilling operations for a portion of such period.  There was $1.2 million of rig termination and standby expense that related to the reduction in development activity for the nine months ended September 30, 2019.

Gain on sale of assets was $1.4 million for the nine months ended September 30, 2020 compared to $0.7 million for the nine months ended September 30, 2019 due to certain sales of oil and natural gas properties and other assets during 2020.

Other Income (Expense)

Gain (loss) on derivative instruments was a loss of ($11.3) million for the nine months ended September 30, 2020 compared to a gain of $40.6 million for the nine months ended September 30, 2019, primarily due to changes in commodity prices and interest rates during each period.  Cash receipts were approximately $61.9 million and $11.1 million for derivative instruments that settled during the nine months ended September 30, 2020 and 2019, respectively.

Interest expense, net was $44.2 million for the nine months ended September 30, 2020 compared to $44.1 million for the nine months ended September 30, 2019.  The increase in interest expense primarily related to our increased borrowings under our revolving credit facility during the nine months ended September 30, 2020.

Income tax benefit (expense) was not recognized for the nine months ended September 30, 2020 and 2019 due to the Company recording a higher valuation allowance related to its pre-tax losses and reducing the valuation allowance to the extent of pre-tax income.

Cash Flows, Capital Resources and Liquidity

Cash Flows

Cash flows from operations are primarily affected by production volumes and commodity prices. Our cash flows from operations also are impacted by changes in working capital. Short-term liquidity needs are satisfied by our operating cash flow, proceeds from asset sales and borrowings under our revolving credit facility.  We sell a large portion of our production at the wellhead under floating price contracts.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Net cash provided by operations in the nine months ended September 30, 2020 was $72.8 million compared to $176.3 million in the nine months ended September 30, 2019. The decrease in cash provided by operating activities reflects working capital changes, operating income (loss) and timing of cash receipts and disbursements during the year-over-year comparative periods.

Net cash used in investing activities in the nine months ended September 30, 2020 was $120.9 million compared to $254.7 million in the nine months ended September 30, 2019.

During the nine months ended September 30, 2020, we:

• spent $122.0 million on capital expenditures for oil and natural gas properties;

• spent $0.3 million on property and equipment; and

• received $1.4 million from asset sales.

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During the nine months ended September 30, 2019, we:

• spent $268.8 million on capital expenditures for oil and natural gas properties;

• received $1.8 million from asset sales; and

• received $12.9 million of cash as part of the assets acquired in the BRMR Merger.

Net cash provided by financing activities in the nine months ended September 30, 2020 was $40.0 million compared to $84.0 million in the nine months ended September 30, 2019.

During the nine months ended September 30, 2020, we:

• borrowed $40.0 million under our revolving credit facility; and

• borrowed $1.1 million under other notes payable.

During the nine months ended September 30, 2019, we:

• borrowed $95.0 million under our revolving credit facility;

• paid $4.2 million in debt issuance costs associated with the amendment and restatement of the Credit Agreement; and

• withheld from employees’ shares totaling $6.5 million related to the settlement of equity compensation awards.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources are internally generated cash flow from operations, asset sales, borrowings under our revolving credit facility and access to the debt and equity capital markets. We must find new and develop existing reserves to maintain and grow our production and cash flows. We accomplish this primarily through successful drilling programs, which require substantial capital expenditures. We periodically review capital expenditures and adjust our budget based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices. We believe that our existing cash on hand, operating cash flow and available borrowings under our revolving credit facility will be adequate to meet our capital and operating requirements for 2020.

Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We will continue using net cash on hand, cash flows from operations and borrowings under our revolving credit facility to satisfy near-term financial obligations and liquidity needs, and as necessary, we will seek additional sources of debt or equity to fund these requirements. Longer-term cash flows are subject to a number of variables including the level of production and prices we receive for our production as well as various economic conditions that have historically affected the natural gas and oil business. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings, asset sales or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.  Furthermore, no assurance can be made that additional debt or equity financing will be available to us, or if available, will be available on satisfactory terms.

As of September 30, 2020, we were in compliance with all of our debt covenants under the Credit Agreement governing our revolving credit facility and the indenture governing our 8.875% senior unsecured notes due 2023. Further, based on our current forecast and activity levels, we expect to remain in compliance with all such debt covenants for the next 12 months. However, if oil and natural gas prices decrease to lower levels, we are likely to generate lower operating cash flows, which would make it more difficult for us to remain in compliance with all of our debt covenants, including requirements with respect to working capital and leverage ratios. This could negatively impact our ability to maintain sufficient liquidity and access to capital resources.

Credit Arrangements

Long-term debt as of September 30, 2020 and December 31, 2019, excluding discount, totaled $680.5 million and $640.5 million, respectively.  Information related to our credit arrangements is described in Note 8—Debt to our Condensed Consolidated Financial Statements and is incorporated herein by reference.

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Commodity Hedging Activities

Our primary market risk exposure is in the prices we receive for our natural gas, NGLs and oil production. Realized pricing is primarily driven by the spot regional market prices applicable to our U.S. natural gas, NGLs and oil production. Pricing for natural gas, NGLs and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate the potential negative impact on our cash flow caused by changes in natural gas, NGLs and oil prices, we may enter into financial commodity derivative contracts to ensure that we receive minimum prices for a portion of our future natural gas production when management believes that favorable future prices can be secured. We typically hedge the NYMEX Henry Hub price for natural gas and the WTI price for oil.

Our hedging activities are intended to support natural gas, NGLs and oil prices at targeted levels and to manage our exposure to price fluctuations. The counterparty is required to make a payment to us for the difference between the floor price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the floor price. We are required to make a payment to the counterparty for the difference between the ceiling price and the settlement price if the ceiling price is below the settlement price. These contracts may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, zero cost collars that set a floor and ceiling price for the hedged production, and puts that require us to pay a premium either up front or at settlement and allow us to receive a fixed price at our option if the put price is above the market price. Information regarding our outstanding derivative contracts as of September 30, 2020 is set forth in Note 6— Derivative Instruments to our Condensed Consolidated Financial Statements.

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our 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 us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our 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 our counterparties is subject to periodic review. We have derivative instruments in place with Bank of Montreal, BP Energy Company, Capital One N.A., Citibank, Citizens Bank N.A., East West Bank, J Aron, KeyBank N.A., Morgan Stanley, Royal Bank of Canada, and Wells Fargo. We believe all such institutions currently are an acceptable credit risk. As of September 30, 2020, we did not have any past due receivables from such counterparties.

Capital Requirements

Our primary needs for cash are for exploration, development and acquisition of natural gas and oil properties and repayment of principal and interest on outstanding debt. Our Board of Directors approved a capital budget for 2020 of between approximately $190 - $210 million, allocated approximately 95% for drilling and completions activities and approximately 5% for land capital requirements.  In March 2020, the Company reduced its 2020 capital budget by approximately $45 million, to $145 - $165 million, allocated approximately 90% for drilling and completions activities and approximately 10% for land and other capital expenditures.  In May 2020, the Company reduced its 2020 capital budget by approximately $15 million, to $130 - $150 million and in July 2020, the Company further reduced its 2020 capital budget by another $10 million, to $120 - $140 million.  The revised 2020 capital budget is expected to be substantially funded through internally generated cash flows, current cash balances, and borrowings under the revolving credit facility.  The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas, NGLs and oil prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in natural gas, NGLs or oil prices from current levels may result in a further decrease in our actual capital expenditures, which would negatively impact our ability to grow production and our proved reserves as well as our ability to maintain compliance with our debt covenants. Our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities, additional borrowings under our revolving credit facility or the sale of assets.

In addition, we may from time to time seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such transactions, if any, will depend on available funds, prevailing market conditions, our liquidity requirements, contractual restrictions in the Credit Agreement governing our revolving credit facility and other factors.

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Capitalization

As of September 30, 2020 and December 31, 2019, our total debt, excluding debt discount and issuance costs, and capitalization were as follows (in millions):

	September 30, 2020		December 31, 2019
Senior unsecured notes	$	510.5	$	510.5
Revolving credit facility		170.0		130.0
Stockholders’ equity		842.0		997.1
Total capitalization	$	1,522.5	$	1,637.6

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, drilling commitments, firm transportation, gas processing, gathering, and compression services, fractionation services, marketing agreements and asset retirement obligations. As of September 30, 2020 and December 31, 2019, we did not have significant capital leases, any significant off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed any debt of any unrelated party. Our Condensed Consolidated Balance Sheet as of September 30, 2020 reflects accrued interest payable of $9.9 million, compared to $21.3 million as of December 31, 2019.

During the nine months ended September 30, 2020 we renegotiated certain existing gas gathering contracts into a single new consolidated gas gathering contract.  Information related to our revised commitments is set forth in Note 12—Commitments and Contingencies to our Condensed Consolidated Financial Statements and is incorporated herein by reference.

Other

We lease acreage that is generally subject to lease expiration if operations are not commenced within a specified period, generally five years. However, based on our evaluation of prospective economics, including the cost of infrastructure to connect production, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component of our cost structure and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Interest Rates

As of September 30, 2020 and December 31, 2019, we had $510.5 million of senior unsecured notes outstanding, excluding discounts, which bore interest at a fixed cash rate of 8.875% per annum, payable semi-annually.

As of September 30, 2020, we had outstanding borrowings of $170.0 million under our revolving credit facility with interest payable at a variable rate based on LIBOR or the prime rate based on our election at the time of borrowing.  We had outstanding borrowings of $130.0 million under our revolving credit facility as of December 31, 2019.

In April 2020, we entered into an interest rate swap with a notional amount of $100 million to manage our exposure to interest rate volatility, as described in Note 6—Derivative Instruments to our Condensed Consolidated Financial Statements and incorporated herein by reference.

Information related to our interest rates is described in Note 8—Debt to our Condensed Consolidated Financial Statements and is incorporated herein by reference.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments, which are described above under “—Cash Contractual Obligations.”

Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, it does not normally have a significant effect on our business. We expect our costs in fiscal

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2020 to continue to be a function of supply and demand.  Further strengthening of commodity prices could stimulate demand for ancillary services causing service costs to increase.  The majority of our service costs is expected to remain flat in 2020 due to previously negotiated drilling, stimulation, and rentals contracts.  Along with these contracts, we have secured quality service equipment and tenured personnel to limit our exposure to increasing service costs and improve operational efficiencies.  

Non-GAAP Financial Measure

“Adjusted EBITDAX” is a non-GAAP financial measure that we define as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; DD&A; gain (loss) on derivative instruments, net cash receipts (payments) on settled commodity derivative instruments, and premiums (paid) received on options that settled during the period; non-cash compensation expense; gain or loss from sale of interest in gas properties; exploration expenses; and other unusual or infrequent items set forth in the table below. Adjusted EBITDAX, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with U.S. GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with U.S. GAAP. Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:

• is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;

• helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and

• is used by our management team for various purposes, including as a measure of operating performance, in presentations to our Board of Directors, as a basis for strategic planning and forecasting and by our lenders pursuant to covenants under the Credit Agreement governing the revolving credit facility and the indenture governing the senior unsecured notes.

There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. The following table represents a reconciliation of our net income (loss) to Adjusted EBITDAX for the periods presented:

	Three Months Ended September 30,						Nine Months Ended September 30,
$ thousands	2020			2019				2020		2019
Net income (loss)	$	(92,200	)	$	4,284		$	(158,227	)	$	17,698
Depreciation, depletion, amortization and accretion		53,153			45,456			140,058			113,950
Exploration expense		11,767			16,621			34,112			48,602
Rig termination and standby		303			1,221			303			1,221
Stock-based compensation		961			1,061			3,585			7,614
Gain on sale of assets		(62	)		(733	)		(1,419	)		(731	)
(Gain) loss on derivative instruments		40,535			(15,812	)		11,329			(40,620	)
Net cash receipts on settled commodity derivatives		18,806			11,818			61,829			11,072
Interest expense, net		14,402			15,192			44,166			44,140
Other income		(2	)		—			(19	)		(8	)
Merger-related expenses		2,520			3,291			2,696			21,812
(Income) loss from discontinued operations(1)		801			1,237			10,092			(1,286	)
Severance		—			—			2,681			—
Adjusted EBITDAX	$	50,984		$	83,636		$	151,186		$	223,464

(1) We recorded a $6.8 million impairment of proved properties held for sale during the nine months ended September 30, 2020.  See Note 5—Assets Held for Sale and Discontinued Operations.

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Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations are based upon our Condensed Consolidated Financial Statements, which have been prepared in accordance with U.S. GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. See our Annual Report on Form 10-K for further discussion of our critical accounting policies.

Recent Accounting Pronouncements

The Company’s critical accounting policies are described in Note 2—Summary of Significant Accounting Policies of the Consolidated Financial Statements for the year ended December 31, 2019 contained in the Company’s Annual Report on Form 10-K. Information related to recent accounting pronouncements is described in Note 3—Summary of Significant Accounting Policies to our Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q and is incorporated herein by reference.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable to smaller reporting companies.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Company’s management carried out an evaluation (as required by Rule 13a-15(b) under the Exchange Act), with the participation of the Company’s President and Chief Executive Officer and Executive Vice President and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act), as of the end of the period covered by this Quarterly Report. Based upon this evaluation, the Company’s President and Chief Executive Officer and Executive Vice President and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report, such that the information relating to the Company and its consolidated subsidiaries required to be disclosed by the Company in the reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized, and reported, within the time periods specified in the SEC’s rules and forms, and (ii) is accumulated and communicated to the Company’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls

There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15(d)-15(f) under the Exchange Act) during the period covered by this Quarterly Report that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Information regarding the Company’s legal proceedings is set forth in Note 12—Commitments and Contingencies, located in the Notes to the Condensed Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report and is incorporated herein by reference.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, including the risk factors set forth below, you should carefully consider the factors discussed in “Item 1A. Risk Factors” in our Annual Report on Form 10-K, filed with the SEC on March 10, 2020, which could materially affect our business, financial condition, and/or future results.  The risks described in our Annual Report on Form 10-K and in this Quarterly Report are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or results of operations.

Because the exchange ratio in the Southwestern Merger Agreement is fixed and will not be adjusted in the event of any change in either Southwestern’s or our stock price, the value of the merger consideration is uncertain.

Upon completion of the merger, each share of our common stock outstanding immediately prior to the merger will be converted into and become exchangeable for 1.8656 shares of Southwestern common stock. The exchange ratio is fixed in the Southwestern Merger Agreement and will not be adjusted for changes in the market price of either Southwestern common stock or our common stock. The market prices of Southwestern common stock and our common stock have fluctuated prior to and after the date of the announcement of the Southwestern Merger Agreement and will continue to fluctuate to the date of our special meeting of stockholders in connection with the merger and the date the merger is consummated, and the market price of Southwestern common stock will continue to fluctuate thereafter.

Because the value of the merger consideration will depend on the market price of Southwestern common stock at the time the merger is completed, our stockholders will not know, or be able to determine, at the time of our special meeting of stockholders the market value of the merger consideration they would receive upon completion of the merger.

Stock price changes may result from a variety of factors, including, among others, general market and economic conditions, changes in Southwestern’s and our respective businesses, operations and prospects, reductions or changes in U.S. government spending or budgetary policies, market assessments of the likelihood that the merger will be completed, interest rates, general market, industry and economic conditions, such as oil prices and demand for natural gas, oil and NGLs, federal, state and local legislation, governmental regulation and legal developments in the industry segments in which Southwestern or we operate, the effects of the COVID-19 pandemic and governmental and business responses to the pandemic, the timing of the merger and other factors generally affecting the respective prices of Southwestern common stock or our common stock.

Many of these factors are beyond Southwestern’s and our control, and neither Southwestern nor the Company is permitted to terminate the Southwestern Merger Agreement solely due to a decline in the market price of the common stock of the other party. Our stockholders are urged to obtain current market quotations for Southwestern common stock and our common stock in determining whether to vote for the adoption of the Southwestern Merger Agreement.

