UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, ~~2022~~2023

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

For the transition period from ____________ to ____________

Commission File Number 001-14039

Callon Petroleum Company


			(Exact Name of Registrant as Specified in Its Charter)


Delaware		64-0844345
State or Other Jurisdiction of Incorporation or Organization		I.R.S. Employer Identification No.

One Briarlake Plaza
2000 W. Sam Houston Parkway S., Suite 2000
Houston,	Texas	77042
Address of Principal Executive Offices		Zip Code


			(281)						589-5200
			Registrant’s Telephone Number, Including Area Code

			Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report

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

Title of Each Class

Trading Symbol(s)

Name of Each Exchange on Which Registered

Common Stock, $0.01 par value

CPE

New York Stock Exchange

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

The Registrant had ~~61,709,682~~68,157,440 shares of common stock outstanding as of July ~~29, 2022.~~28, 2023.

For certain industry specific terms used in this Quarterly Report on Form 10-Q (this “Form 10-Q”), please see “Glossary of Certain Terms” in our Annual Report on Form 10-K for the year ended December 31, ~~2021~~2022 (“~~2021~~2022 Annual Report”).

Table of Contents

Part I. Financial Information

Item 1. Financial Statements

Callon Petroleum Company

Consolidated Balance Sheets

(In thousands, except par and share amounts)

(Unaudited)


		June 30, 2022	December 31, 2021		June 30, 2023	December 31, 2022*
ASSETS	ASSETS			ASSETS
Current assets:	Current assets:			Current assets:
Cash and cash equivalents	Cash and cash equivalents	$6,100	$9,882	Cash and cash equivalents	$3,650	$3,395
Accounts receivable, net	Accounts receivable, net	360,955	232,436	Accounts receivable, net	164,708	237,128
Fair value of derivatives	Fair value of derivatives	—	22,381	Fair value of derivatives	14,960	21,332
Assets held for sale				Assets held for sale	606,614	—
Other current assets	Other current assets	37,960	30,745	Other current assets	37,975	35,783
Total current assets	Total current assets	405,015	295,444	Total current assets	827,907	297,638
Oil and natural gas properties, full cost accounting method:
Oil and natural gas properties, successful efforts accounting method:				Oil and natural gas properties, successful efforts accounting method:

Evaluated properties, net		3,573,282	3,352,821
Unevaluated properties		1,876,531	1,812,827
Proved properties, net				Proved properties, net	4,216,641	4,851,529
Unproved properties				Unproved properties	1,203,168	1,225,768
Total oil and natural gas properties, net	Total oil and natural gas properties, net	5,449,813	5,165,648	Total oil and natural gas properties, net	5,419,809	6,077,297

Other property and equipment, net	Other property and equipment, net	26,332	28,128	Other property and equipment, net	26,596	26,152

Deferred income taxes				Deferred income taxes	198,534	—
Deferred financing costs	Deferred financing costs	14,961	18,125	Deferred financing costs	15,447	18,822

Other assets, net	Other assets, net	52,209	40,158	Other assets, net	77,265	68,560
Total assets	Total assets	$5,948,330	$5,547,503	Total assets	$6,565,558	$6,488,469
LIABILITIES AND STOCKHOLDERS’ EQUITY	LIABILITIES AND STOCKHOLDERS’ EQUITY			LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:	Current liabilities:			Current liabilities:
Accounts payable and accrued liabilities	Accounts payable and accrued liabilities	$606,093	$569,991	Accounts payable and accrued liabilities	$507,471	$536,233

Fair value of derivatives	Fair value of derivatives	301,362	185,977	Fair value of derivatives	1,506	16,197
Liabilities associated with assets held for sale				Liabilities associated with assets held for sale	71,114	—
Other current liabilities	Other current liabilities	134,581	116,523	Other current liabilities	100,701	150,384
Total current liabilities	Total current liabilities	1,042,036	872,491	Total current liabilities	680,792	702,814
Long-term debt	Long-term debt	2,516,337	2,694,115	Long-term debt	2,268,116	2,241,295

Asset retirement obligations	Asset retirement obligations	57,427	54,458	Asset retirement obligations	36,235	53,892

Fair value of derivatives	Fair value of derivatives	21,251	11,409	Fair value of derivatives	1,941	13,415
Other long-term liabilities	Other long-term liabilities	51,942	49,262	Other long-term liabilities	35,802	51,272
Total liabilities	Total liabilities	3,688,993	3,681,735	Total liabilities	3,022,886	3,062,688
Commitments and contingencies	Commitments and contingencies	0	0	Commitments and contingencies
Stockholders’ equity:	Stockholders’ equity:			Stockholders’ equity:
Common stock, $0.01 par value, 130,000,000 and 78,750,000 shares authorized; 61,715,672 and 61,370,684 shares outstanding, respectively		617	614
Common stock, $0.01 par value, 130,000,000 shares authorized; 61,888,356 and 61,621,518 shares outstanding, respectively				Common stock, $0.01 par value, 130,000,000 shares authorized; 61,888,356 and 61,621,518 shares outstanding, respectively	619	616
Capital in excess of par value	Capital in excess of par value	4,018,178	4,012,358	Capital in excess of par value	4,026,340	4,022,194
Accumulated deficit	Accumulated deficit	(1,759,458)	(2,147,204)	Accumulated deficit	(484,287)	(597,029)
Total stockholders’ equity	Total stockholders’ equity	2,259,337	1,865,768	Total stockholders’ equity	3,542,672	3,425,781
Total liabilities and stockholders’ equity	Total liabilities and stockholders’ equity	$5,948,330	$5,547,503	Total liabilities and stockholders’ equity	$6,565,558	$6,488,469

*Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.

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

Callon Petroleum Company

Consolidated Statements of Operations

(In thousands, except per share amounts)

(Unaudited)


		Three Months Ended June 30,		Six Months Ended June 30,			Three Months Ended June 30,		Six Months Ended June 30,
		2022	2021	2022	2021		2023	2022*	2023	2022*
Operating Revenues:	Operating Revenues:					Operating Revenues:
Oil	Oil	$619,812	$333,442	$1,173,061	$600,487	Oil	$421,775	$619,812	$831,331	$1,173,061
Natural gas	Natural gas	64,913	24,080	108,889	48,300	Natural gas	14,423	64,913	38,009	108,889
Natural gas liquids	Natural gas liquids	75,530	36,625	143,148	65,982	Natural gas liquids	40,629	75,530	83,999	143,148
Sales of purchased oil and gas	Sales of purchased oil and gas	153,365	46,252	265,740	85,511	Sales of purchased oil and gas	85,456	153,365	168,990	265,740
Total operating revenues	Total operating revenues	913,620	440,399	1,690,838	800,280	Total operating revenues	562,283	913,620	1,122,329	1,690,838

Operating Expenses:	Operating Expenses:					Operating Expenses:
Lease operating	Lease operating	72,940	46,460	140,268	86,913	Lease operating	76,788	72,940	151,890	140,268
Production and ad valorem taxes	Production and ad valorem taxes	44,873	21,958	82,551	40,397	Production and ad valorem taxes	24,706	44,873	57,427	82,551
Gathering, transportation and processing	Gathering, transportation and processing	23,267	20,031	44,042	38,012	Gathering, transportation and processing	27,338	23,267	53,315	44,042
Exploration						Exploration	1,882	2,410	4,114	4,295
Cost of purchased oil and gas	Cost of purchased oil and gas	155,397	49,249	266,668	90,166	Cost of purchased oil and gas	88,768	155,397	174,829	266,668
Depreciation, depletion and amortization	Depreciation, depletion and amortization	109,409	83,128	212,388	154,115	Depreciation, depletion and amortization	127,348	115,956	253,313	229,599
Impairment of oil and gas properties						Impairment of oil and gas properties	406,898	—	406,898	—
General and administrative	General and administrative	10,909	11,065	28,030	27,864	General and administrative	29,768	20,175	57,566	47,232

Merger, integration and transaction	Merger, integration and transaction	—	—	769	—	Merger, integration and transaction	1,543	—	1,543	769

Total operating expenses	Total operating expenses	416,795	231,891	774,716	437,467	Total operating expenses	785,039	435,018	1,160,895	815,424
Income From Operations		496,825	208,508	916,122	362,813
Income (Loss) From Operations						Income (Loss) From Operations	(222,756)	478,602	(38,566)	875,414

Other (Income) Expenses:	Other (Income) Expenses:					Other (Income) Expenses:
Interest expense, net of capitalized amounts		20,691	24,634	42,249	49,050
Loss on derivative contracts		81,648	190,463	439,948	404,986
Interest expense						Interest expense	47,239	46,995	93,545	94,091
(Gain) loss on derivative contracts						(Gain) loss on derivative contracts	(5,941)	81,648	(31,586)	439,948
Loss on extinguishment of debt	Loss on extinguishment of debt	42,417	—	42,417	—	Loss on extinguishment of debt	—	42,417	—	42,417
Other (income) expense	Other (income) expense	1,051	5,584	269	2,278	Other (income) expense	54	1,051	(6,360)	269
Total other expense		145,807	220,681	524,883	456,314
Total other (income) expense						Total other (income) expense	41,352	172,111	55,599	576,725

Income (Loss) Before Income Taxes	Income (Loss) Before Income Taxes	351,018	(12,173)	391,239	(93,501)	Income (Loss) Before Income Taxes	(264,108)	306,491	(94,165)	298,689
Income tax benefit (expense)	Income tax benefit (expense)	(3,009)	478	(3,493)	1,399	Income tax benefit (expense)	156,212	(3,240)	206,907	(3,153)
Net Income (Loss)	Net Income (Loss)	$348,009	($11,695)	$387,746	($92,102)	Net Income (Loss)	($107,896)	$303,251	$112,742	$295,536

Net Income (Loss) Per Common Share:	Net Income (Loss) Per Common Share:					Net Income (Loss) Per Common Share:
Basic	Basic	$5.64	($0.25)	$6.30	($2.07)	Basic	($1.74)	$4.92	$1.83	$4.80
Diluted	Diluted	$5.62	($0.25)	$6.26	($2.07)	Diluted	($1.74)	$4.90	$1.82	$4.77

Weighted Average Common Shares Outstanding:	Weighted Average Common Shares Outstanding:					Weighted Average Common Shares Outstanding:
Basic	Basic	61,679	46,267	61,583	44,439	Basic	61,856	61,679	61,741	61,583
Diluted	Diluted	61,909	46,267	61,956	44,439	Diluted	61,856	61,909	61,939	61,956

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

Callon Petroleum Company

Consolidated Statements of Stockholders’ Equity

(In thousands)

(Unaudited)

Common Capital in Total
Stock Excess Accumulated Stockholders’
Shares $ of Par Deficit Equity
Balance at December 31, 2021 61,371 $614 $4,012,358 ($2,147,204) $1,865,768
Net income — — — 39,737 39,737
Restricted stock units 6 — 2,790 — 2,790
Common stock issued for Primexx Acquisition 117 1 6,294 — 6,295
Balance at March 31, 2022 61,494 $615 $4,021,442 ($2,107,467) $1,914,590
Net income — — — 348,009 348,009
Restricted stock units 244 2 (1,901) — (1,899)
Common stock issued for Primexx Acquisition (22) — (1,363) — (1,363)
Balance at June 30, 2022 61,716 $617 $4,018,178 ($1,759,458) $2,259,337


	Common		Capital in		Total
	Stock		Excess	Accumulated	Stockholders’
	Shares	$	of Par	Deficit	Equity


Balance at December 31, 2022*	61,622	$616	$4,022,194	($597,029)	$3,425,781
Net income	—	—	—	220,638	220,638
Restricted stock units	3	—	3,339	—	3,339


Balance at March 31, 2023	61,625	$616	$4,025,533	($376,391)	$3,649,758
Net loss	—	—	—	(107,896)	(107,896)
Restricted stock units	263	3	807	—	810


Balance at June 30, 2023	61,888	$619	$4,026,340	($484,287)	$3,542,672


		Common		Capital in		Total		Common		Capital in		Total
		Stock		Excess	Accumulated	Stockholders’		Stock		Excess	Accumulated	Stockholders’
		Shares	$	of Par	Deficit	Equity		Shares	$	of Par	Deficit	Equity
Balance at December 31, 2020		39,759	$398	$3,222,959	($2,512,355)	$711,002
Previously reported at December 31, 2021							Previously reported at December 31, 2021	61,371	$614	$4,012,358	($2,147,204)	$1,865,768
Effect of change in accounting principle							Effect of change in accounting principle	—	—	—	530,732	530,732
Balance at December 31, 2021 as recast*							Balance at December 31, 2021 as recast*	61,371	614	4,012,358	(1,616,472)	2,396,500
Net loss	Net loss	—	—	—	(80,407)	(80,407)	Net loss	—	—	—	(7,715)	(7,715)
Restricted stock units	Restricted stock units	13	—	2,609	—	2,609	Restricted stock units	6	—	2,790	—	2,790
Warrant exercises		6,385	64	134,754	—	134,818
Balance at March 31, 2021		46,157	$462	$3,360,322	($2,592,762)	$768,022
Net loss		—	—	—	(11,695)	(11,695)
Common stock issued for Primexx Acquisition							Common stock issued for Primexx Acquisition	117	1	6,294	—	6,295
Balance at March 31, 2022*							Balance at March 31, 2022*	61,494	$615	$4,021,442	($1,624,187)	$2,397,870
Net income							Net income	—	—	—	303,251	303,251
Restricted stock units	Restricted stock units	132	1	960	—	961	Restricted stock units	244	2	(1,901)	—	(1,899)

Balance at June 30, 2021		46,289	$463	$3,361,282	($2,604,457)	$757,288
Common stock issued for Primexx Acquisition							Common stock issued for Primexx Acquisition	(22)	—	(1,363)	—	(1,363)
Balance at June 30, 2022*							Balance at June 30, 2022*	61,716	$617	$4,018,178	($1,320,936)	$2,697,859

*Financial information for prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.

