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, ~~2022~~2023

☐ 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.)

1700 Lincoln Street, Suite 3200, 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 27, 2022,~~July 21, 2023, the registrant had ~~122,796,046~~118,665,529 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, ~~2022,~~2023, and December 31, 20 2 12022	4

	Condensed Consolidated Statements of Operations Three and ~~Nine~~Six Months Ended ~~September 30,~~ June 3 0 , 2023, and 2022 ~~and 2021~~	5

	Condensed Consolidated Statements of Comprehensive Income ~~(Loss)~~ Three and ~~Nine~~Six Months Ended ~~September 30,~~Ju ne 3 0 , 2023, and 2022 ~~and 2021~~	6

	Condensed Consolidated Statements of Stockholders’ Equity Continuous Quarterly Presentation Ended ~~September~~June 30, ~~2022,~~2023, and ~~2021~~2022	7

	Condensed Consolidated Statements of Cash Flows ~~Nine~~Six Months Ended ~~September~~June 30, ~~2022,~~2023, and ~~2021~~2022	98

	Notes to Condensed Consolidated Financial Statements	109

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2521

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4236

Item 4.	Controls and Procedures	4236

	Part II	4337

Item 1.	Legal Proceedings	4337

Item 1A.	Risk Factors	4337

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4437



Item 6.	Exhibits	4538

	Signatures	4639

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 (“Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (“Exchange Act”). All statements included in this report, other than statements of historical ~~facts,~~fact, 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,” “goal,” “intend,” “pending,” “plan,” “potential,” “projected,” “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:

•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, debt redemptions or equity repurchases, capital markets activities, environmental, social, and governance (“ESG”) goals and initiatives, and our outlook on our future financial condition or results of operations;

•the amount and nature of future capital expenditures, the resilience of our assets to declining commodity prices, and the availability of liquidity and capital resources to fund capital expenditures;

•our outlook on prices for future crude oil, natural gas, and natural gas liquids (also referred to throughout this report as “oil,” “gas,” and “NGLs,” respectively), well costs, service costs, production costs, and general and administrative ~~costs;~~costs, and the effects of inflation on each of these;

•armed conflict, political instability, or civil unrest in ~~crude~~ oil and ~~natural~~ gas producing regions, including the ongoing conflict between Russia and Ukraine, and related potential effects on laws and regulations, or the imposition of economic or trade sanctions;

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

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

•~~the effects of the global COVID-19 pandemic (“Pandemic”) on us, our industry, our financial condition, and our results of operations;~~

•our drilling and completion activities and other exploration and development activities, each of which could be ~~impacted~~affected by supply chain disruptions and inflation, 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-out of, or farm-in 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, as well as the conversion of proved undeveloped reserves to proved developed reserves;

•our expected future production volumes, identified drilling locations, as well as drilling prospects, inventories, projects and programs; 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. We caution you that forward-looking statements are not guarantees of future performance and these statements are subject to known and unknown risks and uncertainties, which may cause our actual results or 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, ~~2021~~2022 (“~~2021~~2022 Form 10-K”).

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, 2022		December 31, 2021			June 30, 2023		December 31, 2022
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	498,435	$	332,716	Cash and cash equivalents	$	378,238	$	444,998
Accounts receivable	Accounts receivable	258,003		247,201		Accounts receivable	217,794		233,297
Derivative assets	Derivative assets	42,207		24,095		Derivative assets	74,138		48,677
Prepaid expenses and other	Prepaid expenses and other	9,133		9,175		Prepaid expenses and other	8,815		10,231
Total current assets	Total current assets	807,778		613,187		Total current assets	678,985		737,203
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	9,914,261		9,397,407		Proved oil and gas properties	10,824,717		10,258,368
Accumulated depletion, depreciation, and amortization	Accumulated depletion, depreciation, and amortization	(6,054,796)		(5,634,961)		Accumulated depletion, depreciation, and amortization	(6,494,068)		(6,188,147)
Unproved oil and gas properties		579,261		629,098
Unproved oil and gas properties, net of valuation allowance of $37,904 and $38,008, respectively						Unproved oil and gas properties, net of valuation allowance of $37,904 and $38,008, respectively	524,693		487,192
Wells in progress	Wells in progress	276,298		148,394		Wells in progress	332,609		287,267

Other property and equipment, net of accumulated depreciation of $62,950 and $62,359, respectively		31,831		36,060
Other property and equipment, net of accumulated depreciation of $58,203 and $56,512, respectively						Other property and equipment, net of accumulated depreciation of $58,203 and $56,512, respectively	43,276		38,099
Total property and equipment, net	Total property and equipment, net	4,746,855		4,575,998		Total property and equipment, net	5,231,227		4,882,779
Noncurrent assets:	Noncurrent assets:					Noncurrent assets:
Derivative assets	Derivative assets	36,048		239		Derivative assets	12,077		24,465
Other noncurrent assets	Other noncurrent assets	60,832		44,553		Other noncurrent assets	70,337		71,592
Total noncurrent assets	Total noncurrent assets	96,880		44,792		Total noncurrent assets	82,414		96,057
Total assets	Total assets	$	5,651,513	$	5,233,977	Total assets	$	5,992,626	$	5,716,039
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	$	631,984	$	563,306	Accounts payable and accrued expenses	$	530,459	$	532,289

Derivative liabilities	Derivative liabilities	174,717		319,506		Derivative liabilities	22,210		56,181
Other current liabilities	Other current liabilities	7,316		6,515		Other current liabilities	11,319		10,114
Total current liabilities	Total current liabilities	814,017		889,327		Total current liabilities	563,988		598,584
Noncurrent liabilities:	Noncurrent liabilities:					Noncurrent liabilities:
Revolving credit facility	Revolving credit facility	—		—		Revolving credit facility	—		—
Senior Notes, net	Senior Notes, net	1,571,429		2,081,164		Senior Notes, net	1,573,772		1,572,210

Asset retirement obligations	Asset retirement obligations	97,724		97,324		Asset retirement obligations	113,999		108,233

Deferred income taxes	Deferred income taxes	212,470		9,769		Deferred income taxes	375,063		280,811
Derivative liabilities	Derivative liabilities	14,506		25,696		Derivative liabilities	5,894		1,142
Other noncurrent liabilities	Other noncurrent liabilities	73,705		67,566		Other noncurrent liabilities	61,443		69,601
Total noncurrent liabilities	Total noncurrent liabilities	1,969,834		2,281,519		Total noncurrent liabilities	2,130,171		2,031,997

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

Stockholders’ equity:	Stockholders’ equity:					Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 122,796,046 and 121,862,248 shares, respectively		1,228		1,219
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 118,112,105 and 121,931,676 shares, respectively						Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 118,112,105 and 121,931,676 shares, respectively	1,181		1,219
Additional paid-in capital	Additional paid-in capital	1,810,352		1,840,228		Additional paid-in capital	1,680,080		1,779,703
Retained earnings	Retained earnings	1,068,385		234,533		Retained earnings	1,621,202		1,308,558
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(12,303)		(12,849)		Accumulated other comprehensive loss	(3,996)		(4,022)
Total stockholders’ equity	Total stockholders’ equity	2,867,662		2,063,131		Total stockholders’ equity	3,298,467		3,085,458
Total liabilities and stockholders’ equity	Total liabilities and stockholders’ equity	$	5,651,513	$	5,233,977	Total liabilities and stockholders’ equity	$	5,992,626	$	5,716,039

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,
		2022		2021		2022		2021			2023		2022		2023		2022
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	$	827,558	$	759,813	$	2,676,656	$	1,745,547	Oil, gas, and NGL production revenue	$	546,555	$	990,377	$	1,117,333	$	1,849,098

Other operating income	Other operating income	7,893		426		10,673		22,387		Other operating income	4,199		1,725		6,926		2,780
Total operating revenues and other income	Total operating revenues and other income	835,451		760,239		2,687,329		1,767,934		Total operating revenues and other income	550,754		992,102		1,124,259		1,851,878
Operating expenses:	Operating expenses:									Operating expenses:
Oil, gas, and NGL production expense	Oil, gas, and NGL production expense	159,961		135,745		470,245		362,131		Oil, gas, and NGL production expense	145,588		165,593		287,936		310,284
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	Depletion, depreciation, amortization, and asset retirement obligation liability accretion	145,865		202,701		460,169		574,375		Depletion, depreciation, amortization, and asset retirement obligation liability accretion	157,832		154,823		312,021		314,304
Exploration	Exploration	14,203		8,709		44,117		26,746		Exploration	14,960		20,868		33,388		29,914

Impairment		1,077		8,750		6,466		26,250
General and administrative	General and administrative	28,428		25,530		81,715		74,883		General and administrative	27,500		28,291		55,169		53,287
Net derivative (gain) loss	Net derivative (gain) loss	(137,577)		209,146		385,180		924,183		Net derivative (gain) loss	(11,674)		104,236		(63,003)		522,757
Other operating expense, net	Other operating expense, net	1,213		43,401		2,614		44,654		Other operating expense, net	7,197		5,485		17,350		6,790
Total operating expenses	Total operating expenses	213,170		633,982		1,450,506		2,033,222		Total operating expenses	341,403		479,296		642,861		1,237,336
Income (loss) from operations		622,281		126,257		1,236,823		(265,288)
Income from operations										Income from operations	209,351		512,806		481,398		614,542
Interest expense	Interest expense	(22,825)		(40,861)		(97,708)		(120,268)		Interest expense	(22,148)		(35,496)		(44,607)		(74,883)
Gain (loss) on extinguishment of debt		—		5		(67,605)		(2,139)
Loss on extinguishment of debt										Loss on extinguishment of debt	—		(67,226)		—		(67,605)
Other non-operating income (expense), net	Other non-operating income (expense), net	1,163		153		930		(1,071)		Other non-operating income (expense), net	4,763		112		9,233		(233)
Income (loss) before income taxes		600,619		85,554		1,072,440		(388,766)
Income tax (expense) benefit		(119,379)		39		(218,951)		95
Net income (loss)		$	481,240	$	85,593	$	853,489	$	(388,671)
Income before income taxes										Income before income taxes	191,966		410,196		446,024		471,821
Income tax expense										Income tax expense	(42,092)		(86,711)		(97,598)		(99,572)
Net income										Net income	$	149,874	$	323,485	$	348,426	$	372,249

Basic weighted-average common shares outstanding	Basic weighted-average common shares outstanding	123,195		121,457		122,318		118,224		Basic weighted-average common shares outstanding	119,408		121,910		120,533		121,909
Diluted weighted-average common shares outstanding	Diluted weighted-average common shares outstanding	124,279		123,851		124,233		118,224		Diluted weighted-average common shares outstanding	120,074		124,343		121,175		124,267
Basic net income (loss) per common share		$	3.91	$	0.70	$	6.98	$	(3.29)
Diluted net income (loss) per common share		$	3.87	$	0.69	$	6.87	$	(3.29)
Basic net income per common share										Basic net income per common share	$	1.26	$	2.65	$	2.89	$	3.05
Diluted net income per common share										Diluted net income per common share	$	1.25	$	2.60	$	2.88	$	3.00
Dividends per common share	Dividends per common share	$	0.15	$	0.01	$	0.16	$	0.02	Dividends per common share	$	0.15	$	—	$	0.30	$	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)~~ (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,
		2022		2021		2022		2021			2023		2022		2023		2022
Net income (loss)		$	481,240	$	85,593	$	853,489	$	(388,671)
Net income										Net income	$	149,874	$	323,485	$	348,426	$	372,249
Other comprehensive income, net of tax:	Other comprehensive income, net of tax:									Other comprehensive income, net of tax:
Pension liability adjustment	Pension liability adjustment	182		246		546		1,029		Pension liability adjustment	13		182		26		364
Total other comprehensive income, net of tax	Total other comprehensive income, net of tax	182		246		546		1,029		Total other comprehensive income, net of tax	13		182		26		364
Total comprehensive income (loss)		$	481,422	$	85,839	$	854,035	$	(387,642)
Total comprehensive income										Total comprehensive income	$	149,887	$	323,667	$	348,452	$	372,613

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
		Shares	Amount					Accumulated Other Comprehensive Loss				Shares						Amount									Accumulated Other Comprehensive Loss
Balances, December 31, 2021		121,862,248	$	1,219						$	1,840,228				$			234,533		$	(12,849)	$	2,063,131
Net income		—	—				—						48,764			—		48,764
Other comprehensive income		—	—		—			—					182			182
Cash dividends declared, $0.01 per share		—	—		—			(1,218)					—			(1,218)

Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings		1,929	—		(24)			—					—			(24)
Stock-based compensation expense		—	—		4,274			—					—			4,274

Balances, March 31, 2022		121,864,177	$	1,219	$	1,844,478		$	282,079				$	(12,667)		$	2,115,109
Net income		—	—		—			323,485					—			323,485
Other comprehensive income		—	—		—			—					182			182

Issuance of common stock under Employee Stock Purchase Plan		65,634	1		1,644			—					—			1,645

Stock-based compensation expense		29,471	—		4,479			—					—			4,479

Balances, June 30, 2022		121,959,282	$	1,220	$	1,850,601		$	605,564				$	(12,485)		$	2,444,900
Balances, December 31, 2022																		Balances, December 31, 2022	121,931,676			$	1,219		$	1,779,703				$	1,308,558			$	(4,022)			$	3,085,458
Net income	Net income	—	—		—			481,240					—			481,240		Net income	—			—			—					198,552				—				198,552
Other comprehensive income	Other comprehensive income	—	—		—			—					182			182		Other comprehensive income	—			—			—			—				13				13
Cash dividends declared, $0.15 per share	Cash dividends declared, $0.15 per share	—	—		—			(18,419)					—			(18,419)		Cash dividends declared, $0.15 per share	—			—			—			(18,078)				—				(18,078)

Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings		1,289,498	13		(25,118)			—					—			(25,105)

Stock-based compensation expense	Stock-based compensation expense	—	—		5,105			—					—			5,105		Stock-based compensation expense	—			—			4,318			—				—				4,318

Purchase of shares under Stock Repurchase Program	Purchase of shares under Stock Repurchase Program	(452,734)	(5)		(20,236)			—					—			(20,241)		Purchase of shares under Stock Repurchase Program	(1,413,758)			(14)			(40,454)			—				—				(40,468)
Balances, September 30, 2022		122,796,046	$	1,228	$	1,810,352		$	1,068,385				$	(12,303)		$	2,867,662
Balances, March 31, 2023																		Balances, March 31, 2023	120,517,918			$	1,205		$	1,743,567		$	1,489,032			$	(4,009)			$	3,229,795
Net income																		Net income	—			—			—			149,874				—				149,874
Other comprehensive income																		Other comprehensive income	—			—			—			—				13				13
Cash dividends declared, $0.15 per share																		Cash dividends declared, $0.15 per share	—			—			—			(17,704)				—				(17,704)
Issuance of common stock under Employee Stock Purchase Plan																		Issuance of common stock under Employee Stock Purchase Plan	68,210			1			1,815			—				—				1,816
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings																		Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings	774			—			(7)			—				—				(7)
Stock-based compensation expense																		Stock-based compensation expense	56,872			1			4,162			—				—				4,163

Purchase of shares under Stock Repurchase Program																		Purchase of shares under Stock Repurchase Program	(2,550,706)			(26)			(69,457)			—				—				(69,483)
Other																		Other	19,037			—			—			—				—				—
Balances, June 30, 2023																		Balances, June 30, 2023	118,112,105			$	1,181		$	1,680,080		$	1,621,202			$	(3,996)			$	3,298,467


				Additional Paid-in Capital				Accumulated Other Comprehensive Loss		Total Stockholders’ Equity
	Common Stock					Retained Earnings
	Shares	Amount
Balances, December 31, 2021	121,862,248	$	1,219	$	1,840,228	$	234,533	$	(12,849)	$	2,063,131
Net income	—	—		—		48,764		—		48,764
Other comprehensive income	—	—		—		—		182		182
Cash dividends declared, $0.01 per share	—	—		—		(1,218)		—		(1,218)

Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings	1,929	—		(24)		—		—		(24)
Stock-based compensation expense	—	—		4,274		—		—		4,274


Balances, March 31, 2022	121,864,177	$	1,219	$	1,844,478	$	282,079	$	(12,667)	$	2,115,109
Net income	—	—		—		323,485		—		323,485
Other comprehensive income	—	—		—		—		182		182

Issuance of common stock under Employee Stock Purchase Plan	65,634	1		1,644		—		—		1,645

Stock-based compensation expense	29,471	—		4,479		—		—		4,479


Balances, June 30, 2022	121,959,282	$	1,220	$	1,850,601	$	605,564	$	(12,485)	$	2,444,900

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 and dividends per share)~~thousands)

Additional Paid-in Capital Accumulated Other Comprehensive Loss Total Stockholders’ Equity
Common Stock Retained Earnings (Deficit)
Shares Amount
Balances, December 31, 2020 114,742,304 $ 1,147 $ 1,827,914 $ 200,697 $ (13,598) $ 2,016,160
Net loss — — — (251,269) — (251,269)
Other comprehensive income — — — — 191 191
Cash dividends declared, $0.01 per share — — — (1,147) — (1,147)
Stock-based compensation expense — — 5,737 — — 5,737
Balances, March 31, 2021 114,742,304 $ 1,147 $ 1,833,651 $ (51,719) $ (13,407) $ 1,769,672
Net loss — — — (222,995) — (222,995)
Other comprehensive income — — — — 592 592
Cash dividends, $0.01 per share — — — (31) — (31)
Issuance of common stock under Employee Stock Purchase Plan 252,665 3 1,312 — — 1,315
Stock-based compensation expense 57,795 1 3,955 — — 3,956
Issuance of common stock through cashless exercise of Warrants 5,918,089 59 (59) — — —
Balances, June 30, 2021 120,970,853 $ 1,210 $ 1,838,859 $ (274,745) $ (12,815) $ 1,552,509
Net income — — — 85,593 — 85,593
Other comprehensive income — — — — 246 246
Cash dividends declared, $0.01 per share — — — (1,215) — (1,215)
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings 502,937 5 (4,737) — — (4,732)
Stock-based compensation expense — — 4,498 — — 4,498
Balances, September 30, 2021 121,473,790 $ 1,215 $ 1,838,620 $ (190,367) $ (12,569) $ 1,636,899


	For the Six Months Ended June 30,
	2023		2022
Cash flows from operating activities:
Net income	$	348,426	$	372,249
Adjustments to reconcile net income to net cash provided by operating activities:

Depletion, depreciation, amortization, and asset retirement obligation liability accretion	312,021		314,304


Stock-based compensation expense	8,481		8,753
Net derivative (gain) loss	(63,003)		522,757
Derivative settlement gain (loss)	20,712		(408,781)
Amortization of debt discount and deferred financing costs	2,743		7,607
Loss on extinguishment of debt	—		67,605
Deferred income taxes	94,246		92,948
Other, net	(4,305)		16,967
Net change in working capital	(4,436)		(109,748)





Net cash provided by operating activities	714,885		884,661

Cash flows from investing activities:

Capital expenditures	(550,046)		(365,745)
Acquisition of proved and unproved oil and gas properties	(88,834)		—
Other, net	657		—
Net cash used in investing activities	(638,223)		(365,745)

Cash flows from financing activities:



Cash paid to repurchase Senior Notes	—		(584,946)
Repurchase of common stock	(108,863)		—
Net proceeds from sale of common stock	1,815		1,645
Dividends paid	(36,367)		(1,218)
Other, net	(7)		(24)
Net cash used in financing activities	(143,422)		(584,543)

Net change in cash, cash equivalents, and restricted cash	(66,760)		(65,627)
Cash, cash equivalents, and restricted cash at beginning of period	444,998		332,716
Cash, cash equivalents, and restricted cash at end of period	$	378,238	$	267,089

Supplemental schedule of additional cash flow information and non-cash activities:
Operating activities:
Cash paid for interest, net of capitalized interest	$	(42,680)	$	(90,875)
Net cash paid for income taxes	$	(6,137)	$	(10,502)
Investing activities:
Increase in capital expenditure accruals and other	$	24,220	$	37,780
Non-cash financing activities (1)

_______________________________________

(1) Please refer to Note 5 - Long-Term Debt for discussion of the debt transactions executed during the six months ended June 30, 2022.