The merger may not be completed and the Southwestern Merger Agreement may be terminated in accordance with its terms.

The merger is subject to a number of conditions that must be satisfied or waived (to the extent permissible), including the adoption of the Southwestern Merger Agreement by our stockholders prior to the completion of the merger. These conditions to the completion of the merger, some of which are beyond the control of Southwestern and the Company, may not be satisfied or waived in a timely manner or at all, and, accordingly, the merger may be delayed or not completed. Additionally, either Southwestern or the Company may terminate the Southwestern Merger Agreement under certain circumstances, including, among other reasons, if the merger is not completed by February 12, 2021 (subject to certain exceptions). We would be required to pay to Southwestern a termination fee of $9.7 million if the Southwestern Merger Agreement is terminated under certain circumstances.

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The termination of the Southwestern Merger Agreement could negatively impact the Company.

If the merger is not completed for any reason, including as a result of a failure of our stockholders to adopt the Southwestern Merger Agreement, our ongoing business may be adversely affected and, without realizing any of the benefits of having completed the merger, we may experience certain negative effects, including:

• our business may have been adversely impacted by the failure to pursue other beneficial opportunities due to the focus of management on the merger, without realizing any of the anticipated benefits of completing the merger;

• our business may be adversely impacted by the loss of our management personnel or other key employees;

• the market price of our common stock may decline to the extent that the market price prior to termination reflects a market assumption that the merger will be completed; and

• negative reactions from the financial markets may occur if the anticipated benefits of the merger are not able to be realized. Such anticipated benefits may include, among others, operational efficiencies, cost savings, and synergies.

If the merger is not consummated, we cannot assure our stockholders that the risks described above will not negatively impact our business, financial results and ability to pay dividends, if any, to our stockholders.

Our stockholders will have reduced ownership and voting interest in and will exercise less influence over management of Southwestern following completion of the merger.

Our stockholders currently have the right to vote in the election of our board of directors and on other matters affecting the Company. Upon consummation of the merger, each former Company stockholder will be a stockholder of Southwestern with a percentage ownership of Southwestern that is smaller than such stockholder’s percentage ownership of the Company immediately prior to the merger. As of the date of the definitive proxy statement/prospectus relating to the merger, based on the exchange ratio set forth in the Southwestern Merger Agreement, the number of outstanding shares of our common stock (plus the number of shares underlying outstanding Company restricted stock units and performance units) and the number of outstanding shares of Southwestern common stock (on a fully diluted basis), it is estimated that Southwestern stockholders will own approximately 90% and our stockholders will own approximately 10% of the issued and outstanding shares of Southwestern common stock on a fully diluted basis immediately following the effective time of the merger. Because of this, each share of our common stock will represent a smaller percentage ownership of Southwestern than it represented in the Company.

The shares of Southwestern common stock to be received by our stockholders as a result of the merger will have rights different from the shares of our common stock.

Upon consummation of the merger, the rights of our stockholders, who will become stockholders of Southwestern, will be governed by the Southwestern certificate of incorporation and the Southwestern bylaws. The rights associated with our common stock are different from the rights associated with Southwestern common stock.

Until the completion of the merger or the termination of the Southwestern Merger Agreement in accordance with its terms, we are prohibited from entering into certain transactions and taking certain actions that might otherwise be beneficial to us and our stockholders.

From and after the date of the Southwestern Merger Agreement and prior to completion of the merger, the Southwestern Merger Agreement restricts us from taking specified actions without the consent of Southwestern and generally requires that the business of the Company and our subsidiaries be conducted in all material respects in the ordinary course of business consistent with past practice. These restrictions may prevent us from making appropriate changes to our business or organizational structure or from pursuing attractive business opportunities that may arise prior to the completion of the merger, and could have the effect of delaying or preventing other strategic transactions. Adverse effects arising from the pendency of the merger could be exacerbated by any delays in consummation of the merger or termination of the Southwestern Merger Agreement.

Obtaining required approvals and satisfying closing conditions may prevent or delay completion of the merger.

The merger is subject to a number of conditions to closing as specified in the Southwestern Merger Agreement. These closing conditions include, among others, the adoption of the Southwestern Merger Agreement by our stockholders, approval for listing on the New York Stock Exchange of the shares of Southwestern common stock issuable in accordance with the Southwestern Merger Agreement, the absence of governmental restraints or prohibitions preventing the consummation of the merger, the effectiveness of Southwestern’s registration statement on Form S-4 registering the Southwestern common stock issuable pursuant to the Southwestern Merger Agreement (which the SEC declared effective on October 6, 2020) and the absence of any stop order or proceedings by the SEC with respect thereto. The obligation of each of Southwestern and the Company to consummate the merger is also conditioned on,

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among other things, (i) the accuracy of the representations and warranties as set forth by the other party in the Southwestern Merger Agreement, (ii) the performance by the other party, in all material respects, of its obligations under the Southwestern Merger Agreement required to be performed at or prior to the effective time of the merger and (iii) the delivery by the other party of a certificate of an authorized officer certifying that the required conditions have been satisfied. The required stockholder consents and approvals may not be obtained and the required conditions to closing may not be satisfied, and, if all required consents and approvals are obtained and the conditions are satisfied, no assurance can be given as to the terms, conditions and timing of such consents and approvals. Any delay in completing the merger could cause Southwestern and us not to realize, or to be delayed in realizing, some or all of the benefits that Southwestern and we expect to achieve if the merger is successfully completed within its expected time frame.

Completion of the merger will trigger change in control or other provisions in certain agreements to which we are a party.

The completion of the merger will trigger change in control and other provisions in certain agreements to which we are a party. If Southwestern or we are unable to negotiate waivers of those provisions, counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements or seeking monetary damages or equitable remedies. Even if Southwestern and we are able to negotiate consents or waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to us or the combined company.

The merger, and uncertainty regarding the merger, may cause customers or suppliers to delay or defer decisions concerning us and adversely affect our ability to effectively manage our business.

The merger will be consummated only if the stated conditions are satisfied or waived. Many of the conditions are outside the control of Southwestern and the Company, and both parties also have certain rights to terminate the Southwestern Merger Agreement. Accordingly, there may be uncertainty regarding the completion of the merger. This uncertainty may cause customers, suppliers, vendors or others that deal with us to delay or defer entering into contracts with us or making other decisions concerning us or seek to change or cancel existing business relationships with us, which could negatively affect our business. Any delay or deferral of those decisions or changes in existing agreements could have an adverse impact on our business, regardless of whether the merger is ultimately completed.

We may be adversely affected by negative publicity related to the proposed merger and in connection with other matters.

From time to time, political and public sentiment in connection with the proposed merger and in connection with other matters could result in a significant amount of adverse press coverage and other adverse public statements affecting us. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims. Responding to these investigations and lawsuits, regardless of the ultimate outcome of the proceeding, can divert the time and effort of senior management from the management of our business. Addressing any adverse publicity, governmental scrutiny or enforcement or other legal proceedings is time consuming and expensive and, regardless of the factual basis for the assertions being made, can have a negative impact on our reputation, on the morale and performance of our employees and on our relationships with our regulators. It may also have a negative impact on our ability to take timely advantage of various business and market opportunities. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have a material adverse effect on our business, financial condition, results of operations and cash flows.

There are various provisions of the Southwestern Merger Agreement and related documents that restrict our ability to seek alternative transactions or to terminate the merger.

The Southwestern Merger Agreement contains “no shop” provisions that restrict our ability to, among other things, solicit or pursue alternative acquisition proposals. There are only limited circumstances under which the Southwestern Merger Agreement would permit our board of directors to withhold, withdraw, qualify or modify the recommendation of our board of directors with respect to the merger. The Southwestern Merger Agreement also provides that in certain circumstances, we may be required to pay Southwestern a termination fee of $9.7 million if the Southwestern Merger Agreement is terminated. The support agreement entered into in connection with the merger by Southwestern and certain of our stockholders affiliated with EnCap Investments L.P. (“EnCap”) includes covenants that, with limited exceptions, require EnCap to vote all of the shares of our common stock held by EnCap on such date in favor of adoption of the Southwestern Merger Agreement and against actions that may impair or impede the transactions contemplated by the Southwestern Merger Agreement. These provisions could discourage a potential competing acquirer from considering or proposing an acquisition or merger, even if it were prepared to pay consideration with a higher value than that implied by the exchange ratio set forth in the Southwestern Merger Agreement, or might result in a potential competing acquirer proposing to pay a lower per share price than it might otherwise have proposed to pay because of the added expense of the termination fee provisions of the Southwestern Merger Agreement.

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We will incur transaction and merger-related expenses in connection with the merger.

We have incurred and expect to incur a number of non-recurring costs associated with consummating the merger and combining the operations of Southwestern and the Company. These costs and expenses include fees paid to financial, legal and accounting advisors, potential employment-related costs, filing fees, printing expenses and other related charges. Some of these costs are payable by us regardless of whether the merger is completed.

Southwestern and the Company may be targets of securities class action and derivative lawsuits which could result in substantial costs and may delay or prevent the merger from being completed.

Securities class action lawsuits and derivative lawsuits are often brought against companies that have entered into merger agreements. Following the announcement of the Southwestern Merger Agreement, six complaints were filed by purported Company stockholders challenging the merger, captioned as follows: Dinardo v. Montage Resources Corporation, et al., No. 1:20-cv-08416 (S.D.N.Y.); Raul v. Montage Resources Corporation, et al., No. 1:20-cv-08619 (S.D.N.Y.); Waldrop v. Montage Resources Corporation, et al., No. 1:20-cv-04995 (E.D.N.Y.); Wolf v. Montage Resources Corporation, et al., No. 1:20-cv-01324-UNA (D. Del.); Gordon v. Montage Resources Corporation, et al. (Supreme Court of the State of New York, County of New York); and Widrick v. Montage Resources Corporation, et al. No. 1:20-cv-09101 (S.D.N.Y.). The complaints generally assert claims under Sections 14(a) and 20(a) of the Exchange Act, alleging, among other things, that the registration statement on Form S-4, originally filed on September 16, 2020, omits material information with respect to the merger and/or assert claims for breach of fiduciary duty under Delaware law against the Company and our directors.

Defending against these claims can result in substantial costs and divert management time and resources, even if the lawsuits are without merit. An adverse judgment could result in monetary damages, which could have a negative impact on our business, results of operations and financial condition. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the merger, the injunction may delay or prevent the merger from being completed, which may adversely affect our business, results of operations and financial condition.

The COVID-19 pandemic has affected and may materially adversely affect, and any future pandemic or outbreak of any other highly infectious or contagious diseases may materially adversely affect, our operations, financial performance and condition, operating results and cash flows.

The COVID-19 pandemic has affected, and may materially adversely affect, our business and financial and operating results. The severity, magnitude and duration of the COVID-19 pandemic is uncertain, rapidly changing and hard to predict. Thus far in 2020, the pandemic has significantly impacted economic activity and markets around the world, and COVID-19 or another similar pandemic or outbreak could negatively impact our business in numerous ways, including, but not limited to, the following:

• our revenue may be reduced if the pandemic or outbreak results in an economic downturn or recession, as many experts predict, to the extent it leads to a prolonged decrease in the demand for natural gas and, to a lesser extent, NGLs and oil;

• the lack of a market or available storage for our NGL products and oil could cause interruptions in our operations, including temporary curtailments or shut-ins, as our industry is experiencing storage capacity constraints with respect to certain NGL products and oil due to an imbalance between the supply of and demand for natural gas, NGLs and oil;

• our operations may be disrupted or impaired, thus lowering our production level, if our key personnel or a significant portion of our employees or contractors are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to control measures designed to contain the pandemic or outbreak; and

• the operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced natural gas, NGLs and oil, may be disrupted or suspended in response to containing the pandemic or outbreak, and/or the difficult economic environment may lead to the bankruptcy or closing of the facilities and infrastructure of our midstream service providers, which may result in substantial discounts in the prices we receive for our produced natural gas, NGLs and oil or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties.

Further, our office and management personnel are subject to varying governmental restrictions depending on the level of actions taken by governments of the jurisdictions in which such personnel are located.  While substantially all of such personnel have returned to our offices following a period of remote work, such personnel may again be required to work remotely depending on the actions taken by such governments or the decisions of our management team. As the health of our workforce is paramount, we have implemented, and will continue to implement for the foreseeable future, precautionary measures to help minimize the risk of our employees being potentially exposed to, or contracting, COVID-19. Our management team remains focused on mitigating the adverse effects of the spread of COVID-19, which has required, and will continue to require, a large investment of time and resources across the entire Company, thereby diverting time, energy and resources from other priorities that existed prior to the spread of COVID-19. If these conditions exacerbate, or last for an extended period of time, our ability to manage our business may be negatively impacted and preexisting operational and other business risks that we (and our industry) face may be heightened, including, but not limited to, cybersecurity risks. If either our systems or the systems of our service or equipment providers used for protecting against cyber

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incidents or attacks prove to be insufficient and incidents were to occur as a result of working remotely, it could have a material adverse effect on our business, reputation, financial condition, results of operations or cash flows.

In addition, the COVID-19 pandemic has increased volatility and caused negative pressure in the capital and credit markets. As a result, we may experience difficulty accessing the capital or financing needed to fund our exploration and production operations, which have substantial capital requirements. Our 2020 capital budget is expected to be substantially funded through internally generated cash flows, current cash balances, and borrowings under our revolving credit facility. If our cash flows from operations or the borrowing capacity under our revolving credit facility is insufficient to fund our capital expenditures and we are unable to obtain the capital necessary for our planned capital budget or our operations, we could be required to curtail our operations and the development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operations and financial position.  Additionally, to the extent the COVID-19 pandemic adversely affects our business and financial results, it may have the effect of heightening many of the other risks set forth in “Item 1A. Risk Factors” in our Annual Report on Form 10-K, filed with the SEC on March 10, 2020.

The inability of our customers or other counterparties to meet their obligations to us may adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposures to credit risk are through joint interest receivables ($7.0 million as of September 30, 2020) and the sale of our natural gas, NGLs and oil production ($53.5 million in receivables as of September 30, 2020). Joint interest receivables arise from billing entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we wish to drill. We can do very little to choose who participates in our wells. For the three months ended September 30, 2020, two customers, BP Energy Company and Marathon Petroleum Company, LP, accounted for approximately 22% and 15% of our revenues, respectively. As a general policy, we do not always require our customers to post collateral, although customers’ financial condition and creditworthiness are evaluated regularly. The inability or failure of our customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Moreover, the COVID-19 pandemic has generally affected our customers, suppliers, vendors, and other business partners, but we are not able to assess the full extent of the current impact nor predict the ultimate consequences that will result therefrom. If our customers or suppliers experience adverse business consequences due to the spread of COVID-19 or the economic effects therefrom or relating thereto, existing counterparties could seek to invoke “force majeure” clauses, or otherwise seek to excuse their performance, or default, under their respective contracts with us, which could adversely affect our performance under other contracts. The extent to which COVID-19 may impact the counterparties in which we engage in business will depend on future developments, which are highly uncertain and cannot be predicted at this time.  

