sm-20240930

美国

证券交易委员会

华盛顿特区20549

表格10-Q

☑ 根据1934年证券交易法第13或15(d)条，本季度报告

截至季度结束日期的财务报告2024年9月30日

或者

☐ 根据1934年证券交易法第13或15(d)节的转型报告书

过渡期从___________到_____________

委员会文件号 001-31539

Sm ENERGY CO公司

(根据其章程规定的注册人准确名称)

特拉华州

41-0518430

（设立或组织的其他管辖区域）

（纳税人识别号码）

1700 林肯街, 3200套房, 丹佛, 科罗拉多州

80203

，（主要行政办公地址）

(邮政编码)

(303) 861-8140

(注册人电话号码，包括区号)

在法案第12(b)条的规定下注册的证券：


每一类的名称	交易标的	在其上注册的交易所的名称
普通股，每股面值$0.01	SM	请使用moomoo账号登录查看New York Stock Exchange

请在勾选标志处表示注册人是否（1）已经提交了《1934年证券交易法》第13或15（d）条要求提交的所有报告，(2）在过去90天内一直受到提交要求的影响。是 ☑ 没有☐

请在复选框上表示注册人是否在过去的12个月（或者在此前的更短时间内必须提交此类文件的注册人）电子提交了每个必须按照法规S-t（本章第232.405节的规定）提交的交互式数据文件。是 ☑否☐

请勾选是否注册人是大型加速报告人、加速报告人、非加速报告人、小型报告公司或新兴成长公司。请参考交易所法案120亿.2中“大型加速报告人”、“加速报告人”、“小型报告公司”和“新兴成长公司”的定义。

大型加速报告人

☑

加速文件提交人

☐

非加速报告人

☐

较小的报告公司

☐

新兴成长公司

☐

如果是新兴成长型公司，在选中复选标记的同时，如果公司已选择不使用根据证券交易法第13(a)条提供的任何新的或修订后的财务会计准则的延长过渡期来符合新的或修订后的财务会计准则，则表明该公司已选择不使用根据证券交易法第13(a)条提供的任何新的或修订后的财务会计准则的延长过渡期来符合新的或修订后的财务会计准则。☐

请通过复选标记表明注册人是否为壳公司（如《交易所法》规则120亿.2所定义）。是 ☐ 没有☑

请注明在最新适用日期时本发行人每种普通股的流通股数。

截至2024年10月24日，注册人拥有 114,418,413股普通股。


项目
	关于前瞻性声明的警示信息	3

	第一部分	4

项目1。	基本报表（未经审计）	4

	简明合并资产负债表九月 2024年9月30日及2023年12月31日	4

	简明的汇总操作表三个月及 N ine 和202 九月 2024年、2023年和2022年	5

	综合所得简化联合财务报表三个月及有九起类似诉讼针对JAVELIN的要约收购和合并被提起，称违反信托责任，寻求公正补偿，包括但不限于，禁止交易的达成、撤销、解除已经交易的事项，以及发送费用、补贴成本，包括合理的律师费和费用。唯一的佛罗里达州诉讼从未向被告送达，该案件于2017年1月20日自愿撤回并关闭。2016年4月25日，马里兰法院颁布了一项命令，将马里兰案件合并成一起诉讼，标题为JAVELIN Mortgage Investment Corp.股东诉讼（案号24-C-16-001542），并指定一个马里兰案件的律师作为临时首席联合法律顾问。2016年5月26日，临时首席律师提交了经修订的钒化铁质量投诉，声称违反信托责任的集体索赔，教唆和共谋违反信托责任以及浪费。2016年6月27日，被告提出了驳回合并修订集体投诉申请的动议，声称未陈述可以获得救济的规定。在2017年3月3日，听证会召开了驳回动议，法院保留了裁定。法院数次推迟动议陈述的裁定。2024年2月14日，法院颁布裁定，支持被告的驳回动议，并驳回所有原告的权利，无需上诉。在2024年3月11日，原告提出了对法院裁定的上诉通知。2024年7月3日，原告自愿撤回之前提出的上诉通知。和202 九月 2024年、2023年和2022年	6

	股东权益的简化合并报表连续季度演示已结束九月 2024年、2023年和2022年	7

	简明的综合现金流量表 N i 无和202 九月 2024年、2023年和2022年	9

	简明合并财务报表注释	11

事项二	分销计划	25

第3项。	有关市场风险的定量和定性披露	41

事项4。	控制和程序	41

	第二部分	42

项目1。	法律诉讼	42

项目1A。	风险因素	42

事项二	未注册的股票股权销售和筹款用途	42



项目6。	展示资料	43

	签名	44

关于前瞻性声明的注意事项

本第10-Q表格报告（“第10-Q表格”或“本报告”）包含根据1933年证券法修正案（“证券法”）第27A条和1934年证券交易法修正案（“交易所法”）第21E条的“前瞻性声明”。本报告中包含的所有陈述，除了历史事实陈述外，涉及我们的财务状况、经营业绩、业务前景或经济表现的活动、状况、事件或发展，我们预计、相信或预计将来或可能会发生的，或涉及管理层未来经营计划和目标的陈述，均属于前瞻性声明。"预计"，"假设"，"相信"，"预算"，"可能"，"估计"，"期望"，"预测"，"目标"，"打算"，"未决"，"计划"，"潜在"，"预期"，"寻求"，"目标"，"将" 等表示意图识别前瞻性声明的词语。前瞻性声明遍布本报告，内容涉及诸如：

•未来业务策略和其他计划以及目标，包括扩张和业务增长计划或延迟资本投资计划，未来股利支付、债务偿还或股票回购计划，资本市场活动，环保母基、社会和公司治理（"esg"）目标和倡议，以及我们对未来财务状况或经营业绩的展望；

•涉及Uinta Basin收购整合的风险，包括我们实现Uinta Basin收购预期收益的能力，或者由于Uinta Basin收购可能产生的任何业务中断；请参阅附注11 - 收购在此报告的第I部分，第1项中，讨论Uinta Basin收购的定义；

•我们对Uinta Basin收购的预期会计处理在本报告第一部分第一项中讨论；附注11 - 并购在本报告第一部分第一项中。

•未来资本支出的金额和性质，我们的资产对商品价格下降的抵抗力，以及用于资本支出的流动性和资本资源的可用性；

•我们对未来wti原油、天然气和天然气液体的价格走势，井钻成本、服务成本、生产成本和一般行政成本，以及通货膨胀对这些因素的影响的展望

•在石油和燃料币生产地区和运输通道发生武装冲突、政治不稳定或内乱，包括中东地区的不稳定、俄罗斯和乌克兰之间的战争和武装冲突，以及以色列与哈马斯、真主党、伊朗及其代理势力之间的冲突，以及相关潜在影响法律和法规、或实施经济或交易制裁（“战争与地缘政治不稳定”）；

•对借款基数、总体循环借款人承诺或到期日的任何更改，或对我们第七次修订和重签的信贷协议（以下简称“信贷协议”）的任何其他修订；

•现金流量、流动性、利息和相关债务偿付支出、我公司有效税率的变化，以及我们未来偿还债务的能力；

•我们的钻探和完工活动以及其他勘探和开发活动，每一项都可能受到供应链中断和通货膨胀的影响，包括我们、我们的联合开发伙伴和/或其他第三方运营商的计划。

•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;

•我们预期的未来产量、确定的钻井位置，以及钻探前景、存货、项目和计划；

•提议或最终联邦所得税法律和法规的变更，或者接触额外所得税责任；和

•其他类似事项，比如在本报告的第一部分第2条中讨论的那些分销计划在本报告的第一部分第2条中

我们的前瞻性陈述基于我们的经验以及我们对历史趋势、当前状况、预期未来发展以及我们认为在特定情况下适当的其他因素的看法所做的假设和分析。我们提醒您，前瞻性陈述并不能保证未来的表现，这些陈述受已知和未知的风险和不确定性的影响，这可能导致我们的实际业绩或业绩与前瞻性陈述所表达或暗示的任何未来业绩或业绩存在重大差异。可能导致我们的财务状况、经营业绩、业务前景或经济表现与预期不同的因素包括中讨论的因素风险因素我们的第一部分第 1A 项中的部分 10-K 表年度报告截至 2023 年 12 月 31 日的财年（”2023 年表格 10-K”)，以及展品 99.2 参见我们于 2024 年 7 月 18 日向美国证券交易委员会（“SEC”）提交的 8-k 表最新报告，以及我们随后向美国证券交易委员会提交的报告。

本报告中的前瞻性声明仅在本报告提交时有效。虽然我们可能会不时自愿更新我们先前的前瞻性声明，但除非适用证券法要求，否则我们对此没有任何承诺。

第一部分，财务信息。

项目1.基本报表

Sm ENERGY公司及其子公司

简化联合资产负债表（未经审计）

（以千为单位，除股票数据外）


	9月30日, 2024		2023年12月31日, 2023
资产
流动资产：
现金及现金等价物	$	1,735,313	$	616,164
应收账款	226,604		231,165
衍生资产	72,287		56,442
预付费用及其他	10,224		12,668
总流动资产	2,044,428		916,439
资产和设备（成功致力方法）：
已证明的石油和燃料币产权	12,501,494		11,477,358
累计折旧、递耗和摊销	(7,370,881)		(6,830,253)
未经证实的油气资产净额，减值准备后的$33,095 and $35,362，分别	287,311		335,620
正在进行的井	291,197		358,080

其他固定资产，减半数值折旧为 $62,435 and $59,669，分别	45,149		35,615
净房地产和设备总资产	5,754,270		5,376,420
非流动资产:
托管的收购存款	102,000		—
衍生资产	11,584		8,672
其他非流动资产	115,490		78,454
非流动资产总额	229,074		87,126
总资产	$	8,027,772	$	6,379,985
负债和股东权益
流动负债:
应付账款和应计费用	$	560,839	$	611,598

衍生负债	2,401		6,789
其他流动负债	17,859		15,425
总流动负债	581,099		633,812
(
循环信贷额度	—		—
优先票据，净收益	2,706,700		1,575,334


资产养老责任	125,327		118,774

净递延税负	467,459		369,903
衍生负债	448		1,273
其他非流动负债	85,193		65,039
非流动负债合计	3,385,127		2,130,323

合同和事项说明(注6)

股东权益:
普通股，每股面值为 $0.0001；0.01 11,454,512 200,000,000 25,300,372 114,418,413 和 115,745,393 股份分别为	1,144		1,157
追加实收资本	1,492,778		1,565,021
留存收益	2,570,108		2,052,279
累计其他综合损失	(2,484)		(2,607)
股东权益总额	4,061,546		3,615,850
总负债和股东权益	$	8,027,772	$	6,379,985

附带的说明是这些简明合并财务报表不可或缺的一部分。

Sm ENERGY公司及其子公司

未经审计的简明合并营运报表

(以千为单位，除每股数据外)


	截至三个月结束 9月30日,				截至九月三十日的九个月 9月30日,
	2024		2023		2024		2023
营业收入和其他收入：
石油、燃料币和天然气液体生产收入	$	642,380	$	639,699	$	1,835,427	$	1,757,032

其他营业收入，净额	1,233		1,202		2,611		8,128
总营业收入和其他收入	643,613		640,901		1,838,038		1,765,160
运营费用：
石油、燃料币和NGL生产费用	148,380		138,264		422,377		426,200
耗竭、折旧、摊销及资产养老义务负债增值	202,942		189,353		548,781		501,374
勘探	12,097		10,245		47,772		43,633