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,
2022 2021
Cash flows from operating activities:
Net income (loss) $ 853,489 $ (388,671)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and asset retirement obligation liability accretion 460,169 574,375
Impairment 6,466 26,250
Stock-based compensation expense 13,858 14,191
Net derivative loss 385,180 924,183
Derivative settlement loss (595,080) (480,262)
Amortization of debt discount and deferred financing costs 8,910 13,350
Loss on extinguishment of debt 67,605 2,139
Deferred income taxes 202,996 (282)
Other, net 7,668 (7,301)
Net change in working capital (13,230) 52,170
Net cash provided by operating activities 1,398,031 730,142
Cash flows from investing activities:
Capital expenditures (591,846) (550,265)
Other, net (596) 5,514
Net cash used in investing activities (592,442) (544,751)
Cash flows from financing activities:
Proceeds from revolving credit facility — 1,649,500
Repayment of revolving credit facility — (1,742,500)
Net proceeds from Senior Notes — 392,771
Cash paid to repurchase Senior Notes (584,946) (450,776)
Repurchase of common stock (20,241) —
Net proceeds from sale of common stock 1,645 1,315
Dividends paid (1,218) (1,178)
Other, net (35,110) (4,733)
Net cash used in financing activities (639,870) (155,601)
Net change in cash, cash equivalents, and restricted cash 165,719 29,790
Cash, cash equivalents, and restricted cash at beginning of period 332,716 10
Cash, cash equivalents, and restricted cash at end of period $ 498,435 $ 29,800
Supplemental schedule of additional cash flow information and non-cash activities:
Operating activities:
Cash paid for interest, net of capitalized interest $ (125,668) $ (126,228)
Investing activities:
Increase in capital expenditure accruals and other $ 50,590 $ 8,885
Non-cash financing activities (1)

~~(1)~~ ~~Please refer to~~ ~~Note 5 - Long-Term Debt~~ ~~for discussion of the debt transactions executed during the nine months ended September 30, 2022, and 2021.~~

~~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 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 ~~2021~~2022 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, ~~2022,~~2023, 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 ~~2021~~2022 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 ~~2021~~2022 Form 10-K.

Recently Issued Accounting Standards

~~In September 2022, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) No. 2022-04,~~ ~~Liabilities - Supplier Finance Programs (Subtopic 405-50): Disclosure of Supplier Finance Program Obligations~~ ~~(“ASU 2022-04”)~~. ASU 2022-04 was issued to enhance the transparency of supplier finance programs and implement explicit GAAP disclosure requirements for those programs. The guidance is to be applied retrospectively to each period in which a balance sheet is presented, except for the amendment on rollforward information, which is to be applied prospectively. ASU 2022-04 is effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years, except for the amendment on rollforward information, which is effective for fiscal years beginning after December 15, 2023. Early adoption is permitted. The Company is evaluating the impact of ASU 2022-04 on its disclosures.

As of ~~September~~June 30, ~~2022,~~2023, and through the filing of this report, no ~~other ASUs~~new accounting standards have been issued and not yet adopted that are applicable to the Company and that would have a material effect on the Company’s unaudited condensed consolidated financial statements and related disclosures.

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~~reflects 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 areas for the three and ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, and ~~2021:~~2022:


		Midland Basin						South Texas						Total							Midland Basin						South Texas						Total
		Three Months Ended September 30,						Three Months Ended September 30,						Three Months Ended September 30,							Three Months Ended June 30,						Three Months Ended June 30,						Three Months Ended June 30,
		2022			2021			2022			2021			2022			2021				2023			2022			2023			2022			2023			2022

		(in thousands)																			(in thousands)
Oil production revenue	Oil production revenue	$	420,838		$	501,071		$	105,095		$	57,323		$	525,933		$	558,394		Oil production revenue	$	302,874		$	534,927		$	120,519		$	132,092		$	423,393		$	667,019
Gas production revenue	Gas production revenue	123,912			96,082			110,641			52,878			234,553			148,960			Gas production revenue	36,800			137,543			32,927			103,784			69,727			241,327
NGL production revenue	NGL production revenue	315			103			66,757			52,356			67,072			52,459			NGL production revenue	211			130			53,224			81,901			53,435			82,031
Total	Total	$	545,065		$	597,256		$	282,493		$	162,557		$	827,558		$	759,813		Total	$	339,885		$	672,600		$	206,670		$	317,777		$	546,555		$	990,377
Relative percentage	Relative percentage	66		%	79		%	34		%	21		%	100		%	100		%	Relative percentage	62		%	68		%	38		%	32		%	100		%	100		%

Midland Basin South Texas Total
Nine Months Ended
September 30, Nine Months Ended
September 30, Nine Months Ended
September 30,
2022 2021 2022 2021 2022 2021
(in thousands)
Oil production revenue $ 1,449,660 $ 1,191,668 $ 350,594 $ 108,871 $ 1,800,254 $ 1,300,539
Gas production revenue 363,728 205,323 282,201 121,630 645,929 326,953
NGL production revenue 597 315 229,876 117,740 230,473 118,055
Total $ 1,813,985 $ 1,397,306 $ 862,671 $ 348,241 $ 2,676,656 $ 1,745,547
Relative percentage 68 % 80 % 32 % 20 % 100 % 100 %


	Midland Basin						South Texas						Total
	Six Months Ended June 30,						Six Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022			2023			2022

	(in thousands)
Oil production revenue	$	623,009		$	1,028,822		$	221,222		$	245,499		$	844,231		$	1,274,321
Gas production revenue	86,589			239,816			76,869			171,560			163,458			411,376
NGL production revenue	388			282			109,256			163,119			109,644			163,401
Total	$	709,986		$	1,268,920		$	407,347		$	580,178		$	1,117,333		$	1,849,098
Relative percentage	64		%	69		%	36		%	31		%	100		%	100		%

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 transfer of 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~~affected 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~~ ~~2021 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 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, therefore there are no 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, ~~2022,~~2023, and December 31, ~~2021,~~2022, were ~~$220.0~~$162.5 million and ~~$215.6~~$184.5 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. The time period between production and satisfaction of performance obligations is generally less than one day, therefore there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.

Please refer to Note 1 - Summary of Significant Accounting Policies and Note 2 - Revenue from Contracts with Customers in the 2022 Form 10-K for more information regarding the Company’s revenue recognition policy and the types of contracts under which oil, gas, and NGL production revenue is generated.

Note 3 - Equity

Stock Repurchase Program

~~On September 7,~~During 2022, the ~~Company announced that its~~Company’s Board of Directors approved a stock repurchase program authorizing the Company to repurchase up to $500.0 million in aggregate value of its common stock through December 31, 2024 (“Stock Repurchase Program”). The Stock Repurchase Program permits the Company to repurchase shares of its common stock from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws and subject to certain provisions of the Credit Agreement and the indentures governing the Senior Notes, as defined in Note 5 - Long-Term Debt. ~~The Company intends~~Please refer to ~~fund repurchases from available working capital and cash provided by operating activities. Stock repurchases may also be funded with borrowings under~~Note 3 - Equity in the ~~Credit Agreement. The timing, as well as~~2022 Form 10-K for additional information regarding the ~~number and value of shares repurchased under the~~Company’s Stock Repurchase Program, will be determined by certain authorized officers of the Company at their discretion and will depend on a variety of factors, including the market price of the Company’s common stock, general market and economic conditions and applicable legal requirements. The value of shares authorized for repurchase by the Board of Directors does not require the Company to repurchase such shares or guarantee that such shares will be repurchased, and the Stock Repurchase Program may be suspended, modified, or discontinued at any time without prior notice. No assurance can be given that any particular number or dollar value of its shares will be repurchased by the Company. The Stock Repurchase Program terminates and supersedes the August 1998 authorization to repurchase common stock, under which 3,072,184 shares remained available for repurchase prior to termination.Program.

During the three and six months ended ~~September~~June 30, ~~2022,~~2023, the Company repurchased and subsequently retired ~~452,734~~2,550,706 and 3,964,464 shares, respectively, of its common stock at a weighted-average share price of ~~$44.69~~$26.95 and $27.44, respectively, for a total cost of ~~$20.2~~$68.7 million and $108.8 million, respectively, excluding excise taxes, commissions, and fees. As of ~~September~~June 30, ~~2022, $479.8~~2023, $334.0 million remained available for repurchases of the Company’s outstanding common stock under the Stock Repurchase Program.

~~Warrants~~

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 then outstanding common stock, at an exercise price of $0.01 per share (“Warrants”). The Warrants became exercisable at the election of the holders on January 15, 2021, pursuant to the terms of the Warrant Agreement, dated June 17, 2020 (“Warrant Agreement”). The Warrants are indexed to the Company’s common stock and are required to be settled through physical settlement or net share settlement, if exercised.

Upon issuance, the $21.5 million fair value of the Warrants was recorded in additional paid-in capital on the accompanying balance sheets, and 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.

No Warrants were exercised during the nine months ended September 30, 2022. During the second quarter of 2021, the Company issued 5,918,089 shares of common stock as a result of the cashless exercise of 5,922,260 Warrants at a weighted-average share price of $15.45 per share, as determined under the terms of the Warrant Agreement. At the request of stockholders and pursuant to the Company’s obligations under the Warrant Agreement, a registration statement covering the resale of a majority of these shares was filed with the U.S. Securities and Exchange Commission (“SEC”) on June 11, 2021.

~~Dividends~~

During the third quarter of 2022, the Company’s Board of Directors approved an increase to the Company’s fixed dividend to $0.60 per share annually, to be paid in quarterly increments of $0.15 per share. During the three months ended September 30, 2022, cash dividends declared totaled $18.4 million, and will be paid on November 7, 2022, to stockholders of record at the close of business on October 25, 2022.

1210

Note 4 - Income Taxes

The provision for income taxes for the three and ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, and ~~2021,~~2022, consists of the following:


		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,
		2022			2021			2022			2021				2023			2022			2023			2022

		(in thousands)													(in thousands)
Current portion of income tax expense:
Current portion of income tax (expense) benefit:														Current portion of income tax (expense) benefit:
Federal	Federal	$	(7,014)		$	—		$	(11,287)		$	—		Federal	$	2,189		$	(3,664)		$	(2,809)		$	(4,273)
State	State	(2,317)			(29)			(4,668)			(187)			State	(3)			(2,047)			(543)			(2,351)
Deferred portion of income tax (expense) benefit		(110,048)			68			(202,996)			282
Income tax (expense) benefit		$	(119,379)		$	39		$	(218,951)		$	95
Deferred portion of income tax expense														Deferred portion of income tax expense	(44,278)			(81,000)			(94,246)			(92,948)
Income tax expense														Income tax expense	$	(42,092)		$	(86,711)		$	(97,598)		$	(99,572)

Effective tax rate	Effective tax rate	19.9		%	—		%	20.4		%	—		%	Effective tax rate	21.9		%	21.1		%	21.9		%	21.1		%

Recorded income tax expense or benefit differs from the 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 deduction limitations on the compensation of covered individuals, changes in valuation allowances, the cumulative effect of other smaller permanent 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 balances. The quarterly effective tax rate and the resulting income tax ~~(expense)~~expense or benefit can also be affected by the proportional effects of forecast net income or loss and the correlative effect on the valuation allowance for each ~~period~~of the periods presented ~~as reflected~~ in the table above. ~~Forecast net income had~~

The Company commissioned a ~~larger~~multi-year research and development (“R&D”) credit study in 2022, which is expected to be completed in late 2023, and is expected to favorably impact on the Company’s effective tax rate ~~for~~and future tax obligations when the ~~three and nine months ended September 30, 2022, compared with~~results are recorded. The Company’s policy is to not record an R&D credit until it is claimed on a filed tax return, which has not occurred as of the ~~same periods in 2021, and valuation allowance adjustments had a larger impact on~~filing of this report.

The Company made $6.1 million of cash tax payments during the ~~effective tax rate for the three and nine months ended September 30, 2021, compared with the same periods in 2022.~~second quarter of 2023, primarily related to Texas franchise taxes.

For all years before 2019, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities.

Note 5 - Long-Term Debt

Credit Agreement

On August 2, 2022, the Company entered into a Seventh Amended and Restated Credit Agreement by and among the Company, Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender (“Agent”), and the institutions named therein as lenders. The Company’s Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 ~~billion, an initial borrowing base of $2.5 billion, and initial aggregate lender commitments totaling $1.25~~ billion. As of ~~September~~June 30, ~~2022,~~2023, the borrowing base and aggregate lender commitments under the Credit Agreement ~~remained unchanged. The revolving credit facility is secured by substantially all of the Company’s proved oil~~were $2.5 billion and gas properties. The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both the Company’s (a) proved oil and gas properties reflected in the Company’s most recent reserve report; and (b) commodity derivative contracts, each as determined by the Company’s lender group.$1.25 billion, respectively. The next scheduled borrowing base redetermination date is ~~April~~October 1, 2023. The Credit Agreement is scheduled to mature on the earlier of (a) August 2, 2027 (“Stated Maturity Date”), or (b) 91 days prior to the maturity date of any of the Company’s outstanding Senior Notes, as defined below, to the extent that, on or before such date, the respective Senior Notes have not been repaid, exchanged, repurchased, refinanced, or otherwise redeemed in full, and, if refinanced or exchanged, with a scheduled maturity date that is not earlier than at least 180 days after the Stated Maturity Date.

In addition to other terms, conditions, agreements, and provisions, the Credit Agreement establishes the Secured Overnight Financing Rate (“SOFR”) as the benchmark for determining interest rates in replacement of the London Interbank Offered Rate (“LIBOR”). LIBOR was discontinued as a global reference rate for new loans and contracts after December 31, 2021. The financial covenants under the Credit Agreement require, among other customary covenants, that the Company’s (a) total funded debt, as defined by the Credit Agreement, to 12-month trailing adjusted EBITDAX ratio cannot be greater than 3.50 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 1.00 to 1.00 as of the last day of any fiscal quarter.

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, as presented in Note 5 - Long-Term Debt in the ~~table below.~~2022 Form 10-K. At the Company’s election, borrowings under the Credit Agreement may be in the form of ~~SOFR,~~Secured Overnight Financing Rate (“SOFR”), Alternate Base Rate (“ABR”), or Swingline loans. SOFR loans accrue interest at SOFR 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.

Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90%
SOFR Loans 2.000 % 2.250 % 2.500 % 2.750 % 3.000 %
ABR Loans or Swingline Loans 1.000 % 1.250 % 1.500 % 1.750 % 2.000 %
Commitment Fee Rate 0.375 % 0.375 % 0.500 % 0.500 % 0.500 %

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 27, 2022, September~~July 21, 2023, June 30, ~~2022,~~2023, and December 31, ~~2021:~~2022:


		As of October 27, 2022		As of September 30, 2022		As of December 31, 2021			As of July 21, 2023		As of June 30, 2023		As of December 31, 2022

		(in thousands)							(in thousands)
Revolving credit facility (1)	Revolving credit facility (1)	$	—	$	—	$	—	Revolving credit facility (1)	$	—	$	—	$	—
Letters of credit (2)	Letters of credit (2)	6,000		6,000		2,500		Letters of credit (2)	2,500		2,500		6,000
Available borrowing capacity	Available borrowing capacity	1,244,000		1,244,000		1,097,500		Available borrowing capacity	1,247,500		1,247,500		1,244,000
Total aggregate lender commitment amount	Total aggregate lender commitment amount	$	1,250,000	$	1,250,000	$	1,100,000	Total aggregate lender commitment amount	$	1,250,000	$	1,250,000	$	1,250,000

(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 ~~$11.4~~$9.6 million and ~~$2.7~~$10.8 million as of ~~September~~June 30, ~~2022,~~2023, and December 31, ~~2021,~~2022, 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 ~~Secured~~ Notes

On June 17, 2022, the Company redeemed all of the $446.7 million of aggregate principal amount outstanding of its 10.0% Senior Secured Notes due 2025 (“2025 Senior Secured Notes” or “Senior Secured Notes”). The 2025 Senior Secured Notes were redeemed with cash on hand, at a redemption price equal to 107.5 percent of the principal amount outstanding on the date of the redemption, plus accrued and unpaid interest. Upon redemption, the Company recorded a net loss on extinguishment of debt of $67.2 million which included $33.5 million of premium paid, $26.3 million of accelerated unamortized debt discount, and $7.4 million of accelerated unamortized deferred financing costs. The Company canceled all redeemed 2025 Senior Secured Notes upon settlement.

The 1.50% Senior Secured Convertible Notes due 2021 (“2021 Senior Secured Convertible Notes”) matured on July 1, 2021, and on that day, the Company used borrowings under its revolving credit facility to retire at par the outstanding principal amount of $65.5 million. Interest expense recognized on the 2021 Senior Secured Convertible Notes related to the stated interest rate and amortization of the debt discount. No interest expense was recognized for the three months ended September 30, 2021, and $2.3 million of interest expense was recognized for the nine months ended September 30, 2021.

~~Senior Secured Notes, net of unamortized discount and deferred financing costs, included within the~~Company’s Senior Notes, net line item on the accompanying balance sheets as of ~~December 31, 2021, consist of the following:~~


	~~As of December 31, 2021~~
	~~(in thousands)~~

~~Principal amount of 10.0% Senior Secured Notes due 2025~~	$	~~446,675~~
~~Unamortized debt discount~~	~~30,236~~
~~Unamortized deferred financing costs~~	~~8,727~~
~~10.0% Senior Secured Notes due 2025, net of unamortized debt discount and deferred financing costs~~	$	~~407,712~~

~~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, ~~2022,~~2023, and December 31, ~~2021, consist~~2022, consists of the following (collectively referred to as “Senior ~~Unsecured Notes,” and together with the 2025 Senior Secured Notes, “Senior~~ Notes”):


		As of September 30, 2022						As of December 31, 2021							As of June 30, 2023						As of December 31, 2022
		Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net		Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net			Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net		Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net

		(in thousands)													(in thousands)
5.0% Senior Notes due 2024		$	—	$	—	$	—	$	104,769	$	403	$	104,366
5.625% Senior Notes due 2025	5.625% Senior Notes due 2025	349,118		1,686		347,432		349,118		2,160		346,958		5.625% Senior Notes due 2025	$	349,118	$	1,211	$	347,907	$	349,118	$	1,528	$	347,590
6.75% Senior Notes due 2026	6.75% Senior Notes due 2026	419,235		2,744		416,491		419,235		3,270		415,965		6.75% Senior Notes due 2026	419,235		2,219		417,016		419,235		2,569		416,666
6.625% Senior Notes due 2027	6.625% Senior Notes due 2027	416,791		3,366		413,425		416,791		3,949		412,842		6.625% Senior Notes due 2027	416,791		2,784		414,007		416,791		3,172		413,619
6.5% Senior Notes due 2028	6.5% Senior Notes due 2028	400,000		5,919		394,081		400,000		6,679		393,321		6.5% Senior Notes due 2028	400,000		5,158		394,842		400,000		5,665		394,335
Total	Total	$	1,585,144	$	13,715	$	1,571,429	$	1,689,913	$	16,461	$	1,673,452	Total	$	1,585,144	$	11,372	$	1,573,772	$	1,585,144	$	12,934	$	1,572,210

The Senior ~~Unsecured~~ 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.

On February 14, 2022, the Company redeemed ~~all of~~ the remaining $104.8 million of aggregate principal amount outstanding of its 5.0% Senior Notes due 2024 (“2024 Senior Notes”), with cash on hand, pursuant to the terms of the indenture governing the 2024 Senior Notes which provided for a redemption price equal to 100 percent of the principal amount of the 2024 Senior Notes on the date of redemption, plus accrued and unpaid interest. The Company canceled all redeemed 2024 Senior Notes upon settlement.

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 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 6.125% Senior Notes due 2022 (“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 $0.6 million of net premiums. The Company canceled all repurchased and redeemed 2022 Senior Notes and 2024 Senior Notes upon settlement.

Please refer to Note 5 - Long-Term Debt in the ~~2021~~2022 Form 10-K for additional detail on the Company’s Senior Notes.

Senior Secured Notes

On June 17, 2022, the Company redeemed all of the $446.7 million of aggregate principal amount outstanding of its 10.0% Senior Secured Notes due 2025 (“2025 Senior Secured Notes”), with cash on hand, at a redemption price equal to 107.5 percent of the principal amount outstanding on the date of the redemption, plus accrued and unpaid interest. Upon redemption, the Company recorded a net loss on extinguishment of debt of $67.2 million which included $33.5 million of premium paid, $26.3 million of accelerated expense recognition of the remaining unamortized debt discount, and $7.4 million of accelerated expense recognition of the remaining unamortized deferred financing costs. The Company canceled all redeemed 2025 Senior Secured Notes upon settlement.