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Item 6. Exhibits

Exhibit No.	Description
2.1+	Agreement and Plan of Merger, dated as of August 25, 2018, among Eclipse Resources Corporation, Everest Merger Sub Inc., and Blue Ridge Mountain Resources, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).
2.2	Amendment No. 1 to Agreement and Plan of Merger, dated as of January 7, 2019, among Eclipse Resources Corporation, Everest Merger Sub Inc., and Blue Ridge Mountain Resources, Inc. (incorporated by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K filed with the SEC on January 7, 2019).
2.3+	Agreement and Plan of Merger, dated as of August 12, 2020, by and between Montage Resources Corporation and Southwestern Energy Company (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2020).
3.1	Second Amended and Restated Certificate of Incorporation of Montage Resources Corporation (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).
3.2	Second Amended and Restated Bylaws of Montage Resources Corporation (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).
3.3	Certificate of Ownership and Merger, filed with the Secretary of State of the State of Delaware with an effective date of February 28, 2019 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).
4.1	Amended and Restated Registration Rights Agreement, dated January 28, 2015, by and among Eclipse Resources Corporation, Eclipse Resources Holdings, L.P., CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P., Eclipse Management, L.P., Buckeye Investors L.P., GSO Capital Opportunities Fund II (Luxembourg) S.à.r.l., Fir Tree Value Master Fund, L.P., Luxor Capital Partners, LP and Luxor Capital Partners Offshore Master Fund, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 29, 2015).
4.2	Indenture, dated as of July 6, 2015, between Eclipse Resources Corporation, the guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 8, 2015).
4.3	Registration Rights Agreement, dated as of January 18, 2018, by and among Eclipse Resources Corporation, Eclipse Resources-PA, LP, and Travis Peak Resources, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 22, 2018).
10.1	Letter Agreement, dated as of September 28, 2020, by and among Montage Resources Corporation, as borrower, certain of the Company’s subsidiaries, as guarantors, Bank of Montreal, as administrative agent, and each of the lenders that are party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on October 1, 2020).
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) of the Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) of the Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

55

101.INS*	Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*	Inline XBRL Taxonomy Extension Schema Document.
101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104*	Cover Page Interactive Data File (embedded within the Inline XBRL document).

+ Schedules have been omitted pursuant to Item 601(b)(2) or (5) of Regulation S-K. Montage Resources Corporation agrees to furnish a copy of such schedules, or any section thereof, to the SEC upon request.

* Filed herewith.

** These exhibits are furnished herewith and shall not be deemed “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act.

56

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

November 6, 2020	MONTAGE RESOURCES CORPORATION (Registrant)
	/s/ John K. Reinhart
	John K. Reinhart,
	President and Chief Executive Officer
	/s/ Michael L. Hodges
	Michael L. Hodges,
	Executive Vice President and Chief Financial Officer

57

EX-31.1

Exhibit 31.1

CERTIFICATION

I, John K. Reinhart, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Montage Resources Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

November 6, 2020

/s/ John K. Reinhart

John K. Reinhart

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Michael L. Hodges, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Montage Resources Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

November 6, 2020

/s/ Michael L. Hodges

Michael L. Hodges

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this report of Montage Resources Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), John K. Reinhart, President and Chief Executive Officer of the Company hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 6, 2020	/s/ John K. Reinhart
	John K. Reinhart
	President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this report of Montage Resources Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Michael L. Hodges, Executive Vice President and Chief Financial Officer of the Company hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 6, 2020	/s/ Michael L. Hodges
	Michael L. Hodges
	Executive Vice President and Chief Financial Officer

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2020	Nov. 02, 2020
Cover [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2020
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q3
Trading Symbol	MR
Entity Registrant Name	Montage Resources Corporation
Entity Central Index Key	0001600470
Entity Current Reporting Status	Yes
Entity Shell Company	false
Entity File Number	001-36511
Entity Tax Identification Number	46-4812998
Entity Address, Address Line One	122 West John Carpenter Freeway
Entity Address, Address Line Two	Suite 300
Entity Address, City or Town	Irving
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75039
City Area Code	469
Local Phone Number	444-1647
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		36,023,973
Entity Interactive Data Current	Yes
Title of 12(b) Security	Common Stock, Par Value $0.01 Per Share
Security Exchange Name	NYSE
Entity Incorporation, State or Country Code	DE
Document Quarterly Report	true
Document Transition Report	false

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2020	Dec. 31, 2019
CURRENT ASSETS
Cash and cash equivalents	$ 4,013	$ 12,056
Accounts receivable	63,483	77,402
Assets held for sale	1,544	1,047
Other current assets	8,984	35,509
Total current assets	78,024	126,014
Oil and natural gas properties, successful efforts method:
Unproved properties	478,644	508,576
Proved oil and gas properties, net	1,216,836	1,251,105
Other property and equipment, net	10,311	11,226
Total property and equipment, net	1,705,791	1,770,907
OTHER NONCURRENT ASSETS
Other assets	5,353	7,616
Operating lease right-of-use assets	30,830	36,975
Assets held for sale	3,403	9,665
TOTAL ASSETS	1,823,401	1,951,177
CURRENT LIABILITIES
Accounts payable	120,785	119,907
Accrued capital expenditures	11,933	43,500
Accrued liabilities	61,963	53,866
Accrued interest payable	9,921	21,308
Liabilities associated with assets held for sale	3,711	2,815
Operating lease liability	12,773	12,666
Total current liabilities	221,086	254,062
NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs	502,622	500,541
Revolving credit facility	170,000	130,000
Asset retirement obligations	30,336	29,877
Other liabilities	31,421	8,029
Operating lease liability	18,805	24,569
Liabilities associated with assets held for sale	7,150	7,013
Total liabilities	981,420	954,091
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, 36,034,837 and 35,770,934 shares issued and outstanding, respectively	386	383
Additional paid in capital	2,355,890	2,352,309
Treasury stock, shares at cost; 2,600,672 and 2,508,485 shares, respectively	(10,511)	(10,049)
Accumulated deficit	(1,503,784)	(1,345,557)
Total stockholders’ equity	841,981	997,086
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 1,823,401	$ 1,951,177

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Sep. 30, 2020	Dec. 31, 2019
Statement Of Financial Position [Abstract]
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, shares issued	36,034,837	35,770,934
Common stock, shares outstanding	36,034,837	35,770,934
Treasury stock, shares	2,600,672	2,508,485

XML

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
REVENUES
Revenues	$ 115,405	$ 163,295	$ 339,513	$ 460,332
OPERATING EXPENSES
Lease operating	11,494	11,986	33,436	29,651
Transportation, gathering and compression	$ 51,961	$ 57,027	$ 157,472	$ 150,065
Cost, Product and Service [Extensible List]	us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember	us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember	us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember	us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember
Production and ad valorem taxes	$ 3,677	$ 1,660	$ 10,146	$ 8,519
Brokered natural gas and marketing expense	7,345	10,574	24,349	32,017
Depreciation, depletion, amortization and accretion	53,153	45,456	140,058	113,950
Exploration	11,767	16,621	34,112	48,602
General and administrative	12,144	14,580	33,594	57,074
Rig termination and standby	303	1,221	303	1,221
Gain on sale of assets	(62)	(733)	(1,419)	(731)
Other expense	87	2	121	40
Total operating expenses	151,869	158,394	432,172	440,408
OPERATING INCOME (LOSS)	(36,464)	4,901	(92,659)	19,924
OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments	(40,535)	15,812	(11,329)	40,620
Interest expense, net	(14,402)	(15,192)	(44,166)	(44,140)
Other income	2		19	8
Total other income (expense), net	(54,935)	620	(55,476)	(3,512)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(91,399)	5,521	(148,135)	16,412
INCOME (LOSS) FROM CONTINUING OPERATIONS	(91,399)	5,521	(148,135)	16,412
Income (loss) from discontinued operations, net of income tax	(801)	(1,237)	(10,092)	1,286
NET INCOME (LOSS)	$ (92,200)	$ 4,284	$ (158,227)	$ 17,698
Basic:
Weighted average common stock outstanding	36,035	35,684	35,889	32,343
Income (loss) from continuing operations	$ (2.54)	$ 0.15	$ (4.13)	$ 0.51
Income (loss) from discontinued operations	(0.02)	(0.03)	(0.28)	0.04
Net income (loss)	$ (2.56)	$ 0.12	$ (4.41)	$ 0.55
Diluted:
Weighted average common stock outstanding	36,035	35,697	35,889	32,471
Income (loss) from continuing operations	$ (2.54)	$ 0.15	$ (4.13)	$ 0.51
Income (loss) from discontinued operations	(0.02)	(0.03)	(0.28)	0.04
Net income (loss)	$ (2.56)	$ 0.12	$ (4.41)	$ 0.55
Oil and Gas [Member]
REVENUES
Revenues	$ 108,518	$ 153,021	$ 315,471	$ 428,278
Brokered Natural Gas and Marketing Revenue [Member]
REVENUES
Revenues	6,831	10,228	23,859	31,747
Other Revenue [Member]
REVENUES
Revenues	$ 56	$ 46	$ 183	$ 307

XML

Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Accumulated Deficit [Member]
Beginning Balances at Dec. 31, 2018	$ 687,486	$ 3,043	$ 2,065,119	$ (3,357)	$ (1,377,319)
Beginning Balance, shares at Dec. 31, 2018		20,169,063
Stock-based compensation	6,001		6,001
Equity issuance costs	(30)		(30)
Shares of common stock issued in merger, net of equity issuance costs	275,759	$ 150	275,609
Shares of common stock issued in merger, net of equity issuance costs, shares		15,013,520
Reverse split		$ (2,833)	2,833
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings	(5,394)	$ 22	(5)	(5,411)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings, shares		499,897
Net income (loss)	(14,098)				(14,098)
Ending Balances at Mar. 31, 2019	949,724	$ 382	2,349,527	(8,768)	(1,391,417)
Ending Balance, shares at Mar. 31, 2019		35,682,480
Beginning Balances at Dec. 31, 2018	687,486	$ 3,043	2,065,119	(3,357)	(1,377,319)
Beginning Balance, shares at Dec. 31, 2018		20,169,063
Net income (loss)	17,698
Ending Balances at Sep. 30, 2019	982,014	$ 382	2,350,072	(8,819)	(1,359,621)
Ending Balance, shares at Sep. 30, 2019		35,756,088
Beginning Balances at Mar. 31, 2019	949,724	$ 382	2,349,527	(8,768)	(1,391,417)
Beginning Balance, shares at Mar. 31, 2019		35,682,480
Stock-based compensation	552		552
Equity issuance costs	(925)		(925)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings	(26)			(26)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings, shares		4,727
Net income (loss)	27,512				27,512
Ending Balances at Jun. 30, 2019	976,837	$ 382	2,349,154	(8,794)	(1,363,905)
Ending Balance, shares at Jun. 30, 2019		35,687,207
Stock-based compensation	1,061		1,061
Issuance of restricted stock, shares		50,568
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings	(168)		(143)	(25)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings, shares		18,313
Net income (loss)	4,284				4,284
Ending Balances at Sep. 30, 2019	982,014	$ 382	2,350,072	(8,819)	(1,359,621)
Ending Balance, shares at Sep. 30, 2019		35,756,088
Beginning Balances at Dec. 31, 2019	997,086	$ 383	2,352,309	(10,049)	(1,345,557)
Beginning Balance, shares at Dec. 31, 2019		35,770,934
Stock-based compensation	860		860
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings	(95)			(95)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings, shares		33,610
Net income (loss)	2,827				2,827
Ending Balances at Mar. 31, 2020	1,000,678	$ 383	2,353,169	(10,144)	(1,342,730)
Ending Balance, shares at Mar. 31, 2020		35,804,544
Beginning Balances at Dec. 31, 2019	997,086	$ 383	2,352,309	(10,049)	(1,345,557)
Beginning Balance, shares at Dec. 31, 2019		35,770,934
Net income (loss)	(158,227)
Ending Balances at Sep. 30, 2020	841,981	$ 386	2,355,890	(10,511)	(1,503,784)
Ending Balance, shares at Sep. 30, 2020		36,034,837
Beginning Balances at Mar. 31, 2020	1,000,678	$ 383	2,353,169	(10,144)	(1,342,730)
Beginning Balance, shares at Mar. 31, 2020		35,804,544
Stock-based compensation	1,764		1,764
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings	(368)	$ 3	(4)	(367)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings, shares		230,293
Net income (loss)	(68,854)				(68,854)
Ending Balances at Jun. 30, 2020	933,220	$ 386	2,354,929	(10,511)	(1,411,584)
Ending Balance, shares at Jun. 30, 2020		36,034,837
Stock-based compensation	961		961
Net income (loss)	(92,200)				(92,200)
Ending Balances at Sep. 30, 2020	$ 841,981	$ 386	$ 2,355,890	$ (10,511)	$ (1,503,784)
Ending Balance, shares at Sep. 30, 2020		36,034,837

XML

Condensed Consolidated Statements of Stockholders' Equity (Unaudited) (Parenthetical)	3 Months Ended
	Mar. 31, 2019 $ / shares	Sep. 30, 2020 $ / shares	Jun. 30, 2020 $ / shares	Mar. 31, 2020 $ / shares	Dec. 31, 2019 $ / shares	Sep. 30, 2019 $ / shares	Jun. 30, 2019 $ / shares
Statement Of Stockholders Equity [Abstract]
Common stock, par value	$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Reverse split ratio	0.067

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (158,227)	$ 17,698
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, amortization and accretion	140,579	114,331
Exploration expense	30,311	36,193
Stock-based compensation	3,585	7,614
Impairment of oil and gas properties	6,849
Net cash for plugging wells	(222)	(444)
(Gain) loss on derivative instruments	11,329	(40,620)
Net cash receipts on settled derivatives	61,877	11,072
Gain on sale of assets	(1,478)	(734)
Amortization of deferred financing costs	2,041	2,160
Amortization of debt discount	1,000	998
Changes in operating assets and liabilities:
Accounts receivable	15,437	68,056
Other assets	(126)	619
Accounts payable and accrued liabilities	(40,124)	(40,634)
Net cash provided by operating activities	72,831	176,309
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for oil and gas properties	(122,019)	(268,768)
Capital expenditures for other property and equipment	(271)	(576)
Proceeds from sale of assets	1,393	1,810
Cash acquired in merger		12,894
Change in deposits and other long-term assets		(53)
Net cash used in investing activities	(120,897)	(254,693)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from other notes payable	1,141
Debt issuance costs	(80)	(4,242)
Repayments of long-term debt	(575)	(260)
Proceeds from revolving credit facility	40,000	95,000
Equity issuance costs		(31)
Employee tax withholding for settlement of equity compensation awards	(463)	(6,511)
Net cash provided by financing activities	40,023	83,956
Net increase (decrease) in cash and cash equivalents	(8,043)	5,572
Cash and cash equivalents at beginning of period	12,056	5,959
Cash and cash equivalents at end of period	4,013	11,531
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest	52,590	51,280
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES
Asset retirement obligations incurred, including changes in estimate	196	1,006
Additions to oil and natural gas properties - changes in accounts payable, accrued liabilities, and accrued capital expenditures	$ (18,541)	16,583
BRMR Merger consideration		$ 275,759

XML

Organization and Nature of Operations

9 Months Ended

Sep. 30, 2020

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Organization and Nature of Operations

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.

XML

Basis of Presentation

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

Basis of Presentation

Note 2—Basis of Presentation

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

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

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

• 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.

Proposed Merger with Southwestern Energy Company

On August 12, 2020, the Company entered into an Agreement and Plan of Merger (the “Southwestern Merger Agreement”) with Southwestern, pursuant to which the Company will merge with and into Southwestern, with Southwestern continuing as the surviving corporation (the “merger”).  On the terms and subject to the conditions set forth in the Southwestern Merger Agreement, upon consummation of the merger, each issued and outstanding share of the Company’s common stock will be converted into the right to receive 1.8656 shares of Southwestern common stock.

The merger is subject to various closing conditions, including, but not limited to, (i) the adoption of the Southwestern Merger Agreement by the holders of a majority of the Company’s outstanding common stock entitled to vote, (ii) the absence of any law, order or injunction prohibiting the merger, (iii) the expiration or earlier termination of the waiting period under the Hart–Scott–Rodino Antitrust Improvements Act of 1976, as amended (which termination was received on September 9, 2020), (iv) the SEC having declared effective Southwestern’s registration statement on Form S-4 filed in connection with the merger (which the SEC declared on October 6, 2020), (v) the shares of Southwestern common stock issuable in connection with the merger having been authorized for listing on the New York Stock Exchange, upon official notice of issuance, (vi) the accuracy of each party’s representations and warranties, and (vii) each party’s compliance with its covenants and agreements contained in the Southwestern Merger Agreement.