一般和行政	35,141		29,255		96,431		84,424
净衍生工具（收益）损失	(86,283)		75,355		(70,256)		12,352
其他营业费用，净额	384		2,832		4,206		20,182
总营业费用	312,661		445,304		1,049,311		1,088,165
营业利润	330,952		195,597		788,727		676,995
利息支出	(50,682)		(23,106)		(94,362)		(67,713)
利息收入	18,017		4,106		31,120		13,802

其他非经营性支出	(637)		(233)		(684)		(696)
税前收入	297,650		176,364		724,801		622,388
所得税（费用）收益	(57,127)		45,979		(142,786)		(51,619)
净利润	$	240,523	$	222,343	$	582,015	$	570,769

基本加权平均流通股数	114,405		117,823		114,870		119,589
摊薄加权平均普通股份流通量	114,993		118,328		115,701		120,165
每股基本净利润	$	2.10	$	1.89	$	5.07	$	4.77
每股稀释净利润	$	2.09	$	1.88	$	5.03	$	4.75
每普通股净分红派息声明	$	0.20	$	0.15	$	0.56	$	0.45

附带的说明是这些简明合并财务报表不可或缺的一部分。

Sm ENERGY公司及其子公司

简明合并综合收益表（未经审计）

(以千为单位)


	在结束的三个月中九月三十日				在截至的九个月中九月三十日
	2024		2023		2024		2023
净收入	$	240,523	$	222,343	$	582,015	$	570,769
扣除税款的其他综合收入：
养老金负债调整	108		14		123		40
扣除税款的其他综合收益总额	108		14		123		40
综合收入总额	$	240,631	$	222,357	$	582,138	$	570,809

附带的说明是这些简明合并财务报表不可或缺的一部分。

Sm ENERGY公司及其子公司

未经审计的凝聚的股东权益合并报表

(单位为千，除分享数据和每股分红派息外)


				股本溢价				累计其他全面收益亏损		股东权益合计
	普通股					留存收益
	股份	金额
2023年12月31日余额。	115,745,393	$	1,157	$	1,565,021	$	2,052,279	$	(2,607)	$	3,615,850
净利润	—	—		—		131,199		—		131,199
其他综合收益	—	—		—		—		8		8
已宣布的现金分红，$0.18 每股	—	—		—		(20,707)		—		(20,707)

根据限制性股票单位的归属发行普通股，扣除用于税款的股份	1,147	—		(22)		—		—		(22)
基于股票的薪酬费用	1,839	—		5,018		—		—		5,018

根据股票回购计划购买股份	(712,235)	(7)		(33,088)		—		—		(33,095)
2024年3月31日余额	115,036,144	$	1,150	$	1,536,929	$	2,162,771	$	(2,599)	$	3,698,251
净利润	—	—		—		210,293		—		210,293
其他综合收益	—	—		—		—		7		7
宣布的净现金分红，$0.18 每股	—	—		—		(20,532)		—		(20,532)
根据员工股票购买计划发行普通股	56,006	1		1,843		—		—		1,844

基于股票的薪酬费用	35,691	1		5,787		—		—		5,788

根据股票回购计划购买股票	(1,058,956)	(11)		(51,700)		—		—		(51,711)

2024年6月30日的余额	114,068,885	$	1,141	$	1,492,859	$	2,352,532	$	(2,592)	$	3,843,940
净利润	—	—		—		240,523		—		240,523
其他综合收益	—	—		—		—		108		108
已声明的净现金分红，$0.20 每股	—	—		—		(22,947)		—		(22,947)

员工股票期权归属时发行普通股，扣除用于缴税的股份	349,528	3		(6,819)		—		—		(6,816)
基于股票的薪酬费用	—	—		6,587		—		—		6,587
根据股票回购计划购买股份	—	—		151		—		—		151

2024年9月30日余额	114,418,413	$	1,144	$	1,492,778	$	2,570,108	$	(2,484)	$	4,061,546

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) (Continued)

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


				Additional Paid-in Capital				Accumulated Other Comprehensive Loss		Total Stockholders’ Equity
	Common Stock					Retained Earnings
	Shares	Amount
Balances, December 31, 2022	121,931,676	$	1,219	$	1,779,703	$	1,308,558	$	(4,022)	$	3,085,458
Net income	—	—		—		198,552		—		198,552
Other comprehensive income	—	—		—		—		13		13
Net cash dividends declared, $0.15 per share	—	—		—		(18,078)		—		(18,078)


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

Purchase of shares under Stock Repurchase Program	(1,413,758)	(14)		(40,454)		—		—		(40,468)
Balances, March 31, 2023	120,517,918	$	1,205	$	1,743,567	$	1,489,032	$	(4,009)	$	3,229,795
Net income	—	—		—		149,874		—		149,874
Other comprehensive income	—	—		—		—		13		13
Net cash dividends declared, $0.15 per share	—	—		—		(17,704)		—		(17,704)
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	774	—		(7)		—		—		(7)
Stock-based compensation expense	56,872	1		4,162		—		—		4,163
Purchase of shares under Stock Repurchase Program	(2,550,706)	(26)		(69,457)		—		—		(69,483)
Other	19,037	—		—		—		—		—
Balances, June 30, 2023	118,112,105	$	1,181	$	1,680,080	$	1,621,202	$	(3,996)	$	3,298,467
Net income	—	—		—		222,343		—		222,343
Other comprehensive income	—	—		—		—		14		14
Net cash dividends declared, $0.15 per share	—	—		—		(17,543)		—		(17,543)
Issuance of common stock under Employee Stock Purchase Plan	(18)	—		—		—		—		—
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings	553,442	6		(7,881)		—		—		(7,875)
Stock-based compensation expense	—	—		6,038		—		—		6,038

Purchase of shares under Stock Repurchase Program	(2,351,642)	(24)		(97,127)		—		—		(97,151)
Balances, September 30, 2023	116,313,887	$	1,163	$	1,581,110	$	1,826,002	$	(3,982)	$	3,404,293

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,
	2024		2023
Cash flows from operating activities:
Net income	$	582,015	$	570,769
Adjustments to reconcile net income to net cash provided by operating activities:

Depletion, depreciation, amortization, and asset retirement obligation liability accretion	548,781		501,374


Stock-based compensation expense	17,393		14,519
Net derivative (gain) loss	(70,256)		12,352
Net derivative settlement gain	46,288		20,398
Amortization of deferred financing costs	4,925		4,114

Deferred income taxes	116,522		43,171
Other, net	(25,590)		(11,489)
Net change in working capital	(15,433)		(57,329)





Net cash provided by operating activities	1,204,645		1,097,879

Cash flows from investing activities:

Capital expenditures	(957,156)		(766,756)
Acquisition of proved and unproved oil and gas properties	(836)		(109,318)
Other, net	80		657
Net cash used in investing activities	(957,912)		(875,417)

Cash flows from financing activities:


Debt issuance costs related to credit facility	(2,378)		—
Net proceeds from Senior Notes	1,477,032		—
Cash paid to repurchase Senior Notes	(349,118)		—
Repurchase of common stock	(83,991)		(205,246)
Dividends paid	(62,136)		(54,167)
Net proceeds from sale of common stock	1,844		1,815
Net share settlement from issuance of stock awards	(6,837)		(7,882)

Net cash provided by (used in) financing activities	974,416		(265,480)

Net change in cash, cash equivalents, and restricted cash	1,221,149		(43,018)
Cash, cash equivalents, and restricted cash at beginning of period	616,164		444,998
Cash, cash equivalents, and restricted cash at end of period	$	1,837,313	$	401,980

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) (Continued)

(in thousands)


	For the Nine Months Ended September 30,
	2024		2023
Supplemental schedule of additional cash flow information and non-cash activities:
Operating activities:
Cash paid for interest, net of capitalized interest (1)	$	(83,130)	$	(77,514)
Net cash paid for income taxes	$	(7,623)	$	(6,176)
Investing activities:
Changes in capital expenditure accruals	$	(33,187)	$	35,683
Non-cash financing activities (2)

Reconciliation of cash, cash equivalents, and restricted cash:
Cash and cash equivalents	$	1,735,313	$	401,980
Restricted cash (3)	102,000		—
Cash, cash equivalents, and restricted cash at end of period	$	1,837,313	$	401,980

____________________________________________

(1) Cash paid for interest, net of capitalized interest during the nine months ended September 30, 2024, does not include $9.0 million in fees paid to secure firm commitments for senior unsecured bridge term loans in connection with the Uinta Basin Acquisition discussed and defined in Note 11 - Acquisitions.

(2) Please refer to Note 5 - Long-Term Debt for discussion of the debt transactions executed during the nine months ended September 30, 2024.

(3) Represents a deposit held in a third-party escrow account related to the Uinta Basin Acquisition, as defined in Note 11 - Acquisitions, and is included in the acquisition deposit held in escrow line item on the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”). Please refer to Note 11 - Acquisitions for additional discussion.

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, and following the closing of the Uinta Basin Acquisition on October 1, 2024, in the state of Utah. Please refer to Note 11 - Acquisitions for discussion and the definition of the Uinta Basin Acquisition.

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 2023 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 30, 2024, 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 2023 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 2023 Form 10-K.

Recently Issued Accounting Guidance

Accounting Standards Updates. In November 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”). ASU 2023-07 was issued to improve the disclosures about a public entity’s reportable segments and to provide additional, more detailed information about a reportable segment’s expenses. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The guidance is to be applied on a retrospective basis to all prior periods presented in the financial statements. The Company is within the scope of this ASU and expects to adopt ASU 2023-07 and related guidance on December 31, 2024. Adoption of ASU 2023-07 is not expected to have a material impact on the Company’s consolidated financial statements or related disclosures.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 was issued to improve the disclosures primarily related to rate reconciliations and income taxes paid. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, with early adoption permitted. The guidance is to be applied on a prospective basis; however, retrospective application is permitted. The Company is within the scope of this ASU and expects to adopt ASU 2023-09 on January 1, 2025, on a prospective basis. Adoption of ASU 2023-09 is not expected to have a material impact on the Company’s consolidated financial statements or related disclosures.

SEC Final Rule to Enhance and Standardize Climate-Related Disclosures. On March 6, 2024, the SEC adopted final rules to require registrants to disclose certain climate-related information in registration statements and annual reports. On April 4, 2024, the SEC issued an order staying the final rules pending completion of judicial review of the petitions challenging the final rules. The order does not amend the compliance dates contemplated by the final rules, which are applicable to the Company for fiscal years beginning with the Company’s annual report on Form 10-K for the fiscal year ended December 31, 2025. The Company is currently evaluating the potential impact of the final rules on its financial statements and related disclosures.

As of September 30, 2024, and through the filing of this report, no other accounting guidance has been issued and not yet adopted that is 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”) 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:


	Midland Basin						South Texas						Total
	Three Months Ended September 30,						Three Months Ended September 30,						Three Months Ended September 30,
	2024			2023			2024			2023			2024			2023

	(in thousands)
Oil production revenue	$	386,915		$	369,858		$	144,912		$	129,376		$	531,827		$	499,234
Gas production revenue	19,265			45,215			31,290			36,592			50,555			81,807
NGL production revenue	176			175			59,822			58,483			59,998			58,658
Total	$	406,356		$	415,248		$	236,024		$	224,451		$	642,380		$	639,699
Relative percentage	63		%	65		%	37		%	35		%	100		%	100		%


	Midland Basin						South Texas						Total
	Nine Months Ended September 30,						Nine Months Ended September 30,						Nine Months Ended September 30,
	2024			2023			2024			2023			2024			2023

	(in thousands)
Oil production revenue	$	1,097,936		$	992,867		$	407,339		$	350,598		$	1,505,275		$	1,343,465
Gas production revenue	82,636			131,804			80,948			113,461			163,584			245,265
NGL production revenue	394			563			166,174			167,739			166,568			168,302
Total	$	1,180,966		$	1,125,234		$	654,461		$	631,798		$	1,835,427		$	1,757,032
Relative percentage	64		%	64		%	36		%	36		%	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 may differ depending on the applicable contractual terms. Transfer of control determines 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 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 may be affected by fees and other deductions incurred by the purchaser subsequent to the transfer of control.

