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.

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 ~~4, 2019: 35,809,858~~2, 2020: 36,023,973 shares

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”~~“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 ~~15, 2019.~~10, 2020.

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 ~~the significant decline of~~declines in the price of natural gas, NGLs and oil, ~~from historic highs,~~ 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 ~~15, 2019.~~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.

	September 30, 2019			December 31, 2018			September 30, 2020			December 31, 2019
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	11,531		$	5,959		$	4,013		$	12,056
Accounts receivable		77,154			119,332			63,483			77,402
Assets held for sale		1,485			—			1,544			1,047
Other current assets		35,239			8,639			8,984			35,509
Total current assets		125,409			133,930			78,024			126,014

PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method:
Unproved properties		520,941			482,475			478,644			508,576
Proved oil and gas properties, net		1,210,876			807,583			1,216,836			1,251,105
Other property and equipment, net		12,349			6,300			10,311			11,226
Total property and equipment, net		1,744,166			1,296,358			1,705,791			1,770,907

OTHER NONCURRENT ASSETS
Other assets		9,278			3,481			5,353			7,616
Operating lease right-of-use assets		42,936			—			30,830			36,975
Assets held for sale		8,724			—			3,403			9,665
TOTAL ASSETS	$	1,930,513		$	1,433,769		$	1,823,401		$	1,951,177

LIABILITIES AND STOCKHOLDERS' EQUITY
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	122,141		$	116,735		$	120,785		$	119,907
Accrued capital expenditures		51,785			12,979			11,933			43,500
Accrued liabilities		52,081			56,909			61,963			53,866
Accrued interest payable		11,137			21,661			9,921			21,308
Liabilities associated with assets held for sale		4,568			—			3,711			2,815
Operating lease liability		12,889			—			12,773			12,666
Total current liabilities		254,601			208,284			221,086			254,062

NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs		499,848			497,778			502,622			500,541
Revolving credit facility		127,500			32,500			170,000			130,000
Asset retirement obligations		27,169			7,110			30,336			29,877
Other liabilities		2,296			611			31,421			8,029
Operating lease liability		30,185			—			18,805			24,569
Liabilities associated with assets held for sale		6,900			—			7,150			7,013
Total liabilities		948,499			746,283			981,420			954,091
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
STOCKHOLDERS’ EQUITY
Preferred stock, 50,000,000 authorized, 0 shares issued and outstanding		—			—			—			—
Common stock, $0.01 par value, 1,000,000,000 authorized, 35,756,088 and 20,169,063 shares issued and outstanding, respectively		382			3,043
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		2,350,072			2,065,119			2,355,890			2,352,309
Treasury stock, shares at cost; 2,488,525 and 1,747,624 shares, respectively		(8,819	)		(3,357	)
Treasury stock, shares at cost; 2,600,672 and 2,508,485 shares, respectively								(10,511	)		(10,049	)
Accumulated deficit		(1,359,621	)		(1,377,319	)		(1,503,784	)		(1,345,557	)
Total stockholders’ equity		982,014			687,486			841,981			997,086
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,930,513		$	1,433,769
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY							$	1,823,401		$	1,951,177

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

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2019			2018			2019			2018			2020			2019			2020			2019
REVENUES
Natural gas, oil and natural gas liquids sales	$	153,021		$	127,179		$	428,278		$	340,620		$	108,518		$	153,021		$	315,471		$	428,278
Brokered natural gas and marketing revenue		10,228			2,944			31,747			3,318			6,831			10,228			23,859			31,747
Other revenue		46			—			307			—			56			46			183			307
Total revenues		163,295			130,123			460,332			343,938			115,405			163,295			339,513			460,332

OPERATING EXPENSES
Lease operating		11,986			5,312			29,651			22,026			11,494			11,986			33,436			29,651
Transportation, gathering and compression		57,027			39,066			150,065			98,126			51,961			57,027			157,472			150,065
Production and ad valorem taxes		1,660			2,604			8,519			7,226			3,677			1,660			10,146			8,519
Brokered natural gas and marketing expense		10,574			3,237			32,017			3,715			7,345			10,574			24,349			32,017
Depreciation, depletion, amortization and accretion		45,456			34,439			113,950			98,672			53,153			45,456			140,058			113,950
Exploration		16,621			11,328			48,602			36,227			11,767			16,621			34,112			48,602
General and administrative		14,580			12,937			57,074			33,391			12,144			14,580			33,594			57,074
Rig termination and standby		1,221			—			1,221			—			303			1,221			303			1,221
(Gain) loss on sale of assets		(733	)		6			(731	)		(1,814	)
Gain on sale of assets														(62	)		(733	)		(1,419	)		(731	)
Other expense		2			—			40			—			87			2			121			40
Total operating expenses		158,394			108,929			440,408			297,569			151,869			158,394			432,172			440,408
OPERATING INCOME		4,901			21,194			19,924			46,369
OPERATING INCOME (LOSS)														(36,464	)		4,901			(92,659	)		19,924
OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments		15,812			(3,263	)		40,620			(24,055	)		(40,535	)		15,812			(11,329	)		40,620
Interest expense, net		(15,192	)		(13,932	)		(44,140	)		(39,975	)		(14,402	)		(15,192	)		(44,166	)		(44,140	)
Other income (expense)		—			(1	)		8			(1	)
Other income														2			—			19			8
Total other income (expense), net		620			(17,196	)		(3,512	)		(64,031	)		(54,935	)		620			(55,476	)		(3,512	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		5,521			3,998			16,412			(17,662	)		(91,399	)		5,521			(148,135	)		16,412
Income tax benefit (expense)		—			—			—			—			—			—			—			—
INCOME (LOSS) FROM CONTINUING OPERATIONS		5,521			3,998			16,412			(17,662	)		(91,399	)		5,521			(148,135	)		16,412
Income (loss) from discontinued operations, net of income tax		(1,237	)		—			1,286			—			(801	)		(1,237	)		(10,092	)		1,286
NET INCOME (LOSS)	$	4,284		$	3,998		$	17,698		$	(17,662	)	$	(92,200	)	$	4,284		$	(158,227	)	$	17,698

EARNINGS (LOSS) PER SHARE OF COMMON STOCK
Basic:
Weighted average common stock outstanding		35,684			20,144			32,343			19,947			36,035			35,684			35,889			32,343
Income (loss) from continuing operations	$	0.15		$	0.20		$	0.51		$	(0.89	)	$	(2.54	)	$	0.15		$	(4.13	)	$	0.51
Income (loss) from discontinued operations		(0.03	)		—			0.04			—			(0.02	)		(0.03	)		(0.28	)		0.04
Net income (loss)	$	0.12		$	0.20		$	0.55		$	(0.89	)	$	(2.56	)	$	0.12		$	(4.41	)	$	0.55

Diluted:
Weighted average common stock outstanding		35,697			20,170			32,471			19,947			36,035			35,697			35,889			32,471
Income (loss) from continuing operations	$	0.15		$	0.20		$	0.51		$	(0.89	)	$	(2.54	)	$	0.15		$	(4.13	)	$	0.51
Income (loss) from discontinued operations		(0.03	)		—			0.04			—			(0.02	)		(0.03	)		(0.28	)		0.04
Net income (loss)	$	0.12		$	0.20		$	0.55		$	(0.89	)	$	(2.56	)	$	0.12		$	(4.41	)	$	0.55

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

	Number of Shares		Common Stock ($0.01 Par)		Additional Paid-in- Capital			Treasury Stock			Accumulated Deficit			Total			Number of Shares		Common Stock ($0.01 Par)			Additional Paid-in- Capital			Treasury Stock			Accumulated Deficit			Total
Balances, December 31, 2017		17,516,024	$	2,637	$	1,967,958		$	(2,096	)	$	(1,396,145	)	$	572,354
Balances, December 31, 2018																		20,169,063	$	3,043		$	2,065,119		$	(3,357	)	$	(1,377,319	)	$	687,486
Stock-based compensation		—		—		1,981			—			—			1,981			—		—			6,001			—			—			6,001
Equity issuance costs		—		—		(145	)		—			—			(145	)		—		—			(30	)		—			—			(30	)
Shares of common stock issued in asset acquisition, net of equity issuance costs		2,521,573		378		89,642			—			—			90,020
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		80,477		18		(18	)		(935	)		—			(935	)		499,897		22			(5	)		(5,411	)		—			(5,394	)
Net loss		—		—		—			—			(2,624	)		(2,624	)		—		—			—			—			(14,098	)		(14,098	)
Balances, March 31, 2018		20,118,074	$	3,033	$	2,059,418		$	(3,031	)	$	(1,398,769	)	$	660,651
Stock-based compensation		—		—		1,979		—			—				1,979
Equity issuance costs		—		—		(25	)	—			—				(25	)
Issuance of restricted stock		15,476		2		(2	)	—			—				—
Issuance of common stock upon vesting of equity- based compensation awards, net of shares withheld for income tax withholdings		21,452		5		(5	)		(205	)	—				(205	)
Net loss		—	—		—			—				(19,036	)		(19,036	)
Balances, June 30, 2018		20,155,002	$	3,040	$	2,061,365		$	(3,236	)	$	(1,417,805	)	$	643,364
Balances, March 31, 2019																		35,682,480	$	382		$	2,349,527		$	(8,768	)	$	(1,391,417	)	$	949,724
Stock-based compensation		—		—		2,171			—			—			2,171		��	—		—			552		—			—				552
Equity issuance costs		—		—		(137	)		—			—			(137	)		—		—			(925	)	—			—				(925	)
Issuance of common stock upon vesting of equity- based compensation awards, net of shares withheld for income tax withholdings		14,061		3		(3	)		(121	)		—			(121	)		4,727		—			—			(26	)	—				(26	)
Net income		—		—		—			—			3,998			3,998			—	—			—			—				27,512			27,512
Balances, September 30, 2018		20,169,063	$	3,043	$	2,063,396		$	(3,357	)	$	(1,413,807	)	$	649,275
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			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
Balances, December 31, 2019																			35,770,934	$	383	$	2,352,309		$	(10,049	)	$	(1,345,557	)	$	997,086
Stock-based compensation		—		—			6,001			—			—			6,001			—		—		860			—			—			860
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																			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		499,897		22			(5	)		(5,411	)		—			(5,394	)		230,293		3		(4	)		(367	)		—			(368	)
Net loss		—		—			—			—			(14,098	)		(14,098	)	—		—		—			—				(68,854	)		(68,854	)
Balances, March 31, 2019		35,682,480	$	382		$	2,349,527		$	(8,768	)	$	(1,391,417	)	$	949,724
Balances, June 30, 2020																			36,034,837	$	386	$	2,354,929		$	(10,511	)	$	(1,411,584	)	$	933,220
Stock-based compensation	—		—				552		—			—				552			—		—		961			—			—			961
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
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.

	For the Nine Months Ended September 30,						For the Nine Months Ended September 30,
	2019			2018			2020			2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	17,698		$	(17,662	)	$	(158,227	)	$	17,698
Adjustments to reconcile net loss to net cash provided by operating activities
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, amortization and accretion		114,331			98,672			140,579			114,331
Exploration expense		36,193			20,827			30,311			36,193
Stock-based compensation		7,614			6,131			3,585			7,614
Impairment of oil and gas properties								6,849			—
Net cash for plugging wells		(444	)		—			(222	)		(444	)
(Gain) loss on derivative instruments		(40,620	)		24,055			11,329			(40,620	)
Net cash receipts (payments) on settled derivatives		11,072			(7,724	)
Net cash receipts on settled derivatives								61,877			11,072
Gain on sale of assets		(734	)		(1,814	)		(1,478	)		(734	)
Amortization of deferred financing costs		2,160			1,677			2,041			2,160
Amortization of debt discount		998			995			1,000			998
Changes in operating assets and liabilities:
Accounts receivable		68,056			(48,601	)		15,437			68,056
Other assets		619			(2,144	)		(126	)		619
Accounts payable and accrued liabilities		(40,634	)		18,989			(40,124	)		(40,634	)
Net cash provided by operating activities		176,309			93,401			72,831			176,309
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for oil and gas properties		(268,768	)		(210,612	)		(122,019	)		(268,768	)
Capital expenditures for other property and equipment		(576	)		(892	)		(271	)		(576	)
Proceeds from sale of assets		1,810			10,348			1,393			1,810
Cash proceeds from merger		12,894			—
Cash acquired in merger								—			12,894
Change in deposits and other long-term assets		(53	)		—			—			(53	)
Net cash used in investing activities		(254,693	)		(201,156	)		(120,897	)		(254,693	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from other notes payable								1,141			—
Debt issuance costs		(4,242	)		(108	)		(80	)		(4,242	)
Repayments of long-term debt		(260	)		(381	)		(575	)		(260	)
Proceeds from revolving credit facility		95,000			99,000			40,000			95,000
Equity issuance costs		(31	)		(307	)		—			(31	)
Employee tax withholding for settlement of equity compensation awards		(6,511	)		(1,261	)		(463	)		(6,511	)
Net cash provided by financing activities		83,956			96,943			40,023			83,956
Net increase (decrease) in cash and cash equivalents		5,572			(10,812	)		(8,043	)		5,572
Cash and cash equivalents at beginning of period		5,959			17,224			12,056			5,959
Cash and cash equivalents at end of period	$	11,531		$	6,412		$	4,013		$	11,531
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest	$	51,280		$	49,280		$	52,590		$	51,280
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES
Asset retirement obligations incurred, including changes in estimate	$	1,006		$	388		$	196		$	1,006
Additions of other property through debt financing	$	—		$	174
Additions to oil and natural gas properties - changes in accounts payable, accrued liabilities, and accrued capital expenditures	$	16,583		$	3,988		$	(18,541	)	$	16,583
Asset acquisition through stock issuance	$	—		$	90,020
BRMR Merger consideration	$	275,759		$	—		$	—		$	275,759

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

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.

