UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended ~~September~~June 30, ~~2020~~2021

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

For the transition period from ___________ to ___________

Commission File Number 001-31539

SM ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Delaware

41-0518430

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 1200, Denver, Colorado

80203

(Address of principal executive offices)

(Zip Code)

(303) 861-8140

(Registrant’s telephone number, including area code)

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


Title of each class	Trading symbol(s)	Name of each exchange on which registered
Common stock, $0.01 par value	SM	New York Stock Exchange

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

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

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

Large accelerated filer

☑☐

Accelerated filer

☐☑

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

As of ~~October~~July 21, ~~2020,~~2021, the registrant had ~~114,572,800~~121,220,862 shares of common stock outstanding.

TABLE OF CONTENTS


Item		Page
	Cautionary Information about Forward-Looking Statements	3

	Part I	4

Item 1.	Financial Statements (unaudited)	4

	Condensed Consolidated Balance Sheets ~~September~~June 30, ~~2020,~~2021, and December 31, ~~2019~~2020	4

	Condensed Consolidated Statements of Operations Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020,~~2021, and ~~2019~~2020	5

	Condensed Consolidated Statements of Comprehensive ~~Income (Loss)~~Loss Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020,~~2021, and ~~2019~~2020	6

	Condensed Consolidated Statements of Stockholders’ Equity Continuous Quarterly Presentation Ended ~~September~~June 30, ~~2020,~~2021, and ~~2019~~2020	7

	Condensed Consolidated Statements of Cash Flows ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020,~~2021, and ~~2019~~2020	98

	Notes to Condensed Consolidated Financial Statements	109

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2923

Item 3.	Quantitative and Qualitative Disclosures About Market Risk ~~(included within the content of Item 2)~~	4540

Item 4.	Controls and Procedures	4540

	Part II	4641

Item 1.	Legal Proceedings	4641

Item 1A.	Risk Factors	4641

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49

~~Item 5.~~	~~Other Information~~	4941

Item 6.	Exhibits	5142

	Signatures	43

Cautionary Information about Forward-Looking Statements

This Report on Form 10-Q (“Form 10-Q” or “this 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 included in this report, other than statements of historical facts, that address activities, conditions, events, or developments with respect to our financial condition, results of operations, business prospects or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “could,” “estimate,” “expect,” “forecast,” “intend,” “pending,” “plan,” “potential,” “project,” “target,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this report, and include statements about such matters as:

•the impacts of ~~macroeconomic events and~~ the global COVID-19 pandemic (“Pandemic”) on us, our industry, our financial condition, and our results of ~~operations, future operations, business prospects, capital and financial resources, ability to service our debt, ability to access the capital markets, and our plans to address the foregoing;~~operations;

•the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;

•~~our expected total production volumes for the fiscal year 2020;~~

•any changes to the borrowing base or aggregate lender commitments under our Sixth Amended and Restated Credit Agreement, as amended (“Credit Agreement”);

•our outlook on future crude oil, natural gas, and natural gas liquids (also ~~respectively~~ referred to throughout this report as “oil,” “gas,” and ~~“NGLs” throughout this report)~~“NGLs,” respectively) prices, well costs, service costs, ~~lease operating~~production costs, and general and administrative costs;

•our drilling ~~of wells~~and completion activities and other exploration and development activities, our ability to obtain permits and governmental approvals, and plans by us, our joint development partners, and/or other third-party operators;

•possible or expected acquisitions and divestitures, including the possible divestiture or ~~farm-down~~farmout of, or joint development of, certain properties;

•oil, gas, and NGL reserve estimates and estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates;

•our expected future ~~oil, gas, and NGL~~ production ~~estimates,~~volumes, identified drilling locations, as well as drilling prospects, inventories, projects and programs;

•cash flows, liquidity, interest and related debt service expenses, changes in our effective tax rate, and our ability to repay debt in the future;

•business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, plans with respect to future dividend payments, and our outlook on our future financial condition or results of operations; and

•other similar matters, such as those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part I, Item 2 of this report.

Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Factors that may cause our financial condition, results of operations, business prospects or economic performance to differ from expectations include the factors discussed in the Risk Factors section in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, ~~2019~~2020 (“~~2019~~2020 Form 10-K”)~~, in Part II, Item 1A of our Quarterly Reports on Form 10-Q for the quarterly periods ended~~ ~~March 31, 2020~~ ~~and~~ ~~June 30, 2020, our 2020 Proxy Statement, and the~~ ~~Risk Factors~~ ~~section in Part II, Item 1A of this report.~~.

We caution you that forward-looking statements are not guarantees of future performance and actual results or performance may be materially different from those expressed or implied in forward-looking statements. The forward-looking statements in this report speak only as of the filing of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by applicable securities laws.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(in thousands, except share data)


		September 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	10	$	10	Cash and cash equivalents	$	0	$	10
Accounts receivable	Accounts receivable	136,613		184,732		Accounts receivable	229,512		162,455
Derivative assets	Derivative assets	128,046		55,184		Derivative assets	31,303		31,203
Prepaid expenses and other	Prepaid expenses and other	10,221		12,708		Prepaid expenses and other	8,595		10,001
Total current assets	Total current assets	274,890		252,634		Total current assets	269,410		203,669
Property and equipment (successful efforts method):	Property and equipment (successful efforts method):					Property and equipment (successful efforts method):
Proved oil and gas properties	Proved oil and gas properties	8,307,165		8,934,020		Proved oil and gas properties	9,107,281		8,608,522
Accumulated depletion, depreciation, and amortization	Accumulated depletion, depreciation, and amortization	(4,713,442)		(4,177,876)		Accumulated depletion, depreciation, and amortization	(5,244,367)		(4,886,973)
Unproved oil and gas properties	Unproved oil and gas properties	907,864		1,005,887		Unproved oil and gas properties	656,848		714,602
Wells in progress	Wells in progress	226,452		118,769		Wells in progress	153,734		233,498

Other property and equipment, net of accumulated depreciation of $66,025 and $64,032, respectively		37,062		72,848
Other property and equipment, net of accumulated depreciation of $75,328 and $63,662, respectively						Other property and equipment, net of accumulated depreciation of $75,328 and $63,662, respectively	41,313		32,217
Total property and equipment, net	Total property and equipment, net	4,765,101		5,953,648		Total property and equipment, net	4,714,809		4,701,866
Noncurrent assets:	Noncurrent assets:					Noncurrent assets:
Derivative assets	Derivative assets	31,509		20,624		Derivative assets	13,534		23,150
Other noncurrent assets	Other noncurrent assets	50,785		65,326		Other noncurrent assets	55,245		47,746
Total noncurrent assets	Total noncurrent assets	82,294		85,950		Total noncurrent assets	68,779		70,896
Total assets	Total assets	$	5,122,285	$	6,292,232	Total assets	$	5,052,998	$	4,976,431
LIABILITIES AND STOCKHOLDERS' EQUITY
LIABILITIES AND STOCKHOLDERS’ EQUITY						LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable and accrued expenses	Accounts payable and accrued expenses	$	287,777	$	402,008	Accounts payable and accrued expenses	$	496,285	$	371,670

Derivative liabilities	Derivative liabilities	76,969		50,846		Derivative liabilities	545,062		200,189
Other current liabilities	Other current liabilities	12,532		19,189		Other current liabilities	10,321		11,880
Total current liabilities	Total current liabilities	377,278		472,043		Total current liabilities	1,051,668		583,739
Noncurrent liabilities:	Noncurrent liabilities:					Noncurrent liabilities:
Revolving credit facility	Revolving credit facility	178,000		122,500		Revolving credit facility	52,500		93,000
Senior Notes, net	Senior Notes, net	2,175,038		2,610,298		Senior Notes, net	2,139,625		2,121,319

Asset retirement obligations	Asset retirement obligations	87,014		84,134��		Asset retirement obligations	85,390		83,325

Deferred income taxes		34,582		189,386

Derivative liabilities	Derivative liabilities	33,068		3,444		Derivative liabilities	116,273		22,331
Other noncurrent liabilities	Other noncurrent liabilities	52,197		61,433		Other noncurrent liabilities	55,033		56,557
Total noncurrent liabilities	Total noncurrent liabilities	2,559,899		3,071,195		Total noncurrent liabilities	2,448,821		2,376,532

Commitments and contingencies (note 6)	Commitments and contingencies (note 6)					Commitments and contingencies (note 6)	0		0

Stockholders’ equity:	Stockholders’ equity:					Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 114,572,800 and 112,987,952 shares, respectively		1,146		1,130
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 120,970,853 and 114,742,304 shares, respectively						Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 120,970,853 and 114,742,304 shares, respectively	1,210		1,147
Additional paid-in capital	Additional paid-in capital	1,827,836		1,791,596		Additional paid-in capital	1,838,859		1,827,914
Retained earnings		365,872		967,587
Retained earnings (deficit)						Retained earnings (deficit)	(274,745)		200,697
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(9,746)		(11,319)		Accumulated other comprehensive loss	(12,815)		(13,598)
Total stockholders’ equity	Total stockholders’ equity	2,185,108		2,748,994		Total stockholders’ equity	1,552,509		2,016,160
Total liabilities and stockholders’ equity	Total liabilities and stockholders’ equity	$	5,122,285	$	6,292,232	Total liabilities and stockholders’ equity	$	5,052,998	$	4,976,431

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(in thousands, except per share data)


		For the Three Months Ended September 30,				For the Nine Months Ended September 30,					For the Three Months Ended June 30,				For the Six Months Ended June 30,
		2020		2019		2020		2019			2021		2020		2021		2020
Operating revenues and other income:	Operating revenues and other income:									Operating revenues and other income:
Oil, gas, and NGL production revenue	Oil, gas, and NGL production revenue	$	282,012	$	389,419	$	806,035	$	1,136,749	Oil, gas, and NGL production revenue	$	562,569	$	169,790	$	985,734	$	524,023
Net gain on divestiture activity		0		0		91		323
Other operating revenues		(997)		898		255		1,347

Other operating income (loss)										Other operating income (loss)	1,280		(158)		21,961		1,343
Total operating revenues and other income	Total operating revenues and other income	281,015		390,317		806,381		1,138,419		Total operating revenues and other income	563,849		169,632		1,007,695		525,366
Operating expenses:	Operating expenses:									Operating expenses:
Oil, gas, and NGL production expense	Oil, gas, and NGL production expense	95,257		129,042		295,254		373,397		Oil, gas, and NGL production expense	125,456		80,445		226,386		199,997
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	Depletion, depreciation, amortization, and asset retirement obligation liability accretion	181,708		211,125		596,053		595,201		Depletion, depreciation, amortization, and asset retirement obligation liability accretion	204,714		180,856		371,674		414,345
Exploration	Exploration	8,547		11,626		29,683		33,851		Exploration	8,714		9,787		18,037		21,136

Impairment	Impairment	8,750		6,337		1,007,263		25,092		Impairment	8,750		8,750		17,500		998,513
General and administrative	General and administrative	24,452		32,578		79,126		95,584		General and administrative	24,639		27,227		49,353		54,674
Net derivative (gain) loss	Net derivative (gain) loss	63,871		(100,889)		(314,269)		(3,463)		Net derivative (gain) loss	370,348		167,200		715,037		(378,140)
Other operating expense, net	Other operating expense, net	1,562		1,021		10,174		422		Other operating expense, net	1,852		8,046		1,253		8,612
Total operating expenses	Total operating expenses	384,147		290,840		1,703,284		1,120,084		Total operating expenses	744,473		482,311		1,399,240		1,319,137
Income (loss) from operations		(103,132)		99,477		(896,903)		18,335
Loss from operations										Loss from operations	(180,624)		(312,679)		(391,545)		(793,771)
Interest expense	Interest expense	(41,519)		(40,584)		(123,385)		(118,191)		Interest expense	(39,536)		(40,354)		(79,407)		(81,866)
Gain on extinguishment of debt		25,070		0		264,546		0
Gain (loss) on extinguishment of debt										Gain (loss) on extinguishment of debt	(2,144)		227,281		(2,144)		239,476
Other non-operating expense, net	Other non-operating expense, net	(1,680)		(548)		(2,359)		(1,427)		Other non-operating expense, net	(853)		(185)		(1,224)		(679)
Income (loss) before income taxes		(121,261)		58,345		(758,101)		(101,283)
Income tax (expense) benefit		22,969		(16,111)		158,662		16,337
Net income (loss)		$	(98,292)	$	42,234	$	(599,439)	$	(84,946)
Loss before income taxes										Loss before income taxes	(223,157)		(125,937)		(474,320)		(636,840)
Income tax benefit										Income tax benefit	162		36,685		56		135,693
Net loss										Net loss	$	(222,995)	$	(89,252)	$	(474,264)	$	(501,147)

Basic weighted-average common shares outstanding	Basic weighted-average common shares outstanding	114,371		112,804		113,462		112,441		Basic weighted-average common shares outstanding	118,357		113,008		116,568		113,015
Diluted weighted-average common shares outstanding	Diluted weighted-average common shares outstanding	114,371		113,334		113,462		112,441		Diluted weighted-average common shares outstanding	118,357		113,008		116,568		113,015
Basic net income (loss) per common share		$	(0.86)	$	0.37	$	(5.28)	$	(0.76)
Diluted net income (loss) per common share		$	(0.86)	$	0.37	$	(5.28)	$	(0.76)
Basic net loss per common share										Basic net loss per common share	$	(1.88)	$	(0.79)	$	(4.07)	$	(4.43)
Diluted net loss per common share										Diluted net loss per common share	$	(1.88)	$	(0.79)	$	(4.07)	$	(4.43)
Dividends per common share	Dividends per common share	$	0.01	$	0.05	$	0.02	$	0.10	Dividends per common share	$	0	$	0	$	0.01	$	0.01

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE ~~INCOME (LOSS)~~LOSS (UNAUDITED)

(in thousands)


		For the Three Months Ended September 30,				For the Nine Months Ended September 30,					For the Three Months Ended June 30,				For the Six Months Ended June 30,
		2020		2019		2020		2019			2021		2020		2021		2020
Net income (loss)		$	(98,292)	$	42,234	$	(599,439)	$	(84,946)
Net loss										Net loss	$	(222,995)	$	(89,252)	$	(474,264)	$	(501,147)
Other comprehensive income, net of tax:	Other comprehensive income, net of tax:									Other comprehensive income, net of tax:
Pension liability adjustment	Pension liability adjustment	1,195		190		1,573		572		Pension liability adjustment	592		188		783		378
Total other comprehensive income, net of tax	Total other comprehensive income, net of tax	1,195		190		1,573		572		Total other comprehensive income, net of tax	592		188		783		378
Total comprehensive income (loss)		$	(97,097)	$	42,424	$	(597,866)	$	(84,374)
Total comprehensive loss										Total comprehensive loss	$	(222,403)	$	(89,064)	$	(473,481)	$	(500,769)

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (UNAUDITED)

(in thousands, except share data and dividends per share)


					Additional Paid-in Capital								Accumulated Other Comprehensive Loss			Total Stockholders’ Equity												Additional Paid-in Capital						Accumulated Other Comprehensive Loss				Total Stockholders’ Equity
		Common Stock					Retained Earnings								Common Stock											Retained Earnings (Deficit)
		Shares	Amount					Accumulated Other Comprehensive Loss				Shares							Amount											Accumulated Other Comprehensive Loss
Balances, December 31, 2019		112,987,952	$	1,130						$	1,791,596				$				967,587			$	(11,319)	$	2,748,994
Balances, December 31, 2020																Balances, December 31, 2020		114,742,304				$	1,147			$	1,827,914				$	200,697		$	(13,598)	$	2,016,160
Net loss	Net loss	—	—				—						(411,895)			—					(411,895)		Net loss	—				—					—			(251,269)				—	(251,269)
Other comprehensive income	Other comprehensive income	—	—		—			—					190			190			Other comprehensive income	—				—				—			—			191				191
Cash dividends declared, $0.01 per share	Cash dividends declared, $0.01 per share	—	—		—			(1,130)					—			(1,130)			Cash dividends declared, $0.01 per share	—				—				—			(1,147)			—				(1,147)

Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings		730	0		(3)			—					—			(3)

Stock-based compensation expense	Stock-based compensation expense	—	—		5,561			—					—			5,561			Stock-based compensation expense	—				—				5,737			—			—				5,737

Balances, March 31, 2020		112,988,682	$	1,130	$	1,797,154		$	554,562				$	(11,129)		$	2,341,717
Balances, March 31, 2021																			Balances, March 31, 2021	114,742,304				$	1,147			$	1,833,651		$	(51,719)		$	(13,407)			$	1,769,672
Net loss	Net loss	—	—		—			(89,252)					—			(89,252)			Net loss	—				—				—			(222,995)			—				(222,995)
Other comprehensive income	Other comprehensive income	—	—		—			—					188			188			Other comprehensive income	—				—				—			—			592				592

Cash dividends, $0.01 per share																			Cash dividends, $0.01 per share	—				—				—			(31)			—				(31)
Issuance of common stock under Employee Stock Purchase Plan	Issuance of common stock under Employee Stock Purchase Plan	297,013	3		944			—					—			947			Issuance of common stock under Employee Stock Purchase Plan	252,665				3				1,312			—			—				1,315

Stock-based compensation expense	Stock-based compensation expense	267,576	3		5,709			—					—			5,712			Stock-based compensation expense	57,795				1				3,955			—			—				3,956
Issuance of warrants		—	—		21,520			—					—			21,520
Issuance of common stock through cashless exercise of Warrants																			Issuance of common stock through cashless exercise of Warrants	5,918,089				59				(59)			—			—				0

Balances, June 30, 2021																			Balances, June 30, 2021	120,970,853				$	1,210			$	1,838,859		$	(274,745)		$	(12,815)			$	1,552,509

Balances, June 30, 2020		113,553,271	$	1,136	$	1,825,327		$	465,310				$	(10,941)		$	2,280,832
Net loss		—	—		—			(98,292)					—			(98,292)
Other comprehensive income		—	—		—			—					1,195			1,195
Cash dividends declared, $0.01 per share		—	—		—			(1,146)					—			(1,146)

Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings		1,019,529	10		(1,567)			—					—			(1,557)
Stock-based compensation expense		—	—		4,164			—					—			4,164
Other		—	—		(88)			—					—			(88)

Balances, September 30, 2020		114,572,800	$	1,146	$	1,827,836		$	365,872				$	(9,746)		$	2,185,108


				Additional Paid-in Capital				Accumulated Other Comprehensive Loss		Total Stockholders’ Equity
	Common Stock					Retained Earnings
	Shares	Amount
Balances, December 31, 2019	112,987,952	$	1,130	$	1,791,596	$	967,587	$	(11,319)	$	2,748,994
Net loss	—	—		—		(411,895)		—		(411,895)
Other comprehensive income	—	—		—		—		190		190
Cash dividends declared, $0.01 per share	—	—		—		(1,130)		—		(1,130)

Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings	730	0		(3)		—		—		(3)
Stock-based compensation expense	—	—		5,561		—		—		5,561


Balances, March 31, 2020	112,988,682	$	1,130	$	1,797,154	$	554,562	$	(11,129)	$	2,341,717
Net loss	—	—		—		(89,252)		—		(89,252)
Other comprehensive income	—	—		—		—		188		188

Issuance of common stock under Employee Stock Purchase Plan	297,013	3		944		—		—		947

Stock-based compensation expense	267,576	3		5,709		—		—		5,712

Issuance of Warrants	—	—		21,520		—		—		21,520

Balances, June 30, 2020	113,553,271	$	1,136	$	1,825,327	$	465,310	$	(10,941)	$	2,280,832

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF ~~STOCKHOLDERS’ EQUITY~~CASH FLOWS (UNAUDITED) ~~(Continued)~~

(in ~~thousands, except share data~~thousands)


	For the Six Months Ended June 30,
	2021		2020
Cash flows from operating activities:
Net loss	$	(474,264)	$	(501,147)
Adjustments to reconcile net loss to net cash provided by operating activities:

Depletion, depreciation, amortization, and asset retirement obligation liability accretion	371,674		414,345
Impairment	17,500		998,513
Stock-based compensation expense	9,693		11,273
Net derivative (gain) loss	715,037		(378,140)
Derivative settlement gain (loss)	(266,707)		215,965
Amortization of debt discount and deferred financing costs	9,445		8,578
(Gain) loss on extinguishment of debt	2,144		(239,476)
Deferred income taxes	(214)		(136,268)
Other, net	(13,377)		(3,918)
Net change in working capital	31,092		(57,254)





Net cash provided by operating activities	402,023		332,471

Cash flows from investing activities:

Capital expenditures	(370,177)		(310,209)
Other, net	221		92
Net cash used in investing activities	(369,956)		(310,117)

Cash flows from financing activities:
Proceeds from revolving credit facility	944,000		841,000
Repayment of revolving credit facility	(984,500)		(770,500)
Net proceeds from Senior Notes	393,583		0
Cash paid to repurchase Senior Notes	(385,296)		(81,826)
Debt issuance costs related to 10.0% Senior Secured Notes due 2025	0		(10,491)
Net proceeds from sale of common stock	1,315		947
Dividends paid	(1,178)		(1,130)
Other	(1)		(354)
Net cash used in financing activities	(32,077)		(22,354)

Net change in cash, cash equivalents, and restricted cash	(10)		0
Cash, cash equivalents, and restricted cash at beginning of period	10		10
Cash, cash equivalents, and restricted cash at end of period	$	0	$	10

Supplemental schedule of additional cash flow information and non-cash activities:
Operating activities:
Cash paid for interest, net of capitalized interest	$	(74,864)	$	(82,313)

Investing activities:
Increase (decrease) in capital expenditure accruals and other	$	28,987	$	(28,896)
Non-cash financing activities (1)	0		0

____________________________________________

(1) Please refer to Note 5 - Long-Term Debt for discussion of the debt transactions executed during the six months ended June 30, 2021, and ~~dividends per share)~~

Additional Paid-in Capital Accumulated Other Comprehensive Loss Total Stockholders’ Equity
Common Stock Retained Earnings
Shares Amount
Balances, December 31, 2018 112,241,966 $ 1,122 $ 1,765,738 $ 1,165,842 $ (12,380) $ 2,920,322
Net loss — — — (177,568) — (177,568)
Other comprehensive income — — — — 263 263
Cash dividends declared, $0.05 per share — — — (5,612) — (5,612)
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings 2,579 0 (18) — — (18)
Stock-based compensation expense — — 5,838 — — 5,838
Balances, March 31, 2019 112,244,545 $ 1,122 $ 1,771,558 $ 982,662 $ (12,117) $ 2,743,225
Net income — — — 50,388 — 50,388
Other comprehensive income — — — — 119 119
Issuance of common stock under Employee Stock Purchase Plan 184,079 2 1,957 — — 1,959
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings 290 0 (2) — — (2)
Stock-based compensation expense 96,719 1 6,153 — — 6,154
Other — — (1) 1 — 0
Balances, June 30, 2019 112,525,633 $ 1,125 $ 1,779,665 $ 1,033,051 $ (11,998) $ 2,801,843
Net income — — — 42,234 — 42,234
Other comprehensive income — — — — 190 190
Cash dividends declared, $0.05 per share — — — (5,643) — (5,643)
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings 331,530 4 (1,644) — — (1,640)
Stock-based compensation expense — — 6,766 — — 6,766
Balances, September 30, 2019 112,857,163 $ 1,129 $ 1,784,787 $ 1,069,642 $ (11,808) $ 2,843,750
2020.

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

SM ENERGY COMPANY AND SUBSIDIARIES

~~CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)~~

~~(in thousands)~~

For the Nine Months Ended September 30,
2020 2019
Cash flows from operating activities:
Net loss $ (599,439) $ (84,946)
Adjustments to reconcile net loss to net cash provided by operating activities:
Net gain on divestiture activity (91) (323)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion 596,053 595,201
Impairment 1,007,263 25,092
Stock-based compensation expense 15,437 18,758
Net derivative gain (314,269) (3,463)
Derivative settlement gain 286,270 23,843
Amortization of debt discount and deferred financing costs 13,084 11,554
Gain on extinguishment of debt (264,546) 0
Deferred income taxes (159,064) (13,620)
Other, net (6,203) (2,291)
Net change in working capital (40,411) 11,781
Net cash provided by operating activities 534,084 581,586
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties (1)
92 12,520
Capital expenditures (419,777) (788,642)
Acquisition of proved and unproved oil and gas properties (7,075) (2,581)
Net cash used in investing activities (426,760) (778,703)
Cash flows from financing activities:
Proceeds from revolving credit facility 1,165,500 1,124,500
Repayment of revolving credit facility (1,110,000) (995,500)
Debt issuance costs related to 10.0% Senior Secured Notes due 2025 (12,886) 0
Cash paid to repurchase Senior Notes (94,262) 0
Repayment of 1.50% Senior Convertible Notes due 2021 (53,508) 0
Net proceeds from sale of common stock 947 1,959
Dividends paid (1,130) (5,612)
Other, net (1,985) (2,684)
Net cash provided by (used in) financing activities (107,324) 122,663
Net change in cash, cash equivalents, and restricted cash 0 (74,454)
Cash, cash equivalents, and restricted cash at beginning of period 10 77,965
Cash, cash equivalents, and restricted cash at end of period $ 10 $ 3,511
Supplemental schedule of additional cash flow information and non-cash activities:
Operating activities:
Cash paid for interest, net of capitalized interest $ (122,174) $ (113,122)
Investing activities:
Increase (decrease) in capital expenditure accruals and other $ (17,405) $ 34,878
Non-cash investing and financing activities (2)(3)
Reconciliation of cash, cash equivalents, and restricted cash:
Cash and cash equivalents $ 10 $ 10
Restricted cash (1)
0 3,501
Cash, cash equivalents, and restricted cash at end of period $ 10 $ 3,511

~~(1)~~ ~~As of September 30, 2019, a portion of net proceeds from the sale of oil and gas properties was restricted for future property acquisitions.~~

~~(2)~~ ~~Please refer to~~ ~~Note 3 - Divestitures, Assets Held for Sale, and Acquisitions~~ ~~for discussion of the carrying value of properties exchanged during the nine months ended September 30, 2020, and 2019, respectively.~~

~~(3)~~ ~~Please refer to~~ ~~Note 5 - Long-Term Debt~~ ~~for discussion of the debt transactions executed during the nine months ended September 30, 2020.~~

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

~~SM ENERGY COMPANY AND SUBSIDIARIES~~

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Summary of Significant Accounting Policies

Description of Operations

SM Energy Company, together with its consolidated subsidiaries (“SM Energy” or the “Company”), is an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in the ~~State~~state of Texas.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, the instructions to Quarterly Report on Form 10-Q, and Regulation S-X. These financial statements do not include all information and notes required by GAAP for annual financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to the consolidated financial statements included in the ~~2019~~2020 Form 10-K. In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. In connection with the preparation of the Company’s unaudited condensed consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of ~~September~~June 30, ~~2020,~~2021, and through the filing of this report. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying unaudited condensed consolidated financial statements.

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies in the ~~2019~~2020 Form 10-K and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the ~~2019~~2020 Form 10-K.

Recently Issued Accounting Standards

In ~~December 2019,~~March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) ~~No. 2019-12,~~ ~~Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes~~ (“ASU 2019-12”). ASU 2019-12 was issued to reduce the complexity of accounting for income taxes for those entities that fall within the scope of the accounting standard. The guidance is to be applied using a prospective method, excluding amendments related to franchise taxes, which should be applied on either a retrospective basis for all periods presented or a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company early adopted ASU 2019-12 on January 1, 2020, and there was no material impact on the Company’s unaudited condensed consolidated financial statements or disclosures upon adoption.