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

Callon Petroleum Company

Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)


		Six Months Ended June 30,			Six Months Ended June 30,
Cash flows from operating activities:	Cash flows from operating activities:	2022	2021	Cash flows from operating activities:	2023	2022*
Net income (loss)		$387,746	($92,102)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net income				Net income	$112,742	$295,536
Adjustments to reconcile net income to net cash provided by operating activities:				Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	Depreciation, depletion and amortization	212,388	154,115	Depreciation, depletion and amortization	253,313	229,599

Impairment of oil and gas properties				Impairment of oil and gas properties	406,898	—
Amortization of non-cash debt related items, net	Amortization of non-cash debt related items, net	3,201	4,508	Amortization of non-cash debt related items, net	5,245	7,121

Loss on derivative contracts		439,948	404,986
Cash paid for commodity derivative settlements, net		(287,922)	(127,571)
Deferred income tax benefit				Deferred income tax benefit	(204,841)	—
(Gain) loss on derivative contracts				(Gain) loss on derivative contracts	(31,586)	439,948
Cash received (paid) for commodity derivative settlements, net				Cash received (paid) for commodity derivative settlements, net	12,246	(287,922)
Loss on extinguishment of debt	Loss on extinguishment of debt	42,417	—	Loss on extinguishment of debt	—	42,417

Non-cash expense related to share-based awards	Non-cash expense related to share-based awards	956	12,887	Non-cash expense related to share-based awards	5,569	2,686

Other, net	Other, net	5,200	4,511	Other, net	592	5,200
Changes in current assets and liabilities:	Changes in current assets and liabilities:			Changes in current assets and liabilities:
Accounts receivable	Accounts receivable	(130,394)	(67,357)	Accounts receivable	42,571	(123,902)
Other current assets	Other current assets	(7,497)	(7,423)	Other current assets	(6,604)	(7,497)
Accounts payable and accrued liabilities	Accounts payable and accrued liabilities	(18,940)	26,714	Accounts payable and accrued liabilities	(68,710)	(19,280)
Cash received for settlements of contingent consideration arrangements, net		6,492	—

Net cash provided by operating activities	Net cash provided by operating activities	653,595	313,268	Net cash provided by operating activities	527,435	583,906
Cash flows from investing activities:	Cash flows from investing activities:			Cash flows from investing activities:
Capital expenditures	Capital expenditures	(413,939)	(251,003)	Capital expenditures	(498,597)	(344,881)
Acquisition of oil and gas properties	Acquisition of oil and gas properties	(15,945)	(2,215)	Acquisition of oil and gas properties	(14,450)	(15,314)
Deposit for acquisition of oil and gas properties				Deposit for acquisition of oil and gas properties	(36,000)	—
Proceeds from sales of assets				Proceeds from sales of assets	2,113	4,590

Proceeds from sales of assets		4,590	31,611
Cash paid for settlement of contingent consideration arrangement	Cash paid for settlement of contingent consideration arrangement	(19,171)	—	Cash paid for settlement of contingent consideration arrangement	—	(19,171)
Other, net	Other, net	8,709	4,220	Other, net	(1,638)	8,709
Net cash used in investing activities	Net cash used in investing activities	(435,756)	(217,387)	Net cash used in investing activities	(548,572)	(366,067)
Cash flows from financing activities:	Cash flows from financing activities:			Cash flows from financing activities:
Borrowings on Credit Facility		1,724,000	736,500
Payments on Credit Facility		(1,730,000)	(846,500)
Issuance of 7.50% Senior Notes due 2030		600,000	—
Borrowings on credit facility				Borrowings on credit facility	1,524,500	1,724,000
Payments on credit facility				Payments on credit facility	(1,499,500)	(1,730,000)
Issuance of 7.5% Senior Notes due 2030				Issuance of 7.5% Senior Notes due 2030	—	600,000
Redemption of 6.125% Senior Notes due 2024	Redemption of 6.125% Senior Notes due 2024	(467,287)	—	Redemption of 6.125% Senior Notes due 2024	—	(467,287)
Redemption of 9.00% Second Lien Senior Secured Notes due 2025		(339,507)	—
Redemption of 9.0% Second Lien Senior Secured Notes due 2025				Redemption of 9.0% Second Lien Senior Secured Notes due 2025	—	(339,507)

Cash received for settlement of contingent consideration arrangement		8,512	—

Payment of deferred financing costs	Payment of deferred financing costs	(10,542)	—	Payment of deferred financing costs	(50)	(10,542)

Other, net	Other, net	(6,797)	(2,317)	Other, net	(3,558)	1,715
Net cash used in financing activities		(221,621)	(112,317)
Net cash provided by (used in) financing activities				Net cash provided by (used in) financing activities	21,392	(221,621)
Net change in cash and cash equivalents	Net change in cash and cash equivalents	(3,782)	(16,436)	Net change in cash and cash equivalents	255	(3,782)
Balance, beginning of period	Balance, beginning of period	9,882	20,236	Balance, beginning of period	3,395	9,882
Balance, end of period	Balance, end of period	$6,100	$3,800	Balance, end of period	$3,650	$6,100

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

Index to the Notes to the Consolidated Financial Statements


1.	1.	Description of Business and Basis of Presentation	8.	Fair Value Measurements	1.	Description of Business	10.	Fair Value Measurements
2.	2.	Revenue Recognition	9.	Income Taxes	2.	Summary of Significant Accounting Policies	11.	Income Taxes
3.	3.	Acquisitions and Divestitures	10.	Share-Based Compensation	3.	Change in Accounting Principle	12.	Share-Based Compensation
4.	4.	Property and Equipment, Net	11.	Stockholders’ Equity	4.	Revenue Recognition	13.	Stockholders’ Equity
5.	5.	Earnings Per Share	12.	Accounts Receivable, Net	5.	Acquisitions and Divestitures	14.	Accounts Receivable, Net
6.	6.	Borrowings	13.	Accounts Payable and Accrued Liabilities	6.	Property and Equipment, Net	15.	Accounts Payable and Accrued Liabilities
7.	7.	Derivative Instruments and Hedging Activities	14.	Supplemental Cash Flow	7.	Earnings Per Share	16.	Supplemental Cash Flow
8.					8.	Borrowings	17.	Subsequent Events
9.					9.	Derivative Instruments and Hedging Activities

Note 1 ~~- Description of Business and Basis of Presentation~~

— Description of Business

Callon Petroleum Company is an independent oil and natural gas company focused on the acquisition, exploration and sustainable development of high-quality assets in the ~~leading oil plays of South and~~Permian Basin in West Texas. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.

~~The Company’s activities are primarily focused on horizontal development in the Midland and Delaware Basins, both~~

Note 2 — Summary of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford in South Texas. The Company’s primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable cash flow-generating business in the Eagle Ford.Significant Accounting Policies

Basis of Presentation

The accompanying unaudited interim consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances. These financial statements have been prepared pursuant to the rules and regulations of the SEC and therefore do not include all disclosures required for financial statements prepared in conformity with GAAP. In the opinion of management, these financial statements reflect all normal, recurring adjustments and accruals considered necessary to present fairly, in all material respects, the Company’s interim financial position, results of operations and cash flows. However, the results of operations for the periods presented are not necessarily indicative of the results of operations that may be expected for the full year. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications did not have a material impact on prior period financial statements.

Significant Accounting Policies

The Company’s significant accounting policies are described in “Note 2 -— Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its ~~2021~~2022 Annual Report and are supplemented by the notes included in this ~~Quarterly Report on~~ Form 10-Q. The financial statements and related notes included in this ~~report~~Form 10-Q should be read in conjunction with the Company’s ~~2021~~2022 Annual Report.

~~Recently Adopted~~Recast Financial Information for Change in Accounting ~~Standards~~Principle

In ~~August 2020,~~the first quarter of 2023, the Company voluntarily changed its method of accounting for its oil and gas exploration and development activities from the full cost method to the successful efforts method of accounting. Accordingly, the financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the FASB ~~issued ASU No. 2020-06, Debt - Debt with Conversion~~Accounting Standards Codification (“ASC”) 932 “Extractive Activities — Oil and ~~Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06”). ASU 2020-06 was issued to reduce~~Gas.” Although the ~~complexity associated with~~full cost method of accounting ~~for certain financial instruments with characteristics of liabilities and equity. The guidance is~~continues to be ~~applied using either a modified retrospective or a fully retrospective method. ASU 2020-06~~an accepted alternative, the successful efforts method of accounting is ~~effective for fiscal years beginning after December 15, 2021, with early adoption permitted.~~the generally preferred method of the SEC and, because it is more widely used in the industry, the Company expects the change to improve the comparability of its financial statements to its peers. The Company ~~adopted ASU 2020-06~~also believes the successful efforts method provides a more representational depiction of assets and operating results and provides for its investments in oil and natural gas properties to be assessed for impairment in accordance with ASC Topic 360 “Property Plant and Equipment,” rather than valuations based on ~~January 1, 2022. The adoption of ASU 2020-06 did not have a material impact to~~prices and costs prescribed under the ~~Company’s consolidated financial statements or disclosures.~~

~~Recently Issued Accounting Standards~~

~~In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation~~full cost method as of the ~~Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed~~balance sheet date. As required by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04ASC 250 “Accounting Changes and ASU 2021-01 are effective for all entities through December 31, 2022. In April 2022, the FASB proposed to extend the effective date through December 31, 2024; however, a final ruling has not been issued. As of June 30, 2022,Error Corrections”, the Company has ~~not elected to use~~presented the ~~optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to “Note 6 – Borrowings” for discussion~~accumulated effect of the ~~use~~change in accounting principle as a change in the beginning balance of retained earnings (accumulated deficit) of the ~~adjusted LIBO rate~~earliest period presented in ~~connection~~the consolidated financial statements. For detailed information regarding the effects of the change to the successful efforts method, see “Note 3 — Change in Accounting Principle.”

Oil and Natural Gas Properties

Proved oil and natural gas properties. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, associated with ~~borrowings under~~development wells are capitalized to proved oil and gas properties and are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the ~~Company’s Credit Facility (as defined below).~~units-of-production method based on estimated proved developed oil and gas reserves. The calculation of depletion expense takes into consideration estimated asset retirement costs, net of estimated salvage values.

Proved oil and gas properties are assessed for impairment on an asset group basis whenever events and circumstances indicate that there could be a possible decline in the recoverability of the net book value of such property. The Company estimates the expected

future net cash flows of its proved oil and gas properties and compares these undiscounted cash flows to the net book value of the proved oil and gas properties to determine if the net book value is recoverable. If the net book value exceeds the estimated undiscounted future net cash flows, the Company will recognize an impairment to reduce the net book value of the proved oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future development costs and operating costs, and discount rates, which are based on a weighted average cost of capital. There were no impairments of proved oil and gas properties for the three or six months ended June 30, 2022. See “Note 5 — Acquisitions and Divestitures” for details of the impairment recorded in the second quarter of 2023 associated with the assets held for sale classification resulting from the agreement to sell all of the Company’s interests of Callon (Eagle Ford) LLC to Ridgemar Energy Operating, LLC.

The partial sale of a proved property within an existing asset group is accounted for as a normal retirement and no net gain or loss on divestiture is recognized as long as the treatment does not significantly alter the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture is recognized in the consolidated statements of operations for all other sales of proved properties.