The Southwestern Merger Agreement provides for certain termination rights for both the Company and Southwestern, including the right of either party to terminate the Southwestern Merger Agreement if the merger is not consummated by February 12, 2021 (provided certain conditions are met).  Upon termination of the Southwestern Merger Agreement under specified circumstances, the Company would be required to pay Southwestern a termination fee of $9.7 million.  

In connection with the merger, Southwestern filed with the SEC, on October 2, 2020, an amendment to the registration statement on Form S-4 that was originally filed on September 16, 2020, which includes a proxy statement of the Company. The proxy statement also constitutes a prospectus of Southwestern with respect to the shares of Southwestern common stock to be issued to the Company’s stockholders pursuant to the Southwestern Merger Agreement. The registration statement was declared effective by the SEC on October 6, 2020, and the Company commenced mailing the definitive proxy statement/prospectus to the Company’s stockholders on or about October 8, 2020. The Company will hold a special meeting of its stockholders on November 12, 2020 in connection with the merger. Subject to the satisfaction or waiver of the closing conditions, the merger is expected to close in the fourth quarter of 2020.

Additional information on the proposed merger is included in the Form S-4/A filed by Southwestern with the SEC on October 2, 2020, the definitive proxy statement/prospectus filed by the Company with the SEC on October 6, 2020, and this Quarterly Report, including Part II, Item 1A.

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 3—Summary of Significant Accounting Policies

(a) Cash and Cash Equivalents

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

(b) Accounts Receivable

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

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

(c) Property and Equipment

Oil and Natural Gas Properties

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

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

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s Condensed Consolidated Balance Sheets. Upon the sale of an entire interest in an unproved property where the property had been

assessed for impairment individually, a gain or loss is recognized in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

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

	September 30, 2020			December 31, 2019
Oil and natural gas properties:
Unproved	$	478,644		$	508,576
Proved		2,885,622			2,783,232
Gross oil and natural gas properties		3,364,266			3,291,808
Less accumulated depreciation, depletion and amortization		(1,668,786	)		(1,532,127	)
Oil and natural gas properties, net		1,695,480			1,759,681
Other property and equipment		19,596			20,000
Less accumulated depreciation		(9,285	)		(8,774	)
Other property and equipment, net		10,311			11,226
Property and equipment, net	$	1,705,791		$	1,770,907

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

Other Property and Equipment

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

(d) Revenue Recognition

Product Revenue

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

Natural Gas

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

NGLs

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

Oil

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

Marketing Revenue

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

Disaggregation of Revenue

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Revenues (in thousands)
Natural gas sales	$	72,926	$	87,841	$	217,604	$	264,030
NGL sales		18,439		20,200		44,949		60,841
Oil sales		17,153		44,980		52,918		103,407
Brokered natural gas and marketing revenue		6,831		10,228		23,859		31,747
Other revenue		56		46		183		307
Total revenues	$	115,405	$	163,295	$	339,513	$	460,332

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 $53.5 million and $63.7 million as of September 30, 2020 and December 31, 2019, respectively.

(e) Concentration of Credit Risk

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

	September 30, 2020		December 31, 2019
Receivables by product or service:
Sale of oil and natural gas and related products and    services	$	53,466	$	63,730
Joint interest owners		6,983		12,156
Derivatives		1,728		210
Other		1,306		1,306
Total	$	63,483	$	77,402

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

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to the credit risk of the counterparties to these derivative instruments. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, the Company’s policy is to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. Such counterparties are not required to provide credit support to the Company. The fair value of the Company’s unsettled derivative contracts was a net liability position of ($47.7) million and a net asset position of $27.1 million as of September 30, 2020 and December 31, 2019, respectively. Other than as provided by its revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s derivative contracts. As of September 30, 2020 and December 31, 2019, the Company did not have past-due receivables from or payables to any of such counterparties.

(f) Depreciation, Depletion, Amortization and Accretion

Oil and Natural Gas Properties

Depreciation, depletion, amortization and accretion (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties, including accretion expense, totaled approximately $52.8 million and $44.9 million for the three months ended September 30, 2020 and 2019, respectively, and $138.9 million and $112.4 million for the nine months ended September 30, 2020 and 2019, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from five to 40 years. Depreciation totaled approximately $0.4 million and $0.6 million for the three months ended September 30, 2020 and 2019, respectively, and $1.2 million and $1.6 million for the nine months ended September 30, 2020 and 2019, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

(g) Impairment of Long-Lived Assets

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

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

When an impairment charge is recognized it represents a significant Level 3 measurement in the fair value hierarchy. The primary input used is the Company’s forecasted discount net cash flows.

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

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of approximately $11.0 million and $14.1 million for the three months ended September 30, 2020 and 2019, respectively, and $30.3 million and $36.2 million for the nine months ended September 30, 2020 and 2019, respectively. These costs are included in exploration expense in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

(h) Income Taxes

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

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

(i) Fair Value of Financial Instruments

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

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

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

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

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

(j) Derivative Financial Instruments

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

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

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

(k) Asset Retirement Obligation

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

Estimating the future ARO requires management to make estimates and judgments based on historical information regarding timing and existence of a liability, as well as what constitutes adequate restoration.  Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Approximately $2.9 million and $2.0 million, representing the current portion of ARO liability, are included in “Accrued liabilities” in the accompanying Condensed Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019, respectively.  The following table sets forth the changes in the Company’s ARO liability for the nine months ended September 30, 2020 (in thousands):

	Nine Months Ended September 30, 2020
Asset retirement obligations, beginning of period	$	31,841
Accretion		2,245
Additional liabilities incurred		15
Obligation for wells drilled		181
Liabilities settled via plugging		(178	)
Liabilities sold/disposed		(901	)
Less: current ARO portion		(2,867	)
Asset retirement obligations, end of period	$	30,336

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

(l) Off-Balance Sheet Arrangements

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

(m) Segment Reporting

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

(n) Debt Issuance Costs

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

During the three and nine months ended September 30, 2020, the Company amortized $0.9 million and $3.0 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method which includes $0.2 million of unamortized deferred financing costs that the Company wrote off during the second quarter of 2020 in connection with the borrowing base redetermination of the Company’s revolving credit facility (See Note 8— Debt).  During the three and nine months ended September 30, 2019, the Company amortized $0.9 million and $3.2 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method. 

(o) Recent Accounting Pronouncements

Accounting Pronouncements Not Yet Adopted

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

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Acquisitions

9 Months Ended

Sep. 30, 2020

Business Combinations [Abstract]

Acquisitions

Note 4—Acquisitions

Merger with Blue Ridge Mountain Resources

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

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

In connection with the BRMR Merger, the Company incurred $3.3 million of costs for the three months ended September 30, 2019, and $0.2 million and $21.8 million for the nine months ended September 30, 2020 and 2019, respectively, which are included in general and administrative expense on the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).  The Company did not incur any costs during the three months ended September 30, 2020 in connection with the BRMR Merger.  Approximately $100.5 million of revenues and approximately $16.0 million of net income from continuing operations attributed to the BRMR Merger are included in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to September 30, 2019.  Approximately $5.4 million of revenues and approximately $1.3 million of net income from discontinued operations attributed to the BRMR Merger are included in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to September 30, 2019.

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.

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

	Three Months Ended September 30,		Nine Months Ended September 30,
(in thousands, except per share data) (unaudited)	2019		2019
Pro forma total revenues	$	163,295	$	502,989
Pro forma net income	$	4,543	$	24,834
Pro forma net income per share (basic)	$	0.13	$	0.70
Pro forma net income per share (diluted)	$	0.13	$	0.69

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Assets Held for Sale and Discontinued Operations

9 Months Ended

Sep. 30, 2020

Discontinued Operations And Disposal Groups [Abstract]

Assets Held for Sale and Discontinued Operations

Note 5—Assets Held for Sale and Discontinued Operations

Assets Held for Sale

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

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

(in thousands)	September 30, 2020		December 31, 2019
Accounts receivable	$	758	$	343
Other current assets		786		704
Total current assets held for sale	$	1,544	$	1,047
Proved oil and gas properties, net	$	3,351	$	9,528
Other noncurrent assets		52		137
Total noncurrent assets held for sale	$	3,403	$	9,665
Accounts payable	$	2,104	$	2,067
Accrued liabilities		1,576		570
Other current liabilities		31		178
Total current liabilities associated with assets held for sale	$	3,711	$	2,815
Asset retirement obligations	$	7,146	$	6,488
Other liabilities		4		525
Total noncurrent liabilities associated with assets held for sale	$	7,150	$	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 the three and nine months ended September 30, 2020 and 2019.  The Company included the results of operations for MHP for the three and nine months ended September 30, 2020 and 2019 in discontinued operations as follows:

(in thousands)	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
Revenues	$	698		$	1,874		$	2,948		$	5,402
Impairment of proved oil and natural gas properties		—			—			(6,849	)		—
Depreciation, depletion, amortization and accretion		(182	)		(168	)		(523	)		(380	)
Other operating expenses		(1,317	)		(2,943	)		(5,668	)		(3,738	)
Other income		—			—			—			2
Income (loss) from discontinued operations, net of tax	$	(801	)	$	(1,237	)	$	(10,092	)	$	1,286

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

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

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

(in thousands)	Nine Months Ended September 30,
	2020			2019
Net cash provided by operating activities	$	693		$	1,189
Net cash provided by (used in) investing activities	$	(82	)	$	14

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Derivative Instruments

9 Months Ended

Sep. 30, 2020

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Instruments

Note 6—Derivative Instruments

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

Commodity Derivatives

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

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

Natural Gas Derivatives:

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		130,000	October 2020 – December 2020	$	2.42
		145,000	October 2020 – March 2021	$	2.58
		50,000	January 2021 – March 2022	$	2.51
		25,000	April 2021 – March 2022	$	2.47
Natural Gas Collars:
Floor purchase price (put)		25,000	January 2021 – December 2021	$	2.15
Ceiling sold price (call)		25,000	January 2021 – December 2021	$	3.03
Floor purchase price (put)		30,000	April 2021 – March 2022	$	2.40
Ceiling sold price (call)		30,000	April 2021 – March 2022	$	3.05
Floor purchase price (put)		15,000	August 2021 – December 2021	$	2.55
Ceiling sold price (call)		15,000	August 2021 – December 2021	$	3.13
Floor purchase price (put)		15,000	September 2021 – November 2021	$	2.52
Ceiling sold price (call)		15,000	September 2021 – November 2021	$	3.12
Floor purchase price (put)		5,000	August 2021	$	2.50
Ceiling sold price (call)		5,000	August 2021	$	3.05
Floor purchase price (put)		10,000	September 2021	$	2.50
Ceiling sold price (call)		10,000	September 2021	$	3.03
Natural Gas Three-way Collars:
Floor purchase price (put)		80,000	October 2020 – December 2020	$	2.60
Floor sold price (put)		80,000	October 2020 – December 2020	$	1.90
Ceiling sold price (call)		80,000	October 2020 – December 2020	$	2.94
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
Floor purchase price (put)		20,000	April 2021 – March 2022	$	2.62
Floor sold price (put)		20,000	April 2021 – March 2022	$	2.20
Ceiling sold price (call)		20,000	April 2021 – March 2022	$	3.10
Natural Gas Call/Put Options:
Floor sold price (put)		50,000	October 2020 – December 2020	$	2.30
Swaption sold price (call)		50,000	January 2021 – December 2021	$	2.75
Swaption sold price (call)		50,000	January 2022 – December 2022	$	3.00
Ceiling sold price (call)		50,000	January 2022 – December 2022	$	3.00
Floor sold price (put)		50,000	January 2021 – March 2022	$	2.00
Ceiling sold price (call)		80,000	January 2023 – December 2023	$	3.00
Basis Swaps:
Appalachia - Dominion		42,500	October 2020	$	(0.51	)
Appalachia - Dominion		20,000	October 2020 – December 2020	$	(0.59	)

Oil Derivatives:

Description	Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)
Oil Swaps:
		2,500	October 2020 – December 2020	$	57.41
		250	October 2020 – March 2021	$	53.20
		250	January 2021 – March 2021	$	53.00
		100	January 2021	$	43.60
Oil Collars:
Floor purchase price (put)		1,000	October 2020 – December 2020	$	51.00
Ceiling sold price (call)		1,000	October 2020 – December 2020	$	62.00
Floor purchase price (put)		500	January 2021 – December 2021	$	37.50
Ceiling sold price (call)		500	January 2021 – December 2021	$	45.50
Floor purchase price (put)		300	April 2021	$	40.00
Ceiling sold price (call)		300	April 2021	$	47.25
Floor purchase price (put)		200	May 2021	$	40.00
Ceiling sold price (call)		200	May 2021	$	47.55
Floor purchase price (put)		100	June 2021	$	40.00
Ceiling sold price (call)		100	June 2021	$	47.75
Oil Three-way Collars:
Floor purchase price (put)		500	January 2021 – December 2021	$	31.25
Floor sold price (put)		500	January 2021 – December 2021	$	22.50
Ceiling sold price (call)		500	January 2021 – December 2021	$	45.00
Oil Call/Put Options:
Floor sold price (put)		500	October 2020 – December 2020	$	45.00
Swaption sold price (call)		500	January 2021 – December 2021	$	42.50

NGL Derivatives:

Description	Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)
Propane Swaps:
		2,000	October 2020 – December 2020	$	20.94
		1,000	January 2021 – December 2021	$	18.87

Interest Rate Swap

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

Fair Values and Gains (Losses)

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

As of September 30, 2020	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	7,423		$	(4,213	)		3,210		Other current assets
Total assets	$	7,423		$	(4,213	)	$	3,210
Liabilities
Commodity derivatives - current	$	(27,338	)	$	4,213		$	(23,125	)	Accrued liabilities
Interest-rate swap - current		(103	)		—			(103	)	Accrued liabilities
Commodity derivatives - noncurrent		(27,269	)		—			(27,269	)	Other liabilities
Interest-rate swap - noncurrent		(404	)		—			(404	)	Other liabilities
Total liabilities	$	(55,114	)	$	4,213		$	(50,901	)

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	)

(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 Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the periods presented (in thousands):

		Amount of Gain (Loss) Recognized in Income
Derivatives not designated as hedging instruments under ASC 815	Location of Gain (Loss) Recognized in Income	Three Months Ended September 30,					Nine Months Ended September 30,
		2020			2019		2020			2019
Commodity derivatives	Gain (loss) on derivative instruments	$	(40,603	)	$	15,812	$	(10,861	)	$	40,620
Interest-rate swap	Gain (loss) on derivative instruments		68			—		(468	)		—
Total		$	(40,535	)	$	15,812	$	(11,329	)	$	40,620

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Fair Value Measurements

9 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

Fair Value Measurements

Note 7—Fair Value Measurements

Fair Value Measurement on a Recurring Basis

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

	Level 1		Level 2			Level 3		Total Fair Value
As of September 30, 2020: (in thousands)
Commodity derivative instruments	$	—	$	(47,184	)	$	—	$	(47,184	)
Interest-rate swap		—		(507	)		—		(507	)
Total	$	—	$	(47,691	)	$	—	$	(47,691	)
As of December 31, 2019: (in thousands)
Commodity derivative instruments	$	—	$	27,117		$	—	$	27,117
Total	$	—	$	27,117		$	—	$	27,117

Nonfinancial Assets and Liabilities

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

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

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

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Debt

9 Months Ended

Sep. 30, 2020

Debt Disclosure [Abstract]

Debt

Note 8—Debt

8.875% Senior Unsecured Notes Due 2023

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

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

On October 6, 2020, the Company notified the trustee under the indenture that the Company had elected to redeem, subject to certain conditions (the “Redemption”), all of its outstanding senior unsecured notes. On October 9, 2020, the Company issued a conditional notice of full redemption to redeem all of its outstanding senior unsecured notes. The anticipated redemption date is November 13, 2020 (the “Redemption Date”). The redemption price for the senior unsecured notes will be 102.219% (the “Redemption Price”) of the aggregate principal amount being redeemed, plus accrued but unpaid interest on the senior unsecured notes redeemed to, but not including, the Redemption Date. Upon the Redemption by the Company of the senior unsecured notes, none of the senior unsecured notes will remain outstanding.    