The accompanying Condensed Consolidated Financial Statements are unaudited except the ~~Condensed~~ Consolidated Balance Sheet at December 31, ~~2018,~~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 ~~15, 2019.~~10, 2020.

Operating results for interim periods may not necessarily be indicative of the results of operations for the full year ending December 31, ~~2019~~2020 or any other future ~~periods.~~periods, due to fluctuations in demand and the prices received for natural gas, NGLs and oil, the impacts of the COVID-19 pandemic, and other factors.

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

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

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 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 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 ~~did not deem any of its~~had no significant accounts receivables determined to be uncollectible as of September 30, ~~2019~~2020 or December 31, ~~2018.~~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.

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.~~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.~~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, 2019			December 31, 2018			September 30, 2020			December 31, 2019
Oil and natural gas properties:
Unproved	$	520,941		$	482,475		$	478,644		$	508,576
Proved		2,702,202			2,188,233			2,885,622			2,783,232
Gross oil and natural gas properties		3,223,143			2,670,708			3,364,266			3,291,808
Less accumulated depreciation, depletion and amortization		(1,491,326	)		(1,380,650	)		(1,668,786	)		(1,532,127	)
Oil and natural gas properties, net		1,731,817			1,290,058			1,695,480			1,759,681
Other property and equipment		21,935			14,460			19,596			20,000
Less accumulated depreciation		(9,586	)		(8,160	)		(9,285	)		(8,774	)
Other property and equipment, net		12,349			6,300			10,311			11,226
Property and equipment, net	$	1,744,166		$	1,296,358		$	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 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.

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.

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.

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.

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.

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

The following table illustrates the revenue disaggregated by type for the three and nine months ended September 30, ~~2019~~2020 and ~~2018:~~2019:

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018		2020		2019		2020		2019
Revenues (in thousands)
Natural gas sales	$	87,841	$	65,756	$	264,030	$	178,648	$	72,926	$	87,841	$	217,604	$	264,030
NGL sales		20,200		25,074		60,841		63,520		18,439		20,200		44,949		60,841
Oil sales		44,980		36,349		103,407		98,452		17,153		44,980		52,918		103,407
Brokered natural gas and marketing revenue		10,228		2,944		31,747		3,318		6,831		10,228		23,859		31,747
Other revenue		46		—		307		—		56		46		183		307
Total revenues	$	163,295	$	130,123	$	460,332	$	343,938	$	115,405	$	163,295	$	339,513	$	460,332

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.

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 ~~$57.2~~$53.5 million and ~~$94.1~~$63.7 million atas of September 30, ~~2019~~2020 and December 31, ~~2018,~~2019, respectively.

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 ~~commodity~~ 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, ~~2019~~2020 and December 31, ~~2018~~2019 (in thousands):

	September 30, 2019		December 31, 2018		September 30, 2020		December 31, 2019
Receivables by product or service:
Sale of oil and natural gas and related products and services	$	57,245	$	94,107	$	53,466	$	63,730
Joint interest owners		16,305		24,830		6,983		12,156
Derivatives		366		372		1,728		210
Other		3,238		23		1,306		1,306
Total	$	77,154	$	119,332	$	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 ~~commodity~~ derivative contracts was a net liability position of ($47.7) million and a net asset position of ~~$28.1~~$27.1 million ~~and $5.7 million at~~as of September 30, ~~2019~~2020 and December 31, ~~2018,~~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, ~~2019~~2020 and December 31, ~~2018,~~2019, the Company did not have past-due receivables from or payables to any of such counterparties.

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 ~~$44.9~~$52.8 million and ~~$34.0~~$44.9 million for the three months ended September 30, ~~2019~~2020 and ~~2018,~~2019, respectively, and ~~$112.4~~$138.9 million and ~~$97.3~~$112.4 million for the nine months ended September 30, ~~2019~~2020 and ~~2018,~~2019, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of ~~Operations.~~Operations and Comprehensive Income (Loss).

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 ~~$0.6~~$0.4 million and ~~$0.4~~$0.6 million for the three months ended September 30, ~~2019~~2020 and ~~2018,~~2019, respectively, and ~~$1.6~~$1.2 million and ~~$1.4~~$1.6 million for the nine months ended September 30, 2020 and 2019, respectively, and ~~2018, respectively. This amount~~ is included in depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of ~~Operations.~~Operations and Comprehensive Income (Loss).

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 0 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, ~~2019 or~~2020 and 2019. The Company recorded impairment of proved properties held for sale during the ~~three or~~ nine months ended September 30, ~~2018.~~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 ~~$14.1~~$11.0 million and ~~$7.0~~$14.1 million for the three months ended September 30, ~~2019~~2020 and ~~2018,~~2019, respectively, and ~~$36.2~~$30.3 million and ~~$20.6~~$36.2 million for the nine months ended September 30, ~~2019~~2020 and ~~2018,~~2019, respectively. These costs are included in exploration expense in the Condensed Consolidated Statements of ~~Operations.~~Operations and Comprehensive Income (Loss).

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

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

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

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.

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

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, ~~2019~~2020 (in thousands):

	Nine Months Ended September 30, 2019			Nine Months Ended September 30, 2020
Asset retirement obligations, beginning of period	$	7,110		$	31,841
Accretion		1,688			2,245
Additional liabilities incurred		267			15
Obligation for wells acquired		20,188
Obligation for wells drilled		445			181
Liabilities settled via plugging		(387	)		(178	)
Less: current ARO portion (accrued liabilities)		(2,142	)
Liabilities sold/disposed					(901	)
Less: current ARO portion					(2,867	)
Asset retirement obligations, end of period	$	27,169		$	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.

The Company operates in 1 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.

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 ~~balance sheets.~~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.

In ~~February~~June 2016, the FASB issued ASU ~~2016-02, “Leases (Topic 842).~~2016-13, “Financial Instruments – Credit Losses: Measurement of Credit Losses on Financial Instruments” ~~The new standard provides guidance~~, and subsequently, the FASB issued several related ASUs to ~~increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on~~clarify the ~~balance sheet and disclosing key information about leasing arrangements. Entities are required to recognize all leases in the statement of financial position as assets and liabilities regardless~~application of the ~~leases’ classification. These requirements~~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 ~~annual~~smaller reporting companies for fiscal years and interim periods within the fiscal years beginning after December 15, ~~2018, including interim periods within that reporting period with early~~2022. Early adoption is permitted. In July 2018, the FASB issued ASU 2018-11, “Leases: Targeted Improvements.” The update provided an optional transition method of adoption that permitted entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Under the optional transition method, comparative financial information and disclosures are not required. The update also provided transition practical expedients. The standard required disclosures of the nature, maturity and value of an entity's lease liabilities and elections made by the entity. In March 2019, the FASB issued ASU 2019-01, “Leases: Codification Improvements,” which, among other things, clarified interim disclosure requirements in the year of ASU 2016-02 adoption.

The Company ~~adopted these standards effective January 1, 2019 using~~is assessing the ~~optional transition method~~impact, if any, this guidance may have on our consolidated results of ~~adoption. The Company implemented a third-party-sponsored lease accounting information system to facilitate the accounting~~operations, financial position and financial reporting requirements, and implemented processes and controls to review new contracts and modifications to existing contracts that contain lease components for appropriate accounting treatment. See Note 7 – ~~Leases~~ ~~for the~~ disclosures, ~~required by the standards.~~but does not currently anticipate a material impact.

On January 18, 2018, Eclipse Resources-PA, LP, a wholly owned subsidiary of the Company, completed its acquisition of certain oil and gas leases, 1 producing well and other oil and gas rights and interests covering approximately 44,500 net acres located in Tioga and Potter Counties, Pennsylvania, from Travis Peak Resources, LLC for an aggregate adjusted purchase price of $90 million, which was paid entirely with approximately 2.5 million shares of the Company’s common stock (the “Flat Castle Acquisition”). The transaction was accounted for as an asset acquisition. Approximately $86 million of the purchase price was allocated to unproved oil and natural gas properties and approximately $4 million was allocated to proved oil and gas properties associated with the producing well acquired. In addition, the Company capitalized approximately $1 million of transaction costs related to the acquisition.

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

On February 28, 2019, the Company completed its business combination transaction with Blue Ridge Mountain Resources, Inc. (“BRMR”) pursuant to that certain Agreement and Plan of Merger, dated as of August 25, 2018 and amended as of January 7, 2019 (the ~~“Merger~~“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, ~~(the “Effective Time”),~~ 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 ~~13—~~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 0t 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 ~~preliminary~~ purchase price allocation and the values of assets acquired and liabilities assumed (in thousands):

Purchase Price	February 28, 2019			February 28, 2019
Fair value of the Company's common stock issued	$	263,487
Fair value of the Company’s common stock issued				$	263,487
Fair value of BRMR share-based and other compensation		12,272			12,272
Total Fair Value of Consideration	$	275,759		$	275,759

Cash and cash equivalents		12,894			12,894
Accounts receivable		25,884			25,884
Assets held for sale - current		2,296			2,296
Other current assets		1,702			1,702
Unproved properties		84,742			80,843
Proved oil and gas properties		218,866			218,866
Other property and equipment		7,059			7,059
Other assets		2,461			2,461
Operating lease right-of-use asset		7,900			7,900
Assets held for sale - long-term		8,505			9,611
Total assets acquired	$	372,309		$	369,516
Accounts payable		(16,571	)		(16,571	)
Accrued capital expenditures		(5,807	)		(5,807	)
Accrued liabilities		(31,619	)		(28,824	)
Operating lease liability - current		(1,977	)		(1,979	)
Liabilities associated with assets held for sale - current		(7,683	)		(7,683	)
Asset retirement obligations		(20,188	)		(20,188	)
Operating lease liability - noncurrent		(5,923	)		(5,923	)
Liabilities associated with assets held for sale - long-term		(6,782	)		(6,782	)
Total liabilities assumed	$	(96,550	)	$	(93,757	)

Net identifiable assets	$	275,759		$	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, ~~2018.~~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, ~~2018;~~2019; furthermore, the financial information is not intended to be a projection of future results.

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,					Three Months Ended September 30,		Nine Months Ended September 30,
(in thousands, except per share data) (unaudited)	2019		2018		2019		2018			2019		2019
Pro forma total revenues	$	163,294	$	176,925	$	502,989	$	451,761		$	163,295	$	502,989
Pro forma net income (loss)	$	8,220	$	10,127	$	26,638	$	(30,160	)
Pro forma net income (loss) per share (basic and diluted)	$	0.23	$	0.28	$	0.75	$	(0.85	)
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

During the nine months ended September 30, 2018, the Company received approximately $6.0 million from a completed asset sale of approximately 1,000 acres to a third party. As a result of this sale, the Company recognized a gain of approximately $1.5 million.

During the nine months ended September 30, 2018, the Company received approximately $3.8 million from a completed asset sale of approximately 400 acres to a third party. NaN gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

During the nine months ended September 30, 2018, the Company received approximately $0.3 million from an additional completed asset sale of approximately 50 acres to a third party. As a result of this sale, the Company recognized a gain of approximately $0.3 million.