Unproved oil and natural gas properties. Unproved oil and gas properties consist of costs incurred in obtaining a mineral interest or a right in a property such as a lease, in addition to broker fees, recording fees and other similar costs. Leasehold costs are classified as unproved until proved reserves are discovered on or otherwise attributed to the property, at which time the related unproved oil and gas property costs are reclassified to proved oil and gas properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves.

The Company evaluates significant unproved oil and gas property costs for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or changes in future plans to develop acreage. Unproved oil and gas properties that are not individually significant are aggregated by asset group, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on the Company’s historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of unproved oil and gas properties are recognized as “Impairment of oil and gas properties” in the consolidated statements of operations.

Exploratory. Exploratory costs, including personnel and other internal costs, geological and geophysical expenses and delay rentals for oil and gas leases, are expensed as incurred. Exploratory well costs are initially capitalized pending the determination of whether proved reserves have been discovered. If proved reserves are discovered, exploratory well costs are capitalized as proved oil and gas properties. If proved reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes.

Capitalized interest. The Company capitalizes interest on expenditures made in connection with exploration and development projects that meet certain thresholds and are not subject to current amortization. For projects that meet these thresholds, interest is capitalized only for the period that activities are in process to bring the projects to their intended use. Capitalized interest cannot exceed interest expense for the period capitalized. During both the three and six months ended June 30, 2023 and 2022, the Company did not have any projects that met the thresholds, therefore, had no capitalized interest.

Assets Held for Sale

From time to time, the Company may market certain oil and gas properties for sale. At the end of each reporting period, the Company evaluates if these assets should be classified as held for sale. The held for sale criteria includes whether management commits to a plan to sell, the asset is available for immediate sale, an active program to locate a buyer exists, the sale of the asset is probable and expected to be completed within a year, the asset is actively being marketed for sale and that it is unlikely that significant changes to the plan will be made. If each of the criteria are met, then the assets and associated liabilities are classified as held for sale. As of June 30, 2023, the assets and liabilities held for sale are in connection with the agreement to sell all of the Company’s interests of Callon (Eagle Ford) LLC to Ridgemar Energy Operating, LLC. This transaction closed on July 3, 2023. See “Note 5 — Acquisitions and Divestitures” for additional details.

Subsequent Events

The Company evaluates subsequent events through the date the financial statements are issued. See “Note 17 — Subsequent Events” for further discussion.

Note ~~2 -~~3 — Change in Accounting Principle

In the first quarter of 2023, the Company voluntarily changed its method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. In general, under successful efforts, exploration costs such as exploratory dry holes, exploratory geophysical and geological costs, delay rentals, unproved leasehold impairments and

exploration overhead are expensed as incurred as opposed to being capitalized under the full cost method of accounting. The successful efforts method also provides for the assessment of potential proved oil and gas property impairments by comparing the net book value of proved oil and gas properties to associated estimated undiscounted future net cash flows. If the net book value exceeds the estimated undiscounted future net cash flows, an impairment is recorded to reduce the net book value to fair value. Under the full cost method of accounting, an impairment would be required if the net book value of oil and natural gas properties exceeds a full cost ceiling using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are recognized more frequently on the divestitures of oil and gas properties under the successful efforts method, as opposed to an adjustment to the net book value of the oil and gas properties under the full cost method.

The “Assets held for sale” and “Impairment of oil and gas properties” line items presented in the tables below are in connection with the agreement to sell all of the Company’s interests of Callon (Eagle Ford) LLC to Ridgemar Energy Operating, LLC. See “Note 5 — Acquisitions and Divestitures” for additional details.

The following tables present the effects of the change to the successful efforts method in the consolidated balance sheets:


	As of June 30, 2023
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands)
Current assets:
Assets held for sale	$—	$606,614	$606,614
Oil and natural gas properties:
Proved properties	10,949,991	(2,442,302)	8,507,689
Accumulated depreciation, depletion, amortization and impairments	(6,597,479)	2,306,431	(4,291,048)
Unproved properties	1,784,428	(581,260)	1,203,168
Total oil and gas properties, net	6,136,940	(717,131)	5,419,809
Deferred income taxes	157,629	40,905	198,534
Total assets	$6,666,704	($101,146)	$6,565,558
Stockholders’ equity:
Accumulated deficit	(383,141)	(101,146)	(484,287)
Total stockholders' equity	3,643,818	(101,146)	3,542,672
Total liabilities and stockholders' equity	$6,666,704	($101,146)	$6,565,558


	As of December 31, 2022
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands)
Oil and natural gas properties:
Proved properties	$10,367,478	($1,099,343)	$9,268,135
Accumulated depreciation, depletion, amortization and impairments	(6,343,875)	1,927,269	(4,416,606)
Unproved properties	1,711,306	(485,538)	1,225,768
Total oil and gas properties, net	5,734,909	342,388	6,077,297
Total assets	$6,146,081	$342,388	$6,488,469
Deferred income taxes (1)	4,279	2,029	6,308
Stockholders’ equity:
Accumulated deficit	(937,388)	340,359	(597,029)
Total stockholders' equity	3,085,422	340,359	3,425,781
Total liabilities and stockholders' equity	$6,146,081	$342,388	$6,488,469

(1) Included in “Other long-term liabilities” in the consolidated balance sheets.

The following tables present the effects of the change to the successful efforts method in the consolidated statements of operations:


	Three Months Ended June 30, 2023
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands, except per share data)
Operating Expenses:
Exploration	$—	$1,882	$1,882
Depreciation, depletion and amortization	135,135	(7,787)	127,348
Impairment of oil and gas properties	—	406,898	406,898
General and administrative	17,149	12,619	29,768
Income (Loss) From Operations	190,856	(413,612)	(222,756)

Other Expenses:
Interest expense	19,520	27,719	47,239

Income (Loss) Before Income Taxes	177,223	(441,331)	(264,108)
Income tax benefit	88,653	67,559	156,212
Net Income (Loss)	$265,876	($373,772)	($107,896)
Net Income (Loss) Per Common Share:
Basic	$4.30		($1.74)
Diluted	$4.30		($1.74)


	Three Months Ended June 30, 2022
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands, except per share data)
Operating Expenses:
Exploration	$—	$2,410	$2,410
Depreciation, depletion and amortization	109,409	6,547	115,956
General and administrative	10,909	9,266	20,175
Income From Operations	496,825	(18,223)	478,602

Other Expenses:
Interest expense	20,691	26,304	46,995

Income Before Income Taxes	351,018	(44,527)	306,491
Income tax expense	(3,009)	(231)	(3,240)
Net Income	$348,009	($44,758)	$303,251
Net Income Per Common Share:
Basic	$5.64		$4.92
Diluted	$5.62		$4.90


	Six Months Ended June 30, 2023
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands, except per share data)
Operating Expenses:
Exploration	$—	$4,114	$4,114
Depreciation, depletion and amortization	258,035	(4,722)	253,313
Impairment of oil and gas properties	—	406,898	406,898
General and administrative	34,290	23,276	57,566
Income (Loss) From Operations	391,001	(429,567)	(38,566)

Other Expenses:
Interest expense	38,673	54,872	93,545

Income (Loss) Before Income Taxes	390,273	(484,438)	(94,165)
Income tax benefit	163,973	42,934	206,907
Net Income	$554,246	($441,504)	$112,742
Net Income Per Common Share:
Basic	$8.98		$1.83
Diluted	$8.95		$1.82


	Six Months Ended June 30, 2022
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands, except per share data)
Operating Expenses:
Exploration	$—	$4,295	$4,295
Depreciation, depletion and amortization	212,388	17,211	229,599
General and administrative	28,030	19,202	47,232
Income From Operations	916,122	(40,708)	875,414

Other Expenses:
Interest expense	42,249	51,842	94,091

Income Before Income Taxes	391,239	(92,550)	298,689
Income tax expense	(3,493)	340	(3,153)
Net Income	$387,746	($92,210)	$295,536
Net Income Per Common Share:
Basic	$6.30		$4.80
Diluted	$6.26		$4.77

The following tables present the effects of the change to the successful efforts method in the consolidated statements of cash flows:


	Six Months Ended June 30, 2023
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands)
Cash flows from operating activities:
Net income	$554,246	($441,504)	$112,742
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	258,035	(4,722)	253,313
Impairment of oil and gas properties	—	406,898	406,898
Amortization of non-cash debt related items, net	2,168	3,077	5,245
Deferred income tax benefit	(161,907)	(42,934)	(204,841)
Non-cash expense related to share-based awards	2,124	3,445	5,569




Net cash provided by operating activities	603,175	(75,740)	527,435
Cash flows from investing activities:
Capital expenditures	(570,223)	71,626	(498,597)
Acquisition of oil and gas properties	(18,564)	4,114	(14,450)
Net cash used in investing activities	(624,312)	75,740	(548,572)
Net change in cash and cash equivalents	255	—	255
Balance, beginning of period	3,395	—	3,395
Balance, end of period	$3,650	$—	$3,650


	Six Months Ended June 30, 2022
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands)
Cash flows from operating activities:
Net income	$387,746	($92,210)	$295,536
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	212,388	17,211	229,599
Amortization of non-cash debt related items, net	3,201	3,920	7,121

Non-cash expense related to share-based awards	956	1,730	2,686
Changes in current assets and liabilities:


Accounts payable and accrued liabilities	(18,940)	(340)	(19,280)
Net cash provided by operating activities	653,595	(69,689)	583,906
Cash flows from investing activities:
Capital expenditures	(413,939)	69,058	(344,881)
Acquisition of oil and gas properties	(15,945)	631	(15,314)
Net cash used in investing activities	(435,756)	69,689	(366,067)
Net change in cash and cash equivalents	(3,782)	—	(3,782)
Balance, beginning of period	9,882	—	9,882
Balance, end of period	$6,100	$—	$6,100

The following tables present the effects of the change to the successful efforts method in the consolidated statements of stockholders’ equity:


	As of June 30, 2023
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands)
Accumulated deficit	($383,141)	($101,146)	($484,287)
Total stockholders’ equity	$3,643,818	($101,146)	$3,542,672


	As of December 31, 2022
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands)
Accumulated deficit	($937,388)	$340,359	($597,029)
Total stockholders’ equity	$3,085,422	$340,359	$3,425,781

Note 4 — Revenue Recognition

Revenue from Contracts with Customers

The Company recognizes oil, natural gas, and NGL production revenue at the point in time when control of the product transfers to the purchaser, which differs depending on the applicable contractual terms. Transfer of control also drives the presentation of gathering, transportation and processing expenses in the consolidated statements of operations. See “Note 3 -— Revenue Recognition” of the Notes to Consolidated Financial Statements in the ~~2021~~2022 Annual Report for more information regarding the types of contracts under which oil, natural gas, and NGL production revenue is generated.

Oil and Gas Purchase and Sale Arrangements

The Company proactively evaluates development plans and looks to enter into pipeline transportation contracts to mitigate market exposures and help ensure certainty of flow for its oil and gas production, in some cases multiple years in advance of development. Additionally, as the Company looks to optimize its operations and reduce exposures, in certain instances, the Company purchases oil and gas from third parties which is utilized to fulfill portions of its pipeline commitments. Sales of purchased oil and gas represent revenues the Company receives from sales of commodities purchased from a third party. The Company recognizes these revenues and the purchase of the third-party commodities, as well as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer.

Accounts Receivable from Revenues from Contracts with Customers

Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at June 30, ~~2022~~2023 and December 31, ~~2021~~2022 of ~~$274.5~~$101.8 million and ~~$171.8~~$174.1 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets.

Prior Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.

Note ~~3 -~~5 — Acquisitions and Divestitures

~~2021 Acquisitions and Divestitures~~Eagle Ford Divestiture

~~Primexx Acquisition~~

On ~~October 1, 2021,~~May 3, 2023, the Company ~~closed~~ onentered into an agreement with Ridgemar Energy Operating, LLC (“Ridgemar”) for the ~~acquisition~~sale of ~~certain producing~~all its oil and gas properties ~~undeveloped acreage and associated infrastructure assets~~ in the ~~Delaware Basin from Primexx Resource Development, LLC (“Primexx”) and BPP Acquisition, LLC (“BPP”)~~Eagle Ford for ~~an adjusted purchase price~~consideration of ~~approximately $444.8~~$655.0 million in cash, subject to customary purchase price adjustments, as well as contingent consideration where the Company could receive up to $45.0 million if the WTI price of oil exceeds certain thresholds in 2024 (the “Eagle Ford Divestiture”). Upon signing, Ridgemar paid approximately $49.1 million as a deposit into a third-party escrow account. The transaction is structured as the acquisition by Ridgemar of 100% of the limited liability company interests of the Company’s wholly owned subsidiary, Callon (Eagle Ford) LLC.