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 balance sheets until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of September 30, 2024, and December 31, 2023, were $173.1 million and $175.3 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.

Note 3 - Equity

Stock Repurchase Program

During the second quarter of 2024, the Company’s Board of Directors re-authorized the Company’s existing stock repurchase program to re-establish the Company’s authorization to repurchase up to $500.0 million in aggregate value of its common stock through December 31, 2027 (“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. Please refer to Note 3 - Equity in the 2023 Form 10-K for additional information regarding the Company’s Stock Repurchase Program.

The following table presents activity under the Company’s Stock Repurchase Program:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2024		2023		2024		2023

	(in thousands, except per share data)
Shares of common stock repurchased (1)	—		2,352		1,771		6,316
Weighted-average price per share (2)	$	—	$	40.97	$	47.40	$	32.48
Cost of shares of common stock repurchased (2) (3)	$	—	$	96,336	$	83,955	$	205,120

____________________________________________

(1) All repurchased shares of the Company’s common stock were retired upon repurchase.

(2) Amounts exclude excise taxes, commissions, and fees.

(3) Amounts may not calculate due to rounding.

As of September 30, 2024, $500.0 million remained available for repurchases of the Company’s outstanding common stock through December 31, 2027, under the Stock Repurchase Program.

Note 4 - Income Taxes

The provision for income taxes consisted of the following:


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2024			2023			2024			2023

	(in thousands)
Current portion of income tax expense:
Federal	$	(10,201)		$	(3,923)		$	(23,675)		$	(6,732)
State	(1,311)			(1,173)			(2,589)			(1,716)
Deferred portion of income tax (expense) benefit	(45,615)			51,075			(116,522)			(43,171)
Income tax (expense) benefit	$	(57,127)		$	45,979		$	(142,786)		$	(51,619)

Effective tax rate	19.2		%	(26.1)		%	19.7		%	8.3		%

Income tax expense or benefit differs from the amount that would be calculated 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 federal tax credits, state income taxes, excess tax benefits and deficiencies from stock-based compensation awards, tax deduction limitations on 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 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 of the periods presented in the table above.

The Company completed a multi-year research and development (“R&D”) credit study in 2023, which resulted in a favorable adjustment to the Company’s effective tax rate for the three and nine months ended September 30, 2023. The effective tax rates for the three and nine months ended September 30, 2024, reflect the benefit of current R&D credits claimed. The Company expects favorable adjustments to the Company’s effective tax rate to continue in the fourth quarter of 2024 resulting from qualifying R&D activity and anticipated credit claims.

The Company complies with authoritative accounting guidance regarding uncertain tax positions. The entire amount of unrecognized tax benefit reported by the Company would affect its effective tax rate if recognized. The Company does not expect a significant change to the recorded unrecognized tax benefits in 2024, except for any potential changes related to the Company’s 2024 R&D credit claims.

For all years before 2020, 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

The Company’s Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 billion, and as of September 30, 2024, the borrowing base and aggregate lender commitments under the Credit Agreement were $2.5 billion and $1.25 billion, respectively.

Prior to the Second Amendment, as defined and discussed below, commitment fees on the unused portion of the aggregate lender commitment amount were accrued at rates from the borrowing base utilization grid set forth in the Credit Agreement, as presented in Note 5 - Long-Term Debt in the 2023 Form 10-K.

The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of September 30, 2024, and December 31, 2023:


	As of September 30, 2024		As of December 31, 2023

	(in thousands)
Revolving credit facility (1)	$	—	$	—
Letters of credit (2)	2,000		2,500
Available borrowing capacity	1,248,000		1,247,500
Total aggregate lender commitment amount	$	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 $8.9 million and $8.5 million as of September 30, 2024, and December 31, 2023, 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.

First Amendment. On July 2, 2024, the Company and its lenders entered into the First Amendment to the Credit Agreement (“First Amendment”) to amend certain provisions of the Credit Agreement to facilitate financing for the Uinta Basin Acquisition, as defined in Note 11 - Acquisitions.

Second Amendment. On October 1, 2024, the Company and its lenders entered into the Second Amendment to the Credit Agreement (“Second Amendment”) in conjunction with the closing of the Uinta Basin Acquisition, as defined in Note 11 - Acquisitions, to, among other things: (i) increase the aggregate revolving lender commitments available under the Credit Agreement from $1.25 billion to $2.0 billion; (ii) extend the maturity date of the Credit Agreement; and (iii) modify certain other provisions reflective of the increased aggregate revolving lender commitments, increased Company size and scale, and extended maturity date. The Credit Agreement is scheduled to mature on the earlier of (a) October 1, 2029 (“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 in an amount exceeding $50.0 million 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.

Under the Second Amendment, interest and commitment fees associated with the revolving credit facility are accrued based on a total revolving commitments utilization grid set forth in the Second Amendment, and as presented in the table below. At the Company’s election, borrowings under the Credit Agreement may be in the form of Secured Overnight Financing Rate (“SOFR”) revolving loans, Alternate Base Rate (“ABR”) revolving loans, or Swingline loans. SOFR revolving loans accrue interest at SOFR plus the applicable margin from the utilization grid, and ABR revolving loans 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 revolving lender commitment amount at rates from the utilization grid.


Total Revolving Commitments Utilization Percentage	<25%		≥25% <50%		≥50% <75%		≥75% <90%		≥90%
SOFR Revolving Loans	1.750	%	2.000	%	2.250	%	2.500	%	2.750	%
ABR Revolving Loans or Swingline Loans	0.750	%	1.000	%	1.250	%	1.500	%	1.750	%
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 24, 2024:


	As of October 24, 2024

	(in thousands)
Revolving credit facility	$	159,000
Letters of credit (1)	2,000
Available borrowing capacity	1,839,000
Total aggregate lender revolving commitment amount	$	2,000,000

____________________________________________

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

On October 11, 2024, the Company’s lenders completed the semi-annual borrowing base redetermination, which resulted in an increase to the Company’s borrowing base to $3.0 billion and reaffirmed the aggregate revolving lender commitment at the existing amount of $2.0 billion. The next borrowing base redetermination date is scheduled to occur on April 1, 2025.

Senior Notes

The Company’s Senior Notes, net line item on the accompanying balance sheets as of September 30, 2024, and December 31, 2023, consisted of the following (collectively referred to as “Senior Notes”):


	As of September 30, 2024						As of December 31, 2023
	Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net		Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net

	(in thousands)
5.625% Senior Notes due 2025	$	—	$	—	$	—	$	349,118	$	896	$	348,222
6.75% Senior Notes due 2026	419,235		1,343		417,892		419,235		1,868		417,367
6.625% Senior Notes due 2027	416,791		1,813		414,978		416,791		2,395		414,396
6.5% Senior Notes due 2028	400,000		3,890		396,110		400,000		4,651		395,349
6.75% Senior Notes due 2029	750,000		11,061		738,939		—		—		—
7.0% Senior Notes due 2032	750,000		11,219		738,781		—		—		—
Total	$	2,736,026	$	29,326	$	2,706,700	$	1,585,144	$	9,810	$	1,575,334

On July 25, 2024, the Company issued $750.0 million in aggregate principal amount of its 6.75% Senior Notes at par with a maturity date of August 1, 2029 (“2029 Senior Notes”). The Company received net proceeds of $738.5 million after deducting fees of $11.5 million, which are being amortized as deferred financing costs over the life of the 2029 Senior Notes. Also on July 25, 2024, the Company issued $750.0 million in aggregate principal amount of its 7.0% Senior Notes at par with a maturity date of August 1, 2032 (“2032 Senior Notes”). The Company received net proceeds of $738.5 million after deducting fees of $11.5 million, which are being amortized as deferred financing costs over the life of the 2032 Senior Notes.

On August 26, 2024 (“Redemption Date”), the Company redeemed the $349.1 million of aggregate principal amount outstanding of its 5.625% Senior Notes due June 1, 2025 (“2025 Senior Notes”), pursuant to the terms of the indenture governing the 2025 Senior Notes which provided for a redemption price equal to 100 percent of the principal amount outstanding of the 2025 Senior Notes on the Redemption Date, plus accrued and unpaid interest. Upon redemption, the Company recorded a loss on extinguishment of debt of $0.5 million related to the accelerated expense recognition of the remaining unamortized deferred financing costs. The Company canceled all redeemed 2025 Senior Notes upon settlement.

The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. The Company may redeem some or all of its Senior Notes prior to their maturity at redemption prices that may include a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes.

Covenants

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

payments including dividends, sell assets, create liens that secure debt, enter into transactions with affiliates, make certain investments, or merge or consolidate with other entities. The Company was in compliance with all financial and non-financial covenants as of September 30, 2024, and through the filing of this report. Please refer to Note 5 - Long-Term Debt in the 2023 Form 10-K, the First Amendment to the Credit Agreement, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 8, 2024, and the Second Amendment to the Credit Agreement, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on October 2, 2024, 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 30, 2024, and 2023, totaled $5.4 million and $4.9 million, respectively, and totaled $17.6 million and $16.3 million for the nine months ended September 30, 2024, and 2023, 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 2023 Form 10-K.

Drilling Rig Service Contracts. During the nine months ended September 30, 2024, the Company entered into new drilling rig contracts. As of September 30, 2024, the Company’s drilling rig commitments totaled $19.2 million under contract terms extending through the second quarter of 2025. If all of the drilling rig contracts were terminated as of September 30, 2024, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $10.4 million in early termination fees. No early termination penalties or standby fees were incurred by the Company during the nine months ended September 30, 2024, and the Company does not expect to incur material penalties with regard to its drilling rig contracts during the remainder of 2024.

Drilling and Completion Commitments. During the nine months ended September 30, 2024, 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, 2026, 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, 2024, the liquidated damages could range from zero to a maximum of $55.0 million, with the maximum exposure assuming no additional development activity occurs prior to March 31, 2026. As of the filing of this report, the Company expects to meet its drilling and completion footage obligations under this agreement.

Subsequent Events. As part of the Uinta Basin Acquisition, certain contracts and leases containing both short-term and long-term commitments were assigned to the Company effective as of the closing date of October 1, 2024. The Company is evaluating the minimum commitments, terms and conditions, and operational plans related to activities under these contracts and leases, as well as the expected financial statement impact. Please see Note 11 - Acquisitions for discussion and the definition of the Uinta Basin Acquisition.

Certain contracts assigned to the Company include material, long-term oil gathering, processing, transportation throughput, and delivery commitments with various third-parties, under which the Company would be required to make periodic deficiency payments for any shortfalls in delivering specified minimum volume commitments. As of October 1, 2024, if the Company failed to deliver any product under these contracts, the aggregate undiscounted deficiency payments would total approximately $135.8 million. One of these contracts does not have a minimum volume commitment associated with it, however, as of October 1, 2024, the Company would owe a cancellation fee of $4.9 million if the agreement was terminated.