Covenants

~~As discussed above, the~~The Company is subject to certain financial and non-financial covenants under the Credit Agreement and ~~under~~ the indentures governing the Senior Notes that, among other terms, limit the Company’s ability to incur additional indebtedness, make restricted

payments including dividends, ~~and common stock repurchases,~~ sell assets, create liens that secure debt, enter into transactions with affiliates, and merge or consolidate with other entities, 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.entities. The Company was in compliance with all financial and non-financial covenants as of ~~September~~June 30, ~~2022,~~2023, and through the filing of this report. Please refer to Note 5 - Long-Term Debt in the ~~2021~~2022 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, 2023, and 2022, ~~and 2021,~~ totaled ~~$5.1~~$5.9 million and ~~$3.5~~$4.2 million, respectively, and totaled ~~$12.3~~$11.4 million and ~~$12.5~~$7.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, and ~~2021,~~2022, 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 ~~2021~~2022 Form 10-K. Please refer to Note 6 - Commitments and Contingencies in the ~~2021~~2022 Form 10-K for additional discussion of the Company’s commitments.

Drilling Rig Service Contracts. During the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, and through the filing of this report, the Company amended certain of its drilling rig contracts ~~resulting~~to extend contract terms, which resulted in ~~the increase of~~changes to day rates and potential early termination ~~fees, and the extension of contract terms.~~fees. As of the filing of this report, the Company’s drilling rig commitments totaled ~~$32.8~~$27.0 million under contract terms extending through the third quarter of ~~2023.~~2024. If all of these contracts were terminated as of the filing of this report, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay ~~$19.6~~$18.7 million in early termination fees. No early termination penalties or standby fees were incurred by the Company during the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, and the Company does not expect to incur material penalties with regard to its drilling rig contracts during the remainder of ~~2022.~~

~~Drilling and Completion Commitments~~. During the nine months ended September 30, 2022, the Company entered into an agreement that includes minimum drilling and completion footage requirements on certain existing leases. If these minimum requirements are not satisfied by March 31, 2024, 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 30, 2022, the liquidated damages could range from zero to a maximum of $74.5 million, with the maximum exposure assuming no additional development activity occurred prior to March 31, 2024. As of the filing of this report, the Company expects to meet its obligations under this agreement.2023.

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~~Derivative Financial Instruments

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

The Company regularly enters into commodity derivative contracts to mitigate a portion of its exposure to oil, gas, and NGL price volatility and location differentials, and the associated effect on cash flows. All commodity derivative contracts that the Company enters into are for other-than-trading purposes. The Company’s commodity derivative contracts consist of price swap and collar arrangements for oil and gas production, and price swap arrangements for NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap price, the Company receives the difference between the index price and the agreed upon swap price. If the index price is higher than the swap 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 and gas 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 is sold. As of June 30, 2023, the Company had basis swap contracts with fixed price differentials between:

•NYMEX WTI and Argus WTI Midland (“WTI Midland”) for a portion of its Midland Basin oil production with sales contracts that settle at WTI Midland prices;

•NYMEX WTI and Argus WTI Houston Magellan East Houston Terminal (“WTI Houston MEH”) for a portion of its South Texas oil production with sales contracts that settle at WTI Houston MEH prices;

•NYMEX Henry Hub (“NYMEX HH”) and Inside FERC Houston Ship Channel (“IF HSC”) for a portion of its South Texas gas production with sales contracts that settle at IF HSC prices; and

•NYMEX HH and Inside FERC West Texas (“IF Waha”) for a portion of its Midland Basin gas production with sales contracts that settle at IF Waha prices.

The Company has also entered into 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, ~~2022, 3.8 million shares~~2023, the Company had commodity derivative contracts outstanding through the fourth quarter of ~~common stock were available~~2025 as summarized in the table below:


	Contract Period
	Third Quarter 2023		Fourth Quarter 2023		2024		2025
Oil Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
NYMEX WTI Volumes	607		837		—		—
Weighted-Average Contract Price	$	59.77	$	65.91	$	—	$	—
ICE Brent Volumes	920		920		910		—
Weighted-Average Contract Price	$	86.50	$	86.50	$	85.50	$	—
Collars
NYMEX WTI Volumes	291		—		919		—
Weighted-Average Floor Price	$	75.00	$	—	$	75.00	$	—
Weighted-Average Ceiling Price	$	93.05	$	—	$	81.47	$	—
Basis Swaps
WTI Midland-NYMEX WTI Volumes	1,414		1,294		2,961		—
Weighted-Average Contract Price	$	0.88	$	0.88	$	1.17	$	—


WTI Houston MEH-NYMEX WTI Volumes	361		296		877		—
Weighted-Average Contract Price	$	1.59	$	1.53	$	1.85	$	—
Roll Differential Swaps
NYMEX WTI Volumes	1,304		1,201		2,188		—
Weighted-Average Contract Price	$	0.64	$	0.62	$	0.42	$	—

Gas Derivatives (volumes in BBtu and prices in $ per MMBtu):
Swaps
NYMEX HH Volumes	1,470		—		2,759		5,891
Weighted-Average Contract Price	$	5.11	$	—	$	3.27	$	4.20






Collars
NYMEX HH Volumes	6,194		8,362		22,342		5,891
Weighted-Average Floor Price	$	3.75	$	3.90	$	3.61	$	3.50
Weighted-Average Ceiling Price	$	4.62	$	5.70	$	5.76	$	5.32
IF HSC Volumes	1,389		1,451		—		—
Weighted-Average Floor Price	$	4.25	$	4.25	$	—	$	—
Weighted-Average Ceiling Price	$	4.95	$	5.55	$	—	$	—






Basis Swaps




IF Waha-NYMEX HH Volumes	3,505		2,337		20,958		20,501
Weighted-Average Contract Price	$	(0.95)	$	(1.01)	$	(0.86)	$	(0.66)
IF HSC-NYMEX HH Volumes	1,813		2,008		10,208		—
Weighted-Average Contract Price	$	(0.25)	$	(0.25)	$	(0.33)	$	—

NGL Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
OPIS Propane Mont Belvieu Non-TET Volumes	181		187		—		—
Weighted-Average Contract Price	$	36.67	$	36.66	$	—	$	—

Commodity Derivative Contracts Entered Into Subsequent to June 30, 2023

Subsequent to June 30, 2023, and through July 21, 2023, the Company entered into the following commodity derivative contracts:

•NYMEX WTI oil collar contracts for ~~grant under~~ the first and second quarters of 2024 for a total of 0.6 MMBbl of oil production at a weighted-average floor price of $62.38 per Bbl and a weighted-average ceiling price of $76.51 per Bbl;

•WTI Midland-NYMEX WTI basis swap contracts for 2024 for a total of 0.9 MMBbl of oil production at a contract price of $1.35 per Bbl;

•WTI Houston MEH-NYMEX WTI basis swap contract for 2024 for a total of 0.3 MMBbl of oil production at a contract price of $1.75 per Bbl; and

•IF HSC-NYMEX HH basis swap contracts for 2024 for a total of 4,780 BBtu of gas production at a weighted-average contract price of $(0.15) per MMBtu.

Derivative Assets and Liabilities Fair Value

The Company’s ~~Equity Incentive Compensation Plan (“Equity Plan”).~~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 ~~may also grant other types of long-term incentive-based awards, such~~does not designate its commodity derivative contracts as ~~cash awards and performance-based cash awards, to eligible employees.~~

~~Performance Share Units~~

The Company has granted performance share units (“PSU” or “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 zero to two times the number of PSUs awarded and is determined based on certain criteria over a ~~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 2019, which the Company determined to be equity awards, the settlement criteria included a combination of the Company’s 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 stipulated that if the Company’s absolute TSR was negative over the~~ ~~three~~-year performance period, the maximum number of shares of common stock that could be issued to settle outstanding PSUs was 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.hedging instruments. The fair value of the ~~PSUs granted in 2019~~commodity derivative contracts was ~~measured on~~a net asset of $58.1 million and $15.8 million as of June 30, 2023, and December 31, 2022, respectively.

The following table details the ~~grant date using the GBM Model, with the assumption that the associated CRTCI performance condition would be met at the target amount at the end~~fair value of the performance period. Compensation expense for PSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. PSUs granted in 2019 vested during the nine months ended September 30, 2022, and earned a 2.0 times multiplier upon settlement. The Company and all eligible recipients mutually agreed to net share settle a portion of the vested awards to cover income and payroll tax withholdings, as provided forcommodity derivative contracts recorded in the ~~Equity Plan~~accompanying balance sheets, by category:


	As of June 30, 2023		As of December 31, 2022

	(in thousands)
Derivative assets:
Current assets	$	74,138	$	48,677
Noncurrent assets	12,077		24,465
Total derivative assets	$	86,215	$	73,142
Derivative liabilities:
Current liabilities	$	22,210	$	56,181
Noncurrent liabilities	5,894		1,142
Total derivative liabilities	$	28,104	$	57,323

Offsetting of Derivative Assets and Liabilities

As of June 30, 2023, and December 31, 2022, all derivative instruments held by the ~~award agreement. After withholding 349,487 shares~~Company were subject to ~~satisfy income and payroll tax withholding obligations, 654,923 shares of the Company’s common stock were issued in accordance~~master netting arrangements with various financial institutions. In general, the terms of the ~~award agreement.~~

~~For PSUs granted in 2022, which the Company determined to be equity awards, settlement will be determined based on a combination~~Company’s agreements provide for offsetting of ~~the following criteria measured over the~~ ~~three-year performance period: the Company’s TSR relative to the TSR of certain peer companies, the Company’s absolute TSR, free cash flow (“FCF”) generation,~~amounts payable or receivable between it and the ~~achievement~~counterparty, at the election of ~~certain ESG targets,~~both parties, for transactions that settle on the same date and in ~~each case as defined by~~ the ~~award agreement.~~same currency. The ~~absolute~~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 ~~relative TSR portions~~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 ~~PSUs granted in 2022~~Company’s commodity derivative contracts:


	Derivative Assets as of				Derivative Liabilities as of
	June 30, 2023		December 31, 2022		June 30, 2023		December 31, 2022

	(in thousands)
Gross amounts presented in the accompanying balance sheets	$	86,215	$	73,142	$	(28,104)	$	(57,323)
Amounts not offset in the accompanying balance sheets	(24,835)		(26,136)		24,835		26,136
Net amounts	$	61,380	$	47,006	$	(3,269)	$	(31,187)

~~were measured on~~The following table summarizes the ~~grant date using the GBM Model. The portion~~commodity components of the ~~awards associated with FCF generation~~derivative settlement (gain) loss, and ~~ESG performance conditions assumes that target amounts will be met at~~ the ~~end~~net derivative (gain) loss line items presented within the accompanying unaudited condensed consolidated statements of cash flows (“accompanying statements of cash flows”) and the ~~performance period. Compensation expense for PSUs is recognized within general and administrative expense and exploration expense over the vesting periods~~accompanying statements of the respective awards. The Company initially records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the date of grant. 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 FCF generation and achievement of certain ESG targets. During the nine months ended September 30, 2022, the Company granted a total of 276,010 PSUs with a grant date fair value of $7.4 million.operations, respectively:

Total compensation expense recorded for PSUs was $0.6 million and $0.8 million for the three months ended September 30, 2022, and 2021, respectively, and $2.0 million and $5.3 million for the nine months ended September 30, 2022, and 2021, respectively.


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022

	(in thousands)
Derivative settlement (gain) loss:
Oil contracts	$	472	$	179,213	$	6,698	$	308,381
Gas contracts	(14,550)		53,337		(25,852)		80,388
NGL contracts	(1,558)		8,048		(1,558)		20,012
Total derivative settlement (gain) loss	$	(15,636)	$	240,598	$	(20,712)	$	408,781

Net derivative (gain) loss:
Oil contracts	$	(17,518)	$	100,273	$	(46,685)	$	415,323
Gas contracts	10,560		8,548		(10,218)		94,723
NGL contracts	(4,716)		(4,585)		(6,100)		12,711
Total net derivative (gain) loss	$	(11,674)	$	104,236	$	(63,003)	$	522,757

Credit Related Contingent Features

As of ~~September~~June 30, ~~2022, there was $6.8 million of total unrecognized compensation expense related to non-vested PSUs, which is being amortized through mid-2025.~~

~~A summary of activity during the nine months ended September 30, 2022, is presented in the following table:~~

PSUs (1)
Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year 464,483 $ 12.80
Granted 276,010 $ 26.67
Vested (460,928) $ 12.80
Forfeited (3,555) $ 12.80
Non-vested at end of quarter 276,010 $ 26.67

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

~~Employee Restricted Stock Units~~

~~The Company has granted restricted stock units (“RSU” or “RSUs”) to eligible employees as part of its Equity Plan. Each RSU granted represents a right to receive one share~~2023, all of the Company’s ~~common stock upon settlement~~derivative counterparties were members of the ~~award at the end~~Credit Agreement lender group. The Company does not enter into derivative contracts with counterparties that are not part of the ~~specified vesting period. RSUs generally vest in one-third increments~~lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on ~~each anniversary date of the grant over 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~~assets having a 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 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. During the nine months ended September 30, 2022, the Company granted to employees a total of 526,776 RSUs with a grant date fair value of $18.0 million, and the Company settled RSUs upon the vesting of awards granted in previous years. The Company and all eligible recipients mutually agreed to net share settle a portion of the vested awards to cover income and payroll tax withholdings, as provided for in the Equity Plan and applicable award agreements. After withholding 284,423 shares to satisfy income and payroll tax withholding obligations, 636,504 shares of the Company’s common stock were issued in accordance with the terms of the applicable award agreements during the nine months ended September 30, 2022.

Total compensation expense recorded for RSUs was $3.5 million and $2.9 million for the three months ended September 30, 2022, and 2021, respectively, and $10.0 million and $7.2 million for the nine months ended September 30, 2022, and 2021, respectively. As of September 30, 2022, there was $27.8 million of total unrecognized compensation expense related to non-vested RSUs, which is being amortized through mid-2025.

~~A summary of activity during the nine months ended September 30, 2022, is presented in the following table:~~

RSUs Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year 1,841,237 $ 13.79
Granted 526,776 $ 34.08
Vested (920,927) $ 12.17
Forfeited (49,704) $ 16.62
Non-vested at end of quarter 1,397,382 $ 22.41

~~Director Shares~~

During the nine months ended September 30, 2022, and 2021, the Company issued a total of 29,471 and 57,795 shares, respectively, of its common stock as compensation to its non-employee directors under the Equity Plan. Shares issued during 2022 will fully vest on December 31, 2022, and shares issued during 2021 fully vested on December 31, 2021.

~~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, subject to a maximum of 2,500 shares per offering period and a maximum of $25,000 in value related to purchases for each calendar year. The purchase price of the common stock isat least 85 percent of the ~~lower~~total PV-9, as defined in the Credit Agreement, of the ~~trading price of~~Company’s proved oil and gas properties evaluated in the common stock on either the first or last day of the six-month offering period. The ESPP is intended to qualify as an “employee stock purchase plan” under Section 423 of the Internal Revenue Code. There were a total of 65,634 and 252,665 shares issuedmost recent reserve report. Collateral securing indebtedness under the ESPP during the nine months ended September 30, 2022, and 2021, respectively. Total proceeds to the Company for the issuance of these shares was $1.6 million and $1.3 million for the nine months ended September 30, 2022, and 2021, 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 7 - Compensation Plans~~ ~~in the~~ ~~2021 Form 10-K~~ ~~for additional detail on~~Credit Agreement also secures the Company’s ~~Equity Plan.~~derivative agreement obligations.

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 September 30, 2022:~~hierarchy:

~~Level 1~~

~~Level 2~~

~~Level 3~~

~~(in thousands)~~

~~Assets:~~

~~Derivatives~~ ~~(1)~~

—

~~78,255~~

—

~~Liabilities:~~

~~Derivatives~~ ~~(1)~~

—

~~189,223~~

—


	As of June 30, 2023						As of December 31, 2022
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3

	(in thousands)
Assets:
Derivatives (1)	$	—	$	86,215	$	—	$	—	$	73,142	$	—

Liabilities:
Derivatives (1)	$	—	$	28,104	$	—	$	—	$	57,323	$	—

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

1817

~~Level 1~~

~~Level 2~~

~~Level 3~~

~~(in thousands)~~

~~Assets:~~

~~Derivatives~~ ~~(1)~~

—

~~24,334~~

—

~~Liabilities:~~

~~Derivatives~~ ~~(1)~~

—

~~345,202~~

—

~~(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 107 - Derivative Financial Instruments in this report, and to Note 8 - Fair Value Measurements and Note 10 - Derivative Financial Instruments in the ~~2021~~2022 Form 10-K for more information regarding the Company’s derivative instruments.

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 ~~September~~June 30, ~~2022,~~2023, or December 31, ~~2021,~~2022, as they were recorded at carrying value, net of any unamortized ~~discounts and~~ deferred financing costs. Please refer to Note 5 - Long-Term Debt above for additional information.