On July 3, 2023, the Company closed the Eagle Ford Divestiture for cash consideration of approximately $551.0 million, inclusive of the deposit paid at signing, ~~8.84~~subject to customary post-closing purchase price adjustments.

As of June 30, 2023, the assets held for sale and the liabilities associated with assets held for sale in the consolidated balance sheets are in connection with the Eagle Ford Divestiture. In May 2023, the Company ceased depreciation on the assets associated with the Eagle Ford Divestiture. As a result of the classification of assets held for sale, an impairment of $406.9 million was recorded against the properties associated with the Eagle Ford Divestiture as the fair value less cost to sell was less than the carrying amount of the net assets. The assets held for sale as of June 30, 2023 were $606.6 million, comprised of approximately $575.1 million of total oil and natural gas properties, net and $31.5 million of other assets. The liabilities associated with assets held for sale as of June 30, 2023 were $71.1 million, comprised of approximately $24.0 million of asset retirement obligations and $47.1 million of other liabilities.

Percussion Acquisition

On May 3, 2023, the Company entered into an agreement (the “Percussion Agreement”) with Percussion Petroleum Management II, LLC (“Percussion”) for the purchase of its oil and gas properties in the Delaware Basin (the “Percussion Acquisition”) for consideration of $475.0 million, which consisted of $255.0 million in cash, inclusive of the repayment of Percussion’s indebtedness of approximately $220.0 million, and $210.0 million of shares of the Company’s common stock, subject to customary purchase price adjustments. Additionally, the Company would assume Percussion Target’s (as defined below) existing hedges and transportation contract liabilities, and could have to pay up to $62.5 million of contingent consideration if the WTI price of oil exceeds certain thresholds in 2023, 2024, and 2025. Upon signing, the Company paid $36.0 million as a deposit into a third-party escrow account. The transaction is structured as the acquisition by Callon Petroleum Operating Company of 100% of the limited liability company interests of Percussion’s wholly owned subsidiary, Percussion Petroleum Operating II, LLC (“Percussion Target”).

On July 3, 2023, the Company closed the Percussion Acquisition for consideration of approximately $458.6 million, which consisted of $248.6 million in cash, inclusive of the repayment of Percussion Target’s indebtedness of approximately $220.0 million as well as the deposit paid at signing, and approximately 6.3 million shares of the Company’s common stock, ~~and approximately $25.2 million paid upon final closing~~ ~~for total consideration of $880.8 million (the “Primexx Acquisition”),~~ subject to ~~potential adjustments for applicable indemnification claims as discussed below.~~customary post-closing purchase price adjustments. The Company funded the cash portion of the total consideration with ~~borrowings under its Credit Facility. Of~~proceeds from the 8.84 million shares of the Company’s common stock issued upon closing, 2.6 million shares were held in escrow pursuant to the purchase and sale agreements with Primexx and BPP (collectively, the “Primexx PSAs”)~~. Pursuant to the Primexx PSAs, 50% of the shares held in escrow were released six months~~Eagle Ford Divestiture. Immediately after the closing, ~~date, which~~Percussion Target was ~~on April 1, 2022, and the remaining shares~~renamed Callon Permian II, LLC.

The Percussion Acquisition will be released twelve months after the closing date, which will be on October 1, 2022, in each case subject to holdback for the satisfaction of any applicable indemnification claims that may be made under the Primexx PSAs.

Also, pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration structured similarly to the Primexx Acquisition, for an incremental purchase price totaling approximately $31.8 million, net of customary purchase price adjustments, of which $10.7 million closed during the first quarter of 2022.

~~The Primexx Acquisition was~~ accounted for as a business ~~combination;~~ ~~therefore,~~combination. The Company has not completed its initial allocation of the purchase price ~~was allocated~~ to the assets acquired and ~~the~~ liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a

~~risk adjusted discount rate. Certain data necessary to complete the purchase price allocation is not yet available.~~values. The Company ~~expects to complete~~will disclose the ~~purchase price allocation during the 12-month period following the acquisition date.~~

~~The following table sets forth the Company’s~~ preliminary allocation of the ~~total estimated consideration of $912.7 million to the assets acquired and liabilities assumed~~purchase price as ~~of the acquisition date.~~


						Preliminary Purchase Price Allocation
						~~(In thousands)~~
~~Assets:~~
~~Other current assets~~						~~$10,250~~
~~Evaluated oil and natural gas properties~~						~~685,478~~
~~Unevaluated properties~~						~~278,222~~
~~Total assets acquired~~						~~$973,950~~

~~Liabilities:~~
~~Suspense payable~~						~~$16,447~~
~~Other current liabilities~~						~~33,482~~
~~Asset retirement obligation~~						~~1,898~~
~~Other long-term liabilities~~						~~9,425~~
~~Total liabilities assumed~~						~~$61,252~~

~~Total consideration~~						~~$912,698~~

~~Approximately $170.4 million and $308.5 million of revenues and $36.9 million and $65.7 million of direct operating expenses attributed to the Primexx Acquisition are included~~well as other related business combination disclosures in ~~the Company’s consolidated statements of operations~~its Quarterly Report on Form 10-Q for the three ~~and six~~ months ended ~~June~~September 30, ~~2022, respectively.~~2023.

~~Pro Forma Operating Results (Unaudited).~~ The following unaudited pro forma combined condensed financial data for the year ended December 31, 2021 was derived from the historical financial statements of the Company giving effect to the Primexx Acquisition, as if it had occurred on January 1, 2020. The below information reflects pro forma adjustments for the issuance of the Company’s common stock and the borrowings under the Credit Facility as total consideration, as well as pro forma adjustments based on available information and certain assumptions that the Company believes provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Primexx Acquisition.

The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Primexx Acquisition taken place on January 1, 2020 and is not intended to be a projection of future results.

~~For the Year Ended~~

~~December 31, 2021~~

~~(In thousands)~~

~~Revenues~~

~~$2,294,893~~

~~Income from operations~~

~~1,151,493~~

~~Net income~~

~~482,690~~

~~Basic earnings per common share~~

~~$8.37~~

~~Diluted earnings per common share~~

~~$8.13~~

~~Non-Core Asset Divestitures~~

During 2021, we completed divestitures of certain non-core assets in the Delaware Basin, Midland Basin, and Eagle Ford Shale as well as the divestiture of certain non-core water infrastructure for total net proceeds of $179.9 million. The aggregate net proceeds for each of the 2021 divestitures were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves. For additional discussion, see “Note 4 - Acquisitions and Divestitures” of the Notes to Consolidated Financial Statements in the 2021 Annual Report.

Note ~~4 -~~6 — Property and Equipment, Net

As of June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, total property and equipment, net consisted of the following:

June 30, 2022 December 31, 2021
Oil and natural gas properties, full cost accounting method (In thousands)
Evaluated properties $9,667,447 $9,238,823
Accumulated depreciation, depletion, amortization and impairments (6,094,165) (5,886,002)
Evaluated properties, net 3,573,282 3,352,821
Unevaluated properties
Unevaluated leasehold and seismic costs 1,570,069 1,557,453
Capitalized interest 306,462 255,374
Total unevaluated properties 1,876,531 1,812,827
Total oil and natural gas properties, net $5,449,813 $5,165,648
Other property and equipment $57,201 $58,367
Accumulated depreciation (30,869) (30,239)
Other property and equipment, net $26,332 $28,128


	June 30, 2023	December 31, 2022*
Oil and natural gas properties, successful efforts accounting method	(In thousands)
Proved properties	$8,507,689	$9,268,135
Accumulated depreciation, depletion, amortization and impairments	(4,291,048)	(4,416,606)
Proved properties, net	4,216,641	4,851,529
Unproved properties	1,203,168	1,225,768
Total oil and natural gas properties, net	$5,419,809	$6,077,297

Other property and equipment	$40,104	$40,530
Accumulated depreciation	(13,508)	(14,378)
Other property and equipment, net	$26,596	$26,152

The Company capitalized internal costs of employee compensation and benefits, including share-based compensation, directly associated with acquisition, exploration and development activities totaling $11.3 million and $12.1 million

*Financial information for the ~~three months ended June 30, 2022 and 2021, respectively, and $22.9 million and $23.3 million~~prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for ~~the six months ended June 30, 2022 and 2021, respectively.~~

The Company capitalized interest costs to unproved properties totaling $26.3 million and $23.9 million for the three months ended June 30, 2022 and 2021, respectively, and $51.8 million and $47.9 million for the six months ended June 30, 2022 and 2021, respectively.additional information.

Note ~~5 -~~7 — Earnings Per Share

Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted stock units ~~and unexercised warrants~~ outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. For the three ~~and six~~ months ended June 30, ~~2021,~~2023, the Company reported a net loss. As a result, the calculation of diluted weighted average common shares outstanding excluded all potentially dilutive common shares ~~outstanding for those periods.~~outstanding.

The following table sets forth the computation of basic and diluted earnings per share:


		Three Months Ended June 30,		Six Months Ended June 30,			Three Months Ended June 30,		Six Months Ended June 30,
		2022	2021	2022	2021		2023	2022*	2023	2022*
		(In thousands, except per share amounts)					(In thousands, except per share amounts)

Net Income (Loss)	Net Income (Loss)	$348,009	($11,695)	$387,746	($92,102)	Net Income (Loss)	($107,896)	$303,251	$112,742	$295,536
Basic weighted average common shares outstanding	Basic weighted average common shares outstanding	61,679	46,267	61,583	44,439	Basic weighted average common shares outstanding	61,856	61,679	61,741	61,583
Dilutive impact of restricted stock units	Dilutive impact of restricted stock units	230	—	373	—	Dilutive impact of restricted stock units	—	230	198	373

Diluted weighted average common shares outstanding	Diluted weighted average common shares outstanding	61,909	46,267	61,956	44,439	Diluted weighted average common shares outstanding	61,856	61,909	61,939	61,956

Net Income (Loss) Per Common Share	Net Income (Loss) Per Common Share					Net Income (Loss) Per Common Share
Basic	Basic	$5.64	($0.25)	$6.30	($2.07)	Basic	($1.74)	$4.92	$1.83	$4.80
Diluted	Diluted	$5.62	($0.25)	$6.26	($2.07)	Diluted	($1.74)	$4.90	$1.82	$4.77

Restricted stock units (1)	Restricted stock units (1)	26	140	12	882	Restricted stock units (1)	807	26	91	12
Warrants (1)	Warrants (1)	345	1,066	336	3,433	Warrants (1)	481	345	481	336

(1) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

Note ~~6 -~~8 — Borrowings

The Company’s borrowings consisted of the following:

June 30, 2022 December 31, 2021
(In thousands)
6.125% Senior Notes due 2024 $— $460,241
Senior Secured Revolving Credit Facility due 2024 779,000 785,000
9.00% Second Lien Senior Secured Notes due 2025 — 319,659
8.25% Senior Notes due 2025 187,238 187,238
6.375% Senior Notes due 2026 320,783 320,783
8.00% Senior Notes due 2028 650,000 650,000
7.50% Senior Notes due 2030 600,000 —
Total principal outstanding 2,537,021 2,722,921
Unamortized premium on 6.125% Senior Notes — 2,373
Unamortized discount on 9.00% Second Lien Notes — (14,852)
Unamortized premium on 8.25% Senior Notes 2,096 2,477
Unamortized deferred financing costs for Second Lien Notes — (2,910)
Unamortized deferred financing costs for Senior Unsecured Notes (22,780) (15,894)
Total carrying value of borrowings (1)
$2,516,337 $2,694,115


	June 30, 2023	December 31, 2022
	(In thousands)
8.25% Senior Notes due 2025 (1)	$187,238	$187,238
6.375% Senior Notes due 2026	320,783	320,783
Senior Secured Revolving Credit Facility due 2027	528,000	503,000
8.0% Senior Notes due 2028	650,000	650,000
7.5% Senior Notes due 2030	600,000	600,000
Total principal outstanding	2,286,021	2,261,021
Unamortized premium on 8.25% Senior Notes	1,333	1,715
Unamortized deferred financing costs for Senior Notes	(19,238)	(21,441)
Total carrying value of borrowings (2)	$2,268,116	$2,241,295

(1) The Company redeemed all of the outstanding 8.25% Senior Notes due 2025 on August 2, 2023.

(2) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of ~~$15.0~~$15.4 million and ~~$18.1~~$18.8 million as of June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets.