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. As of the filing of this report, 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 - 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 September 30, 2024, 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 (“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 30, 2024, the Company had commodity derivative contracts outstanding through the fourth quarter of 2026 as summarized in the table below:


	Contract Period
	Fourth Quarter 2024		2025		2026
Oil Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
NYMEX WTI Volumes	1,906		1,973		—
Weighted-Average Contract Price	$	74.25	$	72.36	$	—


Collars
NYMEX WTI Volumes	1,917		4,515		—
Weighted-Average Floor Price	$	69.93	$	65.69	$	—
Weighted-Average Ceiling Price	$	82.27	$	81.65	$	—
Basis Swaps
WTI Midland-NYMEX WTI Volumes	1,230		4,556		—
Weighted-Average Contract Price	$	1.21	$	1.18	$	—


WTI Houston MEH-NYMEX WTI Volumes	309		2,130		1,546
Weighted-Average Contract Price	$	1.82	$	1.86	$	2.02
Roll Differential Swaps
NYMEX WTI Volumes	2,334		—		—
Weighted-Average Contract Price	$	0.66	$	—	$	—

Gas Derivatives (volumes in BBtu and prices in $ per MMBtu):
Swaps
NYMEX HH Volumes	1,569		7,321		4,645
Weighted-Average Contract Price	$	3.03	$	3.97	$	3.73


IF Waha Volumes	—		—		1,548
Weighted-Average Contract Price	$	—	$	—	$	3.26


Collars
NYMEX HH Volumes	7,328		29,920		13,438
Weighted-Average Floor Price	$	3.38	$	3.23	$	3.25
Weighted-Average Ceiling Price	$	4.97	$	4.70	$	4.90









Basis Swaps




IF Waha-NYMEX HH Volumes	5,240		20,501		—
Weighted-Average Contract Price	$	(0.73)	$	(0.66)	$	—
IF HSC-NYMEX HH Volumes	5,750		946		—
Weighted-Average Contract Price	$	(0.38)	$	0.0025	$	—

NGL Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
OPIS Propane Mont Belvieu Non-TET Volumes	434		396		—
Weighted-Average Contract Price	$	31.85	$	32.86	$	—
OPIS Normal Butane Mont Belvieu Non-TET Volumes	97		45		—
Weighted-Average Contract Price	$	39.84	$	39.48	$	—
OPIS Isobutane Mont Belvieu Non-TET Volumes	28		25		—
Weighted-Average Contract Price	$	41.58	$	41.58	$	—

Commodity Derivative Contracts Entered Into Subsequent to September 30, 2024

Subsequent to September 30, 2024, and through the filing of this report, the Company entered into the following commodity derivative contracts:

•NYMEX WTI price swap contracts for the first through third quarters of 2025 for a total of 1.9 MMBbl of oil production at a weighted-average contract price of $71.72 per Bbl; and

•NYMEX HH price swap contract for the second quarter of 2026 for a total of 1,430 BBtu of gas production at a weighted-average contract price of $3.25 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 commodity derivative contracts at September 30, 2024, and December 31, 2023, was a net asset of $81.0 million and $57.1 million, respectively.

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


	As of September 30, 2024		As of December 31, 2023

	(in thousands)
Derivative assets:
Current assets	$	72,287	$	56,442
Noncurrent assets	11,584		8,672
Total derivative assets	$	83,871	$	65,114
Derivative liabilities:
Current liabilities	$	2,401	$	6,789
Noncurrent liabilities	448		1,273
Total derivative liabilities	$	2,849	$	8,062

Offsetting of Derivative Assets and Liabilities

As of September 30, 2024, and December 31, 2023, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets.

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


	Derivative Assets as of				Derivative Liabilities as of
	September 30, 2024		December 31, 2023		September 30, 2024		December 31, 2023

	(in thousands)
Gross amounts presented in the accompanying balance sheets	$	83,871	$	65,114	$	(2,849)	$	(8,062)
Amounts not offset in the accompanying balance sheets	(2,849)		(7,362)		2,849		7,362
Net amounts	$	81,022	$	57,752	$	—	$	(700)

The following table summarizes the commodity components of the net derivative settlement (gain) 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,
	2024		2023		2024		2023

	(in thousands)
Net derivative settlement (gain) loss:
Oil contracts	$	487	$	13,446	$	(877)	$	20,144
Gas contracts	(16,735)		(11,643)		(46,639)		(37,495)
NGL contracts	(243)		(1,489)		1,228		(3,047)
Total net derivative settlement (gain) loss	$	(16,491)	$	314	$	(46,288)	$	(20,398)

Net derivative (gain) loss:
Oil contracts	$	(65,633)	$	77,857	$	(29,805)	$	31,172
Gas contracts	(15,291)		(4,437)		(41,624)		(14,655)
NGL contracts	(5,359)		1,935		1,173		(4,165)
Total net derivative (gain) loss	$	(86,283)	$	75,355	$	(70,256)	$	12,352

Credit Related Contingent Features

As of September 30, 2024, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s 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.

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, 2024						As of December 31, 2023
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3

	(in thousands)
Assets:
Derivatives (1)	$	—	$	83,871	$	—	$	—	$	65,114	$	—

Liabilities:
Derivatives (1)	$	—	$	2,849	$	—	$	—	$	8,062	$	—

__________________________________________

(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 derivative instruments. 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 7 - Derivative Financial Instruments 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 30, 2024, or December 31, 2023, as they were recorded at carrying value, net of any unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional information.


	As of September 30, 2024				As of December 31, 2023
	Principal Amount		Fair Value		Principal Amount		Fair Value

	(in thousands)
5.625% Senior Notes due 2025	$	—	$	—	$	349,118	$	348,189
6.75% Senior Notes due 2026	$	419,235	$	419,759	$	419,235	$	420,660
6.625% Senior Notes due 2027	$	416,791	$	417,362	$	416,791	$	416,549
6.5% Senior Notes due 2028	$	400,000	$	400,240	$	400,000	$	401,372
6.75% Senior Notes due 2029	$	750,000	$	753,750	$	—	$	—
7.0% Senior Notes due 2032	$	750,000	$	753,780	$	—	$	—

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 restricted stock units (“RSU” or “RSUs”) and contingent performance share units (“PSU” or “PSUs”), which were measured using the treasury stock method. Please refer to Note 10 - Compensation Plans in this report and Note 9 - Earnings Per Share in the 2023 Form 10-K for additional detail on these potentially dilutive securities.

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


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2024		2023		2024		2023

	(in thousands, except per share data)
Net income	$	240,523	$	222,343	$	582,015	$	570,769

Basic weighted-average common shares outstanding	114,405		117,823		114,870		119,589
Dilutive effect of non-vested RSUs, contingent PSUs, and other	588		505		831		576
Diluted weighted-average common shares outstanding	114,993		118,328		115,701		120,165

Basic net income per common share	$	2.10	$	1.89	$	5.07	$	4.77
Diluted net income per common share	$	2.09	$	1.88	$	5.03	$	4.75

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 time-based 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 September 30, 2024, approximately 2.3 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 grant date or upon other triggering events as set forth in the Equity Plan.

For PSUs granted in 2024, 2023, and 2022, 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 $1.1 million and $1.0 million for the three months ended September 30, 2024, and 2023, respectively, and $3.5 million and $1.8 million for the nine months ended September 30, 2024, and 2023, respectively. As of September 30, 2024, there was $6.0 million of total unrecognized compensation expense related to non-vested PSUs, which is being amortized through mid-2026. There were no material changes to the outstanding and non-vested PSUs during the nine months ended September 30, 2024. Subsequent to September 30, 2024, the Company granted a total of 231,120 PSUs with a grant date fair value of $9.9 million.

Employee 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 of the applicable grant date 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 grant date. The fair value of an RSU is equal to the closing price of the Company’s common stock on the grant date. 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, 2024, the Company granted a total of 490,481 RSUs with a grant date fair value of $21.3 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 awards to cover income and payroll tax withholdings, as provided for in the Equity Plan and applicable award agreements. After withholding 158,252 shares to satisfy income and payroll tax withholding obligations, the Company issued 350,675 shares of common stock in accordance with the terms of the applicable award agreements.

Total compensation expense recorded for RSUs was $4.5 million and $4.1 million for the three months ended September 30, 2024, and 2023, respectively, and $12.0 million and $10.8 million for the nine months ended September 30, 2024, and 2023, respectively. As of September 30, 2024, there was $33.8 million of total unrecognized compensation expense related to non-vested RSUs, which is being amortized through mid-2027.

A summary of activity during the nine months ended September 30, 2024, is presented in the following table:


	RSUs	Weighted-Average Grant-Date Fair Value (1)
Non-vested at beginning of year	1,080,544	$	31.49
Granted	490,481	$	43.42
Vested	(507,171)	$	30.18
Forfeited	(36,906)	$	32.87
Non-vested at end of quarter	1,026,948	$	37.79

____________________________________________

(1) Amounts represent price per unit.

Director Shares

During the nine months ended September 30, 2024, and 2023, the Company issued a total of 37,530 and 56,872 shares, respectively, of its common stock to its non-employee directors under the Equity Plan. Shares issued to non-employee directors that were elected at the Company’s 2024 annual meeting of stockholders will fully vest on December 31, 2024, and shares issued to non-employee directors that were elected at the Company’s 2023 annual meeting of stockholders fully vested on December 31, 2023.

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 their 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 56,006 and 68,192 shares issued under the ESPP during the nine months ended September 30, 2024, and 2023, respectively. Total proceeds to the Company for the issuance of these shares was $1.8 million during each of the nine months ended September 30, 2024, and 2023. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.

Please refer to Note 10 - Compensation Plans in the 2023 Form 10-K for additional detail on the Company’s compensation plans.

Note 11 - Acquisitions

2024 Acquisition Activity

On June 27, 2024, the Company entered into a Purchase and Sale Agreement (“XCL Acquisition Agreement”) with XCL AssetCo, LLC, XCL Marketing, LLC, Wasatch Water Logistics, LLC, XCL Resources, LLC, and XCL SandCo, LLC, (collectively referred to as the “XCL Sellers”) and, for the limited purposes described therein, Northern Oil and Gas, Inc. (“NOG”). Pursuant to the XCL Acquisition Agreement, the Company agreed to purchase all of the rights, titles and interests in the Uinta Basin oil and gas assets owned by the XCL Sellers (“XCL Assets”). Concurrently with the execution of the XCL Acquisition Agreement, the Company entered into an Acquisition and Cooperation Agreement (“Cooperation Agreement”) with NOG, pursuant to which the Company and NOG agreed to cooperate in connection with the XCL Acquisition Agreement and NOG agreed to acquire an undivided 20 percent interest in the assets acquired pursuant to the XCL Acquisition Agreement. Upon execution of the XCL Acquisition Agreement, the Company deposited with an escrow agent a cash deposit of $102.0 million (“Cash Deposit”), which is presented in the acquisition deposit held in escrow line item on the accompanying balance sheets as of September 30, 2024. Pursuant to the terms of the XCL Acquisition Agreement, the Company had the option to acquire certain additional assets adjacent to the XCL Assets (“Altamont Option Assets”) from the XCL Sellers for a purchase price equal to the XCL Sellers’ cost to acquire the Altamont Option Assets plus the XCL Sellers’ related out of pocket expenses. On August 5, 2024, the Company exercised the option to acquire the Altamont Option Assets.