Redemption of the senior unsecured notes is conditional on the consummation of the transactions set forth in the Southwestern Merger Agreement, pursuant to which, on the terms and subject to the conditions set forth therein, among other things, (i) the Company will merge with and into Southwestern, with Southwestern continuing as the surviving company, and (ii) Southwestern will deposit cash proceeds with the trustee under the indenture in an amount at least sufficient to pay and discharge the Redemption Price, all accrued and unpaid interest on the senior unsecured notes redeemed to, but not including, the Redemption Date and all other amounts owing under the indenture. The Company may delay the Redemption Date until such time as the foregoing conditions are satisfied, or such redemption may not occur and the conditional notice of redemption may be rescinded in the event that the foregoing conditions are not satisfied by the Redemption Date, or by such later date to which the Redemption Date has been delayed.

Based on Level 2 market data inputs, the fair value of the senior unsecured notes as of September 30, 2020 was $519.0 million.

Revolving Credit Facility

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

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

On September 28, 2020, the Company entered into a letter agreement with its lenders to, among other things, (i) postpone the scheduled redetermination of the borrowing base under the Credit Agreement from October 1, 2020 until on or about November 15, 2020, (ii) obtain the lenders’ consent to the Company’s sending of a notice of redemption to the holders of the Company’s senior unsecured notes in accordance with the terms of the Southwestern Merger Agreement, and (iii) obtain the lenders’ consent to the redemption of the senior unsecured notes in full; provided, that such redemption occurs concurrently with the date that the secured obligations under the Credit Agreement are paid in full in cash and the transactions contemplated by the Southwestern Merger Agreement are consummated.

As of September 30, 2020, the borrowing base was $475 million and the Company had $170.0 million in outstanding borrowings under the revolving credit facility. After giving effect to outstanding letters of credit issued by the Company totaling $29.2 million and the outstanding borrowings of $170.0 million, the Company had available borrowing capacity under the revolving credit facility of $275.8 million as of September 30, 2020.  

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

Other Notes Payable

From time to time, the Company enters into other notes payable for the purchase of vehicles and equipment or to finance its insurance premiums.  The Company had outstanding notes payable of $0.8 million and $0.3 million included in “Accrued liabilities” in the accompanying Condensed Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019, respectively.

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Benefit Plans

9 Months Ended

Sep. 30, 2020

Compensation And Retirement Disclosure [Abstract]

Benefit Plans

Note 9—Benefit Plans

Defined Contribution Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(k) of the Internal Revenue Code, as amended (the “Code”), under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(k) plan, the Company provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company recorded compensation expense related to matching contributions, classified under general and administrative, of $0.2 million and $0.3 million for the three months ended September 30, 2020 and 2019, respectively, and $0.9 million and $0.8 million for the nine months ended September 30, 2020 and 2019, respectively.

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Stock-Based Compensation

9 Months Ended

Sep. 30, 2020

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Stock-Based Compensation

Note 10—Stock-Based Compensation

The Company is authorized to grant up to 2,650,000 shares of common stock under its 2019 Long-Term Incentive Plan (the “2019 Plan”).  The 2019 Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, bonus stock or other stock-based awards and performance awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 303,911 shares were available for future grants under the Plan as of September 30, 2020.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Restricted stock units	$	357	$	445	$	1,424	$	3,773
Performance units		535		374		1,226		3,364
Restricted and unrestricted stock		69		242		935		477
Total expense	$	961	$	1,061	$	3,585	$	7,614

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 September 30, 2020, there was $3.1 million of total unrecognized compensation cost related to outstanding 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 nine months ended September 30, 2020 is as follows:

	Number of units			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2019		437,559		$	7.83	$	3,474
Granted		351,467			5.86
Vested		(214,804	)		9.14
Forfeited		(3,023	)		6.02
Total awarded and unvested, September 30, 2020		571,199		$	6.14	$	2,508

Performance Units

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

As of September 30, 2020, there was $4.1 million of total unrecognized compensation cost related to outstanding performance units. The weighted average period for the units to vest is approximately two years. A summary of performance stock unit awards activity during the nine months ended September 30, 2020 is as follows:

	Number of units			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2019		320,120		$	11.26	$	2,522
Granted		618,483			6.21
Vested		(51,858	)		20.89
Forfeited		(55,547	)		16.69
Total awarded and unvested, September 30, 2020		831,198		$	6.54	$	932

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

	Nine Months Ended September 30,
	2020			2019
Volatility		79.70	%		65.10	%
Risk-free interest rate		0.20	%		1.83	%

Restricted and Unrestricted Stock

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

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

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

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

As of September 30, 2020, there was $0.2 million of total unrecognized compensation cost related to restricted and unrestricted stock.

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Net Income (Loss) Per Share

9 Months Ended

Sep. 30, 2020

Earnings Per Share [Abstract]

Net Income (Loss) Per Share

Note 11—Net Income (Loss) Per Share

Net Income (Loss) Per Share

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

Reverse Stock Split

Effective immediately prior to the effective time of the BRMR Merger, on February 28, 2019 (See Note 4— Acquisitions), the Company effected a 15-to-1 reverse stock split of its common stock.  Holders of shares of the Company’s common stock immediately prior to the effective time received cash for any fractional shares of the Company’s common stock to which they might otherwise have been entitled as a result of the reverse stock split. The reverse stock split lowered the aggregate par value of the common stock reflected in the Consolidated Statements of Stockholders’ Equity to reflect the reduced shares with the offset to additional paid-in-capital.  The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the three and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,
(in thousands, except per share data)	2020								2019
	Loss			Shares		Per Share			Income		Shares		Per Share
Basic:
Net income (loss), shares, basic	$	(92,200	)		36,035	$	(2.56	)	$	4,284		35,684	$	0.12
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—			—					—		13
Diluted:
Net income (loss), shares, diluted	$	(92,200	)		36,035	$	(2.56	)	$	4,284		35,697	$	0.12

	Nine Months Ended September 30,
(in thousands, except per share data)	2020								2019
	Loss			Shares		Per Share			Income		Shares		Per Share
Basic:
Net income (loss), shares, basic	$	(158,227	)		35,889	$	(4.41	)	$	17,698		32,343	$	0.55
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—			—					—		128
Diluted:
Net income (loss), shares, diluted	$	(158,227	)		35,889	$	(4.41	)	$	17,698		32,471	$	0.55

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2020

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 12—Commitments and Contingencies

(a) Legal Matters

From time to time, the Company is 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 any legal proceedings to which the Company is a party.

Following the announcement of the Southwestern Merger Agreement, six complaints have been filed by purported Company stockholders challenging the merger; of those six complaints, three were filed in the United States District Court for the Southern District of New York, one in the United States District Court for the Eastern District of New York, one in the United States District Court for the District of Delaware and one in the Supreme Court of the State of New York, County of New York. The complaints are captioned as follows: Dinardo v. Montage Resources Corporation, et al., No. 1:20-cv-08416 (S.D.N.Y.); Raul v. Montage Resources Corporation, et al., No. 1:20-cv-08619 (S.D.N.Y.); Waldrop v. Montage Resources Corporation, et al., No. 1:20-cv-04995 (E.D.N.Y.); Wolf v. Montage Resources Corporation, et al., No. 1:20-cv-01324-UNA (D. Del.); Gordon v. Montage Resources

Corporation, et al. (Supreme Court of the State of New York, County of New York); and Widrick v. Montage Resources Corporation, et al. No. 1:20-cv-09101 (S.D.N.Y.).

The complaints name as defendants the Company and the Company’s directors, and two of the six complaints also name Southwestern as defendant. The complaints generally assert claims under Sections 14(a) and 20(a) of the Exchange Act, alleging, among other things, that the registration statement on Form S-4, originally filed on September 16, 2020, omits material information with respect to the merger and/or assert claims for breach of fiduciary duty under Delaware law against the Company and its directors. The complaints generally seek to enjoin the merger and seek rescission and rescissory damages, including attorneys’ fees, among other relief. The Company and Southwestern believe the claims are meritless.

(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 March 2020, the Company completed the renegotiation of certain existing gas gathering contracts with a midstream service provider into a single new consolidated gas gathering agreement.  Revised commitments under the new consolidated gas gathering agreement (in thousands) are included in the table below:

	Firm transportation(i)		Gas processing, gathering, and compression services(ii)		Total
Year Ending December 31:
Remainder of 2020	$	25,025	$	11,132	$	36,157
2021		99,828		44,801		144,629
2022		99,828		49,404		149,232
2023		99,828		52,342		152,170
2024		100,101		52,972		153,073
Thereafter		722,369		303,890		1,026,259
Total	$	1,146,979	$	514,541	$	1,661,520

(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 rates. The values in the table represent the gross amounts that the Company is committed to pay and do not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company records in its Condensed 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 do not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company records in its Condensed Consolidated Financial Statements its proportionate share of costs based on the Company’s working interest.

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Income Tax

9 Months Ended

Sep. 30, 2020

Income Tax Disclosure [Abstract]

Income Tax

Note 13—Income Tax

For the year ending December 31, 2020, the Company’s annual estimated effective tax rate is forecasted to be 0%, exclusive of discrete items.  The Company expects to incur a book loss and a tax loss in fiscal year 2020, and thus, no current federal income taxes are anticipated to be paid.  The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective tax rate to the Company’s year-to-date loss.  On December 22, 2017, Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, resulted in the reduction in the U.S. statutory rate for corporations from 35% to 21%.  The Company’s interest expense deduction has the potential to be limited as a result of the enactment of the Tax Cuts and Jobs Act and the

federal Coronavirus Aid, Relief, and Economic Security Act; however, the impact is anticipated to be minimal as a result of its full valuation allowance.

In forecasting the 2020 annual estimated effective tax rate, management believes that it should limit any tax benefit suggested by the tax effect of the forecasted book loss such that no net deferred tax asset is recorded in 2020. Management reached this conclusion considering several factors such as: (i) the lack of carryback potential resulting in a tax refund, and (ii) in light of current commodity pricing uncertainty, there is insufficient external evidence to suggest that net tax attribute carryforwards are collectible beyond offsetting existing deferred tax liabilities inherent in the Company’s Condensed Consolidated Balance Sheet.

The Company is forecasting pre-tax book loss for the year ending December 31, 2020.  As a result, no net income tax expense or benefit is allocable to either income from continuing operations or to discontinued operations.

In connection with the BRMR Merger (See Note 4— Acquisitions), the Company experienced an ownership change as described in Section 382 of the Code.  As a result, the Company’s net operating losses as well as certain tax deductions are subject to an annual limitation imposed by the 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.

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Subsidiary Guarantors

9 Months Ended

Sep. 30, 2020

Text Block [Abstract]

Subsidiary Guarantors

Note 14—Subsidiary Guarantors

Each subsidiary of the Company that guarantees the Company’s revolving credit facility is required to fully and unconditionally, jointly 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 8—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 senior unsecured notes 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.

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Subsequent Events

9 Months Ended

Sep. 30, 2020

Subsequent Events [Abstract]

Subsequent Events

Note 15—Subsequent Events

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

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

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

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

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

• 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.

Proposed Merger with Southwestern Energy Company

On August 12, 2020, the Company entered into an Agreement and Plan of Merger (the “Southwestern Merger Agreement”) with Southwestern, pursuant to which the Company will merge with and into Southwestern, with Southwestern continuing as the surviving corporation (the “merger”).  On the terms and subject to the conditions set forth in the Southwestern Merger Agreement, upon consummation of the merger, each issued and outstanding share of the Company’s common stock will be converted into the right to receive 1.8656 shares of Southwestern common stock.

The merger is subject to various closing conditions, including, but not limited to, (i) the adoption of the Southwestern Merger Agreement by the holders of a majority of the Company’s outstanding common stock entitled to vote, (ii) the absence of any law, order or injunction prohibiting the merger, (iii) the expiration or earlier termination of the waiting period under the Hart–Scott–Rodino Antitrust Improvements Act of 1976, as amended (which termination was received on September 9, 2020), (iv) the SEC having declared effective Southwestern’s registration statement on Form S-4 filed in connection with the merger (which the SEC declared on October 6, 2020), (v) the shares of Southwestern common stock issuable in connection with the merger having been authorized for listing on the New York Stock Exchange, upon official notice of issuance, (vi) the accuracy of each party’s representations and warranties, and (vii) each party’s compliance with its covenants and agreements contained in the Southwestern Merger Agreement.

The Southwestern Merger Agreement provides for certain termination rights for both the Company and Southwestern, including the right of either party to terminate the Southwestern Merger Agreement if the merger is not consummated by February 12, 2021 (provided certain conditions are met).  Upon termination of the Southwestern Merger Agreement under specified circumstances, the Company would be required to pay Southwestern a termination fee of $9.7 million.  

In connection with the merger, Southwestern filed with the SEC, on October 2, 2020, an amendment to the registration statement on Form S-4 that was originally filed on September 16, 2020, which includes a proxy statement of the Company. The proxy statement also constitutes a prospectus of Southwestern with respect to the shares of Southwestern common stock to be issued to the Company’s stockholders pursuant to the Southwestern Merger Agreement. The registration statement was declared effective by the SEC on October 6, 2020, and the Company commenced mailing the definitive proxy statement/prospectus to the Company’s stockholders on or about October 8, 2020. The Company will hold a special meeting of its stockholders on November 12, 2020 in connection with the merger. Subject to the satisfaction or waiver of the closing conditions, the merger is expected to close in the fourth quarter of 2020.

Additional information on the proposed merger is included in the Form S-4/A filed by Southwestern with the SEC on October 2, 2020, the definitive proxy statement/prospectus filed by the Company with the SEC on October 6, 2020, and this Quarterly Report, including Part II, Item 1A.

Cash and Cash Equivalents

(a) Cash and Cash Equivalents

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

Accounts Receivable

(b) Accounts Receivable

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

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

Property and Equipment

(c) Property and Equipment

Oil and Natural Gas Properties

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

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

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s Condensed Consolidated Balance Sheets. Upon the sale of an entire interest in an unproved property where the property had been

assessed for impairment individually, a gain or loss is recognized in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

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

	September 30, 2020			December 31, 2019
Oil and natural gas properties:
Unproved	$	478,644		$	508,576
Proved		2,885,622			2,783,232
Gross oil and natural gas properties		3,364,266			3,291,808
Less accumulated depreciation, depletion and amortization		(1,668,786	)		(1,532,127	)
Oil and natural gas properties, net		1,695,480			1,759,681
Other property and equipment		19,596			20,000
Less accumulated depreciation		(9,285	)		(8,774	)
Other property and equipment, net		10,311			11,226
Property and equipment, net	$	1,705,791		$	1,770,907

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

Other Property and Equipment

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

Revenue Recognition

(d) Revenue Recognition

Product Revenue

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

Natural Gas

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

NGLs

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

Oil

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

Marketing Revenue

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

Disaggregation of Revenue

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Revenues (in thousands)
Natural gas sales	$	72,926	$	87,841	$	217,604	$	264,030
NGL sales		18,439		20,200		44,949		60,841
Oil sales		17,153		44,980		52,918		103,407
Brokered natural gas and marketing revenue		6,831		10,228		23,859		31,747
Other revenue		56		46		183		307
Total revenues	$	115,405	$	163,295	$	339,513	$	460,332

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 $53.5 million and $63.7 million as of September 30, 2020 and December 31, 2019, respectively.