~~In March 2020, the FASB issued ASU~~ No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting(“ (“ASU 2020-04”)., and in January 2021, issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 isand ASU 2021-01 are effective for all entities ~~as of March 12, 2020~~ through December 31, 2022. ~~The~~As of June 30, 2021, the Company ~~is evaluating~~has not elected to use the optional guidance and continues to evaluate the options provided by ASU ~~2020-04.~~2020-04 and ASU 2021-01. Please refer to Note 5 - Long-Term Debt for discussion of the use of the London Interbank Offered Rate (“LIBOR”) in connection with borrowings under the Credit Agreement.

~~In August 2020, the FASB issued ASU No. 2020-06,~~ ~~Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40)~~ ~~(“ASU 2020-06”)~~. ASU 2020-06 was issued to reduce the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The guidance is to be applied using either a modified retrospective or a fully retrospective method. ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. The Company is evaluating the impact of ASU 2020-06 on its consolidated financial statements and related disclosures.

~~As disclosed in the~~ ~~2019 Form 10-K, on January 1, 2020, the Company adopted ASU No. 2016-13,~~ ~~Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, and ASU No. 2018-15,~~ ~~Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. As expected, there was no material impact on the Company’s unaudited condensed consolidated financial statements or disclosures upon adoption of these ASUs.~~

There are no other ASUs that would have a material effect on the Company’s unaudited condensed consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of ~~September~~June 30, ~~2020,~~2021, or through the filing of this report.

Note 2 - Revenue from Contracts with Customers

The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs from its Midland Basin and South Texas assets. Oil, gas, and NGL production revenue presented within the accompanying unaudited condensed consolidated statements of operations (“accompanying statements of operations”) is reflective of the revenue generated from contracts with customers.

The tables below present oil, gas, and NGL production revenue by product type for each of the Company’s operating ~~regions~~areas for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, and ~~2019:~~2020:


																					Midland Basin						South Texas						Total
		Midland Basin						South Texas						Total							Three Months Ended June 30,						Three Months Ended June 30,						Three Months Ended June 30,
		Three Months Ended September 30,						Three Months Ended September 30,						Three Months Ended September 30,							2021			2020			2021			2020			2021			2020
		2020			2019			2020			2019			2020			2019
		(in thousands)																			(in thousands)
Oil production revenue	Oil production revenue	$	194,547		$	277,361		$	13,100		$	15,496		$	207,647		$	292,857		Oil production revenue	$	404,492		$	114,358		$	31,876		$	5,158		$	436,368		$	119,516
Gas production revenue	Gas production revenue	23,304			17,780			26,251			46,267			49,555			64,047			Gas production revenue	51,435			11,921			36,900			22,942			88,335			34,863
NGL production revenue	NGL production revenue	115			124			24,695			32,391			24,810			32,515			NGL production revenue	112			45			37,754			15,366			37,866			15,411
Total	Total	$	217,966		$	295,265		$	64,046		$	94,154		$	282,012		$	389,419		Total	$	456,039		$	126,324		$	106,530		$	43,466		$	562,569		$	169,790
Relative percentage	Relative percentage	77		%	76		%	23		%	24		%	100		%	100		%	Relative percentage	81		%	74		%	19		%	26		%	100		%	100		%

Note: Amounts may not calculate due to rounding.


																					Midland Basin						South Texas						Total
		Midland Basin						South Texas						Total							Six Months Ended June 30,						Six Months Ended June 30,						Six Months Ended June 30,
		Nine Months Ended September 30,						Nine Months Ended September 30,						Nine Months Ended September 30,							2021			2020			2021			2020			2021			2020
		2020			2019			2020			2019			2020			2019
		(in thousands)																			(in thousands)
Oil production revenue	Oil production revenue	$	585,041		$	791,055		$	33,815		$	45,007		$	618,856		$	836,062		Oil production revenue	$	690,597		$	390,494		$	51,548		$	20,715		$	742,145		$	411,209
Gas production revenue	Gas production revenue	46,559			49,821			78,569			144,563			125,128			194,384			Gas production revenue	109,241			23,255			68,752			52,318			177,993			75,573
NGL production revenue	NGL production revenue	218			102			61,833			106,201			62,051			106,303			NGL production revenue	212			103			65,384			37,138			65,596			37,241
Total	Total	$	631,818		$	840,978		$	174,217		$	295,771		$	806,035		$	1,136,749		Total	$	800,050		$	413,852		$	185,684		$	110,171		$	985,734		$	524,023
Relative percentage	Relative percentage	78		%	74		%	22		%	26		%	100		%	100		%	Relative percentage	81		%	79		%	19		%	21		%	100		%	100		%

Note: Amounts may not calculate due to rounding.

The Company recognizes oil, gas, and NGL production revenue at the point in time when custody and title (“control”) of the product transfers to the purchaser, which differs depending on the applicable contractual terms. Transfer of control drives the presentation of transportation, gathering, processing, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred by the Company prior to control transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations. When control is transferred at or near the wellhead, sales are based on a wellhead market price that is impacted by fees and other deductions incurred by the purchaser subsequent to the transfer of control. Please refer to Note 2 - Revenue from Contracts with Customers in the ~~2019~~2020 Form 10-K for more information regarding the types of contracts under which oil, gas, and NGL production revenue is generated.

Significant judgments made in applying the guidance in Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers, relate to the point in time when control transfers to purchasers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with generally predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.

The Company’s performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control transferring to a purchaser at the wellhead, inlet, or tailgate of the midstream processor’s processing facility, or other contractually specified delivery point. The time period between

production and satisfaction of performance obligations is generally less than one ~~day; thus,~~day, therefore there are 0 material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.

Revenue is recorded in the month when performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within the accounts receivable line item on the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”) until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of ~~September~~June 30, ~~2020,~~2021, and

December 31, ~~2019,~~2020, were ~~$79.3~~$173.3 million and ~~$146.3~~$108.9 million, respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser.

Note 3 - ~~Divestitures, Assets Held for Sale,~~Equity

On June 17, 2020, the Company issued warrants to purchase up to an aggregate of approximately 5.9 million shares, or approximately 5 percent of its then outstanding common stock, at an exercise price of $0.01 per share (“Warrants”).

Upon issuance, the $21.5 million fair value of the Warrants was recorded in additional paid-in capital on the accompanying balance sheets, and ~~Acquisitions~~was determined using a stochastic Monte Carlo simulation using geometric Brownian motion (“GBM Model”). The Company evaluated the Warrants under authoritative accounting guidance and determined that they should be classified as equity instruments, with no recurring fair value measurement required. There have been no changes to the initial carrying amount of the Warrants since issuance.

~~Divestitures~~

~~No material divestitures occurred during~~The Warrant Agreement, dated June 17, 2020 (“Warrant Agreement”), provides that the Warrants are exercisable any time from and after the Triggering Date, as subsequently defined, until June 30, 2023. The Triggering Date is defined by the Warrant Agreement as the first ~~nine months~~trading day following five consecutive trading days on which the product of ~~2020~~the number of shares of common stock issued and ~~2019,~~outstanding on four of the five trading days multiplied by the closing price per share of common stock for each such trading day exceeds $1.0 billion (“Triggering Date”). The Warrants are indexed to the Company’s common stock and ~~there were 0 assets classified as held for sale as~~are required to be settled through physical settlement or net share settlement, if exercised. The Triggering Date occurred on January 15, 2021, and the Warrants became and will remain exercisable at the election of ~~September~~the holders until their expiration on June 30, ~~2020, or December 31, 2019.~~

~~Acquisitions~~2023.

During the ~~third~~second quarter of ~~2020,~~2021, the Company ~~completed~~issued 5,918,089 shares of common stock as a ~~non-monetary acreage trade~~result of ~~primarily undeveloped properties located in Upton County, Texas, resulting in~~ the ~~exchange~~cashless exercise of ~~approximately 535 net acres, with $6.5 million~~5,922,260 Warrants at a weighted-average share price of ~~carrying value attributed~~$15.45 per share, as determined under the terms of the Warrant Agreement. At the request of stockholders and pursuant to the ~~properties transferred by~~Company’s obligations under the ~~Company. This trade~~Warrant Agreement, a registration statement covering the resale of a majority of these shares was ~~recorded at carryover basis~~filed with ~~0 gain or loss recognized. Also during~~ the ~~third quarter of 2020, the Company acquired approximately 380 net acres of proved~~U.S. Securities and ~~unproved properties in Martin County, Texas, for $7.1 million.~~

During the first nine months of 2019, the Company completed several non-monetary acreage trades of primarily undeveloped properties located in Howard, Martin, and Midland Counties, Texas, resulting in the exchange of approximately 2,100 net acres, with $70.8 million of carrying value attributed to the properties transferred by the Company. These trades were recorded at carryover basis with 0 gain or loss recognized.Exchange Commission on June 11, 2021.

Note 4 - Income Taxes

The provision for income taxes for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, and ~~2019,~~2020, consisted of the following:


															For the Three Months Ended June 30,						For the Six Months Ended June 30,
		For the Three Months Ended September 30,						For the Nine Months Ended September 30,							2021			2020			2021			2020
		2020			2019			2020			2019
		(in thousands)													(in thousands)
Current portion of income tax (expense) benefit:	Current portion of income tax (expense) benefit:													Current portion of income tax (expense) benefit:
Federal	Federal	$	0		$	3,826		$	0		$	3,826		Federal	$	0		$	0		$	0		$	0
State	State	173			(320)			(402)			(1,109)			State	0			(236)			(158)			(575)
Deferred portion of income tax (expense) benefit		22,796			(19,617)			159,064			13,620
Income tax (expense) benefit		$	22,969		$	(16,111)		$	158,662		$	16,337
Deferred portion of income tax benefit														Deferred portion of income tax benefit	162			36,921			214			136,268
Income tax benefit														Income tax benefit	$	162		$	36,685		$	56		$	135,693

Effective tax rate	Effective tax rate	18.9		%	27.6		%	20.9		%	16.1		%	Effective tax rate	0.1		%	29.1		%	0		%	21.3		%

Recorded income tax expense or benefit differs from the ~~amounts~~amount that would be provided by applying the statutory United States federal income tax rate to income or loss before income taxes. These differences primarily relate to the effect of state income taxes, excess tax benefits and deficiencies from stock-based compensation awards, tax limitations on the compensation of covered individuals, changes in valuation allowances, ~~and~~ the cumulative impact of other smaller permanent ~~differences.~~differences, and can also reflect the cumulative effect of an enacted tax rate change, in the period of enactment, on the Company’s net deferred tax asset and liability balance. The quarterly rate and the resulting income tax benefit can also be affected by the proportional impacts of forecasted net income or loss and the correlative effect on the valuation allowance for each period presented, as reflected in the table above.

During the third quarter of 2020, the proportional effect of recording discrete excess tax deficiencies from share-based compensation awards and other permanent items decreased the Company’s effective tax rate for the three months ended September 30, 2020, compared with the same period in 2019.

The Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. The primary feature of the CARES Act that the Company benefited from was the acceleration of its refundable Alternative Minimum Tax (“AMT”) credits. On April 1, 2020, the Company filed an election to accelerate its remaining refundable AMT credits of $7.6 million. The Company received the refund in July 2020.

For all years before ~~2016,~~2017, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities.

Note 5 - Long-Term Debt

The following table summarizes the Company’s total outstanding balance on its revolving credit facility, Senior Secured Notes net of unamortized discount and deferred financing costs, and Senior Unsecured Notes net of unamortized deferred financing costs, as of ~~September~~June 30, ~~2020,~~2021, and December 31, ~~2019:~~2020:


							As of June 30, 2021		As of December 31, 2020
		As of September 30, 2020		As of December 31, 2019
		(in thousands)					(in thousands)
Revolving credit facility	Revolving credit facility	$	178,000	$	122,500	Revolving credit facility	$	52,500	$	93,000
Senior Secured Notes (1)	Senior Secured Notes (1)	457,391		0		Senior Secured Notes (1)	467,807		460,656
Senior Unsecured Notes (1)	Senior Unsecured Notes (1)	1,717,647		2,610,298		Senior Unsecured Notes (1)	1,671,818		1,660,663
Total	Total	$	2,353,038	$	2,732,798	Total	$	2,192,125	$	2,214,319

(1) Senior Secured Notes and Senior Unsecured Notes ~~have been~~are defined below.

During the nine months ended September 30, 2020, the Company executed multiple transactions to reduce outstanding debt. During the second quarter of 2020, the Company initiated an offer to exchange its outstanding senior unsecured notes, as presented in the ~~Senior Unsecured Notes~~ section below (“Senior Unsecured Notes”), other than the 1.50% Senior Convertible Notes due 2021 (“2021 Senior Convertible Notes,” and together with the Senior Unsecured Notes, “Old Notes”), and a private exchange of its outstanding 2021 Senior Convertible Notes and portions of its outstanding Senior Unsecured Notes (“Private Exchange”), in each case for newly issued 10.0% Senior Secured Second Lien Notes due January 15, 2025 (“2025 Senior Secured Notes”), referred to together as “Exchange Offers.” In connection with the Exchange Offers, the Company and its lenders amended the Credit Agreement to increase the amount of permitted second lien indebtedness to an aggregate amount of $1.0 billion, inclusive of the 2021 Senior Convertible Notes (“Permitted Second Lien Debt”). Additionally, the Company amended the indenture governing its 2021 Senior Convertible Notes, by entering into the Third Supplemental Indenture, dated as of April 29, 2020 (“Third Supplemental Indenture”), to the original Indenture, dated as of May 21, 2015, as supplemented and amended by the Second Supplemental Indenture, dated as of August 12, 2016, collectively referred to as the “2021 Notes Indenture.” The Third Supplemental Indenture provides that the Company will satisfy any conversion obligation solely in cash.

On June 17, 2020 (“Settlement Date”), the Company exchanged $611.9 million in aggregate principal amount of Senior Unsecured Notes and $107.0 million in aggregate principal amount of 2021 Senior Convertible Notes for $446.7 million in aggregate principal amount of 2025 Senior Secured Notes, as well as, in connection with the Private Exchange, (a) $53.5 million in cash to certain holders of the 2021 Senior Convertible Notes and (b) warrants to acquire up to an aggregate of approximately 5.9 million shares, or approximately five percent of its outstanding common stock, exercisable upon the occurrence of certain future triggering events, to certain holders who exchanged Old Notes in the Private Exchange. Please refer to ~~Note 11 - Fair Value Measurements~~ for more information regarding the warrants issued by the Company. Pursuant to the 2021 Notes Indenture, upon the issuance of Permitted Second Lien Debt, the remaining outstanding 2021 Senior Convertible Notes became secured and are subsequently referred to as the “2021 Senior Secured Convertible Notes,” and together with the 2025 Senior Secured Notes, the “Senior Secured Notes.”

~~The following table summarizes the principal amounts of the Old Notes tendered as of the Settlement Date:~~


~~Title of Old Notes Tendered~~	~~Principal Amount of Old Notes Tendered~~
	~~(in thousands)~~
~~1.50% Senior Convertible Notes due 2021~~	$	~~107,015~~
~~6.125% Senior Notes due 2022~~	~~141,701~~
~~5.0% Senior Notes due 2024~~	~~155,339~~
~~5.625% Senior Notes due 2025~~	~~150,882~~
~~6.75% Senior Notes due 2026~~	~~80,765~~
~~6.625% Senior Notes due 2027~~	~~83,209~~
~~Total~~	$	~~718,911~~

The Company retired $611.9 million and $107.0 million in aggregate principal amount of its Senior Unsecured Notes and 2021 Senior Convertible Notes, respectively, upon the closing of the Exchange Offers. Upon closing, the Company paid $8.9 million of accrued and unpaid interest and accelerated $5.6 million of previously unamortized deferred financing costs associated with the retired Senior Unsecured Notes and 2021 Senior Convertible Notes and accelerated $6.1 million of previously unamortized debt discount associated with the retired 2021 Senior Convertible Notes. The Exchange Offers resulted in a net gain on extinguishment of debt of $227.3 million. The Company cancelled all retired Senior Unsecured Notes and 2021 Senior Convertible Notes upon the closing of the Exchange Offers.

Additionally, during the first and third quarters of 2020, the Company repurchased certain of its Senior Unsecured Notes in open market transactions. During the three months ended September 30, 2020, the Company repurchased a total of $62.5 million in aggregate principal amount of its 6.125% Senior Notes due 2022 (“2022 Senior Notes”) and $29.0 million in aggregate principal amount of its 5.0% Senior Notes due 2024 (“2024 Senior Notes”) in open market transactions for a total settlement amount, excluding accrued interest, of $65.9 million. In connection with the repurchases, the Company recorded a gain on extinguishment of debt of $25.1 million for the three months ended September 30, 2020. This amount included discounts realized upon repurchase of $25.5 million partially offset by approximately $480,000 of accelerated unamortized deferred financing costs. During the three months ended March 31, 2020, the Company repurchased a total of $40.7 million in aggregate principal amount of its 2022 Senior Notes in open market transactions for a total settlement amount, excluding accrued interest, of $28.3 million. In connection with the repurchase, the Company recorded a gain on extinguishment of debt of $12.2 million for the three months ended March 31, 2020. This amount included discounts realized upon repurchase of $12.4 million partially offset by approximately $235,000 of accelerated unamortized deferred financing costs. The Company canceled all repurchased 2022 Senior Notes and 2024 Senior Notes upon settlement.

~~Please refer to the~~ ~~Credit Agreement~~ ~~and~~ ~~Senior Secured Notes~~ ~~sections below for additional information.~~

Credit Agreement

The Company’s Credit Agreement, which is scheduled to mature on September 28, 2023, provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion. ~~During the second quarter~~As of ~~2020, as a result of lower commodity prices and a corresponding decrease in the value of the Company’s proved reserves,~~June 30, 2021, the borrowing base and aggregate lender commitments under the Credit Agreement were ~~both reduced to~~ $1.1 billion. Also during the second quarter of 2020, the Company entered into the Third Amendment and the Fourth Amendment to the Credit Agreement (collectively, the “Amendments”), which permitted the Company to incur new second lien debt of up to $827.5 million prior to the fall semi-annual borrowing base redetermination, provided that all principal amounts of such debt are used to redeem unsecured senior debt of the Company for less than or equal to 80% of par value. The Amendments also permitted the Company to grant a second-priority security interest to the holders of the Company’s outstanding 2021 Senior Convertible Notes to secure the Company’s obligations under the 2021 Senior Convertible Notes. Additionally, the Amendments reduced the amount of dividends that the Company may declare and pay on an annual basis from $50.0 million to $12.0 million. As of the filing of this report, the fall semi-annual borrowing base redetermination was in process. The next scheduled borrowing base redetermination date is ~~April~~October 1, 2021.

~~The~~ On June 8, 2021, the Company entered into a sixth amendment (“Sixth Amendment”) to the Credit Agreement ~~is scheduled~~ to ~~mature on September 28, 2023, except that, pursuant~~amend certain definitions and covenants relating to the ~~Amendments, newly issued Permitted Second Lien Debt used~~Company's ability to issue permitted refinancing debt and repurchase or redeem ~~any portion of~~outstanding indebtedness to facilitate the ~~remaining~~Tender Offer and the 2022 Senior Notes must have maturities on or after 180 days after September 28, 2023; otherwise, the maturity date of the Credit Agreement will be July 2, 2023. Without regard to which maturity date is in effect, the maturity date could occur earlier on August 16, 2022, if the Company has not completed certain repurchase, redemption, or refinancing activities associated with its 2022 Senior Notes, and does not have certain unused availability for borrowing under the Credit Agreement,Redemption, each as ~~outlined in the Credit Agreement.~~defined below.

Interest and commitment fees associated with the revolving credit facility are accrued based on a borrowing base utilization grid set forth in the Credit ~~Agreement. The Third Amendment to the Credit~~ Agreement ~~amended the borrowing base utilization grid~~ as presented in Note 5 - Long-Term Debt in the ~~table below.~~2020 Form 10-K. At the Company’s election, borrowings under the Credit Agreement may be in the form of Eurodollar, Alternate Base Rate (“ABR”), or Swingline loans. Eurodollar loans accrue interest at LIBOR, plus the applicable margin from the utilization grid, and ABR and Swingline loans accrue interest at a market-based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount at rates from the utilization grid and are included in the interest expense line item on the accompanying statements of operations.

Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90%
Eurodollar Loans (1)
1.750 % 2.000 % 2.500 % 2.750 % 3.000 %
ABR Loans or Swingline Loans 0.750 % 1.000 % 1.500 % 1.750 % 2.000 %
Commitment Fee Rate 0.375 % 0.375 % 0.500 % 0.500 % 0.500 %

~~(1)~~ The Credit Agreement specifies that if LIBOR is no longer a widely used benchmark rate, or if it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with the Company. Please refer to Note 1 - Summary of Significant Accounting Policies for discussion of FASB ASU 2020-04 and ASU 2021-01, which provides guidance related to reference rate reform.

The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of ~~October~~July 21, ~~2020, September~~2021, June 30, ~~2020,~~2021, and December 31, ~~2019:~~2020:


									As of July 21, 2021		As of June 30, 2021		As of December 31, 2020
		As of October 21, 2020		As of September 30, 2020		As of December 31, 2019
		(in thousands)							(in thousands)
Revolving credit facility (1)	Revolving credit facility (1)	$	129,000	$	178,000	$	122,500	Revolving credit facility (1)	$	99,000	$	52,500	$	93,000
Letters of credit (2)	Letters of credit (2)	42,000		42,000		0		Letters of credit (2)	0		0		42,000
Available borrowing capacity	Available borrowing capacity	929,000		880,000		1,077,500		Available borrowing capacity	1,001,000		1,047,500		965,000
Total aggregate lender commitment amount	Total aggregate lender commitment amount	$	1,100,000	$	1,100,000	$	1,200,000	Total aggregate lender commitment amount	$	1,100,000	$	1,100,000	$	1,100,000

(1) Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item on the accompanying balance sheets and totaled ~~$4.7~~$3.5 million and ~~$5.9~~$4.3 million as of ~~September~~June 30, ~~2020,~~2021, and December 31, ~~2019,~~2020, respectively. These costs are being amortized over the term of the revolving credit facility on a straight-line basis.

(2) Letters of credit outstanding reduce the amount available under the revolving credit facility on a dollar-for-dollar basis.

Senior Notes

Q2 2021 Senior Notes Transactions. On June 23, 2021, the Company issued $400.0 million in aggregate principal amount of its 6.5% Senior Notes at par with a maturity date of July 15, 2028 (“2028 Senior Notes”). The Company received net proceeds of

$392.8 million after deducting paid and accrued fees of $7.2 million, which are being amortized as deferred financing costs over the life of the 2028 Senior Notes. The net proceeds were used to repurchase $193.1 million and $172.3 million of outstanding principal amount of the Company’s 2022 Senior Notes and 2024 Senior Notes, respectively, through a cash tender offer (“Tender Offer”), and to redeem the remaining $19.3 million of 2022 Senior Notes not repurchased as part of the Tender Offer (“2022 Senior Notes Redemption”). The Company paid total consideration, excluding accrued interest, of $385.3 million, and recorded a net loss on extinguishment of debt of $2.1 million for the three months ended June 30, 2021, which included $1.5 million of accelerated unamortized deferred financing costs and $600,000 of net premiums. The Company canceled all repurchased and redeemed 2022 Senior Notes and 2024 Senior Notes upon settlement.

Q2 2020 Senior Notes Transactions. During the second quarter of 2020, the Company initiated an offer to exchange certain of its outstanding Senior Unsecured Notes, as defined and presented in the Senior Unsecured Notes section below, other than its 1.50% Senior Convertible Notes due 2021 (“2021 Senior Convertible Notes,” and together with the Senior Unsecured Notes, “Old Notes”), and entered into a private exchange of certain of its outstanding 2021 Senior Convertible Notes and portions of its outstanding Senior Unsecured Notes (“Private Exchange”), in each case, for newly issued 10.0% Senior Secured Second Lien Notes due January 15, 2025 (“2025 Senior Secured Notes”), referred to together as “Exchange Offers.”

On June 17, 2020, the Company exchanged $611.9 million in aggregate principal amount of Senior Unsecured Notes and $107.0 million in aggregate principal amount of 2021 Senior Convertible Notes for $446.7 million in aggregate principal amount of 2025 Senior Secured Notes. Further, in connection with the Private Exchange, the Company tendered $53.5 million in cash to certain holders of the 2021 Senior Convertible Notes and issued the Warrants. Please refer to Note 3 - Equity for more information regarding the Warrants issued by the Company. Upon the closing of the Exchange Offers, the Company recorded a net gain on extinguishment of debt of $227.3 million which included the recognition of $6.1 million and $5.6 million of previously unamortized debt discount and deferred financing costs, respectively. The Company canceled all retired Senior Unsecured Notes and 2021 Senior Convertible Notes upon closing of the Exchange Offers. Pursuant to the indenture governing its 2021 Senior Convertible Notes, the Company’s remaining outstanding 2021 Senior Convertible Notes became secured and are subsequently referred to as the “2021 Senior Secured Convertible Notes,” and together with the 2025 Senior Secured Notes, the “Senior Secured Notes.” Please refer to Note 5 - Long-Term Debt in the 2020 Form 10-K for additional information regarding the debt transactions that occurred during the second quarter of 2020.

Q1 2020 Senior Notes Transactions. During the first quarter of 2020, the Company repurchased a total of $40.7 million in aggregate principal amount of its 2022 Senior Notes in open market transactions for a total settlement amount, excluding accrued interest, of $28.3 million. In connection with the repurchases, the Company recorded a net gain on extinguishment of debt of $12.2 million for the three months ended March 31, 2020. This amount included discounts realized upon repurchase of $12.4 million partially offset by $235,000 of accelerated unamortized deferred financing costs. The Company canceled all repurchased 2022 Senior Notes upon settlement.

Senior Secured Notes. Senior Secured Notes, net of unamortized discount and deferred financing costs, included within the Senior Notes, net line item on the accompanying balance sheets as of ~~September~~June 30, 2021, and December 31, 2020, consisted of the following:


		As of September 30, 2020									As of June 30, 2021
		Principal Amount		Unamortized Debt Discount		Unamortized Deferred Financing Costs		Principal Amount, Net			Principal Amount		Unamortized Debt Discount		Unamortized Deferred Financing Costs		Net
		(in thousands)
											(in thousands)
1.50% Senior Secured Convertible Notes due 2021										1.50% Senior Secured Convertible Notes due 2021	$	65,485	$	0	$	0	$	65,485
10.0% Senior Secured Notes due 2025	10.0% Senior Secured Notes due 2025	$	446,675	$	(39,706)	$	(12,091)	$	394,878	10.0% Senior Secured Notes due 2025	446,675		34,208		10,145		402,322
1.50% Senior Secured Convertible Notes due 2021 (1)		65,485		(2,710)		(262)		62,513
Total	Total	$	512,160	$	(42,416)	$	(12,353)	$	457,391	Total	$	512,160	$	34,208	$	10,145	$	467,807

											As of December 31, 2020
											Principal Amount		Unamortized Debt Discount		Unamortized Deferred Financing Costs		Net

											(in thousands)
1.50% Senior Secured Convertible Notes due 2021										1.50% Senior Secured Convertible Notes due 2021	$	65,485	$	1,828	$	175	$	63,482
10.0% Senior Secured Notes due 2025										10.0% Senior Secured Notes due 2025	446,675		37,943		11,558		397,174
Total										Total	$	512,160	$	39,771	$	11,733	$	460,656

~~(1)~~ ~~As discussed above, as required by~~The Senior Secured Notes are senior obligations of the ~~2021 Notes Indenture and as permitted by~~Company, secured on a second-priority basis, ranking junior to the Company’s obligations under the Credit Agreement asand equal in priority to one another. The Senior Secured Notes rank senior in right of payment with all of the Company’s existing and any future unsecured senior or subordinated debt.