Senior Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility with a syndicate of lenders (the “Credit Facility”) that, as of June 30, ~~2022,~~2023, had a maximum credit amount of $5.0 billion, a borrowing base of $2.0 billion and an elected commitment amount of ~~$1.6~~$1.5 billion, with borrowings outstanding of ~~$779.0~~$528.0 million at a weighted-average interest rate of ~~4.16%~~7.26%, and letters of credit outstanding of $16.4 million. The credit agreement governing the Credit Facility (the “Credit Agreement”) provides for interest-only payments until ~~December 20, 2024~~October 19, 2027 when the ~~credit agreement~~Credit Agreement matures and any outstanding borrowings are due. ~~The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties.~~

The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. On May 2, 2022, as part of the Company’s spring 2022 redetermination, the borrowing base and elected commitment amount of $1.6 billion were reaffirmed.

Borrowings outstanding under the ~~credit agreement~~Credit Agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between ~~1.00%~~0.75% to ~~2.00%~~1.75%, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50%, and the ~~adjusted LIBO rate~~SOFR plus 0.1% (“Adjusted SOFR”) for a one month period plus 1.00%, or (ii) an ~~adjusted LIBO rate for a Eurodollar loan~~Adjusted SOFR plus a margin between ~~2.00%~~1.75% to ~~3.00%~~2.75%. The Company also incurs commitment fees at rates ranging between 0.375% to 0.500% on the unused portion of lender commitments, which are included in “Interest ~~expense, net of capitalized amounts”~~expense” in the consolidated statements of operations.

~~Issuance~~The borrowing base under the Credit Agreement is subject to regular redeterminations in the spring and fall of ~~7.50%~~ ~~Senior Notes and Redemption of~~ ~~6.125%~~ ~~Senior Notes and Second Lien Notes~~

~~On June 9, 2022,~~each year, as well as special redeterminations described in the ~~Company entered into a Purchase~~Credit Agreement, ~~pursuant to~~ which ~~it agreed to issue and sell $600.0 million~~ in aggregate principal amount of 7.50% senior unsecured notes due 2030 (the “7.50% Senior Notes”) in a private placement, which closed on June 24, 2022, for proceeds of approximately $588.0 million, net of underwriting discounts and commissions. The 7.50% Senior Notes mature on June 15, 2030 and interest is payable semi-annually each ~~June 15 and December 15, commencing on December 15, 2022.~~

~~At any time prior to June 15, 2025,~~case may reduce the ~~Company may, from time to time, redeem up to 35% of the aggregate principal~~ amount of the ~~7.50% Senior Notes in an~~borrowing base. On May 1, 2023, as part of the Company’s spring 2023 redetermination, the borrowing base of $2.0 billion and elected commitment amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.50% of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65% of the aggregate principal amount of the 7.50% Senior Notes remains outstanding after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to June 15, 2025, the Company may, at its option, on any one or more occasions, redeem all or a portion of the 7.50% Senior Notes at 100.00% of the principal amount plus an applicable make-whole premium and accrued and unpaid interest. On or after June 15, 2025, the Company may redeem all or a portion of the 7.50% Senior Notes at redemption prices decreasing annually from 103.75% to 100.00% of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain kinds of change of control that are accompanied by a ratings decline, each holder of the 7.50%$1.5 billion were reaffirmed.

1115

Senior Notes may require the Company to repurchase all or a portion of such holder’s 7.50% Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest.

Also on June 9, 2022, the Company directed the trustee of the 6.125% Senior Notes due 2024 (the “6.125% Senior Notes”) and the 9.00% Second Lien Senior Secured Notes due 2025 (the “Second Lien Notes”) to deliver redemption notices with respect to all $460.2 million of its outstanding 6.125% Senior Notes and all $319.7 million of its outstanding Second Lien Notes. On June 24, 2022, the Company deposited with the trustee the proceeds from the offering of the 7.50% Senior Notes, along with borrowings under the Credit Facility, to redeem all of its outstanding 6.125% Senior Notes and Second Lien Notes. The Company recognized a loss on extinguishment of debt of approximately $42.4 million in its consolidated statements of operations as a result of the redemptions, which primarily related to redemption premiums and the write-off of the remaining unamortized premium associated with the 6.125% Senior Notes, partially offset by the write-offs of the remaining unamortized discount associated with the Second Lien Notes and deferred financing costs.

Covenants

The Company’s ~~credit agreement governing the~~ Credit Facility and the indentures governing the 8.25% Senior Notes due 2025, the 6.375% Senior Notes due 2026, the ~~8.00%~~8.0% Senior Notes due 2028, and the ~~7.50%~~7.5% Senior Notes due 2030 (collectively, the “Senior ~~Unsecured~~ Notes”) limit the Company and certain of its subsidiaries with respect to the amount of additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters, along with maintenance of certain financial ratios.

Under the ~~credit agreement,~~Credit Agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter: (1) a Leverage Ratio (as defined in the ~~credit agreement governing the~~ Credit ~~Facility)~~Agreement) of no more than ~~4.00~~3.50 to 1.00 and (2) a Current Ratio (as defined in the ~~credit agreement governing the~~ Credit ~~Facility)~~Agreement) of not less than 1.00 to 1.00. The Company was in compliance with these covenants at June 30, ~~2022.~~2023.

The ~~credit agreement~~Credit Agreement and indentures are subject to customary events of default. If an event of default occurs and is continuing, the holders or lenders may elect to accelerate amounts due (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).

Note ~~7 -~~9 — Derivative Instruments and Hedging Activities

Objectives and Strategies for Using Derivative Instruments

The Company is exposed to fluctuations in oil, natural gas and NGL prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil, natural gas and NGL production. The Company utilizes a mix of collars, swaps, ~~and~~ put and call options, and basis differential swaps to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.

Counterparty Risk and Offsetting

The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.

~~As of June 30, 2022,~~The Company strives to minimize its credit exposure to any individual counterparty and, as such, the Company has outstanding commodity derivative instruments with 10nine counterparties ~~to minimize its credit exposure to any individual counterparty.~~as of June 30, 2023. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s ~~credit agreement.~~Credit Facility. Therefore, each of the Company’s counterparties allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the ~~credit agreement,~~Credit Facility, thus eliminating the need for independent collateral posting.

Because each of the Company’s counterparties has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each counterparty.

While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject

to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument. See “Note ~~8 -~~10 — Fair Value Measurements” for further discussion.

~~Contingent Consideration Arrangements~~

The Company met certain oil pricing thresholds for 2021 associated with certain contingent consideration arrangements described in “Note 8 - Derivative Instruments and Hedging Activities” of the Notes to Consolidated Financial Statements in its 2021 Annual Report. Cash received or paid for settlements of contingent consideration arrangements are classified as cash flows from financing activities or cash flows from investing activities, respectively, up to the divestiture or acquisition date fair value, respectively, with any excess classified as cash flows from operating activities. As a result, the Company received $20.8 million, of which $8.5 million is presented in cash flows from financing activities with the remaining $12.3 million presented in cash flows from operating activities, and paid $25.0 million, of which $19.2 million is presented in cash flows from investing activities with the remaining $5.8 million presented in cash flows from operating activities, in the first quarter of 2022. Both of these contingent consideration arrangements expired at the end of 2021.

Financial Statement Presentation and Settlements

The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value, as ~~“(Gain) loss on derivative contracts” in~~well as settlements during the ~~consolidated statements of operations. Settlements are also recorded~~period, as “(Gain) loss on derivative contracts” in the consolidated statements of operations. The Company presents the fair value of derivative contracts on a net basis in the consolidated balance sheets as they are subject to master netting arrangements. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:


		As of June 30, 2022				As of June 30, 2023
		Presented without		As Presented with		Presented without		As Presented with
		Effects of Netting	Effects of Netting	Effects of Netting		Effects of Netting	Effects of Netting	Effects of Netting
		(In thousands)				(In thousands)
Derivative Assets	Derivative Assets				Derivative Assets
Fair value of derivatives - current	Fair value of derivatives - current	$28,933	($28,933)	$—	Fair value of derivatives - current	$20,387	($5,427)	$14,960
Other assets, net	Other assets, net	$11,485	($11,485)	$—	Other assets, net	$—	$—	$—

Derivative Liabilities	Derivative Liabilities				Derivative Liabilities
Fair value of derivatives - current	Fair value of derivatives - current	($330,295)	$28,933	($301,362)	Fair value of derivatives - current	($6,933)	$5,427	($1,506)
Fair value of derivatives - non-current	Fair value of derivatives - non-current	($32,736)	$11,485	($21,251)	Fair value of derivatives - non-current	($1,941)	$—	($1,941)

As of December 31, 2021
Presented without As Presented with
Effects of Netting Effects of Netting Effects of Netting
(In thousands)
Assets
Commodity derivative instruments $25,469 ($23,921) $1,548
Contingent consideration arrangements 20,833 — 20,833
Fair value of derivatives - current $46,302 ($23,921) $22,381
Commodity derivative instruments $1,119 ($869) $250
Contingent consideration arrangements — — —
Other assets, net $1,119 ($869) $250
Liabilities
Commodity derivative instruments (1)
($184,898) $23,921 ($160,977)
Contingent consideration arrangements (25,000) — (25,000)
Fair value of derivatives - current ($209,898) $23,921 ($185,977)
Commodity derivative instruments ($12,278) $869 ($11,409)
Contingent consideration arrangements — — —
Fair value of derivatives - non-current ($12,278) $869 ($11,409)


	As of December 31, 2022
	Presented without		As Presented with
	Effects of Netting	Effects of Netting	Effects of Netting
	(In thousands)
Derivative Assets
Fair value of derivatives - current	$51,984	($30,652)	$21,332
Other assets, net	$1,343	($889)	$454

Derivative Liabilities
Fair value of derivatives - current	($46,849)	$30,652	($16,197)
Fair value of derivatives - non-current	($14,304)	$889	($13,415)

~~(1) Includes approximately $2.9 million of deferred premiums, which will be paid as the applicable contracts settle.~~

The components of ~~“Loss~~“(Gain) loss on derivative contracts” are as follows for the respective periods:
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 2022 2021
(In thousands)
Loss on oil derivatives $75,910 $177,033 $401,258 $326,594
Loss on natural gas derivatives 5,738 12,816 33,919 15,513
Loss on NGL derivatives — 3,734 4,771 4,872
(Gain) loss on contingent consideration arrangements — (3,120) — 2,617
Loss on September 2020 Warrants liability (1)
— — — 55,390
Loss on derivative contracts $81,648 $190,463 $439,948 $404,986


	Three Months Ended June 30,		Six Months Ended June 30,
	2023	2022	2023	2022
	(In thousands)
(Gain) loss on oil derivatives	($12,937)	$75,910	($36,281)	$401,258
Loss on natural gas derivatives	6,996	5,738	4,695	33,919
Loss on NGL derivatives	—	—	—	4,771


(Gain) loss on derivative contracts	($5,941)	$81,648	($31,586)	$439,948

(1) Further details of the Company’s September 2020 Warrants and the loss on the associated September 2020 Warrants liability are described in “Note 7 - Borrowings”, “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” of the Notes to Consolidated Financial Statements in its 2021 Annual Report.

The components of “Cash ~~paid~~received (paid) for commodity derivative settlements, net” and “Cash received (paid) for settlements of contingent consideration arrangements, net” are as follows for the respective periods:


		Three Months Ended June 30,		Six Months Ended June 30,			Three Months Ended June 30,		Six Months Ended June 30,
		2022	2021	2022	2021		2023	2022	2023	2022
		(In thousands)					(In thousands)
Cash flows from operating activities	Cash flows from operating activities					Cash flows from operating activities
Cash paid on oil derivatives		($162,334)	($82,413)	($257,687)	($122,360)
Cash paid on natural gas derivatives		(21,808)	(1,906)	(26,452)	(3,275)
Cash received (paid) on oil derivatives						Cash received (paid) on oil derivatives	$1,268	($162,334)	($6,130)	($257,687)
Cash received (paid) on natural gas derivatives						Cash received (paid) on natural gas derivatives	11,757	(21,808)	18,376	(26,452)
Cash paid on NGL derivatives	Cash paid on NGL derivatives	(2,255)	(1,090)	(3,783)	(1,936)	Cash paid on NGL derivatives	—	(2,255)	—	(3,783)
Cash paid for commodity derivative settlements, net		($186,397)	($85,409)	($287,922)	($127,571)
Cash received (paid) for commodity derivative settlements, net						Cash received (paid) for commodity derivative settlements, net	$13,025	($186,397)	$12,246	($287,922)
Cash received for settlements of contingent consideration arrangements, net(1)	Cash received for settlements of contingent consideration arrangements, net(1)	$—	$—	$6,492	$—	Cash received for settlements of contingent consideration arrangements, net(1)	$—	$—	$—	$6,492

Cash flows from investing activities	Cash flows from investing activities					Cash flows from investing activities
Cash paid for settlement of contingent consideration arrangement(1)	Cash paid for settlement of contingent consideration arrangement(1)	$—	$—	($19,171)	$—	Cash paid for settlement of contingent consideration arrangement(1)	$—	$—	$—	($19,171)

Cash flows from financing activities	Cash flows from financing activities					Cash flows from financing activities
Cash received for settlement of contingent consideration arrangement(1)	Cash received for settlement of contingent consideration arrangement(1)	$—	$—	$8,512	$—	Cash received for settlement of contingent consideration arrangement(1)	$—	$—	$—	$8,512

(1) See “Note 8 — Derivative Instruments and Hedging Activities” of the Notes to Consolidated Financial Statements in our 2022 Annual Report for discussion of the Company’s contingent consideration arrangements.