Concentration of Credit Risk

(e) Concentration of Credit Risk

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

	September 30, 2020		December 31, 2019
Receivables by product or service:
Sale of oil and natural gas and related products and    services	$	53,466	$	63,730
Joint interest owners		6,983		12,156
Derivatives		1,728		210
Other		1,306		1,306
Total	$	63,483	$	77,402

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

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to the credit risk of the counterparties to these derivative instruments. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, the Company’s policy is to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. Such counterparties are not required to provide credit support to the Company. The fair value of the Company’s unsettled derivative contracts was a net liability position of ($47.7) million and a net asset position of $27.1 million as of September 30, 2020 and December 31, 2019, respectively. Other than as provided by its revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s derivative contracts. As of September 30, 2020 and December 31, 2019, the Company did not have past-due receivables from or payables to any of such counterparties.

Depreciation, Depletion, Amortization, and Accretion

(f) Depreciation, Depletion, Amortization and Accretion

Oil and Natural Gas Properties

Depreciation, depletion, amortization and accretion (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties, including accretion expense, totaled approximately $52.8 million and $44.9 million for the three months ended September 30, 2020 and 2019, respectively, and $138.9 million and $112.4 million for the nine months ended September 30, 2020 and 2019, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from five to 40 years. Depreciation totaled approximately $0.4 million and $0.6 million for the three months ended September 30, 2020 and 2019, respectively, and $1.2 million and $1.6 million for the nine months ended September 30, 2020 and 2019, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

Impairment of Long-Lived Assets

(g) Impairment of Long-Lived Assets

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

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

When an impairment charge is recognized it represents a significant Level 3 measurement in the fair value hierarchy. The primary input used is the Company’s forecasted discount net cash flows.

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

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of approximately $11.0 million and $14.1 million for the three months ended September 30, 2020 and 2019, respectively, and $30.3 million and $36.2 million for the nine months ended September 30, 2020 and 2019, respectively. These costs are included in exploration expense in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

Income Taxes

(h) Income Taxes

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

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

Fair Value of Financial Instruments

(i) Fair Value of Financial Instruments

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

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

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

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

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

Derivative Financial Instruments

(j) Derivative Financial Instruments

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

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

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

Asset Retirement Obligation

(k) Asset Retirement Obligation

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

Estimating the future ARO requires management to make estimates and judgments based on historical information regarding timing and existence of a liability, as well as what constitutes adequate restoration.  Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Approximately $2.9 million and $2.0 million, representing the current portion of ARO liability, are included in “Accrued liabilities” in the accompanying Condensed Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019, respectively.  The following table sets forth the changes in the Company’s ARO liability for the nine months ended September 30, 2020 (in thousands):

	Nine Months Ended September 30, 2020
Asset retirement obligations, beginning of period	$	31,841
Accretion		2,245
Additional liabilities incurred		15
Obligation for wells drilled		181
Liabilities settled via plugging		(178	)
Liabilities sold/disposed		(901	)
Less: current ARO portion		(2,867	)
Asset retirement obligations, end of period	$	30,336

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.

Off-Balance Sheet Arrangements

(l) Off-Balance Sheet Arrangements

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

Segment Reporting

(m) Segment Reporting

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

Debt Issuance Costs

(n) Debt Issuance Costs

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

During the three and nine months ended September 30, 2020, the Company amortized $0.9 million and $3.0 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method which includes $0.2 million of unamortized deferred financing costs that the Company wrote off during the second quarter of 2020 in connection with the borrowing base redetermination of the Company’s revolving credit facility (See Note 8— Debt).  During the three and nine months ended September 30, 2019, the Company amortized $0.9 million and $3.2 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method. 

Recent Accounting Pronouncements

(o) Recent Accounting Pronouncements

Accounting Pronouncements Not Yet Adopted

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

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

Summary of Property and Equipment Including Oil and Natural Gas Properties

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

	September 30, 2020			December 31, 2019
Oil and natural gas properties:
Unproved	$	478,644		$	508,576
Proved		2,885,622			2,783,232
Gross oil and natural gas properties		3,364,266			3,291,808
Less accumulated depreciation, depletion and amortization		(1,668,786	)		(1,532,127	)
Oil and natural gas properties, net		1,695,480			1,759,681
Other property and equipment		19,596			20,000
Less accumulated depreciation		(9,285	)		(8,774	)
Other property and equipment, net		10,311			11,226
Property and equipment, net	$	1,705,791		$	1,770,907

Summary of Revenue Disaggregated by Type

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Revenues (in thousands)
Natural gas sales	$	72,926	$	87,841	$	217,604	$	264,030
NGL sales		18,439		20,200		44,949		60,841
Oil sales		17,153		44,980		52,918		103,407
Brokered natural gas and marketing revenue		6,831		10,228		23,859		31,747
Other revenue		56		46		183		307
Total revenues	$	115,405	$	163,295	$	339,513	$	460,332

Concentration Risk

The following table summarizes the Company’s concentration of receivables, net of allowances (if any), by product or service as of September 30, 2020 and December 31, 2019 (in thousands):

	September 30, 2020		December 31, 2019
Receivables by product or service:
Sale of oil and natural gas and related products and    services	$	53,466	$	63,730
Joint interest owners		6,983		12,156
Derivatives		1,728		210
Other		1,306		1,306
Total	$	63,483	$	77,402

Changes in Company's Asset Retirement Obligation Liability

The following table sets forth the changes in the Company’s ARO liability for the nine months ended September 30, 2020 (in thousands):

	Nine Months Ended September 30, 2020
Asset retirement obligations, beginning of period	$	31,841
Accretion		2,245
Additional liabilities incurred		15
Obligation for wells drilled		181
Liabilities settled via plugging		(178	)
Liabilities sold/disposed		(901	)
Less: current ARO portion		(2,867	)
Asset retirement obligations, end of period	$	30,336

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Acquisitions (Tables)

9 Months Ended

Sep. 30, 2020

Business Combinations [Abstract]

Summary of Purchase Price Allocation and Values of Assets Acquired and Liabilities Assumed

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

Unaudited Pro Forma Financial Information

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

	Three Months Ended September 30,		Nine Months Ended September 30,
(in thousands, except per share data) (unaudited)	2019		2019
Pro forma total revenues	$	163,295	$	502,989
Pro forma net income	$	4,543	$	24,834
Pro forma net income per share (basic)	$	0.13	$	0.70
Pro forma net income per share (diluted)	$	0.13	$	0.69

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Assets Held for Sale and Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2020

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Summary of Assets Held for Sale and Discontinued Operations

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

(in thousands)	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
Revenues	$	698		$	1,874		$	2,948		$	5,402
Impairment of proved oil and natural gas properties		—			—			(6,849	)		—
Depreciation, depletion, amortization and accretion		(182	)		(168	)		(523	)		(380	)
Other operating expenses		(1,317	)		(2,943	)		(5,668	)		(3,738	)
Other income		—			—			—			2
Income (loss) from discontinued operations, net of tax	$	(801	)	$	(1,237	)	$	(10,092	)	$	1,286

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

(in thousands)	Nine Months Ended September 30,
	2020			2019
Net cash provided by operating activities	$	693		$	1,189
Net cash provided by (used in) investing activities	$	(82	)	$	14

Assets Held for Sale [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Summary of Assets Held for Sale and Discontinued Operations

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

(in thousands)	September 30, 2020		December 31, 2019
Accounts receivable	$	758	$	343
Other current assets		786		704
Total current assets held for sale	$	1,544	$	1,047
Proved oil and gas properties, net	$	3,351	$	9,528
Other noncurrent assets		52		137
Total noncurrent assets held for sale	$	3,403	$	9,665
Accounts payable	$	2,104	$	2,067
Accrued liabilities		1,576		570
Other current liabilities		31		178
Total current liabilities associated with assets held for sale	$	3,711	$	2,815
Asset retirement obligations	$	7,146	$	6,488
Other liabilities		4		525
Total noncurrent liabilities associated with assets held for sale	$	7,150	$	7,013

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2020

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Summary of Derivative Instrument Positions for Future Production Periods

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

Natural Gas Derivatives:

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		130,000	October 2020 – December 2020	$	2.42
		145,000	October 2020 – March 2021	$	2.58
		50,000	January 2021 – March 2022	$	2.51
		25,000	April 2021 – March 2022	$	2.47
Natural Gas Collars:
Floor purchase price (put)		25,000	January 2021 – December 2021	$	2.15
Ceiling sold price (call)		25,000	January 2021 – December 2021	$	3.03
Floor purchase price (put)		30,000	April 2021 – March 2022	$	2.40
Ceiling sold price (call)		30,000	April 2021 – March 2022	$	3.05
Floor purchase price (put)		15,000	August 2021 – December 2021	$	2.55
Ceiling sold price (call)		15,000	August 2021 – December 2021	$	3.13
Floor purchase price (put)		15,000	September 2021 – November 2021	$	2.52
Ceiling sold price (call)		15,000	September 2021 – November 2021	$	3.12
Floor purchase price (put)		5,000	August 2021	$	2.50
Ceiling sold price (call)		5,000	August 2021	$	3.05
Floor purchase price (put)		10,000	September 2021	$	2.50
Ceiling sold price (call)		10,000	September 2021	$	3.03
Natural Gas Three-way Collars:
Floor purchase price (put)		80,000	October 2020 – December 2020	$	2.60
Floor sold price (put)		80,000	October 2020 – December 2020	$	1.90
Ceiling sold price (call)		80,000	October 2020 – December 2020	$	2.94
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
Floor purchase price (put)		20,000	April 2021 – March 2022	$	2.62
Floor sold price (put)		20,000	April 2021 – March 2022	$	2.20
Ceiling sold price (call)		20,000	April 2021 – March 2022	$	3.10
Natural Gas Call/Put Options:
Floor sold price (put)		50,000	October 2020 – December 2020	$	2.30
Swaption sold price (call)		50,000	January 2021 – December 2021	$	2.75
Swaption sold price (call)		50,000	January 2022 – December 2022	$	3.00
Ceiling sold price (call)		50,000	January 2022 – December 2022	$	3.00
Floor sold price (put)		50,000	January 2021 – March 2022	$	2.00
Ceiling sold price (call)		80,000	January 2023 – December 2023	$	3.00
Basis Swaps:
Appalachia - Dominion		42,500	October 2020	$	(0.51	)
Appalachia - Dominion		20,000	October 2020 – December 2020	$	(0.59	)

Oil Derivatives:

Description	Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)
Oil Swaps:
		2,500	October 2020 – December 2020	$	57.41
		250	October 2020 – March 2021	$	53.20
		250	January 2021 – March 2021	$	53.00
		100	January 2021	$	43.60
Oil Collars:
Floor purchase price (put)		1,000	October 2020 – December 2020	$	51.00
Ceiling sold price (call)		1,000	October 2020 – December 2020	$	62.00
Floor purchase price (put)		500	January 2021 – December 2021	$	37.50
Ceiling sold price (call)		500	January 2021 – December 2021	$	45.50
Floor purchase price (put)		300	April 2021	$	40.00
Ceiling sold price (call)		300	April 2021	$	47.25
Floor purchase price (put)		200	May 2021	$	40.00
Ceiling sold price (call)		200	May 2021	$	47.55
Floor purchase price (put)		100	June 2021	$	40.00
Ceiling sold price (call)		100	June 2021	$	47.75
Oil Three-way Collars:
Floor purchase price (put)		500	January 2021 – December 2021	$	31.25
Floor sold price (put)		500	January 2021 – December 2021	$	22.50
Ceiling sold price (call)		500	January 2021 – December 2021	$	45.00
Oil Call/Put Options:
Floor sold price (put)		500	October 2020 – December 2020	$	45.00
Swaption sold price (call)		500	January 2021 – December 2021	$	42.50

NGL Derivatives:

Description	Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)
Propane Swaps:
		2,000	October 2020 – December 2020	$	20.94
		1,000	January 2021 – December 2021	$	18.87

Fair Value of Derivative Instruments on a Gross Basis and on a Net basis as Presented in Consolidated Balance Sheets

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

As of September 30, 2020	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	7,423		$	(4,213	)		3,210		Other current assets
Total assets	$	7,423		$	(4,213	)	$	3,210
Liabilities
Commodity derivatives - current	$	(27,338	)	$	4,213		$	(23,125	)	Accrued liabilities
Interest-rate swap - current		(103	)		—			(103	)	Accrued liabilities
Commodity derivatives - noncurrent		(27,269	)		—			(27,269	)	Other liabilities
Interest-rate swap - noncurrent		(404	)		—			(404	)	Other liabilities
Total liabilities	$	(55,114	)	$	4,213		$	(50,901	)

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	)

(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.

Summary of Gains and Losses on Derivative Instruments

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

		Amount of Gain (Loss) Recognized in Income
Derivatives not designated as hedging instruments under ASC 815	Location of Gain (Loss) Recognized in Income	Three Months Ended September 30,					Nine Months Ended September 30,
		2020			2019		2020			2019
Commodity derivatives	Gain (loss) on derivative instruments	$	(40,603	)	$	15,812	$	(10,861	)	$	40,620
Interest-rate swap	Gain (loss) on derivative instruments		68			—		(468	)		—
Total		$	(40,535	)	$	15,812	$	(11,329	)	$	40,620

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value 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.

	Level 1		Level 2			Level 3		Total Fair Value
As of September 30, 2020: (in thousands)
Commodity derivative instruments	$	—	$	(47,184	)	$	—	$	(47,184	)
Interest-rate swap		—		(507	)		—		(507	)
Total	$	—	$	(47,691	)	$	—	$	(47,691	)
As of December 31, 2019: (in thousands)
Commodity derivative instruments	$	—	$	27,117		$	—	$	27,117
Total	$	—	$	27,117		$	—	$	27,117

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Stock-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2020

Schedule of Stock Based Compensation Expense

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Restricted stock units	$	357	$	445	$	1,424	$	3,773
Performance units		535		374		1,226		3,364
Restricted and unrestricted stock		69		242		935		477
Total expense	$	961	$	1,061	$	3,585	$	7,614

Summary of Employee Restricted Stock Unit Awards Activity

A summary of employee restricted stock unit awards activity during the nine months ended September 30, 2020 is as follows:

	Number of units			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2019		437,559		$	7.83	$	3,474
Granted		351,467			5.86
Vested		(214,804	)		9.14
Forfeited		(3,023	)		6.02
Total awarded and unvested, September 30, 2020		571,199		$	6.14	$	2,508

Summary of Performance Stock Unit Awards Activity

A summary of performance stock unit awards activity during the nine months ended September 30, 2020 is as follows

	Number of units			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2019		320,120		$	11.26	$	2,522
Granted		618,483			6.21
Vested		(51,858	)		20.89
Forfeited		(55,547	)		16.69
Total awarded and unvested, September 30, 2020		831,198		$	6.54	$	932

Performance Units [Member]

Summary of Assumptions to Determine Fair Value for Performance Stock Units Granted

The following table presents the assumptions used to determine the fair value for performance stock units granted during the nine months ended September 30, 2020 and 2019:

	Nine Months Ended September 30,
	2020			2019
Volatility		79.70	%		65.10	%
Risk-free interest rate		0.20	%		1.83	%

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Net Income (Loss) Per Share (Tables)

9 Months Ended

Sep. 30, 2020

Earnings Per Share [Abstract]

Calculation of Basic and Diluted Weighted-Average Number of Shares of Common Stock and EPS

The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the three and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,
(in thousands, except per share data)	2020								2019
	Loss			Shares		Per Share			Income		Shares		Per Share
Basic:
Net income (loss), shares, basic	$	(92,200	)		36,035	$	(2.56	)	$	4,284		35,684	$	0.12
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—			—					—		13
Diluted:
Net income (loss), shares, diluted	$	(92,200	)		36,035	$	(2.56	)	$	4,284		35,697	$	0.12

	Nine Months Ended September 30,
(in thousands, except per share data)	2020								2019
	Loss			Shares		Per Share			Income		Shares		Per Share
Basic:
Net income (loss), shares, basic	$	(158,227	)		35,889	$	(4.41	)	$	17,698		32,343	$	0.55
Weighted-average number of shares of common    stock-diluted:
Restricted stock and performance unit awards		—			—					—		128
Diluted:
Net income (loss), shares, diluted	$	(158,227	)		35,889	$	(4.41	)	$	17,698		32,471	$	0.55

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2020

Commitments And Contingencies Disclosure [Abstract]

Schedule of Other Commitments

In March 2020, the Company completed the renegotiation of certain existing gas gathering contracts with a midstream service provider into a single new consolidated gas gathering agreement.  Revised commitments under the new consolidated gas gathering agreement (in thousands) are included in the table below:

	Firm transportation(i)		Gas processing, gathering, and compression services(ii)		Total
Year Ending December 31:
Remainder of 2020	$	25,025	$	11,132	$	36,157
2021		99,828		44,801		144,629
2022		99,828		49,404		149,232
2023		99,828		52,342		152,170
2024		100,101		52,972		153,073
Thereafter		722,369		303,890		1,026,259
Total	$	1,146,979	$	514,541	$	1,661,520

(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 rates. The values in the table represent the gross amounts that the Company is committed to pay and do not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company records in its Condensed 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 do not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company records in its Condensed Consolidated Financial Statements its proportionate share of costs based on the Company’s working interest.