The 2021 Senior Secured Convertible Notes matured on July 1, 2021, and on that day, the Company ~~issued Permitted Second Lien Debt upon~~used borrowings under its revolving credit facility to retire at par the ~~closing of the Exchange Offers, its remaining 2021 Senior Convertible Notes contemporaneously became secured.~~

~~2025 Senior Secured Notes. On June 17, 2020, the Company issued $446.7 million in aggregate~~outstanding principal amount of ~~2025~~$65.5 million. Interest expense recognized on the 2021 Senior Secured Convertible Notes ~~due January 15, 2025. The Company incurred fees of $12.9 million, which are being amortized as deferred financing costs over~~related to the ~~life~~stated interest rate and amortization of the 2025 Senior Secured Notes. Upon the issuance of the 2025 Senior Secured Notes, the Company recorded $405.0 million as the initial carrying amount, which approximated their fair value at issuance. The excess of the principal amount of the 2025 Senior Secured Notes over its fair value was recorded as a debt discount. The debt discount totaled $1.1 million and ~~deferred financing costs are being amortized to interest expense through~~$2.6 million for the ~~maturity date.~~three months ended June 30, 2021, and 2020, respectively, and totaled $2.3 million and $5.4 million for the six months ended June 30, 2021, and 2020, respectively.

In connection with the issuance of the 2025 Senior Secured Notes, the Company entered into an indenture dated as of June 17, 2020, with UMB Bank, N.A., as trustee, governing the 2025 Senior Secured Notes (“2025 Notes Indenture”). The Company may redeem some or all of its 2025 Senior Secured Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest, as described in the ~~2025 Notes Indenture.~~

The 2025 Senior Secured Notes are senior obligations of the Company, secured on a second-priority basis, ranking junior to the Company’s obligations under the Credit Agreement and equal in priority with the 2021 Senior Secured Convertible Notes. The 2025 Senior Secured Notes rank senior in right of payment with all of the Company’s existing and any future unsecured senior or subordinated debt.

~~2021 Senior Secured Convertible Notes. Upon issuance of~~indenture governing the 2025 Senior Secured Notes, which was Permitted Second Lien Debt, as required by the 2021 Notes Indenture, and as permitted by the Credit Agreement, the 2021 Senior Convertible Notes became secured senior obligations of the Company on a second-priority basis, ranking junior to the Company’s obligations under the Credit Agreement and equal in priority with the 2025 Senior Secured Notes. The 2021 Senior Secured Convertible Notes rank senior in right of payment to all of the Company’s existing and any future unsecured senior or subordinated debt. During the second quarter of 2020, pursuant to the Third Supplemental Indenture, the Company agreed to satisfy any conversion obligation solely in cash, resulting in reclassification of the fair value of the equity components out of additional paid-in capital. Please refer to ~~Note 5 - Long-Term Debt~~ ~~in the~~ ~~2019 Form 10-K~~ ~~for additional detail on the Company’s 2021 Senior Convertible Notes and associated capped call transactions.~~

The 2021 Senior Secured Convertible Notes were not convertible at the option of holders as of September 30, 2020, or through the filing of this report. Notwithstanding the inability to convert, the if-converted value of the 2021 Senior Secured Convertible Notes did not exceed the principal amount. The Company has the ability to settle its 2021 Senior Secured Convertible Notes obligation, due July 1, 2021, with borrowings under its revolving credit facility. The remaining debt discount and debt-related issuance costs are being amortized to the principal value of the 2021 Senior Secured Convertible Notes as interest expense through the maturity date. Interest expense recognized on the 2021 Senior Secured Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $1.1 million and $2.8 million for the three months ended September 30, 2020, and 2019, respectively, and totaled $6.6 million and $8.2 million for the nine months ended September 30, 2020, and 2019, respectively.

Senior Unsecured Notes. Senior Unsecured Notes, net of unamortized deferred financing costs, included within the Senior Notes, net line item on the accompanying balance sheets as of ~~September~~June 30, ~~2020,~~2021, and December 31, ~~2019,~~2020, consisted of the following:

As of September 30, 2020 As of December 31, 2019
Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net
(in thousands)
6.125% Senior Notes due 2022 $ 231,881 $ 1,055 $ 230,826 $ 476,796 $ 2,920 $ 473,876
5.0% Senior Notes due 2024 315,633 1,941 313,692 500,000 3,766 496,234
5.625% Senior Notes due 2025 349,118 2,950 346,168 500,000 4,903 495,097
6.75% Senior Notes due 2026 419,235 4,145 415,090 500,000 5,571 494,429
6.625% Senior Notes due 2027 416,791 4,920 411,871 500,000 6,601 493,399
1.50% Senior Convertible Notes due 2021 (1)(2)
0 0 0 172,500 15,237 157,263
Total $ 1,732,658 $ 15,011 $ 1,717,647 $ 2,649,296 $ 38,998 $ 2,610,298

~~(1)~~ ~~Unamortized deferred financing costs attributable to the 2021 Senior Convertible Notes include $13.9 million related to the unamortized debt discount as of December 31, 2019.~~


	As of June 30, 2021						As of December 31, 2020
	Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net		Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net

	(in thousands)
6.125% Senior Notes due 2022	$	0	$	0	$	0	$	212,403	$	855	$	211,548
5.0% Senior Notes due 2024	104,769		499		104,270		277,034		1,576		275,458
5.625% Senior Notes due 2025	349,118		2,476		346,642		349,118		2,792		346,326
6.75% Senior Notes due 2026	419,235		3,620		415,615		419,235		3,970		415,265
6.625% Senior Notes due 2027	416,791		4,337		412,454		416,791		4,725		412,066
6.5% Senior Notes due 2028	400,000		7,163		392,837		0		0		0
Total	$	1,689,913	$	18,095	$	1,671,818	$	1,674,581	$	13,918	$	1,660,663

~~(2)~~ As discussed above, as required by the 2021 Notes Indenture and as permitted by the Credit Agreement, as the Company issued Permitted Second Lien Debt upon the closing of the Exchange Offers, its remaining 2021 Senior Convertible Notes contemporaneously became secured.

The senior unsecured notes listed above (collectively referred to as “Senior Unsecured Notes,” and together with the Senior Secured Notes, “Senior Notes”) are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. The Company may redeem some or all of its Senior Unsecured Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Unsecured Notes.

Please refer to Note 5 - Long-Term Debt in the ~~2019~~2020 Form 10-K for additional detail on the Company’s Senior ~~Unsecured~~ Notes.

Covenants

The Company is subject to certain financial and non-financial covenants under the Credit Agreement and the indentures governing the Senior Notes that, among other terms, limit the Company’s ability to incur additional indebtedness, make restricted payments including dividends, sell assets, create liens that secure debt, enter into transactions with affiliates, merge or consolidate with another company, and with respect to the Company’s restricted subsidiaries, permit the consensual restriction on the ability of such restricted subsidiaries to pay dividends or indebtedness owing to the Company or to any other restricted ~~subsidiaries, create liens that secure debt, enter into transactions with affiliates, and merge or consolidate with another company.~~subsidiaries. The Company was in compliance with all

covenants under the Credit Agreement and the indentures governing the Senior Notes as of ~~September~~June 30, ~~2020,~~2021, and through the filing of this report.

Please refer to Note 5 - Long-Term Debt in the 2020 Form 10-K for additional detail on the Company’s covenants under the Credit Agreement and indentures governing the Senior Notes.

Capitalized Interest

Capitalized interest costs for the three months ended ~~September~~June 30, 2021, and 2020, ~~and 2019,~~ totaled ~~$4.8~~$4.7 million and ~~$4.2~~$4.1 million, respectively, and totaled ~~$11.6~~$9.0 million and ~~$14.1~~$6.8 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, and ~~2019,~~2020, respectively. The amount of interest the Company capitalizes generally fluctuates based on the amount borrowed, the Company’s capital program, and the timing and amount of costs associated with capital projects that are considered in progress. Capitalized interest costs are included in total costs incurred.

Note 6 - Commitments and Contingencies

Commitments

Other than those items discussed below, there have been no changes in commitments through the filing of this report that differ materially from those disclosed in the ~~2019~~2020 Form 10-K. Please refer to Note 6 - Commitments and Contingencies in the ~~2019~~2020 Form 10-K for additional discussion of the Company’s commitments.

Drilling Rig Service Contracts. During the ~~nine months ended September 30, 2020,~~first half of 2021, the Company amended certain of its drilling rig contracts resulting in the ~~reduction of day rates and potential early termination fees and the~~ extension of contract terms. As of ~~September~~June 30, ~~2020,~~2021, the Company’s drilling rig commitments totaled ~~$12.2~~$16.1 million under contract terms extending through the second quarter of ~~2021.~~2022. If all of these contracts were terminated as of ~~the filing of this report,~~June 30, 2021, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay ~~$5.7~~$9.7 million in early termination fees. No material expenses related to early termination or standby fees were incurred by the Company during the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, and the Company does not expect to incur material penalties with regard to its drilling rig contracts during the remainder of ~~2020.~~2021.

Drilling and Completion Commitments. During the ~~second quarter~~first half of ~~2020,~~2021, the Company ~~entered into~~amended an agreement that ~~included~~includes minimum drilling and completion footage requirements on certain existing leases. If these minimum requirements are not satisfied by March 31, ~~2021,~~2022, the Company will be required to pay liquidated damages based on the difference between the actual footage drilled and completed and the minimum requirements. As of ~~September~~June 30, ~~2020,~~2021, the liquidated damages could range from 0 to a maximum of ~~$35.7~~$45.1 million, with the maximum exposure assuming no additional development activity occurred prior to March 31, 2021. The Company also entered into an agreement that included a minimum number of wells drilled and completed on certain existing leases. If these minimum requirements are not satisfied by December 31, 2021, the Company will be required to pay liquidated damages based on the difference between the actual number of wells drilled and completed and the minimum requirements. As of September 30, 2020, the liquidated damages could range from 0 to a maximum of $11.5 million, with the maximum exposure assuming no additional development activity occurred prior to December 31, 2021.2022. As of the filing of this report, the Company expects to meet its obligations under ~~both agreements.~~this agreement.

Other Contracts. During the second quarter of 2021, the Company entered into an operating lease agreement with a total estimated obligation of $26.1 million and an initial term extending through the second quarter of 2033. As of the filing of this report, the Company expects to meet this commitment.

Contingencies

The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.

Note 7 - Compensation Plans

~~Equity Incentive Compensation Plan~~

As of ~~September~~June 30, ~~2020, 4.4~~2021, 3.8 million shares of common stock were available for grant under the Company’s Equity Incentive Compensation Plan (“Equity Plan”). The Company may also grant other types of long-term incentive-based awards, such as cash awards and performance-based cash awards to eligible employees under its compensation plan.

Performance Share Units

The Company ~~grants~~has granted performance share units (“PSUs”) to eligible employees as part of its Equity Plan. The number of shares of the Company’s common stock issued to settle PSUs ranges from 0 to 2 times the number of PSUs awarded and is determined based on certain criteria over a ~~three-year~~three-year performance period. PSUs generally vest on the third anniversary of the date of the grant or upon other triggering events as set forth in the Equity Plan.

For PSUs granted in 2017, which the Company determined to be equity awards, the settlement criteria included a combination of the Company’s Total Shareholder Return (“TSR”) on an absolute basis, and the Company’s TSR relative to the TSR of certain peer companies over the associated three-year performance period. The fair value of the PSUs granted in 2017 was measured on the grant

date using a stochastic Monte Carlo simulation using geometric Brownian motion (“GBM Model”). As these awards depend entirely on market-based settlement criteria, the associated compensation expense is recognized on a straight-line basis within general and administrative expense and exploration expense over the vesting periods of the respective awards.

For PSUs granted in 2018 and 2019, the settlement criteria include a combination of the Company’s ~~TSR~~Total Shareholder Return (“TSR”) relative to the TSR of certain peer companies and the Company’s cash return on total capital invested (“CRTCI”) relative to the CRTCI of certain peer companies over the associated three-year performance period. In addition to these performance criteria, the award agreements for these grants also stipulate that if the Company’s absolute TSR is negative over the three-year performance period, the maximum number of shares of common stock that can be issued to settle outstanding PSUs is capped at one times the number of PSUs granted on the award date, regardless of the Company’s TSR and CRTCI performance relative to its peer group. The fair ~~value~~values of the PSUs granted in 2018 and 2019 ~~was~~were measured on the applicable grant dates using the GBM Model, with the assumption that the associated CRTCI performance condition will be met at the target amount at the end of the respective performance periods. Compensation expense for PSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. As these awards depend on a combination of performance-based settlement criteria and market-based settlement criteria, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the Company’s expected CRTCI performance relative to the applicable peer companies.

The Company records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the date of grant. Total compensation expense recorded for PSUs was ~~$1.6~~$1.3 million and ~~$2.9~~$2.8 million for the three months ended ~~September~~June 30, ~~2020,~~2021, and ~~2019,~~2020, respectively, and ~~$7.0~~$4.5 million and ~~$8.6~~$5.4 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, and ~~2019,~~ 2020,

respectively. As of ~~September~~June 30, ~~2020,~~2021, there was ~~$8.1~~$3.0 million of total unrecognized compensation expense related to non-vested PSU awards, which is being amortized through 2022.

~~A summary of~~ There were no material changes to the ~~status~~outstanding and ~~activity of~~ non-vested PSUs ~~for~~during the ~~nine~~six months ended ~~September~~June 30, ~~2020, is presented in the following table:~~

PSUs (1)
Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year 2,022,585 $ 16.87
Granted 0 $ 0
Vested (791,962) $ 15.85
Forfeited (45,731) $ 16.69
Non-vested at end of quarter 1,184,892 $ 17.56

~~(1)~~ The number of shares of common stock assumes a multiplier of 1. The actual final number of shares of common stock to be issued will range from 0 to 2 times the number of PSUs awarded depending on the three-year performance multiplier.

During the nine months ended September 30, 2020, the Company settled 791,962 PSUs that were granted in 2017, which earned a 0.9 times multiplier. The Company and the majority of grant participants mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings, as provided for in the Equity Plan and applicable award agreements. After withholding 215,451 shares to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs, 485,060 shares of the Company’s common stock were issued in accordance with the terms of the applicable PSU awards.2021.

Employee Restricted Stock Units

The Company grants restricted stock units (“RSUs”) to eligible persons as part of its Equity Plan. Each RSU represents a right to receive 1 share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. RSUs generally vest one-third of the total grant on each anniversary date of the grant over ~~a three-year~~the applicable vesting period or upon other triggering events as set forth in the Equity Plan.

The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the date of grant. The fair value of an RSU is equal to the closing price of the Company’s common stock on the ~~day~~date of the grant. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for employee RSUs was ~~$1.8~~$2.1 million and ~~$2.9~~$2.7 million for the three months ended ~~September~~June 30, ~~2020,~~2021, and ~~2019,~~2020, respectively, and ~~$7.1~~$4.3 million and ~~$8.4~~$5.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, and ~~2019,~~2020, respectively. As of ~~September~~June 30, ~~2020,~~2021, there was ~~$8.6~~$10.1 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through ~~2022.~~

~~A summary of~~2023. There were no material changes to the ~~status~~outstanding and ~~activity of~~ non-vested RSUs ~~granted to employees for~~during the ~~nine~~six months ended ~~September~~June 30, ~~2020, is presented in the following table:~~2021.

RSUs Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year 1,532,131 $ 16.01
Granted 0 $ 0
Vested (744,325) $ 16.74
Forfeited (77,814) $ 15.67
Non-vested at end of quarter 709,992 $ 15.29

~~During the nine months ended September~~Subsequent to June 30, ~~2020,~~2021, the Company settled ~~744,325~~349,328 RSUs ~~that related to~~upon the vesting of awards granted in previous years. The Company and ~~the majority of~~all grant participants mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings, as provided for in the Equity Plan and applicable award agreements. As a result, ~~209,126~~the Company issued 250,009 net shares of common stock upon settlement of the awards. The remaining 99,319 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those RSUs.

Director Shares

During the second quarters of ~~2020,~~2021, and ~~2019,~~2020, the Company issued ~~267,576~~57,795 and ~~96,719~~267,576 shares, respectively, of its common stock to its non-employee directors under the Equity Plan. Shares issued during the second quarter of ~~2020~~2021 will fully vest on December 31, ~~2020.~~2021. Shares issued during the second quarter of ~~2019~~2020 fully vested on December 31, ~~2019. The Company did not issue any director shares during the third quarters of 2020 or 2019.~~2020.

Employee Stock Purchase Plan

Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, ~~without accruing~~ensuring that the accrual is no more than 2,500 shares per offering period and not in excess of $25,000 in value ~~from~~related to purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on either the first or last day of the purchase period. The ESPP is intended to qualify as an “employee stock purchase plan” under Section 423 of the Internal Revenue Code. There were ~~297,013~~252,665 and ~~184,079~~297,013 shares issued under the ESPP during the ~~nine months ended September 30,~~second quarters of 2021, and 2020, ~~and 2019,~~ respectively. Total proceeds to the Company for the issuance of these shares was ~~$947,000~~$1.3 million and ~~$2.0 million~~$947,000 for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, and ~~2019,~~2020, respectively. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.

Please refer to Note 87 - ~~Pension Benefits~~

~~Pension~~Compensation Plans

The Company has a non-contributory defined benefit pension plan covering employees who meet age and service requirements and who began employment with the Company prior to January 1, 2016 (“Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (“Nonqualified Pension Plan” and together with the Qualified Pension Plan, “Pension Plans”). The Company froze the Pension Plans to new participants, effective as of January 1, 2016. Employees participating in the ~~Pension Plans prior to the plans being frozen will continue to earn benefits.~~

~~Components of Net Periodic Benefit Cost~~2020 Form 10-K for ~~the Pension Plans~~

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2020 2019 2020 2019
(in thousands)
Components of net periodic benefit cost:
Service cost $ 1,129 $ 1,395 $ 3,387 $ 4,186
Interest cost 590 699 1,768 2,094
Expected return on plan assets that reduces periodic pension benefit cost (434) (393) (1,301) (1,180)
Amortization of prior service cost 4 4 13 13
Amortization of net actuarial loss 238 239 713 718
Settlements 1,282 0 1,282 0
Net periodic benefit cost $ 2,809 $ 1,944 $ 5,862 $ 5,831

Prior service costs are amortized on a straight-line basis over the average remaining service period of active participants. Gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants. The service cost component of net periodic benefit cost for the Pension Plans is presented as an operating expense within the general and administrative and exploration expense line itemsadditional detail on the accompanying statements of operations while the other components of net periodic benefit cost for the Pension Plans are presented as non-operating expenses within the other non-operating expense, net line item on the accompanying statements of operations.

~~Contributions~~

~~As of the filing of this report, the Company has contributed $5.9 million to the Qualified Pension Plan in 2020.~~Company’s Equity Plan.

Note 8 - Fair Value Measurements

The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:

•Level 1 – quoted prices in active markets for identical assets or liabilities

•Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

•Level 3 – significant inputs to the valuation model are unobservable.

The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of June 30, 2021:


	Level 1		Level 2		Level 3

	(in thousands)
Assets:
Derivatives (1)	$	0	$	44,837	$	0

Liabilities:
Derivatives (1)	$	0	$	661,335	$	0

(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.


	Level 1		Level 2		Level 3

	(in thousands)
Assets:
Derivatives (1)	$	0	$	54,353	$	0
Liabilities:
Derivatives (1)	$	0	$	222,520	$	—

(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy.

Derivatives

The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active.

Please refer to Note 10 - Derivative Financial Instruments in this report, and to Note 10 - Derivative Financial Instruments and Note 11 - Fair Value Measurements in the 2020 Form 10-K for more information regarding the Company’s derivative instruments.

Oil and Gas Properties and Other Property and Equipment

The Company had 0 material assets included in total property and equipment, net, measured at fair value as of June 30, 2021, or December 31, 2020.

The following table presents impairment of proved properties expense and abandonment and impairment of unproved properties expense recorded for the periods presented:


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020

	(in millions)
Impairment of proved oil and gas properties and related support equipment	$	0	$	0	$	0	$	956.7
Abandonment and impairment of unproved properties (1)	8.8		8.8		17.5		41.9
Impairment (2)	$	8.8	$	8.8	$	17.5	$	998.5

(1) These impairments related to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. The balances in the unproved oil and gas properties line item on the accompanying balance sheets as of June 30, 2021, and December 31, 2020, are recorded at carrying value.

(2) Amounts may not calculate due to rounding.

For the six months ended June 30, 2020, the Company recorded impairment expense of $956.7 million related to its South Texas proved oil and gas properties and related support facilities as a result of the decrease in commodity price forecasts at the end of the first quarter of 2020, specifically decreases in oil and NGL prices. The Company used a discount rate of 11 percent in its calculation of the present value of expected future net cash flows based on the prevailing market-based weighted average cost of capital as of March 31, 2020.

Please refer to Note 1 - Summary of Significant Accounting Policies and Note 11 - Fair Value Measurements in the 2020 Form 10-K for more information regarding the Company’s approach in determining the fair value of its properties.

Long-Term Debt

The following table reflects the fair value of the Company’s Senior Notes obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of June 30, 2021, or December 31, 2020, as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional discussion.


	As of June 30, 2021				As of December 31, 2020
	Principal Amount		Fair Value		Principal Amount		Fair Value

	(in thousands)
1.50% Senior Secured Convertible Notes due 2021	$	65,485	$	64,888	$	65,485	$	61,449
10.0% Senior Secured Notes due 2025	$	446,675	$	505,511	$	446,675	$	482,887
6.125% Senior Notes due 2022	$	0	$	0	$	212,403	$	205,379
5.0% Senior Notes due 2024	$	104,769	$	104,662	$	277,034	$	240,072
5.625% Senior Notes due 2025	$	349,118	$	349,118	$	349,118	$	289,401
6.75% Senior Notes due 2026	$	419,235	$	427,079	$	419,235	$	342,385
6.625% Senior Notes due 2027	$	416,791	$	429,061	$	416,791	$	331,220
6.5% Senior Notes due 2028	$	400,000	$	412,000	$	0	$	0

The carrying value of the Company’s revolving credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market rates.

Note 9 - Earnings Per Share

Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. As of September 30, 2019, potentially dilutive securities for this calculation consisted primarily of non-vested RSUs, contingent PSUs, and shares into which the 2021 Senior Convertible Notes were convertible, which were measured using the treasury stock method. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price applicable to the 2021 Senior Convertible Notes for the three and nine months ended September 30, 2019, therefore, the 2021 Senior Convertible Notes had no dilutive impact. On April 29, 2020, pursuant to the Third Supplemental Indenture, the Company agreed that it will satisfy any conversion obligation with respect to the 2021 Senior Convertible Notes solely in cash. As a result, the Company’s 2021 Senior Secured Convertible Notes are no longer convertible into shares of the Company’s common stock and thus, were not considered to be a potentially dilutive instrument as of September 30, 2020.

On June 17, 2020, the Company issued warrants to purchase up to an aggregate of approximately 5.9 million shares, or approximately five percent of its outstanding common stock, at an exercise price of $0.01 per share, as discussed in ~~Note 5 - Long-Term Debt. The Warrant Agreement dated as of June 17, 2020 (“Warrant Agreement”), states that the warrants are only exercisable upon the Triggering Date, as defined in~~ ~~Note 11 - Fair Value Measurements.~~ ~~The warrants were not exercisable during the three and nine months ended September 30, 2020, and therefore had 0 dilutive impact. Please refer to~~ ~~Note 11 - Fair Value Measurements~~ ~~for additional detail regarding the terms of the warrants.~~

~~As of September 30, 2020, potentially~~Potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and ~~warrants,~~the Warrants, which were measured using the treasury stock method. The Warrants became exercisable at the election of the holders on January 15, 2021, and as a result, they were included as potentially dilutive securities on an adjusted weighted-average basis for the portion of the three and six months ended June 30, 2021, for which

they were outstanding. Please refer toNote 3 - Equity and Note 7 - Compensation Plans ~~and~~ ~~Note 11 - Fair Value Measurements~~in this report, and Note 9 - Earnings Per Share in the ~~2019~~2020 Form 10-K for additional detail on these potentially dilutive securities.

When the Company recognizes a net loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share. The following table details the weighted-average number of anti-dilutive securities for the periods presented:

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2020 2019 2020 2019
(in thousands)
Anti-dilutive 158 0 450 707


	For the Three Months Ended June 30,		For the Six Months Ended June 30,
	2021	2020	2021	2020

	(in thousands)
Anti-dilutive	5,178	701	6,744	877

The following table sets forth the calculations of basic and diluted net ~~income (loss)~~loss per common share:


		For the Three Months Ended September 30,				For the Nine Months Ended September 30,					For the Three Months Ended June 30,				For the Six Months Ended June 30,
		2020		2019		2020		2019			2021		2020		2021		2020
		(in thousands, except per share data)
Net income (loss)		$	(98,292)	$	42,234	$	(599,439)	$	(84,946)
											(in thousands, except per share data)
Net loss										Net loss	$	(222,995)	$	(89,252)	$	(474,264)	$	(501,147)

Basic weighted-average common shares outstanding	Basic weighted-average common shares outstanding	114,371		112,804		113,462		112,441		Basic weighted-average common shares outstanding	118,357		113,008		116,568		113,015
Dilutive effect of non-vested RSUs and contingent PSUs	Dilutive effect of non-vested RSUs and contingent PSUs	0		530		0		0		Dilutive effect of non-vested RSUs and contingent PSUs	0		0		0		0

Dilutive effect of warrants										Dilutive effect of warrants	0		0		0		0
Diluted weighted-average common shares outstanding	Diluted weighted-average common shares outstanding	114,371		113,334		113,462		112,441		Diluted weighted-average common shares outstanding	118,357		113,008		116,568		113,015

Basic net income (loss) per common share		$	(0.86)	$	0.37	$	(5.28)	$	(0.76)
Diluted net income (loss) per common share		$	(0.86)	$	0.37	$	(5.28)	$	(0.76)
Basic net loss per common share										Basic net loss per common share	$	(1.88)	$	(0.79)	$	(4.07)	$	(4.43)
Diluted net loss per common share										Diluted net loss per common share	$	(1.88)	$	(0.79)	$	(4.07)	$	(4.43)

Note 10 - Derivative Financial Instruments

Summary of Oil, Gas, and NGL Derivative Contracts in Place

The Company ~~has entered~~regularly enters into ~~various~~ commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. As of ~~September~~June 30, ~~2020,~~2021, all derivative counterparties were members of the Company’s Credit Agreement lender group and all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap and collar arrangements for oil production and NGL production, and swap arrangements for gas ~~and NGL~~ production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. For collar arrangements, the Company receives the difference between an agreed upon index price and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices.