On October 1, 2024 (“Closing Date”), immediately prior to the closing of the transactions contemplated by the XCL Acquisition Agreement, and as permitted by the XCL Acquisition Agreement and Cooperation Agreement, the Company assigned an undivided 20 percent interest in the XCL Acquisition Agreement to NOG and caused the XCL Sellers to directly assign an undivided 20 percent interest in both the XCL Assets and the Altamont Option Assets to NOG. Accordingly, on the Closing Date, the Company completed the acquisition of an undivided 80 percent interest in both the XCL Assets and the Altamont Option Assets, with an effective date of May 1, 2024 (“Uinta Basin Acquisition”). The Company’s undivided 80 percent interest in the assets acquired in the Uinta Basin Acquisition consists of approximately 63,300 net acres.

On the Closing Date, the unadjusted purchase price, net to the Company’s 80 percent undivided interest in the Uinta Basin Acquisition, was approximately $2.1 billion. The Company paid approximately $1.9 billion in cash to the XCL Sellers, using a portion of

the net proceeds from the issuance of the 2029 Senior Notes and 2032 Senior Notes discussed in Note 5 - Long-Term Debt, cash on hand, and borrowings under the Company’s revolving credit facility. Additionally, a majority of the Cash Deposit was disbursed to the XCL Sellers on the Closing Date. The remaining portion of the Cash Deposit will remain in escrow pending the completion of post-closing purchase price adjustments, which are expected to occur in the first quarter of 2025. Final purchase accounting for the Uinta Basin Acquisition was not complete at the time that this report was filed. The Company expects to account for the Uinta Basin Acquisition as an asset acquisition and will include any required disclosures and information related to the Uinta Basin Acquisition in its 2024 Annual Report on Form 10-K or earlier filed Current Reports on Form 8-K, as applicable, pursuant to the rules and regulations of the SEC and authoritative accounting guidance.

2023 Acquisition Activity

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 during the nine months ended September 30, 2023, was $88.9 million. Under authoritative accounting guidance, this transaction was accounted for as 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. Additionally, during the third quarter of 2023, the Company acquired additional working interests in certain wells located in the Midland Basin for approximately $20.4 million.

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 on Form 10-Q for the quarter ended June 30, 2024, filed with the SEC on August 8, 2024. Throughout the following discussion, we explain changes between the three months ended September 30, 2024, and the three months ended June 30, 2024 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the nine months ended September 30, 2024, and the nine months ended September 30, 2023 (“YTD 2024-over-YTD 2023”).

Overview of the Company

General Overview

Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our long-term vision and strategy is to sustainably grow value for all of our stakeholders as a premier operator of top-tier assets by maintaining and optimizing our high-quality asset portfolio, generating cash flows, and maintaining a strong balance sheet. 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 focusing on continued operational excellence, successfully integrating the Uinta Basin assets, and continuing to return value to stockholders through fixed dividend payments and our Stock Repurchase Program, while also transferring value to stockholders through reduced debt.

Our asset portfolio is comprised of high-quality assets in the Midland Basin in West Texas, the Maverick Basin in South Texas, and as of October 1, 2024, the Uinta Basin in northeast Utah, which we believe are capable of generating strong returns in the current macroeconomic environment and provide resilience to commodity price risk and volatility. We seek to maximize returns and increase the value of our top-tier assets through disciplined capital spending, strategic acquisitions, such as the Uinta Basin Acquisition, and continued development and optimization of our existing assets. We believe that our high-quality assets facilitate a sustainable approach to prioritizing operational execution, maintaining a strong balance sheet, generating cash flows, returning capital to stockholders, and maintaining financial flexibility.

We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; 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. The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the effectiveness of our ESG policies, programs and initiatives, monitors and responds to emerging trends, issues, and associated risks, 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.

We are impacted by global commodity and financial markets that remain subject to heightened levels of uncertainty and volatility. Key factors contributing to market fluctuations include ongoing oil production curtailment agreements among the Organization of the Petroleum Exporting Countries (“OPEC”) plus other non-OPEC oil producing countries (collectively referred to as “OPEC+”); lower than expected oil and gas demand from China; War and Geopolitical Instability; United States Federal Reserve monetary policy; shipping channel constraints and disruptions; and changes in global oil inventory in storage. These factors have driven commodity price volatility, contributed to instances of supply chain disruptions and fluctuations in interest rates, and could have further industry-specific impacts 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 2023 Form 10-K, and Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on July 18, 2024. Despite continuing uncertainty, we expect to maximize the value of our high-quality asset base and sustain strong operational performance and financial stability. We remain focused on returning capital to stockholders through cash flow generation.

Areas of Operations

Our Midland Basin assets are comprised of approximately 110,000 net acres located in the Permian Basin in West Texas (“Midland Basin”). In the third quarter of 2024, our drilling and completion activities focused on development optimization of our RockStar and Sweetie Peck assets, and delineation and development of our Klondike assets. 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 Dimmit and Webb counties, Texas (“South Texas”). In the third quarter of 2024, we focused our operations on development and further delineation of the Austin Chalk formation, and on production from both the Austin Chalk formation and Eagle Ford shale formation. Our overlapping acreage position in the Maverick Basin in South Texas 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.

On October 1, 2024, we acquired approximately 63,300 net acres located in Duchesne and Uintah counties, Utah (“Uinta Basin”). Our Uinta Basin position provides future development opportunities within multiple oil-rich intervals in the Lower Green River and Wasatch formations, and includes acreage with waxy crude and gas composition amenable to processing for NGL extraction. Please refer to Note 11 - Acquisitions in Part I, Item 1 of this report for additional discussion.

Third Quarter 2024 Overview and Outlook for the Remainder of 2024

During the third quarter of 2024:

•We exercised the option to purchase the Altamont Option Assets, and on October 1, 2024, we closed the Uinta Basin Acquisition, as discussed in Note 11 - Acquisitions in Part I, Item 1 of this report.

•We issued our 2029 Senior Notes and 2032 Senior Notes and redeemed the remaining $349.1 million of aggregate principal amount outstanding of our 2025 Senior Notes. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

•We continued to execute on our goal of sustainably returning capital to our stockholders by paying a net cash dividend of $0.18 per share totaling $20.6 million. Additionally, we declared an increased net cash dividend of $0.20 per share totaling $22.9 million, which will be paid in the fourth quarter of 2024.

Financial and Operational Results. Average net daily equivalent production for the three months ended September 30, 2024, increased seven percent sequentially to 170.0 MBOE, consisting of increases of eight percent and six percent from our South Texas and Midland Basin assets, respectively. These increases were a result of strong well performance and the timing of well completions.

Oil, gas, and NGL production revenue increased one percent to $642.4 million for the three months ended September 30, 2024, compared with $633.5 million for the three months ended June 30, 2024. Oil, gas, and NGL production expense increased nine percent to $148.4 million for the three months ended September 30, 2024, compared with $136.6 million for the three months ended June 30, 2024, as a result of increases in transportation expense and lease operating expense (“LOE”).

Realized price per BOE, before the effect of net derivative settlements (“realized price” or “realized prices”), decreased six percent sequentially. During the third quarter of 2024, oil and NGL benchmark prices decreased, and the gas benchmark price increased. These changes resulted in sequential quarterly decreases in oil and NGL realized prices of seven percent and five percent, respectively, partially offset by an increase in the gas realized price of four percent.

We recorded net derivative gains of $86.3 million and $12.1 million for the three months ended September 30, 2024, and June 30, 2024, respectively. Included within these amounts are net derivative settlement gains of $16.5 million for each of the three months ended September 30, 2024, and June 30, 2024.

Operational and financial activities during the three months ended September 30, 2024, resulted in the following:

•Net cash provided by operating activities of $452.3 million, compared with $476.4 million for the three months ended June 30, 2024.

•Net income of $240.5 million, or $2.09 per diluted share, compared with net income of $210.3 million, or $1.82 per diluted share, for the three months ended June 30, 2024.

•Adjusted EBITDAX, a non-GAAP financial measure, of $481.5 million, compared with $485.9 million for the three months ended June 30, 2024. Please refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations to net income 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, 2024, and June 30, 2024, and Between the Nine Months Ended September 30, 2024, and 2023 below for additional discussion.

Operational Activities. We expect our total 2024 capital program to be between $1.24 billion and $1.26 billion, including capital expenditures related to the development of our recently acquired Uinta Basin assets, but excluding acquisitions. Our capital program remains focused on highly economic oil development projects in our Midland Basin, South Texas, and Uinta Basin assets. During 2024, we expect to continue our focus on strategic inventory replacement and growth by 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 2024 capital program.

In our Midland Basin program, we operated four drilling rigs and averaged one completion crew, drilled 27 gross (19 net) wells, and completed 17 gross (15 net) wells during the third quarter of 2024. Average net daily equivalent production volumes increased sequentially by six percent to 84.6 MBOE. Costs incurred during the three months ended September 30, 2024, totaled $168.3 million, or 55 percent of our total costs incurred for the period. We anticipate operating four drilling rigs and one completion crew for the remainder of 2024, focused on developing formations within our RockStar, Sweetie Peck, and Klondike assets.

In our South Texas program, we operated two drilling rigs and one completion crew, drilled 16 gross (16 net) wells, and completed 20 gross (20 net) wells during the third quarter of 2024. Average net daily equivalent production volumes increased sequentially by eight percent to 85.4 MBOE. Costs incurred during the three months ended September 30, 2024, totaled $125.9 million, or 41 percent of our total costs incurred for the period. We anticipate operating two drilling rigs and no completion crews for the remainder of 2024, focused primarily on developing the Austin Chalk formation.

In our Uinta Basin program, we anticipate operating three drilling rigs and one completion crew during the remainder of 2024, focused primarily on delineating and developing our recently acquired assets.

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 months ended September 30, 2024:


	Midland Basin		South Texas (1)		Total
	Gross	Net	Gross	Net	Gross	Net
Wells drilled but not completed at December 31, 2023	39	29	37	37	76	66
Wells drilled	19	17	12	12	31	29
Wells completed	(16)	(11)	(16)	(16)	(32)	(27)

Wells drilled but not completed at March 31, 2024	42	35	33	33	75	68
Wells drilled	24	21	10	10	34	31
Wells completed	(32)	(26)	(10)	(10)	(42)	(36)

Wells drilled but not completed at June 30, 2024	34	30	33	33	67	63
Wells drilled	27	19	16	16	43	35
Wells completed	(17)	(15)	(20)	(20)	(37)	(35)

Wells drilled but not completed at September 30, 2024 (2)	44	34	29	29	73	63

____________________________________________

(1) As of December 31, 2023, the drilled but not completed well count included nine gross (nine net) wells that were not included in our five-year development plan as of December 31, 2023, eight of which were in the Eagle Ford shale.

(2) Amount excludes five gross (two net) non-operated wells drilled in the Midland Basin during the third quarter of 2024, resulting in five gross (two net) non-operated wells drilled but not completed at September 30, 2024.

Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $304.7 million and $956.8 million for the three and nine months ended September 30, 2024, respectively, and were primarily incurred in our Midland Basin and South Texas programs as discussed in Operational Activities above.