Derivative Positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of June 30, ~~2022:~~2023:

For the Remainder For the Full Year
Oil Contracts (WTI) 2022 2023
Swap Contracts
Total volume (Bbls) 3,634,000 1,538,500
Weighted average price per Bbl $64.83 $81.04
Collar Contracts
Total volume (Bbls) 2,392,000 2,730,000
Weighted average price per Bbl
Ceiling (short call) $70.12 $87.15
Floor (long put) $60.00 $71.92
Short Call Swaption Contracts (1)
Total volume (Bbls) — 1,825,000
Weighted average price per Bbl $— $72.00
Oil Contracts (Midland Basis Differential)
Swap Contracts
Total volume (Bbls) 1,196,000 —
Weighted average price per Bbl $0.50 $—

~~(1) The 2023 short call swaption contracts have exercise expiration dates of December 30, 2022.~~


	For the Remainder	For the Full Year
Oil Contracts (WTI)	2023	2024
Swap Contracts
Total volume (Bbls)	460,000	—
Weighted average price per Bbl	$82.10	$—






Collar Contracts
Total volume (Bbls)	920,000	—
Weighted average price per Bbl
Ceiling (short call)	$90.00	$—
Floor (long put)	$70.00	$—
Put Contracts
Total volume (Bbls)	736,000	—
Weighted average price per Bbl	$70.00	$—

1418


		For the Remainder	For the Full Year		For the Remainder	For the Full Year
Natural Gas Contracts (Henry Hub)	Natural Gas Contracts (Henry Hub)	2022	2023	Natural Gas Contracts (Henry Hub)	2023	2024
Swap Contracts	Swap Contracts			Swap Contracts
Total volume (MMBtu)	Total volume (MMBtu)	6,150,000	—	Total volume (MMBtu)	2,460,000	—
Weighted average price per MMBtu	Weighted average price per MMBtu	$3.62	$—	Weighted average price per MMBtu	$3.00	$—
Collar Contracts	Collar Contracts			Collar Contracts
Total volume (MMBtu)	Total volume (MMBtu)	5,510,000	6,640,000	Total volume (MMBtu)	3,217,643	1,820,000
Weighted average price per MMBtu	Weighted average price per MMBtu			Weighted average price per MMBtu
Ceiling (short call)	Ceiling (short call)	$5.96	$6.60	Ceiling (short call)	$5.58	$6.00
Floor (long put)	Floor (long put)	$4.21	$4.48	Floor (long put)	$3.43	$3.00

Natural Gas Contracts (Waha Basis Differential)	Natural Gas Contracts (Waha Basis Differential)			Natural Gas Contracts (Waha Basis Differential)
Swap Contracts				Swap Contracts
Total volume (MMBtu)				Total volume (MMBtu)	4,300,000	3,660,000
Weighted average price per MMBtu				Weighted average price per MMBtu	($1.09)	($1.05)

Natural Gas Contracts (HSC Basis Differential)				Natural Gas Contracts (HSC Basis Differential)
Swap Contracts	Swap Contracts			Swap Contracts
Total volume (MMBtu)	Total volume (MMBtu)	1,220,000	6,080,000	Total volume (MMBtu)	5,520,000	14,640,000
Weighted average price per MMBtu	Weighted average price per MMBtu	($0.75)	($0.75)	Weighted average price per MMBtu	($0.29)	($0.42)

Note ~~8 -~~10 — Fair Value Measurements

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2 – Other inputs that are observable directly or indirectly, such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 – Unobservable inputs for which there is little or no market data and for which the Company makes its own assumptions about how market participants would price the assets and liabilities.

Fair Value of Financial Instruments

Cash, Cash Equivalents, and Restricted Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.

Debt. The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the ~~Company’s Second Lien Notes and~~ Senior ~~Unsecured~~ Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. ~~See “Note 6 - Borrowings” for further discussion.~~

June 30, 2022 December 31, 2021
Principal Amount Fair Value Principal Amount Fair Value
(In thousands)
6.125% Senior Notes $— $— $460,241 $455,639
9.00% Second Lien Notes — — 319,659 343,633
8.25% Senior Notes 187,238 183,025 187,238 184,429
6.375% Senior Notes 320,783 295,409 320,783 309,556
8.00% Senior Notes 650,000 625,144 650,000 663,000
7.50% Senior Notes 600,000 554,466 — —
Total $1,758,021 $1,658,044 $1,937,921 $1,956,257


	June 30, 2023		December 31, 2022
	Principal Amount	Fair Value	Principal Amount	Fair Value
	(In thousands)


8.25% Senior Notes	$187,238	$186,952	$187,238	$186,719
6.375% Senior Notes	320,783	312,054	320,783	301,732
8.0% Senior Notes	650,000	643,000	650,000	616,935
7.5% Senior Notes	600,000	566,424	600,000	550,812
Total	$1,758,021	$1,708,430	$1,758,021	$1,656,198

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheets. The following methods and assumptions were used to estimate fair value:

Commodity Derivative Instruments. The fair value of commodity derivative instruments is derived using a third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity

derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and as there is a wide availability of quoted market prices for

similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note ~~7 -~~9 — Derivative Instruments and Hedging Activities” for further discussion.

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of June 30, ~~2022~~2023 and December 31, ~~2021:~~2022:

June 30, ~~2022~~2023

Level 1

Level 2

Level 3

(In thousands)

Commodity derivative assets

$—

$14,960

$—

Commodity derivative liabilities

$—

($~~322,613)~~3,447)

$—

December 31, ~~2021~~2022

Level 1

Level 2

Level 3

(In thousands)

~~Assets~~

Commodity derivative ~~instruments~~assets

$—

$~~1,798~~21,786

$—

~~Contingent consideration arrangements~~Commodity derivative liabilities

$—

~~20,833~~

—

~~Liabilities~~

~~Commodity derivative instruments~~ ~~(1)~~

—

~~(172,386)~~

—

~~Contingent consideration arrangements~~

—

~~(25,000)~~

—

~~Total net assets (liabilities)~~

$—

($~~174,755)~~29,612)

$—

~~(1) Includes approximately $2.9 million of deferred premiums, which will be paid as the applicable contracts settle.~~

There were no transfers between any of the fair value levels during any period presented.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

~~Acquisitions.~~ The fair value of assets acquired and liabilities assumed are measured as of the acquisition date by a third-party valuation specialist using a combination of income and market approaches, which are not observable in the market and are therefore designated as Level 3 inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and costs to produce and develop reserves, oil and natural gas forward prices, and a risk-adjusted discount rate. See “Note 3 - Acquisitions and Divestitures” for additional discussion.

Asset Retirement Obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and that, therefore, are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities, restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates.

Note ~~9 -~~11 — Income Taxes

The Company provides for income taxes at the statutory rate of 21%. Reported income tax ~~benefit (expense)~~expense differs from the amount of income tax ~~benefit (expense)~~expense that would result from applying domestic federal statutory tax rates to pretax ~~income (loss).~~income. These differences primarily relate to non-deductible executive compensation expenses, restricted stock unit windfalls, changes in valuation allowances, and state income taxes.

For the three months ended June 30, 2022 and 2021, the Company’s effective income tax rates were 1% and 4%, respectively. For both the six months ended June 30, 2022 and 2021, the Company’s effective income tax rate was 1%. The primary differences between the effective tax rates for the three and six months ended June 30, ~~2022~~2023, the Company recognized income tax benefit of $156.2 million and ~~2021 and~~$206.9 million, respectively, as a result of the ~~statutory rate resulted from~~release of the valuation allowance recorded against the Company’s net deferred tax assets ~~beginning~~as discussed further below. For both the three and six months ended June 30, 2022, the Company recognized income tax expense of $3.2 million as a result of the full valuation allowance that was in ~~the second quarter of 2020~~place and the effect of state income taxes.

Deferred Tax Asset Valuation Allowance

Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that

the Company’s net deferred tax assets will be utilized prior to their expiration. ~~A significant item of objective negative evidence considered was~~As previously disclosed in the ~~cumulative historical three-year pre-tax loss and a net deferred tax asset position at June 30,~~Company’s 2022 ~~driven primarily by the impairments of evaluated oil and gas properties recognized~~Annual Report, beginning in the second quarter of 2020 and ~~continuing~~ through the fourth quarter of ~~2020. This limits~~2022, the ~~ability to consider other subjective~~Company maintained a valuation allowance against its net deferred tax assets. Considering all available evidence ~~such as the Company’s potential for future growth. Since the second quarter of 2020, based on the evaluation of the evidence available,~~(both positive and negative), the Company concluded that it ~~is more likely than~~

~~not that the net deferred tax assets will not be realized. As a result, the Company has recorded a valuation allowance, reducing the net deferred tax assets as of June 30, 2022 to zero.~~

The Company currently believes it is reasonably possible it could achieve a three-year cumulative level of profitability within the next 12 months, which would enhance its ability to conclude that it iswas more likely than not that the deferred tax assets would be realized and support a release of substantially all or a portion of the valuation allowance. However, the exact timing and amount of the release is unknown at this time. The Company will continue to evaluate whetherreleased the valuation allowance ~~is needed~~ in ~~future reporting periods based on available information each reporting period. As long as~~ the ~~Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant~~first quarter of 2023. This release resulted in a deferred income tax ~~expense or benefit. The valuation allowance does not preclude~~benefit of $152.9 million and $204.8 million for the ~~Company from utilizing the tax attributes if it recognizes taxable income.~~three and six months ended June 30, 2023, respectively.

Note ~~10 -~~12 — Share-Based Compensation

RSU Equity Awards

The following table summarizes activity for restricted stock units that may be settled in common stock (“RSU Equity Awards”) for the six months ended June 30, ~~2022:~~2023:


		Six Months Ended June 30, 2022			Six Months Ended June 30, 2023
		RSU Equity Awards (In thousands)	Weighted Average Grant Date Fair Value		RSU Equity Awards (In thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	Unvested, beginning of the period	968	$34.04	Unvested, beginning of the period	800	$44.79
Granted	Granted	355	$60.02	Granted	502	$34.21
Vested	Vested	(354)	$35.28	Vested	(367)	$39.87
Forfeited	Forfeited	(42)	$14.59	Forfeited	(93)	$44.24
Unvested, end of the period	Unvested, end of the period	927	$22.66	Unvested, end of the period	842	$40.68

Grant activity for the six months ended June 30, ~~2022~~2023 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards with a weighted-average grant date fair value of ~~$60.02~~.$34.21.

The aggregate fair value of RSU Equity Awards that vested during the six months ended June 30, ~~2022~~2023 was ~~$21.5~~$12.3 million. As of June 30, ~~2022,~~2023, unrecognized compensation costs related to unvested RSU Equity Awards were ~~$33.2~~$29.3 million and will be recognized over a weighted average period of ~~2.2~~2.1 years.

Cash-Settled Awards

NoAs of June 30, 2023 and December 31, 2022, the Company had a total liability of $3.3 million and $6.5 million, respectively, which, as of December 31, 2022, consisted of restricted stock ~~units~~unit awards that may be settled in cash (“Cash-Settled RSU Awards”) ~~or cash-settled~~and stock appreciation rights to be settled in cash (“Cash SARs”~~) were granted to employees during~~ and, collectively with the ~~three or six months ended~~Cash-Settled RSU Awards, the “Cash-Settled Awards”). As of June 30, ~~2022 or 2021. The following table summarizes the Company’s liabilities for cash-settled awards and the classification in the consolidated balance sheets for the periods indicated:~~

June 30, 2022 December 31, 2021
(In thousands)
Cash SARs $6,306 $7,884
Cash-Settled RSU Awards 1,287 1,382
Other current liabilities 7,593 9,266
Cash-Settled RSU Awards 1,406 6,366
Other long-term liabilities 1,406 6,366
Total Cash-Settled RSU Awards $8,999 $15,632

2023, there were no Cash-Settled RSU Awards outstanding.