The Company has entered into fixed price oil basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where the Company’s production volumes are sold. Currently, the Company has basis swap contracts with fixed price differentials between ~~New York Mercantile Exchange (“NYMEX”)~~NYMEX WTI and WTI Midland for a portion of its Midland Basin production with sales contracts that settle at WTI Midland prices, ~~and basis swap contracts with fixed price differentials between~~ NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a portion of its Midland Basin oil production with sales contracts that settle at ICE Brent prices, and between NYMEX WTI and Argus WTI Houston Magellan East Houston Terminal (“MEH”) for a portion of its South Texas oil production with sales contracts that settle at Argus WTI Houston MEH prices. The Company has also entered into crude oil swap contracts to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (“Roll Differential”) in which the Company pays the periodic variable Roll Differential and receives a weighted-average fixed price differential. The weighted-average fixed price differential represents the amount of net addition (reduction) to delivery month prices for the notional volumes covered by the swap contracts.

As of ~~September~~June 30, ~~2020,~~2021, the Company had commodity derivative contracts outstanding through the fourth quarter of ~~2022~~2023 as summarized in the tables below.

~~Oil Swaps~~

Contract Period
NYMEX WTI Volumes
Weighted-Average
Contract Price
(MBbl) (per Bbl)
Fourth quarter 2020 4,397 $ 57.03
2021 17,115 $ 40.38
2022 3,885 $ 43.58
Total 25,397

~~Oil Collars~~

Contract Period NYMEX WTI Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price
(MBbl) (per Bbl) (per Bbl)
Fourth quarter 2020 610 $ 55.00 $ 61.90
2021 551 $ 48.97 $ 51.96
Total 1,161

~~Oil Basis Swaps~~

Contract Period WTI Midland-NYMEX WTI Volumes
Weighted-Average
Contract Price (1)
NYMEX WTI-ICE Brent Volumes
Weighted-Average Contract Price (2)
(MBbl) (per Bbl) (MBbl) (per Bbl)
Fourth quarter 2020 4,087 $ (0.38) 920 $ (8.01)
2021 13,975 $ 0.75 3,650 $ (7.86)
2022 9,500 $ 1.15 3,650 $ (7.78)
Total 27,562 8,220


	Contract Period
	Q3 2021		Q4 2021		2022		2023
Oil Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
NYMEX WTI Volumes	5,363		4,744		7,823		1,190
Weighted-Average Contract Price	$	41.16	$	39.85	$	44.69	$	45.20
Collars
NYMEX WTI Volumes	0		0		1,721		0
Weighted-Average Floor Price	$	0	$	0	$	51.84	$	0
Weighted-Average Ceiling Price	$	0	$	0	$	58.37	$	0
Basis Swaps
WTI Midland-NYMEX WTI Volumes	3,756		3,824		9,500		0
Weighted-Average Contract Price (1)	$	0.75	$	0.71	$	1.15	$	0
NYMEX WTI-ICE Brent Volumes	920		920		3,650		0
Weighted-Average Contract Price (2)	$	(7.86)	$	(7.86)	$	(7.78)	$	0
WTI Houston MEH-NYMEX WTI Volumes	356		466		1,329		0
Weighted-Average Contract Price (3)	$	0.60	$	0.60	$	1.25	$	0
Roll Differential Swaps
NYMEX WTI Volumes	4,326		3,831		11,278		1,832
Weighted-Average Contract Price	$	(0.18)	$	(0.16)	$	0.11	$	0.39

Gas Derivatives (volumes in BBtu and prices in $ per MMBtu):
Swaps (4)
IF HSC Volumes	12,575		12,412		28,932		0
Weighted-Average Contract Price	$	2.40	$	2.41	$	2.52	$	0
WAHA Volumes	8,086		7,627		14,087		0
Weighted-Average Contract Price	$	1.88	$	1.82	$	2.32	$	0
IF Tenn TX Z0	0		0		513		0
Weighted-Average Contract Price	$	0	$	0	$	3.22	$	0

NGL Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
OPIS Propane Mont Belvieu Non-TET Volumes	854		824		461		0
Weighted-Average Contract Price	$	22.16	$	22.15	$	27.19	$	0
OPIS Normal Butane Mont Belvieu Non-TET Volumes	37		36		0		0
Weighted-Average Contract Price	$	30.87	$	30.87	$	0	$	0
Collars
OPIS Propane Mont Belvieu Non-TET Volumes	0		0		627		0
Weighted-Average Floor Price	$	0	$	0	$	23.83	$	0
Weighted-Average Ceiling Price	$	0	$	0	$	29.19	$	0

(1) Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma).

(2) Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea).

~~Oil Roll Differential Swaps~~(3) Represents the price differential between Argus WTI Houston MEH (Houston, Texas) and NYMEX WTI (Cushing, Oklahoma).

Contract Period
NYMEX WTI Volumes Weighted-Average
Contract Price
(MBbl) (per Bbl)
Fourth quarter 2020 2,503 $ (1.18)
2021 6,058 $ (0.40)
Total 8,561

~~Gas Swaps~~

Contract Period IF HSC Volumes Weighted-Average
Contract Price WAHA Volumes Weighted-Average Contract Price
(BBtu) (per MMBtu) (BBtu) (per MMBtu)
Fourth quarter 2020 9,327 $ 2.39 4,872 $ 1.21
2021 47,800 $ 2.42 25,155 $ 1.67
2022 6,104 $ 2.23 5,904 $ 2.10
Total (1)
63,231 35,931

~~(1)~~(4) The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas, ~~(“IF WAHA”),~~ and Platt’s Gas Daily West Texas (“GDIF WAHA” and “GD WAHA”, respectively, and together “WAHA”), and Inside FERC Tennessee Texas, Zone 0 (“IF Tenn TX Z0”). As of ~~September~~June 30, ~~2020,~~2021, WAHA volumes were comprised of 6470 percent IF WAHA and 3630 percent GD WAHA.

~~NGL Swaps~~

OPIS Propane Mont Belvieu Non-TET
Contract Period Volumes Weighted-Average Contract Price
(MBbl) (per Bbl)
Fourth quarter 2020 466 $ 22.29
2021 392 $ 19.74
Total 858

2220

Commodity Derivative Contracts Entered Into Subsequent to ~~September~~June 30, ~~2020~~2021

Subsequent to ~~September~~June 30, ~~2020,~~2021, the Company entered into the following commodity derivative contracts:

•fixed price NYMEX WTI oil swap contracts ~~for~~through the ~~second~~fourth quarter of 2021 for a total of ~~0.3~~0.4 MMBbl of oil production at a weighted-average contract price of ~~$42.53~~$70.09 per Bbl;

•fixed price GD WAHA gas swap contracts for the second and third quarters of 2021 for a total of 924 BBtu of gas production at a weighted-average contract price of $2.47 per MMBtu and for 2022 for a total of 2,911 BBtu of gas production at a weighted-average contract price of $2.46 per MMBtu;

•fixed price IF HSC gas swap contracts for the second quarter of 2021 for a total of 1,290 BBtu of gas production at a weighted-average contract price of $2.62 per MMBtu and for 2022 for a total of 15,015 BBtu of gas production at a weighted-average contract price of $2.58 per MMBtu; and

•a fixed price OPIS Propane Mont Belvieu Non-TET swap ~~contracts~~contract for ~~2021~~the second quarter of 2022 for a total of ~~0.9~~0.1 MMBbl of propane production at a ~~weighted-average~~ contract price of ~~$20.93~~$35.70 per Bbl.

Derivative Assets and Liabilities Fair Value

The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its commodity derivative contracts as hedging instruments. The fair value of the commodity derivative contracts was a net ~~asset~~liability of ~~$49.5~~$616.5 million and ~~$21.5~~$168.2 million as of ~~September~~June 30, ~~2020,~~2021, and December 31, ~~2019,~~2020, respectively.

The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category:


							As of June 30, 2021		As of December 31, 2020
		As of September 30, 2020		As of December 31, 2019
		(in thousands)					(in thousands)
Derivative assets:	Derivative assets:					Derivative assets:
Current assets	Current assets	$	128,046	$	55,184	Current assets	$	31,303	$	31,203
Noncurrent assets	Noncurrent assets	31,509		20,624		Noncurrent assets	13,534		23,150
Total derivative assets	Total derivative assets	$	159,555	$	75,808	Total derivative assets	$	44,837	$	54,353
Derivative liabilities:	Derivative liabilities:					Derivative liabilities:
Current liabilities	Current liabilities	$	76,969	$	50,846	Current liabilities	$	545,062	$	200,189
Noncurrent liabilities	Noncurrent liabilities	33,068		3,444		Noncurrent liabilities	116,273		22,331
Total derivative liabilities	Total derivative liabilities	$	110,037	$	54,290	Total derivative liabilities	$	661,335	$	222,520

Offsetting of Derivative Assets and Liabilities

As of ~~September~~June 30, ~~2020,~~2021, and December 31, ~~2019,~~2020, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets.

The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts:


											Derivative Assets as of				Derivative Liabilities as of
		Derivative Assets as of				Derivative Liabilities as of					June 30, 2021		December 31, 2020		June 30, 2021		December 31, 2020
		September 30, 2020		December 31, 2019		September 30, 2020		December 31, 2019
		(in thousands)									(in thousands)
Gross amounts presented in the accompanying balance sheets	Gross amounts presented in the accompanying balance sheets	$	159,555	$	75,808	$	(110,037)	$	(54,290)	Gross amounts presented in the accompanying balance sheets	$	44,837	$	54,353	$	(661,335)	$	(222,520)
Amounts not offset in the accompanying balance sheets	Amounts not offset in the accompanying balance sheets	(104,037)		(35,075)		104,037		35,075		Amounts not offset in the accompanying balance sheets	(44,370)		(53,598)		44,370		53,598
Net amounts	Net amounts	$	55,518	$	40,733	$	(6,000)	$	(19,215)	Net amounts	$	467	$	755	$	(616,965)	$	(168,922)

2321

The following table summarizes the commodity components of the derivative settlement (gain) loss, as well as the components of the net derivative (gain) loss line item presented in the accompanying statements of operations:


											For the Three Months Ended June 30,				For the Six Months Ended June 30,
		For the Three Months Ended September 30,				For the Nine Months Ended September 30,					2021		2020		2021		2020
		2020		2019		2020		2019
		(in thousands)									(in thousands)
Derivative settlement (gain) loss:	Derivative settlement (gain) loss:									Derivative settlement (gain) loss:
Oil contracts	Oil contracts	$	(68,907)	$	2,246	$	(261,095)	$	14,304	Oil contracts	$	134,298	$	(138,606)	$	190,627	$	(192,188)
Gas contracts	Gas contracts	(896)		(12,210)		(16,575)		(13,744)		Gas contracts	12,232		(1,054)		52,680		(15,679)
NGL contracts	NGL contracts	(502)		(14,758)		(8,600)		(24,403)		NGL contracts	12,292		(2,868)		23,400		(8,098)
Total net derivative settlement gain		$	(70,305)	$	(24,722)	$	(286,270)	$	(23,843)
Total net derivative settlement (gain) loss										Total net derivative settlement (gain) loss	$	158,822	$	(142,528)	$	266,707	$	(215,965)

Net derivative (gain) loss:	Net derivative (gain) loss:									Net derivative (gain) loss:
Oil contracts	Oil contracts	$	30,641	$	(83,984)	$	(360,649)	$	67,261	Oil contracts	$	277,215	$	151,250	$	543,030	$	(391,290)
Gas contracts	Gas contracts	31,548		(4,228)		46,537		(36,337)		Gas contracts	61,364		8,261		110,286		14,989
NGL contracts	NGL contracts	1,682		(12,677)		(157)		(34,387)		NGL contracts	31,769		7,689		61,721		(1,839)
Total net derivative (gain) loss	Total net derivative (gain) loss	$	63,871	$	(100,889)	$	(314,269)	$	(3,463)	Total net derivative (gain) loss	$	370,348	$	167,200	$	715,037	$	(378,140)

Credit Related Contingent Features

As of ~~September~~June 30, ~~2020,~~2021, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on assets having a value equal to at least 85 percent of the total PV-9, as defined in the Credit Agreement, of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit Agreement also secures the Company’s derivative agreement obligations.

~~Note 11 - Fair Value Measurements~~

•~~Level 1 – quoted prices in active markets for identical assets or liabilities~~

•~~Level 3 – significant inputs to the valuation model are unobservable.~~

Level 1 Level 2 Level 3
(in thousands)
Assets:
Derivatives (1)
$ 0 $ 159,555 $ 0
Liabilities:
Derivatives (1)
$ 0 $ 110,037 $ 0

~~(1)~~ ~~This represents a financial asset or liability that is measured at fair value on a recurring basis.~~

Level 1 Level 2 Level 3
(in thousands)
Assets:
Derivatives (1)
$ 0 $ 75,808 $ 0
Liabilities:
Derivatives (1)
$ 0 $ 54,290 $ 0

~~(1)~~ ~~This represents a financial asset or liability that is measured at fair value on a recurring basis.~~

~~Derivatives~~

~~Please refer to~~ ~~Note 10 - Derivative Financial Instruments~~ ~~and to~~ ~~Note 11 - Fair Value Measurements~~ ~~in the~~ ~~2019 Form 10-K~~ ~~for more information regarding the Company’s derivative instruments.~~

~~Oil and Gas Properties and Other Property and Equipment~~

~~The Company had 0 assets included in total property and equipment, net, measured at fair value as of September 30, 2020, or December 31, 2019.~~

~~Proved oil and gas properties~~. Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses an income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties using a discount rate, price and cost forecasts, and certain reserve risk-adjustment factors, as selected by the Company’s management. The Company uses a discount rate that represents a current market-based weighted average cost of capital. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using Oil Price Information Service (“OPIS”) Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Certain undeveloped reserve estimates are also risk-adjusted given the risk to related projected cash flows due to performance and exploitation uncertainties.

~~Other Property and Equipment.~~ Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. To measure the fair value of other property and equipment, the Company uses an income valuation technique or market approach depending on the quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and unproved assets supported by the property and equipment, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets.

NaN proved property impairment expense was recorded during the three months ended September 30, 2020. For the nine months ended September 30, 2020, the Company recorded impairment expense of $956.7 million related to its South Texas proved oil and gas properties and related support facilities due to the decrease in commodity price forecasts at the end of the first quarter of 2020, specifically decreases in oil and NGL prices. The Company used a discount rate of 11 percent in its calculation of the present value of expected future cash flows based on the prevailing market-based weighted average cost of capital as of March 31, 2020. NaN proved property impairment expense was recorded during the three or nine months ended September 30, 2019.

~~The following table presents impairment of oil and gas properties expense and abandonment and impairment of unproved properties expense recorded during the periods presented:~~

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2020 2019 2020 2019
(in millions)
Impairment of proved oil and gas properties and related support equipment $ 0 $ 0 $ 956.7 $ 0
Abandonment and impairment of unproved properties (1)
8.8 6.3 50.6 25.1
Impairment $ 8.8 $ 6.3 $ 1,007.3 $ 25.1

~~(1)~~ These impairments related to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. The balances in the unproved oil and gas properties line item on the accompanying balance sheets as of September 30, 2020, and December 31, 2019, are recorded at carrying value.

~~Please refer to~~ ~~Note 1 - Summary of Significant Accounting Policies~~ ~~and~~ ~~Note 11 - Fair Value Measurements~~ ~~in the~~ ~~2019 Form 10-K~~ ~~for more information regarding the Company’s approach in determining the fair value of its properties.~~

~~Long-Term Debt~~

The following table reflects the fair value of the Company’s Senior Note obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of September 30, 2020, or December 31, 2019, as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to ~~Note 5 - Long-Term Debt~~ ~~for additional discussion.~~

As of September 30, 2020 As of December 31, 2019
Principal Amount Fair Value Principal Amount Fair Value
(in thousands)
6.125% Senior Unsecured Notes due 2022 $ 231,881 $ 182,027 $ 476,796 $ 481,564
5.0% Senior Unsecured Notes due 2024 $ 315,633 $ 173,655 $ 500,000 $ 479,815
5.625% Senior Unsecured Notes due 2025 $ 349,118 $ 162,228 $ 500,000 $ 475,835
6.75% Senior Unsecured Notes due 2026 $ 419,235 $ 192,659 $ 500,000 $ 494,860
6.625% Senior Unsecured Notes due 2027 $ 416,791 $ 185,964 $ 500,000 $ 493,750
10.0% Senior Secured Notes due 2025 $ 446,675 $ 426,820 $ 0 $ 0
1.50% Senior Convertible Notes due 2021 (1)
$ 0 $ 0 $ 172,500 $ 164,430
1.50% Senior Secured Convertible Notes due 2021 (1)
$ 65,485 $ 61,195 $ 0 $ 0

~~(1)~~ ~~The Company’s 2021 Senior Convertible Notes became secured in the second quarter of 2020 upon the closing of the Exchange Offers. Please refer to~~ ~~Note 5 - Long-Term Debt~~ ~~for additional information.~~

~~The carrying value of the Company’s revolving credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market rates.~~

~~Warrants~~

~~As discussed in~~ ~~Note 5 - Long-Term Debt~~, on June 17, 2020, the Company issued warrants to purchase up to an aggregate of approximately 5.9 million shares, or approximately five percent of its outstanding common stock, at an exercise price of $0.01 per share. The warrants are exercisable any time from and after the Triggering Date, as subsequently defined, until June 30, 2023. The Triggering Date is defined by the Warrant Agreement as the first trading day following five consecutive trading days on which the product of the number of shares of common stock issued and outstanding on four of the five trading days multiplied by the closing price per share of common stock for each such trading day exceeds $1.0 billion (“Triggering Date”). The warrants issued are indexed to the Company’s common stock and are required to be settled through physical settlement or net share settlement if exercised. The warrants were not exercisable during the nine months ended September 30, 2020, and through the filing of this report.

The fair value of the warrants on the issuance date was determined using a stochastic Monte Carlo simulation using the GBM Model. The Company evaluated the warrants under authoritative accounting guidance and determined that they should be classified as

equity instruments. Upon issuance, the warrants were recorded in additional paid-in capital on the accompanying balance sheets at a fair value of $21.5 million, with no recurring fair value measurement required. There have been no changes to the initial carrying amount of the warrants since issuance.

~~Note 12 - Leases~~

ASC Topic 842 - Leases (“Topic 842”), requires lessees to recognize operating and finance leases with terms greater than 12 months on the balance sheet. As of September 30, 2020, the Company did not have any agreements in place that were classified as finance leases under Topic 842. Arrangements classified as operating leases are included on the accompanying balance sheets within the other noncurrent assets, other current liabilities, and other noncurrent liabilities line items.

As outlined in Topic 842, a right-of-use (“ROU”) asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. Excluded from the initial measurement are certain variable lease payments, which for the Company’s drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs. Subsequent to initial measurement, costs associated with the Company’s operating leases are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset and in accordance with GAAP requirements.

~~Please refer to~~ ~~Note 12 - Leases~~ ~~in the~~ ~~2019 Form 10-K~~ ~~for more information regarding the Company's policy on leases, and assumptions and judgments made in the initial and subsequent measurement of lease ROU assets and corresponding liabilities.~~

Currently, the Company has operating leases for asset classes that include office space, office equipment, drilling rigs, midstream agreements, vehicles, and equipment rentals used in field operations. For those operating leases included on the accompanying balance sheets, which only includes leases with terms greater than 12 months at commencement, remaining lease terms range from less than one year to approximately six years. The weighted-average lease term remaining for these leases is approximately three years. Certain leases also contain optional extension periods that allow for terms to be extended for up to an additional 10 years. An early termination option also exists for certain leases, some of which allow for the Company to terminate a lease within one year. Exercising an early termination option may also result in an early termination penalty depending on the terms of the underlying agreement. Based on expectations for those agreements with early termination options, there are no leases in which material early termination options are reasonably certain to be exercised by the Company.

For the three months ended September 30, 2020, and 2019, total costs related to operating leases, including short-term leases, and variable lease payments made for leases with initial lease terms greater than 12 months, were $49.9 million and $107.3 million, respectively. For the nine months ended September 30, 2020, and 2019, total lease costs were $184.9 million and $422.4 million, respectively. These totals do not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. Components of the Company’s total lease cost, whether capitalized or expensed, for the three and nine months ended September 30, 2020, and 2019, consisted of the following:

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2020 2019 2020 2019
(in thousands)
Operating lease cost $ 3,364 $ 8,344 $ 14,651 $ 28,802
Short-term lease cost (1)
27,787 72,874 107,989 309,876
Variable lease cost (2)
18,787 26,090 62,257 83,696
Total lease cost $ 49,938 $ 107,308 $ 184,897 $ 422,374

~~(1)~~ Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected that this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements.

~~(2)~~ Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding liability for lease agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain midstream agreements, actual usage associated with drilling rigs, completion crews, and vehicles, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes delivered and the number of drilling rigs and completion crews operating under long-term agreements.

Right-of-use assets obtained in exchange for new operating lease liabilities totaled 0 and $745,000 for the three and nine months ended September 30, 2020, respectively, and $1.3 million and $24.0 million for the three and nine months ended September 30, 2019, respectively.

~~Cash paid for amounts included in the measurement of lease liabilities for the nine months ended September 30, 2020, and 2019, was as follows:~~

For the Nine Months Ended September 30,
2020 2019
(in thousands)
Operating cash flows from operating leases $ 9,074 $ 9,029
Investing cash flows from operating leases $ 6,751 $ 20,256

~~Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of September 30, 2020, were as follows:~~

As of September 30, 2020
(in thousands)
2020 (remaining after September 30, 2020) $ 3,546
2021 12,855
2022 5,920
2023 3,596
2024 2,081
Thereafter 1,640
Total Lease payments $ 29,638
Less: Imputed interest (1)
(2,856)
Total $ 26,782

~~(1)~~ ~~The weighted-average discount rate used to determine the operating lease liability as of September 30, 2020, was 6.9 percent.~~

~~Amounts recorded on the accompanying balance sheets for operating leases as of September 30, 2020, and December 31, 2019, were as follows:~~

As of September 30, 2020 As of December 31, 2019
(in thousands)
Other noncurrent assets $ 24,728 $ 39,717
Other current liabilities $ 12,311 $ 19,189
Other noncurrent liabilities $ 14,471 $ 23,137

~~As of September 30, 2020, and through the filing of this report, the Company has no material lease arrangements which are scheduled to commence in the future.~~

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion includes forward-looking statements. Please refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements. Additionally, the following discussion includes sequential quarterly comparison to financial information presented in our Quarterly Report on Form 10-Q for the qu arter ended March 31, 2021, filed with the SEC on April 30, 2021. Throughout the following discussion, we explain changes between the three months ended June 30, 2021, compared with the three months ended March 31, 2021 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the six months ended June 30, 2021, compared with the same period in 2020 (“YTD 2021-over-YTD 2020”).

Overview of the Company

General Overview

Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our ~~long-term~~ vision is to be a premier operator of top tier assets and to sustainably grow value for all of our stakeholders. ~~We believe~~This includes short-term operational and financial goals of generating positive cash flows while strengthening our balance sheet through absolute debt reduction and improved leverage metrics, and increasing the value of our capital project inventory through exploration and development optimization. Our long-term goal is to deliver cash flow growth that ~~in order~~is supported by our high-quality asset base and ability to ~~accomplish this vision, we must be a premier operator of top tier assets.~~generate favorable returns. Our investment portfolio is ~~currently focused on high quality~~comprised of oil and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in the Maverick Basin of South Texas.

~~Areas of Operations~~

~~Our Midland Basin assets~~We are located in the Permian Basin in West Texas and are comprised of approximately 80,000 net acres (“Midland Basin”). In the third quarter of 2020, we focused on continuing to delineate, develop, and expand our Midland Basin position. Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations.

Our South Texas assets are comprised of approximately 159,000 net acres located in Dimmit and Webb Counties, Texas (“South Texas”). Our current operations in South Texas are focused on developing the Eagle Ford shale formation and delineating the Austin Chalk formation. Our overlapping acreage position in the Eagle Ford shale and Austin Chalk formations includes acreage in oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.

~~Third Quarter 2020 Overview and Outlook for the Remainder of 2020~~

The impacts of the Pandemic on supply and demand for oil, gas, and NGLs continue to be unpredictable. Given the dynamic nature of the Pandemic, we are unable to reasonably estimate the period of time that these market conditions will exist or the extent to which they will continue to impact our business, results of operations, and financial condition, or the timing of any subsequent recovery. Future case surges or outbreaks could have further negative impacts, and as a result, we may be required to adjust our business plan. For additional detail, please refer to ~~Risk Factors~~ in~~Part II, Item 1A of this report and those risk factors previously disclosed in our~~ ~~2019 Form 10-K~~.

During the third quarter of 2020, the Pandemic and associated macroeconomic events continued to affect the realized prices we received for our production, and we expect these impacts to continue for the remainder of the year. Despite continuing negative impacts and future uncertainty, we expect to maintain our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our top tier Midland Basin and South Texas assets. During the third quarter of 2020, we repurchased $62.5 million and $29.0 million in aggregate principal amount of our 2022 Senior Notes and 2024 Senior Notes, respectively, while also reducing the balance on our revolving credit facility by $15.0 million from June 30, 2020 to September 30, 2020. Please refer to ~~Note 5 - Long-Term Debt~~ in Part I, Item 1 of this report for additional discussion. Our financial risk management program has significantly reduced the impact of substantially lower oil prices in 2020, and as a result of this program we recorded an oil derivative settlement gain of $15.16 per barrel for the nine months ended September 30, 2020. Our realized oil price before the effects of derivative settlements was $35.92 for the nine months ended September 30, 2020. As of September 30, 2020, a majority of our expected oil production for the remainder of 2020 is covered by derivative contracts at weighted-average NYMEX equivalent prices greater than $56.00 per barrel. Please refer to ~~Oil, Gas, and NGL Prices~~ below for additional detail on our financial risk management program and the pricing effects of our derivative settlements. Additionally, in response to the current economic environment, we have renegotiated certain contracts resulting in realized and future cost savings that directly support our objective of maximizing cash flows. As a result of these cost saving measures and improving operational efficiencies, we expect average well costs for 2020 to be lower than our preliminary expectations for the year.

We believe that sustainability is critical to positioning ourselves financially to participate in future energy investment opportunities and executing our strategy of being a premier operator with high standards for corporate responsibility. We remain committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive ~~difference~~impact in the communities where we live and work; and transparency in reporting on our progress in these areas. The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the development and implementation of the Company’s environmental, social and governance policies, programs and initiatives, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations, compensation for our executives and eligible employees under our long-term incentive plans, and compensation for all employees under our short-term incentive plans is calculated based on certain Company-wide performance-based metrics that include key financial, operational, and environmental, health, and safety measures.

Areas of Operations

Our Midland Basin assets are comprised of approximately 81,000 net acres located in the Permian Basin in West Texas (“Midland Basin”). In the second quarter of 2021, drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continued to focus primarily on delineating, developing, and expanding our Midland Basin position. Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations.

Our South Texas assets are comprised of approximately 155,000 net acres located in the Maverick Basin in Dimmit and Webb Counties, Texas (“South Texas”). Our current operations in South Texas are focused on production from both the Eagle Ford shale formation and Austin Chalk formation and further delineation and development of the Austin Chalk formation. Our overlapping acreage position in the Eagle Ford shale and Austin Chalk formations includes acreage in oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction. 2021 capital activity in South Texas has been, and will continue to be, concentrated on the Austin Chalk formation given the favorable economics we achieve from a higher oil and NGL product mix.