Production Results. The table below presents our net production by product type for each of our assets for the periods presented:


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2024		June 30, 2024		September 30, 2024		September 30, 2023
Midland Basin Net Production:
Oil (MMBbl)	5.1		4.7		14.1		13.0
Gas (Bcf)	16.1		15.4		46.0		44.6
NGLs (MMBbl)	—		—		—		—
Equivalent (MMBOE)	7.8		7.2		21.8		20.4
Average net daily equivalent (MBOE per day)	84.6		79.7		79.6		74.8
Relative percentage	50	%	50	%	50	%	49	%

South Texas Net Production:
Oil (MMBbl)	2.0		1.9		5.4		4.7
Gas (Bcf)	18.5		16.8		51.9		54.2
NGLs (MMBbl)	2.8		2.4		7.4		7.2
Equivalent (MMBOE)	7.9		7.2		21.5		21.0
Average net daily equivalent (MBOE per day)	85.4		78.8		78.3		76.7
Relative percentage	50	%	50	%	50	%	51	%

Total Net Production:
Oil (MMBbl)	7.1		6.6		19.5		17.7
Gas (Bcf)	34.5		32.2		97.9		98.9
NGLs (MMBbl)	2.8		2.4		7.4		7.2
Equivalent (MMBOE)	15.6		14.4		43.3		41.4
Average net daily equivalent (MBOE per day)	170.0		158.5		157.9		151.5

____________________________________________

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 net 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 net derivative settlements, for the three months ended September 30, 2024, June 30, 2024, and September 30, 2023:


	For the Three Months Ended
	September 30, 2024		June 30, 2024		September 30, 2023
Oil (per Bbl):
Average NYMEX contract monthly price	$	75.10	$	80.57	$	82.26
Realized price	$	74.72	$	80.48	$	80.95
Effect of oil net derivative settlements	$	(0.07)	$	(0.18)	$	(2.18)
Gas:
Average NYMEX monthly settle price (per MMBtu)	$	2.16	$	1.89	$	2.55
Realized price (per Mcf)	$	1.46	$	1.40	$	2.48
Effect of gas net derivative settlements (per Mcf)	$	0.48	$	0.55	$	0.35
NGLs (per Bbl):
Average OPIS price (1)	$	26.68	$	27.96	$	27.81
Realized price	$	21.70	$	22.86	$	23.61
Effect of NGL net derivative settlements	$	0.09	$	—	$	0.60

____________________________________________

(1) 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. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

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. Given the uncertainty surrounding global financial markets, production output from OPEC+, global shipping channel constraints and disruptions, lower than expected oil and gas demand from China, War and Geopolitical Instability, changes in global oil inventory in storage, and the potential impacts of these issues on global commodity 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 inflation, supply chain disruptions, fluctuations in interest rates, and industry-specific impacts. 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 realized price for our Midland Basin gas production was impacted by residue pipeline capacity constraints during the third quarter of 2024; however, a portion of any negative impact to the realized price was mitigated by our commodity derivative contracts in effect during the third quarter of 2024. We expect that increased infrastructure capacity will alleviate constraints during the fourth quarter of 2024.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of October 24, 2024, and September 30, 2024:


	As of October 24, 2024		As of September 30, 2024
NYMEX WTI oil (per Bbl)	$	69.04	$	67.27
NYMEX Henry Hub gas (per MMBtu)	$	3.06	$	3.20
OPIS NGLs (per Bbl)	$	27.50	$	27.02

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 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 7 - 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 30, 2024, and the preceding three quarters:


	For the Three Months Ended
	September 30,		June 30,		March 31,		December 31,
	2024		2024		2024		2023

	(in millions)
Net production (MMBOE)	15.6		14.4		13.2		14.1
Oil, gas, and NGL production revenue	$	642.4	$	633.5	$	559.6	$	606.9
Oil, gas, and NGL production expense	$	148.4	$	136.6	$	137.4	$	137.3
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	202.9	$	179.7	$	166.2	$	189.1
Exploration	$	12.1	$	17.1	$	18.6	$	15.8
General and administrative	$	35.1	$	31.1	$	30.2	$	36.6
Net income	$	240.5	$	210.3	$	131.2	$	247.1

Selected Performance Metrics


	For the Three Months Ended
	September 30,			June 30,			March 31,			December 31,
	2024			2024			2024			2023
Average net daily equivalent production (MBOE per day)	170.0			158.5			145.1			153.5
Lease operating expense (per BOE)	$	4.73		$	4.82		$	5.54		$	5.31
Transportation costs (per BOE)	$	2.13		$	1.94		$	2.07		$	2.08
Production taxes as a percent of oil, gas, and NGL production revenue	4.6		%	4.3		%	4.5		%	4.6		%
Ad valorem tax expense (per BOE)	$	0.76		$	0.82		$	0.89		$	0.37
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)	$	12.98		$	12.46		$	12.59		$	13.39
General and administrative (per BOE)	$	2.25		$	2.16		$	2.29		$	2.60

____________________________________________

Note: Amounts may not calculate due to rounding.

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
	September 30,		June 30,						September 30,		September 30,
	2024		2024						2024		2023
Net production volumes: (1)
Oil (MMBbl)	7.1		6.6		0.5		8	%	19.5		17.7			1.8			10	%
Gas (Bcf)	34.5		32.2		2.3		7	%	97.9		98.9			(1.0)			(1)	%
NGLs (MMBbl)	2.8		2.4		0.3		13	%	7.4		7.2			0.2			3	%
Equivalent (MMBOE)	15.6		14.4		1.2		8	%	43.3		41.4			1.9			5	%
Average net daily production: (1)
Oil (MBbl per day)	77.4		72.7		4.7		6	%	71.3		64.8			6.4			10	%
Gas (MMcf per day)	375.4		354.0		21.5		6	%	357.3		362.2			(4.9)			(1)	%
NGLs (MBbl per day)	30.1		26.8		3.3		12	%	27.1		26.3			0.7			3	%
Equivalent (MBOE per day)	170.0		158.5		11.5		7	%	157.9		151.5			6.4			4	%
Oil, gas, and NGL production revenue (in millions): (1)
Oil production revenue	$	531.8	$	532.6	$	(0.7)	—	%	$	1,505.3	$	1,343.5		$	161.8		12	%
Gas production revenue	50.6		45.2		5.4		12	%	163.6		245.3			(81.7)			(33)	%
NGL production revenue	60.0		55.7		4.3		8	%	166.6		168.3			(1.7)			(1)	%
Total oil, gas, and NGL production revenue	$	642.4	$	633.5	$	8.9	1	%	$	1,835.4	$	1,757.0		$	78.4		4	%
Oil, gas, and NGL production expense (in millions): (1)
Lease operating expense	$	73.9	$	69.5	$	4.4	6	%	$	216.6	$	209.9		$	6.7		3	%
Transportation costs	33.3		28.0		5.3		19	%	88.7		106.9			(18.2)			(17)	%
Production taxes	29.3		27.2		2.1		8	%	81.7		77.4			4.3			6	%
Ad valorem tax expense	11.8		11.8		—		—	%	35.5		32.1			3.4			11	%
Total oil, gas, and NGL production expense	$	148.4	$	136.6	$	11.8	9	%	$	422.4	$	426.2		$	(3.8)		(1)	%
Realized price:
Oil (per Bbl)	$	74.72	$	80.48	$	(5.76)	(7)	%	$	77.08	$	75.90		$	1.18		2	%
Gas (per Mcf)	$	1.46	$	1.40	$	0.06	4	%	$	1.67	$	2.48		$	(0.81)		(33)	%
NGLs (per Bbl)	$	21.70	$	22.86	$	(1.16)	(5)	%	$	22.45	$	23.40		$	(0.95)		(4)	%
Per BOE	$	41.08	$	43.92	$	(2.84)	(6)	%	$	42.42	$	42.47		$	(0.05)		—	%
Per BOE data: (1)
Oil, gas, and NGL production expense:
Lease operating expense	$	4.73	$	4.82	$	(0.09)	(2)	%	$	5.01	$	5.07		$	(0.06)		(1)	%
Transportation costs	2.13		1.94		0.19		10	%	2.05		2.58			(0.53)			(21)	%
Production taxes	1.87		1.89		(0.02)		(1)	%	1.89		1.87			0.02			1	%
Ad valorem tax expense	0.76		0.82		(0.06)		(7)	%	0.82		0.78			0.04			5	%
Total oil, gas, and NGL production expense (1)	$	9.49	$	9.47	$	0.02	—	%	$	9.76	$	10.30		$	(0.54)		(5)	%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	12.98	$	12.46	$	0.52	4	%	$	12.68	$	12.12		$	0.56		5	%
General and administrative	$	2.25	$	2.16	$	0.09	4	%	$	2.23	$	2.04		$	0.19		9	%
Net derivative settlement gain (2)	$	1.05	$	1.15	$	(0.10)	(9)	%	$	1.07	$	0.49		$	0.58		118	%
Earnings per share information (in thousands, except per share data): (3)
Basic weighted-average common shares outstanding	114,405		114,634		(229)		—	%	114,870		119,589			(4,719)			(4)	%
Diluted weighted-average common shares outstanding	114,993		115,715		(722)		(1)	%	115,701		120,165			(4,464)			(4)	%
Basic net income per common share	$	2.10	$	1.83	$	0.27	15	%	$	5.07	$	4.77		$	0.30		6	%
Diluted net income per common share	$	2.09	$	1.82	$	0.27	15	%	$	5.03	$	4.75		$	0.28		6	%

______________________________________

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

(2) Net derivative settlements for the three months ended September 30, 2024, and for the nine months ended September 30, 2024, and 2023, 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 30, 2024, increased seven percent sequentially, consisting of increases of eight percent and six percent from our South Texas and Midland Basin assets, respectively. Average net daily equivalent production increased four percent YTD 2024-over-YTD 2023, consisting of increases of six percent and two percent from our Midland Basin and South Texas assets, respectively. These increases were a result of strong well performance and the timing of well completions. We expect a slight increase in total net equivalent production for the full-year 2024, compared with 2023, driven by well performance and an accelerated pace of development of our existing assets, as well as production from our newly acquired assets in the Uinta Basin.

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. The full-year 2024 trends discussed below include our expectations related to the Uinta Basin Acquisition.

Our realized price on a per BOE basis decreased $2.84 sequentially and remained flat YTD 2024-over-YTD 2023. The sequential decrease primarily resulted from a decrease in oil benchmark prices. For the three months ended September 30, 2024, and June 30, 2024, we recognized net gains on the settlement of our commodity derivative contracts of $1.05 per BOE and $1.15 per BOE, respectively. For the nine months ended September 30, 2024, and 2023, we recognized net gains on the settlement of our commodity derivative contracts of $1.07 per BOE and $0.49 per BOE, respectively.

LOE on a per BOE basis remained relatively flat both sequentially and YTD 2024-over-YTD 2023 as increases in labor costs and certain other operating costs were mostly offset by a decrease in workover expense due to timing of activity. For the full-year 2024, we expect LOE on a per BOE basis to remain relatively flat, compared with 2023, primarily as a result of expected increases in labor costs and certain other operating costs offset by decreases in workover expense and changes in our overall production mix. 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 affect total LOE.

Transportation costs on a per BOE basis increased ten percent sequentially as a result of an eight percent increase in net equivalent production from our South Texas assets, which incur higher transportation costs than our Midland Basin assets. Transportation costs on a per BOE basis in South Texas also increased slightly as a result of expenditures necessary to upgrade certain gathering and transportation infrastructure to handle increasingly liquids-rich production from the Austin Chalk formation. Transportation costs on a per BOE basis decreased 21 percent YTD 2024-over-YTD 2023 primarily as a result of the expiration of a long-term contract in South Texas on June 30, 2023. In general, we expect total transportation costs to fluctuate relative to changes in gas and NGL production from our South Texas assets and oil production from our Uinta Basin assets, where we incur and anticipate incurring a majority of our transportation costs. For the full-year 2024, we expect transportation costs on a per BOE basis to increase compared with 2023, as a result of the addition of our Uinta Basin assets.