Share-Based Compensation Expense (Benefit), Net

Share-based compensation expense associated with the RSU Equity Awards and the Cash-Settled ~~RSU~~ Awards ~~and Cash SARs, net of amounts capitalized,~~ is included in “General and administrative” in the consolidated statements of operations. The following table presents share-based compensation expense (benefit), net for the periods indicated:

Three Months Ended
June 30, Six Months Ended
June 30,
2022 2021 2022 2021
(In thousands)
RSU Equity Awards $4,323 $3,242 $7,689 $5,850
Cash-Settled RSU Awards (3,662) 3,007 (3,425) 7,449
Cash SARs (4,018) 3,676 (1,578) 8,542
(3,357) 9,925 2,686 21,841
Less: amounts capitalized to oil and gas properties 147 (4,646) (1,730) (8,954)
Total share-based compensation expense (benefit), net ($3,210) $5,279 $956 $12,887


	Three Months Ended June 30,		Six Months Ended June 30,
	2023	2022*	2023	2022*
	(In thousands)
RSU Equity Awards	$4,081	$4,323	$7,707	$7,689
Cash-Settled Awards	(393)	(7,680)	(2,138)	(5,003)
Total share-based compensation expense (benefit), net	$3,688	($3,357)	$5,569	$2,686

See “Note 10 -— Share-Based Compensation” of the Notes to Consolidated Financial Statements in the ~~2021~~2022 Annual Report for details of the Company’s equity-based incentive plans.

Note 1113 - Stockholders’ Equity

~~Increase in Authorized Common Shares~~

~~The~~On May 2, 2023, the board of directors (the “Board”) of the Company ~~filed an amendment~~approved a share repurchase program (the “Share Repurchase Program”), pursuant to which the Company is authorized to repurchase up to $300.0 million of its ~~certificate of incorporation, which became effective on May 25, 2022, to increase the number of authorized shares of~~outstanding common stock through the second quarter of 2025, contingent upon the consummation of the Eagle Ford Divestiture and the Percussion Acquisition, both of which closed on July 3, 2023. Repurchases under the Share Repurchase Program may be made, from ~~78,750,000~~time to ~~130,000,000, as approved~~time, in amounts and at prices the Company deems appropriate and will be subject to a variety of factors, including the market price of the Company’s common stock, general market and economic conditions and applicable legal requirements. The Share Repurchase Program may be suspended, modified or discontinued by the ~~Company’s shareholders~~Board at ~~the 2022 Annual Meeting of Shareholders on May 25, 2022.~~

~~Note 12 - Accounts Receivable, Net~~

June 30, 2022 December 31, 2021
(In thousands)
Oil and natural gas receivables $274,476 $171,837
Joint interest receivables 15,434 13,751
Other receivables 73,273 49,053
Total 363,183 234,641
Allowance for credit losses (2,228) (2,205)
Total accounts receivable, net $360,955 $232,436

~~Note 13 - Accounts Payable and Accrued Liabilities~~

June 30, 2022 December 31, 2021
(In thousands)
Accounts payable $221,044 $151,836
Revenues and royalties payable 284,470 294,143
Accrued capital expenditures 60,492 64,412
Accrued interest 40,087 59,600
Total accounts payable and accrued liabilities $606,093 $569,991
any time without prior notice.

1821

Note 14 -— Accounts Receivable, Net


	June 30, 2023	December 31, 2022
	(In thousands)
Oil and natural gas receivables	$101,849	$174,107
Joint interest receivables	23,856	16,778
Other receivables	40,171	48,277
Total	165,876	239,162
Allowance for credit losses	(1,168)	(2,034)
Total accounts receivable, net	$164,708	$237,128

Note 15 — Accounts Payable and Accrued Liabilities


	June 30, 2023	December 31, 2022
	(In thousands)
Accounts payable	$177,430	$191,133
Revenues and royalties payable	194,346	244,408
Accrued capital expenditures	93,203	58,395
Accrued interest	42,492	42,297
Total accounts payable and accrued liabilities	$507,471	$536,233

Note 16 — Supplemental Cash Flow

Six Months Ended June 30,
2022 2021
(In thousands)
Supplemental cash flow information:
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases $15,149 $14,576
Investing cash flows from operating leases 19,318 8,402
Non-cash investing and financing activities:
Change in accrued capital expenditures $56,213 $47,247
Change in asset retirement costs 2,237 2,567
ROU assets obtained in exchange for lease liabilities:
Operating leases $26,971 $9,710


	Six Months Ended June 30,
	2023	2022*
	(In thousands)
Supplemental cash flow information:
Interest paid	$88,097	$105,985
Income taxes paid (1)	4,477	—



Non-cash investing and financing activities:
Change in accrued capital expenditures	$54,377	$56,213
Change in asset retirement costs	1,848	2,237

(1) The Company did not pay or receive a refund for any federal income tax for the six months ended June 30, 2022. For the six months ended June 30, 2023 and 2022, the Company had net payments of $2.3 million and $0.2 million, respectively, for state income taxes.

Note 17 — Subsequent Events

Acquisition and Divestiture

On July 3, 2023, the Company closed the Percussion Acquisition and the Eagle Ford Divestiture. See “Note 5 — Acquisitions and Divestitures” for additional details.

1922

As part of the Percussion Acquisition, the Company assumed all of Percussion Target’s oil, natural gas, and NGL hedge contracts, which are presented in the following tables:


	For the Remainder	For the Full Year
Oil Contracts (WTI)	2023	2024
Collar Contracts (Three-Way Collars)
Total volume (Bbls)	1,034,556	3,963,023
Weighted average price per Bbl
Ceiling (short call)	$70.20	$78.86
Floor (long put)	$55.00	$58.16
Floor (short put)	$45.00	$48.16
Collar Contracts (Two-Way Collars)
Total volume (Bbls)	309,054	—
Weighted average price per Bbl
Ceiling (short call)	$72.40	$—
Floor (long put)	$60.00	$—
CMA Roll Swap Contracts
Total volume (Bbls)	1,512,363	—
Weighted average price per Bbl	$0.30	$—


	For the Remainder	For the Full Year
Natural Gas Contracts (Henry Hub)	2023	2024
Collar Contracts
Total volume (MMBtu)	555,755	6,778,555
Weighted average price per MMBtu
Ceiling (short call)	$3.69	$3.33
Floor (long put)	$2.86	$3.00
Natural Gas Contracts (Waha Basis Differential)
Swap Contracts
Total volume (MMBtu)	1,840,000	3,660,000
Weighted average price per MMBtu	($1.94)	($1.07)


	For the Remainder	For the Full Year
NGL Contracts (Mont Belvieu Natural Gasoline)	2023	2024
Swap Contracts
Total volume (Bbls)	83,510	—
Weighted average price per Bbl	$56.31	$—
NGL Contracts (Mont Belvieu Propane)
Swap Contracts
Total volume (Bbls)	71,831	—
Weighted average price per Bbl	$31.37	$—
NGL Contracts (Mont Belvieu Purity Ethane)
Swap Contracts
Total volume (Bbls)	70,428	—
Weighted average price per Bbl	$9.66	$—
NGL Contracts (Mont Belvieu Normal Butane)
Swap Contracts
Total volume (Bbls)	64,606	72,105
Weighted average price per Bbl	$35.60	$33.18
NGL Contracts (Mont Belvieu Isobutane)
Swap Contracts
Total volume (Bbls)	21,141	23,462
Weighted average price per Bbl	$35.47	$33.18

Redemption of 8.25% Senior Notes

On July 3, 2023, the Company delivered a redemption notice with respect to all $187.2 million of its outstanding 8.25% Senior Notes due 2025 (the “2025 Notes”). The Company redeemed the 2025 Notes on August 2, 2023 using borrowings under the Company’s Credit Facility.

Special Note Regarding ~~Forward Looking~~Forward-Looking Statements

This ~~report~~Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-Q by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.

All statements, other than statements of historical facts, included in this ~~report~~Form 10-Q that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements ~~including such things as:~~may include statements regarding the following (to the extent not historical):

•our oil and natural gas reserve quantities and the discounted present value of these reserves;

•the amount and nature of our capital expenditures;

•our future drilling and development plans and our potential drilling locations;

•the timing and amount of future capital and operating costs;

•production decline rates from our wells being greater than expected;

•commodity price risk management activities and the impact on our average realized prices;

•business strategies and plans of management;

•our ability to efficiently integrate recent acquisitions; and

•prospect development and property acquisitions.

We caution you that the forward-looking statements contained in this Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. We disclose these and other important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” in Part I, Item 1A of our ~~2021~~2022 Annual Report. These factors include:

•the volatility of oil, natural gas and NGL prices or a prolonged period of low oil, natural gas or NGL prices;

•general economic conditions, including the availability of credit, ~~and~~ access to existing lines of ~~credit;~~credit, inflation and rising interest rates;

•changes in the supply of and demand for oil and natural gas, including as a result of ~~the COVID-19 pandemic and various governmental actions taken to mitigate its impact or~~ actions by, or disputes among, members of OPEC and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil;

•the uncertainty of estimates of oil and natural gas reserves;

•impairments;

•the impact of competition;

•the availability and cost of ~~seismic,~~ drilling ~~completions~~rigs, pressure pumping equipment and crews, other equipment, ~~waste~~supplies, water, personnel and ~~water disposal infrastructure,~~oil field services;

•our dependency on third-party service providers;

•restrictions on our ability to obtain, recycle and ~~personnel;~~dispose of water;

•operating hazards inherent in the exploration for and production of oil and natural gas;

•difficulties encountered during the exploration for and production of oil and natural gas;

•physical risks arising from climate change;

•the potential impact of future drilling on production from existing wells;

•difficulties encountered in delivering oil and natural gas to commercial ~~markets;~~markets and the availability and capacity of gas processing facilities and pipelines and other transportation operations owned and operated by third parties;

•the uncertainty of our ability to attract capital and obtain financing on favorable terms;

•our ability to keep pace with technological developments in our industry;

•compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases;

•the impact of government regulation, including regulation of hydraulic fracturing and water disposal wells;

•climate-related transition risks, including evolving climate change legislation, fuel conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry, which could result in increased operating expenses and capital costs, financial risks and potential reduction in demand for oil and natural gas;

•any increase in severance or similar taxes;

•the financial impact of accounting regulations and critical accounting policies;

•the comparative cost of alternative fuels;

•credit risk relating to the risk of loss as a result of non-performance by our counterparties;

•cyberattacks on the Company or on systems and infrastructure used by the oil and natural gas industry;

•weather conditions; and

•risks associated with ~~acquisitions.~~acquisitions, including the Percussion Acquisition.

Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Additional risks or uncertainties that are not currently known to us, that we currently deem to be immaterial, or that could apply to any company could also materially adversely affect our business, financial condition, or future results. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

In addition, we caution that reserve engineering is a process of estimating oil and natural gas accumulated underground and cannot be measured exactly. Accuracy of reserve estimates depend on a number of factors including data available at the point in time, engineering interpretation of the data, and assumptions used by the reserve engineers as it relates to price and cost estimates and recoverability. New results of drilling, testing, and production history may result in revisions of previous estimates and, if significant,

would impact future development plans. As such, reserve estimates may differ from actual results of oil and natural gas quantities ultimately recovered.

Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

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

The following management’s discussion and analysis describes the principal factors affecting our results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with ~~the accompanying unaudited~~our consolidated financial statements and accompanying notes included under Part I, Item I, “Financial Statements” of this Form 10-Q, as well as our ~~2021~~consolidated financial statements, accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our 2022 Annual ~~Report, which include additional~~Report.

Financial information ~~about our business practices, significant~~for all prior periods has been recast to reflect the retrospective application of the successful efforts method of accounting, ~~policies, risk factors, and~~as discussed under “Note 2 — Summary of Significant Accounting Policies” of the ~~transactions that underlie our financial results.~~Notes to Consolidated Financial Statements in this Form 10-Q.

General

We are an independent oil and natural gas company focused on the acquisition, exploration and sustainable development of high-quality assets in the ~~leading oil plays of South and West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger~~ Permian Basin in West ~~Texas, as well as the Eagle Ford in South~~ Texas.

Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals in the Permian, including multiple ~~levels~~layers of the Wolfcamp ~~formation~~and Bone Springs formations and the ~~Lower~~ Spraberry ~~shales, and the Eagle Ford.~~shale. We have assembled a ~~multi-year~~decade-plus inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and through the acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps.