		As of September 30, 2022				As of December 31, 2021					As of June 30, 2023				As of December 31, 2022
		Principal Amount		Fair Value		Principal Amount		Fair Value			Principal Amount		Fair Value		Principal Amount		Fair Value

		(in thousands)									(in thousands)
10.0% Senior Secured Notes due 2025		$	—	$	—	$	446,675	$	491,628
5.0% Senior Notes due 2024		$	—	$	—	$	104,769	$	104,583
5.625% Senior Notes due 2025	5.625% Senior Notes due 2025	$	349,118	$	337,073	$	349,118	$	353,091	5.625% Senior Notes due 2025	$	349,118	$	341,560	$	349,118	$	337,821
6.75% Senior Notes due 2026	6.75% Senior Notes due 2026	$	419,235	$	401,627	$	419,235	$	431,787	6.75% Senior Notes due 2026	$	419,235	$	411,332	$	419,235	$	409,484
6.625% Senior Notes due 2027	6.625% Senior Notes due 2027	$	416,791	$	403,154	$	416,791	$	432,783	6.625% Senior Notes due 2027	$	416,791	$	408,259	$	416,791	$	402,120
6.5% Senior Notes due 2028	6.5% Senior Notes due 2028	$	400,000	$	381,456	$	400,000	$	417,284	6.5% Senior Notes due 2028	$	400,000	$	384,584	$	400,000	$	384,520

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. Potentially dilutive securities for this calculation consist primarily of non-vested ~~RSUs,~~restricted stock units (“RSU” or “RSUs”) and contingent ~~PSUs, and Warrants, all of~~performance share units (“PSU” or “PSUs”), 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 nine months ended September 30, 2021, for which they were outstanding. A majority of the Warrants were exercised during the second quarter of 2021, and the remaining outstanding Warrants were dilutive during the three months ended September 30, 2022, and 2021, and the nine months ended September 30, 2022, as presented below. Please refer to Note ~~3 - Equity~~ ~~and~~ ~~Note 7~~10 - Compensation Plans in this reportand Note 9 - Earnings Per Share in the ~~2021~~2022 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,
2022 2021 2022 2021
(in thousands)
Anti-dilutive — — — 5,200

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

For the Three Months Ended
September 30, For the Nine Months Ended
September 30,
2022 2021 2022 2021
(in thousands, except per share data)
Net income (loss) $ 481,240 $ 85,593 $ 853,489 $ (388,671)
Basic weighted-average common shares outstanding 123,195 121,457 122,318 118,224
Dilutive effect of non-vested RSUs and contingent PSUs 1,065 2,375 1,896 —
Dilutive effect of Warrants 19 19 19 —
Diluted weighted-average common shares outstanding 124,279 123,851 124,233 118,224
Basic net income (loss) per common share $ 3.91 $ 0.70 $ 6.98 $ (3.29)
Diluted net income (loss) per common share $ 3.87 $ 0.69 $ 6.87 $ (3.29)

~~Note 10 - Derivative Financial Instruments~~

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

The Company regularly enters into commodity derivative contracts to mitigate a portion of its exposure to oil, gas, and NGL price volatility and location differentials, and the associated impact on cash flows. As of September 30, 2022, all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of price swap and collar arrangements for oil, 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 price, the Company receives the difference between the index price and the agreed upon swap price. If the index price is higher than the swap 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 and gas 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 is sold. As of September 30, 2022, the Company has basis swap contracts with fixed price differentials between:

•~~NYMEX WTI and WTI Midland for a portion of its Midland Basin oil production with sales contracts that settle at WTI Midland prices;~~

•~~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;~~

•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 (“WTI Houston MEH”) prices;

•~~NYMEX HH and Inside FERC West Texas (“IF Waha”) for a portion of its Midland Basin gas production with sales contracts that settle at IF Waha prices; and~~

•~~NYMEX HH and Inside FERC Houston Ship Channel (“IF HSC”) for a portion of its South Texas gas production with sales contracts that settle at IF HSC prices.~~


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022

	(in thousands, except per share data)
Net income	$	149,874	$	323,485	$	348,426	$	372,249

Basic weighted-average common shares outstanding	119,408		121,910		120,533		121,909
Dilutive effect of non-vested RSUs, contingent PSUs, and other	666		2,433		642		2,358
Diluted weighted-average common shares outstanding	120,074		124,343		121,175		124,267

Basic net income per common share	$	1.26	$	2.65	$	2.89	$	3.05
Diluted net income per common share	$	1.25	$	2.60	$	2.88	$	3.00

~~As of September 30, 2022, the Company had commodity derivative contracts outstanding through the fourth quarter of 2025 as summarized in the table below:~~

Contract Period
Fourth Quarter 2022 2023 2024 2025
Oil Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
NYMEX WTI Volumes 1,923 1,190 — —
Weighted-Average Contract Price $ 44.58 $ 45.20 $ — $ —
ICE Brent Volumes — 3,650 910 —
Weighted-Average Contract Price $ — $ 86.50 $ 85.50 $ —
Collars
NYMEX WTI Volumes 1,128 1,331 919 —
Weighted-Average Floor Price $ 63.74 $ 66.01 $ 75.00 $ —
Weighted-Average Ceiling Price $ 75.48 $ 80.79 $ 81.47 $ —
Basis Swaps
WTI Midland-NYMEX WTI Volumes 2,462 3,613 — —
Weighted-Average Contract Price $ 1.15 $ 0.73 $ — $ —
ICE Brent-NYMEX WTI Volumes 920 — — —
Weighted-Average Contract Price $ (7.78) $ — $ — $ —
WTI Houston MEH-NYMEX WTI Volumes 374 1,234 — —
Weighted-Average Contract Price $ 1.25 $ 1.52 $ — $ —
Roll Differential Swaps
NYMEX WTI Volumes 3,248 4,968 — —
Weighted-Average Contract Price $ 0.21 $ 0.62 $ — $ —
Gas Derivatives (volumes in BBtu and prices in $ per MMBtu):
Swaps
NYMEX HH Volumes 2,806 — — —
Weighted-Average Contract Price $ 5.50 $ — $ — $ —
IF HSC Volumes 6,982 — — —
Weighted-Average Contract Price $ 2.47 $ — $ — $ —
IF Waha Volumes 3,067 900 — —
Weighted-Average Contract Price $ 2.22 $ 3.98 $ — $ —
Collars
NYMEX HH Volumes 1,908 24,170 — —
Weighted-Average Floor Price $ 3.50 $ 3.74 $ — $ —
Weighted-Average Ceiling Price $ 4.44 $ 6.32 $ — $ —
IF HSC Volumes — 5,085 — —
Weighted-Average Floor Price $ — $ 4.10 $ — $ —
Weighted-Average Ceiling Price $ — $ 5.63 $ — $ —

Contract Period (continued)
Fourth Quarter 2022 2023 2024 2025
Basis Swaps
IF Waha-NYMEX HH Volumes — 7,247 20,958 20,501
Weighted-Average Contract Price $ — $ (1.02) $ (0.86) $ (0.66)
IF HSC-NYMEX HH Volumes — 9,582 — —
Weighted-Average Contract Price $ — $ 0.07 $ — $ —
NGL Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
OPIS Propane Mont Belvieu Non-TET Volumes 113 — — —
Weighted-Average Contract Price $ 35.91 $ — $ — $ —
Collars
OPIS Propane Mont Belvieu Non-TET Volumes 173 — — —
Weighted-Average Floor Price $ 24.11 $ — $ — $ —
Weighted-Average Ceiling Price $ 28.13 $ — $ — $ —

~~Commodity Derivative Contracts Entered Into Subsequent to September 30, 2022~~

~~Subsequent to September 30, 2022, the Company entered into the following commodity derivative contracts:~~

•~~WTI Midland-NYMEX WTI basis swap contracts for 2023 for a total of 1.7 MMBbl of oil production at a weighted-average contract price of $1.36 per Bbl;~~

•~~WTI Houston MEH-NYMEX WTI basis swap contracts for the first and second quarters of 2023 for a total of 0.2 MMBbl of oil production at a weighted-average contract price of $2.11 per Bbl;~~

•~~NYMEX HH swap contracts for the second and third quarters of 2023 for a total of 2,890 BBtu of gas production at a weighted-average contract price of $5.08 per MMBtu;~~

•NYMEX HH collar contracts for the fourth quarter of 2023 and the first quarter of 2024 for a total of 3,423 BBtu of gas production at a weighted-average floor price of $4.27 per MMBtu and a weighted-average ceiling price of $8.52 per MMBtu; and

•~~IF HSC-NYMEX HH basis swap contract for the second through fourth quarters of 2023 for a total of 2,750 BBtu of gas production at a contract price of $(0.30) per MMBtu.~~

~~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 liability of $111.0 million and $320.9 million as of September 30, 2022, and December 31, 2021, respectively.

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

As of September 30, 2022 As of December 31, 2021
(in thousands)
Derivative assets:
Current assets $ 42,207 $ 24,095
Noncurrent assets 36,048 239
Total derivative assets $ 78,255 $ 24,334
Derivative liabilities:
Current liabilities $ 174,717 $ 319,506
Noncurrent liabilities 14,506 25,696
Total derivative liabilities $ 189,223 $ 345,202

~~Offsetting of Derivative Assets and Liabilities~~

As of September 30, 2022, and December 31, 2021, 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.

Derivative Assets as of Derivative Liabilities as of
September 30,
2022 December 31, 2021 September 30,
2022 December 31, 2021
(in thousands)
Gross amounts presented in the accompanying balance sheets $ 78,255 $ 24,334 $ (189,223) $ (345,202)
Amounts not offset in the accompanying balance sheets (56,524) (22,862) 56,524 22,862
Net amounts $ 21,731 $ 1,472 $ (132,699) $ (322,340)

The following table summarizes the commodity components of the derivative settlement loss, and the net derivative (gain) loss line items presented within the accompanying unaudited condensed consolidated statements of cash flows (“accompanying statements of cash flows”) and the accompanying statements of operations, respectively:

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2022 2021 2022 2021
(in thousands)
Derivative settlement loss:
Oil contracts $ 120,430 $ 154,113 $ 428,811 $ 344,740
Gas contracts 61,981 35,757 142,369 88,437
NGL contracts 3,888 23,685 23,900 47,085
Total derivative settlement loss $ 186,299 $ 213,555 $ 595,080 $ 480,262
Net derivative (gain) loss:
Oil contracts $ (180,300) $ 68,194 $ 235,023 $ 611,224
Gas contracts 47,973 109,802 142,695 220,088
NGL contracts (5,250) 31,150 7,462 92,871
Total net derivative (gain) loss $ (137,577) $ 209,146 $ 385,180 $ 924,183

~~Credit Related Contingent Features~~

As of September 30, 2022, all of the Company’s derivative counterparties were members of the Credit Agreement lender group, with the exception of one counterparty with whom the Company has derivative contracts outstanding through December 31, 2022, that was a part of the lender group under the prior credit agreement. The contracts with this counterparty were entered into while the counterparty was a member of the prior credit agreement lender group. The Company does not enter into derivative contracts with counterparties that are not part of the 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.

2418

Note 10 - Compensation Plans

The Company may grant various types of both short-term and long-term incentive-based awards under its compensation plans, such as cash awards, performance-based cash awards, and equity awards to eligible employees. Additionally, the Company grants stock-based compensation to its Board of Directors and provides an employee stock purchase plan. As of June 30, 2023, approximately 3.7 million shares of common stock were available for grant under the Company’s Equity Incentive Compensation Plan (“Equity Plan”).

Performance Share Units

The Company has granted 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 zero to two times the number of PSUs awarded and is determined based on certain criteria over a 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 2022 and 2023, which the Company determined to be equity awards, settlement will be determined based on a combination of the following criteria measured over the three-year performance period: the Company’s Total Shareholder Return (“TSR”) relative to the TSR of certain peer companies, the Company’s absolute TSR, free cash flow (“FCF”) generation, and the achievement of certain ESG targets, in each case as defined by the award agreement. The Company initially records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the grant date. As a portion of these awards depends on performance-based settlement criteria, compensation expense may be adjusted in future periods as the expected number of shares of the Company’s common stock issued to settle the units increases or decreases based on the Company’s expected FCF generation and achievement of certain ESG targets.

Compensation expense for PSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for PSUs was $0.2 million and $0.7 million for the three months ended June 30, 2023, and 2022, respectively, and $0.8 million and $1.4 million for the six months ended June 30, 2023, and 2022, respectively. As of June 30, 2023, there was $4.1 million of total unrecognized compensation expense related to non-vested PSUs, which is being amortized through mid-2025. There were no material changes to the outstanding and non-vested PSUs during the six months ended June 30, 2023.

Subsequent to June 30, 2023, the Company granted a total of 256,633 PSUs with a grant date fair value of $7.7 million.

Restricted Stock Units

The Company has granted RSUs to eligible employees as part of its Equity Plan. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. RSUs generally vest in one-third increments on each anniversary date of the grant over 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 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 RSUs was $3.4 million and $3.2 million for the three months ended June 30, 2023, and 2022, respectively, and $6.7 million and $6.5 million for the six months ended June 30, 2023, and 2022, respectively. As of June 30, 2023, there was $17.4 million of total unrecognized compensation expense related to non-vested RSUs, which is being amortized through January 2026. There were no material changes to the outstanding and non-vested RSUs during the six months ended June 30, 2023.

Subsequent to June 30, 2023, the Company settled RSUs upon the vesting of awards granted in previous years. The Company and a majority of eligible recipients 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 248,963 shares to satisfy income and payroll tax withholding obligations, the Company issued 553,442 shares of common stock in accordance with the terms of the applicable award agreements. Additionally, the Company granted to employees a total of 591,361 RSUs with a grant date fair value of $18.7 million.

Director Shares

During the second quarters of 2023, and 2022, the Company issued a total of 56,872 and 29,471 shares, respectively, of its common stock as compensation to its non-employee directors under the Equity Plan. Shares issued during 2023 will fully vest on December 31, 2023, and shares issued during 2022 fully vested on December 31, 2022.

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, subject to a maximum of 2,500 shares per offering period and a maximum of $25,000 in value related to purchases for each calendar year. The purchase price of the common stock is 85 percent of the lower of the trading price of the common stock on either the first or last day of the six-month offering period. The ESPP is intended to qualify as an “employee stock purchase plan” under Section 423 of the Internal Revenue Code. There were a total of 68,210 and 65,634 shares issued under the ESPP during the second quarters of 2023, and 2022, respectively. Total proceeds to the Company for the issuance of these shares was $1.8 million and $1.6 million for the six months ended June 30, 2023, and 2022, 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 7 - Compensation Plans in the 2022 Form 10-K for additional detail on the Company’s compensation plans.

Note 11 - Acquisitions

Acquisitions

On June 30, 2023, the Company acquired approximately 20,000 net acres of oil and gas properties located in Dawson and northern Martin Counties, Texas. Total consideration paid after purchase price adjustments was $88.8 million. Under authoritative accounting guidance, this transaction was considered to be an asset acquisition. Therefore, the properties were recorded based on the total consideration paid after purchase price adjustments and the transaction costs were capitalized as a component of the cost of the assets acquired.

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 the financial information presented in our Quarterly Report onForm 10-Q for the quarter ended ~~June 30, 2022~~March 31, 2023, filed with the ~~SEC~~Securities and Exchange Commission (“SEC”) on ~~August 4, 2022.~~April 28, 2023. Throughout the following discussion, we explain changes between the three months ended ~~September~~June 30, ~~2022,~~2023, and the three months ended ~~June 30, 2022~~March 31, 2023 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the ~~nine~~six months ended ~~September~~June 30, 2023, and the six months ended June 30, 2022 ~~and the nine months ended September 30, 2021~~ (“YTD ~~2022-over-YTD 2021”~~2023-over-YTD 2022”).

Overview of the Company

General Overview

~~Our strategic objective is to be a premier operator of top-tier oil and gas assets.~~ 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 sustainably grow value for all of our ~~stakeholders.~~stakeholders by maintaining and optimizing our high-quality asset portfolio, generating cash flows, and maintaining a strong balance sheet. Our strategy ~~for achieving our goals~~ is to ~~focus~~be a premier operator of top-tier oil and gas assets. Our team executes this strategy by prioritizing safety, technological innovation, and stewardship of natural resources, all of which are integral to our corporate culture. Our near-term goals include returning value to stockholders through our Stock Repurchase Program and fixed dividend payments, and focusing on ~~high-quality economic drilling, completion, and production opportunities.~~ continued operational excellence.

Our ~~investment~~asset portfolio is comprised of ~~oil and gas producing~~high-quality assets ~~in the state of Texas, specifically~~ in the Midland Basin of West Texas and in the Maverick Basin of South ~~Texas. With~~Texas that are capable of generating strong returns in the current macroeconomic environment, and present resilience to commodity price risk and volatility. We remain focused on maximizing returns and increasing the value of our top-tier assets through disciplined capital spending, strategic acreage acquisitions, and continued ~~success in~~development and optimization of our existing assets. We believe that our high-quality asset base provides for a sustainable approach to prioritizing operational execution, maintaining a strong balance sheet, generating cash flows, ~~and reducing our outstanding principal debt balance, our short-term goals include~~ returning ~~value~~capital to stockholders, ~~in a sustainable~~ and ~~repeatable way through our Stock Repurchase Program and recently increased fixed dividend payments.~~maintaining strong financial flexibility.

We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; ~~making a positive impact~~building and maintaining partnerships with our stakeholders by investing in and connecting with the communities where we live and work; and transparency in reporting on our progress in these areas. We have prioritized ESG initiatives by, among other things, integrating enhanced environmental and social programs throughout the organization and setting near-term and medium-term goals that include reducing flaring and greenhouse gas emissions intensity and maintaining low methane emissions intensity. Additionally, we are implementing systems to track additional ESG metrics, to improve future reporting, and to increase employee awareness. The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the development and implementation of the Company’s ESG policies, programs and initiatives, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations and environmental stewardship, compensation for our executives and eligible employees under our long-term incentive plan, and compensation for all employees under our short-term incentive plan is calculated based on, in part, certain Company-wide, performance-based metrics that include key financial, operational, environmental, health, and safety measures.

~~Global~~While the United States inflation rate has decreased since the beginning of the year and the average rate of inflation in 2023 is lower than it was in 2022, global commodity and financial markets remain subject to heightened levels of uncertainty and ~~volatility~~volatility. Tightening of monetary policy by the United States Federal Reserve, recent oil production curtailment agreements among the Organization of the Petroleum Exporting Countries (“OPEC”) plus other non-OPEC oil producing countries (collectively referred to as ~~a result of inflation, macroeconomic uncertainty,~~“OPEC+”), and the ongoing conflict between Russia and Ukraine and associated economic and trade sanctions ~~on Russia, and the Pandemic. These issues~~ have driven commodity price volatility, contributed to ~~increased service provider costs,~~instances of supply chain disruptions and a rise in interest rates, and could have further industry-specific impacts ~~which~~that 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 ~~2021~~2022 Form 10-K. Despite continuing ~~impacts of geopolitical issues and future macroeconomic~~ uncertainty, we expect to ~~maintain~~maximize the value of our ~~ability to~~high-quality asset base and sustain strong operational performance and financial ~~stability while maximizing returns, improving leverage metrics, and maximizing the value of our top-tier Midland Basin and South Texas assets.~~stability. We remain focused on returning capital to stockholders through cash flow generation.

Areas of Operations

Our Midland Basin assets are comprised of approximately ~~80,000~~110,000 net acres located in the Permian Basin in West Texas (“Midland Basin”). In the ~~third~~second quarter of ~~2022,~~2023, drilling and completion activities within our RockStar and Sweetie Peck positions continued to focus primarily on development optimization ~~and further delineating~~of our Midland Basin position. Our 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”). In the ~~third~~second quarter of ~~2022,~~2023, we focused our operations in South Texas ~~were focused~~ on production from both the Austin Chalk formation and Eagle Ford shale formation, development of the Eagle Ford shale formation, and development and further ~~development~~delineation of the Austin Chalk formation. Our overlapping acreage position in the Maverick Basin covers a significant portion of the western Eagle Ford shale and Austin Chalk formations, and includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.

Second Quarter 2023 Overview and Outlook for the Remainder of 2023

During the second quarter of 2023, we continued to execute on our goal of sustainably returning capital to our stockholders through our Stock Repurchase Program and fixed quarterly dividend by repurchasing and subsequently retiring approximately 2.6 million shares of our outstanding common stock at a cost of $68.7 million, excluding excise taxes, commissions, and fees, and declaring quarterly dividends of $0.15 per share totaling $17.7 million. Please refer to Note 3 - Equity in Part I, Item 1 of this report for additional discussion of our Stock Repurchase Program.

Additionally, during the second quarter of 2023, we acquired approximately 20,000 net acres of oil and gas properties in the Midland Basin, and an additional 2,800 net acres through our continued leasing efforts, demonstrating our repeated success in extending inventory life and maintaining a strong balance sheet. Please refer to Note 11 - Acquisitions in Part I, Item 1 of this report for additional discussion.

Our ~~2022~~total 2023 capital program, excluding acquisitions and leasing efforts, is expected to be ~~between $870.0~~approximately $1.05 billion. This reflects a decrease of $50.0 million, ~~and $900.0 million.~~as compared to our original expectation, primarily as a result of lower-than-expected costs. Our ~~financial and operational flexibility allows us to continually monitor the economic environment and adjust our activity level as warranted. Our 2022~~ capital program remains focused on our highly economic oil development projects in both our Midland Basin and South Texas assets. ~~We believe that our high-quality asset portfolio is capable of generating strong returns in the current macroeconomic environment, which~~During 2023, we expect ~~will~~

~~enable us~~ to ~~grow cash flows, improve leverage metrics,~~repeat our track record of inventory replacement and ~~maintain strong financial flexibility.~~growth, and to continue applying our strength in geosciences and development optimization. Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund the remainder of our ~~2022~~2023 capital program.

~~Third Quarter 2022 Overview and Outlook for the Remainder of 2022~~

During the third quarter of 2022, our Board of Directors authorized the Stock Repurchase Program and increased our fixed dividend to $0.60 per share annually, to be paid in quarterly increments of $0.15 per share, both of which align with our goal to implement a sustainable and repeatable capital return program that creates long-term value for our stockholders. During the three months ended September 30, 2022, we repurchased and subsequently retired 452,734 shares of our outstanding common stock at a cost of $20.2 million. Please refer to ~~Note 3 - Equity~~ ~~in Part I, Item 1 of this report for additional discussion.~~

Financial and Operational Results. Average net daily equivalent production for the three months ended ~~September~~June 30, ~~2022, decreased six~~2023, increased five percent sequentially to ~~137.8~~154.4 MBOE, consisting of ~~decreases in~~a 12 percent increase from our South Texas assets driven by higher oil, ~~volumes of nine percent, or 5.8 MBbl per day,~~ gas, ~~volumes of three percent, or 9.9 MMcf per day,~~ and NGL production volumes from both new and existing wells. This increase was slightly offset by a one percent decrease from our Midland Basin assets resulting from the timing of ~~six percent, or 1.4 MBbl per day.~~well completions.