Production tax expense on a per BOE basis remained relatively flat both sequentially and YTD 2024-over-YTD 2023. Our overall production tax rate for the three and nine months ended September 30, 2024, was 4.6 percent and 4.4 percent, respectively, compared with 4.3 percent for the three months ended June 30, 2024, and 4.4 percent for the nine months ended September 30, 2023. We expect that our Uinta Basin assets will incur a lower production tax rate compared to our Midland Basin and South Texas assets. 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 decreased seven percent sequentially and increased five percent YTD 2024-over-YTD 2023, as a result of changes to the assessed values of our producing properties. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties changes, which is generally driven by fluctuations in commodity prices.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis increased four percent sequentially primarily as a result of an increase in our DD&A rate due to inflation. DD&A expense on a per BOE basis increased five percent YTD 2024-over-YTD 2023 due to inflation and a slight shift in production mix resulting from higher activity in our Midland Basin assets, which have a higher DD&A rate than our South Texas assets. Our DD&A rate fluctuates as a result of changes in our production mix, changes in our total estimated net proved reserve volumes, changes in capital allocation, impairments, acquisition and divestiture activity, and carrying cost funding and sharing arrangements with third parties. For the full-year 2024, we expect DD&A expense per BOE and on an absolute basis to increase, compared with 2023, primarily as a result of expected increased production, the acquisition of the Uinta Basin assets, and a shift in our production mix.

General and administrative (“G&A”) expense on a per BOE basis increased four percent sequentially and nine percent YTD 2024-over-YTD 2023 primarily as a result of increased compensation expense due to inflation and increases in certain G&A expenses resulting from the Uinta Basin Acquisition. We expect that these factors will lead to an increase in G&A expense per BOE and G&A expense on an absolute basis for the full-year 2024, compared with 2023.

Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2024, and June 30, 2024, and Between the Nine Months Ended September 30, 2024, and 2023 below for additional discussion of operating expenses.

Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2024, and June 30, 2024, and Between the Nine Months Ended September 30, 2024, and 2023

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, 2024, and June 30, 2024:


	Average Net Equivalent Production Increase	Oil, Gas, and NGL Production Revenue Increase	Oil, Gas, and NGL Production Expense Increase
	(MBOE per day)	(in millions)	(in millions)
Midland Basin	4.9		$	4.6	$	2.8
South Texas	6.6		4.4		9.0
Total	11.5		$	8.9	$	11.8

__________________________________________

Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes increased seven percent, consisting of increases of eight percent and six percent from our South Texas and Midland Basin assets, respectively. As a result of decreases in benchmark commodity prices for oil and NGLs, total realized price per BOE decreased six percent. The increase in average net daily equivalent production volumes was partially offset by the decrease in total realized price per BOE resulting in a one percent increase in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense increased nine percent, primarily driven by the impact of the increase in net production volumes on transportation expense and LOE.

YTD 2024-over-YTD 2023 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 nine months ended September 30, 2024, and 2023:


	Average Net Equivalent Production Increase	Oil, Gas, and NGL Production Revenue Increase	Oil, Gas, and NGL Production Expense Increase (Decrease)
	(MBOE per day)	(in millions)	(in millions)
Midland Basin	4.8		$	55.7	$	6.2
South Texas	1.5		22.7		(10.0)
Total	6.4		$	78.4	$	(3.8)

__________________________________________

Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes increased four percent, consisting of increases of six percent and two percent from our Midland Basin and South Texas assets, respectively. Total realized price per BOE remained flat. As a result of the increase in average net daily equivalent production volumes, oil, gas, and NGL production revenue increased four percent. Oil, gas, and NGL production expense decreased one percent, primarily driven by a decrease in transportation expense, partially offset by increases in LOE, production tax expense, and ad valorem tax expense.

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, 2024		June 30, 2024		September 30, 2024		September 30, 2023

	(in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	202.9	$	179.7	$	548.8	$	501.4

DD&A expense increased 13 percent sequentially and nine percent YTD 2024-over-YTD 2023. The sequential quarterly increase was primarily driven by an increase in average net daily equivalent production and an increase in our DD&A rate due to inflation. The YTD 2024-over-YTD 2023 increase resulted from a combination of increased average net daily equivalent production, an increase in our DD&A rate due to inflation, and a slight shift in production mix resulting from higher activity in our Midland Basin assets, which have a higher DD&A rate than our South Texas assets. Please refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of DD&A expense on a per BOE basis.

Exploration


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2024		June 30, 2024		September 30, 2024		September 30, 2023

	(in millions)
Geological, geophysical, and other expenses	$	3.0	$	8.7	$	22.7	$	20.7
Overhead	9.1		8.4		25.1		22.9
Total	$	12.1	$	17.1	$	47.8	$	43.6

Exploration expense decreased 29 percent sequentially primarily due to a decrease in geological and geophysical expenses, partially offset by an increase in exploration overhead expense. The YTD 2024-over-YTD 2023 increase of 10 percent primarily resulted from expenses incurred related to one well deemed non-commercial, which primarily affected the three months ended March 31, 2024. 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.

General and administrative


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2024		June 30, 2024		September 30, 2024		September 30, 2023

	(in millions)
General and administrative	$	35.1	$	31.1	$	96.4	$	84.4

G&A expense increased 13 percent sequentially and 14 percent YTD 2024-over-YTD 2023 as a result of increases in compensation expense due to inflation and increases in certain G&A expenses resulting from the Uinta Basin Acquisition. Please refer to the section Overview of Selected Production and Financial Information, Including Trends above for 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, 2024		June 30, 2024		September 30, 2024		September 30, 2023

	(in millions)
Net derivative (gain) loss	$	(86.3)	$	(12.1)	$	(70.3)	$	12.4

Net derivative (gain) loss is a result of changes in 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. We expect increases in benchmark commodity prices to result in net derivative losses and decreases in benchmark commodity prices to result in net derivative gains, as measured against our derivative contract prices. Please refer to Note 7 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.

Interest expense


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2024		June 30, 2024		September 30, 2024		September 30, 2023

	(in millions)
Interest expense	$	(50.7)	$	(21.8)	$	(94.4)	$	(67.7)

Interest expense increased 133 percent sequentially and 39 percent YTD 2024-over-YTD 2023. The sequential quarterly and YTD 2024-over-YTD 2023 increases primarily resulted from the issuance of our 2029 Senior Notes and 2032 Senior Notes during the third quarter of 2024 and a $9.0 million fee that was paid to secure firm commitments for up to $1.2 billion of senior unsecured 364-day bridge term loans (“Bridge Facility”) in connection with the Uinta Basin Acquisition. We did not draw on the Bridge Facility, and after issuance of the 2029 Senior Notes and the 2032 Senior Notes on July 25, 2024, we terminated the Bridge Facility, and the associated fees were recognized as interest expense. Total interest expense can vary based on the amount of our outstanding fixed-rate debt securities, fluctuations in the amount of capitalized interest as a result of the timing of the development of our wells in progress, and due to the timing and amount of borrowings under our revolving credit facility. Please refer to Overview of Liquidity and Capital Resources below and to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

Income tax expense


	For the Three Months Ended						For the Nine Months Ended
	September 30, 2024			June 30, 2024			September 30, 2024			September 30, 2023

	(in millions, except tax rate)
Income tax expense	$	(57.1)		$	(53.6)		$	(142.8)		$	(51.6)
Effective tax rate	19.2		%	20.3		%	19.7		%	8.3		%

The sequential quarterly decrease in the effective tax rate is due to the effect of excess tax benefits from share-based payment awards during the third quarter of 2024 and an increased benefit from qualified R&D credits claimed. The YTD 2024-over-YTD 2023 increase in the effective tax rate is primarily due to the benefit recognized from the multi-year R&D credit study which was completed during the third quarter of 2023. The effective tax rate for the three and nine months ended September 30, 2024, reflects the benefit of current R&D credits claimed and we expect to continue to recognize benefits from R&D activities for the remainder of 2024.

Based on current projections, we estimate that after utilization of a portion of the R&D credits, between $25.0 million and $35.0 million of full-year 2024 income tax expense will be current. Please refer to Note 4 - Income Taxes in Part I, Item 1 of this report for additional discussion.

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 effect on our effective tax rate and current tax expense. Effective for tax years beginning after December 31, 2022, the Inflation Reduction Act of 2022 provides for a 15 percent corporate alternative minimum tax (“CAMT”) on corporations with average adjusted financial statement income over $1.0 billion for any three-year period preceding the tax year. Final proposed regulations regarding the CAMT may impact our calculation and the CAMT could become applicable to us beginning in 2025. Please refer to Overview of Liquidity and Capital Resources below and to the Risk Factors section in Part 1, Item 1A of our 2023 Form 10-K.

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 months ended September 30, 2024, we funded our capital expenditures and return of capital program with cash flows from operating activities and cash on hand. For the remainder of 2024, we expect to fund our capital expenditures and return of capital program with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. Although we expect cash flows from these sources to be sufficient for the remainder of 2024, we may also elect to raise funds through new debt or equity offerings or from other sources of financing. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current stockholders could be diluted, and these newly issued securities may have rights, preferences, or privileges senior to those of certain existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs.

During the third quarter of 2024, we issued our 2029 Senior Notes and 2032 Senior Notes. Please see below for discussion on how the net proceeds received were used, and refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

Our credit ratings affect the availability of, and cost for us to borrow, additional funds. Subsequent to September 30, 2024, one major credit rating agency upgraded our credit ratings following the close of the Uinta Basin Acquisition on October 1, 2024, citing our increased size and scale, increased inventory, increased oil percentage of expected production, strong operational performance, our priority of improving our leverage metrics, our ability to consistently generate cash flows, and our use of financial derivative instruments as part of our financial risk management program.

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.

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 financial 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 7 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information about our commodity derivative contracts currently in place and the timing of settlement of those contracts.

Credit Agreement

Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 billion. As of September 30, 2024, the borrowing base and aggregate lender commitments under our Credit Agreement were $2.5 billion and $1.25 billion, respectively. Subsequent to September 30, 2024, we entered into the Second Amendment with our lenders. The Second Amendment amended certain provisions of the Credit Agreement to, among other things, increase the aggregate revolving lender commitments available under the Credit Agreement from $1.25 billion to $2.0 billion and extend the Stated Maturity Date to October 1, 2029. On October 11, 2024, our lenders completed the semi-annual borrowing base redetermination, which resulted in an increase to our borrowing base to $3.0 billion and reaffirmed the aggregate revolving lender commitment at the existing amount of $2.0 billion. 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 borrowing base redetermination date is scheduled to occur on April 1, 2025. 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 30, 2024, and through the filing of this report.

We had no revolving credit facility borrowings during the nine months ended September 30, 2024, or at any time during 2023. Subsequent to September 30, 2024, we borrowed under our revolving credit facility to fund a portion of the Uinta Basin Acquisition as discussed in Note 11 - Acquisitions in Part I, Item 1 of this report. 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, other financing activities, and our capital expenditures, including acquisitions, all impact the amount we borrow under our revolving credit facility.

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 24, 2024, September 30, 2024, and December 31, 2023.