Second Quarter 2021 Overview and Outlook for the Remainder of 2021

During the second quarter of 2021, we issued $400.0 million in aggregate principal amount of our 2028 Senior Notes and we used the net proceeds to repurchase $193.1 million and $172.3 million of outstanding principal amount of our 2022 Senior Notes and 2024 Senior Notes, respectively, through the Tender Offer, and to redeem the remaining $19.3 million of 2022 Senior Notes outstanding through the 2022 Senior Notes Redemption. We paid total consideration, excluding accrued interest, of $385.3 million, and recorded a loss on extinguishment of debt of $2.1 million for the three months ended June 30, 2021, which included $1.5 million of accelerated unamortized deferred financing costs and $600,000 of net premiums. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

The Pandemic remains a global health crisis, and while the United States has seen substantial improvements in public health and macroeconomic measures in recent months, and has deployed vaccinations to prevent the spread of the COVID-19 virus, stability in the markets and demand for the commodities produced by our industry have not returned to pre-Pandemic levels, and may not for some time. The impacts of the Pandemic continue to be unpredictable and dynamic, so we are unable to reasonably estimate the period of time that related market conditions could exist or the extent to which they could continue to impact our business, results of operations, financial condition, or the timing of further recovery. Commodity prices have improved from historic lows in 2020, however,

future case surges or outbreaks, and COVID-19 virus variants, could have further negative impacts, and as a result, may require us to adjust our business plan. For additional detail, please refer to the Risk Factors section in Part I, Item 1A of our 2020 Form 10-K. Despite continuing impacts of the Pandemic and future uncertainty, we expect to maintain our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our top tier Midland Basin and South Texas assets.

The safety of our employees, contractors, and the communities where we work isremains our first priority as we continue to operate during the Pandemic. While ~~the execution of~~ our core business operations ~~requires~~require certain individuals to be physically present at well

site locations, ~~substantially all~~the vast majority of our office-based employees have continued working remotely in order to limit physical interactions and to mitigate the spread of COVID-19. For individuals who are unable to perform their jobs remotely, we maintain and continually assess procedures designed to limit the spread of COVID-19, including social distancing and enhanced sanitization measures, and we continue to communicate to and train all of our employees regarding best practices for maintaining a healthy and safe work environment. We believe that we meet or exceed Centers for Disease Control and Prevention and federal Occupational Safety and Health Act guidelines related to the prevention of the transmission of COVID-19. Since these measures were initially implemented in the first quarter of 2020, we have continued to operate without significant disruptions to our business operations. Our pre-existing control environment and internal controls ~~continue~~have continued to be effective and we ~~continue~~have continued to address new risks directly related to the Pandemic as we identify them.

~~The information below summarizes our operating and financial performance and our expectations for the remainder of 2020.~~

~~We entered 2020 with a~~Our 2021 total capital program budget is between ~~$825~~$650.0 million and ~~$850~~$675.0 million. ~~However, given the Pandemic and related circumstances discussed above, we reduced our 2020 capital program by approximately 25 percent for the full year 2020.~~ Our financial and operational flexibility allows us to continually monitor the economic environment and adjust our activity level as warranted. Our ~~2020~~2021 capital program remains focused on ~~developing and retaining our most~~highly economic oil development projects in both our Midland Basin assets and South Texas assets. Based on the current macroeconomic environment, we believe our assets provide strong returns and are capable of providing for growth of internally generated cash flows while allowing for flexibility of production levels, which aligns with our priorities of improving leverage metrics and maintaining strong financial flexibility. Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund our ~~2020~~2021 capital program.

Financial and Operational Results. Average net daily equivalent production for the three months ended ~~September~~June 30, ~~2020,~~2021, was ~~126.3~~136.5 MBOE ~~compared with 134.9 MBOE for~~and increased 22 percent sequentially as the ~~same period in 2019. This decrease~~first quarter of 2021 was ~~driven~~impacted by a ~~22 percent decrease~~significant weather event in ~~production volumes from our South~~the state of Texas ~~assets, partially offset by a seven percent increase~~that lasted for several days in ~~production volumes from our Midland Basin assets. The overall decrease~~February 2021, which included abnormally low temperatures and freezing conditions, and resulted in production volumes for the three months ended September 30, 2020, was primarily due to fewer net well completions during the nine months ended September 30, 2020, compared with the same period in 2019, as we reduced capital expenditures in response to lowerwidespread power outages (“Texas Weather Event”).

Strengthening benchmark commodity prices in ~~2020. Realized~~the second quarter of 2021 resulted in increases in realized prices, ~~before the effects of derivative settlements~~as defined below, for oil ~~gas,~~ and NGLs ~~decreased 30 percent, 12~~of 16 percent and 11five percent, respectively, for the three months ended ~~September~~June 30, ~~2020,~~2021, compared with the ~~same period~~three months ended March 31, 2021. The supply and demand imbalance caused by the Texas Weather Event inflated realized prices for gas in ~~2019. As~~the first quarter of 2021, which resulted in a ~~result of decreased production and pricing,~~20 percent decrease in realized prices for the three months ended June 30, 2021, compared with the three months ended March 31, 2021. Total realized price per BOE increased eight percent for the three months ended June 30, 2021, compared with the three months ended March 31, 2021. This increase resulted in oil, gas, and NGL production revenue ~~decreased 28 percent to $282.0~~of $562.6 million for the three months ended ~~September~~June 30, ~~2020, from $389.4 million for the same period in 2019.~~

~~We recorded a net derivative loss of $63.9 million and a net derivative gain of $100.9~~2021, compared with $423.2 million for the three months ended ~~September 30, 2020, and 2019, respectively. Included within these derivative amounts is a gain~~March 31, 2021, which was an increase of ~~$70.3 million on derivative contracts that settled during the three months ended September 30, 2020, and a gain of $24.7 million for the same period in 2019. Total production~~33 percent. Production costs ~~on a~~ per BOE ~~basis decreased 21 percent to $8.20 per BOE~~of $10.10 for the three months ended ~~September~~June 30, ~~2020, from $10.41 per BOE~~2021, were flat compared with the three months ended March 31, 2021.

We recorded net derivative losses of $370.3 million and $344.7 million for the ~~same period in 2019.~~ three months ended June 30, 2021, and March 31, 2021, respectively. Included within these amounts are realized derivative settlement losses of $158.8 million and $107.9 million for the three months ended June 30, 2021, and March 31, 2021, respectively, resulting from increased commodity prices.

Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2021, and March 31, 2021, and Between the Six Months Ended June 30, 2021, and 2020 below for additional discussion.

Financial and operational activities during the three months ended ~~September~~June 30, ~~2020,~~2021, resulted in the following:

•~~a $103.1 million decrease in our total outstanding long-term debt balance from June 30, 2020, to September 30, 2020, primarily driven by net~~Net cash provided by operating activities of ~~$201.6~~$296.4 million for the three months ended ~~September~~June 30, ~~2020, which was in excess of net cash used in investing activities of $116.6~~2021, compared with $105.6 million for the three months ended ~~September 30, 2020;~~March 31, 2021. The sequential quarterly increase was primarily a result of changes in working capital.

•A net loss of ~~$98.3~~$223.0 million, or ~~$0.86~~$1.88 per diluted share, for the three months ended ~~September~~June 30, ~~2020,~~2021, compared with a net ~~income~~loss of ~~$42.2~~$251.3 million, or ~~$0.37~~$2.19 per diluted share, for the ~~same period in 2019.~~three months ended March 31, 2021. The net loss for the three months ended ~~September~~June 30, ~~2020,~~2021, was primarily due to a ~~$134.2~~$370.3 million ~~downward mark-to-market adjustment on our commodity~~net derivative ~~contracts.~~loss. Please refer to Comparison of Financial Results and Trends Between the Three ~~and Nine~~ Months Ended ~~September~~June 30, ~~2020,~~2021, and ~~2019~~March 31, 2021, and Between the Six Months Ended June 30, 2021, and 2020 below for additional discussion regarding the components of net ~~income (loss)~~loss for the periods ~~presented; and~~presented.

•~~adjusted~~Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended ~~September~~June 30, ~~2020,~~2021, was ~~$232.5~~$256.9 million, compared with ~~$257.8~~$215.0 million for the ~~same period in 2019.~~three months ended March 31, 2021. Please refer to the caption Non-GAAP

Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations of net ~~income (loss)~~loss and net cash provided by operating activities.

Operational Activities. The financial results and operational activity discussed throughout this report reflect the impacts of the Pandemic and the misalignment of supply and demand caused by competition among oil producing nations for crude oil market share. We will continue to monitor the economic environment through the remainder of the year and maintain flexibility to make related financial and operational adjustments as warranted.

In our Midland Basin program, we operated ~~four~~three drilling rigs and ~~one~~averaged three completion ~~crew~~crews during the ~~third~~second quarter of ~~2020.~~2021. We drilled 2314 gross ~~(19~~(11 net) wells and completed 2244 gross ~~(22~~(40 net) wells during the ~~third~~second quarter of ~~2020,~~2021, and ~~increased~~ production volumes ~~year-over-year~~increased sequentially by ~~seven~~22 percent to ~~7.1 MMBOE.~~8.3 MMBOE compared with the three months ended March 31, 2021. Costs incurred ~~for oil and gas producing activities~~ in our Midland Basin program during the three months ended ~~September~~June 30, ~~2020,~~2021, totaled ~~$120.4~~$155.9 million, or 89 percent of our total costs incurred for the period. We plan to operate between three and four drilling rigs and between one and two completion crews for the remainder of the year. Drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continue to focus primarily on delineating and developing the Lower Spraberry and Wolfcamp shale intervals.

In our South Texas program, we entered the third quarter of 2020 with no drilling rigs and we began operating one drilling rig in September. We completed two gross (two net) wells during the third quarter of 2020. Production volumes for the third quarter of 2020 decreased 22 percent year-over-year. While natural decline and our deferral of activity led to a decrease in total production volumes, oil production volumes increased 40 percent year-over-year as a result of the higher liquids content from our Austin Chalk completions. Costs incurred for oil and gas producing activities in our South Texas program during the three months ended September 30, 2020, totaled $7.2 million, or five69 percent of our total costs incurred for the period. We anticipate operating between two and three drilling rigs and between one and two completion crews at times during the remainder of 2021, focused primarily on delineating and developing the Spraberry and Wolfcamp formations within our RockStar and Sweetie Peck positions in the Midland Basin.

In our South Texas program, we operated two drilling ~~rig~~rigs and one completion crew at times during the ~~remainder~~second quarter of ~~2020~~2021. We drilled 11 gross (11 net) wells and completed five gross (five net) wells during the second quarter of 2021, and production volumes increased sequentially by 28 percent to 4.1 MMBOE compared with the three months ended March 31, 2021. Costs incurred in ~~South Texas. Drilling and completion activities in~~our South Texas program during the three months ended June 30, 2021, totaled $59.5 million, or 26 percent of our total costs incurred for the period. We anticipate operating between one and two drilling rigs and one completion crew during the remainder of ~~2020 will be~~2021, focused primarily on delineating and developing the Austin Chalk formation.

The table below provides a quarterly summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020:~~2021:


		Midland Basin		South Texas		Total			Midland Basin		South Texas (2)		Total
		Gross	Net	Gross	Net	Gross	Net		Gross	Net	Gross	Net	Gross	Net
Wells drilled but not completed at December 31, 2019		51	48	21	21	72	69
Wells drilled but not completed at December 31, 2020								Wells drilled but not completed at December 31, 2020	66	58	31	28	97	86
Wells drilled	Wells drilled	25	22	3	3	28	25	Wells drilled	16	13	5	5	21	18
Wells completed	Wells completed	(19)	(19)	(1)	(1)	(20)	(20)	Wells completed	(16)	(14)	(6)	(3)	(22)	(17)
Other (1)	Other (1)	—	1	—	—	—	1	Other (1)	—	1	—	—	—	1
Wells drilled but not completed at March 31, 2020		57	52	23	23	80	75
Wells drilled but not completed at March 31, 2021								Wells drilled but not completed at March 31, 2021	66	58	30	30	96	88
Wells drilled	Wells drilled	25	23	4	4	29	27	Wells drilled	14	11	11	11	25	22
Wells completed	Wells completed	(13)	(10)	(1)	(1)	(14)	(11)	Wells completed	(44)	(40)	(5)	(5)	(49)	(45)

Wells drilled but not completed at June 30, 2020		69	65	26	26	95	91
Wells drilled		23	19	—	—	23	19
Wells completed		(22)	(22)	(2)	(2)	(24)	(24)
Other (1)		—	1	—	—	—	1
Wells drilled but not completed at September 30, 2020		70	63	24	24	94	87
Wells drilled but not completed at June 30, 2021								Wells drilled but not completed at June 30, 2021	36	29	36	36	72	65

(1) Includes adjustments related to normal business activities, including working interest changes for existing drilled but not completed wells. Working interest changes can result from divestitures, joint development agreements, farmouts, and other activities.

(2) The South Texas drilled but not completed well count as of each period end presented above includes 13 gross (13 net) wells that are not included in our five-year development plan, 12 of which are in the Eagle Ford shale.

Costs ~~Incurred in Oil and Gas Producing Activities.~~Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled ~~$135.7~~$224.6 million and ~~$437.1~~$417.2 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, respectively, and were primarily incurred in our Midland Basin and South Texas programs as further detailed in Operational Activities above.

Production Results. The table below presents our production by product type for each of our areas of operation for the ~~three months ended September 30,~~sequential quarterly periods and the YTD 2021-over-YTD 2020 ~~and 2019:~~periods:

Midland Basin South Texas Total
Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30,
2020 2019 2020 2019 2020 2019
Production:
Oil (MMBbl) 5.0 5.1 0.5 0.3 5.5 5.4
Gas (Bcf) 12.3 9.1 13.8 20.4 26.1 29.5
NGLs (MMBbl) — — 1.8 2.1 1.8 2.1
Equivalent (MMBOE) 7.1 6.6 4.5 5.8 11.6 12.4
Average net daily equivalent (MBOE/d) 76.9 71.7 49.3 63.2 126.3 134.9
Relative percentage 61 % 53 % 39 % 47 % 100 % 100 %

~~Note: Amounts may not calculate due to rounding.~~

~~The table below presents our production by product type for each of our areas of operation for the nine months ended September 30, 2020, and 2019:~~


		Midland Basin				South Texas				Total					For the Three Months Ended				For the Six Months Ended
		Nine Months Ended September 30,				Nine Months Ended September 30,				Nine Months Ended September 30,					June 30, 2021		March 31, 2021		June 30, 2021		June 30, 2020
		2020		2019		2020		2019		2020		2019
Production:
Midland Basin Production:														Midland Basin Production:
Oil (MMBbl)	Oil (MMBbl)	16.0		14.8		1.3		0.9		17.2		15.7		Oil (MMBbl)	6.2		5.1		11.3		10.9
Gas (Bcf)	Gas (Bcf)	34.0		24.4		44.6		57.3		78.6		81.7		Gas (Bcf)	12.8		10.6		23.4		21.7
NGLs (MMBbl)	NGLs (MMBbl)	—		—		4.8		6.2		4.8		6.2		NGLs (MMBbl)	—		—		—		—
Equivalent (MMBOE)	Equivalent (MMBOE)	21.6		18.8		13.5		16.7		35.2		35.5		Equivalent (MMBOE)	8.3		6.9		15.2		14.6
Average net daily equivalent (MBOE/d)		79.0		69.0		49.4		61.1		128.3		130.1
Average net daily equivalent (MBOE per day)														Average net daily equivalent (MBOE per day)	91.6		76.1		83.9		80.0
Relative percentage	Relative percentage	62	%	53	%	38	%	47	%	100	%	100	%	Relative percentage	67	%	68	%	68	%	62	%

South Texas Production:														South Texas Production:
Oil (MMBbl)														Oil (MMBbl)	0.5		0.3		0.8		0.8
Gas (Bcf)														Gas (Bcf)	13.6		11.0		24.6		30.8
NGLs (MMBbl)														NGLs (MMBbl)	1.3		1.0		2.4		3.1
Equivalent (MMBOE)														Equivalent (MMBOE)	4.1		3.2		7.3		9.0
Average net daily equivalent (MBOE per day)														Average net daily equivalent (MBOE per day)	44.9		35.5		40.2		49.4
Relative percentage														Relative percentage	33	%	32	%	32	%	38	%

Total Production:														Total Production:
Oil (MMBbl)														Oil (MMBbl)	6.7		5.4		12.1		11.7
Gas (Bcf)														Gas (Bcf)	26.5		21.5		48.0		52.5
NGLs (MMBbl)														NGLs (MMBbl)	1.3		1.0		2.4		3.1
Equivalent (MMBOE)														Equivalent (MMBOE)	12.4		10.0		22.5		23.6
Average net daily equivalent (MBOE per day)														Average net daily equivalent (MBOE per day)	136.5		111.6		124.2		129.4

Note: Amounts may not calculate due to rounding.

Please refer to ~~A Three Month and Nine Month~~ Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three ~~and Nine~~ Months Ended ~~September~~June 30, ~~2020,~~2021, and ~~2019~~March 31, 2021, and Between the Six Months Ended June 30, 2021, and 2020 below for discussion on production.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effects of derivative settlements, unless otherwise indicated. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, and transportation differentials and contracted pricing benchmarks for these products.

The following table summarizes commodity price data, as well as the effects of derivative settlements, for the ~~third~~three months ended June 30, 2021, March 31, 2021, and ~~second quarters of 2020 as well as the third quarter of 2019:~~June 30, 2020:


		For the Three Months Ended							For the Three Months Ended
		September 30, 2020		June 30, 2020		September 30, 2019			June 30, 2021		March 31, 2021		June 30, 2020
Oil (per Bbl):	Oil (per Bbl):							Oil (per Bbl):
Average NYMEX contract monthly price	Average NYMEX contract monthly price	$	40.93	$	27.85	$	56.45	Average NYMEX contract monthly price	$	66.07	$	57.84	$	27.85
Realized price, before the effect of derivative settlements	Realized price, before the effect of derivative settlements	$	37.69	$	22.25	$	53.99	Realized price, before the effect of derivative settlements	$	65.34	$	56.33	$	22.25
Effect of oil derivative settlements	Effect of oil derivative settlements	$	12.51	$	25.81	$	(0.41)	Effect of oil derivative settlements	$	(20.11)	$	(10.38)	$	25.81
Gas:	Gas:							Gas:
Average NYMEX monthly settle price (per MMBtu)	Average NYMEX monthly settle price (per MMBtu)	$	1.98	$	1.72	$	2.23	Average NYMEX monthly settle price (per MMBtu)	$	2.83	$	2.69	$	1.72
Realized price, before the effect of derivative settlements (per Mcf)	Realized price, before the effect of derivative settlements (per Mcf)	$	1.90	$	1.34	$	2.17	Realized price, before the effect of derivative settlements (per Mcf)	$	3.34	$	4.16	$	1.34
Effect of gas derivative settlements (per Mcf)	Effect of gas derivative settlements (per Mcf)	$	0.03	$	0.04	$	0.41	Effect of gas derivative settlements (per Mcf)	$	(0.46)	$	(1.88)	$	0.04
NGLs (per Bbl):	NGLs (per Bbl):							NGLs (per Bbl):
Average OPIS price (1)	Average OPIS price (1)	$	19.13	$	14.02	$	18.89	Average OPIS price (1)	$	31.52	$	30.47	$	14.02
Realized price, before the effect of derivative settlements	Realized price, before the effect of derivative settlements	$	14.07	$	10.43	$	15.73	Realized price, before the effect of derivative settlements	$	28.41	$	26.93	$	10.43
Effect of NGL derivative settlements	Effect of NGL derivative settlements	$	0.29	$	1.94	$	7.14	Effect of NGL derivative settlements	$	(9.22)	$	(10.79)	$	1.94

(1) �� Average OPIS price per barrel of NGL, historical or strip, assumes a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

~~During~~Given the ~~first nine months~~dynamic nature of ~~2020,~~the Pandemic, we expect future benchmark prices for oil, ~~were impacted by~~gas, and NGLs to remain volatile for the ~~misalignment~~foreseeable future, and we cannot reasonably predict the timing of ~~supply and demand caused by the Pandemic and other macroeconomic events.~~any further recovery or future infection rate surges or outbreaks. In addition to supply and demand fundamentals, as a global commodity, the price of oil is affected by real or perceived geopolitical risks in various regions of the world as well as the relative strength of the United States dollar compared to other currencies. ~~We expect future benchmark prices for oil, gas, and NGLs to remain depressed for~~

~~the foreseeable future due to the Pandemic and the misalignment of supply and demand.~~ Our realized prices at local sales points may also be affected by infrastructure capacity in the area of our operations and beyond. Please refer to ~~Third~~Second Quarter ~~2020~~2021 Overview and Outlook for the Remainder of ~~2020~~2021 above for additional discussion of factors impacting pricing.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of ~~October~~July 21, ~~2020,~~2021, and ~~September~~June 30, ~~2020:~~2021:


		As of October 21, 2020		As of September 30, 2020			As of July 21, 2021		As of June 30, 2021
NYMEX WTI oil (per Bbl)	NYMEX WTI oil (per Bbl)	$	41.13	$	41.53	NYMEX WTI oil (per Bbl)	$	67.29	$	69.99
NYMEX Henry Hub gas (per MMBtu)	NYMEX Henry Hub gas (per MMBtu)	$	3.13	$	2.84	NYMEX Henry Hub gas (per MMBtu)	$	3.69	$	3.48
OPIS NGLs (per Bbl)	OPIS NGLs (per Bbl)	$	20.22	$	19.46	OPIS NGLs (per Bbl)	$	34.64	$	35.61

We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives, and decisions regarding entering into commodity derivative contracts are overseen by a financial risk management committee consisting of certain of our senior executive officers and finance personnel. ~~The~~We make decisions about the amount of our expected production ~~covered~~that we cover by derivatives ~~is driven by~~based on the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and our ability to enter into favorable commodity derivative contracts. With our current commodity derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor for a portion of our oil and gas production. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report and to Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.

Financial Results of Operations and Additional Comparative Data

The tables below provide information regarding selected production and financial information for the three months ended ~~September~~June 30, ~~2020,~~2021, and the preceding three quarters.


											For the Three Months Ended
		For the Three Months Ended									June 30,		March 31,		December 31,		September 30,
		September 30,		June 30,		March 31,		December 31,			2021		2021		2020		2020
		2020		2020		2020		2019
		(in millions)									(in millions)
Production (MMBOE)	Production (MMBOE)	11.6		11.2		12.4		12.8		Production (MMBOE)	12.4		10.0		11.3		11.6
Oil, gas, and NGL production revenue	Oil, gas, and NGL production revenue	$	282.0	$	169.8	$	354.2	$	449.0	Oil, gas, and NGL production revenue	$	562.6	$	423.2	$	320.2	$	282.0
Oil, gas, and NGL production expense	Oil, gas, and NGL production expense	$	95.3	$	80.4	$	119.6	$	127.3	Oil, gas, and NGL production expense	$	125.5	$	100.9	$	96.0	$	95.3
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	181.7	$	180.9	$	233.5	$	228.7	Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	204.7	$	167.0	$	188.9	$	181.7
Exploration	Exploration	$	8.5	$	9.8	$	11.3	$	17.7	Exploration	$	8.7	$	9.3	$	11.3	$	8.5
General and administrative	General and administrative	$	24.5	$	27.2	$	27.4	$	37.2	General and administrative	$	24.6	$	24.7	$	20.0	$	24.5
Net loss	Net loss	$	(98.3)	$	(89.3)	$	(411.9)	$	(102.1)	Net loss	$	(223.0)	$	(251.3)	$	(165.2)	$	(98.3)

Note: Amounts may not calculate due to rounding.

Selected Performance Metrics


		For the Three Months Ended													For the Three Months Ended
		September 30,			June 30,			March 31,			December 31,				June 30,			March 31,			December 31,			September 30,
		2020			2020			2020			2019				2021			2021			2020			2020
Average net daily equivalent production (MBOE per day)	Average net daily equivalent production (MBOE per day)	126.3			122.9			135.9			138.8			Average net daily equivalent production (MBOE per day)	136.5			111.6			122.4			126.3
Lease operating expense (per BOE)	Lease operating expense (per BOE)	$	3.65		$	3.30		$	4.75		$	4.67		Lease operating expense (per BOE)	$	4.62		$	4.64		$	4.10		$	3.65
Transportation costs (per BOE)	Transportation costs (per BOE)	$	3.11		$	3.12		$	3.11		$	3.46		Transportation costs (per BOE)	$	3.01		$	2.94		$	2.89		$	3.11
Production taxes as a percent of oil, gas, and NGL production revenue	Production taxes as a percent of oil, gas, and NGL production revenue	4.3		%	3.7		%	4.2		%	4.2		%	Production taxes as a percent of oil, gas, and NGL production revenue	4.5		%	4.6		%	4.0		%	4.3		%
Ad valorem tax expense (per BOE)	Ad valorem tax expense (per BOE)	$	0.40		$	0.22		$	0.60		$	0.37		Ad valorem tax expense (per BOE)	$	0.45		$	0.52		$	0.38		$	0.40
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)	Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)	$	15.64		$	16.17		$	18.88		$	17.91		Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)	$	16.48		$	16.62		$	16.77		$	15.64
General and administrative (per BOE)	General and administrative (per BOE)	$	2.10		$	2.43		$	2.22		$	2.92		General and administrative (per BOE)	$	1.98		$	2.46		$	1.78		$	2.10

Note: Amounts may not calculate due to rounding.