Oil, gas, and NGL realized prices, before the effect of derivative settlements (“realized price” or “realized prices”), decreased sequentially by 15three percent, 29 percent, and 1421 percent, respectively, as a result of decreases in benchmark commodity prices during the ~~third~~second quarter of ~~2022. Realized prices for gas remained flat sequentially.~~2023. Total realized price per BOE decreased 1210 percent ~~sequentially. The decrease in total realized price per BOE and the decrease in total net equivalent production volumes resulted~~sequentially, resulting in a 16four percent ~~sequential~~ decrease in oil, gas, and NGL production revenue, which was ~~$827.6 million for the three months ended September 30, 2022, compared with $990.4~~$546.6 million for the three months ended June 30, ~~2022.~~2023, compared with $570.8 million for the three months ended March 31, 2023. Oil, gas, and NGL production expense of $10.36 per BOE ~~of $12.62~~ for the three months ended ~~September~~June 30, ~~2022, increased two~~2023, decreased four percent sequentially, primarily as a result of ~~increases~~decreases in production tax expense per BOE and lease operating expense (“LOE”) per ~~BOE and ad valorem tax expense per BOE, mostly offset by a decrease in production tax expense per~~ BOE.

We recorded a net derivative ~~gain~~gains of ~~$137.6~~$11.7 million ~~for the three months ended September 30, 2022, compared with a net derivative loss of $104.2~~and $51.3 million for the three months ended June 30, ~~2022.~~2023, and March 31, 2023, respectively. Included within these amounts are derivative settlement ~~losses~~gains of ~~$186.3~~$15.6 million and ~~$240.6~~$5.1 million for the three months ended ~~September 30, 2022, and~~ June 30, ~~2022,~~2023, and March 31, 2023, respectively.

Operational and financial activities during the three months ended ~~September~~June 30, ~~2022,~~2023, resulted in the following:

•Net cash provided by operating activities of ~~$513.4~~$383.3 million, compared with $331.6 million for the three months ended ~~September 30, 2022, compared with $542.6 million for the three months ended June 30, 2022.~~March 31, 2023.

•Net income of ~~$481.2~~$149.9 million, or ~~$3.87~~$1.25 per diluted share, compared with net income of $198.6 million, or $1.62 per diluted share, for the three months ended ~~September 30, 2022, compared with net income of $323.5 million, or $2.60 per diluted share, for the three months ended June 30, 2022.~~March 31, 2023.

•Adjusted EBITDAX, a non-GAAP financial measure, ~~for the three months ended September 30, 2022,~~ of ~~$460.2~~$390.2 million, compared with ~~$559.7~~$401.4 million for the three months ended ~~June 30, 2022.~~March 31, 2023. Please refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations to net income ~~(loss)~~ and net cash provided by operating activities.

Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended ~~September 30, 2022, and~~ June 30, ~~2022,~~2023, and March 31, 2023, and Between the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2022,~~2023, and ~~2021~~2022 below for additional discussion.

Operational Activities. In our Midland Basin program, we operated three drilling rigs and ~~two~~one completion ~~crews,~~crew, drilled 1211 gross ~~(10~~(five net) wells, and completed 1520 gross ~~(14~~(16 net) wells during the ~~third~~second quarter of ~~2022. Net~~2023. Average net daily equivalent production volumes decreased sequentially by ~~five~~one percent to ~~7.2 MMBOE.~~73.0 MBOE. Costs incurred in our Midland Basin program during the three months ended ~~September~~June 30, ~~2022,~~2023, totaled ~~$129.0~~$261.0 million, or 5170 percent of our total costs incurred for the period. During the remainder of ~~2022,~~2023, we anticipate operating ~~three drilling rigs and~~ one completion ~~crew. Activity is expected~~crew, and we plan to add an additional drilling rig in the fourth quarter to begin drilling on recently acquired acreage. We expect our activity to focus primarily on developing ~~the Spraberry and Wolfcamp~~ formations within our RockStar and Sweetie Peck positions.

In our South Texas program, we operated two drilling rigs and ~~averaged~~ one completion crew, drilled 12 gross (12 net) wells, and completed eight gross (eight net) wells ~~and completed 17 gross (17 net) wells~~ during the ~~third~~second quarter of ~~2022. Net~~2023. Average net daily equivalent production volumes ~~decreased~~increased sequentially by ~~five~~12 percent to ~~5.5 MMBOE.~~81.4 MBOE. Costs incurred in our South Texas program during the three months ended ~~September~~June 30, ~~2022,~~ 2023,

totaled ~~$110.7~~$102.6 million, or 4427 percent of our total costs incurred for the period. ~~During the remainder of 2022, we~~We anticipate operating two drilling rigs for the remainder of 2023 and one completion crew for a majority of the remainder of 2023, focused primarily on 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, ~~2022:~~2023:


		Midland Basin		South Texas (1)		Total			Midland Basin		South Texas (1)		Total
		Gross	Net	Gross	Net	Gross	Net		Gross	Net	Gross	Net	Gross	Net
Wells drilled but not completed at December 31, 2021		30	27	32	32	62	59
Wells drilled but not completed at December 31, 2022 (2)								Wells drilled but not completed at December 31, 2022 (2)	49	40	29	28	78	69
Wells drilled	Wells drilled	16	14	9	9	25	23	Wells drilled	8	7	7	7	15	14
Wells completed	Wells completed	(6)	(5)	(13)	(13)	(19)	(18)	Wells completed	(12)	(10)	(17)	(16)	(29)	(26)

Wells drilled but not completed at March 31, 2022		40	36	28	28	68	64
Wells drilled but not completed at March 31, 2023 (2)								Wells drilled but not completed at March 31, 2023 (2)	45	37	19	19	64	56
Wells drilled ~~(2)~~	Wells drilled ~~(2)~~	16	13	11	10	27	23	Wells drilled ~~(2)~~	11	5	12	12	23	17
Wells completed ~~(2)~~	Wells completed ~~(2)~~	(7)	(7)	(2)	(2)	(9)	(9)	Wells completed ~~(2)~~	(20)	(16)	(8)	(8)	(28)	(24)

Wells drilled but not completed at June 30, 2022 (3)		49	41	37	36	86	78
Wells drilled		12	10	8	8	20	18
Wells completed		(15)	(14)	(17)	(17)	(32)	(31)

Wells drilled but not completed at September 30, 2022 (3)		46	38	28	27	74	65
Wells drilled but not completed at June 30, 2023 (2)								Wells drilled but not completed at June 30, 2023 (2)	36	27	23	23	59	50

(1) The South Texas drilled but not completed well count ~~includes 11~~as of December 31, 2022, included nine gross ~~(11~~(nine net) wells that were not included in our five-year development plan atas of December 31, ~~2021.~~2022, eight of which were in the Eagle Ford shale formation.

(2) ~~Wells drilled and wells completed during the three months ended June 30, 2022, exclude one drilled and completed well that was subsequently abandoned, outside of our core areas of operations~~.

~~(3)~~ Amounts may not calculate due to rounding.

Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled ~~$253.8~~$373.9 million and ~~$677.4~~$682.6 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, respectively, and were primarily incurred in our Midland Basin and South Texas programs as ~~further detailed~~discussed in Operational Activities above.

Production Results. The table below presents our production by product type for each of our assets for the ~~sequential quarterly~~ periods ~~and the YTD 2022-over-YTD 2021 periods:~~presented:


		For the Three Months Ended				For the Nine Months Ended					For the Three Months Ended				For the Six Months Ended
		September 30, 2022		June 30, 2022		September 30, 2022		September 30, 2021			June 30, 2023		March 31, 2023		June 30, 2023		June 30, 2022
Midland Basin Production:	Midland Basin Production:									Midland Basin Production:
Oil (MMBbl)	Oil (MMBbl)	4.5		4.9		14.7		18.5		Oil (MMBbl)	4.2		4.2		8.4		10.2
Gas (Bcf)	Gas (Bcf)	16.1		16.0		47.5		38.9		Gas (Bcf)	14.8		14.5		29.2		31.4
NGLs (MMBbl)	NGLs (MMBbl)	—		—		—		—		NGLs (MMBbl)	—		—		—		—
Equivalent (MMBOE)	Equivalent (MMBOE)	7.2		7.6		22.6		25.0		Equivalent (MMBOE)	6.6		6.7		13.3		15.4
Average net daily equivalent (MBOE per day)	Average net daily equivalent (MBOE per day)	78.1		83.2		82.9		91.6		Average net daily equivalent (MBOE per day)	73.0		74.0		73.5		85.3
Relative percentage	Relative percentage	57	%	57	%	57	%	68	%	Relative percentage	47	%	51	%	49	%	57	%

South Texas Production:	South Texas Production:									South Texas Production:
Oil (MMBbl)	Oil (MMBbl)	1.2		1.2		3.6		1.7		Oil (MMBbl)	1.7		1.4		3.1		2.4
Gas (Bcf)	Gas (Bcf)	14.9		15.5		46.3		38.2		Gas (Bcf)	18.9		17.8		36.7		31.4
NGLs (MMBbl)	NGLs (MMBbl)	1.8		1.9		5.9		3.8		NGLs (MMBbl)	2.6		2.1		4.7		4.0
Equivalent (MMBOE)	Equivalent (MMBOE)	5.5		5.8		17.2		11.8		Equivalent (MMBOE)	7.4		6.5		13.9		11.7
Average net daily equivalent (MBOE per day)	Average net daily equivalent (MBOE per day)	59.7		63.4		63.0		43.2		Average net daily equivalent (MBOE per day)	81.4		72.5		77.0		64.6
Relative percentage	Relative percentage	43	%	43	%	43	%	32	%	Relative percentage	53	%	49	%	51	%	43	%

Total Production:	Total Production:									Total Production:
Oil (MMBbl)	Oil (MMBbl)	5.7		6.1		18.3		20.2		Oil (MMBbl)	5.9		5.7		11.5		12.6
Gas (Bcf)	Gas (Bcf)	31.0		31.5		93.8		77.1		Gas (Bcf)	33.7		32.2		65.9		62.9
NGLs (MMBbl)	NGLs (MMBbl)	1.8		1.9		5.9		3.8		NGLs (MMBbl)	2.6		2.1		4.7		4.1
Equivalent (MMBOE)	Equivalent (MMBOE)	12.7		13.3		39.8		36.8		Equivalent (MMBOE)	14.1		13.2		27.2		27.1
Average net daily equivalent (MBOE per day)	Average net daily equivalent (MBOE per day)	137.8		146.6		145.8		134.8		Average net daily equivalent (MBOE per day)	154.4		146.4		150.5		149.9

Note: Amounts may not calculate due to rounding.

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 effect of derivative settlements. 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 effect of derivative settlements, for the three months ended ~~September 30, 2022,~~ June 30, ~~2022,~~2023, March 31, 2023, and ~~September~~June 30, ~~2021:~~2022:


		For the Three Months Ended							For the Three Months Ended
		September 30, 2022		June 30, 2022		September 30, 2021			June 30, 2023		March 31, 2023		June 30, 2022
Oil (per Bbl):	Oil (per Bbl):							Oil (per Bbl):
Average NYMEX contract monthly price	Average NYMEX contract monthly price	$	91.56	$	108.41	$	70.56	Average NYMEX contract monthly price	$	73.78	$	76.13	$	108.41
Realized price	Realized price	$	92.66	$	108.64	$	69.30	Realized price	$	72.12	$	74.31	$	108.64
Effect of oil derivative settlements	Effect of oil derivative settlements	$	(21.22)	$	(29.19)	$	(19.13)	Effect of oil derivative settlements	$	(0.08)	$	(1.10)	$	(29.19)
Gas:	Gas:							Gas:
Average NYMEX monthly settle price (per MMBtu)	Average NYMEX monthly settle price (per MMBtu)	$	8.20	$	7.17	$	4.01	Average NYMEX monthly settle price (per MMBtu)	$	2.10	$	3.42	$	7.17
Realized price (per Mcf)	Realized price (per Mcf)	$	7.58	$	7.66	$	5.12	Realized price (per Mcf)	$	2.07	$	2.91	$	7.66
Effect of gas derivative settlements (per Mcf)	Effect of gas derivative settlements (per Mcf)	$	(2.00)	$	(1.69)	$	(1.23)	Effect of gas derivative settlements (per Mcf)	$	0.43	$	0.35	$	(1.69)
NGLs (per Bbl):	NGLs (per Bbl):							NGLs (per Bbl):
Average OPIS price (1)	Average OPIS price (1)	$	42.47	$	50.05	$	40.39	Average OPIS price (1)	$	25.21	$	30.95	$	50.05
Realized price	Realized price	$	36.36	$	42.08	$	36.87	Realized price	$	20.83	$	26.24	$	42.08
Effect of NGL derivative settlements	Effect of NGL derivative settlements	$	(2.11)	$	(4.13)	$	(16.65)	Effect of NGL derivative settlements	$	0.61	$	—	$	(4.13)

(1) ~~Average~~Effective January 1, 2023, average OPIS price per barrel of NGL, historical or strip, assumes a composite barrel product mix of 42% Ethane, 28% Propane, 6% Isobutane, 11% Normal Butane, and 13% Natural Gasoline. For periods prior to 2023, average OPIS price per barrel of NGL, historical or strip, assumed a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural ~~Gasoline for all periods presented. This~~Gasoline. These product ~~mix represents~~mixes represent the industry standard composite barrel for the respective periods presented and ~~does~~do not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

Given the uncertainty surrounding ~~(a)~~global financial markets, production output from OPEC+, the ongoing conflict between Russia and Ukraine ~~(b)~~and the associated economic and trade sanctions, that certain countries have imposed on Russia, (c) production output from the Organization of the Petroleum Exporting Countries (“OPEC”) plus other non-OPEC oil producing countries (collectively referred to as “OPEC+”), and the potential impacts of these issues on global commodity ~~and financial~~ markets, we expect benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future, and we cannot reasonably predict the timing or likelihood of any future impacts that may result, which could include further inflation, supply chain disruptions, a continued rise in interest rates, and industry-specific impacts. In addition to supply and demand fundamentals, as global commodities, the prices for oil, gas, and NGLs are 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. Our realized prices at local sales points may also be affected by infrastructure capacity or outages in the areas of our operations and beyond.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of ~~October 27, 2022,~~July 21, 2023, and ~~September~~June 30, ~~2022:~~2023:


		As of October 27, 2022		As of September 30, 2022			As of July 21, 2023		As of June 30, 2023
NYMEX WTI oil (per Bbl)	NYMEX WTI oil (per Bbl)	$	83.78	$	75.32	NYMEX WTI oil (per Bbl)	$	75.43	$	70.13
NYMEX Henry Hub gas (per MMBtu)	NYMEX Henry Hub gas (per MMBtu)	$	5.14	$	5.85	NYMEX Henry Hub gas (per MMBtu)	$	3.24	$	3.22
OPIS NGLs (per Bbl)	OPIS NGLs (per Bbl)	$	33.81	$	32.91	OPIS NGLs (per Bbl)	$	26.39	$	23.62

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. We

make decisions about the amount of our expected production that we cover by derivatives based on the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and the terms and futures prices that are made available by our approved counterparties. 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 below which we are insulated from further price decreases. Please refer to Note 107 - 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, ~~2022,~~2023, and the preceding three quarters:

For the Three Months Ended
September 30, June 30, March 31, December 31,
2022 2022 2022 2021
(in millions)
Production (MMBOE) 12.7 13.3 13.8 14.6
Oil, gas, and NGL production revenue $ 827.6 $ 990.4 $ 858.7 $ 852.4
Oil, gas, and NGL production expense $ 160.0 $ 165.6 $ 144.7 $ 143.3
Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 145.9 $ 154.8 $ 159.5 $ 200.0
Exploration $ 14.2 $ 20.9 $ 9.0 $ 12.6
General and administrative $ 28.4 $ 28.3 $ 25.0 $ 37.1
Net income $ 481.2 $ 323.5 $ 48.8 $ 424.9

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


	For the Three Months Ended
	June 30,		March 31,		December 31,		September 30,
	2023		2023		2022		2022

	(in millions)
Production (MMBOE)	14.1		13.2		13.1		12.7
Oil, gas, and NGL production revenue	$	546.6	$	570.8	$	669.3	$	827.6
Oil, gas, and NGL production expense	$	145.6	$	142.3	$	150.7	$	160.0
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	157.8	$	154.2	$	143.6	$	145.9
Exploration	$	15.0	$	18.4	$	10.8	$	14.2
General and administrative	$	27.5	$	27.7	$	32.8	$	28.4
Net income	$	149.9	$	198.6	$	258.5	$	481.2

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,
		2022			2022			2022			2021				2023			2023			2022			2022
Average net daily equivalent production (MBOE per day)	Average net daily equivalent production (MBOE per day)	137.8			146.6			153.3			158.3			Average net daily equivalent production (MBOE per day)	154.4			146.4			142.9			137.8
Lease operating expense (per BOE)	Lease operating expense (per BOE)	$	5.64		$	5.11		$	4.25		$	4.21		Lease operating expense (per BOE)	$	4.98		$	5.16		$	5.20		$	5.64
Transportation costs (per BOE)	Transportation costs (per BOE)	$	2.87		$	2.87		$	2.74		$	2.61		Transportation costs (per BOE)	$	2.89		$	2.81		$	2.86		$	2.87
Production taxes as a percent of oil, gas, and NGL production revenue	Production taxes as a percent of oil, gas, and NGL production revenue	4.9		%	5.1		%	4.7		%	4.8		%	Production taxes as a percent of oil, gas, and NGL production revenue	4.3		%	4.7		%	4.8		%	4.9		%
Ad valorem tax expense (per BOE)	Ad valorem tax expense (per BOE)	$	0.93		$	0.69		$	0.58		$	0.22		Ad valorem tax expense (per BOE)	$	0.83		$	0.81		$	0.97		$	0.93
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)	Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)	$	11.50		$	11.60		$	11.56		$	13.74		Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)	$	11.23		$	11.70		$	10.93		$	11.50
General and administrative (per BOE)	General and administrative (per BOE)	$	2.24		$	2.12		$	1.81		$	2.55		General and administrative (per BOE)	$	1.96		$	2.10		$	2.50		$	2.24

Note: Amounts may not calculate due to rounding.