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Basis of Presentation - Additional Information (Detail) - Southwestern Energy Company [Member] $ in Millions	Aug. 12, 2020 USD ($) shares
Basis Of Presentation [Line Items]
Common stock convertible into right to receive after merger | shares	1.8656
Termination fee required to pay in merger agreement | $	$ 9.7

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Summary of Significant Accounting Policies - Summary of Property and Equipment Including Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands	Sep. 30, 2020	Dec. 31, 2019
Oil and natural gas properties:
Unproved properties	$ 478,644	$ 508,576
Proved properties	2,885,622	2,783,232
Gross oil and natural gas properties	3,364,266	3,291,808
Less accumulated depreciation, depletion and amortization	(1,668,786)	(1,532,127)
Total oil and natural gas properties, net	1,695,480	1,759,681
Other property and equipment	19,596	20,000
Less accumulated depreciation	(9,285)	(8,774)
Other property and equipment, net	10,311	11,226
Total property and equipment, net	$ 1,705,791	$ 1,770,907

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Summary of Significant Accounting Policies - Summary of Revenue Disaggregated by Type (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Disaggregation Of Revenue [Line Items]
Total revenues	$ 115,405	$ 163,295	$ 339,513	$ 460,332
Natural Gas Sales [Member]
Disaggregation Of Revenue [Line Items]
Total revenues	72,926	87,841	217,604	264,030
NGL Sales [Member]
Disaggregation Of Revenue [Line Items]
Total revenues	18,439	20,200	44,949	60,841
Oil Sales [Member]
Disaggregation Of Revenue [Line Items]
Total revenues	17,153	44,980	52,918	103,407
Brokered Natural Gas and Marketing Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total revenues	6,831	10,228	23,859	31,747
Other Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total revenues	$ 56	$ 46	$ 183	$ 307

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Summary of Significant Accounting Policies - Additional Information (Detail)	3 Months Ended			9 Months Ended
	Sep. 30, 2020 USD ($)	Jun. 30, 2020 USD ($)	Sep. 30, 2019 USD ($)	Sep. 30, 2020 USD ($) Segment	Sep. 30, 2019 USD ($)	Dec. 31, 2019 USD ($)	Jul. 06, 2015
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable	$ 63,483,000			$ 63,483,000		$ 77,402,000
Depreciation, depletion, amortization and accretion	53,153,000		$ 45,456,000	140,058,000	$ 113,950,000
Impairment of oil and gas properties				6,849,000
ARO liability current	2,867,000			$ 2,867,000
Number of operating segment | Segment				1
Amortization of deferred financing costs and debt discount	$ 900,000		900,000	$ 3,000,000.0	3,200,000
Wrote off unamortized deferred financing costs		$ 200,000
8.875% Senior Unsecured Notes Due 2023 [Member]
Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest rate	8.875%			8.875%			8.875%
Accrued Liabilities [Member]
Summary Of Significant Accounting Policies [Line Items]
ARO liability current	$ 2,900,000			$ 2,900,000		2,000,000.0
Oil and Gas Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciation, depletion, amortization and accretion	52,800,000		44,900,000	138,900,000	112,400,000
Other property and equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciation	400,000		600,000	$ 1,200,000	1,600,000
Other property and equipment [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Property and equipment, expected lives				5 years
Other property and equipment [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Property and equipment, expected lives				40 years
Proved Oil And Gas Properties [Member] | Utica and Marcellus Shales [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and gas properties	0		0	$ 0	0
Unproved Oil And Gas Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and gas properties	11,000,000.0		$ 14,100,000	30,300,000	$ 36,200,000
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Summary Of Significant Accounting Policies [Line Items]
Fair value of derivative contracts	(47,700,000)			(47,700,000)		27,100,000
Revenue From Contract With Customer [Member]
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable	$ 53,500,000			$ 53,500,000		$ 63,700,000

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Summary of Significant Accounting Policies - Summary for Concentration of Receivables, Net of Allowances, By Product or Service (Detail) - USD ($) $ in Thousands	Sep. 30, 2020	Dec. 31, 2019
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	$ 63,483	$ 77,402
Product Concentration Risk [Member] | Sale of Oil and Natural Gas and Related Products and Services [Member]
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	53,466	63,730
Product Concentration Risk [Member] | Joint Interest Owners [Member]
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	6,983	12,156
Product Concentration Risk [Member] | Derivatives [Member]
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	1,728	210
Product Concentration Risk [Member] | Other [Member]
Revenue, Major Customer [Line Items]
Concentration of receivables, net of allowances	$ 1,306	$ 1,306

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Summary of Significant Accounting Policies - Changes in Company's Asset Retirement Obligation Liability (Detail) $ in Thousands	9 Months Ended
	Sep. 30, 2020 USD ($)
Asset Retirement Obligation [Abstract]
Asset retirement obligations, beginning of period	$ 31,841
Accretion	2,245
Additional liabilities incurred	15
Obligation for wells drilled	181
Liabilities settled via plugging	(178)
Liabilities sold/disposed	(901)
Less: current ARO portion	(2,867)
Asset retirement obligations, end of period	$ 30,336

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Acquisitions - Additional Information (Detail)		3 Months Ended			7 Months Ended	9 Months Ended
	Feb. 28, 2019 $ / shares shares	Sep. 30, 2020 USD ($) $ / shares	Sep. 30, 2019 USD ($) $ / shares	Mar. 31, 2019 $ / shares	Sep. 30, 2019 USD ($) $ / shares	Sep. 30, 2020 USD ($) $ / shares	Sep. 30, 2019 USD ($) $ / shares	Jun. 30, 2020 $ / shares	Mar. 31, 2020 $ / shares	Dec. 31, 2019 $ / shares	Jun. 30, 2019 $ / shares
Business Acquisition [Line Items]
Common stock, par value | $ / shares		$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Reverse stock split				0.067
Revenue		$ 115,405,000	$ 163,295,000			$ 339,513,000	$ 460,332,000
Net income from continuing operations		(91,399,000)	5,521,000			(148,135,000)	16,412,000
Net income from discontinued operations		801,000	1,237,000			10,092,000	(1,286,000)
BRMR and Everest Merger Sub Inc. [Member]
Business Acquisition [Line Items]
Common stock, par value | $ / shares	$ 0.01
Net income from continuing operations					$ 16,000,000.0
Net income from discontinued operations					1,300,000
BRMR and Everest Merger Sub Inc. [Member] | Continuing Operations [Member]
Business Acquisition [Line Items]
Revenue					100,500,000
BRMR and Everest Merger Sub Inc. [Member] | Discontinued Operations [Member]
Business Acquisition [Line Items]
Revenue					$ 5,400,000
BRMR and Everest Merger Sub Inc. [Member] | General and Administrative Expense [Member]
Business Acquisition [Line Items]
Acquisition costs		$ 0	$ 3,300,000			$ 200,000	$ 21,800,000
Common Stock [Member] | BRMR and Everest Merger Sub Inc. [Member]
Business Acquisition [Line Items]
Purchase price paid through shares of common stock | shares	0.29506
Reverse stock split, description	15-to-1
Reverse stock split	0.067

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Acquisitions - Summary of Purchase Price Allocation and Values of Assets Acquired and Liabilities Assumed (Detail) - BRMR and Everest Merger Sub Inc. [Member] $ in Thousands	Feb. 28, 2019 USD ($)
Business Acquisition [Line Items]
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

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Acquisitions - Unaudited Pro Forma Financial Information (Detail) - BRMR and Everest Merger Sub Inc. [Member] - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019
Business Acquisition [Line Items]
Pro forma total revenues	$ 163,295	$ 502,989
Pro forma net income	$ 4,543	$ 24,834
Pro forma net income per share (basic)	$ 0.13	$ 0.70
Pro forma net income per share (diluted)	$ 0.13	$ 0.69

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Assets Held for Sale and Discontinued Operations - Summary of Assets and Liabilities Held for Sale (Detail) - USD ($) $ in Thousands	Sep. 30, 2020	Dec. 31, 2019
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total current assets held for sale	$ 1,544	$ 1,047
Total noncurrent assets held for sale	3,403	9,665
Total current liabilities associated with assets held for sale	3,711	2,815
Total noncurrent liabilities associated with assets held for sale	7,150	7,013
Assets Held for Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable	758	343
Other current assets	786	704
Total current assets held for sale	1,544	1,047
Proved oil and gas properties, net	3,351	9,528
Other noncurrent assets	52	137
Total noncurrent assets held for sale	3,403	9,665
Accounts payable	2,104	2,067
Accrued liabilities	1,576	570
Other current liabilities	31	178
Total current liabilities associated with assets held for sale	3,711	2,815
Asset retirement obligations	7,146	6,488
Other liabilities	4	525
Total noncurrent liabilities associated with assets held for sale	$ 7,150	$ 7,013

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Assets Held for Sale and Discontinued Operations - Summary of Results of Operations for Discontinued Operations (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Discontinued Operations And Disposal Groups [Abstract]
Revenues	$ 698	$ 1,874	$ 2,948	$ 5,402
Impairment of proved oil and natural gas properties			(6,849)
Depreciation, depletion, amortization and accretion	(182)	(168)	(523)	(380)
Other operating expenses	(1,317)	(2,943)	(5,668)	(3,738)
Other income				2
Income (loss) from discontinued operations, net of tax	$ (801)	$ (1,237)	$ (10,092)	$ 1,286

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Assets Held for Sale and Discontinued Operations - Additional Information (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Discontinued Operations And Disposal Groups [Abstract]
Accrued liabilities		$ 3,500
Impairment of proved oil and gas properties	$ 6,849

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Assets Held for Sale and Discontinued Operations - Summary of Operating and Investing Cash Flows of Discontinued Operations (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Discontinued Operations And Disposal Groups [Abstract]
Net cash provided by operating activities	$ 693	$ 1,189
Net cash provided by (used in) investing activities	$ (82)	$ 14

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Derivative Instruments - Summary of Derivative Instrument Positions for Future Production Periods (Detail)	9 Months Ended
	Sep. 30, 2020 MMBTU $ / MMBTU $ / bbl bbl
Natural Gas Swaps Production Period October 2020 - December 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	130,000
Weighted Average Price | $ / MMBTU	2.42
Natural Gas Swaps Production Period October 2020 - March 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	145,000
Weighted Average Price | $ / MMBTU	2.58
Natural Gas Swaps Production Period January 2021 - March 2022 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	50,000
Weighted Average Price | $ / MMBTU	2.51
Natural Gas Swaps Production Period April 2021 - March 2022 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	25,000
Weighted Average Price | $ / MMBTU	2.47
Basis Swaps Production Period October 2020 [Member] | Appalachia [Member] | Dominion Resources, Inc [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	42,500
Weighted Average Price ($/MMBtu) | $ / MMBTU	(0.51)
Basis Swaps Production Period October 2020 - December 2020 [Member] | Appalachia [Member] | Dominion Resources, Inc [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	20,000
Weighted Average Price ($/MMBtu) | $ / MMBTU	(0.59)
Natural Gas Collars Production Period January 2021 - December 2021 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	25,000
Weighted Average Price, Floor | $ / MMBTU	2.15
Natural Gas Collars Production Period January 2021 - December 2021 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	25,000
Weighted Average Price, Ceiling | $ / MMBTU	3.03
Natural Gas Collars Production Period April 2021 - March 2022 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	30,000
Weighted Average Price, Floor | $ / MMBTU	2.40
Natural Gas Collars Production Period April 2021 - March 2022 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	30,000
Weighted Average Price, Ceiling | $ / MMBTU	3.05
Natural Gas Collars Production Period August 2021 - December 2021 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	15,000
Weighted Average Price, Floor | $ / MMBTU	2.55
Natural Gas Collars Production Period August 2021 - December 2021 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	15,000
Weighted Average Price, Ceiling | $ / MMBTU	3.13
Natural Gas Collars Production Period September 2021 - November 2021 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	15,000
Weighted Average Price, Floor | $ / MMBTU	2.52
Natural Gas Collars Production Period September 2021 - November 2021 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	15,000
Weighted Average Price, Ceiling | $ / MMBTU	3.12
Natural Gas Collars Production Period August 2021 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	5,000
Weighted Average Price, Floor | $ / MMBTU	2.50
Natural Gas Collars Production Period August 2021 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	5,000
Weighted Average Price, Ceiling | $ / MMBTU	3.05
Natural Gas Collars Production Period September 2021 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	10,000
Weighted Average Price, Floor | $ / MMBTU	2.50
Natural Gas Collars Production Period September 2021 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	10,000
Weighted Average Price, Ceiling | $ / MMBTU	3.03
Natural Gas Three-way Collars Production Period October 2020 - December 2020 [Member] | Put Option | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	80,000
Weighted Average Price, Floor | $ / MMBTU	1.90
Natural Gas Three-way Collars Production Period October 2020 - December 2020 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	80,000
Weighted Average Price, Floor | $ / MMBTU	2.60
Natural Gas Three-way Collars Production Period October 2020 - December 2020 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	80,000
Weighted Average Price, Ceiling | $ / MMBTU	2.94
Natural Gas Three-way Collars Production Period January 2021 - December 2021 [Member] | Put Option | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	45,000
Weighted Average Price, Floor | $ / MMBTU	2.25
Natural Gas Three-way Collars Production Period January 2021 - December 2021 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	45,000
Weighted Average Price, Floor | $ / MMBTU	2.55
Natural Gas Three-way Collars Production Period January 2021 - December 2021 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	45,000
Weighted Average Price, Ceiling | $ / MMBTU	2.81
Natural Gas Three-way Collars Production Period April 2021 - March 2022 [Member] | Put Option | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	20,000
Weighted Average Price, Floor | $ / MMBTU	2.20
Natural Gas Three-way Collars Production Period April 2021 - March 2022 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	20,000
Weighted Average Price, Floor | $ / MMBTU	2.62
Natural Gas Three-way Collars Production Period April 2021 - March 2022 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	20,000
Weighted Average Price, Ceiling | $ / MMBTU	3.10
Natural Gas Call/Put Options Production Period October 2020 - December 2020 [Member] | Put Option | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	50,000
Weighted Average Price | $ / MMBTU	2.30
Natural Gas Call/Put Options Production Period January 2021 - December 2021 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	50,000
Weighted Average Price | $ / MMBTU	2.75
Natural Gas Call/Put Options Production Period January 2022 - December 2022 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	50,000
Weighted Average Price | $ / MMBTU	3.00
Natural Gas Call/Put Options Production Period January 2022 - December 2022 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	50,000
Weighted Average Price | $ / MMBTU	3.00
Natural Gas Call/Put Options Production Period January 2021 - March 2022 [Member] | Put Option | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	50,000
Weighted Average Price | $ / MMBTU	2.00
Natural Gas Call/Put Options Production Period January 2023 - December 2023 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (MMBtu/d) | MMBTU	80,000
Weighted Average Price | $ / MMBTU	3.00
Oil Swaps Production Period October 2020 - December 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price | $ / bbl	57.41
Volume (Bbls/d) | bbl	2,500
Oil Swaps Production Period October 2020 - March 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price | $ / bbl	53.20
Volume (Bbls/d) | bbl	250
Oil Swaps Production Period January 2021 - March 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price | $ / bbl	53.00
Volume (Bbls/d) | bbl	250
Oil Swaps Production Period January 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price | $ / bbl	43.60
Volume (Bbls/d) | bbl	100
Oil Collars Production Period October 2020 - December 2020 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor | $ / bbl	51.00
Volume (Bbls/d) | bbl	1,000
Oil Collars Production Period October 2020 - December 2020 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Ceiling | $ / bbl	62.00
Volume (Bbls/d) | bbl	1,000
Oil Collars Production Period January 2021 - December 2021 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor | $ / bbl	37.50
Volume (Bbls/d) | bbl	500
Oil Collars Production Period January 2021 - December 2021 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Ceiling | $ / bbl	45.50
Volume (Bbls/d) | bbl	500
Oil Collars Production Period April 2021 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor | $ / bbl	40.00
Volume (Bbls/d) | bbl	300
Oil Collars Production Period April 2021 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Ceiling | $ / bbl	47.25
Volume (Bbls/d) | bbl	300
Oil Collars Production Period May 2021 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor | $ / bbl	40.00
Volume (Bbls/d) | bbl	200
Oil Collars Production Period May 2021 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Ceiling | $ / bbl	47.55
Volume (Bbls/d) | bbl	200
Oil Collars Production Period June 2021 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor | $ / bbl	40.00
Volume (Bbls/d) | bbl	100
Oil Collars Production Period June 2021 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Ceiling | $ / bbl	47.75
Volume (Bbls/d) | bbl	100
Oil Three-way Collars Production Period January 2021 - December 2021 [Member] | Put Option | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor | $ / bbl	22.50
Volume (Bbls/d) | bbl	500
Oil Three-way Collars Production Period January 2021 - December 2021 [Member] | Put Option | Purchase [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Floor | $ / bbl	31.25
Volume (Bbls/d) | bbl	500
Oil Three-way Collars Production Period January 2021 - December 2021 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price, Ceiling | $ / bbl	45.00
Volume (Bbls/d) | bbl	500
Oil Call/Put Option Production Period October 2020 - December 2020 [Member] | Put Option | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price | $ / bbl	45.00
Volume (Bbls/d) | bbl	500
Oil Call/Put Option Production Period January 2021 - December 2021 [Member] | Call Option [Member] | Sold [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price | $ / bbl	42.50
Volume (Bbls/d) | bbl	500
Propane Swaps Production Period October 2020 - December 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price | $ / bbl	20.94
Volume (Bbls/d) | bbl	2,000
Propane Swaps Production Period January 2021 - December 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Weighted Average Price | $ / bbl	18.87
Volume (Bbls/d) | bbl	1,000