~~During the nine months ended September 30, 2019, the Company received $1.8 million from acreage trades from various working interest owners which resulted in a gain of approximately $0.7 million.~~

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 atas of September 30, 2020 and December 31, 2019:

(in thousands)	September 30, 2019		September 30, 2020		December 31, 2019
Accounts receivable	$	605	$	758	$	343
Other current assets		880		786		704
Total current assets held for sale	$	1,485	$	1,544	$	1,047

Proved oil and gas properties, net	$	8,552	$	3,351	$	9,528
Other noncurrent assets		172		52		137
Total noncurrent assets held for sale	$	8,724	$	3,403	$	9,665

Accounts payable	$	3,489	$	2,104	$	2,067
Accrued liabilities		525		1,576		570
Other current liabilities		554		31		178
Total current liabilities associated with assets held for sale	$	4,568	$	3,711	$	2,815

Asset retirement obligations	$	6,346	$	7,146	$	6,488
Other liabilities		554		4		525
Total noncurrent liabilities associated with assets held for sale	$	6,900	$	7,150	$	7,013

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)	For the Three Months Ended September 30, 2019			For the Nine Months Ended September 30, 2019			Three Months Ended September 30,						Nine Months Ended September 30,
							2020			2019			2020			2019
Revenues	$	1,874		$	5,402		$	698		$	1,874		$	2,948		$	5,402
Impairment of proved oil and natural gas properties								—			—			(6,849	)		—
Depreciation, depletion, amortization and accretion		(168	)		(380	)		(182	)		(168	)		(523	)		(380	)
Other operating expenses		(2,943	)		(3,738	)		(1,317	)		(2,943	)		(5,668	)		(3,738	)
Other income		—			2			—			—			—			2
Income (loss) from discontinued operations, net of tax		(1,237	)		1,286		$	(801	)	$	(1,237	)	$	(10,092	)	$	1,286
Gain on disposal of discontinued operations, net of tax		—			—
Income (loss) from discontinued operations, net of tax	$	(1,237	)	$	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)	For the Nine Months Ended September 30, 2019		Nine Months Ended September 30,
			2020			2019
Net cash provided by operating activities	$	1,189	$	693		$	1,189
Net cash provided by investing activities	$	14
Net cash provided by (used in) investing activities			$	(82	)	$	14

The Company leases drilling rigs, compressors, vehicles, office space, and other equipment under non-cancelable operating leases expiring through 2036. Certain lease agreements may include options to renew the lease, terminate the lease early, or purchase the underlying asset(s). The Company determines the lease term at the lease commencement date as the non-cancelable periodAll of the ~~lease, including the options~~Company’s derivative instruments are used for risk management purposes and none is held for trading or speculative purposes. By using derivative instruments to ~~extend or terminate the lease when such an option is reasonably certain~~hedge exposures to ~~be exercised.~~

~~As discussed~~changes in ~~Note 3—Summary of Significant Accounting Policies~~,commodity prices and interest rates, the Company ~~adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 “Leases (Topic 842)” on January 1, 2019 using~~is exposed to the ~~optional transition method~~credit risk of ~~adoption. The Company elected~~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 ~~package of practical expedients that together allows an entity to not reassess (i) whether a~~derivative contract is ~~or contains a lease, (ii) lease classification, and (iii) initial direct costs. In addition,~~positive, the counterparty is expected to owe the Company, ~~elected~~which creates credit risk. To minimize the ~~following practical expedients for all asset classes: (i)~~credit risk in derivative instruments, it is the Company’s policy to ~~not reassess certain land easements, (ii)~~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 not apply the recognition requirements under the standard to short-term leases, and (iii) to combine and account for lease and nonlease contract components as a lease, which requires the capitalization of fixed nonlease payments on January 1, 2019 or lease effective date and recognition of variable nonlease payments as variable lease expense.

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

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

The Company incurred $4.3 million and $12.2 million in operating lease cost during the three and nine months ended September 30, 2019, respectively. The operating lease right-of-use assets were reported in other noncurrent assets and the current and noncurrent portions of the operating lease liabilities were reported in current liabilities and noncurrent liabilities, respectively, on the Condensed Consolidated Balance Sheets.periodic review. As of September 30, 2019, the operating right-of-use assets were $42.9 million and operating lease liabilities were $43.1 million, of which $12.9 million was classified as current. As of September 30, 2019, the weighted average remaining lease term was 4.0 years and the weighted average discount rate was 5.4%.

~~Supplemental cash flow information related to~~2020, the Company’s ~~operating leases is included in the table below (in thousands):~~

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

~~Note 8—Derivative Instruments~~Company has not experienced any issues of non-performance by derivative counterparties.

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. ~~All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes.~~

The Company is exposed to credit risk in the event of non-performance by counterparties. To mitigate this risk, the Company enters into derivative contracts only with counterparties that are rated “A” or higher by S&P or Moody’s. The creditworthiness of counterparties is subject to periodic review. As of September 30, 2019, the Company’s derivative instruments were with Bank of Montreal, BP Energy Company, Capital One N.A., Citibank, EDF Energy, J Aron, KeyBank N.A., Morgan Stanley, NextEra Energy, Inc., Royal Bank of Canada, and Wells Fargo. The Company has not experienced any issues of non-performance by derivative counterparties. Below is a summary of the Company’s derivative instrument positions, as of September 30, ~~2019,~~2020, for future production periods:

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)			Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		120,000	October 2019 – December 2019	$	2.80			130,000	October 2020 – December 2020	$	2.42
		50,000	January 2020 – December 2020	$	2.67			145,000	October 2020 – March 2021	$	2.58
		20,000	January 2020 – March 2020	$	2.80			50,000	January 2021 – March 2022	$	2.51
		50,000	January 2020 – June 2020	$	2.70			25,000	April 2021 – March 2022	$	2.47
		20,000	April 2020 – June 2020	$	2.75
		30,000	July 2020 – December 2020	$	2.60
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)		95,000	October 2019 – December 2019	$	2.60			15,000	August 2021 – December 2021	$	2.55
Ceiling sold price (call)		95,000	October 2019 – December 2019	$	2.91			15,000	August 2021 – December 2021	$	3.13
Floor purchase price (put)		50,000	January 2020 – December 2020	$	2.49			15,000	September 2021 – November 2021	$	2.52
Ceiling sold price (call)		50,000	January 2020 – December 2020	$	2.88			15,000	September 2021 – November 2021	$	3.12
Floor purchase price (put)		30,000	January 2020 – March 2020	$	2.65			5,000	August 2021	$	2.50
Ceiling sold price (call)		30,000	January 2020 – March 2020	$	2.98			5,000	August 2021	$	3.05
Floor purchase price (put)		15,000	April 2020 – June 2020	$	2.50			10,000	September 2021	$	2.50
Ceiling sold price (call)		15,000	April 2020 – June 2020	$	2.80			10,000	September 2021	$	3.03
Natural Gas Three-way Collars:
Floor purchase price (put)		77,500	October 2019 – December 2019	$	2.72			80,000	October 2020 – December 2020	$	2.60
Floor sold price (put)		77,500	October 2019 – December 2019	$	2.30			80,000	October 2020 – December 2020	$	1.90
Ceiling sold price (call)		77,500	October 2019 – December 2019	$	3.04			80,000	October 2020 – December 2020	$	2.94
Floor purchase price (put)		30,000	January 2020 – December 2020	$	2.70			45,000	January 2021 – December 2021	$	2.55
Floor sold price (put)		30,000	January 2020 – December 2020	$	2.40			45,000	January 2021 – December 2021	$	2.25
Ceiling sold price (call)		30,000	January 2020 – December 2020	$	3.05			45,000	January 2021 – December 2021	$	2.81
Floor purchase price (put)		30,000	January 2020 – March 2020	$	2.72			20,000	April 2021 – March 2022	$	2.62
Floor sold price (put)		30,000	January 2020 – March 2020	$	2.25			20,000	April 2021 – March 2022	$	2.20
Ceiling sold price (call)		30,000	January 2020 – March 2020	$	3.15			20,000	April 2021 – March 2022	$	3.10
Floor purchase price (put)		20,000	January 2020 – June 2020	$	2.70
Floor sold price (put)		20,000	January 2020 – June 2020	$	2.25
Ceiling sold price (call)		20,000	January 2020 – June 2020	$	3.05
Floor purchase price (put)		30,000	October 2019 – June 2020	$	2.90
Floor sold price (put)		30,000	October 2019 – June 2020	$	2.50
Ceiling sold price (call)		30,000	October 2019 – June 2020	$	3.15
Natural Gas Call/Put Options:
Ceiling sold price (call)		40,000	October 2019 – December 2019	$	3.44
Floor sold price (put)		50,000	January 2020 – December 2020	$	2.30
Floor sold price (put)		50,000	January 2020 – June 2020	$	2.25			50,000	October 2020 – December 2020	$	2.30
Swaption sold price (call)		50,000	January 2021 – December 2021	$	2.75			50,000	January 2021 – December 2021	$	2.75
Swaption sold price (call)		50,000	January 2022 – December 2022	$	3.00			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		12,500	October 2019	$	(0.52	)		42,500	October 2020	$	(0.51	)
Appalachia - Dominion		12,500	April 2020 – October 2020	$	(0.52	)		20,000	October 2020 – December 2020	$	(0.59	)
Appalachia - Dominion		20,000	January 2020 – December 2020	$	(0.59	)
Appalachia - Dominion		20,000	October 2019 – March 2020	$	(0.39	)
Appalachia - Dominion		17,500	October 2019 – December 2019	$	(0.50	)

Description	Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)		Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)
Oil Swaps:
							2,500	October 2020 – December 2020	$	57.41
		1,500	October 2019 – December 2019	$	59.18		250	October 2020 – March 2021	$	53.20
		1,000	January 2020 – December 2020	$	58.60		250	January 2021 – March 2021	$	53.00
		1,000	July 2020 – December 2020	$	56.53		100	January 2021	$	43.60
Oil Collars:
Floor purchase price (put)		1,500	October 2019 – December 2019	$	51.67		1,000	October 2020 – December 2020	$	51.00
Ceiling sold price (call)		1,500	October 2019 – December 2019	$	65.92		1,000	October 2020 – December 2020	$	62.00
Floor purchase price (put)		1,000	January 2020 – December 2020	$	51.50		500	January 2021 – December 2021	$	37.50
Ceiling sold price (call)		1,000	January 2020 – December 2020	$	64.25		500	January 2021 – December 2021	$	45.50
Floor purchase price (put)		500	July 2020 – December 2020	$	52.00		300	April 2021	$	40.00
Ceiling sold price (call)		500	July 2020 – December 2020	$	60.00		300	April 2021	$	47.25
Floor purchase price (put)		500	October 2019 – March 2020	$	60.00		200	May 2021	$	40.00
Ceiling sold price (call)		500	October 2019 – March 2020	$	67.00		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)		2,000	October 2019 – December 2019	$	50.00		500	January 2021 – December 2021	$	31.25
Floor sold price (put)		2,000	October 2019 – December 2019	$	40.00		500	January 2021 – December 2021	$	22.50
Ceiling sold price (call)		2,000	October 2019 – December 2019	$	60.56		500	January 2021 – December 2021	$	45.00
Floor purchase price (put)		2,000	January 2020 – June 2020	$	62.50
Oil Call/Put Options:
Floor sold price (put)		2,000	January 2020 – June 2020	$	55.00		500	October 2020 – December 2020	$	45.00
Ceiling sold price (call)		2,000	January 2020 – June 2020	$	74.00
Oil Call/Put Options:
Swaption sold price (call)		500	January 2021 – December 2021	$	56.80		500	January 2021 – December 2021	$	42.50

Description	Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)		Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)
Propane Swaps:
		350	October 2019 – December 2019	$	39.90		2,000	October 2020 – December 2020	$	20.94
							1,000	January 2021 – December 2021	$	18.87

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.

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 ~~are~~is designated as a hedge for accounting purposes.

As of September 30, 2019	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
As of September 30, 2020											Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	32,344		$	(3,279	)		29,065		Other current assets	$	7,423		$	(4,213	)		3,210		Other current assets
Commodity derivatives - noncurrent		2,816			(699	)		2,117		Other assets
Total assets	$	35,160		$	(3,978	)	$	31,182			$	7,423		$	(4,213	)	$	3,210

Liabilities
Commodity derivatives - current	$	(4,232	)	$	3,279		$	(953	)	Accrued liabilities	$	(27,338	)	$	4,213		$	(23,125	)	Accrued liabilities
Interest-rate swap - current												(103	)		—			(103	)	Accrued liabilities
Commodity derivatives - noncurrent		(2,804	)		699			(2,105	)	Other liabilities		(27,269	)		—			(27,269	)	Other liabilities
Interest-rate swap - noncurrent												(404	)		—			(404	)	Other liabilities
Total liabilities	$	(7,036	)	$	3,978		$	(3,058	)		$	(55,114	)	$	4,213		$	(50,901	)

As of December 31, 2018	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
As of December 31, 2019											Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	4,960		$	(845	)	$	4,115		Other current assets	$	33,762		$	(3,719	)	$	30,043		Other current assets
Commodity derivatives - noncurrent		1,910			—			1,910		Other assets		833			(45	)		788		Other assets
Total assets	$	6,870		$	(845	)	$	6,025			$	34,595		$	(3,764	)	$	30,831

Liabilities
Commodity derivatives - current	$	(845	)	$	845		$	—		Accrued liabilities	$	(5,081	)	$	3,719		$	(1,362	)	Accrued liabilities
Commodity derivatives - noncurrent		(326	)		—			(326	)	Other liabilities		(2,397	)		45			(2,352	)	Other liabilities
Total liabilities	$	(1,171	)	$	845		$	(326	)		$	(7,478	)	$	3,764		$	(3,714	)

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											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,					Location of Gain (Loss) Recognized in Income	Three Months Ended September 30,					Nine Months Ended September 30,
		2019		2018			2019		2018				2020			2019		2020			2019
Commodity derivatives	Gain (loss) on derivative instruments	$	15,812	$	(3,263	)	$	40,620	$	(24,055	)	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

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		Level 1		Level 2			Level 3		Total Fair Value
As of September 30, 2019: (in thousands)
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	$	—	$	28,124	$	—	$	28,124	$	—	$	27,117		$	—	$	27,117
Total	$	—	$	28,124	$	—	$	28,124	$	—	$	27,117		$	—	$	27,117
As of December 31, 2018: (in thousands)
Commodity derivative instruments	$	—	$	5,699	$	—	$	5,699
Total	$	—	$	5,699	$	—	$	5,699

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 ~~10—~~8—Debt).