3328

~~A Three Month and Nine Month~~ Overview of Selected Production and Financial Information, Including Trends


																						For the Three Months Ended						Amount Change Between Periods			Percent Change Between Periods					For the Six Months Ended								Amount Change Between Periods				Percent Change Between Periods
		For the Three Months Ended September 30,				Amount Change Between Periods		Percent Change Between Periods			For the Nine Months Ended September 30,						Amount Change Between Periods		Percent Change Between Periods			June 30,			March 31,									June 30,						June 30,
		2020		2019						2020			2019			2021							2021				2021												2020
Net production volumes: (1)	Net production volumes: (1)																							Net production volumes: (1)
Oil (MMBbl)	Oil (MMBbl)	5.5		5.4		0.1		2	%		17.2			15.7			1.5		10	%	Oil (MMBbl)	6.7			5.4					1.2			23		%			12.1					11.7				0.4				3		%
Gas (Bcf)	Gas (Bcf)	26.1		29.5		(3.4)		(12)	%		78.6			81.7			(3.1)		(4)	%	Gas (Bcf)	26.5			21.5				4.9			23		%			48.0					52.5				(4.5)				(9)		%
NGLs (MMBbl)	NGLs (MMBbl)	1.8		2.1		(0.3)		(15)	%		4.8			6.2			(1.4)		(22)	%	NGLs (MMBbl)	1.3			1.0			0.3			29		%			2.4					3.1				(0.7)				(23)		%
Equivalent (MMBOE)	Equivalent (MMBOE)	11.6		12.4		(0.8)		(6)	%		35.2			35.5			(0.4)		(1)	%	Equivalent (MMBOE)	12.4			10.0			2.4			24		%			22.5					23.6				(1.1)				(5)		%
Average net daily production: (1)	Average net daily production: (1)																				Average net daily production: (1)
Oil (MBbl per day)	Oil (MBbl per day)	59.9		59.0		0.9		2	%		62.9			57.5			5.4		9	%	Oil (MBbl per day)	73.4			60.3			13.1			22		%			66.9					64.4				2.5				4		%
Gas (MMcf per day)	Gas (MMcf per day)	283.3		320.6		(37.4)		(12)	%		286.7			299.2			(12.4)		(4)	%	Gas (MMcf per day)	290.9			239.4			51.6			22		%			265.3					288.5				(23.2)				(8)		%
NGLs (MBbl per day)	NGLs (MBbl per day)	19.2		22.5		(3.3)		(15)	%		17.7			22.8			(5.1)		(22)	%	NGLs (MBbl per day)	14.6			11.4			3.2			28		%			13.1					16.9				(3.9)				(23)		%
Equivalent (MBOE per day)	Equivalent (MBOE per day)	126.3		134.9		(8.6)		(6)	%		128.3			130.1			(1.8)		(1)	%	Equivalent (MBOE per day)	136.5			111.6			24.9			22		%			124.2					129.4				(5.2)				(4)		%
Oil, gas, and NGL production revenue (in millions): (1)	Oil, gas, and NGL production revenue (in millions): (1)																				Oil, gas, and NGL production revenue (in millions): (1)
Oil production revenue	Oil production revenue	$	207.6	$	292.9	$	(85.2)	(29)	%		$	618.9		$	836.1		$	(217.2)	(26)	%	Oil production revenue	$	436.4		$	305.8		$	130.6		43		%			$	742.1				$	411.2			$	330.9			80		%
Gas production revenue	Gas production revenue	49.6		64.0		(14.5)		(23)	%		125.1			194.4			(69.3)		(36)	%	Gas production revenue	88.3			89.7			(1.3)			(1)		%			178.0					75.6				102.4				136		%
NGL production revenue	NGL production revenue	24.8		32.5		(7.7)		(24)	%		62.1			106.3			(44.3)		(42)	%	NGL production revenue	37.9			27.7			10.1			37		%			65.6					37.2				28.4				76		%
Total oil, gas, and NGL production revenue	Total oil, gas, and NGL production revenue	$	282.0	$	389.4	$	(107.4)	(28)	%		$	806.0		$	1,136.7		$	(330.7)	(29)	%	Total oil, gas, and NGL production revenue	$	562.6		$	423.2		$	139.4		33		%			$	985.7				$	524.0			$	461.7			88		%
Oil, gas, and NGL production expense (in millions): (1)	Oil, gas, and NGL production expense (in millions): (1)																				Oil, gas, and NGL production expense (in millions): (1)
Lease operating expense	Lease operating expense	$	42.4	$	58.7	$	(16.3)	(28)	%		$	138.1		$	166.0		$	(27.9)	(17)	%	Lease operating expense	$	57.4		$	46.7		$	10.7		23		%			$	104.0				$	95.7			$	8.3			9		%
Transportation costs	Transportation costs	36.1		49.6		(13.5)		(27)	%		109.4			142.9			(33.5)		(23)	%	Transportation costs	37.4			29.6			7.8			26		%			66.9					73.3				(6.4)				(9)		%
Production taxes	Production taxes	12.1		16.0		(3.9)		(25)	%		33.2			46.1			(12.9)		(28)	%	Production taxes	25.2			19.5			5.7			29		%			44.7					21.1				23.5				111		%
Ad valorem tax expense	Ad valorem tax expense	4.7		4.8		(0.1)		(2)	%		14.6			18.4			(3.8)		(21)	%	Ad valorem tax expense	5.6			5.2			0.3			7		%			10.8					9.9				0.9				9		%
Total oil, gas, and NGL production expense	Total oil, gas, and NGL production expense	$	95.3	$	129.0	$	(33.8)	(26)	%		$	295.3		$	373.4		$	(78.1)	(21)	%	Total oil, gas, and NGL production expense	$	125.5		$	100.9		$	24.5		24		%			$	226.4				$	200.0			$	26.4			13		%
Realized price, before the effect of derivative settlements:
Realized price, before the effect of derivative settlements (“realized price”):																					Realized price, before the effect of derivative settlements (“realized price”):
Oil (per Bbl)	Oil (per Bbl)	$	37.69	$	53.99	$	(16.30)	(30)	%		$	35.92		$	53.31		$	(17.39)	(33)	%	Oil (per Bbl)	$	65.34		$	56.33		$	9.01		16		%			$	61.30				$	35.09			$	26.21			75		%
Gas (per Mcf)	Gas (per Mcf)	$	1.90	$	2.17	$	(0.27)	(12)	%		$	1.59		$	2.38		$	(0.79)	(33)	%	Gas (per Mcf)	$	3.34		$	4.16		$	(0.82)		(20)		%			$	3.71				$	1.44			$	2.27			158		%
NGLs (per Bbl)	NGLs (per Bbl)	$	14.07	$	15.73	$	(1.66)	(11)	%		$	12.81		$	17.09		$	(4.28)	(25)	%	NGLs (per Bbl)	$	28.41		$	26.93		$	1.48		5		%			$	27.77				$	12.09			$	15.68			130		%
Per BOE	Per BOE	$	24.28	$	31.39	$	(7.11)	(23)	%		$	22.92		$	32.00		$	(9.08)	(28)	%	Per BOE	$	45.28		$	42.11		$	3.17		8		%			$	43.87				$	22.25			$	21.62			97		%
Per BOE data: (1)	Per BOE data: (1)																				Per BOE data: (1)
Production costs:	Production costs:																				Production costs:
Lease operating expense	Lease operating expense	$	3.65	$	4.73	$	(1.08)	(23)	%		$	3.93		$	4.67		$	(0.74)	(16)	%	Lease operating expense	$	4.62		$	4.64		$	(0.02)		—		%			$	4.63				$	4.06			$	0.57			14		%
Transportation costs	Transportation costs	3.11		4.00		(0.89)		(22)	%		3.11			4.02			(0.91)		(23)	%	Transportation costs	3.01			2.94			0.07			2		%			2.98					3.11				(0.13)				(4)		%
Production taxes	Production taxes	1.04		1.29		(0.25)		(19)	%		0.94			1.30			(0.36)		(28)	%	Production taxes	2.03			1.94			0.09			5		%			1.99					0.90				1.09				121		%
Ad valorem tax expense	Ad valorem tax expense	0.40		0.39		0.01		3	%		0.41			0.52			(0.11)		(21)	%	Ad valorem tax expense	0.45			0.52			(0.07)			(13)		%			0.48					0.42				0.06				14		%
Total production costs (1)	Total production costs (1)	$	8.20	$	10.41	$	(2.21)	(21)	%		$	8.40		$	10.51		$	(2.11)	(20)	%	Total production costs (1)	$	10.10		$	10.04		$	0.06		1		%			$	10.07				$	8.49			$	1.58			19		%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	15.64	$	17.02	$	(1.38)	(8)	%		$	16.95		$	16.76		$	0.19	1	%	Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	16.48		$	16.62		$	(0.14)		(1)		%			$	16.54				$	17.59			$	(1.05)			(6)		%
General and administrative	General and administrative	$	2.10	$	2.63	$	(0.53)	(20)	%		$	2.25		$	2.69		$	(0.44)	(16)	%	General and administrative	$	1.98		$	2.46		$	(0.48)		(20)		%			$	2.20				$	2.32			$	(0.12)			(5)		%
Derivative settlement gain (2)		$	6.05	$	1.99	$	4.06	204	%		$	8.14		$	0.67		$	7.47	1,115	%
Earnings per share information: (3)
Basic weighted-average common shares outstanding (in thousands)		114,371		112,804		1,567		1	%		113,462			112,441			1,021		1	%
Diluted weighted-average common shares outstanding (in thousands)		114,371		113,334		1,037		1	%		113,462			112,441			1,021		1	%
Basic net income (loss) per common share		$	(0.86)	$	0.37	$	(1.23)	(332)	%		$	(5.28)		$	(0.76)		$	(4.52)	(595)	%
Diluted net income (loss) per common share		$	(0.86)	$	0.37	$	(1.23)	(332)	%		$	(5.28)		$	(0.76)		$	(4.52)	(595)	%
Derivative settlement gain (loss) (2)																					Derivative settlement gain (loss) (2)	$	(12.78)		$	(10.74)		$	(2.04)		(19)		%			$	(11.87)				$	9.17			$	(21.04)			(229)		%
Earnings per share information (in thousands, except per share data): (3)																					Earnings per share information (in thousands, except per share data): (3)
Basic weighted-average common shares outstanding																					Basic weighted-average common shares outstanding	118,357			114,759			3,598			3		%			116,568					113,015				3,553				3		%
Diluted weighted-average common shares outstanding																					Diluted weighted-average common shares outstanding	118,357			114,759			3,598			3		%			116,568					113,015				3,553				3		%
Basic net loss per common share																					Basic net loss per common share	$	(1.88)		$	(2.19)		$	0.31		14		%			$	(4.07)				$	(4.43)			$	0.36			8		%
Diluted net loss per common share																					Diluted net loss per common share	$	(1.88)		$	(2.19)		$	0.31		14		%			$	(4.07)				$	(4.43)			$	0.36			8		%

(1) Amounts and percentage changes may not calculate due to rounding.

(2) Derivative settlements for the three ~~and nine~~ months ended ~~September~~June 30, ~~2020,~~2021, and ~~2019~~for the six months ended June 30, 2021, and 2020, are included within the net derivative (gain) loss line item in the accompanying statements of operations.

(3) Please refer to Note 9 - Earnings Per Share in Part I, Item 1 of this report for additional discussion.

Average net daily equivalent production for the three months ended ~~September~~June 30, ~~2020, decreased six percent compared with the same period in 2019, primarily driven by a~~2021, increased 22 percent ~~decrease~~sequentially and decreased four percent YTD 2021-over-YTD 2020. The sequential quarterly increase is primarily related to the Texas Weather Event that caused temporary impacts to production in production volumes from our South Texas assets, partially offset by a seven percent increase in production volumes from our Midland Basin assets. The total decrease in production volumes was primarily due to fewer net well completions during the nine months ended September 30, 2020, compared with the same period in 2019, as we reduced capital expenditures in response to lower commodity prices in 2020. Average net daily equivalent production for the nine months ended September 30, 2020, remained relatively flat compared with the same period in 2019 as decreases in production volumes from our South Texas assets were mostly offset by increases in production volumes from our Midland Basin assets. For the full year 2020, we expect total production volumes to decrease compared with 2019.first quarter of 2021.

We present certain information on a per BOE basis in order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis and discussion.

Our realized price ~~before the effect of derivative settlements~~ on a per BOE basis ~~decreased $7.11 per BOE and $9.08 per BOE~~ for the three ~~and nine~~ months ended ~~September~~June 30, ~~2020, respectively, compared with the same periods in 2019, primarily driven by lower~~2021, increased $3.17 sequentially as a result of strengthening benchmark commodity ~~prices for~~prices. The positive impact on oil, gas, and ~~NGLs~~NGL production revenues resulting from the ~~Pandemic and other macroeconomic events. Regional pricing differentials in the Midland Basin negatively affected our~~sequential quarterly realized prices in 2019 and continue to negatively affect our realized prices in 2020. The negative impacts on revenue associated with the decreases in our realized prices before the effect of derivative settlements on a per BOE basis wereprice increase was partially offset by ~~increases~~an increase in the ~~gains we recognized~~loss on the settlement of our derivative contracts of ~~$4.06~~$2.04 per BOE. Our realized price on a per BOE basis increased $21.62 YTD 2021-over-YTD 2020, primarily as a result of strengthening benchmark commodity prices as benchmark commodity prices during the six months ended June 30, 2020, fell to historic lows as a result of the impacts of the Pandemic. Further contributing to the YTD 2021-over-YTD 2020 increase were increased gas prices during the first quarter of 2021 resulting from the supply and ~~$7.47~~demand imbalance caused by the Texas Weather Event. The positive impact on oil, gas, and NGL production revenues resulting from the YTD 2021-over-YTD 2020 realized price increase was mostly offset by a 229% change in the settlement of our derivative contracts which were a loss of $11.87 per BOE for the ~~three and nine~~six months ended ~~September~~June 30, ~~2020, respectively,~~2021, compared ~~with~~to a gain of $9.17 per BOE for the same ~~periods~~period in ~~2019.~~2020.

Lease operating expense (“LOE”) on a per BOE basis ~~decreased 23 percent and 16 percent~~ for the three ~~and nine~~ months ended ~~September~~June 30, 2021, remained flat sequentially, and increased 14 percent YTD 2021-over-YTD 2020. The YTD 2021-over-YTD 2020 ~~respectively, compared with the same periods in 2019. These decreases were~~increase was driven by ~~reduced~~the increased percentage of oil in our total product mix, which has higher lifting costs per BOE, and ~~reduced workover activity during the first nine months~~by a total net equivalent production volume decrease of ~~2020.~~five percent. For the full year ~~2020,~~2021, we expect LOE on a per BOE basis to ~~be lower,~~increase, compared with ~~2019, as we continue~~2020, due to ~~benefit from reduced costs~~higher oil production and ~~improved operational efficiencies. While we will continue our efforts to reduce costs during 2020, we~~increased workover expense. We anticipate volatility in LOE on a per BOE basis as a result of changes in total production, changes in our overall production mix, timing of workover projects, and industry activity, all of which ~~impacts~~impact total LOE.

Transportation costs on a per BOE basis ~~decreased 22 percent and 23 percent~~ for the three ~~and nine~~ months ended ~~September~~June 30, 2021 increased slightly sequentially, and decreased four percent YTD 2021-over-YTD 2020 ~~respectively, compared with the same periods in 2019. These decreases were driven by~~as a ~~22 percent and~~result of a 19 percent ~~reduction~~decrease in production volumes from our South Texas assets, which incur the majority of our transportation ~~costs, for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019.~~costs. We expect total transportation costs to fluctuate relative to changes in production from our South Texas assets. On a per BOE basis, we expect transportation costs to decrease ~~in 2020,~~for the full year 2021, compared with ~~2019,~~2020, as production from our Midland Basin assets, which is sold at or near the wellhead and incurs minimal transportation costs, ~~continues to become~~comprises a larger portion of our total ~~production, and as~~production. Further, we ~~experience~~anticipate natural declines in production from our Eagle Ford shale wells in South Texas, aswhich incur higher transportation costs on a per BOE basis, and we intend to focus on new wells with higher liquids content in the Austin Chalk, which have lower transportation costs on a per BOE basis. In addition, we expect to benefit from certain transportation contract cost reductions that are expected to further reduce our transportation expense per BOE during 2021.

Production taxes on a per BOE basis ~~decreased 19 percent and 28 percent~~ for the three ~~and nine~~ months ended ~~September~~June 30, 2021, increased five percent sequentially, and increased 121 percent YTD 2021-over-YTD 2020, ~~respectively, compared with the same periods in 2019. These decreases were~~ primarily driven by ~~a decrease~~increases in realized prices. Our overall production tax ~~rates for the three and nine months ended September 30, 2020, were 4.3 percent and 4.1 percent, respectively, compared to 4.1~~rate was 4.5 percent for each of the three and ~~nine~~six months ended ~~September~~June 30, ~~2019.~~2021, compared with 4.6 percent for the three months ended March 31, 2021, and 4.0 percent for the six months ended June 30, 2020. The YTD 2021-over-YTD 2020 increase in the production tax rate was primarily driven by increases in realized prices and increased production from our Midland Basin assets. We expect our total production tax expense to ~~decrease~~increase in ~~2020,~~2021, compared with ~~2019,~~2020, as we expect oil, gas, and NGL production revenue to ~~decrease~~increase due to ~~decreased pricing and volumes.~~increased pricing. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue on an absolute and per BOE basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax that we recognize.

Ad valorem tax expense on a per BOE basis ~~increased three percent and decreased 21 percent~~ for the three ~~and nine~~ months ended ~~September~~June 30, 2021, decreased 13 percent sequentially, and increased 14 percent YTD 2021-over-YTD 2020. The sequential quarterly decrease was a result of increased net equivalent production volumes. The YTD 2021-over-YTD 2020 ~~respectively, compared with the same periods in 2019. The decrease for the nine months ended September 30, 2020,~~increase was primarily ~~the~~a result of changes to the expected ~~2020~~ value assessments of our producing ~~properties by respective tax authorities.~~properties. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties change.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis remained flat sequentially, and decreased ~~eight~~six percent ~~and remained relatively flat for the three and nine months ended September 30,~~YTD 2021-over-YTD 2020. The YTD 2021-over-YTD 2020 ~~respectively, compared with the same periods in 2019. The~~ decrease ~~for the three months ended September 30, 2020,~~ was primarily driven by the reduction in the depletable cost basis of our South Texas proved oil and gas properties as a result of proved property impairments recognized during the first quarter of ~~2020, partially offset by higher production volumes from our oil producing Midland Basin assets as these assets have higher depletion rates than our primarily gas and NGL producing South Texas assets.~~2020. Our DD&A rate fluctuates as a result of impairments, divestiture activity, carrying cost funding and sharing arrangements with third parties, changes in our production mix, and changes in our total estimated proved reserve volumes. For the full year ~~2020,~~2021, we expect ~~the~~ DD&A ~~rate to be relatively flat compared with 2019~~per BOE and DD&A expense on an absolute basis to ~~be lower~~

decrease compared with ~~2019,~~2020, primarily as a result of ~~anticipated~~increased activity in our Austin Chalk program compared with 2020, as these assets have a lower ~~production volumes.~~

DD&A rate than our Midland Basin assets.

General and administrative (“G&A”) expense on a per BOE basis decreased 20 percent sequentially, and 16decreased five percent ~~for~~YTD 2021-over-YTD 2020. The sequential quarterly decrease was primarily the result of increased production volumes during the three ~~and nine~~ months ended ~~September~~June 30, 2021, and the YTD 2021-over-YTD 2020 ~~respectively, compared with~~decrease was primarily the ~~same periods in 2019. These decreases were primarily due to reduced overhead costs resulting from the reorganization~~result of ~~certain functions in the fourth quarter of 2019 that eliminated duplicative regional operational functions, and~~ actions taken to reduce costs ~~as a result of~~in response to the Pandemic. For the full year ~~2020,~~2021, we expect G&A expense to be ~~lower,~~relatively flat, in total and on a per BOE basis, compared with ~~2019.~~2020.

Please refer to Comparison of Financial Results and Trends Between the Three ~~and Nine~~ Months Ended ~~September~~June 30, ~~2020,~~2021, and ~~2019~~March 31, 2021, and Between the Six Months Ended June 30, 2021, and 2020 below for additional discussion on operating expenses.

Comparison of Financial Results and Trends Between the Three ~~and Nine~~ Months Ended ~~September~~June 30, ~~2020,~~2021, and ~~2019~~March 31, 2021, and Between the Six Months Ended June 30, 2021, and 2020

Net equivalent production, production revenue, and production expense

Sequential Quarterly Changes. The following table presents the ~~regional~~ changes in our net equivalent production, production revenue, and production expense, by area, between the three ~~and nine~~ months ended ~~September~~June 30, ~~2020,~~2021, and ~~2019:~~March 31, 2021:


		Net Equivalent Production Increase (Decrease)		Production Revenue Decrease				Production Expense Decrease					Net Equivalent Production Increase	Production Revenue Increase	Production Expense Increase
		Three Months Ended	Nine Months Ended	Three Months Ended		Nine Months Ended		Three Months Ended		Nine Months Ended
		(MBOE per day)		(in millions)				(in millions)					(MBOE per day)	(in millions)	(in millions)
Midland Basin	Midland Basin	5.2	10.0	$	(77.3)	$	(209.2)	$	(11.7)	$	(22.1)	Midland Basin	15.5		$	112.0	$	13.9
South Texas	South Texas	(13.8)	(11.7)	(30.1)		(121.6)		(22.1)		(56.0)		South Texas	9.4		27.4		10.6
Total	Total	(8.6)	(1.8)	$	(107.4)	$	(330.7)	$	(33.8)	$	(78.1)	Total	24.9		$	139.4	$	24.5

Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes ~~for the three and nine months ended September 30, 2020, decreased six~~increased 22 percent driven by increases of 26 percent and ~~one~~20 percent in average net daily equivalent production volumes from our South Texas and Midland Basin assets, respectively. These increases were primarily related to the Texas Weather Event, which caused temporary impacts to production in the first quarter of 2021. Realized prices for oil and NGLs increased 16 percent and five percent, respectively, ~~compared with the same periods in 2019. Realized prices before the effects of derivative settlements for oil, gas,~~ and ~~NGLs~~ decreased 30 percent, 12 percent, and 11 percent, respectively, for the three months ended September 30, 2020, compared with the same period in 2019. For the nine months ended September 30, 2020, realized prices before the effects of derivative settlements decreased 3320 percent for ~~both oil and gas, and decreased 25 percent for NGLs, compared with the same period in 2019.~~gas. As a result of increases in benchmark commodity prices for oil and NGLs during the ~~decreases in production and pricing,~~second quarter of 2021, oil, gas, and NGL production revenue ~~decreased 28 percent and 29 percent for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019.~~increased 33 percent. Total production expense ~~for~~increased 24 percent as a result of increased average net daily equivalent production volumes and realized prices.

YTD 2021-over-YTD 2020. The following table presents the ~~three~~changes in our net equivalent production, production revenue, and ~~nine~~production expense, by area, between the six months ended ~~September~~June 30, ~~2020,~~2021, and 2020:


	Net Equivalent Production Increase (Decrease)	Production Revenue Increase	Production Expense Increase (Decrease)

	(MBOE per day)	(in millions)	(in millions)
Midland Basin	3.9		$	386.2	$	27.7
South Texas	(9.2)		75.5		(1.3)
Total	(5.2)		$	461.7	$	26.4

Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes decreased 26four percent, driven by a decrease of 19 percent in average net daily equivalent production volumes from our South Texas assets, partially offset by an increase of five percent in average net daily equivalent production volumes from our Midland Basin assets. These changes were primarily the result of higher capital allocations to the Midland Basin in prior years. Realized prices for oil, gas, and NGLs increased 75 percent, 158 percent, and 21130 percent, ~~respectively, compared with~~respectively. As a result of increases in benchmark commodity prices, during the ~~same periods in 2019.~~ first half of 2021, oil, gas, and NGL production revenue increased 88 percent. Total production expense increased 13 percent, primarily as a result of increased production taxes.

Please refer to ~~A Three Month and Nine Month~~ Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including discussion of trends on a per BOE basis.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2020 2019 2020 2019
(in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 181.7 $ 211.1 $ 596.1 $ 595.2


	For the Three Months Ended				For the Six Months Ended
	June 30, 2021		March 31, 2021			June 30, 2021		June 30, 2020

	(in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	204.7	$	167.0		$	371.7	$	414.3

DD&A expense ~~decreased 14 percent~~ for the three months ended ~~September~~June 30, ~~2020, compared with the same period in 2019,~~2021, increased 23 percent sequentially, and ~~remained relatively flat for the nine months ended September 30, 2020, compared with the same period in 2019.~~decreased 10 percent YTD 2021-over-YTD 2020. The ~~decrease for the three months ended September 30, 2020~~sequential quarterly increase was primarily driven by an increase in total net equivalent production volumes of 24 percent. The YTD 2021-over-YTD 2020 decrease was driven by both a decrease in production volumes of five percent and the reduction in the depletable cost basis of our South Texas proved oil and gas properties as a result of proved property impairments recognized during the first quarter of ~~2020, partially offset by higher production volumes from our oil producing Midland Basin assets as these assets have higher depletion rates than our primarily gas and NGL producing South Texas assets.~~2020. Please refer to ~~A Three Month and Nine Month~~ Overview of Selected Production and Financial Information, Including Trends above for additional ~~discussion.~~discussion of DD&A expense on a per BOE basis.

Exploration


											For the Three Months Ended				For the Six Months Ended
		For the Three Months Ended September 30,				For the Nine Months Ended September 30,					June 30, 2021		March 31, 2021			June 30, 2021		June 30, 2020
		2020		2019		2020		2019
		(in millions)									(in millions)
Geological and geophysical expenses	Geological and geophysical expenses	$	0.2	$	1.1	$	1.7	$	2.0	Geological and geophysical expenses	$	0.8	$	0.3		$	1.1	$	1.4
Overhead and other expenses	Overhead and other expenses	8.3		10.5		28.0		31.9		Overhead and other expenses	7.9		9.0			16.9		19.7
Total	Total	$	8.5	$	11.6	$	29.7	$	33.9	Total	$	8.7	$	9.3		$	18.0	$	21.1

Exploration expense ~~decreased 26 percent and 12 percent~~ for the three ~~and nine~~ months ended ~~September~~June 30, 2021, decreased seven percent sequentially, and decreased 15 percent YTD 2021-over-YTD 2020, ~~respectively, compared with the same periods in 2019. These decreases were~~ primarily driven by the reorganization of certain functions in the fourth quarter of 2019 that eliminated duplicative regional operational functions and reduced overhead costs. For the full year 2020, we expect exploration expense to decrease compared with 2019 as a result of ~~lower overhead; however, exploration~~decreases in overhead and other expenses. Exploration expense is impacted by actual geological and geophysical studies we perform within an exploratory area and the potential for exploratory dry hole expense.

Impairment


											For the Three Months Ended				For the Six Months Ended
		For the Three Months Ended September 30,				For the Nine Months Ended September 30,					June 30, 2021		March 31, 2021			June 30, 2021		June 30, 2020
		2020		2019		2020		2019
		(in millions)									(in millions)
Impairment of proved oil and gas properties and related support equipment	Impairment of proved oil and gas properties and related support equipment	$	—	$	—	$	956.7	$	—	Impairment of proved oil and gas properties and related support equipment	$	—	$	—		$	—	$	956.7
Abandonment and impairment of unproved properties	Abandonment and impairment of unproved properties	8.8		6.3		50.6		25.1		Abandonment and impairment of unproved properties	8.8		8.8			17.5		41.9
Total	Total	$	8.8	$	6.3	$	1,007.3	$	25.1	Total	$	8.8	$	8.8		$	17.5	$	998.5

__________________________________________

AsNote: Amounts may not calculate due to rounding.

There were no proved oil and gas property impairments for the three and six months ended June 30, 2021. During the six months ended June 30, 2020, we recorded impairment expense related to our South Texas proved oil and gas properties and related support facilities as a result of the decrease in commodity price forecasts at the end of the first quarter of 2020, specifically decreases in oil and NGL prices, we recorded impairment expense related to our South Texas proved oil and gas properties and related support facilities during the nine months ended September 30, 2020. There were no proved oil and gas property impairments recorded during the same period in 2019.prices. Unproved property abandonments and impairments recorded during ~~the three and nine months ended September 30, 2020, and 2019~~each period presented above related to actual and anticipated lease expirations, as well as actual and anticipated losses of acreage due to title defects, changes in development plans, and other inherent acreage risks.

We expect proved property impairments to occur more frequently in periods of declining or depressed commodity prices, and that the frequency of unproved property abandonments and impairments will fluctuate with the timing of lease expirations or defects, and changing economics associated with decreases in commodity prices. Additionally, changes in drilling plans, unsuccessful exploration activities, and downward engineering revisions may result in proved and unproved property impairments.

~~Reserve estimates and related~~Future impairments of proved and unproved properties are difficult to ~~predict in a volatile~~predict; however, based on our commodity price ~~environment. If commodity prices for the products~~assumptions as of July 21, 2021, we ~~produce remain depressed or decline further as a result of supply and demand fundamentals associated with the Pandemic or other macroeconomic events, we may experience additional proved and unproved~~do not expect any material property impairments in the ~~future. Given the uncertainties in~~third quarter of 2021 resulting from commodity prices and the associated impacts they may have on service provider costs, we cannot predict with any reasonable certainty the likelihood or magnitude of further property impairments beyond those recorded during the nine months ended September 30, 2020.price impacts.