3025

Overview of Selected Production and Financial Information, Including Trends


		For the Three Months Ended				Amount Change Between Periods			Percent Change Between Periods				For the Nine Months Ended							Amount Change Between Periods						Percent Change Between Periods		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
		September 30,		June 30,							September 30,					September 30,					Percent Change Between Periods			June 30,	March 31,				Amount Change Between Periods														Amount Change Between Periods			June 30,					Percent Change Between Periods
		2022		2022							2022					2021								2023	2023																					2022
Net production volumes: (1)	Net production volumes: (1)																																			Net production volumes: (1)
Oil (MMBbl)	Oil (MMBbl)	5.7		6.1				(0.5)			(8)	%			18.3				20.2				(1.9)								(9)		%	Oil (MMBbl)	5.9					5.7				0.2					4		%	11.5						12.6			(1.1)						(8)	%
Gas (Bcf)	Gas (Bcf)	31.0		31.5		(0.6)			(2)	%			93.8				77.1				16.7						22	%		Gas (Bcf)		33.7					32.2				1.5				5		%			65.9						62.9			3.1					5		%
NGLs (MMBbl)	NGLs (MMBbl)	1.8		1.9		(0.1)			(5)	%			5.9				3.8				2.1						56	%		NGLs (MMBbl)		2.6					2.1				0.4				20		%			4.7						4.1			0.6					16		%
Equivalent (MMBOE)	Equivalent (MMBOE)	12.7		13.3		(0.7)			(5)	%			39.8				36.8				3.0						8	%	Equivalent (MMBOE)	14.1					13.2				0.9					7		%			27.2						27.1			0.1					—		%
Average net daily production: (1)	Average net daily production: (1)																										Average net daily production: (1)
Oil (MBbl per day)	Oil (MBbl per day)	61.7		67.5		(5.8)			(9)	%			66.9				73.9				(6.9)						(9)	%	Oil (MBbl per day)	64.5					62.9				1.6				3		%			63.7						69.6			(5.9)					(8)		%
Gas (MMcf per day)	Gas (MMcf per day)	336.5		346.3		(9.9)			(3)	%			343.7				282.5				61.2						22	%	Gas (MMcf per day)	370.4					358.1				12.3				3		%			364.3						347.4			17.0					5		%
NGLs (MBbl per day)	NGLs (MBbl per day)	20.1		21.4		(1.4)			(6)	%			21.6				13.9				7.8						56	%	NGLs (MBbl per day)	28.2					23.8				4.4				18		%			26.0						22.4			3.6					16		%
Equivalent (MBOE per day)	Equivalent (MBOE per day)	137.8		146.6		(8.8)			(6)	%			145.8				134.8				11.0						8	%	Equivalent (MBOE per day)	154.4					146.4				8.0				5		%			150.5						149.9			0.5					—		%
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	$	525.9	$	667.0	$	(141.1)		(21)	%			$	1,800.3			$	1,300.5			$	499.7					38	%	Oil production revenue	$	423.4				$	420.8			$	2.6			1		%			$	844.2					$	1,274.3		$	(430.1)				(34)		%
Gas production revenue	Gas production revenue	234.6		241.3		(6.8)			(3)	%			645.9				327.0				319.0						98	%	Gas production revenue	69.7					93.7				(24.0)				(26)		%			163.5						411.4			(247.9)					(60)		%
NGL production revenue	NGL production revenue	67.1		82.0		(15.0)			(18)	%			230.5				118.1				112.4						95	%	NGL production revenue	53.4					56.2				(2.8)				(5)		%			109.6						163.4			(53.8)					(33)		%
Total oil, gas, and NGL production revenue	Total oil, gas, and NGL production revenue	$	827.6	$	990.4	$	(162.8)		(16)	%			$	2,676.7			$	1,745.5			$	931.1					53	%	Total oil, gas, and NGL production revenue	$	546.6				$	570.8			$	(24.2)			(4)		%			$	1,117.3					$	1,849.1		$	(731.8)				(40)		%
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	$	71.5	$	68.1	$	3.3		5	%			$	198.2			$	164.2			$	34.0					21	%	Lease operating expense	$	69.9				$	68.0			$	1.9			3		%			$	138.0					$	126.7		$	11.3				9		%
Transportation costs	Transportation costs	36.4		38.3		(1.8)			(5)	%			112.4				101.4				11.0						11	%	Transportation costs	40.6					37.0				3.6				10		%			77.7						76.0			1.7					2		%
Production taxes	Production taxes	40.2		50.0		(9.8)			(20)	%			130.7				80.4				50.3						63	%	Production taxes	23.4					26.7				(3.3)				(12)		%			50.0						90.4			(40.4)					(45)		%
Ad valorem tax expense	Ad valorem tax expense	11.9		9.2		2.7			29	%			29.0				16.2				12.8						79	%	Ad valorem tax expense	11.6					10.6				1.0				9		%			22.3						17.1			5.1					30		%
Total oil, gas, and NGL production expense	Total oil, gas, and NGL production expense	$	160.0	$	165.6	$	(5.6)		(3)	%			$	470.2			$	362.1			$	108.1					30	%	Total oil, gas, and NGL production expense	$	145.6				$	142.3			$	3.2			2		%			$	287.9					$	310.3		$	(22.3)				(7)		%
Realized price:	Realized price:																										Realized price:
Oil (per Bbl)	Oil (per Bbl)	$	92.66	$	108.64	$	(15.98)		(15)	%			$	98.52			$	64.50			$	34.02					53	%	Oil (per Bbl)	$	72.12				$	74.31			$	(2.19)			(3)		%			$	73.19					$	101.15		$	(27.96)				(28)		%
Gas (per Mcf)	Gas (per Mcf)	$	7.58	$	7.66	$	(0.08)		(1)	%			$	6.88			$	4.24			$	2.64					62	%	Gas (per Mcf)	$	2.07				$	2.91			$	(0.84)			(29)		%			$	2.48					$	6.54		$	(4.06)				(62)		%
NGLs (per Bbl)	NGLs (per Bbl)	$	36.36	$	42.08	$	(5.72)		(14)	%			$	39.04			$	31.19			$	7.85					25	%	NGLs (per Bbl)	$	20.83				$	26.24			$	(5.41)			(21)		%			$	23.29					$	40.25		$	(16.96)				(42)		%
Per BOE	Per BOE	$	65.27	$	74.23	$	(8.96)		(12)	%			$	67.23			$	47.43			$	19.80					42	%	Per BOE	$	38.89				$	43.31			$	(4.42)			(10)		%			$	41.03					$	68.14		$	(27.11)				(40)		%
Per BOE data: (1)	Per BOE data: (1)																												Per BOE data: (1)
Oil, gas, and NGL production expense:	Oil, gas, and NGL production expense:																												Oil, gas, and NGL production expense:
Lease operating expense	Lease operating expense	$	5.64	$	5.11	$	0.53		10	%			$	4.98			$	4.46			$	0.52					12	%	Lease operating expense	$	4.98				$	5.16			$	(0.18)			(3)		%			$	5.07					$	4.67		$	0.40				9		%
Transportation costs	Transportation costs	2.87		2.87		—			—	%			2.82				2.75				0.07						3	%	Transportation costs	2.89					2.81				0.08				3		%			2.85						2.80			0.05					2		%
Production taxes	Production taxes	3.17		3.75		(0.58)			(15)	%			3.28				2.18				1.10						50	%	Production taxes	1.66					2.02				(0.36)				(18)		%			1.84						3.33			(1.49)					(45)		%
Ad valorem tax expense	Ad valorem tax expense	0.93		0.69		0.24			35	%			0.73				0.44				0.29						66	%	Ad valorem tax expense	0.83					0.81				0.02				2		%			0.82						0.63			0.19					30		%
Total oil, gas, and NGL production expense (1)	Total oil, gas, and NGL production expense (1)	$	12.62	$	12.41	$	0.21		2	%			$	11.81			$	9.84			$	1.97					20	%	Total oil, gas, and NGL production expense (1)	$	10.36				$	10.80			$	(0.44)			(4)		%			$	10.57					$	11.43		$	(0.86)				(8)		%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	11.50	$	11.60	$	(0.10)		(1)	%			$	11.56			$	15.61			$	(4.05)					(26)	%	Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	11.23				$	11.70			$	(0.47)			(4)		%			$	11.46					$	11.58		$	(0.12)				(1)		%
General and administrative	General and administrative	$	2.24	$	2.12	$	0.12		6	%			$	2.05			$	2.03			$	0.02					1	%	General and administrative	$	1.96				$	2.10			$	(0.14)			(7)		%			$	2.03					$	1.96		$	0.07				4		%
Derivative settlement loss (2)		$	(14.69)	$	(18.03)	$	3.34		19	%			$	(14.95)			$	(13.05)			$	(1.90)					(15)	%
Derivative settlement gain (loss)(2)																													Derivative settlement gain (loss)(2)	$	1.11				$	0.39			$	0.72			185		%			$	0.76					$	(15.06)		$	15.82				105		%
Earnings per share information (in thousands, except per share data): (3)	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	123,195		121,910		1,285			1	%			122,318				118,224				4,094						3	%	Basic weighted-average common shares outstanding	119,408					121,671				(2,263)				(2)		%			120,533						121,909			(1,376)					(1)		%
Diluted weighted-average common shares outstanding	Diluted weighted-average common shares outstanding	124,279		124,343		(64)			—	%			124,233				118,224				6,009						5	%	Diluted weighted-average common shares outstanding	120,074					122,294				(2,220)				(2)		%			121,175						124,267			(3,092)					(2)		%
Basic net income (loss) per common share		$	3.91	$	2.65	$	1.26		48	%			$	6.98			$	(3.29)			$	10.27					312	%
Diluted net income (loss) per common share		$	3.87	$	2.60	$	1.27		49	%			$	6.87			$	(3.29)			$	10.16					309	%
Basic net income per common share																													Basic net income per common share	$	1.26				$	1.63			$	(0.37)			(23)		%			$	2.89					$	3.05		$	(0.16)				(5)		%
Diluted net income per common share																													Diluted net income per common share	$	1.25				$	1.62			$	(0.37)			(23)		%			$	2.88					$	3.00		$	(0.12)				(4)		%

3126

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

(2) Derivative settlements for the three months ended ~~September~~June 30, ~~2022,~~2023, and for the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, and ~~2021,~~2022, 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, ~~2022, decreased six~~2023, increased five percent sequentially, primarily consisting of ~~six~~a 12 percent ~~decreases~~increase from our South Texas assets, driven by higher oil, gas, and NGL production volumes from both new and existing wells. The increase from our South Texas assets was slightly offset by a one percent decrease from our Midland Basin ~~and South Texas~~ assets, ~~primarily due to~~which resulted from the ~~effects~~timing of ~~delayed~~ well ~~completions which were largely related to the supply chain, and impacts to production associated with offset activity.~~completions. Average net daily equivalent production ~~for the nine months ended September 30,~~remained flat YTD 2023-over-YTD 2022 ~~increased eight~~as a 19 percent ~~compared with the same period in 2021, driven by an~~ increase ~~of 46 percent~~ from our South Texas assets ~~which~~ was offset by a 14 percent decrease from our Midland Basin assets. These changes were primarily the result of the timing of well completions. We expect a slight increase in total net equivalent production for the full-year 2023, compared with 2022, driven by increased ~~capital allocation~~production from both new and existing wells in South Texas and as we benefit from reduced production curtailments because the build-out of South Texas oil handling capacity is expected to ~~our Austin Chalk assets, and strong well performance.~~meet production volume needs.

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 on a per BOE basis decreased ~~$8.96~~$4.42 sequentially and decreased $27.11 YTD 2023-over-YTD 2022, as a result of decreases in oil, gas, and NGL benchmark prices. ~~The impact on oil, gas,~~For the three months ended June 30, 2023, and ~~NGL production revenues resulting from these decreases was partially offset by a decrease in the loss~~March 31, 2023, we had gains on the settlement of our commodity derivative contracts of ~~$3.34 per BOE. Our realized price on a~~$1.11 per BOE ~~basis increased $19.80 YTD 2022-over-YTD 2021 as~~and $0.39 per BOE, respectively. For the six months ended June 30, 2023, we had a ~~result of increased benchmark commodity prices. The positive impact on oil, gas, and NGL production revenues resulting from this increase was partially offset by an increase in the loss~~gain on the settlement of our commodity derivative contracts of ~~$1.90~~$0.76 per ~~BOE.~~BOE, compared to a loss of $15.06 per BOE for the same period in 2022.

LOE on a per BOE basis ~~increased 10~~decreased three percent sequentially as a result of increases in net equivalent production volumes outpacing increases in recurring LOE and 12workover expense. LOE on a per BOE basis increased nine percent YTD ~~2022-over-YTD 2021. These increases were the~~2023-over-YTD 2022 as a result of increased workover activity and ~~increased service provider~~increases in labor costs, both of which ~~have been impacted by inflation. The sequential quarterly increase was also driven by a five percent decrease in total net equivalent production volumes. For the full-year 2022,~~ we expect will lead to an increase in LOE on a per BOE basis ~~to increase,~~for the full-year 2023, compared with 2021, due to increases in service provider costs and workover activity, which we expect to be partially offset by increasing activity in the Austin Chalk, where operating costs are lower than in the Midland Basin.2022. 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 ~~impact~~affect total LOE.

Transportation costs on a per BOE basis ~~remained flat~~increased three percent sequentially and increased ~~three~~two percent YTD 2022-over-YTD 2021. The YTD 2022-over-YTD 2021 increase was the result of a 46 percent increase in net daily equivalent production volumes from our South Texas assets which was partially offset by transportation contract cost reductions.2023-over-YTD 2022. In general, we expect total transportation costs to fluctuate relative to changes in gas and NGL production from our South Texas ~~assets. For the full-year 2022, we expect transportation costs on an absolute basis to increase compared with 2021, as a result of increased activity in South Texas in 2022,~~assets, where we incur a majority of our transportation costs. ~~The impact of~~For the ~~expected increase in net equivalent production volumes from our South Texas assets is expected to outweigh the impact of transportation contract cost reductions, resulting in an expected increase in~~full-year 2023, we expect transportation costs on a per BOE basis ~~for the full-year 2022,~~to decrease compared with ~~2021.~~2022, as a result of transportation cost reductions in the second half of 2023 resulting from the expiration of a long-term contract in South Texas.

Production tax expense on a per BOE basis decreased 1518 percent sequentially and decreased 45 percent YTD 2023-over-YTD 2022, as a result of decreases in realized ~~prices, and increased 50 percent YTD 2022-over-YTD 2021, as a result of increases in realized prices during the period.~~prices. Our overall production tax rate for the three and ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, was ~~4.9~~4.3 percent and 4.5 percent, respectively, compared with ~~5.1~~4.7 percent for the three months ended ~~June 30, 2022,~~March 31, 2023, and ~~4.6~~4.9 percent for the ~~nine~~six months ended ~~September~~June 30, ~~2021.~~2022. 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 expense that we recognize.

Ad valorem tax expense on a per BOE basis increased 35two percent sequentially and 66increased 30 percent YTD ~~2022-over-YTD 2021~~2023-over-YTD 2022 as a result of changes to the expected value assessments of our producing properties, which are driven by ~~increases~~fluctuations in commodity prices. ~~The sequential quarterly increase was further impacted by a decrease in total net equivalent production volumes.~~ We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties changes.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis decreased four percent sequentially and remained flat ~~sequentially and decreased 26 percent~~ YTD ~~2022-over-YTD 2021 as~~2023-over-YTD 2022. The sequential quarterly decrease resulted from a ~~result of increased estimated proved reserves at year-end 2021 and~~shift in our production mix resulting from increased activity in our ~~Austin Chalk program,~~South Texas assets, which ~~has~~have a lower DD&A ~~rates compared with~~rate than our Midland Basin assets. Our DD&A rate fluctuates as a result of changes in our production mix, changes in our total estimated proved reserve volumes, changes in capital allocation, impairments, divestiture activity, and carrying cost funding and sharing arrangements with third ~~parties, changes in our production mix, and changes in our total estimated proved reserve volumes.~~parties. We expect DD&A expense per BOE and ~~DD&A expense~~ on an absolute basis to ~~decrease~~increase in ~~2022,~~2023, compared with ~~2021,~~2022, primarily as a result of cost increases, partially offset by increased ~~estimated proved reserves and increased activity in~~production from our ~~Austin Chalk program.~~South Texas assets.

General and administrative (“G&A”) expense on a per BOE basis ~~increased six~~decreased seven percent sequentially as a result of ~~decreased total~~increased net equivalent production volumes and ~~remained flat~~increased four percent YTD ~~2022-over-YTD 2021. Despite inflationary pressures, for the full-year~~2023-over-YTD 2022 weas a result of increased compensation expense. We currently expect G&A expense to ~~decrease slightly~~increase per BOE and on an absolute basis ~~and to decrease on~~for the full-year 2023 compared with 2022, primarily as a ~~per BOE basis, compared with~~

~~2021. However, G&A expense could fluctuate based on the results~~result of ~~the Company’s full year financial and operational performance metrics.~~expected increases in compensation expense.

Please refer to Comparison of Financial Results and Trends Between the Three Months Ended ~~September 30, 2022, and~~ June 30, ~~2022,~~2023, and March 31, 2023, and Between the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2022,~~2023, and ~~2021~~2022 below for additional discussion of operating expenses.

Comparison of Financial Results and Trends Between the Three Months Ended ~~September 30, 2022, and~~ June 30, ~~2022,~~2023, and March 31, 2023, and Between the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2022,~~2023, and ~~2021~~2022

Average net daily equivalent production, oil, gas, and NGL production revenue, and oil, gas, and NGL production expense

Sequential Quarterly Changes. The following table presents changes in our average net daily equivalent production, oil, gas, and NGL production revenue, and oil, gas, and NGL production expense, by area, between the three months ended ~~September 30, 2022, and~~ June 30, ~~2022:~~2023, and March 31, 2023:

Net Equivalent Production
Decrease Production Revenue
Decrease Production Expense Increase (Decrease)
(MBOE per day) (in millions) (in millions)
Midland Basin (5.1) $ (127.5) $ (8.3)
South Texas (3.7) (35.3) 2.7
Total (8.8) $ (162.8) $ (5.6)

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

Average net daily equivalent production volumes decreased six percent, consisting of six percent decreases from both our Midland Basin and South Texas assets. Our realized oil, gas, and NGL prices decreased 15 percent, one percent, and 14 percent, respectively. The 12 percent decrease in total realized price per BOE, combined with a six percent decrease in average net daily equivalent production volumes, resulted in a 16 percent decrease in oil, gas, and NGL production revenue. Total production expense decreased three percent, primarily driven by a decrease in production tax expense, partially offset by increases in LOE and ad valorem tax expense.

~~YTD 2022-over-YTD 2021 Changes.~~ ~~The following table presents changes in our average net daily equivalent production, production revenue, and production expense, by area, between the nine months ended September 30, 2022, and 2021:~~


		Net Equivalent Production Increase (Decrease)	Production Revenue Increase	Production Expense Increase		Net Equivalent Production Increase (Decrease)	Oil, Gas, and NGL Production Revenue Increase (Decrease)			Oil, Gas, and NGL Production Expense Increase (Decrease)
		(MBOE per day)	(in millions)	(in millions)		(MBOE per day)	(in millions)			(in millions)
Midland Basin	Midland Basin	(8.7)		$	416.7			$	57.4		Midland Basin	(0.9)	$	(30.2)	$	(1.8)
South Texas	South Texas	19.7		514.4				50.7			South Texas	9.0	6.0		5.1
Total	Total	11.0		$	931.1			$	108.1		Total	8.0	$	(24.2)	$	3.2

Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes increased ~~eight~~five percent, consisting of ana 12 percent increase ~~of 46 percent~~ from our South Texas assets, ~~partially~~slightly offset by a one percent decrease ~~of 10 percent~~ from our Midland Basin assets. Realized prices for oil, gas, and NGLs ~~increased 53~~decreased three percent, 6229 percent, and 2521 percent, respectively. As a result of ~~increases~~decreases in benchmark commodity prices for oil, gas, and NGLs, total realized price per BOE decreased 10 percent. This decrease was partially offset by increased average net daily equivalent production ~~volumes,~~resulting in a four percent decrease in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense increased two percent, primarily driven by increases in transportation costs and LOE, partially offset by a decrease in production tax expense.

YTD 2023-over-YTD 2022 Changes. The following table presents changes in our average net daily equivalent production, oil, gas, and NGL production revenue, ~~increased 53 percent. Total~~and oil, gas, and NGL production expense, ~~increased~~by area, between the six months ended June 30, 2023, and 2022:


	Net Equivalent Production Increase (Decrease)	Oil, Gas, and NGL Production Revenue Decrease	Oil, Gas, and NGL Production Expense Increase (Decrease)
	(MBOE per day)	(in millions)	(in millions)
Midland Basin	(11.8)		$	(558.9)	$	(30.4)
South Texas	12.4		(172.8)		8.0
Total	0.5		$	(731.8)	$	(22.3)

Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes remained flat, as a 19 percent ~~primarily as~~increase from our South Texas assets was offset by a 14 percent decrease from our Midland Basin assets. Realized prices for oil, gas, and NGLs decreased 28 percent, 62 percent, and 42 percent, respectively. As a result of ~~increases~~decreases in benchmark commodity prices for oil, gas, and NGLs, total realized price per BOE decreased 40 percent, resulting in a 40 percent decrease in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense decreased seven percent, primarily driven by a decrease in production tax expense, ~~and~~partially offset by an increase in LOE.

Please refer to 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 For the Nine Months Ended
September 30, 2022 June 30,
2022 September 30, 2022 September 30, 2021
(in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 145.9 $ 154.8 $ 460.2 $ 574.4


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		March 31, 2023			June 30, 2023		June 30, 2022

	(in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	157.8	$	154.2		$	312.0	$	314.3

3328

DD&A expense ~~decreased six~~increased two percent sequentially and ~~20 percent~~remained flat YTD 2022-over-YTD 2021. The sequential quarterly decrease was primarily driven by a five percent decrease in net equivalent production volumes, and the YTD 2022-over-YTD 2021 decrease was driven by increased estimated proved reserves at year-end 2021 and increased activity in our Austin Chalk program, which has lower DD&A rates compared with our Midland Basin assets.2023-over-YTD 2022. Please refer to Overview of Selected Production and Financial Information, Including Trends above for ~~additional~~ discussion of DD&A expense on a per BOE basis.