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.

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. The Company amortized $0.9 million and $2.7 million of deferred financing costs and debt discount to interest expense using the effective interest method for the three and nine months ended September 30, 2018, respectively.

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 atas of September 30, ~~2019.~~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 atas of September 30, ~~2019~~2020 was ~~$390.7~~$519.0 million.

~~During the first quarter of 2014, Eclipse Resources I, LP, a wholly owned subsidiary of the~~The Company ~~(“Eclipse I”) entered into a $500 million~~maintains an asset-based, senior secured revolving bank credit facility ~~(the “revolving credit facility”) that was scheduled to mature in 2018. Borrowings under~~ (“the revolving credit ~~facility are subject to~~facility”). The borrowing base ~~limitations based on the collateral value of~~is derived from the Company’s proved properties and ~~commodity hedge positions and are~~is subject to ~~semiannual~~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 ~~restated on January 12, 2015. The primary change effected by such amendment was~~2019 in order to, among other things, add the Company as a party to the revolving credit facility, ~~and thereby subject~~extend the ~~Company~~maturity date to February 2024, amend the ~~representations, warranties,~~borrowing base, revise certain financial covenants, and events of default provisions thereof. Relative to Eclipse I’s previous credit agreement, the Credit Agreement also (i) requires financial reporting regarding, and tests financial covenants with respect to, Montage Resources Corporation (f/k/a Eclipse Resources Corporation) rather than Eclipse I, (ii) increases the basket sizes underrevise certain of the negative covenants, and (iii) includes certain other changes favorable to Eclipse I. Other terms of the Credit Agreement remain generally consistent with Eclipse I’s previous credit agreement.

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

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

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

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

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

At September 30, 2019, the borrowing base was $500 million and the Company had $127.5 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 $127.5 million, the Company had available borrowing capacity under the revolving credit facility of $343.3 million at September 30, 2019.

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. ~~The Company was in compliance with all applicable covenants under the revolving credit facility as of September 30, 2019.~~ Commitment fees on the unused portion of the revolving credit facility are due quarterly at 0.375%-0.500% of the unused facility based on utilization.

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.

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.

The Company currently maintains a retirement plan intended to provide benefits under section 401(k) of the Internal Revenue Code, as amended ~~(“the Code”~~(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 ~~each of~~ the three months ended September 30, 2020 and 2019, respectively, and ~~2018,~~$0.9 million and $0.8 ~~million and $0.7~~ million for the nine months ended September 30, ~~2019~~2020 and ~~2018,~~2019, respectively.

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

The Company is authorized to grant up to 2,650,000 shares of common stock under ~~the~~its 2019 ~~Plan.~~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, ~~qualified performance-based~~bonus stock or other stock-based awards and ~~other types of~~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 ~~1,778,895~~303,911 shares were available for future grants under the Plan as of September 30, ~~2019.~~2020.

Stock-based compensation expense was as follows for the three and nine months ended September 30, ~~2019~~2020 and ~~2018~~2019 (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018		2020		2019		2020		2019
Restricted stock units	$	445	$	1,026	$	3,773	$	3,164	$	357	$	445	$	1,424	$	3,773
Performance units		374		1,047		3,364		2,685		535		374		1,226		3,364
Restricted and unrestricted stock		242		98		477		282		69		242		935		477
Total expense	$	1,061	$	2,171	$	7,614	$	6,131	$	961	$	1,061	$	3,585	$	7,614

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, ~~2019,~~2020, there was ~~$2.8~~$3.1 million of total unrecognized compensation cost related to outstanding restricted stock units. The weighted average period for the ~~shares~~units to vest is approximately ~~two years.~~one year. A summary of employee restricted stock unit awards activity during the nine months ended September 30, ~~2019~~2020 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)		Number of units			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2018		233,960		$	29.27	$	3,685
Total awarded and unvested, December 31, 2019									437,559		$	7.83	$	3,474
Granted		407,714			6.46				351,467			5.86
Vested		(212,140	)		28.71				(214,804	)		9.14
Forfeited		(485	)		31.78				(3,023	)		6.02
Total awarded and unvested, September 30, 2019		429,049		$	7.86	$	1,622
Total awarded and unvested, September 30, 2020									571,199		$	6.14	$	2,508

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 ~~Total Shareholder Return (as defined in~~ the ~~award agreements), as~~Company’s performance compared to an industry peer ~~group~~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 ~~that same~~the performance period. ~~The~~All performance unit awards are measured at the grant date at fair value using a Monte Carlo valuation method.

As of September 30, ~~2019,~~2020, there was ~~$2.0~~$4.1 million of total unrecognized compensation cost related to outstanding performance units. The weighted average period for the ~~shares~~units to vest is approximately two years. A summary of performance stock unit awards activity during the nine months ended September 30, ~~2019~~2020 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)		Number of units			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2018		346,589		$	27.68	$	716
Total awarded and unvested, December 31, 2019									320,120		$	11.26	$	2,522
Granted		255,419			7.25				618,483			6.21
Vested		(270,068	)		27.57				(51,858	)		20.89
Forfeited		(16,483	)		24.60				(55,547	)		16.69
Total awarded and unvested, September 30, 2019		315,457		$	11.39	$	—
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~~risk-free interest rate and a volatility estimate tied to the Company’s stock price. ~~Prior to 2018, the volatility estimate was tied to the Company’s public peer group.~~ The following table presents the assumptions used to determine the fair value for performance stock units granted during the nine months ended September 30, ~~2019~~2020 and ~~2018:~~2019:

	Nine Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2020			2019
Volatility		65.10	%		89.70	%		79.70	%		65.10	%
Risk-free interest rate		1.83	%		2.37	%		0.20	%		1.83	%

On May 17, 2017, the Company issued an aggregate of 10,212 restricted shares of common stock to its 3 non-employee members of its Board of Directors who were not affiliated with the Company’s then controlling stockholder, which shares became fully vested on May 17, 2018.

On May 16, 2018, the Company issued an aggregate of 15,476 restricted shares of common stock to its 3 non-employee members of its Board of Directors who were not affiliated with the Company’s then controlling stockholder, which shares became fully vested on May 16, 2019.

Effective February 28, 2019, the Company issued an aggregate of 70,409 restricted shares of common stock to 2 of its officers in connection with retention bonus arrangements entered into between the Company and each of these officers. NaN 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 ~~75%~~50% of the restricted shares ~~vest in substantially equal installments~~vested on ~~February 28, 2020, August 28, 2020 and February 28, 2021.~~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 8 of the non-employee members of its Board of Directors, which shares ~~are scheduled to~~became fully ~~vest~~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 4 of the non-employee members of its Board of ~~Directors.~~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 5 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.

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.

Effective immediately prior to the ~~Effective Time~~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~~effective time received cash for any fractional shares of the Company’s common stock to which they might otherwise have been entitled as a result of the reverse stock split. The reverse stock split lowered the aggregate par value of the common stock reflected in the Consolidated Statements of Stockholders’ Equity to reflect the reduced shares with the offset to additional paid-in-capital. ~~The table below retroactively reflects, in accordance with ASC 505 “Equity,” the reverse stock split that occurred on February 28, 2019 for the three and nine months ended September 30, 2018.~~ 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, ~~2019~~2020 and ~~2018:~~2019:

	Three Months Ended September 30,												Three Months Ended September 30,
(in thousands, except per share data)	2019						2018						2020								2019
	Income		Shares		Per Share		Income		Shares		Per Share		Loss			Shares		Per Share			Income		Shares		Per Share
Basic:
Net income, shares, basic	$	4,284		35,684	$	0.12	$	3,998		20,144	$	0.20
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				—		26				—			—					—		13
Diluted:
Net income, shares, diluted	$	4,284		35,697	$	0.12	$	3,998		20,170	$	0.20
Net income (loss), shares, diluted													$	(92,200	)		36,035	$	(2.56	)	$	4,284		35,697	$	0.12

	Nine Months Ended September 30,														Nine Months Ended September 30,
(in thousands, except per share data)	2019						2018								2020								2019
	Income		Shares		Per Share		Loss			Shares		Per Share			Loss			Shares		Per Share			Income		Shares		Per Share
Basic:
Net income (loss), shares, basic	$	17,698		32,343	$	0.55	$	(17,662	)		19,947	$	(0.89	)	$	(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		—		127				—			—					—			—					—		128
Diluted:
Net income (loss), shares, diluted	$	17,698		32,471	$	0.55	$	(17,662	)		19,947	$	(0.89	)	$	(158,227	)		35,889	$	(4.41	)	$	17,698		32,471	$	0.55

During the three and nine months ended September 30, 2018, the Company incurred approximately $0.2 million and $0.5 million, respectively, related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which were owned by the Company’s former Chairman, President and Chief Executive Officer. The Company incurred less than $0.1 million during the nine months ended September 30, 2019, and during the three months ended September 30, 2019, the Company did 0t incur any expense related to such flight charter services. The fees were paid in accordance with a standard service contract that did not obligate the Company to any minimum terms. The Company no longer utilizes any flight charter services under this arrangement.

Travis Peak Resources, LLC, the seller from whom the Company acquired assets in the Flat Castle Acquisition, is an affiliate of EnCap Investments L.P. (“EnCap”). EnCap has representatives on the Board, and affiliates of EnCap collectively beneficially own approximately 40% of the outstanding shares of the Company’s common stock (See Note 4—~~Acquisitions~~).

From time to time, the Company ~~may be~~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 ~~such proceedings.~~

~~During the nine months ended September 30, 2019,~~any legal proceedings to which the Company ~~removed an accrued liability related~~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 ~~certain litigation involving MHP (See Note 6—~~ ~~Assets Held~~the merger and/or assert claims for ~~Sale~~breach of fiduciary duty under Delaware law against the Company and ~~Discontinued Operations~~).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.

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.

~~As a result of the BRMR Merger, effective as of February 28, 2019,~~In March 2020, the Company ~~assumed~~completed the renegotiation of certain existing gas gathering contracts with a midstream service provider into a single new consolidated gas gathering agreement. Revised commitments ~~related to certain firm transportation and~~under the new consolidated gas ~~processing,~~ gathering ~~and compression service agreements entered into by Triad Hunter, LLC (“Triad Hunter”), a wholly owned subsidiary of BRMR, as shown below~~agreement (in thousands): are included in the table below:

	Firm transportation⁽ⁱ⁾		Gas processing, gathering, and compression services⁽ⁱⁱ⁾		Total		Firm transportation⁽ⁱ⁾		Gas processing, gathering, and compression services⁽ⁱⁱ⁾		Total
Year Ending December 31:
2019	$	14,562	$	12,873	$	27,435
2020		19,416		17,133		36,549
Remainder of 2020							$	25,025	$	11,132	$	36,157
2021		19,416		17,087		36,503		99,828		44,801		144,629
2022		19,416		17,087		36,503		99,828		49,404		149,232
2023		18,047		16,561		34,608		99,828		52,342		152,170
2024								100,101		52,972		153,073
Thereafter		92,395		139,545		231,940		722,369		303,890		1,026,259
Total	$	183,252	$	220,286	$	403,538	$	1,146,979	$	514,541	$	1,661,520

For the year ending December 31, ~~2019,~~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 ~~income but~~loss and a tax loss in fiscal year ~~2019,~~2020, and thus, 0 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, ~~the~~ 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 ~~2019~~2020 annual estimated effective tax rate, management believes that it should limit any tax benefit suggested by the tax effect of the forecasted book ~~income~~loss such that 0 net deferred tax asset is recorded in ~~2019.~~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 ~~balance sheet.~~Condensed Consolidated Balance Sheet.

The Company is forecasting ~~positive~~ pre-tax book ~~income~~loss for the year ending December 31, ~~2019. Management expects that income tax expense attributable to current year operations will be offset by a release of the valuation allowance on hand at the beginning of the year.~~2020. As a result, 0 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, of the BRMR Merger, BRMR’s pre-acquisition tax loss carryforward (“NOL”) and other tax attributes will be subject to limitation in accordance with ownership change rules under Code section 382, and the Company will have an ownership change which would similarly limit its ability to use pre-acquisition NOLs and other tax attributes. The Company is still evaluating the impact that Code section 382 will have on both the acquired BRMR tax attributesCompany’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 ~~pre-acquisition~~stock, the Company’s use of remaining U.S. tax ~~attributes.~~attributes may be further limited.