Please refer to Note 118 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion of impairment expense.

General and administrative

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2020 2019 2020 2019
(in millions)
General and administrative $ 24.5 $ 32.6 $ 79.1 $ 95.6


	For the Three Months Ended				For the Six Months Ended
	June 30, 2021		March 31, 2021			June 30, 2021		June 30, 2020

	(in millions)
General and administrative	$	24.6	$	24.7		$	49.4	$	54.7

G&A expense remained flat sequentially, and decreased 2510 percent ~~and 17 percent for the three and nine months ended September 30,~~YTD 2021-over-YTD 2020, ~~respectively, compared with the same periods in 2019. These decreases were~~ primarily ~~due to reduced overhead costs resulting from the reorganization that was announced in the fourth quarter~~as a result of ~~2019, and~~ actions taken to reduce costs ~~as a result of~~in response to the Pandemic. Please refer to the section ~~A Three Month and Nine Month~~ Overview of Selected Production and Financial Information, Including Trends above for additional discussion of G&A expense in total and on a per BOE basis.

Net derivative (gain) loss

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2020 2019 2020 2019
(in millions)
Net derivative (gain) loss $ 63.9 $ (100.9) $ (314.3) $ (3.5)


	For the Three Months Ended				For the Six Months Ended
	June 30, 2021		March 31, 2021			June 30, 2021		June 30, 2020

	(in millions)
Net derivative (gain) loss	$	370.3	$	344.7		$	715.0	$	(378.1)

We recognized a derivative loss of $370.3 million for the three months ended June 30, 2021. The loss was primarily driven by a $211.5 million downward mark-to-market adjustment due to strengthening commodity prices during the second quarter of 2021. Additionally, we recognized losses on the settlement of derivative contracts of $158.8 million during the three months ended June 30, 2021.

We recognized a derivative loss of $344.7 million for the three months ended March 31, 2021. The loss was primarily driven by a $236.8 million downward mark-to-market adjustment due to strengthening commodity prices during the first three months of 2021. Additionally, we recognized losses on the settlement of derivative contracts of $107.9 million during the three months ended March 31, 2021.

We recognized a derivative loss of $715.0 million for the six months ended June 30, 2021. For contracts that settled during the first half of 2021, the fair value was a net liability of $76.1 million at December 31, 2020, and net cash settlements totaled $266.7 million, resulting in a $190.6 million loss. We recorded a $524.4 million mark-to-market loss on unsettled contracts as of June 30, 2021 resulting from strengthening commodity prices during the first half of 2021.

We recognized a derivative gain of ~~$545.3~~$378.1 million infor the ~~first quarter of~~six months ended June 30, 2020, ~~and derivative losses of $167.2 million and $63.9 million in the second and third quarters of 2020, respectively. The gain in the first quarter of 2020 was primarily~~ driven by ~~a $471.9~~$216.0 million ~~upward mark-to-market adjustment due to weakening oil prices during the first three months~~ of ~~the year. The losses~~gains recognized in the second and third quarters of 2020 were driven by downward mark-to-market adjustments of $309.7 million and $134.2 million, respectively, due to strengthening commodity prices during these periods. Additionally, we recognized gains on the settlement of derivative contracts ~~of $70.3~~and a $162.2 million ~~and $286.3 million during the three and nine months ended September 30, 2020, respectively.~~

We recognized a derivative loss of $177.1 million in the first quarter of 2019, and derivative gains of $79.7 million and $100.9 million in the second and third quarters of 2019, respectively. The loss in the first quarter of 2019 was primarily driven by a $172.1 million downwardupward mark-to-market adjustment ~~due to strengthening~~resulting from oil ~~prices~~price fluctuations during the first ~~three months~~half of the year. The gains recognized in the second and third quarters of 2019 were driven by upward mark-to-market adjustments of $75.6 million and $76.2 million, respectively, due to weakening commodity prices during these periods. Additionally, we recognized gains on the settlement of derivative contracts of $24.7 million and $23.8 million during the three and nine months ended September 30, 2019, respectively.

Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.

Interest expense

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2020 2019 2020 2019
(in millions)
Interest expense $ 41.5 $ 40.6 $ 123.4 $ 118.2


	For the Three Months Ended				For the Six Months Ended
	June 30, 2021		March 31, 2021			June 30, 2021		June 30, 2020

	(in millions)
Interest expense	$	39.5	$	39.9		$	79.4	$	81.9

Interest expense ~~increased two percent~~remained flat sequentially and four percent for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019. The increase for the nine months ended September 30, 2020, was primarily due to an increase in interest expense associated with borrowings under our revolving credit facility and a decrease in interest expense capitalized to wells.YTD 2021-over-YTD 2020. We expect interest expense related to our Senior Notes to ~~remain relatively flat~~decrease slightly for ~~the remainder of 2020~~2021 compared with ~~2019~~2020 primarily as ~~the increase related to the higher interest rate on the 2025 Senior Secured Notes will be mostly offset by~~a result of the decreased ~~interest associated with~~principal amount outstanding on our Senior Notes resulting from the ~~reduction~~Exchange Offers executed in ~~principal~~the second quarter of ~~Old Notes exchanged.~~2020. Total interest expense is impacted by and can vary based on the timing and amount of borrowings under our revolving credit facility. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report and Overview of Liquidity and Capital Resources below for additional discussion.

Gain (loss) on extinguishment of debt

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2020 2019 2020 2019
(in millions)
Gain on extinguishment of debt $ 25.1 $ — $ 264.5 $ —


	For the Three Months Ended				For the Six Months Ended
	June 30, 2021		March 31, 2021			June 30, 2021		June 30, 2020

	(in millions)
Gain (loss) on extinguishment of debt	$	(2.1)	$	—		$	(2.1)	$	239.5

~~During the three months ended September 30, 2020, we recorded net gains on the early extinguishment of portions of our~~The Tender Offer and 2022 Senior Notes Redemption executed during the second quarter of 2021 resulted in a net loss on extinguishment of debt of $2.1 million, which included $1.5 million of accelerated unamortized deferred financing costs and ~~2024 Senior Notes~~$600,000 of ~~$12.2 million and $12.9 million, respectively.~~ net premiums paid.

The Exchange Offers executed during the second quarter of 2020 resulted in a net gain on extinguishment of debt of $227.3 million, which was primarily comprised of the ~~gain on the~~ partial principal redemption of Old Notes and the debt discount associated with the issuance of the 2025 Senior Secured Notes. During the ~~first quarter of~~three months ended March 31, 2020, we recorded a $12.2 million net gain on the early extinguishment of a portion of our 2022 Senior ~~Notes.~~Notes, which included discounts realized upon repurchase of $12.4 million partially offset by $235,000 of accelerated unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion onof these transactions.

Income tax (expense) benefit


															For the Three Months Ended						For the Six Months Ended
		For the Three Months Ended September 30,						For the Nine Months Ended September 30,							June 30, 2021			March 31, 2021				June 30, 2021			June 30, 2020
		2020			2019			2020			2019
		(in millions, except tax rate)													(in millions, except tax rate)
Income tax (expense) benefit	Income tax (expense) benefit	$	23.0		$	(16.1)		$	158.7		$	16.3		Income tax (expense) benefit	$	0.2		$	(0.1)			$	0.1		$	135.7
Effective tax rate	Effective tax rate	18.9		%	27.6		%	20.9		%	16.1		%	Effective tax rate	0.1		%	—		%		—		%	21.3		%

The effective tax benefit rate remained flat sequentially. The decrease in the effective ~~income~~ tax benefit rate for the ~~three~~six months ended ~~September~~June 30, 2020, compared to the income tax expense rate during the same period in 2019, was primarily due to the differing effects permanent items have on the loss before income taxes compared to the income before income taxes for the three months ended September 30, 2020, and 2019, respectively. The increase in the effective tax rate for the nine months ended September 30, 2020,2021, compared with the same period in ~~2019,~~2020, was primarily due to the effects of forecasted income for the year ended December 31, 2021, compared to forecasted loss at June 30, 2020, and the correlative effect on the valuation allowance balance in each period.

For each of the comparable periods, the tax rates reflect the proportional ~~effect~~effects of ~~recording discrete~~ excess tax deficiencies from ~~share-based~~stock-based compensation awards, and ~~other permanent items~~limits on expensing of certain covered individual’s compensation.

Changes in federal income tax laws or enactment of proposed legislation to increase the corporate tax rate and eliminate or reduce certain oil and gas industry deductions could have a ~~larger pretax loss for the nine months ended September 30, 2020, compared~~material impact on our effective tax rate and current tax expense. Please refer to the ~~same period~~Risk Factors section in ~~2019.~~ Part I, Item 1A of our 2020 Form 10-K for additional discussion.

Please refer to Note 4 - Income Taxes in Part I, Item 1 of this report for additional discussion.

Overview of Liquidity and Capital Resources

Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to ~~achieve~~execute our ~~operational objectives~~business plan while continuing to meet our current financial ~~obligations in a challenging commodity price environment.~~obligations. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain flexibility with regard to our activity level and capital ~~expenditures, and we have successfully renegotiated certain contracts and have realized cost savings that directly support our objective of maximizing cash flows.~~expenditures.

Sources of Cash

We ~~currently~~ expect our ~~2020~~2021 capital program to be funded by cash flows from operations with any remaining cash needs being funded by borrowings under our revolving credit facility. During the nine months ended September 30, 2020, we generated $534.1 million of cash flows from operating activities.operations. Although we expect cash flows from ~~these sources~~operations to be sufficient to fund our expected ~~2020~~2021 capital program, we may also use borrowings under our revolving credit facility or may elect to raise funds through new debt or equity offerings or from other sources of financing. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current stockholders could be diluted, and these newly issued securities may have rights, preferences, or privileges senior to those of existing stockholders and bondholders. Additionally, we may enter into cost carrying ~~cost~~ and sharing arrangements with third parties for certain exploration or development programs. All of our sources of liquidity can be affected by the general conditions of the broader economy, force majeure events, fluctuations in commodity prices, operating costs, tax law changes, and volumes produced, all of which affect us and our industry.

~~As a result of the current macroeconomic environment, our~~Our credit ratings ~~were downgraded during~~impact the ~~first half~~availability of ~~2020 by three major rating agencies. These downgrades~~ and ~~any future downgrades in our credit ratings could make it more difficult or expensive~~cost for us to borrow additional funds. During the first half of 2021, three major credit rating agencies upgraded our credit ratings, citing our improved debt leverage and our expected ability to generate meaningful free cash flows, among other reasons. Additionally, one of these major credit rating agencies further upgraded our credit rating in conjunction with the issuance of our 2028 Senior Notes.

We have no control over the market prices for oil, gas, or NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. ~~Current~~Commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or ~~future macroeconomic events may negatively impact our ability to benefit from these contracts.~~NGL prices rise substantially over the price established by the commodity derivative contract. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information about our oil, gas, and NGL derivative contracts currently in place and the timing of settlement of those contracts.

Credit Agreement

Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion, and a borrowing base and aggregate lender commitments of $1.1 billion. The borrowing base under the Credit Agreement is subject to regular, semi-annual redetermination, and considers the value of both our (a) proved oil and gas properties reflected in the most recent reserve report provided to our lenders under the Credit Agreement; and (b) commodity derivative contracts, each as determined by our lender group. AsDuring March 2021, as a result of the ~~filing of this report,~~regular, semi-annual redetermination, both the ~~fall semi-annual~~ borrowing base ~~redetermination was in process.~~and aggregate lender commitments were reaffirmed at the amounts noted above. The next scheduled borrowing base redetermination date is ~~April~~October 1, 2021. As of ~~September~~June 30, ~~2020,~~2021, the remaining available borrowing capacity under our Credit Agreement provided ~~$880.0 million~~$1.0 billion in ~~liquidity; however, our~~liquidity. Our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties, or financing ~~activities.~~activities, all as provided for in the Credit Agreement. No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under our Credit Agreement as of ~~October~~July 21, ~~2020, September~~2021, June 30, ~~2020,~~2021, and December 31, ~~2019.~~2020.

We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring that we maintain certain financial ratios, as set forth in the Credit Agreement. ~~The~~

financial covenants under the Credit Agreement require that our (a) total funded debt, as defined in the Credit Agreement, to 12-month trailing adjusted EBITDAX ratio cannot be greater than 4.00 to 1.00 on the last day of each fiscal quarter; and (b) adjusted current ratio, as defined in the Credit Agreement, cannot be less than 1.0 to 1.0 as of the last day of any fiscal quarter. We were in compliance with all financial and non-financial covenants as of ~~September~~June 30, ~~2020,~~2021, and through the filing of this report. Please refer to ~~the caption~~ ~~Non-GAAP Financial Measures~~Note 5 - Long-Term Debt ~~below~~in Part I, Item 1 of this report for ~~our definition of adjusted EBITDAX and reconciliations of net income (loss) and net cash provided by operating activities to adjusted EBITDAX.~~additional discussion.

Our daily weighted-average revolving credit facility debt balance was ~~$200.1~~$141.5 million and ~~$170.9~~$134.2 million for the three months ended ~~September~~June 30, ~~2020,~~2021, and ~~2019,~~March 31, 2021, respectively, and ~~$142.2~~$137.9 million and ~~$97.5~~$113.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, and ~~2019,~~2020, respectively. Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities, including open market debt repurchases, repayment of scheduled debt maturities, and our capital expenditures, including acquisitions, all impact the amount we borrow under our revolving credit facility.

Under our Credit Agreement, borrowings in the form of Eurodollar loans accrue interest based on LIBOR. The use of LIBOR as a global reference rate is expected to be discontinued after 2021. Our Credit Agreement specifies that if LIBOR is no longer a widely used benchmark rate, or if it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with us. We currently do not expect the transition from LIBOR to have a material impact on interest expense or borrowing activities under the Credit Agreement, or to otherwise have a material adverse impact on our business. Please refer to Note 1 - Summary of Significant Accounting Policies for discussion of FASB ASU 2020-04 and ASU 2021-01, which ~~provides~~provide guidance related to reference rate reform.

Weighted-Average Interest and Weighted-Average Borrowing Rates

Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate commitment amount under the Credit Agreement, letter of credit fees, the non-cash amortization of deferred financing costs, and the non-cash amortization of the discounts related to the ~~2025 Senior Secured Notes and~~ 2021 Senior Secured Convertible Notes and 2025 Senior Secured Notes. Our weighted-average borrowing rate includes paid and accrued interest only.

The following table ~~presents~~details our weighted-average interest rates and our weighted-average borrowing rates for the ~~three and nine months ended September 30, 2020, and 2019:~~periods presented:


		For the Three Months Ended September 30,				For the Nine Months Ended September 30,					For the Three Months Ended				For the Six Months Ended
		2020		2019		2020		2019			June 30, 2021		March 31, 2021		June 30, 2021		June 30, 2020
Weighted-average interest rate	Weighted-average interest rate	7.3	%	6.3	%	6.8	%	6.4	%	Weighted-average interest rate	7.6	%	7.7	%	7.7	%	6.6	%
Weighted-average borrowing rate	Weighted-average borrowing rate	6.5	%	5.6	%	6.0	%	5.7	%	Weighted-average borrowing rate	6.7	%	6.7	%	6.7	%	5.8	%

Our weighted-average interest rates and weighted-average borrowing rates are impacted by the timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility. Additionally, our weighted-average interest rates are impacted by the fees paid on the unused portion of our aggregate lender commitments. For the three ~~and nine~~ months ended ~~September~~June 30, ~~2020,~~2021, our weighted-average interest rate and our weighted-average borrowing rate remained flat sequentially, and increased ~~compared with the same periods in 2019,~~YTD 2021-over-YTD 2020, primarily as a result of the higher interest rate on our 2025 Senior Secured Notes issued during the second

quarter of 2020. The rates disclosed in the above table do not reflect amounts associated with the ~~early~~repurchase or redemption of ~~certain of our Old~~Senior Notes, such as the acceleration of unamortized deferred financing costs, as these amounts are netted against the associated gain or loss on extinguishment of debt. ~~Please refer to~~ ~~Note 5 - Long-Term Debt~~ ~~in Part I, Item 1 of this report for additional discussion.~~

Uses of Cash

We use cash for the development, exploration, and acquisition of oil and gas properties and for the payment of operating and general and administrative costs, income taxes, dividends, and debt obligations, including interest. Expenditures for the development, exploration, and acquisition of oil and gas properties are the primary use of our capital resources. During the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, we spent ~~$426.9~~approximately $370.2 million on capital ~~expenditures and on acquiring proved and unproved oil and gas properties.~~expenditures. This amount differs from the costs incurred amount of ~~$437.1~~$417.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, acquisitions of oil and gas properties, and exploration overhead amounts.

The amount and allocation of our future capital expenditures will depend upon a number of factors, including our cash flows from operating, investing, and financing activities, our ability to execute our development program, and the number and size of acquisitions. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, tax law changes, and the timing and results of our exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget and guidance to assess if changes are necessary based on current and projected

cash flows, acquisition and divestiture activities, debt requirements, and other factors. ~~We entered 2020 with a~~Our 2021 total capital program budget is between ~~$825~~$650.0 million and ~~$850~~$675.0 million. However, given the macroeconomic events discussed throughout this report, we currently expect to reduce our 2020 capital program by approximately 25 percent for the full year 2020. We are unable to reasonably estimate the period of time that these market conditions will exist, the extent of the impact they will have on our business, liquidity, results of operations, financial condition, or the timing of any subsequent recovery. We will continue to monitor the economic environment throughout the year and adjust our activity level as warranted.

We may from time to time repurchase or redeem all or portions of our outstanding debt securities for cash, through exchanges for other securities, or a combination of both. Such repurchases or ~~exchanges~~redemptions may be made in open market transactions, privately negotiated transactions, or otherwise. Any such repurchases or ~~exchanges~~redemptions will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material.

During the ~~nine months ended September 30, 2020,~~second quarter of 2021, we ~~repurchased $103.2~~issued our 2028 Senior Notes and used the net cash proceeds of $393.6 million to repurchase $193.1 million and $172.3 million of outstanding principal amount of our 2022 Senior Notes and ~~$29.0~~2024 Senior Notes, respectively, through the Tender Offer, and to redeem the remaining $19.3 million of 2022 Senior Notes then outstanding through the 2022 Senior Notes Redemption. We paid total consideration of $385.3 million, including net premiums, and paid $5.2 million of accrued interest related to the 2022 and 2024 Senior Notes. During the first quarter of 2020, we repurchased a total of $40.7 million in aggregate principal amount of our ~~2024~~2022 Senior Notes in open market transactions at a discount, resulting in a net ~~gains~~gain on extinguishment of debt of ~~$24.4 million and $12.9 million, respectively.~~$12.2 million. During the second quarter of 2020, we completed the Exchange Offers, which resulted in the exchange of $718.9 million in aggregate principal amount of Old Notes for $446.7 million in aggregate principal amount of 2025 Senior Secured ~~Notes, as well as,~~Notes. Further, in connection with the Private Exchange, ~~(a)~~we tendered $53.5 million in cash to certain holders of the 2021 Senior Convertible Notes, which was borrowed against our revolving credit facility, and ~~(b) warrants to acquire up to an aggregate of approximately 5.9 million shares, or approximately five percent of our outstanding common stock, exercisable upon~~issued the ~~occurrence of certain future triggering events.~~

The balance of our revolving credit facility increased $55.5 million from $122.5 million at December 31, 2019, to $178.0 million at September 30, 2020, notwithstanding the redemption of $185.7 million in aggregate principal amount of our Senior Unsecured Notes and 2021 Senior Convertible Notes for $147.8 million in cash during the nine months ended September 30, 2020.

Warrants. Please refer toNote 3 - Equity for additional discussion of the Warrants, including related impacts to equity and Note 5 - Long-Term Debt ~~and~~ ~~Note 11 - Fair Value Measurements~~ in Part I, Item 1 of this report for additional ~~discussion.~~discussion of the debt transactions. As part of our strategy for ~~2020,~~2021, we ~~expect to~~will continue to focus on improving our debt metrics, which could include ~~further~~ reducing the amount of our outstanding debt.

As of the filing of this report, we could repurchase up to 3,072,184 shares of our common stock under our stock repurchase program, subject to the approval of our Board of Directors. Shares may be repurchased from time to time in the open market, or in privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing each series of our outstanding Senior Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of Directors periodically reviews this program as part of the allocation of our capital. During the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, we did not repurchase any shares of our common stock, and we currently do not plan to repurchase any outstanding shares of our common stock during the remainder of ~~2020.~~2021.

Analysis of Cash Flow Changes Between the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020,~~2021, and ~~2019~~2020

The following tables present changes in cash flows between the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, and ~~2019,~~2020, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying unaudited condensed consolidated statements of cash flows in Part I, Item 1 of this report.

Operating activities

For the Nine Months Ended
September 30, Amount Change Between Periods
2020 2019
(in millions)
Net cash provided by operating activities $ 534.1 $ 581.6 $ (47.5)


	For the Six Months Ended June 30,				Amount Change Between Periods
	2021		2020

	(in millions)
Net cash provided by operating activities	$	402.0	$	332.5	$	69.5

Net cash provided by operating activities ~~decreased~~increased for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, compared with the same period in ~~2019. Cash~~2020, primarily due to working capital changes resulting from the timing of cash receipts and disbursements. During the six months ended June 30, 2021, compared with the same period in 2020, cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes ~~decreased $215.9~~increased $295.8 million, cash paid for ~~interest increased $9.1~~LOE and ad valorem taxes decreased $22.7 million, and cash ~~received from~~paid on settled derivative trades increased ~~$228.3~~$379.9 million. ~~Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements.~~

Investing activities

For the Nine Months Ended
September 30, Amount Change Between Periods
2020 2019
(in millions)
Net cash used in investing activities $ (426.8) $ (778.7) $ 351.9


	For the Six Months Ended June 30,				Amount Change Between Periods
	2021		2020

	(in millions)
Net cash used in investing activities	$	(370.0)	$	(310.1)	$	(59.9)

Net cash used in investing activities ~~decreased~~increased for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, compared with the same period in ~~2019, primarily~~2020, due to ~~reduced~~increased capital expenditures of ~~$368.9~~$60.0 million.

Financing activities


	For the Six Months Ended June 30,				Amount Change Between Periods
	2021		2020

	(in millions)
Net cash used in financing activities	$	(32.1)	$	(22.4)	$	(9.7)

Net cash used in ~~investing~~financing activities ~~during~~for the ~~nine~~six months ended ~~September~~June 30, ~~2020, was funded~~2021, related to $385.3 million of net cash paid, including net premiums to fund the Tender Offer and the 2022 Senior Notes Redemption and net repayments under our revolving credit facility of $40.5 million, offset by net cash ~~provided by operating activities.~~

~~Financing activities~~

For the Nine Months Ended
September 30, Amount Change Between Periods
2020 2019
(in millions)
Net cash provided by (used in) financing activities $ (107.3) $ 122.7 $ (230.0)
proceeds of $393.6 million from the issuance of our 2028 Senior Notes.

~~For~~Net cash used in financing activities for the ~~nine~~six months ended ~~September~~June 30, 2020, werelated to $81.8 million of net cash paid ~~$94.3 million~~ to repurchase certain of our ~~2022~~ Senior Notes, and ~~2024~~$10.5 million of debt issuance costs incurred upon the issuance of the 2025 Senior Secured Notes, ~~in open market transactions.~~offset by net borrowings under our revolving credit facility of $70.5 million. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. ~~For the nine months ended September 30, 2019, we had net borrowings under our revolving credit facility of $129.0 million used to fund capital expenditures.~~

Interest Rate Risk

We are exposed to market risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. As of ~~September~~June 30, ~~2020,~~2021, we had a ~~$178.0~~$52.5 million balance on our revolving credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Unsecured Notes or fixed-rate Senior Secured Notes but can impact their fair values. As of ~~September~~June 30, ~~2020,~~2021, our outstanding principal amount of fixed-rate debt totaled $2.2 billion and our floating-rate debt outstanding totaled ~~$178.0~~$52.5 million. Please refer to Note 118 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair values of our Senior Notes.

Commodity Price Risk

The prices we receive for our oil, gas, and NGL production directly impact our revenue, profitability, access to capital, and future rate of growth. Oil, gas, and NGL prices are subject to unpredictable fluctuations resulting from a variety of factors, including changes in supply and demand and the macroeconomic environment, and seasonal anomalies, all of which are typically beyond our control. The markets for oil, gas, and NGLs have been volatile, especially over the last several ~~months and~~ years. ~~During the first half of 2020, oil, gas, and NGL~~Commodity prices ~~weakened to~~have improved from historic lows ~~as a result~~in 2020 resulting from the impacts of the Pandemic, ~~and other macroeconomic events and will likely continue to be volatile in the future.~~however, future infection rate surges or outbreaks could have further negative impacts on prices. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our production for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, a 10 percent decrease in our average realized oil, gas, and NGL prices, before the effects of derivative settlements, would have reduced our oil, gas, and NGL production revenues by approximately ~~$61.9~~$74.2 million, ~~$12.5~~$17.8 million, and ~~$6.2~~$6.6 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, would have offset the declines in oil, gas, and NGL production revenue by approximately ~~$59.2~~$82.1 million.

We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of ~~September~~June 30, ~~2020,~~2021, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative

instruments would have changed our net derivative positions for these products by approximately ~~$117.7~~$145.1 million, ~~$26.2~~$28.3 million, and ~~$1.8~~$11.8 million, respectively.

Off-Balance Sheet Arrangements

As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

We evaluate our transactions to determine if any variable interest entities exist. If we determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions during the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, or through the filing of this report.

Critical Accounting Policies and Estimates

Please refer to the corresponding section in Part II, Item 7 and to Note 1 - Summary of Significant Accounting Policies included in Part II, Item 8 of our ~~2019~~2020 Form 10-K for discussion of our accounting policies and estimates.

New Accounting Pronouncements

Please refer to Note 1 - Summary of Significant Accounting Policies ~~under~~in Part I, Item 1 of this report for new accounting pronouncements.

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Non-GAAP Financial Measures

Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on adjusted EBITDAX ratios as further described in Note 5 - Long-Term Debt in the ~~Credit Agreement~~2020 Form 10-K ~~section in~~ ~~Overview of Liquidity and Capital Resources~~ ~~above.~~. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our revolving credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, we would be in default, an event that would prevent us from borrowing under our revolving credit facility and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under our revolving credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing each series of our outstanding Senior Notes would be entitled to exercise all of their remedies for default.