Exploration

For the Three Months Ended For the Nine Months Ended
September 30, 2022 June 30,
2022 September 30, 2022 September 30, 2021
(in millions)
Geological, geophysical, and other expenses $ 6.8 $ 13.7 $ 21.8 $ 5.3
Overhead 7.4 7.2 22.3 21.4
Total $ 14.2 $ 20.9 $ 44.1 $ 26.7

~~Note: Prior periods have been adjusted to conform to the current period presentation.~~


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		March 31, 2023			June 30, 2023		June 30, 2022

	(in millions)
Geological, geophysical, and other expenses	$	7.4	$	10.6		$	18.0	$	15.0
Overhead	7.6		7.8			15.4		14.9
Total	$	15.0	$	18.4		$	33.4	$	29.9

Exploration expense decreased 3219 percent sequentially and increased 6512 percent YTD ~~2022-over-YTD 2021, as~~2023-over-YTD 2022. The sequential quarterly decrease was primarily a result of unsuccessful exploration ~~efforts outside of our core areas of operations~~activity related to one well that experienced technical issues during the drilling phase, which ~~primarily impacted~~affected the three months ended ~~June 30, 2022.~~March 31, 2023. The YTD 2023-over-YTD 2022 increase was primarily due to an increase in geological and geophysical expense. Exploration expense fluctuates based on actual geological and geophysical studies we perform within an exploratory area, exploratory dry hole expense incurred, and changes in the amount of allocated overhead.

~~Impairment~~General and administrative

For the Three Months Ended For the Nine Months Ended
September 30, 2022 June 30,
2022 September 30, 2022 September 30, 2021
(in millions)
Impairment $ 1.1 $ 4.4 $ 6.5 $ 26.3


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		March 31, 2023			June 30, 2023		June 30, 2022

	(in millions)
General and administrative	$	27.5	$	27.7		$	55.2	$	53.3

~~Impairment~~G&A expense ~~recorded during~~remained flat sequentially and increased four percent YTD 2023-over-YTD 2022. The YTD 2023-over-YTD 2022 increase was primarily a result of increased compensation expense. We currently expect G&A expense to increase on an absolute basis for the periods presented consists entirely of unproved property abandonments and impairments 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. Impairment expense decreased YTD 2022-over-YTD 2021,full-year 2023 compared with 2022, primarily as a result of ~~fewer actual and anticipated lease expirations and title defects.~~

~~We expect proved property impairments to occur more frequently~~expected increases 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 title 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.

Future impairments of proved and unproved properties are difficult to predict; however, based on our commodity price assumptions as of October 27, 2022, we do not expect any material oil and gas property impairments in the fourth quarter of 2022 resulting from commodity price impacts. We expect abandonment and impairment expense related to unproved properties to decrease for the full-year 2022, compared with 2021.

~~General and administrative~~

For the Three Months Ended For the Nine Months Ended
September 30, 2022 June 30,
2022 September 30, 2022 September 30, 2021
(in millions)
General and administrative $ 28.4 $ 28.3 $ 81.7 $ 74.9

~~G&A expense increased nine percent YTD 2022-over-YTD 2021 as a result of increased~~ compensation expense. Please refer to the section Overview of Selected Production and Financial Information, Including Trends above for ~~additional~~ discussion of G&A expense on a per BOE basis.

Net derivative (gain) loss

For the Three Months Ended For the Nine Months Ended
September 30, 2022 June 30,
2022 September 30, 2022 September 30, 2021
(in millions)
Net derivative (gain) loss $ (137.6) $ 104.2 $ 385.2 $ 924.2


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		March 31, 2023			June 30, 2023		June 30, 2022

	(in millions)
Net derivative (gain) loss	$	(11.7)	$	(51.3)		$	(63.0)	$	522.8

Net derivative (gain) loss is a result of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. The net derivative ~~gain for the three months ended September 30, 2022, resulted from decreases in oil and NGL benchmark prices. The net derivative losses~~gains for the three months ended June 30, ~~2022,~~2023, and March 31, 2023, and for the ~~nine~~six months ended ~~September~~June 30, 2023, resulted from decreases in benchmark commodity prices during those periods. The net derivative loss for the six months ended June 30, 2022, ~~and 2021,~~ resulted from increases in benchmark commodity prices. Please refer to Note 107 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.

~~Other operating~~Interest expense ~~net~~

For the Three Months Ended For the Nine Months Ended
September 30, 2022 June 30,
2022 September 30, 2022 September 30, 2021
(in millions)
Other operating expense, net $ 1.2 $ 1.1 $ 2.6 $ 44.7

~~Other operating expense, net, recorded during the third quarter of 2021 related to legal settlements, including the settlement of the SPM NAM LLC et al. case. Please refer to~~ ~~Legal Proceedings~~ ~~in Part I, Item 3 of our~~ ~~2021~~ ~~Form 10-K~~ ~~for additional discussion.~~


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		March 31, 2023			June 30, 2023		June 30, 2022

	(in millions)
Interest expense	$	(22.1)	$	(22.5)		$	(44.6)	$	(74.9)

Interest expense

For the Three Months Ended For the Nine Months Ended
September 30, 2022 June 30,
2022 September 30, 2022 September 30, 2021
(in millions)
Interest expense $ (22.8) $ (35.5) $ (97.7) $ (120.3)

~~Interest expense decreased 36 percent~~ remained flat sequentially and 19decreased 40 percent YTD ~~2022-over-YTD 2021~~2023-over-YTD 2022 as a result of the reduction in the aggregate principal amount of our Senior Notes through various transactions in ~~2021 and~~ 2022, including the redemption of our 2024 Senior Notes on February 14, 2022, and the redemption of our 2025 Senior Secured Notes on June 17, 2022. As a result of these transactions, we expect interest expense to decrease for the full-year ~~2022,~~2023, compared with ~~2021.~~2022. Total interest expense 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.

Loss on extinguishment of debt

For the Three Months Ended For the Nine Months Ended
September 30, 2022 June 30,
2022 September 30, 2022 September 30, 2021
(in millions)
Loss on extinguishment of debt $ — $ (67.2) $ (67.6) $ (2.1)


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		March 31, 2023			June 30, 2023		June 30, 2022

	(in millions)
Loss on extinguishment of debt	$	—	$	—		$	—	$	(67.6)

The redemption of our 2025 Senior Secured Notes on June 17, 2022, resulted in a net loss on extinguishment of debt of $67.2 million for the six months ended June 30, 2022, which included $33.5 million of premium paid, $26.3 million of accelerated expense recognition of the remaining unamortized debt discount, and $7.4 million of accelerated expense recognition of the remaining unamortized deferred financing costs.

Income tax expense


	For the Three Months Ended						For the Six Months Ended
	June 30, 2023			March 31, 2023				June 30, 2023			June 30, 2022

	(in millions, except tax rate)
Income tax expense	$	(42.1)		$	(55.5)			$	(97.6)		$	(99.6)
Effective tax rate	21.9		%	21.8		%		21.9		%	21.1		%

~~The Tender Offer~~Our effective tax rate remained flat sequentially and increased YTD 2023-over-YTD 2022 ~~Senior Notes Redemption completed~~primarily due to a benefit recognized from the release of the valuation allowance 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 $0.6 million of net premiums paid during the ninesix months ended ~~September~~June 30, ~~2021. Please refer to~~ ~~Note 5 - Long-Term Debt~~ ~~in Part I, Item 1 of this report for additional discussion of these transactions.~~

~~Income tax (expense) benefit~~

For the Three Months Ended For the Nine Months Ended
September 30, 2022 June 30,
2022 September 30, 2022 September 30, 2021
(in millions, except tax rate)
Income tax (expense) benefit $ (119.4) $ (86.7) $ (219.0) $ 0.1
Effective tax rate 19.9 % 21.1 % 20.4 % — %

~~The sequential quarterly decrease in~~2022, that lowered the effective tax rate ~~is primarily due~~compared to no valuation benefit recognized during the effect of recorded discrete adjustments related to excess tax benefits from stock-based compensation awards which were partially offset by discrete adjustments related to compensation limits for certain covered individuals. Additionally, as a result of commodity price increases during 2022, compared with 2021, and cumulative financial statement income exceeding cumulative financial statement losses over the prior three years, we anticipate that the valuation allowance recorded against the derivative deferred tax asset as of September 30, 2022, will be reversed at year-end 2022. The effect of this anticipated reversal is included in the effective tax rate for the three and ninesix months ended ~~September~~June 30, ~~2022.~~

The YTD 2022-over-YTD 2021 increase in the effective tax rate was primarily due to the effect of higher forecast income for the year ended December 31, 2022, compared with the amount of forecast net income for the full-year 2021 as of September 30, 2021.

2023. The tax rates for each period presented reflect the ~~effect of valuation allowance adjustments, the~~ proportional effects of ~~excess tax benefits from stock-based compensation awards, and~~state income taxes, limits on expensing of certain covered individual’s ~~compensation.~~compensation, and the cumulative effect of other small differences. Based on current projections, we estimate that between ~~six~~two percent and ~~eight~~six percent of full-year ~~2022~~2023 income tax expense will be ~~current. During~~current, however, this could be impacted by the ~~nine months ended September 30, 2022, we~~R&D credit study as further discussed in Note 4 - Income Taxes in Part I, Item 1 of this report.

We made ~~estimated federal income~~$6.1 million of cash tax payments during the second quarter of ~~$10.0 million.~~2023, primarily related to Texas franchise taxes.

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 material ~~impact~~effect on our effective tax rate and current tax expense. ~~The enactment~~Please refer to the Risk Factors section in Part 1, Item 1A of ~~the Inflation Reduction Act on August 16,~~ our 2022 ~~is currently not expected to have a material effect on our consolidated financial statements.~~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 execute our business plan while continuing to meet our current financial 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.

Sources of Cash

For the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, our capital expenditures, return of capital program, ~~was~~and asset acquisitions were funded with cash flows from operating activities and cash on hand, and we expect that to continue for the remainder of 2022. As of September 30, 2022, our cash and cash equivalents balance was $498.4 million, which was an increase of $231.3 million from our cash and cash equivalents balance as of June 30, 2022. Although we expect cash flows from operations to be sufficient to fund our expected 2022 capital program,2023. However, we may also use borrowings under our revolving credit facility or 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 certain existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs.

Our credit ratings affect the availability of, and cost for us to borrow, additional funds. Two major credit rating agencies upgraded our credit rating during the second quarter of 2023, citing our ability to consistently generate meaningful cash flows, disciplined capital spending, return of capital to stockholders, debt redemptions during 2022, and sustained strong operational performance, including our established inventory of drilling locations in our primary plays, all of which contribute to our strong liquidity

profile. 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, interest rate changes, tax law changes, and volumes produced, all of which affect us and our industry.

Our credit ratings affect the availability of and cost for us to borrow additional funds. Three major credit rating agencies have upgraded our credit ratings during 2022, reflecting our top-tier assets and operational performance, the redemption of our 2024 Senior Notes, and our strong liquidity profile, among other factors. Most recently, one major credit rating agency upgraded our credit rating upon our announcement of the Stock Repurchase Program in September 2022, citing our strong operational performance, ability to consistently generate cash flows with proceeds used to reduce gross debt, strong liquidity profile, and our use of financial derivative instruments as part of our financial risk management program. The credit rating agencies have also cited our priorities of improving our leverage metrics and continuing to reduce total debt, which we have achieved through the redemption of our 2025 Senior Secured Notes, and our expected ability to generate meaningful cash flows, among other reasons for the rating upgrades.

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 commodity derivative contracts as part of our commodity price risk management program. Commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise substantially over the price established by the commodity derivative contract. Please refer to Note 107 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information about our ~~oil, gas, and NGL~~commodity derivative contracts currently in place and the timing of settlement of those contracts.

Credit Agreement

~~On August 2, 2022, we entered into the~~Our Credit Agreement ~~which~~ provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 ~~billion, an initial borrowing base of $2.5 billion, and initial aggregate lender commitments totaling $1.25~~ billion. As of ~~September~~June 30, ~~2022,~~2023, the borrowing base and aggregate lender commitments under ~~the~~our Credit Agreement ~~remained unchanged.~~were $2.5 billion and $1.25 billion, respectively. The borrowing base is subject to regular, semi-annual redetermination, which considers the value of both our proved oil and gas properties reflected in our most recent reserve report and commodity derivative contracts, each as determined by our lender group. The next scheduled borrowing base redetermination date is October 1, 2023. No individual bank participating in the Credit Agreement represents more than 10 percent of the aggregate lender commitment. We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement. We were in compliance with all financial and non-financial covenants under the Credit Agreement as of ~~September~~June 30, ~~2022,~~2023, and through the filing of this report. 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 the Credit Agreement as of ~~October 27, 2022, September~~July 21, 2023, June 30, ~~2022,~~2023, and December 31, ~~2021.~~2022.

We had no revolving credit facility borrowings during the ~~nine~~six months ended ~~September~~June 30, 2023, and 2022. ~~Our daily weighted-average revolving credit facility debt balance for the nine months ended September 30, 2021, was $134.6 million.~~ Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, debt redemptions, repayment of scheduled debt maturities, and our capital expenditures, including acquisitions, all impact the amount we borrow under our revolving credit facility.

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, ~~and~~ the non-cash amortization of deferred financing ~~costs. Our weighted-average interest rate was impacted by~~costs, and for the periods during which the 2025 Senior Secured Notes were outstanding, the non-cash amortization of the ~~discount~~ related ~~to our 2025 Senior Secured Notes and our 2021 Senior Secured Convertible Notes for the periods during which they were outstanding.~~discount. Our weighted-average borrowing rate includes paid and accrued interest only.

The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the periods presented:


		For the Three Months Ended				For the Nine Months Ended					For the Three Months Ended				For the Six Months Ended
		September 30, 2022		June 30, 2022		September 30, 2022		September 30, 2021			June 30, 2023		March 31, 2023		June 30, 2023		June 30, 2022
Weighted-average interest rate	Weighted-average interest rate	7.0	%	8.1	%	7.8	%	7.7	%	Weighted-average interest rate	7.1	%	7.2	%	7.1	%	8.2	%
Weighted-average borrowing rate	Weighted-average borrowing rate	6.4	%	7.1	%	7.0	%	6.7	%	Weighted-average borrowing rate	6.4	%	6.5	%	6.5	%	7.2	%

Our weighted-average interest ~~rates~~rate and our weighted-average borrowing ~~rates~~rate each remained flat sequentially, and decreased ~~sequentially,~~YTD 2023-over-YTD 2022, primarily due to the redemption of ~~the~~our 2024 Senior Notes and 2025 Senior Secured Notes ~~on June 17,~~during 2022. WeAs a result of these redemptions, we expect our weighted-average interest ~~rates~~rate and weighted-average borrowing ~~rates~~rate to decrease for the full-year ~~2022~~2023 compared with ~~2021, primarily as a result of the redemption of our 2025 Senior Secured Notes.~~2022.

Our weighted-average interest rate and weighted-average borrowing rate are ~~impacted~~affected by the occurrence and 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~~affected by the fees paid on the unused portion of our aggregate lender commitments. The rates disclosed in the above table do not reflect certain amounts associated with the repurchase or redemption of Senior Notes, such as the acceleration of unamortized deferred financing costs and unamortized discounts, as these amounts are netted against the associated gain or loss on extinguishment of debt. The ~~2021 Senior Secured Convertible Notes were retired upon maturity on July 1, 2021, the~~ 2024 Senior Notes were redeemed on February 14, 2022, and the 2025 Senior Secured Notes were redeemed on June 17, 2022. After these dates, the weighted-average interest rate was no longer ~~impacted~~affected by the non-cash amortization of deferred financing costs or, for the ~~2021 Senior Secured Convertible Notes and the~~ 2025 Senior Secured Notes, the non-cash amortization of the ~~discounts.~~discount.

Uses of Cash

We use cash for the development, exploration, and acquisition of oil and gas properties; for the payment of operating and general and administrative costs, income taxes, dividends, ~~and~~ debt obligations, including ~~interest;~~interest and early repayments or redemptions; and for repurchases of shares of our common stock under the Stock Repurchase Program. 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, ~~2022,~~2023, we spent approximately ~~$591.8~~$638.9 million on capital ~~expenditures.~~expenditures and on acquiring proved and unproved oil and gas properties. This amount differs from the costs incurred amount of ~~$677.4~~$682.6 million for the ~~nine~~six months ended

~~September~~ June 30, ~~2022,~~2023, 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, inflation, and the number and size of acquisitions that we complete. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, tax law and other regulatory 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. Our ~~2022~~total 2023 capital program, which we expect to fund with cash flows from operations, is expected to be ~~between $870.0~~approximately $1.05 billion, excluding acquisitions. This reflects a decrease of $50.0 million, ~~and $900.0 million. We will continue~~as compared to ~~monitor the economic environment through the remainder~~our original expectation, primarily as a result of ~~the year and adjust our activity level as warranted.~~lower-than-expected costs.

We may from time to time repurchase shares of our common stock, or 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 redemptions may be made in open market transactions, privately negotiated transactions, tender offers, pursuant to contractual provisions, or otherwise. Any such repurchases or redemptions will depend on our business strategy, prevailing market conditions, our liquidity requirements, contractual restrictions or covenants, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material.

On September 7, 2022, we announced that our Board of Directors approved the Stock Repurchase Program authorizing us to repurchase up to $500.0 million in aggregate value of our common stock through December 31, 2024. We intend to fund repurchases from available working capital and cash provided by operating activities. Stock repurchases may also be funded with borrowings under the Credit Agreement. The timing, as well as the number and value of our shares repurchased under the Stock Repurchase Program, will be determined by certain authorized officers of the Company at their discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. During the three and six months ended ~~September~~June 30, ~~2022,~~2023, we repurchased and subsequently retired ~~452,734~~2,550,706 and 3,964,464 shares, respectively, of our common stock at a cost of ~~$20.2~~$68.7 million and as$108.8 million, respectively, excluding excise taxes, commissions, and fees. As of ~~September~~June 30, ~~2022, $479.8~~2023, $334.0 million remained available under the Stock Repurchase Program for repurchases of our common stock. Please refer to Note 3 - Equity in Part I, Item 1 of this report for additional discussion. ~~The Stock Repurchase Program terminates and supersedes the August 1998 authorization to repurchase common stock, under which 3,072,184 shares remained available for repurchase prior to termination.~~

On February 14, 2022, we redeemed all of the $104.8 million of aggregate principal amount outstanding of our 2024 Senior Notes, ~~at a redemption price equal to 100 percent of the principal amount of the 2024 Senior Notes~~and on ~~the date of redemption, plus accrued and unpaid interest. On~~ June 17, 2022, we redeemed all of the $446.7 million of aggregate principal amount outstanding of our 2025 Senior Secured Notes. All redeemed 2024 Senior Notes ~~at a redemption price equal to 107.5 percent of the principal amount of the~~and 2025 Senior Secured Notes on the date of the redemption. We paid total consideration of $480.2 million, including premium, and paid $18.9 million of accrued interest related to the 2025 Senior Secured Notes. During the second quarter of 2021, we issued our 2028 Senior Notes and used the net cash proceeds of $392.8 million 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 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 Senior Notes and 2024 Senior Notes. The 2021 Senior Secured Convertible Notes matured on July 1, 2021, and on that day, we used borrowings under our revolving credit facility to retire at par the outstanding principal amount of $65.5 million.were canceled upon settlement. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. ~~These transactions were completed as part of our strategy for 2022 to reduce absolute debt and improve our leverage metrics.~~

Analysis of Cash Flow Changes Between the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2022,~~2023, and ~~2021~~2022

The following tables present changes in cash flows between the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, and ~~2021,~~2022, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying 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
2022 2021
(in millions)
Net cash provided by operating activities $ 1,398.0 $ 730.1 $ 667.9


	For the Six Months Ended June 30,				Amount Change Between Periods
	2023		2022

	(in millions)
Net cash provided by operating activities	$	714.9	$	884.7	$	(169.8)

Net cash provided by operating activities ~~increased~~decreased for the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, compared with the same period in ~~2021,~~2022, primarily ~~due to~~as a ~~$985.3~~result of a $583.5 million ~~increase~~decrease in cash received from oil, gas, and NGL production ~~revenues,~~revenue net of transportation costs and production taxes and an increase of $38.5 million in cash paid for LOE and ad valorem taxes, partially offset by a ~~$218.8~~$397.3 million ~~increase~~decrease in cash paid on settled derivative trades, ~~and an increase~~a $45.6 million decrease in cash paid for ~~LOE, ad valorem taxes,~~interest, and a $19.0 million decrease in cash paid for G&A ~~expense of $50.8 million.~~expense. 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
2022 2021
(in millions)
Net cash used in investing activities $ (592.4) $ (544.8) $ (47.6)


	For the Six Months Ended June 30,				Amount Change Between Periods
	2023		2022

	(in millions)
Net cash used in investing activities	$	(638.2)	$	(365.7)	$	(272.5)

Net cash used in investing activities increased for the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, compared with the same period in ~~2021, primarily due to increased~~2022, as a result of a $184.3 million increase in capital expenditures and $88.8 million of ~~$41.6 million.~~cash paid to acquire proved and unproved oil

and gas properties in the Midland Basin. Please refer to Note 11 - Acquisitions in Part I, Item 1 of this report for additional discussion of acquisition activity.