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 ~~10—~~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:

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.

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, ~~2018~~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.

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 ~~(“Montage”)~~ and its subsidiaries.

As of September 30, ~~2019,~~2020, we had assembled an acreage position approximating ~~236,700~~233,000 net surface acres in Eastern Ohio, ~~44,600~~33,300 net surface acres in Pennsylvania, and ~~49,700~~54,300 net surface acres in West Virginia, which excludes any acreage currently pending title.

Approximately ~~224,300~~178,600 of our net acres are located in the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately ~~92,500~~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, ~~2019,~~2020, we were not operating ~~one horizontal rig.~~any rigs. We had average daily production for the three months ended September 30, ~~2019~~2020 of approximately ~~621.7~~602.6 MMcfe comprised of approximately ~~76%~~82% natural gas, ~~14%~~12% NGLs and ~~10%~~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.

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.

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.

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.

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”); ~~amortization of deferred financing costs;~~ 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 ~~assets and liabilities are included in the Unaudited Condensed Consolidated Balance Sheet as of September 30, 2019 and BRMR’s~~ revenues and expenses are included in the ~~Unaudited~~ Condensed Consolidated ~~Statement~~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, ~~2019~~2020

During the three months ended September 30, ~~2019,~~2020, we achieved the following financial and operating results:

During the nine months ended September 30, ~~2019,~~2020, we achieved the following financial and operating results:

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, ~~2019~~2020 and ~~2018:~~2019:

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018		2020		2019		2020			2019
NYMEX Henry Hub High ($/MMBtu)	$	2.75	$	3.12	$	4.25	$	6.24	$	2.57	$	2.75	$	2.57		$	4.25
NYMEX Henry Hub Low ($/MMBtu)		2.02		2.73		2.02		2.49		1.33		2.02		1.33			2.02
Average Daily NYMEX Henry Hub ($/MMBtu)		2.38		2.93		2.62		2.95		2.00		2.38		1.87			2.62
Average Monthly Settled NYMEX Henry Hub ($/MMBtu)		2.23		2.90		2.67		2.90		1.98		2.23		1.88			2.67

NYMEX WTI High ($/Bbl)	$	63.10	$	74.19	$	66.24	$	77.41	$	43.21	$	63.10	$	63.27		$	66.24
NYMEX WTI Low ($/Bbl)		51.14		65.07		46.31		59.20		36.87		51.14		(36.98	)		46.31
Average Daily NYMEX WTI ($/Bbl)		56.34		69.69		57.04		66.93		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, ~~2018.~~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, ~~2019~~2020 and held all other factors constant, then our estimated net proved reserves at December 31, ~~2018~~2019 would have decreased by approximately ~~3.3%~~34.2% from our previously reported estimated net proved reserves at such time, including a ~~1.4%~~9.7% reduction of proved developed reserves and a ~~4.4%~~63.7% reduction of proved undeveloped reserves. The foregoing estimate is based upon an average SEC benchmark price of ~~$2.87~~ $1.97

per MMBtu for natural gas and ~~$57.69~~$43.63 per Bbl for ~~oil.~~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, ~~2018.~~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 atas of September 30, ~~2019,~~2020, cash flows from operations and borrowings under our revolving credit ~~facility, and proceeds from asset sales.~~facility.

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, ~~2019~~2020 and ~~2018.~~2019. The results of operations of MHP are reflected as discontinued operations for all periods presented.

Three Months Ended September 30, ~~2019~~2020 Compared to Three Months Ended September 30, ~~2018~~2019

The following table illustrates the revenue attributable to our operations for the three months ended September 30, ~~2019~~2020 and ~~2018:~~2019:

	Three Months Ended September 30,							Three Months Ended September 30,
	2019		2018		Change			2020		2019		Change
Revenues (in thousands)
Natural gas sales	$	87,841	$	65,756	$	22,085		$	72,926	$	87,841	$	(14,915	)
NGL sales		20,200		25,074		(4,874	)		18,439		20,200		(1,761	)
Oil sales		44,980		36,349		8,631			17,153		44,980		(27,827	)
Brokered natural gas and marketing revenue		10,228		2,944		7,284			6,831		10,228		(3,397	)
Other revenue		46		—		46			56		46		10
Total revenues	$	163,295	$	130,123	$	33,172		$	115,405	$	163,295	$	(47,890	)

Our production ~~grew~~decreased by approximately ~~25.3~~1.8 Bcfe for the three months ended September 30, ~~2019~~2020 over the same period in ~~2018~~2019 due to ~~increased~~natural decline as we decreased drilling ~~activity and from wells acquired as part of the BRMR Merger.~~activity. Our production for the three months ended September 30, ~~2019~~2020 and ~~2018~~2019 is set forth in the following table:

	Three Months Ended September 30,						Three Months Ended September 30,
	2019		2018		Change		2020		2019		Change
Production:
Natural gas (MMcf)		43,289.9		22,979.7		20,310.2		45,333.6		43,289.9		2,043.7
NGLs (Mbbls)		1,401.1		906.4		494.7		1,150.6		1,401.1		(250.5	)
Oil (Mbbls)		916.2		574.8		341.4		533.3		916.2		(382.9	)
Total (MMcfe)		57,193.7		31,866.9		25,326.8		55,437.0		57,193.7		(1,756.7	)

Average daily production volume:
Natural gas (Mcf/d)		470,542		249,779		220,763		492,757		470,542		22,215
NGLs (Bbls/d)		15,229		9,852		5,377		12,507		15,229		(2,722	)
Oil (Bbls/d)		9,959		6,248		3,711		5,797		9,959		(4,162	)
Total (Mcfe/d)		621,670		346,379		275,291		602,576		621,670		(19,094	)

Our average realized price (including cash settled commodity derivatives and firm transportation) received during the three months ended September 30, ~~2019~~2020 was ~~$2.56~~$1.95 per Mcfe compared to ~~$3.34~~$2.56 per Mcfe during the three months ended September 30, ~~2018.~~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 ~~sales~~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.~~Operations and Comprehensive Income (Loss). Average ~~sales~~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, ~~2019~~2020 and ~~2018~~2019 are shown below:

	Three Months Ended September 30,							Three Months Ended September 30,
	2019		2018		Change			2020		2019		Change
Average realized price (excluding cash settled derivatives and firm transportation)
Average realized price (excluding cash settled commodity derivatives and firm transportation)
Natural gas ($/Mcf)	$	2.03	$	2.86	$	(0.83	)	$	1.61	$	2.03	$	(0.42	)
NGLs ($/Bbl)		14.42		27.66		(13.24	)		16.03		14.42		1.61
Oil ($/Bbl)		49.09		63.24		(14.15	)		32.16		49.09		(16.93	)
Total average prices ($/Mcfe)		2.68		3.99		(1.31	)		1.96		2.68		(0.72	)

Average realized price (including cash settled derivatives, excluding firm transportation)
Average realized price (including cash settled commodity derivatives, excluding firm transportation)
Natural gas ($/Mcf)	$	2.28	$	2.89	$	(0.61	)	$	1.92	$	2.28	$	(0.36	)
NGLs ($/Bbl)		14.92		27.66		(12.74	)		16.00		14.92		1.08
Oil ($/Bbl)		49.53		52.67		(3.14	)		40.76		49.53		(8.77	)
Total average prices ($/Mcfe)		2.88		3.82		(0.94	)		2.30		2.88		(0.58	)

Average realized price (including firm transportation, excluding cash settled derivatives)
Average realized price (including firm transportation, excluding cash settled commodity derivatives)
Natural gas ($/Mcf)	$	1.60	$	2.19	$	(0.59	)	$	1.18	$	1.60	$	(0.42	)
NGLs ($/Bbl)		14.42		27.66		(13.24	)		16.03		14.42		1.61
Oil ($/Bbl)		49.09		63.24		(14.15	)		32.16		49.09		(16.93	)
Total average prices ($/Mcfe)		2.35		3.51		(1.16	)		1.61		2.35		(0.74	)

Average realized price (including cash settled derivatives and firm transportation)
Average realized price (including cash settled commodity derivatives and firm transportation)
Natural gas ($/Mcf)	$	1.85	$	2.22	$	(0.37	)	$	1.50	$	1.85	$	(0.35	)
NGLs ($/Bbl)		14.92		27.66		(12.74	)		16.00		14.92		1.08
Oil ($/Bbl)		49.53		52.67		(3.14	)		40.76		49.53		(8.77	)
Total average prices ($/Mcfe)		2.56		3.34		(0.78	)		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, ~~compared to $2.9 million for the three months ended September 30, 2018.~~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 ~~increase~~decrease for the three months ended September 30, ~~2019~~2020 was due to ~~an increase~~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.

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, ~~2019~~2020 and ~~2018:~~2019:

	Three Months Ended September 30,							Three Months Ended September 30,
	2019		2018		Change			2020		2019		Change
Operating expenses (in thousands):
Lease operating	$	11,986	$	5,312	$	6,674		$	11,494	$	11,986	$	(492	)
Transportation, gathering and compression		57,027		39,066		17,961			51,961		57,027		(5,066	)
Production and ad valorem taxes		1,660		2,604		(944	)		3,677		1,660		2,017
Depreciation, depletion, amortization and accretion		45,456		34,439		11,017			53,153		45,456		7,697
General and administrative		14,580		12,937		1,643			12,144		14,580		(2,436	)
Operating expenses per Mcfe:
Lease operating	$	0.21	$	0.17	$	0.04		$	0.21	$	0.21	$	—
Transportation, gathering and compression		0.99		1.21		(0.22	)		0.93		0.99		(0.06	)
Production and ad valorem taxes		0.03		0.08		(0.05	)		0.07		0.03		0.04
Depreciation, depletion, amortization and accretion		0.79		1.08		(0.29	)		0.96		0.79		0.17
General and administrative		0.25		0.41		(0.16	)		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 compared to $5.3 million in the three months ended September 30, 2018.~~2019. Lease operating expense per Mcfe was $0.21 in each of the three months ended September 30, ~~2019 compared~~2020 and 2019. The decrease of $0.5 million was primarily attributable to ~~$0.17~~a decrease in water disposal costs in the three months ended September 30, ~~2018. The increase of $6.7 million was primarily attributable to an increase in the number of producing wells. The increase of $0.04~~2020. Expenses on a per Mcfe ~~was primarily due to increased water disposal costs~~basis were comparable for the three months ended September 30, ~~2019 as~~2020 compared to the three months ended September 30, ~~2018.~~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 compared to $39.1 million during the three months ended September 30, 2018.~~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 compared to $1.21 in the three months ended September 30, 2018.~~2019. The following table details our transportation, gathering and compression expenses for the three months ended September 30, ~~2019~~2020 and ~~2018:~~2019:

	Three Months Ended September 30,							Three Months Ended September 30,
	2019		2018		Change			2020		2019		Change
Transportation, gathering and compression (in thousands):
Gathering, compression and fuel	$	18,346	$	10,732	$	7,614		$	16,271	$	18,346	$	(2,075	)
Processing and fractionation		17,894		10,588		7,306			15,218		17,894		(2,676	)
Liquids transportation and stabilization		2,320		2,326		(6	)		1,179		2,320		(1,141	)
Marketing		—		12		(12	)		—		—		—
Firm transportation		18,467		15,408		3,059			19,293		18,467		826
	$	57,027	$	39,066	$	17,961		$	51,961	$	57,027	$	(5,066	)
Transportation, gathering and compression per Mcfe:
Gathering, compression and fuel	$	0.32	$	0.33	$	(0.01	)	$	0.29	$	0.32	$	(0.03	)
Processing and fractionation		0.31		0.33		(0.02	)		0.27		0.31		(0.04	)
Liquids transportation and stabilization		0.04		0.07		(0.03	)		0.02		0.04		(0.02	)
Marketing		—		—		—			—		—		—
Firm transportation		0.32		0.48		(0.16	)		0.35		0.32		0.03
	$	0.99	$	1.21	$	(0.22	)	$	0.93	$	0.99	$	(0.06	)

The ~~increase~~decrease of ~~$18.0~~$5.1 million to transportation, gathering and compression expenses during the three months ended September 30, ~~2019~~2020 was primarily due to ~~increased firm transportation capacity and increased production~~lower contractual rates during the three months ended September 30, ~~2019.~~2020. The decrease of ~~$0.22~~$0.06 per Mcfe was primarily due to a higher percentage of production attributable to natural gas and ~~fixed~~lower contractual rates offset by increased firm transportation ~~costs spread across increased~~expense from lower marketed production during the three months ended September 30, ~~2019.~~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 compared to $2.6 million in the three months ended September 30, 2018.~~2019. Production and ad valorem taxes per Mcfe was ~~$0.03~~$0.07 for the three months ended September 30, ~~2019~~2020 compared to ~~$0.08~~$0.03 per Mcfe for the three months ended September 30, ~~2018.~~2019. The ~~decrease~~increase of ~~$0.9~~$2.0 million and ~~$0.05~~$0.04 per Mcfe was primarily due to the recognition of a refund of production taxes from a state taxing authority ~~partially offset by increased well count for~~during the three months ended September 30, ~~2019.~~2019, as well as increased well count.