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Derivative Instruments - Additional Information (Detail) - Interest Rate Swap [Member]	1 Months Ended
	Apr. 30, 2020 USD ($)
Derivative [Line Items]
Derivative, notional amount	$ 100,000,000
Derivative, maturity date	Feb. 28, 2022
Derivative, optional extended maturity date	Feb. 28, 2024
1-Month LIBOR [Member]
Derivative [Line Items]
Derivative, fixed interest rate	0.255%

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Derivative Instruments - Fair Value of Derivative Instruments on a Gross basis and on a Net Basis as Presented in Consolidated Balance Sheets (Detail) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Thousands		Sep. 30, 2020	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Gross Amount		$ (55,114)
Netting Adjustments	[1]	4,213
Net Amount Presented in Balance Sheets		(50,901)
Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		7,423	$ 34,595
Netting Adjustments	[1]	(4,213)	(3,764)
Net Amount Presented in Balance Sheets		3,210	30,831
Gross Amount			(7,478)
Netting Adjustments	[1]		3,764
Net Amount Presented in Balance Sheets			(3,714)
Commodity Contract [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		7,423	33,762
Netting Adjustments	[1]	(4,213)	(3,719)
Net Amount Presented in Balance Sheets		3,210	30,043
Commodity Contract [Member] | Current Liabilities [Member] | Accrued Liabilities [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		(27,338)	(5,081)
Netting Adjustments	[1]	4,213	3,719
Net Amount Presented in Balance Sheets		(23,125)	(1,362)
Commodity Contract [Member] | Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		(27,269)	(2,397)
Netting Adjustments	[1]		45
Net Amount Presented in Balance Sheets		(27,269)	(2,352)
Commodity Contract [Member] | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Gross Amount			833
Netting Adjustments	[1]		(45)
Net Amount Presented in Balance Sheets			$ 788
Interest-Rate Swap [Member] | Current Liabilities [Member] | Accrued Liabilities [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		(103)
Net Amount Presented in Balance Sheets		(103)
Interest-Rate Swap [Member] | Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Gross Amount		(404)
Net Amount Presented in Balance Sheets		$ (404)

[1] 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.

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Derivative Instruments - Summary of Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$ (40,535)	$ 15,812	$ (11,329)	$ 40,620
Not Designated as Hedging Instrument [Member] | Gain (Loss) on Derivative Instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	(40,535)	15,812	(11,329)	40,620
Not Designated as Hedging Instrument [Member] | Gain (Loss) on Derivative Instruments [Member] | Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	(40,603)	$ 15,812	(10,861)	$ 40,620
Not Designated as Hedging Instrument [Member] | Gain (Loss) on Derivative Instruments [Member] | Interest-Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$ 68		$ (468)

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Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Detail) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Sep. 30, 2020	Dec. 31, 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total fair value	$ (47,691)	$ 27,117
Commodity Derivative Instruments [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total fair value	(47,184)	27,117
Interest-Rate Swap [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total fair value	(507)
Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total fair value	(47,691)	27,117
Level 2 [Member] | Commodity Derivative Instruments [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total fair value	(47,184)	$ 27,117
Level 2 [Member] | Interest-Rate Swap [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total fair value	$ (507)

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Debt - Additional Information (Detail) - USD ($)				3 Months Ended	9 Months Ended
	Oct. 09, 2020	May 04, 2020	Jul. 06, 2015	Jun. 30, 2020	Sep. 30, 2020	May 03, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Debt instrument, covenant description					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.
Outstanding letters of credit					$ 29,200,000
Wrote off unamortized deferred financing costs				$ 200,000
Outstanding notes payable					$ 800,000		$ 300,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Percentage of company's proved reserves and guarantees secured by mortgages					85.00%
Borrowing base		$ 475,000,000			$ 475,000,000	$ 500,000,000
Outstanding borrowings					170,000,000.0
Available capacity on the Revolving Credit Facility					$ 275,800,000
Applicable margin		0.25%
Reduced borrowing base		$ (25,000,000)
Prepayment requirements on cash balances		40,000,000
Wrote off unamortized deferred financing costs		$ 200,000
Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Commitment fees on unused portion of revolving credit facility					0.375%
Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Commitment fees on unused portion of revolving credit facility					0.50%
8.875% Senior Unsecured Notes Due 2023 [Member]
Debt Instrument [Line Items]
Issuance date			Jul. 06, 2015
Debt instrument, outstanding principal balance amount			$ 550,000,000
Debt instrument interest rate			8.875%		8.875%
Debt instrument maturity year			2023
Notes issued percentage price			97.903%
Debt instrument, proceeds			$ 525,500,000
8.875% Senior Unsecured Notes Due 2023 [Member] | Level 2 [Member]
Debt Instrument [Line Items]
Fair value of senior unsecured notes					$ 519,000,000.0
8.875% Senior Unsecured Notes Due 2023 [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Debt instrument, redemption description	On October 6, 2020, the Company notified the trustee under the indenture that the Company had elected to redeem, subject to certain conditions (the “Redemption”), all of its outstanding senior unsecured notes. On October 9, 2020, the Company issued a conditional notice of full redemption to redeem all of its outstanding senior unsecured notes. The anticipated redemption date is November 13, 2020 (the “Redemption Date”). The redemption price for the senior unsecured notes will be 102.219% (the “Redemption Price”) of the aggregate principal amount being redeemed, plus accrued but unpaid interest on the senior unsecured notes redeemed to, but not including, the Redemption Date. Upon the Redemption by the Company of the senior unsecured notes, none of the senior unsecured notes will remain outstanding.
Debt instrument, anticipated redemption date	Nov. 13, 2020
Debt instrument, redemption price, percentage	102.219%
Senior PIK Notes [Member]
Debt Instrument [Line Items]
Debt instrument repurchase amount			$ 510,700,000

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Benefit Plans - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Defined Contribution Plan Disclosure [Line Items]
Matching contribution by the company to the plan			100.00%
Percentage of employees' eligible compensation			6.00%
Plan name			401(k) plan
General and Administrative [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined contribution plan, compensation expense	$ 0.2	$ 0.3	$ 0.9	$ 0.8

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Stock-Based Compensation - Additional Information (Detail) $ in Millions						9 Months Ended
	Jun. 19, 2020 Director shares	Oct. 08, 2019 Director shares	Aug. 02, 2019 Director shares	Jun. 18, 2019 Director shares	Feb. 28, 2019 Officer shares	Sep. 30, 2020 USD ($) shares
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation awards, requisite service period						3 years
Unrecognized compensation cost | $						$ 3.1
Weighted average period for units to vest						1 year
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation awards, requisite service period						3 years
Unrecognized compensation cost | $						$ 4.1
Weighted average period for units to vest						2 years
Restricted Stock [Member] | Officer [Member] | February 2019 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of common stock issued					70,409
Number of officers | Officer					2
Restricted Stock [Member] | Officer [Member] | February 2019 [Member] | August 28, 2019 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage					25.00%
Restricted Stock [Member] | Officer [Member] | February 2019 [Member] | February 28, 2020 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage					25.00%
Restricted Stock [Member] | Officer [Member] | February 2019 [Member] | June 1, 2020 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage					50.00%
Restricted Stock [Member] | Director | June 2019 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of common stock issued				53,328
Number of non employee directors | Director				8
Restricted Stock [Member] | Director | June 2020 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of common stock issued	58,335
Number of non employee directors | Director	5
Share-based compensation, vesting date	Jun. 19, 2021
Unrestricted Stock [Member] | Director | August 2019 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of common stock issued			26,935
Number of non employee directors | Director			4
Unrestricted Stock [Member] | Director | October 2019 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of common stock issued		22,661
Number of non employee directors | Director		4
Restricted and Unrestricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost | $						$ 0.2
2019 Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be issue						2,650,000
Number of shares are available for future grants						303,911

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Stock-Based Compensation - Schedule of Stock Based Compensation Expense (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	$ 961	$ 1,061	$ 3,585	$ 7,614
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	357	445	1,424	3,773
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	535	374	1,226	3,364
Restricted and Unrestricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock based compensation expense	$ 69	$ 242	$ 935	$ 477

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Stock-Based Compensation - Summary of Restricted Stock and Employee Restricted Stock Unit Awards Activity (Detail) - Restricted Stock Units [Member] - USD ($) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units, Beginning Balance	437,559
Number of units, Granted	351,467
Number of units, Vested	(214,804)
Number of units, Forfeited	(3,023)
Number of units, Ending Balance	571,199
Weighted average grant date fair value, Beginning Balance	$ 7.83
Weighted average grant date fair value, Granted	5.86
Weighted average grant date fair value, Vested	9.14
Weighted average grant date fair value, Forfeited	6.02
Weighted average grant date fair value, Ending Balance	$ 6.14
Aggregate intrinsic value	$ 2,508	$ 3,474

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Stock-Based Compensation - Summary of Performance Stock Unit Awards Activity (Detail) - Performance Units [Member] - USD ($) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units, Beginning Balance	320,120
Number of units, Granted	618,483
Number of units, Vested	(51,858)
Number of units, Forfeited	(55,547)
Number of units, Ending Balance	831,198
Weighted average grant date fair value, Beginning Balance	$ 11.26
Weighted average grant date fair value, Granted	6.21
Weighted average grant date fair value, Vested	20.89
Weighted average grant date fair value, Forfeited	16.69
Weighted average grant date fair value, Ending Balance	$ 6.54
Aggregate intrinsic value	$ 932	$ 2,522

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Stock-Based Compensation - Summary of Assumptions to Determine Fair Value for Performance Stock Units Granted (Detail) - Performance Units [Member]	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility	79.70%	65.10%
Risk-free interest rate	0.20%	1.83%

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Net Income (Loss) Per Share - Additional Information (Detail)		3 Months Ended
	Feb. 28, 2019	Mar. 31, 2019
Business Acquisition [Line Items]
Reverse stock split		0.067
BRMR and Everest Merger Sub Inc. [Member] | Common Stock [Member]
Business Acquisition [Line Items]
Reverse stock split, description	15-to-1
Reverse stock split	0.067

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Net Income (Loss) Per Share - Calculation of Basic and Diluted Weighted-Average Number of Shares of Common Stock and EPS (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Basic:
Net income (loss), basic	$ (92,200)	$ 4,284	$ (158,227)	$ 17,698
Net income (loss), shares, basic	36,035	35,684	35,889	32,343
Net income (loss), per shares, basic	$ (2.56)	$ 0.12	$ (4.41)	$ 0.55
Weighted-average number of shares of common stock-diluted:
Restricted stock and performance unit awards		13		128
Diluted:
Net income (loss), diluted	$ (92,200)	$ 4,284	$ (158,227)	$ 17,698
Net income (loss), shares, diluted	36,035	35,697	35,889	32,471
Net income (loss), per shares, diluted	$ (2.56)	$ 0.12	$ (4.41)	$ 0.55

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Commitments and Contingencies - Schedule of Other Commitments (Detail) $ in Thousands	Sep. 30, 2020 USD ($)
Other Commitments [Line Items]
Remainder of 2020	$ 36,157
2021	144,629
2022	149,232
2023	152,170
2024	153,073
Thereafter	1,026,259
Total	1,661,520
Firm Transportation [Member]
Other Commitments [Line Items]
Remainder of 2020	25,025	[1]
2021	99,828	[1]
2022	99,828	[1]
2023	99,828	[1]
2024	100,101	[1]
Thereafter	722,369	[1]
Total	1,146,979	[1]
Gas Processing, Gathering, and Compression Services [Member]
Other Commitments [Line Items]
Remainder of 2020	11,132	[2]
2021	44,801	[2]
2022	49,404	[2]
2023	52,342	[2]
2024	52,972	[2]
Thereafter	303,890	[2]
Total	$ 514,541	[2]

[1] 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 rates. The values in the table represent the gross amounts that the Company is committed to pay and do not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company records in its Condensed Consolidated Financial Statements the Company’s proportionate share of costs based on its working interest.

[2] 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 do not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company records in its Condensed Consolidated Financial Statements its proportionate share of costs based on the Company’s working interest.

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Income Tax - Additional Information (Detail) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2020	Dec. 31, 2017
Income Tax [Line Items]
U.S. statutory tax rate	21.00%		35.00%
Scenario, Forecast [Member]
Income Tax [Line Items]
Percentage of annual effective income tax rate		0.00%
Current federal income tax anticipated to be paid		$ 0
Net deferred tax asset		0
Net income tax expense or benefit		$ 0

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Subsidiary Guarantors - Additional Information (Detail)	Sep. 30, 2020	Jul. 06, 2015
8.875% Senior Unsecured Notes Due 2023 [Member]
Guarantee Obligations [Line Items]
Debt instrument interest rate	8.875%	8.875%