Financing activities

For the Nine Months Ended September 30, Amount Change Between Periods
2022 2021
(in millions)
Net cash used in financing activities $ (639.9) $ (155.6) $ (484.3)


	For the Six Months Ended June 30,				Amount Change Between Periods
	2023		2022

	(in millions)
Net cash used in financing activities	$	(143.4)	$	(584.5)	$	441.1

Net cash used in financing activities for the ~~nine~~six months ended ~~September~~June 30, 2023, related to $108.9 million of cash paid, including commissions and fees, to repurchase and subsequently retire 3,964,464 shares of our common stock under the Stock Repurchase Program and $36.4 million of dividends paid.

Net cash used in financing activities for the six months ended June 30, 2022, related to $480.2 million of cash paid, including premium, to redeem our 2025 Senior Secured Notes, and $104.8 million of cash paid to redeem our 2024 Senior Notes. These redemptions were made using cash on hand. Additionally, we paid $25.1 million for the net share settlement of employee and director stock awards and $20.2 million to repurchase and subsequently retire 452,734 shares of our common stock under the Stock Repurchase Program.

Net cash used in financing activities for the nine months ended September 30, 2021, related to net repayments under our revolving credit facility of $93.0 million and $65.5 million of cash paid to retire our 2021 Senior Secured Convertible Notes. Additionally, we paid $385.3 million of net cash, including net premiums, to fund the Tender Offer and the 2022 Senior Notes Redemption, and we received net cash proceeds of $392.8 million from the issuance of our 2028 Senior Notes.

Interest Rate Risk

We are exposed to market and credit risk due to the floating interest rate associated with any outstanding 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~~affect 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~~affect future results of operations and cash flows. Changes in interest rates do not ~~impact~~affect the amount of interest we pay on our fixed-rate Senior Notes, but can ~~impact~~affect their fair values. As of ~~September~~June 30, ~~2022,~~2023, our outstanding principal amount of fixed-rate debt totaled $1.6 billion and we had no floating-rate debt outstanding. Please refer to Note 8 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair values of our Senior Notes.

The Federal Reserve has continued to increase short-term interest rates in 2023. These increases, and any future increases, could affect the cost and our ability to borrow funds.

Commodity Price Risk

The prices we receive for our oil, gas, and NGL production directly ~~impact~~affect our revenue, profitability, access to capital, ability to execute our Stock Repurchase Program and pay dividends, and future rate of growth. Oil, gas, and NGL prices are subject to unpredictable fluctuations resulting from a variety of factors that are typically beyond our control, including changes in supply and demand associated with the broader macroeconomic environment, constraints on gathering systems, processing facilities, pipelines, and other transportation systems, and weather-related events. The markets for oil, gas, and NGLs have been volatile, especially over the last decade, and remain subject to ~~heightened~~high levels of uncertainty and volatility related to ~~(a)~~production output from OPEC+, the ongoing conflict between Russia and Ukraine ~~(b)~~and the associated economic and trade sanctions, ~~that certain countries have imposed on Russia, (c) production output from OPEC+,~~ and the ~~associated~~ potential impacts of these issues on global commodity and financial markets. These ~~issues~~circumstances have contributed to inflation, instances of supply chain disruptions, and a rise in interest rates, and could have further industry-specific impacts ~~which~~that may require us to adjust our business plan. 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, ~~2022,~~2023, 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~~revenue by approximately ~~$180.0~~$84.4 million, ~~$64.6~~$16.3 million, and ~~$23.0~~$11.0 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, would have offset the declines in oil, gas, and NGL production revenue by approximately ~~$128.2~~$27.0 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, ~~2022,~~2023, 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 ~~$79.2~~$38.6 million, ~~$10.3~~$8.3 million, and ~~$1.0~~$0.9 million, respectively.

Off-Balance Sheet Arrangements

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”~~SPE”), 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, ~~2022,~~2023, 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 ~~2021~~2022 Form 10-K for discussion of our accounting ~~policies and~~ estimates.

Accounting Matters

Please refer to Note 1 - Summary of Significant Accounting Policies in Part I, Item 1 of this report for information on new authoritative accounting guidance.

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 ~~Part I, Item 1 of this report.~~the 2022 Form 10-K. 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)~~ (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						For the Six Months Ended
		2022		2021		2022			2021			June 30, 2023			June 30, 2022		June 30, 2023		June 30, 2022

		(in thousands)
Net income (loss) (GAAP)		$	481,240	$	85,593	$	853,489		$	(388,671)

												(in thousands)
Net income (GAAP)											Net income (GAAP)	$	149,874		$	323,485	$	348,426	$	372,249
Interest expense	Interest expense	22,825		40,861		97,708			120,268		Interest expense	22,148			35,496		44,607		74,883
Income tax expense (benefit)		119,379		(39)		218,951			(95)
Interest income (1)											Interest income (1)	(4,994)			(496)		(9,696)		(534)
Income tax expense											Income tax expense	42,092			86,711		97,598		99,572
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	Depletion, depreciation, amortization, and asset retirement obligation liability accretion	145,865		202,701		460,169			574,375		Depletion, depreciation, amortization, and asset retirement obligation liability accretion	157,832			154,823		312,021		314,304
Exploration (1)		13,203		7,801		41,152			23,742
Impairment		1,077		8,750		6,466			26,250
Exploration (2)											Exploration (2)	14,064			19,894		31,541		27,949

Stock-based compensation expense	Stock-based compensation expense	5,105		4,498		13,858			14,191		Stock-based compensation expense	4,163			4,479		8,481		8,753
Net derivative (gain) loss	Net derivative (gain) loss	(137,577)		209,146		385,180			924,183		Net derivative (gain) loss	(11,674)			104,236		(63,003)		522,757
Derivative settlement loss		(186,299)		(213,555)		(595,080)			(480,262)
Derivative settlement gain (loss)											Derivative settlement gain (loss)	15,636			(240,598)		20,712		(408,781)

(Gain) loss on extinguishment of debt		—		(5)		67,605			2,139
Loss on extinguishment of debt											Loss on extinguishment of debt	—			67,226		—		67,605
Other, net	Other, net	(4,663)		905		(5,064)			2,407		Other, net	1,079			4,459		927		5,522
Adjusted EBITDAX (non-GAAP)	Adjusted EBITDAX (non-GAAP)	460,155		346,656		1,544,434			818,527		Adjusted EBITDAX (non-GAAP)	390,220			559,715		791,614		1,084,279
Interest expense	Interest expense	(22,825)		(40,861)		(97,708)			(120,268)		Interest expense	(22,148)			(35,496)		(44,607)		(74,883)
Income tax (expense) benefit		(119,379)		39		(218,951)			95
Exploration (1)(2)		(11,993)		(7,801)		(27,959)			(23,742)
Interest income (1)											Interest income (1)	4,994			496		9,696		534
Income tax expense											Income tax expense	(42,092)			(86,711)		(97,598)		(99,572)
Exploration (2)(3)											Exploration (2)(3)	(14,473)			(7,911)		(22,654)		(15,966)
Amortization of debt discount and deferred financing costs	Amortization of debt discount and deferred financing costs	1,303		3,905		8,910			13,350		Amortization of debt discount and deferred financing costs	1,372			3,597		2,743		7,607
Deferred income taxes	Deferred income taxes	110,048		(68)		202,996			(282)		Deferred income taxes	44,278			81,000		94,246		92,948
Other, net	Other, net	(457)		5,171		(461)			(9,708)		Other, net	(680)			(335)		(14,119)		(538)
Net change in working capital	Net change in working capital	96,518		21,078		(13,230)			52,170		Net change in working capital	21,780			28,214		(4,436)		(109,748)
Net cash provided by operating activities (GAAP)	Net cash provided by operating activities (GAAP)	$	513,370	$	328,119	$	1,398,031		$	730,142	Net cash provided by operating activities (GAAP)	$	383,251		$	542,569	$	714,885	$	884,661

(1) Interest income is included within the other non-operating income (expense), net line item on the accompanying statements of operations.

(2) 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.

~~(2)~~(3) For the three and ~~nine~~six months ended ~~September~~June 30, 2023, amounts exclude certain capital expenditures related to unsuccessful exploration activity for one well that experienced technical issues during the drilling phase. For the three and six months ended June 30, 2022, amounts ~~are net of~~exclude certain capital expenditures related to unsuccessful exploration efforts outside of our core areas of ~~operations.~~operation.

4135

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 107 - 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 ~~2021~~2022 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~~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 ~~2022~~2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

4236

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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 likely to have a materially adverse effect upon our financial condition, results of operations, or cash flows.

ITEM 1A. RISK FACTORS

Global geopolitical tensions, specifically including the ongoing conflict between Russia and Ukraine, may create heightened volatility in oil, gas, and NGL prices and could adversely affect our business, financial condition and results of operations.

On February 24, 2022, Russian military forces commenced a military operation in Ukraine and the sustained conflict and disruption in the region that has occurred since this date is expected to continue. Although the length, impact, and outcome of the ongoing military conflict in Ukraine is highly unpredictable, this conflict could lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability, changes in consumer or purchaser preferences, as well as increases in cyberattacks and espionage.

While it is not possible at this time to predict or determine the ultimate consequences of the conflict in Ukraine, which could include, among other things, additional sanctions, greater regional instability, embargoes, geopolitical shifts and other material and adverse effects on macroeconomic conditions, supply chains, financial markets, and hydrocarbon price volatility in particular is likely to continue for the foreseeable future. To the extent negotiations of a cease fire between Russia and Ukraine are unsuccessful, the potential destruction of critical oil-related infrastructure in Ukraine, and the implementation of further sanctions and other measures taken by governmental bodies and private actors, could have a lasting impact in the short- and long-term on the operations and financial condition of our business and the global economy.

There have been no other material changes to the risk factors as previously disclosed in our ~~2021~~2022 Form 10-K.

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

The following table provides information about purchases made by us and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the three months ended ~~September~~June 30, ~~2022,~~2023, 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:


PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASES	PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASES							PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASES
Period	Period	Total Number of Shares Purchased (1)	Weighted Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program (2)	Maximum Number or Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (as of period end date) (2)(3)		Period	Total Number of Shares Purchased (1)	Weighted Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program (2)	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (as of period end date) (2)
07/01/2022 - 07/31/2022		283,800	$	34.19	—	3,072,184
08/01/2022 - 08/31/2022		—	$	—	—	3,072,184
09/01/2022 - 09/30/2022		802,221	$	44.42	452,734	$	479,767,724
04/01/2023 - 04/30/2023								04/01/2023 - 04/30/2023	270	$	26.21	—	$	402,780,476
05/01/2023 - 05/31/2023								05/01/2023 - 05/31/2023	1,947,246	$	26.49	1,947,246	$	351,203,216
06/01/2023 - 06/30/2023								06/01/2023 - 06/30/2023	603,460	$	28.45	603,460	$	334,036,922
Total:	Total:	1,086,021	$	41.75	452,734			Total:	2,550,976	$	26.95	2,550,706

(1) ~~633,287~~270 shares purchased by us in the ~~third~~second quarter of ~~2022~~2023 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) OnIn September 7, 2022, ~~we announced that~~ our Board of Directors approved the Stock Repurchase Program authorizing us to repurchase up to $500.0 million in aggregate value of our common stock through December 31, 2024. The Stock Repurchase Program permits us to repurchase our shares from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws and subject to certain provisions of our Credit Agreement and the indentures governing our Senior Notes. We intend to ~~fund repurchases from available working capital and~~utilize net cash provided by operating ~~activities.~~activities to repurchase shares of our common stock. Stock repurchases may also be ~~funded~~made with borrowings under our Credit Agreement. The timing, as well as the number and value of shares repurchased under the Stock Repurchase Program, will be determined by certain authorized officers of the Company at their discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. The value of shares authorized for repurchase by our Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the Stock Repurchase Program may be suspended, modified, or discontinued at any time without prior notice. No assurance can be given that any particular number or dollar value of our shares will be repurchased. During the three months ended ~~September~~June 30, ~~2022,~~2023, we repurchased and subsequently retired ~~452,734~~2,550,706 shares of our common stock under the Stock Repurchase Program at a weighted-average share price of ~~$44.69~~$26.95 for a total cost of ~~$20.2~~$68.7 million, excluding excise taxes, commissions, and fees.

~~(3)~~ ~~The Stock Repurchase Program terminates and supersedes the August 1998 authorization to repurchase common stock, under which 3,072,184 shares remained available for repurchase prior to termination.~~

Our payment of cash dividends to our stockholders isand repurchases of our common stock are each 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 potential repurchases of our common stock or our payment of dividends at our current rate for the foreseeable future if any dividends are declared by our Board of Directors.

4437

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			Certificate of Amendment to Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010, dated May 25, 2023 (filed as Exhibit 3.1 to the registrant’s Current Report on Form 8-K filed on May 30, 2023, and incorporated herein by reference)
3.3			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)~~
~~10.1~~			Seventh Amended and Restated Credit Agreement dated as of August 2, 2022, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2022, and incorporated herein by reference)
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.

4538

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

~~November 4, 2022~~August 3, 2023	By:	/s/ HERBERT S. VOGEL
		Herbert S. Vogel
		President and Chief Executive Officer
		(Principal Executive Officer)

~~November 4, 2022~~August 3, 2023	By:	/s/ A. WADE PURSELL
		A. Wade Pursell
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

~~November 4, 2022~~August 3, 2023	By:	/s/ PATRICK A. LYTLE
		Patrick A. Lytle
		Vice President - Chief Accounting Officer and Controller
		(Principal Accounting Officer)

4639


	For the Nine Months Ended September 30,
	2022		2021
Cash flows from operating activities:
Net income (loss)	$	853,489	$	(388,671)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depletion, depreciation, amortization, and asset retirement obligation liability accretion	460,169		574,375

Impairment	6,466		26,250
Stock-based compensation expense	13,858		14,191
Net derivative loss	385,180		924,183
Derivative settlement loss	(595,080)		(480,262)
Amortization of debt discount and deferred financing costs	8,910		13,350
Loss on extinguishment of debt	67,605		2,139
Deferred income taxes	202,996		(282)
Other, net	7,668		(7,301)
Net change in working capital	(13,230)		52,170





Net cash provided by operating activities	1,398,031		730,142

Cash flows from investing activities:

Capital expenditures	(591,846)		(550,265)
Other, net	(596)		5,514
Net cash used in investing activities	(592,442)		(544,751)

Cash flows from financing activities:
Proceeds from revolving credit facility	—		1,649,500
Repayment of revolving credit facility	—		(1,742,500)
Net proceeds from Senior Notes	—		392,771
Cash paid to repurchase Senior Notes	(584,946)		(450,776)
Repurchase of common stock	(20,241)		—
Net proceeds from sale of common stock	1,645		1,315
Dividends paid	(1,218)		(1,178)
Other, net	(35,110)		(4,733)
Net cash used in financing activities	(639,870)		(155,601)

Net change in cash, cash equivalents, and restricted cash	165,719		29,790
Cash, cash equivalents, and restricted cash at beginning of period	332,716		10
Cash, cash equivalents, and restricted cash at end of period	$	498,435	$	29,800

Supplemental schedule of additional cash flow information and non-cash activities:
Operating activities:
Cash paid for interest, net of capitalized interest	$	(125,668)	$	(126,228)

Investing activities:
Increase in capital expenditure accruals and other	$	50,590	$	8,885
Non-cash financing activities (1)


Borrowing Base Utilization Percentage	<25%		≥25% <50%		≥50% <75%		≥75% <90%		≥90%
SOFR Loans	2.000	%	2.250	%	2.500	%	2.750	%	3.000	%
ABR Loans or Swingline Loans	1.000	%	1.250	%	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	464,483	$	12.80
Granted	276,010	$	26.67
Vested	(460,928)	$	12.80
Forfeited	(3,555)	$	12.80
Non-vested at end of quarter	276,010	$	26.67


	RSUs	Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year	1,841,237	$	13.79
Granted	526,776	$	34.08
Vested	(920,927)	$	12.17
Forfeited	(49,704)	$	16.62
Non-vested at end of quarter	1,397,382	$	22.41


	Contract Period
	Fourth Quarter 2022		2023		2024		2025
Oil Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
NYMEX WTI Volumes	1,923		1,190		—		—
Weighted-Average Contract Price	$	44.58	$	45.20	$	—	$	—
ICE Brent Volumes	—		3,650		910		—
Weighted-Average Contract Price	$	—	$	86.50	$	85.50	$	—
Collars
NYMEX WTI Volumes	1,128		1,331		919		—
Weighted-Average Floor Price	$	63.74	$	66.01	$	75.00	$	—
Weighted-Average Ceiling Price	$	75.48	$	80.79	$	81.47	$	—
Basis Swaps
WTI Midland-NYMEX WTI Volumes	2,462		3,613		—		—
Weighted-Average Contract Price	$	1.15	$	0.73	$	—	$	—
ICE Brent-NYMEX WTI Volumes	920		—		—		—
Weighted-Average Contract Price	$	(7.78)	$	—	$	—	$	—
WTI Houston MEH-NYMEX WTI Volumes	374		1,234		—		—
Weighted-Average Contract Price	$	1.25	$	1.52	$	—	$	—
Roll Differential Swaps
NYMEX WTI Volumes	3,248		4,968		—		—
Weighted-Average Contract Price	$	0.21	$	0.62	$	—	$	—

Gas Derivatives (volumes in BBtu and prices in $ per MMBtu):
Swaps
NYMEX HH Volumes	2,806		—		—		—
Weighted-Average Contract Price	$	5.50	$	—	$	—	$	—
IF HSC Volumes	6,982		—		—		—
Weighted-Average Contract Price	$	2.47	$	—	$	—	$	—
IF Waha Volumes	3,067		900		—		—
Weighted-Average Contract Price	$	2.22	$	3.98	$	—	$	—


Collars
NYMEX HH Volumes	1,908		24,170		—		—
Weighted-Average Floor Price	$	3.50	$	3.74	$	—	$	—
Weighted-Average Ceiling Price	$	4.44	$	6.32	$	—	$	—
IF HSC Volumes	—		5,085		—		—
Weighted-Average Floor Price	$	—	$	4.10	$	—	$	—
Weighted-Average Ceiling Price	$	—	$	5.63	$	—	$	—


	Contract Period (continued)
	Fourth Quarter 2022		2023		2024		2025
Basis Swaps




IF Waha-NYMEX HH Volumes	—		7,247		20,958		20,501
Weighted-Average Contract Price	$	—	$	(1.02)	$	(0.86)	$	(0.66)
IF HSC-NYMEX HH Volumes	—		9,582		—		—
Weighted-Average Contract Price	$	—	$	0.07	$	—	$	—

NGL Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
OPIS Propane Mont Belvieu Non-TET Volumes	113		—		—		—
Weighted-Average Contract Price	$	35.91	$	—	$	—	$	—


Collars
OPIS Propane Mont Belvieu Non-TET Volumes	173		—		—		—
Weighted-Average Floor Price	$	24.11	$	—	$	—	$	—
Weighted-Average Ceiling Price	$	28.13	$	—	$	—	$	—


	Net Equivalent Production Decrease	Production Revenue Decrease	Production Expense Increase (Decrease)
	(MBOE per day)	(in millions)	(in millions)
Midland Basin	(5.1)		$	(127.5)	$	(8.3)
South Texas	(3.7)		(35.3)		2.7
Total	(8.8)		$	(162.8)	$	(5.6)