Depreciation, depletion, amortization and accretion was approximately ~~$45.5~~$53.2 million in the three months ended September 30, ~~2019~~2020 compared to ~~$34.4~~$45.5 million in the three months ended September 30, 2018. DD&A per Mcfe was $0.79 for the three months ended September 30, 2019 compared to $1.08 for the three months ended September 30, 2018. DD&A increased on an aggregate basis due to increased production 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 ~~lower~~higher depletion rate resulting from reserves increasing at a ~~higher~~lower rate than capital costs for the three months ended September 30, ~~2019.~~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 compared to $12.9 million for~~2019. General and administrative expense per Mcfe was $0.22 in the three months ended September 30, ~~2018. General and administrative expense per Mcfe was~~2020 compared to $0.25 in the three months ended September 30, ~~2019 compared~~2019. The decrease of $2.4 million and $0.03 per Mcfe was related to ~~$0.41~~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, ~~2018. The increase of $1.6 million was primarily related~~2020 compared to ~~an increase in professional fees.~~the three months ended September 30, 2019. General and administrative ~~expense~~expenses for the three months ended September 30, 2020 included ~~$1.1 million and $2.2~~$1.0 million of stock-based compensation expense ~~as well as $3.3 million~~ and ~~$3.0~~$2.5 million of merger-related expenses. General and administrative expenses ~~related to the BRMR Merger~~ for the three months ended September 30, 2019 included $1.1 million of stock-based compensation expense and ~~2018, respectively. The decrease~~$3.3 million of ~~$0.16 per Mcfe was due to fixed costs spread across increased production during the three months ended September 30, 2019.~~merger-related 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, ~~2019~~2020 and ~~2018:~~2019:

	Three Months Ended September 30,								Three Months Ended September 30,
	2019			2018		Change			2020			2019			Change
Other operating expenses (in thousands):
Brokered natural gas and marketing expense	$	10,574		$	3,237	$	7,337		$	7,345		$	10,574		$	(3,229	)
Exploration		16,621			11,328		5,293			11,767			16,621			(4,854	)
Rig termination and standby		1,221			—		1,221			303			1,221			(918	)
(Gain) loss on sale of assets		(733	)		6		(739	)
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 compared to $3.2 million for the three months ended September 30, 2018.~~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 ~~increase~~decrease for the three months ended September 30, ~~2019~~2020 was due to ~~an increase~~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.~~transactions or release to third parties.

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 compared to $11.3 million for the three months ended September 30, 2018.~~2019. The following table details our exploration-related expenses for the three months ended September 30, ~~2019~~2020 and ~~2018:~~2019:

	Three Months Ended September 30,							Three Months Ended September 30,
	2019		2018		Change			2020		2019		Change
Exploration expenses (in thousands):
Geological and geophysical	$	180	$	182	$	(2	)	$	11	$	180	$	(169	)
Delay rentals		2,327		4,082		(1,755	)		669		2,327		(1,658	)
Impairment of unproved properties		14,114		6,971		7,143			10,952		14,114		(3,162	)
Dry hole and other		—		93		(93	)		135		—		135
	$	16,621	$	11,328	$	5,293		$	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 compared to $4.1 million for the three months ended September 30, 2018.~~2019. The decrease in delay rental expense related to the reduction in future drilling activity and ~~concentrating~~concentration of lease renewals in our core acreage area during the three months ended September 30, ~~2019.~~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 compared to $7.0 million for the three months ended September 30, 2018.~~2019. The ~~increase~~decrease in impairment charges during the three months ended September 30, ~~2019~~2020 was the result of ~~an increase~~a decrease in expected ~~lease expirations due~~leases subject to ~~a reduction in planned future drilling activity.~~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 ~~primarily related~~due to ~~the reduction in development activity~~certain sales of oil and natural gas properties and other assets during the ~~three months ended September 30, 2019. There were no rig termination and standby expenses for the three months ended September 30, 2018.~~

~~(Gain) loss on sale of assets~~ ~~was ($0.7) million for the three months ended September 30, 2019 compared to less than $0.1 million for the three months ended September 30, 2018.~~relevant periods.

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, ~~compared to ($3.3) million for the three months ended September 30, 2018,~~ primarily due to changes in commodity prices and interest rates during each period. Cash receipts ~~(payments)~~ were approximately ~~$11.8~~$18.9 million and ~~($5.4)~~$11.8 million for derivative instruments that settled during the three months ended September 30, ~~2019~~2020 and ~~2018,~~2019, respectively.

Interest expense, net was ~~$15.2~~$14.4 million for the three months ended September 30, ~~2019~~2020 compared to ~~$13.9~~$15.2 million for three months ended September 30, ~~2018.~~2019. Interest expense ~~increased~~decreased primarily due to ~~our increased~~lower interest rates on borrowings under ~~our~~the revolving credit facility during the three months ended September 30, ~~2019.~~2020.

Income tax benefit (expense) was not recognized for the three months ended September 30, ~~2019~~2020 and ~~2018~~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, respectively.~~income.

Nine Months Ended September 30, ~~2019~~2020 Compared to Nine Months Ended September 30, ~~2018~~2019

The following table illustrates the revenue attributable to our operations for the nine months ended September 30, ~~2019~~2020 and ~~2018:~~2019:

	Nine Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Change			2020		2019		Change
Revenues (in thousands)
Natural gas sales	$	264,030	$	178,648	$	85,382		$	217,604	$	264,030	$	(46,426	)
NGL sales		60,841		63,520		(2,679	)		44,949		60,841		(15,892	)
Oil sales		103,407		98,452		4,955			52,918		103,407		(50,489	)
Brokered natural gas and marketing revenue		31,747		3,318		28,429			23,859		31,747		(7,888	)
Other revenue		307		—		307			183		307		(124	)
Total revenues	$	460,332	$	343,938	$	116,394		$	339,513	$	460,332	$	(120,819	)

Our production grew by approximately ~~54.6~~18.6 Bcfe for the nine months ended September 30, ~~2019~~2020 over the same period in ~~2018~~2019 due to ~~increased~~ drilling activity and from wells acquired as part of the BRMR Merger. Our production for the nine months ended September 30, ~~2019~~2020 and ~~2018~~2019 is set forth in the following table:

	Nine Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		Change		2020		2019		Change
Production:
Natural gas (MMcf)		109,613.9		63,308.4		46,305.5		131,353.1		109,613.9		21,739.2
NGLs (Mbbls)		3,414.9		2,492.6		922.3		3,342.7		3,414.9		(72.2	)
Oil (Mbbls)		2,083.3		1,629.4		453.9		1,635.1		2,083.3		(448.2	)
Total (MMcfe)		142,603.1		88,040.4		54,562.7		161,219.9		142,603.1		18,616.8

Average daily production volume:
Natural gas (Mcf/d)		401,516		231,899		169,617		479,391		401,516		77,875
NGLs (Bbls/d)		12,509		9,130		3,379		12,200		12,509		(309	)
Oil (Bbls/d)		7,631		5,968		1,663		5,968		7,631		(1,663	)
Total (Mcfe/d)		522,356		322,487		199,869		588,394		522,356		66,038

Our average realized price (including cash settled commodity derivatives and firm transportation) received during the nine months ended September 30, ~~2019~~2020 was ~~$2.72~~$1.97 per Mcfe compared to ~~$3.39~~$2.72 per Mcfe during the nine months ended September 30, ~~2018.~~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 ~~sales~~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.~~Operations and Comprehensive Income (Loss). Average ~~sales~~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, ~~2019~~2020 and ~~2018~~2019 are shown below:

	Nine Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Change			2020		2019		Change
Average realized price (excluding cash settled derivatives and firm transportation)
Average realized price (excluding cash settled commodity derivatives and firm transportation)
Natural gas ($/Mcf)	$	2.41	$	2.82	$	(0.41	)	$	1.66	$	2.41	$	(0.75	)
NGLs ($/Bbl)		17.82		25.48		(7.66	)		13.45		17.82		(4.37	)
Oil ($/Bbl)		49.64		60.42		(10.78	)		32.36		49.64		(17.28	)
Total average prices ($/Mcfe)		3.00		3.87		(0.87	)		1.96		3.00		(1.04	)

Average realized price (including cash settled derivatives, excluding firm transportation)
Average realized price (including cash settled commodity derivatives, excluding firm transportation)
Natural gas ($/Mcf)	$	2.49	$	2.92	$	(0.43	)	$	2.02	$	2.49	$	(0.47	)
NGLs ($/Bbl)		18.19		25.11		(6.92	)		13.70		18.19		(4.49	)
Oil ($/Bbl)		50.15		52.32		(2.17	)		40.32		50.15		(9.83	)
Total average prices ($/Mcfe)		3.08		3.78		(0.70	)		2.34		3.08		(0.74	)

Average realized price (including firm transportation, excluding cash settled derivatives)
Average realized price (including firm transportation, excluding cash settled commodity derivatives)
Natural gas ($/Mcf)	$	1.94	$	2.28	$	(0.34	)	$	1.20	$	1.94	$	(0.74	)
NGLs ($/Bbl)		17.82		25.48		(7.66	)		13.45		17.82		(4.37	)
Oil ($/Bbl)		49.64		60.42		(10.78	)		32.36		49.64		(17.28	)
Total average prices ($/Mcfe)		2.64		3.48		(0.84	)		1.59		2.64		(1.05	)

Average realized price (including cash settled derivatives and firm transportation)
Average realized price (including cash settled commodity derivatives and firm transportation)
Natural gas ($/Mcf)	$	2.02	$	2.38	$	(0.36	)	$	1.57	$	2.02	$	(0.45	)
NGLs ($/Bbl)		18.19		25.11		(6.92	)		13.70		18.19		(4.49	)
Oil ($/Bbl)		50.15		52.32		(2.17	)		40.32		50.15		(9.83	)
Total average prices ($/Mcfe)		2.72		3.39		(0.67	)		1.97		2.72		(0.75	)

Brokered natural gas and marketing revenue was ~~$31.7~~$23.9 million and ~~$3.3~~$31.7 million for the nine months ended September 30, ~~2019~~2020 and ~~2018,~~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 ~~increase~~decrease for the nine months ended September 30, ~~2019~~2020 was due to ~~an increase~~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.

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, ~~2019~~2020 and ~~2018:~~2019:

	Nine Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Change			2020		2019		Change
Operating expenses (in thousands)
Lease operating	$	29,651	$	22,026	$	7,625		$	33,436	$	29,651	$	3,785
Transportation, gathering and compression		150,065		98,126		51,939			157,472		150,065		7,407
Production and ad valorem taxes		8,519		7,226		1,293			10,146		8,519		1,627
Depreciation, depletion, amortization and accretion		113,950		98,672		15,278			140,058		113,950		26,108
General and administrative		57,074		33,391		23,683			33,594		57,074		(23,480	)
Operating expenses per Mcfe:
Lease operating	$	0.21	$	0.25	$	(0.04	)	$	0.21	$	0.21	$	—
Transportation, gathering and compression		1.04		1.11		(0.07	)		0.98		1.04		(0.06	)
Production and ad valorem taxes		0.06		0.08		(0.02	)		0.06		0.06		—
Depreciation, depletion, amortization and accretion		0.80		1.12		(0.32	)		0.87		0.80		0.07
General and administrative		0.40		0.38		0.02			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 compared to $22.0 million in the nine months ended September 30, 2018.~~2019. Lease operating expense per Mcfe was $0.21 in each of the nine months ended September 30, ~~2019 compared to $0.25 in the nine months ended September 30, 2018.~~2020 and 2019. The increase of ~~$7.6~~$3.8 million was primarily attributable to an increase in the number of producing ~~wells. The decrease of $0.04~~wells in the nine months ended September 30, 2020. Expenses on a per Mcfe ~~was primarily due to a decrease in non-recurring workovers and fixed costs spread across increased production~~basis were comparable for the nine months ended September 30, ~~2019~~2020 compared to the nine months ended September 30, ~~2018.~~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 compared to $98.1 million during the nine months ended September 30, 2018.~~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 compared to $1.11 in the nine months ended September 30, 2018.~~2019. The following table details our transportation, gathering and compression expenses for the nine months ended September 30, ~~2019~~2020 and ~~2018:~~2019:

	Nine Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Change			2020		2019		Change
Transportation, gathering and compression (in thousands):
Gathering, compression and fuel	$	48,014	$	30,075	$	17,939		$	49,255	$	48,014	$	1,241
Processing and fractionation		44,836		27,910		16,926			44,175		44,836		(661	)
Liquids transportation and stabilization		5,347		5,679		(332	)		4,582		5,347		(765	)
Marketing		103		15		88			—		103		(103	)
Firm transportation		51,765		34,447		17,318			59,460		51,765		7,695
	$	150,065	$	98,126	$	51,939		$	157,472	$	150,065	$	7,407
Transportation, gathering and compression per Mcfe:
Gathering, compression and fuel	$	0.33	$	0.34	$	(0.01	)	$	0.31	$	0.33	$	(0.02	)
Processing and fractionation		0.31		0.32		(0.01	)		0.27		0.31		(0.04	)
Liquids transportation and stabilization		0.04		0.06		(0.02	)		0.03		0.04		(0.01	)
Marketing		—		—		—			—		—		—
Firm transportation		0.36		0.39		(0.03	)		0.37		0.36		0.01
	$	1.04	$	1.11	$	(0.07	)	$	0.98	$	1.04	$	(0.06	)

The increase of ~~$51.9~~$7.4 million to transportation, gathering and compression expenses during the nine months ended September 30, ~~2019~~2020 was due to increased production and increased firm transportation ~~capacity.~~capacity during the nine months ended September 30, 2020. The decrease of ~~$0.07~~$0.06 per Mcfe during the nine months ended September 30, ~~2019~~2020 was primarily due to a higher percentage of production attributable to natural gas and ~~fixed firm transportation costs spread across increased production~~lower contractual rates during the ~~period.~~nine 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 $10.1 million in the nine months ended September 30, 2020 compared to $8.5 million in the nine months ended September 30, ~~2019 compared to $7.2 million in the nine months ended September 30, 2018.~~2019. Production and ad valorem taxes per Mcfe were $0.06 in each of the nine months ended September 30, ~~2019 compared to $0.08 in the nine months ended September 30, 2018.~~2020 and 2019. The increase of ~~$1.3~~$1.6 million ~~was primarily due to increased well count for the nine months ended September 30, 2019. The decrease of $0.02 per Mcfe~~ was primarily due to the recognition of a refund ~~for~~of production taxes from a state taxing authority during the nine months ended September 30, ~~2019.~~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 compared to $98.7 million~~2019. DD&A per Mcfe was $0.87 in the nine months ended September 30, ~~2018. DD&A per Mcfe was~~2020 compared to $0.80 in the nine months ended September 30, ~~2019 compared to $1.12 in the nine months ended September 30, 2018.~~2019. DD&A increased on an aggregate basis due to increased production and a higher depletion rate in the nine months ended September 30, ~~2019.~~2020. DD&A ~~decreased~~increased on a per Mcfe basis due to a ~~lower~~higher depletion rate resulting from reserves increasing at a ~~higher~~lower rate than capital costs for the nine months ended September 30, ~~2019.~~2020.

General and administrative expense was ~~$57.1~~$33.6 million for the nine months ended September 30, ~~2019~~2020 compared to ~~$33.4~~$57.1 million for the nine months ended September 30, 2018. General and administrative expense per Mcfe was $0.40 in the nine months ended September 30, 2019 compared to $0.38 in the nine months ended September 30, 2018. The increase of $23.7 million and $0.02 per Mcfe was primarily related to approximately $18.8 million of expenses related to the BRMR Merger incurred in the nine months ended September 30, 2019. General and administrative expense ~~included $7.6~~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 ~~$6.1~~$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 ~~2018, respectively.~~$21.8 million of merger-related 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, ~~2019~~2020 and ~~2018:~~2019:

	Nine Months Ended September 30,								Nine Months Ended September 30,
	2019			2018			Change		2020			2019			Change
Other operating expenses (in thousands):
Brokered natural gas and marketing expense	$	32,017		$	3,715		$	28,302	$	24,349		$	32,017		$	(7,668	)
Exploration		48,602			36,227			12,375		34,112			48,602			(14,490	)
Rig termination and standby		1,221			—			1,221		303			1,221			(918	)
Gain on sale of assets		(731	)		(1,814	)		1,083		(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 compared to $3.7 million for the nine months ended September 30, 2018.~~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 ~~increase~~decrease for the nine months ended September 30, ~~2019~~2020 was due to ~~an increase~~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.~~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 compared to $36.2 million for the nine months ended September 30, 2018.~~2019. The following table details our exploration-related expenses for the nine months ended September 30, ~~2019~~2020 and ~~2018:~~2019:

	Nine Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Change			2020		2019		Change
Exploration expenses (in thousands):
Geological and geophysical	$	643	$	1,015	$	(372	)	$	186	$	643	$	(457	)
Delay rentals		11,639		14,385		(2,746	)		3,472		11,639		(8,167	)
Impairment of unproved properties		36,157		20,638		15,519			30,311		36,157		(5,846	)
Dry hole and other		163		189		(26	)		143		163		(20	)
	$	48,602	$	36,227	$	12,375		$	34,112	$	48,602	$	(14,490	)

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 compared to $14.4 million for the nine months ended September 30, 2018.~~2019. The decrease in delay rental ~~expenses~~expense related to the reduction in future drilling activity and ~~concentrating~~concentration of lease renewals in our core acreage area during the nine months ended September 30, ~~2019.~~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 compared to $20.6 million for the nine months ended September 30, 2018.~~2019. The ~~increase~~decrease in impairment charges during the nine months ended September 30, ~~2019~~2020 was the result of ~~an increase~~a decrease in expected ~~lease expirations due~~leases subject to ~~a reduction in planned future drilling activity.~~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, ~~2019 primarily related~~2020 compared to ~~the reduction in development activity during the nine months ended September 30, 2019. There were no rig termination and standby expenses for the nine months ended September 30, 2018.~~

~~Gain on sale of assets~~ ~~was~~ $0.7 million for the nine months ended September 30, 2019 ~~compared~~due to ~~$1.8 million for the nine months ended September 30, 2018.~~certain sales of oil and natural gas properties and other assets during 2020.

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, ~~compared to ($24.1) million for the nine months ended September 30, 2018,~~ primarily due to changes in commodity prices and interest rates during each period. Cash receipts ~~(payments)~~ were approximately ~~$11.1~~$61.9 million and ~~($7.7)~~$11.1 million for derivative instruments that settled during the nine months ended September 30, ~~2019~~2020 and ~~2018,~~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 compared to $40.0 million for the nine months ended September 30, 2018.~~2019. The increase in interest expense primarily related to our increased borrowings under our revolving credit facility during the nine months ended September 30, ~~2019.~~2020.

Income tax benefit (expense) was not recognized for the nine months ended September 30, ~~2019~~2020 and ~~2018~~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 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, and issuances of debt and equity securities.~~facility. We sell a large portion of our production at the wellhead under floating ~~market~~price contracts.

Nine Months Ended September 30, ~~2019~~2020 Compared to ~~the~~ Nine Months Ended September 30, ~~2018~~2019

Net cash provided by operations in the nine months ended September 30, ~~2019~~2020 was ~~$176.3~~$72.8 million compared to ~~$93.4~~$176.3 million in the nine months ended September 30, ~~2018.~~2019. The ~~increase~~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, ~~2019~~2020 was ~~$254.7~~$120.9 million compared to ~~$201.2~~$254.7 million in the nine months ended September 30, ~~2018.~~2019.

Net cash provided by financing activities in the nine months ended September 30, ~~2019~~2020 was ~~$84.0~~$40.0 million compared to ~~$96.9~~$84.0 million in the nine months ended September 30, ~~2018.~~2019.

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 ~~2019.~~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, ~~2019,~~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 ~~interest coverage~~leverage ratios. This could negatively impact our ability to maintain sufficient liquidity and access to capital resources.

Long-term debt atas of September 30, ~~2019~~2020 and December 31, ~~2018,~~2019, excluding discount, totaled ~~$638.0~~$680.5 million and ~~$543.0~~$640.5 million, respectively. Information related to our credit arrangements is described in Note ~~10—~~8—Debt to our Condensed Consolidated Financial Statements and is incorporated herein by reference.

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. AsInformation regarding our outstanding derivative contracts as of September 30, ~~2019, we had entered into the following derivative contracts:~~

2020 is set forth in Note 6— ~~Natural Gas Derivatives:~~Derivative Instruments

Description

Volume
(MMBtu/d)

Production Period

Weighted Average
Price ($/MMBtu)

Natural Gas Swaps:

120,000

October 2019 – December 2019

$
2.80

50,000

January 2020 – December 2020

$
2.67

20,000

January 2020 – March 2020

$
2.80

50,000

January 2020 – June 2020

$
2.70

20,000

April 2020 – June 2020

$
2.75

30,000

July 2020 – December 2020

$
2.60

Natural Gas Collars:

Floor purchase price (put)

95,000

October 2019 – December 2019

$
2.60

Ceiling sold price (call)

95,000

October 2019 – December 2019

$
2.91

Floor purchase price (put)

50,000

January 2020 – December 2020

$
2.49

Ceiling sold price (call)

50,000

January 2020 – December 2020

$
2.88

Floor purchase price (put)

30,000

January 2020 – March 2020

$
2.65

Ceiling sold price (call)

30,000

January 2020 – March 2020

$
2.98

Floor purchase price (put)

15,000

April 2020 – June 2020

$
2.50

Ceiling sold price (call)

15,000

April 2020 – June 2020

$
2.80

Natural Gas Three-way Collars:

Floor purchase price (put)

77,500

October 2019 – December 2019

$
2.72

Floor sold price (put)

77,500

October 2019 – December 2019

$
2.30

Ceiling sold price (call)

77,500

October 2019 – December 2019

$
3.04

Floor purchase price (put)

30,000

January 2020 – December 2020

$
2.70

Floor sold price (put)

30,000

January 2020 – December 2020

$
2.40

Ceiling sold price (call)

30,000

January 2020 – December 2020

$
3.05

Floor purchase price (put)

30,000

January 2020 – March 2020

$
2.72

Floor sold price (put)

30,000

January 2020 – March 2020

$
2.25

Ceiling sold price (call)

30,000

January 2020 – March 2020

$
3.15

Floor purchase price (put)

20,000

January 2020 – June 2020

$
2.70

Floor sold price (put)

20,000

January 2020 – June 2020

$
2.25

Ceiling sold price (call)

20,000

January 2020 – June 2020

$
3.05

Floor purchase price (put)

30,000

October 2019 – June 2020

$
2.90

Floor sold price (put)

30,000

October 2019 – June 2020

$
2.50

Ceiling sold price (call)

30,000

October 2019 – June 2020

$
3.15

Natural Gas Call/Put Options:

Ceiling sold price (call)

40,000

October 2019 – December 2019

$
3.44

Floor sold price (put)

50,000

January 2020 – December 2020

$
2.30

Floor sold price (put)

50,000

January 2020 – June 2020

$
2.25

Swaption sold price (call)

50,000

January 2021 – December 2021

$
2.75

Swaption sold price (call)

50,000

January 2022 – December 2022

$
3.00

Basis Swaps:

Appalachia - Dominion

12,500

October 2019

$
(0.52
)
Appalachia - Dominion

12,500

April 2020 – October 2020

$
(0.52
)
Appalachia - Dominion

20,000

January 2020 – December 2020

$
(0.59
)
Appalachia - Dominion

20,000

October 2019 – March 2020

$
(0.39
)
Appalachia - Dominion

17,500

October 2019 – December 2019

$
(0.50
)

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., ~~EDF Energy,~~East West Bank, J Aron, KeyBank N.A., Morgan Stanley, ~~NextEra Energy, Inc.,~~ Royal Bank of Canada, and Wells Fargo. We believe all such institutions currently are an acceptable credit risk. As of September 30, ~~2019,~~2020, we did not have any past due receivables from such counterparties.

~~A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at September 30, 2019 as shown in the following table:~~

~~Subsequent to September 30, 2019, we entered into the following derivative instruments to mitigate our exposure to natural gas and oil prices:~~

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 ~~an initial~~a capital budget for ~~2019~~2020 of between approximately ~~$375~~$190 - ~~$400~~$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 ~~activities~~ and other capital ~~requirements.~~expenditures. In ~~July 2019,~~May 2020, the Company reduced its ~~planned drilling activity to one gross operating rig through the remainder of 2019 and in connection therewith reduced its 2019~~2020 capital budget by approximately ~~$30~~$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 ~~2019~~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.

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

As a result of the BRMR Merger, each share of common stock, par value $0.01 per share, of BRMR issued and outstanding immediately prior to the effective time of the BRMR Merger (the “Effective Time”), excluding certain Excluded Shares (as such term is defined in the Merger Agreement), was converted into the right to receive from the Company ~~0.29506~~ ~~of a validly issued, fully-paid, and nonassessable share of common stock, par value $0.01 per share, of the Company. The exchange ratio reflects an adjustment to account for the~~ ~~15-to-1~~ ~~reverse stock split~~ ~~(See Note 13—~~ ~~Net Income (Loss) Per Share~~). Former stockholders of BRMR received cash for any fractional shares of the Company’s common stock to which they might otherwise have been entitled as a result of the BRMR Merger. In addition, upon completion of the BRMR Merger, all shares of BRMR restricted stock and all BRMR restricted

~~stock units and performance interest awards were converted into the right to receive shares of common stock of the Company or cash, in each case as specified in the Merger Agreement.~~

In 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 ~~repurchases or exchanges,~~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.