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 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
	September 30, 2024		June 30, 2024		September 30, 2024		September 30, 2023
Weighted-average interest rate	7.3	%	7.1	%	7.2	%	7.1	%
Weighted-average borrowing rate	6.8	%	6.4	%	6.6	%	6.4	%

Our weighted-average interest and weighted-average borrowing rate each increased sequentially and YTD 2024-over-YTD 2023 as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes, which have greater outstanding aggregate principal balances and higher interest rates than our 2025 Senior Notes that we redeemed during the third quarter of 2024. Our weighted-average interest rate was further impacted by an increase in the non-cash amortization of deferred financing costs related to the 2029 Senior Notes and 2032 Senior Notes, which was only partially offset by a decrease related to the 2025 Senior Notes. We expect our weighted-average interest rate and weighted-average borrowing rate to increase for the full-year 2024 compared with 2023. The rates disclosed in the table above for the three and nine months ended September 30, 2024, do not reflect the $9.0 million fee paid to secure the Bridge Facility in connection with the Uinta Basin Acquisition. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

Our weighted-average interest rate and weighted-average borrowing rate are affected by the occurrence and timing of long-term debt issuances and redemptions and the average outstanding balance under our revolving credit facility. Additionally, our weighted-average interest rate is 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 redemption of Senior Notes, such as the accelerated expense recognition of the unamortized deferred financing costs, because these amounts are netted against the associated gain or loss on extinguishment of debt. The 2025 Senior Notes were redeemed on August 26, 2024. After this date, the weighted-average interest rate was no longer impacted by the non-cash amortization of deferred financing costs related to the 2025 Senior Notes.

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, debt obligations, including interest and early repayments or redemptions, dividends, and for repurchases of shares of our outstanding 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 months ended September 30, 2024, we spent $957.2 million on capital expenditures. This amount differs from the costs incurred amount of $956.8 million for the nine months ended September 30, 2024, 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 total 2024 capital program is expected to be between $1.24 billion and $1.26 billion, including capital expenditures related to the development of our recently acquired Uinta Basin assets, but excluding acquisitions.

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 August 26, 2024, we redeemed all of the $349.1 million of aggregate principal amount outstanding of our 2025 Senior Notes. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

During the nine months ended September 30, 2024, and 2023, we repurchased and subsequently retired 1.8 million and 6.3 million shares, respectively, of our common stock at a cost of $84.0 million and $205.1 million, respectively, excluding excise taxes, commissions, and fees. As of September 30, 2024, $500.0 million was available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2027. Please refer to Note 3 - Equity in Part I, Item 1 of this report for additional discussion.

During the nine months ended September 30, 2024, and 2023, we paid $62.1 million and $54.2 million, respectively, in dividends to our stockholders. In the second quarter of 2024, our Board of Directors approved an increase to our fixed dividend policy, pursuant to which we intend to pay $0.80 per share annually, in quarterly increments of $0.20 per share, beginning in the fourth quarter of 2024. We currently intend to continue paying dividends to our stockholders for the foreseeable future, subject to our future earnings, our financial condition, covenants under our Credit Agreement and indentures governing each series of our outstanding Senior Notes, and other factors that could arise. The payment and amount of future dividends remain at the discretion of our Board of Directors.

On October 1, 2024, we used a portion of the net proceeds from the 2029 Senior Notes and 2032 Senior Notes, cash on hand, a portion of the Cash Deposit, and borrowings under our revolving credit facility to fund our proportionate share of the Uinta Basin Acquisition. Please refer to Note 5 - Long-Term Debt and Note 11 - Acquisitions in Part I, Item 1 of this report for additional discussion.

Changes in federal income tax laws could increase our corporate income tax rate and could eliminate or reduce current tax deductions. The CAMT could become applicable to us beginning in 2025. The CAMT and other possible future legislation could reduce our net cash provided by operating activities resulting in a reduction of available funding. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2024, and June 30, 2024, and Between the Nine Months Ended September 30, 2024, and 2023 above for additional discussion.

Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2024, and 2023

The following tables present changes in cash flows between the nine months ended September 30, 2024, and 2023, 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
	2024		2023

	(in millions)
Net cash provided by operating activities	$	1,204.6	$	1,097.9	$	106.7

Net cash provided by operating activities increased for the nine months ended September 30, 2024, compared with the same period in 2023, primarily as a result of a $125.0 million increase in cash received from oil, gas, and NGL production revenue net of transportation costs and production taxes, partially offset by an increase of $40.6 million in cash paid on settled derivative trades and an increase of $34.2 million in cash paid for G&A 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
	2024		2023

	(in millions)
Net cash used in investing activities	$	(957.9)	$	(875.4)	$	(82.5)

Net cash used in investing activities increased for the nine months ended September 30, 2024, compared with the same period in 2023, as a result of a $190.4 million increase in capital expenditures, partially offset by a $109.3 million decrease in cash paid to acquire proved and unproved oil and gas properties in the Midland Basin.

Financing activities


	For the Nine Months Ended September 30,				Amount Change Between Periods
	2024		2023

	(in millions)
Net cash provided by (used in) financing activities	$	974.4	$	(265.5)	$	1,239.9

Net cash provided by (used in) financing activities for the nine months ended September 30, 2024, primarily related to the net cash proceeds of $1.48 billion received from the issuance of our 2029 Senior Notes and 2032 Senior Notes, partially offset by $349.1 million of cash paid to redeem our 2025 Senior Notes, $84.0 million of cash paid, including commissions and fees, to repurchase and subsequently retire 1.8 million shares of our common stock under the Stock Repurchase Program, and $62.1 million of dividends paid to our stockholders.

Net cash used in financing activities for the nine months ended September 30, 2023, related to $205.2 million of cash paid, including commissions and fees, to repurchase and subsequently retire 6.3 million shares of our common stock under the Stock Repurchase Program and $54.2 million of dividends paid to our stockholders.

Interest Rate Risk

We are exposed to market and credit risk due to the floating interest rate associated with any outstanding balance under 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 of 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 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 affect future results of operations and cash

flows. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate Senior Notes, but can affect their fair values. As of September 30, 2024, our outstanding principal amount of fixed-rate debt totaled $2.7 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.

Commodity Price Risk

The prices we receive for our oil, gas, and NGL production directly affect our revenue, profitability, access to capital, ability to return capital to our stockholders, 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 high levels of uncertainty and volatility related to production output from OPEC+, lower than expected oil and gas demand from China, global shipping channel constraints and disruptions, War and Geopolitical Instability, and the potential impacts of these issues on global commodity and financial markets. These circumstances have contributed to inflation, instances of supply chain disruptions, and fluctuations in interest rates, and could have further industry-specific impacts 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 months ended September 30, 2024, a 10 percent decrease in our average realized oil, gas, and NGL prices would have reduced our oil, gas, and NGL production revenue by approximately $150.5 million, $16.4 million, and $16.7 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the nine months ended September 30, 2024, would have offset the declines in oil, gas, and NGL production revenue by approximately $24.3 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 30, 2024, 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 $54.3 million, $26.7 million, and $3.4 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 (“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 months ended September 30, 2024, or through the filing of this report.

Critical Accounting 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 2023 Form 10-K for discussion of our accounting 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 the 2023 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 (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:


	For the Three Months Ended		For the Nine Months Ended
	September 30, 2024		September 30, 2023		September 30, 2024		September 30, 2023



	(in thousands)
Net income (GAAP)	$	240,523	$	222,343	$	582,015	$	570,769
Interest expense	50,682		23,106		94,362		67,713
Interest income	(18,017)		(4,106)		(31,120)		(13,802)
Income tax expense (benefit)	57,127		(45,979)		142,786		51,619
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	202,942		189,353		548,781		501,374
Exploration (1)	10,759		9,071		44,121		40,612

Stock-based compensation expense	6,587		6,038		17,393		14,519
Net derivative (gain) loss	(86,283)		75,355		(70,256)		12,352
Net derivative settlement gain (loss)	16,491		(314)		46,288		20,398


Other, net	706		698		2,126		1,625
Adjusted EBITDAX (non-GAAP)	481,517		475,565		1,376,496		1,267,179
Interest expense	(50,682)		(23,106)		(94,362)		(67,713)
Interest income	18,017		4,106		31,120		13,802
Income tax (expense) benefit	(57,127)		45,979		(142,786)		(51,619)
Exploration (1) (2)	(10,456)		(8,912)		(34,892)		(31,566)
Amortization of deferred financing costs	2,182		1,371		4,925		4,114
Deferred income taxes	45,615		(51,075)		116,522		43,171
Other, net	(8,843)		(8,041)		(36,945)		(22,160)
Net change in working capital	32,040		(52,893)		(15,433)		(57,329)
Net cash provided by operating activities (GAAP)	$	452,263	$	382,994	$	1,204,645	$	1,097,879

____________________________________________

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

(2) For the three and nine months ended September 30, 2024, amounts exclude certain capital expenditures primarily related to one well deemed non-commercial. For the three and nine months ended September 30, 2023, amounts exclude certain capital expenditures primarily related to unsuccessful exploration activity for one well that experienced technical issues during the drilling phase.

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 7 - 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 2023 Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

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

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

Changes in Internal Control Over Financial Reporting

There have been no changes during the third quarter of 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

There have been no material changes to the risk factors as previously disclosed in our 2023 Form 10-K, and Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on July 18, 2024.

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 30, 2024, 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
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 the period end date) (2)
07/01/2024 - 07/31/2024	157,643	$	43.23	—	$	500,000,000
08/01/2024 - 08/31/2024	—	$	—	—	$	500,000,000
09/01/2024 - 09/30/2024	—	$	—	—	$	500,000,000
Total:	157,643	$	43.23	—

___________________________________

(1) 157,643 shares purchased by us in the third quarter of 2024 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs issued under the terms of award agreements granted under the Equity Plan.

(2) During the second quarter of 2024, our Board of Directors re-authorized the existing Stock Repurchase Program, which authorizes us to repurchase up to $500.0 million in aggregate value of our common stock through December 31, 2027. 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. The timing, as well as the number and value of shares repurchased under the Stock Repurchase Program, is determined by certain authorized officers of the Company at their discretion and depends 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 30, 2024, we did not repurchase any shares of our common stock under the Stock Repurchase Program.

Our payment of cash dividends to our stockholders and 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.

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 of 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)
4.1			Indenture, dated as of July 25, 2024, by and between SM Energy Company and U.S. Bank Trust Company, National Association, as trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on July 25, 2024, and incorporated herein by reference)
10.1			Purchase and Sale Agreement dated as of June 27, 2024 by and among XCL AssetCo, LLC, XCL Marketing, LLC, Wasatch Water Logistics, LLC, XCL Resources, LLC and XCL SandCo, LLC, as Seller, and SM Energy Company, as Purchaser, and solely for the limited purposes as set forth therein, Northern Oil and Gas, Inc. (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on June 28, 2024, and incorporated herein by reference)
10.2			Acquisition and Cooperation Agreement dated as of June 27, 2024 by and between SM Energy Company and Northern Oil and Gas, Inc. (filed as Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on June 28, 2024, and incorporated herein by reference)
10.3			First Amendment to Seventh Amended and Restated Credit Agreement, dated as of July 2, 2024, by and among SM Energy Company, a Delaware corporation, each of the Lenders that is a party thereto; and Wells Fargo Bank, National Association, as administrative agent for the Lenders, the Issuing Banks and the Swingline Lender (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on July 8, 2024, and incorporated herein by reference)
1 0.4			Second Amendment to Seventh Amended and Restated Credit Agreement, dated as of October 1, 2024, by and among SM Energy Company, a Delaware corporation, each of the Lenders that is a party thereto; and Wells Fargo Bank, National Association, as administrative agent for the Lenders, the Issuing Banks and the Swingline Lender (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on October 2, 2024, 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.

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 1, 2024	By:	/s/ HERBERT S. VOGEL
		Herbert S. Vogel
		President and Chief Executive Officer
		(Principal Executive Officer)

November 1, 2024	By:	/s/ A. WADE PURSELL
		A. Wade Pursell
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

November 1, 2024	By:	/s/ PATRICK A. LYTLE
		Patrick A. Lytle
		Vice President - Chief Accounting Officer and Controller
		(Principal Accounting Officer)