The following table provides reconciliations of our net ~~income (loss)~~loss (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:


		For the Three Months Ended September 30,				For the Nine Months Ended September 30,					For the Three Months Ended June 30,				For the Six Months Ended June 30,
		2020		2019		2020		2019			2021		2020		2021		2020
		(in thousands)
Net income (loss) (GAAP)		$	(98,292)	$	42,234	$	(599,439)	$	(84,946)
											(in thousands)
Net loss (GAAP)										Net loss (GAAP)	$	(222,995)	$	(89,252)	$	(474,264)	$	(501,147)
Interest expense	Interest expense	41,519		40,584		123,385		118,191		Interest expense	39,536		40,354		79,407		81,866
Income tax expense (benefit)		(22,969)		16,111		(158,662)		(16,337)
Income tax benefit										Income tax benefit	(162)		(36,685)		(56)		(135,693)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	Depletion, depreciation, amortization, and asset retirement obligation liability accretion	181,708		211,125		596,053		595,201		Depletion, depreciation, amortization, and asset retirement obligation liability accretion	204,714		180,856		371,674		414,345
Exploration (1)	Exploration (1)	7,882		10,341		26,970		30,070		Exploration (1)	7,902		8,696		15,941		19,088
Impairment	Impairment	8,750		6,337		1,007,263		25,092		Impairment	8,750		8,750		17,500		998,513
Stock-based compensation expense	Stock-based compensation expense	4,164		6,766		15,437		18,758		Stock-based compensation expense	3,956		5,712		9,693		11,273
Net derivative (gain) loss	Net derivative (gain) loss	63,871		(100,889)		(314,269)		(3,463)		Net derivative (gain) loss	370,348		167,200		715,037		(378,140)
Derivative settlement gain		70,305		24,722		286,270		23,843
Net gain on divestiture activity		—		—		(91)		(323)
Gain on extinguishment of debt		(25,070)		—		(264,546)		—
Derivative settlement gain (loss)										Derivative settlement gain (loss)	(158,822)		142,528		(266,707)		215,965

(Gain) loss on extinguishment of debt										(Gain) loss on extinguishment of debt	2,144		(227,281)		2,144		(239,476)
Other, net	Other, net	615		434		1,651		1,129		Other, net	1,512		612		1,502		945
Adjusted EBITDAX (non-GAAP)	Adjusted EBITDAX (non-GAAP)	232,483		257,765		720,022		707,215		Adjusted EBITDAX (non-GAAP)	256,883		201,490		471,871		487,539
Interest expense	Interest expense	(41,519)		(40,584)		(123,385)		(118,191)		Interest expense	(39,536)		(40,354)		(79,407)		(81,866)
Income tax (expense) benefit		22,969		(16,111)		158,662		16,337
Income tax benefit										Income tax benefit	162		36,685		56		135,693
Exploration (1)	Exploration (1)	(7,882)		(10,341)		(26,970)		(30,070)		Exploration (1)	(7,902)		(8,696)		(15,941)		(19,088)
Amortization of debt discount and deferred financing costs	Amortization of debt discount and deferred financing costs	4,506		3,921		13,084		11,554		Amortization of debt discount and deferred financing costs	4,722		4,586		9,445		8,578
Deferred income taxes	Deferred income taxes	(22,796)		19,617		(159,064)		(13,620)		Deferred income taxes	(162)		(36,921)		(214)		(136,268)
Other, net	Other, net	(2,991)		(1,438)		(7,854)		(3,420)		Other, net	(297)		(3,714)		(14,879)		(4,863)
Net change in working capital	Net change in working capital	16,843		(9,673)		(40,411)		11,781		Net change in working capital	82,529		(38,737)		31,092		(57,254)
Net cash provided by operating activities (GAAP)	Net cash provided by operating activities (GAAP)	$	201,613	$	203,156	$	534,084	$	581,586	Net cash provided by operating activities (GAAP)	$	296,399	$	114,339	$	402,023	$	332,471

(1) Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this item is provided under the captions Interest Rate Risk and Commodity Price Risk in Item 2 above, as well as under the section entitled Summary of Oil, Gas, and NGL Derivative Contracts in Place in Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report and is incorporated herein by reference. Please also refer to the information under Interest Rate Risk and Commodity Price Risk in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our ~~2019~~2020 Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer (Principal Executive Officer) and our Chief Financial Officer (Principal Financial Officer), as appropriate, to allow for timely decisions regarding required disclosure.

Our management, including our Chief Executive Officer and our Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes during the ~~third~~second quarter of ~~2020~~2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

~~From time to time,~~At times, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing of this report, no legal proceedings are pending against us that we believe individually or collectively are ~~expected~~likely to have a materially adverse effect upon our financial condition, results of operations or cash flows.

SPM NAM LLC. et al., v. SM Energy Company,, Case No. 2018-07160, in the 189th Judicial District of Harris County, Texas. The case remains in discovery and ~~the original~~ trial ~~date of June 22, 2020 has been postponed until the first quarter of 2021 due to the Pandemic.~~is scheduled for November 8, 2021. Please refer to Legal Proceedings in Part I, Item 3 of ~~the~~our ~~2019~~2020 Form 10-K for additional detail regarding this case.

Other than as described above, there have been no material changes to the legal proceedings as previously disclosed in our ~~2019~~2020 Form 10-K.

ITEM 1A. RISK FACTORS

The global COVID-19 Pandemic has impacted and will likely continue to impact us, and could have a material adverse effect on our business, financial condition, liquidity, results of operations and prospects.

Since the beginning of 2020, the Pandemic has spread across the globe and disrupted economies around the world, including the oil, gas and NGL industry in which we operate. The rapid spread of the virus has led to the implementation of various responses, including federal, state and local government-imposed quarantines, shelter-in-place mandates, sweeping restrictions on travel, and other public health and safety measures, nearly all of which have materially reduced global demand for crude oil. The extent to which the Pandemic will continue to affect our business, financial condition, liquidity, results of operations, prospects, and the demand for our production will depend on future developments, which are highly uncertain and cannot be predicted with confidence, including the duration or any recurrence of the outbreak and responsive measures, additional or modified government actions, new information which may emerge concerning the severity of the Pandemic, and the effectiveness of actions taken to contain COVID-19 or treat its impact, such as development of a vaccine or other treatment protocol, now or in the future, among others.

~~Some impacts of the Pandemic that could have an adverse effect on our business, financial condition, liquidity and results of operations, include:~~

•~~significantly reduced prices for our oil, gas, and NGL production, resulting from a world-wide decrease in demand for hydrocarbons and a resulting oversupply of existing production;~~

•further decreases in the demand for our oil, gas, and NGL production, resulting from significantly decreased levels of global, regional and local travel as a result of federal, state and local government-imposed quarantines, including shelter-in-place mandates, enacted to slow the spread of the virus;

•the continuing possibility that we may further voluntarily curtail or shut-in production, resulting from depressed oil prices, lack of storage, and other market or political forces, or that we may curtail or shut-in production as a result of third-party and regulatory mandates;

•~~increased costs associated with, or actual unavailability of, facilities for the storage of oil, gas, and NGL production, in the markets in which we operate;~~

•~~increased operational difficulties associated with, or an inability to, deliver oil, gas, and NGLs to end-markets, resulting from pipeline and storage constraints;~~

•the potential for loss of leasehold or asset value for failure to produce oil and gas in paying quantities as a result of significantly lower commodity prices, or failures or difficulties in bringing shut-in wells back online at their prior production levels, or other factors related to the misalignment of supply and demand, and the potential to incur significant costs associated with litigation related to the foregoing;

•increased third-party credit risk, including the risk that counterparties may not accept the delivery of our oil, gas, and NGL production, resulting from adverse market conditions, a lack of access to capital and the failure of certain of our counterparties to continue as going concerns;

•increased likelihood that counterparties to our existing agreements may seek to invoke force majeure provisions to avoid the performance of contractual obligations, resulting from significantly adverse market conditions;

•~~decreased ability to access the capital markets or other sources of capital;~~

•cyber attacks or information security breaches resulting in information theft, data corruption, operational disruption, rendering data or systems unusable, and/or financial loss as a consequence of employees working and accessing information from remote work locations;

•increased costs and staffing requirements related to facility modifications, social distancing measures or other best practices implemented in connection with federal, state or local government, and voluntarily imposed quarantines or other regulations or guidelines concerning physical gatherings;

•~~risks associated with companies and/or individuals moving to a permanent remote work status such that certain elements of demand may never recover to previous, historic levels;~~

•~~loss of talent in our industry including technical personnel and other professionals as people pursue other industries; and~~

•~~increased legal and operational costs related to compliance with significant changes in federal, state, and local laws and regulations.~~

To the extent the Pandemic continues to adversely affect the global economy, and/or adversely affects our business, financial condition, liquidity, results of operations and prospects it may also increase the likelihood and/or magnitude of other risks described in Risk Factors in Part I, Item 1A of our ~~2019 Form 10-K~~ and in this report, including those risks related to market, credit, geopolitical and business operations, or risks described in our other filings with the SEC. In addition, the Pandemic, or any recurrence of the outbreak may also affect our business, operations or financial condition in a manner that is not presently known to us or that we currently do not expect to present a significant risk to our business, operations, or financial condition. Also, the extent and duration of the impacts of macroeconomic events and the Pandemic on our stock price and that of our peer companies is uncertain and may make us look less attractive to investors and, as a result, there may be a less active trading market for our common stock, our stock price may be more volatile and our ability to raise capital could be impaired. Any such future developments are dependent upon factors including, but are not limited to, the duration and spread of the outbreak, its severity, any recurrence of the outbreak, the actions to contain the virus or treat its impact, the size and effectiveness of the compensating measures taken by governments, and how quickly and to what extent normal economic and operating conditions can resume.

The ability or willingness of the Organization of the Petroleum Exporting Countries (“OPEC”), Russia and other oil exporting nations to set, maintain and enforce production levels has a significant impact on oil, gas and NGL commodity prices, which could have a material adverse effect on our business, financial condition, liquidity and results of operations.

OPEC is an intergovernmental organization that seeks to manage the price and supply of oil and oil pricing on the global energy market. Actions taken by OPEC member countries, including those taken along with other oil exporting nations, have a significant impact on global oil supply and pricing. In March 2020, members of OPEC and ten other oil producing countries met to discuss how to respond to the potential market effects of the Pandemic. The meeting ended in discord regarding production cuts and oil pricing among OPEC, Russia, and other oil exporting nations. These actions flooded the global market with an oversupply of crude oil, and led to an immediate and steep decrease in global oil prices. In early April 2020, in response to significantly depressed global oil prices, 23 countries, led by Saudi Arabia, Russia and the United States, committed to implement reductions in world oil production.

There can be no assurance that measures to limit global production will stabilize oil prices or that they will be maintained. The impacts of the Pandemic continue to be unpredictable and future case surges or outbreaks may continue to have further negative effects on global oil demand, despite the concerted action to reduce global production. Further, there is a lack of transparency regarding production volumes among oil-producing nations, and there are limited enforcement mechanisms for real or perceived violations of the production cuts. In connection with past production cuts, OPEC has at times failed to enforce its own production limits on violating members, with no official mechanism for punishing member countries that do not comply. There can be no assurance that OPEC and non-OPEC member countries will abide by the quotas or that OPEC will enforce the quotas. Additionally, certain other countries with free-market economies that agreed to reduce production, are unable to impose mandatory production cuts on non-OPEC oil producers operating in their countries, but instead expect to realize a decrease in production through market forces, as companies tend to cut production voluntarily when prices drop. For such countries, there can be no assurance that oil producers will react in the desired manner or that the market will behave as expected. Uncertainty regarding the effectiveness and enforcement of the production cuts is likely to lead to increased volatility in the supply and demand of oil and the price of oil, all of which could have a material adverse effect on our business, financial condition, liquidity and results of operations.

If we cannot continue to meet the continued listing requirements of the New York Stock Exchange (the “NYSE”), the NYSE may delist our common stock, which would have an adverse impact on the trading volume, liquidity and market price of our common stock and allow holders of our 2021 Senior Secured Convertible Notes to require us to repurchase their notes.

Pursuant to the NYSE Listed Company Manual, a company will be considered to be out of compliance with the NYSE’s continued listing standards if the average trading price of its common stock over any consecutive 30-trading-day period falls below $1.00 per share, which is the minimum average closing price required to maintain listing on the NYSE. While we continue to maintain compliance with the minimum average closing price required to maintain listing on the NYSE through the filing of this report, if we do not maintain an average closing price of $1.00 or more for our common stock over any consecutive 30 trading-day period, the NYSE may delist our common stock for failure to maintain compliance with the NYSE price criteria listing standards. NYSE rules provide issuers six months from NYSE notification of a deficiency to cure noncompliance with the stock price listing standard before the NYSE begins suspension and delisting procedures. An issuer can regain compliance at any time during the six-month cure period if, on the last trading day of any calendar month during the cure period, the company has a closing stock price of at least $1.00 and an average

~~closing stock price of at least $1.00 over the 30~~-~~trading-day period ending on the last trading day of that month. However, there can be no assurance that we would be able to regain compliance during such cure period.~~

A delisting of our common stock from the NYSE could negatively impact us by, among other things: reducing the liquidity and market price of our common stock; reducing the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing; decreasing the number of equity analysts that cover and report on our common stock, which could further reduce the number of investors willing to hold or acquire our common stock; and limiting our ability to issue additional securities or obtain additional financing in the future. In addition, delisting from the NYSE is likely to negatively impact our reputation and, as a consequence, our business.

Further, if our common stock is delisted by the NYSE (and we are not eligible to become listed on other specified exchanges), holders of our 2021 Senior Secured Convertible Notes would have a right to require us to repurchase the 2021 Senior Secured Convertible Notes at a purchase price equal to 100% of the principal amount thereof, plus accrued and unpaid interest thereon. As of September 30, 2020, $65.5 million aggregate principal amount of the 2021 Senior Secured Convertible Notes was outstanding, and there can be no assurance we would have sufficient funds available to us to repurchase the 2021 Senior Secured Convertible Notes put to us if required to do so in connection with a delisting. Failure to repurchase the 2021 Senior Secured Convertible Notes put to us could, subject to a 60-day right to cure set forth in the 2021 Notes Indenture, result in (a) an event of default under the supplemental indenture, and (b) the potential acceleration of our obligation to repay all outstanding 2021 Senior Secured Convertible Notes, and could cause a cross-default under our other outstanding indebtedness, which could result in the foreclosure on the collateral securing our secured debt. As a result, we could be forced into bankruptcy or liquidation.

The depressed price of our common stock and market capitalization, resulting from the current macroeconomic environment and historically low commodity prices, could cause the Company to be subject to an unsolicited or hostile acquisition bid, which could result in substantial costs and diversion of management attention.

Due to the currently constrained macroeconomic environment and historically low commodity prices, the price of our common stock and market capitalization are significantly depressed. A relatively low stock price may cause us to become subject to an unsolicited or hostile acquisition bid, or other change in control. There can be no assurance that a third-party will not make an unsolicited takeover proposal in the future or take other action to acquire control of us or to otherwise influence our management and policies. Although we have certain anti-takeover measures in place, we have not adopted a shareholder rights plan, commonly known as a poison pill. The lack of this particular anti-takeover measure could make a change in control of us easier to accomplish.

Considering and responding to any future acquisition proposal or other stockholder action designed to acquire control, including the litigation that often accompanies such actions, is likely to be costly and time-consuming. Evaluating and addressing these overtures would require the time and attention of our management and Board of Directors, divert them from their focus on our business, and require us to incur additional expenses on outside legal, financial and other advisors, all of which could materially and adversely affect our business, financial condition and results of operations. Further, in the event that such an unsolicited or hostile bid is publicly disclosed, it may result in increased speculation and volatility in the price of our common stock.

There have been no ~~other~~ material changes to the risk factors as previously disclosed in our ~~2019~~2020 Form 10-K~~, our Quarterly Reports on Form 10-Q for the quarterly periods ended~~ ~~March 31, 20~~20 ~~and~~ ~~June 30, 20~~20~~, and our 2020 Proxy Statement.~~.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

~~The following table provides information about~~There were no purchases made by us ~~and~~or any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the three months ended ~~September~~June 30, ~~2020,~~2021, of shares of our common stock, which is the sole class of equity securities registered by us pursuant to Section 12 of the Exchange ~~Act:~~Act.

PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASES
Period
Total Number of Shares Purchased (1)
Weighted Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Program
Maximum Number of Shares that May Yet Be Purchased Under the Program (2)
07/01/2020 - 07/31/2020 381,977 $ 3.75 — 3,072,184
08/01/2020 - 08/31/2020 42,259 $ 2.95 — 3,072,184
09/01/2020 - 09/30/2020 — $ — — 3,072,184
Total: 424,236 $ 3.67 — 3,072,184

~~(1)~~ All shares purchased by us in the third quarter of 2020 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs and PSUs issued under the terms of award agreements granted under the Equity Plan.

~~(2)~~In July 2006, our Board of Directors approved an increase in the number of shares of common stock that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the filing of this report, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior ~~Secured Notes and Senior Unsecured~~ Notes, and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flows, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time. During the three months ended ~~September~~June 30, ~~2020,~~2021, we did not repurchase any shares of our common stock pursuant to this Board of Director’s approval, and we currently do not plan to repurchase any outstanding shares of our common stock during the remainder of ~~2020.~~2021.

Our payment of cash dividends to our stockholders is subject to certain covenants under the terms of our Credit Agreement and Senior Notes. Based on our current performance, we do not anticipate that any of these covenants will limit our payment of dividends at our current rate for the foreseeable future if any dividends are declared by our Board of Directors.

~~ITEM 5. OTHER INFORMATION~~

As previously announced, Javan D. Ottoson, the Chief Executive Officer of the Company, previously advised the Board of Directors of his intention to retire before the end of 2020. Mr. Ottoson has determined and notified the Board of Directors that he will retire at the close of business on November 2, 2020. There were no known disagreements between Mr. Ottoson and the Company that led to Mr. Ottoson’s decision to retire.

Mr. Ottoson and the Company entered into a Non-Competition and Non-Solicitation Agreement on October 26, 2020 (the “Non-Competition Agreement”), pursuant to which, among other customary agreements, Mr. Ottoson covenants not to compete with the Company’s business and not to solicit the Company’s employees for a period of two years following his retirement from the Company. Subject to Mr. Ottoson’s continued compliance with such covenants, the Company will pay Mr. Ottoson an aggregate of $800,000 in two equal annual cash installments of $400,000 on the first and second anniversaries of his retirement from the Company. The foregoing description of the Non-Competition Agreement is qualified in its entirety by reference to the full text of the Non-Competition Agreement, a copy of which is attached hereto as Exhibit 10.7.

Following Mr. Ottoson’s retirement as the Chief Executive Officer of the Company, he will continue to serve as a member of the Board of Directors until the Company’s annual meeting of stockholders in May 2021, and will receive prorated cash consideration of $105,000, reflecting the portion of the term during which he will serve as a non-employee director.

In addition, Mr. Ottoson will remain eligible to receive a cash bonus under the Company’s Cash Bonus Plan, as amended and restated as of February 1, 2014 (“STIP”). If Mr. Ottoson is granted a cash bonus, such bonus will be prorated for the portion of the 2020 calendar year during which he served as the President and/or Chief Executive Officer of the Company. The cash bonus will be determined by the Compensation Committee, based on Mr. Ottoson’s individual performance and Company performance as measured against the pre-established metrics applicable to all employees under the STIP, and will be paid at the same time as cash bonuses are paid to all other Company employees.

On October 26, 2020, the Board of Directors appointed Herbert S. Vogel to serve as Chief Executive Officer of the Company, effective upon Mr. Ottoson’s retirement. Mr. Vogel currently serves as the President and Chief Operating Officer of the Company.

In connection with his promotion, Mr. Vogel’s annual base salary will be increased to $750,000, which amount presently will be reduced by 20% to $600,000 in response to previously announced cost-reduction efforts related to the COVID-19 Pandemic and other macroeconomic events, and his annual cash bonus target under the STIP will be 120% of his base salary. For plan year 2020, (i) Mr. Vogel’s annual cash bonus under the STIP will be determined using the applicable target percentage for the portion of the year that he served in each of the roles he held during the fiscal year, subject, in each case, to individual performance and Company performance as measured against the pre-established metrics applicable to all employees, and (ii) the target value of his long-term incentive plan award under the Company’s Equity Incentive Compensation Plan will be $2.950 million, a reduced amount this year reflective of industry and macroeconomic conditions.

The Board of Directors also approved on October 26, 2020, an increase in the number of authorized directors constituting the Board of Directors from nine members to ten members, and the appointment of Mr. Vogel as an employee director to fill the vacancy created by such increase, effective as of his appointment to the role of Chief Executive Officer, to serve until the Company’s annual meeting of stockholders in May 2021.

5041

ITEM 6. EXHIBITS

The following exhibits are filed or furnished with or incorporated by reference into this report:


Exhibit Number			Description
3.1			Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated herein by reference)
3.2			Amended and Restated By-Laws of SM Energy Company, effective as of February 21, 2017 (filed as Exhibit 3.2 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2016, and incorporated herein by reference)
4.1			~~Third~~Fifth Supplemental Indenture, dated as of ~~April 29, 2020, to the Indenture, dated as of May 21, 2015,~~June 23, 2021, by and between ~~the~~SM Energy Company and U.S. Bank National Association, as trustee as supplemented and amended by the Second Supplemental Indenture, dated as of August 12, 2016 governing the Company’s outstanding 1.50% Senior Convertible Notes due 2021 (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on April 29, 2020, and incorporated herein by reference)
~~4.2~~			Indenture, dated as of June 17, 2020, between SM Energy Company and UMB Bank, N.A., as trustee, governing the Company’s outstanding 10.0% Senior Secured Notes due 2025 (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on June 17, 2020, and incorporated herein by reference)
~~4.3~~			~~Warrant Agreement dated as of June 17, 2020, among SM Energy Company, Computershare Inc. and Computershare Trust Company, N.A., collectively as warrant agent~~ (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on June ~~17, 2020,~~23, 2021, and incorporated herein by reference)
~~10.1~~4.2			~~Third Amendment to the Sixth Amended~~2022 Notes Supplemental Indenture, dated as of June 23, 2021, by and ~~Restated Credit Agreement, dated April 29, 2020, among~~between SM Energy Company ~~Wells Fargo~~and U.S. Bank National Association, as ~~Administrative Agent, and the institutions named therein as Lenders that are party thereto~~trustee (filed as Exhibit ~~10.1~~4.3 to the registrant’s ~~Quarterly~~Current Report on Form ~~10-Q for~~8-K filed on June 23, 2021, and incorporated herein by reference)
10.1†			SM Energy Company Employee Stock Purchase Plan, amended and restated effective as of April 5, 2021 (filed as Annex A in the ~~quarter ended March 31, 2020,~~registrant’s Definitive Proxy Statement on Schedule 14A, filed on April 16, 2021, and incorporated herein by reference)
10.2			~~Fourth~~Sixth Amendment to the Sixth Amended and Restated Credit Agreement, dated as of ~~May 5, 2020,~~June 8, 2021, by and among the Company, Wells Fargo Bank, National Association, as Administrative Agent, and the institutions named therein as Lenders that are a party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on ~~May 6, 2020,~~June 9 , 2021, and incorporated herein by reference)
~~10.3~~			Intercreditor Agreement dated as of June 17, 2020 among SM Energy Company, Wells Fargo Bank, National Association, as priority lien agent, and UMB Bank, N.A., as second lien collateral trustee (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on June 17, 2020, and incorporated herein by reference)
~~10.4~~			Second Lien Pledge and Security Agreement dated as of June 17, 2020 between SM Energy Company and UMB Bank, N.A., as collateral trustee (filed as Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on June 17, 2020, and incorporated herein by reference)
~~10.5~~			Second Lien Security Agreement dated as of June 17, 2020 between SM Energy Company and UMB Bank, N.A., as collateral trustee (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on June 17, 2020, and incorporated herein by reference)
~~10.6~~			Collateral Trust Agreement dated as of June 17, 2020 among SM Energy Company, UMB Bank, N.A., as trustee, UMB Bank, N.A., as collateral trustee, and (by joinder) U.S. Bank National Association, as trustee under the 2021 Notes Indenture (filed as Exhibit 10.4 to the registrant’s Current Report on Form 8-K filed on June 17, 2020, and incorporated herein by reference)
10.7*			~~Non-Competition and Non-Solicitation Agreement~~ ~~dated~~ ~~October 26, 2020between Javan D. Ottoson and SM Energy Company~~
31.1*			Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
31.2*			Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
32.1**			Certification 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 Schema Document
101.CAL*			Inline XBRL Calculation Linkbase Document
101.LAB*			Inline XBRL Label Linkbase Document
101.PRE*			Inline XBRL Presentation Linkbase Document
101.DEF*			Inline XBRL Taxonomy Extension Definition Linkbase Document
104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101.INS)


*			Filed with this report.
**			Furnished with this report.
†			Exhibit constitutes a management contract or compensatory plan or agreement.

5142

SIGNATURES

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


	SM ENERGY COMPANY

~~October~~July 30, ~~2020~~2021	By:	/s/ ~~JAVAN D. OTTOSON~~HERBERT S. VOGEL
		~~Javan D. Ottoson~~Herbert S. Vogel
		President and Chief Executive Officer
		(Principal Executive Officer)

~~October~~July 30, ~~2020~~2021	By:	/s/ A. WADE PURSELL
		A. Wade Pursell
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

~~October~~July 30, ~~2020~~2021	By:	/s/ PATRICK A. LYTLE
		Patrick A. Lytle
		Vice President - Chief Accounting Officer and Controller and Assistant Secretary
		(Principal Accounting Officer)

5243


Borrowing Base Utilization Percentage	<25%		≥25% <50%		≥50% <75%		≥75% <90%		≥90%
Eurodollar Loans (1)	1.750	%	2.000	%	2.500	%	2.750	%	3.000	%
ABR Loans or Swingline Loans	0.750	%	1.000	%	1.500	%	1.750	%	2.000	%
Commitment Fee Rate	0.375	%	0.375	%	0.500	%	0.500	%	0.500	%


	PSUs (1)	Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year	2,022,585	$	16.87
Granted	0	$	0
Vested	(791,962)	$	15.85
Forfeited	(45,731)	$	16.69
Non-vested at end of quarter	1,184,892	$	17.56


	RSUs	Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year	1,532,131	$	16.01
Granted	0	$	0
Vested	(744,325)	$	16.74
Forfeited	(77,814)	$	15.67
Non-vested at end of quarter	709,992	$	15.29


Contract Period	NYMEX WTI Volumes	Weighted-Average Contract Price
	(MBbl)	(per Bbl)


Fourth quarter 2020	4,397	$	57.03
2021	17,115	$	40.38
2022	3,885	$	43.58
Total	25,397


Contract Period	WTI Midland-NYMEX WTI Volumes	Weighted-Average Contract Price (1)		NYMEX WTI-ICE Brent Volumes	Weighted-Average Contract Price (2)
	(MBbl)	(per Bbl)		(MBbl)	(per Bbl)


Fourth quarter 2020	4,087	$	(0.38)	920	$	(8.01)
2021	13,975	$	0.75	3,650	$	(7.86)
2022	9,500	$	1.15	3,650	$	(7.78)

Total	27,562			8,220


	OPIS Propane Mont Belvieu Non-TET
Contract Period		Volumes	Weighted-Average Contract Price
		(MBbl)	(per Bbl)


Fourth quarter 2020		466	$	22.29
2021		392	$	19.74

Total		858


	As of September 30, 2020
	(in thousands)
2020 (remaining after September 30, 2020)	$	3,546
2021	12,855
2022	5,920
2023	3,596
2024	2,081
Thereafter	1,640
Total Lease payments	$	29,638
Less: Imputed interest (1)	(2,856)
Total	$	26,782


PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASES
Period	Total Number of Shares Purchased (1)	Weighted Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum Number of Shares that May Yet Be Purchased Under the Program (2)
07/01/2020 - 07/31/2020	381,977	$	3.75	—	3,072,184
08/01/2020 - 08/31/2020	42,259	$	2.95	—	3,072,184
09/01/2020 - 09/30/2020	—	$	—	—	3,072,184
Total:	424,236	$	3.67	—	3,072,184