As of September 30, ~~2019~~2020 and December 31, ~~2018,~~2019, our total debt, excluding debt discount and issuance costs, and capitalization were as follows (in millions):

	September 30, 2019		December 31, 2018		September 30, 2020		December 31, 2019
Senior unsecured notes	$	510.5	$	510.5	$	510.5	$	510.5
Revolving credit facility		127.5		32.5		170.0		130.0
Stockholders' equity		982.0		687.5
Stockholders’ equity						842.0		997.1
Total capitalization	$	1,620.0	$	1,230.5	$	1,522.5	$	1,637.6

Our contractual obligations include long-term debt, operating leases, drilling commitments, firm transportation, gas processing, gathering, and ~~compressions~~compression services, fractionation services, marketing agreements and asset retirement obligations. As of September 30, ~~2019~~2020 and December 31, ~~2018,~~2019, we did not have ~~any~~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 atas of September 30, ~~2019~~2020 reflects accrued interest payable of ~~$11.1~~$9.9 million, compared to ~~$21.7~~$21.3 million as of December 31, ~~2018.~~2019.

AsDuring the nine months ended September 30, 2020 we renegotiated certain existing gas gathering contracts into a ~~result of the BRMR Merger, we assumed commitments~~single new consolidated gas gathering contract. Information related to ~~certain firm transportation and gas processing, gathering and compression agreements entered into by Triad Hunter, LLC (“Triad Hunter”), a wholly owned subsidiary of BRMR (See~~our revised commitments is set forth in Note ~~15—~~12—Commitments and Contingencies~~). See~~ to our ~~Annual Report on Form 10-K for further discussion of our Midstream Agreements~~Condensed Consolidated Financial Statements and ~~Other Commitments.~~

~~Triad Hunter~~ is party to a gas processing agreement with MarkWest Liberty Midstream & Resources, L.L.C (“MarkWest”). The agreement provides for minimum volume commitments of 37,500 Mcf per day and expires in October 2023. Effective May 1, 2019, this agreement was amended to reflect an adjusted acreage dedication and reduced processing fee.

Triad Hunter is party to a gas transportation agreement with Equitrans, L.P. Under the gas transportation agreement, which expires on October 31, 2029, Triad Hunter’s maximum daily quantities are 50,000 MMBtu per day through December 31, 2024 and are reduced to 35,000 MMBtu per day effective as of January 1, 2025.

Triad Hunter is party to a gas gathering contract with Eureka Midstream, LLC (“Eureka Midstream”). The gas gathering contract provides for minimum volume commitments determined on a system-wide basis with volume banking, with annual commitments of 210,000 MMBtu per day for 2019 through 2033. In addition, the contract includes a minimum volume commitment of 50,000 Mcf per day for a compression facility.

In March 2019, Eclipse Resources I, L.P., a wholly owned subsidiary of the Company (“Eclipse I”), entered into a rich gas gathering agreement (firm service – three well pads) with Eureka Midstream, under which Eclipse I committed to the payment of monthly reservation fees for certain maximum daily quantities of gas delivered from three well pads in Monroe County, Ohio. The rich gas gathering agreement provides for minimum volume commitments with respect to production from the pads, with annual commitments as follows:

In June 2019, Eclipse I entered into an agreement with MarkWest for gas processing and fractionation. This gas processing agreement contains terms and conditions substantially similar to the legacy gas processing agreement between Triad Hunter and MarkWest. In June 2019, Triad Hunter and Eclipse I amended their gas processing agreements with MarkWest. The amendments were effective as of May 1, 2019 and provide for reduced processing and compression charges as well as firm capacity that increases during the term of the agreements from approximately 150 MMcf to 275 MMcf per day. These gas processing agreements include a dedication of Marcellus acreage and no minimum volume commitments. The agreements expire in October 2023.

~~Triad Hunter is party to certain transportation services agreements with Rockies Express Pipeline LLC (“REX”) for the delivery~~incorporated herein by Triad Hunter and the transportation by REX of natural gas produced by Triad Hunter. Under the agreements, Triad Hunter committed to purchase 50,000 MMBtu per day of firm transportation through 2031. In January 2018, Triad Hunter committed to purchase an additional 50,000 MMBtu per day of firm transportation capacity for the period October 1, 2018 through September 30, 2023. In April 2019, REX and Triad Hunter agreed to extend the term of the additional 50,000 MMBtu per day of capacity through September 30, 2027.

In connection with its transportation services agreements with REX, Triad Hunter is required to provide credit support, which as of March 31, 2019 consisted of a letter of credit of $20 million and a cash prepayment to REX of $1.4 million. Triad Hunter was also party to an Asset Management Agreement with BP Energy Company pursuant to which BP Energy Company agreed to provide the $20 million letter of credit to REX on behalf of Triad Hunter. In April 2019, per the terms of the additional 50,000 MMBtu per day of capacity extension, REX and Triad Hunter agreed to reduce the currently held letter of credit to $14.4 million from the previously held $20 million. The $20 million letter of credit posted by BP Energy Company expired on April 28, 2019, and the Company issued the reduced $14.4 million letter of credit under its revolving credit facility (See Note 10—~~Debt). Triad Hunter still maintains a $1.4 million cash prepayment with REX.~~ reference.

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.

AtAs of September 30, ~~2019~~2020 and December 31, ~~2018,~~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.

AtAs of September 30, ~~2019,~~2020, we had outstanding borrowings of ~~$127.5~~$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 ~~$32.5~~$130.0 million under our revolving credit facility as of December 31, ~~2018.~~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 ~~10—~~8—Debt to our Condensed Consolidated Financial Statements and is incorporated herein by reference.

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.”

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 ~~2019~~

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. ~~In the near term, the~~The majority of our service costs ~~are~~is expected to remain flat in ~~2019~~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.

“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; ~~amortization of deferred financing costs;~~ 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:

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) ~~from operations~~ to Adjusted EBITDAX for the periods presented:

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
$ thousands	2019			2018				2019		2018			2020			2019				2020		2019
Net income (loss)	$	4,284		$	3,998		$	17,698		$	(17,662	)	$	(92,200	)	$	4,284		$	(158,227	)	$	17,698
Depreciation, depletion, amortization and accretion		45,456			34,439			113,950			98,672			53,153			45,456			140,058			113,950
Exploration expense		16,621			11,328			48,602			36,227			11,767			16,621			34,112			48,602
Rig termination and standby		1,221			—			1,221			—			303			1,221			303			1,221
Stock-based compensation		1,061			2,171			7,614			6,131			961			1,061			3,585			7,614
(Gain) loss on sale of assets		(733	)		6			(731	)		(1,814	)
Gain on sale of assets														(62	)		(733	)		(1,419	)		(731	)
(Gain) loss on derivative instruments		(15,812	)		3,263			(40,620	)		24,055			40,535			(15,812	)		11,329			(40,620	)
Net cash receipts (payments) on settled derivatives		11,818			(5,377	)		11,072			(7,724	)
Net cash receipts on settled commodity derivatives														18,806			11,818			61,829			11,072
Interest expense, net		15,192			13,932			44,140			39,975			14,402			15,192			44,166			44,140
Other income (expense)		—			1			(8	)		1
Other income														(2	)		—			(19	)		(8	)
Merger-related expenses		3,291			2,993			21,812			2,993			2,520			3,291			2,696			21,812
Income (loss) from discontinued operations		1,237			—			(1,286	)		—
(Income) loss from discontinued operations⁽¹⁾														801			1,237			10,092			(1,286	)
Severance														—			—			2,681			—
Adjusted EBITDAX	$	83,636		$	66,754		$	223,464		$	180,854		$	50,984		$	83,636		$	151,186		$	223,464

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.

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, ~~2018~~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.

~~The primary objective of the following information is~~Not applicable to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated.

We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Natural gas and oil prices have been volatile and unpredictable for many years. Natural gas prices affect us more than oil prices because approximately 82% of our December 31, 2018 proved reserves were natural gas.

~~For a discussion of how we use financial commodity derivative contracts to mitigate some of the potential negative impact on our cash flow caused by changes in natural gas prices (See Note 8—Derivative Instruments~~).

~~Information related to our interest rates is described in Note 10—Debt~~ ~~to our Consolidated Financial Statements and is incorporated herein by reference.~~

Our principal exposures to credit risk are through receivables resulting from commodity derivatives contracts, the sale of our oil and gas production which we market to energy companies, end users and refineries, and joint interest receivables.

By using derivative instruments that are not traded on an exchange 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. These counterparties are not required to provide credit support to us. As of September 30, 2019, we had economic hedges in place with 11 counterparties. The fair value of our commodity derivative contracts of approximately $28.1 million at September 30, 2019 includes the following values by counterparty: Bank of Montreal $6.3 million; BP Energy Company $2.6 million; Capital One N.A. $6.7 million; Citibank $0.6 million; EDF Energy $1.6 million; J Aron $7.8 million; KeyBank N.A. $1.7 million; Morgan Stanley ($1.1) million; NextEra Energy, Inc. $0.5 million; Royal Bank of Canada $1.0 million; and Wells Fargo $0.4 million. The estimated fair value of our commodity derivative assets has been risk adjusted using a discount rate based upon the respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) at September 30, 2019 for each of the counterparties. We believe that all of these institutions currently are acceptable credit risks. Other than as provided by our revolving credit facility, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts. As of September 30, 2019, we did not have past-due receivables from, or payables to, any of our counterparties under our derivative contracts.

We are also subject to credit risk due to concentration of our receivables from several significant customers for sales of natural gas. We generally do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

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 drill. We can do very little to choose who participates in our wells.smaller reporting companies.

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) ofunder 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.

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.

Information regarding the Company’s legal proceedings is set forth in Note ~~15—~~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.

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 ~~15, 2019,~~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.

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:

~~The following table sets forth our share purchase activity for each period presented:~~

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,

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.

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:

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

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.

~~See the list of exhibits below in the index to exhibits to this Quarterly Report on Form 10-Q, which is incorporated herein by reference.~~

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.

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)

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

		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	5349
Item 4.	Controls and Procedures	5449

PART II - Other Information		5550
Item 1.	Legal Proceedings	5550
Item 1A.	Risk Factors	55
~~Item 2.~~	~~Unregistered Sales of Equity Securities and Use of Proceeds~~	5550
Item 6.	Exhibits	5655

~~Index to Exhibits~~		56
Signatures		5857

	For the Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	3,851
Investing cash flows for operating leases	$	8,394
ROU assets added in exchange for lease obligations (upon adoption)	$	10,434
ROU assets and lease obligations acquired in BRMR Merger	$	7,900
ROU assets added in exchange for lease obligations, net of terminations (since adoption)	$	34,331

	Operating Leases
Remainder of 2019	$	3,653
2020		15,034
2021		13,616
2022		6,158
2023		4,259
Thereafter		5,424
Total lease payments	$	48,144
Less imputed interest		(5,070	)
Total lease liability	$	43,074

(in thousands)	Hypothetical 10% Increase in Future Prices			Hypothetical 10% Decrease in Future Prices
Natural Gas	$	(19,300	)	$	16,607
NGLs		(62	)		62
Oil		(7,094	)		7,061

~~Term~~	~~Natural Gas~~ ~~(Mcf/d)~~
~~July 2019 – June 2020~~		~~41,000~~
~~July 2020 – June 2021~~		~~40,000~~
~~July 2021 – June 2022~~		~~23,000~~
~~July 2022 – June 2023~~		~~16,500~~
~~July 2023 – June 2024~~		~~12,500~~
~~July 2024 – June 2025~~		~~10,400~~
~~July 2025 – June 2026~~		~~8,500~~
~~July 2026 – June 2027~~		~~7,250~~
~~July 2027 – June 2028~~		~~6,000~~
~~July 2028 – June 2029~~		~~5,250~~
~~July 2029 – June 2030~~		~~4,250~~
~~July 2030 – June 2031~~		~~3,500~~
~~July 2031 – June 2032~~		~~3,000~~
~~July 2032 – June 2033~~		~~2,500~~
~~July 2033 – June 2034~~		~~2,000~~

Period	Total Number of Shares Purchased (a)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans		Maximum Number of Shares that May Yet be Purchased Under the Plan
July 1, 2019 - July 31, 2019		—	$	—		—	N/A
August 1, 2019 - August 31, 2019		3,252	$	2.81		—	N/A
September 1, 2019 - September 30, 2019		—	$	—		—	N/A

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*10.1		~~First Amendment to Third Amended and Restated Credit~~Letter Agreement, dated as of September ~~19, 2019,~~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.


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).

November ~~8, 2019~~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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company