~~Second Quarter 2022 Highlights~~Recent Developments and Overview

•~~Total production for~~Share Repurchase Program

On May 2, 2023, the ~~three months ended June 30, 2022 was 100.7 MBoe/d, a decrease~~Board approved the Share Repurchase Program to repurchase up to $300.0 million of 2% from the three months ended March 31, 2022, primarily due to normal production decline and increased downtime due to an escalation in capital-efficient workover activity partially offset by new wells placed on production duringour outstanding common stock through the second quarter of ~~2022. Total production~~2025, contingent upon the consummation of the Eagle Ford Divestiture and the Percussion Acquisition, both of which closed on July 3, 2023.

Acquisition and Divestiture

On July 3, 2023, we closed the Percussion Acquisition for total consideration of approximately $458.6 million and the ~~six months ended June 30, 2022 increased 20% from~~Eagle Ford Divestiture for cash consideration of approximately $551.0 million, both subject to customary post-closing purchase price adjustments. See “Note 5 — Acquisitions and Divestitures” for additional details.

Redemption of 2025 Notes

On July 3, 2023, we delivered a redemption notice with respect to all $187.2 million of our outstanding 2025 Notes and redeemed the ~~six months ended June 30, 2021, primarily due to new wells acquired in the Primexx Acquisition as well as new wells placed~~2025 Notes on ~~production, partially offset by normal production decline as well as non-core asset divestitures which occurred primarily in the fourth quarter of 2021.~~August 2, 2023 using borrowings under our Credit Facility.

Second Quarter 2023 Highlights

•Operated drilling and ~~completion~~turned in-line activity for the three months ended June 30, ~~2022~~2023 along with our drilled but uncompleted and producing wells as of June 30, ~~2022~~2023 are summarized in the table below.


		Three Months Ended June 30, 2022				As of June 30, 2022					Three Months Ended June 30, 2023				As of June 30, 2023
		Drilled		Completed		Drilled But Uncompleted		Producing			Drilled		Turned In-Line		Drilled But Uncompleted		Producing
Region	Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Permian	Permian	27	25.2	13	12.2	40	36.9	774	685.8	Permian	24	21.9	29	26.9	19	17.4	798	702.1
Eagle Ford	Eagle Ford	8	7.4	15	13.0	8	7.4	603	543.5	Eagle Ford	6	3.7	3	2.4	6	3.7	607	543.6
Total	Total	35	32.6	28	25.2	48	44.3	1,377	1,229.3	Total	30	25.6	32	29.3	25	21.1	1,405	1,245.7

•Operational capital expenditures, exclusive of leasehold, ~~and seismic,~~ for the second quarter of ~~2022~~2023 were ~~$237.8~~$285.1 million, of which approximately ~~80%~~90% were in the ~~Permian with the remaining balance in the Eagle Ford. See “—Liquidity and Capital Resources—2022 Capital Budget and Funding Strategy” for additional details.~~

•On June 24, 2022, we issued $600.0 million in aggregate principal amount of our 7.50% Senior Notes in a private placement for proceeds of approximately $588.0 million, net of underwriting discounts and commissions. Also on June 24, 2022, using the proceeds from the offering of the 7.50% Senior Notes, along with borrowings under the Credit Facility, we redeemed all of the outstanding 6.125% Senior Notes and all of the outstanding Second Lien Notes.Permian.

•Recorded a net loss for the three months ended June 30, 2023 of $107.9 million, or $1.74 per diluted share, compared to net income for the three months ended June 30, 2022 of ~~$348.0~~$303.3 million, or ~~$5.62 per diluted share, compared to net loss for the three months ended June 30, 2021 of $11.7 million, or $0.25~~$4.90 per diluted share. The variance between the periods was ~~driven~~ primarily ~~by an increase~~due to a decrease in operating revenues in the second quarter of ~~2022 driven by~~2023 as a result of an approximate ~~70% increase~~41% decrease in the total average realized sales price and an ~~increase~~impairment of ~~13% in production volumes compared to~~oil and gas properties of $406.9 million, partially offset by a gain on derivative contracts of $5.9 million during the second quarter of ~~2021 as well as~~2023 compared to a ~~decrease in the~~ loss ~~on derivative contracts to~~of approximately $81.6 million during the second quarter of 2022, ~~compared to approximately $190.5~~as well as income tax benefit of $156.2 million during the second quarter of ~~2021. This increase was partially offset by an increase~~2023 due to the release of our deferred tax asset valuation allowance in ~~operating expenses as well as the~~2023. Additionally, a loss ~~recognized upon the redemption~~on extinguishment of ~~the 6.125% Senior Notes and Second Lien Notes~~debt of $42.4 ~~million. See “—Results~~million was recorded during the second quarter of ~~Operations” below for further details.~~2022.

Results of Operations

Production


	Three Months Ended							Six Months Ended June 30,
	June 30, 2023		March 31, 2023		Change	% Change		2023		2022		Change	% Change
Total production
Oil (MBbls)
Permian	4,671		4,275		396	9	%	8,946		8,759		187	2	%
Eagle Ford	1,066		1,139		(73)	(6	%)	2,205		2,676		(471)	(18	%)
Total oil	5,737		5,414		323	6	%	11,151		11,435		(284)	(2	%)

Natural gas (MMcf)
Permian	10,409		9,288		1,121	12	%	19,697		17,465		2,232	13	%
Eagle Ford	1,292		1,336		(44)	(3	%)	2,628		2,962		(334)	(11	%)
Total natural gas	11,701		10,624		1,077	10	%	22,325		20,427		1,898	9	%

NGLs (MBbls)
Permian	1,816		1,572		244	16	%	3,388		3,077		311	10	%
Eagle Ford	229		222		7	3	%	451		484		(33)	(7	%)
Total NGLs	2,045		1,794		251	14	%	3,839		3,561		278	8	%

Total production (MBoe)
Permian	8,222		7,395		827	11	%	15,617		14,747		870	6	%
Eagle Ford	1,510		1,584		(74)	(5	%)	3,094		3,654		(560)	(15	%)
Total barrels of oil equivalent	9,732		8,979		753	8	%	18,711		18,401		310	2	%

Total daily production (Boe/d)	106,948		99,768		7,180	7	%	103,377		101,665		1,712	2	%
Percent of total daily production
Oil	59	%	60	%		(2	%)	60	%	62	%		(3	%)
Natural gas	20	%	20	%		—	%	20	%	19	%		5	%
NGLs	21	%	20	%		5	%	20	%	19	%		5	%

The ~~following table sets forth certain operating information with respect~~increase in production for both the three months ended June 30, 2023 and the six months ended June 30, 2023 compared to the ~~Company’s oil~~three months ended March 31, 2023 and ~~natural gas operations for~~ the ~~periods indicated:~~

Three Months Ended Six Months Ended June 30,
June 30, 2022 March 31, 2022 Change % Change 2022 2021 Change % Change
Total production
Oil (MBbls)
Permian 4,290 4,469 (179) (4 %) 8,759 6,320 2,439 39 %
Eagle Ford 1,299 1,377 (78) (6 %) 2,676 3,463 (787) (23 %)
Total oil 5,589 5,846 (257) (4 %) 11,435 9,783 1,652 17 %
Natural gas (MMcf)
Permian 8,875 8,590 285 3 % 17,465 13,346 4,119 31 %
Eagle Ford 1,437 1,525 (88) (6 %) 2,962 3,372 (410) (12 %)
Total natural gas 10,312 10,115 197 2 % 20,427 16,718 3,709 22 %
NGLs (MBbls)
Permian 1,622 1,455 167 11 % 3,077 2,291 786 34 %
Eagle Ford 232 252 (20) (8 %) 484 523 (39) (7 %)
Total NGLs 1,854 1,707 147 9 % 3,561 2,814 747 27 %
Total production (MBoe)
Permian 7,391 7,356 35 — % 14,747 10,835 3,912 36 %
Eagle Ford 1,771 1,883 (112) (6 %) 3,654 4,548 (894) (20 %)
Total barrels of oil equivalent 9,162 9,239 (77) (1 %) 18,401 15,383 3,018 20 %
Total daily production (Boe/d) 100,685 102,655 (1,970) (2 %) 101,665 84,991 16,674 20 %
Oil as % of total daily production 61 % 63 % 62 % 64 %
Benchmark prices (1)
WTI (per Bbl) $108.42 $94.38 $14.04 15 % $101.44 $61.95 $39.49 64 %
Henry Hub (per Mcf) 7.50 4.57 2.93 64 % 6.04 2.85 3.19 112 %
Average realized sales price (excluding impact of derivative settlements)

Oil (per Bbl)
Permian $110.71 $94.52 $16.19 17 % $102.45 $60.97 $41.48 68 %
Eagle Ford 111.53 95.02 16.51 17 % 103.03 62.14 40.89 66 %
Total oil 110.90 94.64 16.26 17 % 102.59 61.38 41.21 67 %
Natural gas (per Mcf)
Permian 6.14 4.20 1.94 46 % 5.18 2.88 2.30 80 %
Eagle Ford 7.27 5.18 2.09 40 % 6.20 2.92 3.28 112 %
Total natural gas 6.29 4.35 1.94 45 % 5.33 2.89 2.44 84 %
NGL (per Bbl)
Permian 41.06 40.25 0.81 2 % 40.67 23.76 16.91 71 %
Eagle Ford 38.53 35.93 2.60 7 % 37.18 22.10 15.08 68 %
Total NGLs 40.74 39.61 1.13 3 % 40.20 23.45 16.75 71 %
Total average realized sales price (per Boe)
Permian 80.64 70.29 10.35 15 % 75.48 44.13 31.35 71 %
Eagle Ford 92.75 78.50 14.25 18 % 85.40 52.02 33.38 64 %
Total average realized sales price $82.98 $71.97 $11.01 15 % $77.45 $46.46 $30.99 67 %
six months ended June 30, 2022, respectively, was primarily due to new wells turned in-line during 2023, partially offset by normal production decline on existing wells.

2227

Three Months Ended Six Months Ended June 30,
June 30, 2022 March 31, 2022 $
Change % Change 2022 2021 $
Change % Change
Revenues (in thousands)
Oil
Permian $474,936 $422,404 $52,532 12 % $897,340 $385,307 $512,033 133 %
Eagle Ford 144,876 130,845 14,031 11 % 275,721 215,180 60,541 28 %
Total oil 619,812 553,249 66,563 12 % 1,173,061 600,487 572,574 95 %
Natural gas
Permian 54,469 36,069 18,400 51 % 90,538 38,442 52,096 136 %
Eagle Ford 10,444 7,907 2,537 32 % 18,351 9,858 8,493 86 %
Total natural gas 64,913 43,976 20,937 48 % 108,889 48,300 60,589 125 %
NGLs
Permian 66,592 58,563 8,029 14 % 125,155 54,423 70,732 130 %
Eagle Ford 8,938 9,055 (117) (1 %) 17,993 11,559 6,434 56 %
Total NGLs 75,530 67,618 7,912 12 % 143,148 65,982 77,166 117 %
Total revenues
Permian 595,997 517,036 78,961 15 % 1,113,033 478,172 634,861 133 %
Eagle Ford 164,258 147,807 16,451 11 % 312,065 236,597 75,468 32 %
Total revenues $760,255 $664,843 $95,412 14 % $1,425,098 $714,769 $710,329 99 %
Additional per Boe data
Lease operating expense
Permian $7.33 $6.85 $0.48 7 % $7.09 $4.46 $2.63 59 %
Eagle Ford 10.59 8.99 1.60 18 % 9.77 8.49 1.28 15 %
Total lease operating expense $7.96 $7.29 $0.67 9 % $7.62 $5.65 $1.97 35 %
Production and ad valorem taxes
Permian $4.66 $3.89 $0.77 20 % $4.28 $2.43 $1.85 76 %
Eagle Ford 5.89 4.82 1.07 22 % 5.34 3.10 2.24 72 %
Total production and ad valorem taxes $4.90 $4.08 $0.82 20 % $4.49 $2.63 $1.86 71 %
Gathering, transportation and processing
Permian $2.69 $2.33 $0.36 15 % $2.51 $2.65 ($0.14) (5 %)
Eagle Ford 1.93 1.92 0.01 1 % 1.92 2.05 (0.13) (6 %)
Total gathering, transportation and processing $2.54 $2.25 $0.29 13 % $2.39 $2.47 ($0.08) (3 %)
Pricing


	Three Months Ended					Six Months Ended June 30,
	June 30, 2023	March 31, 2023	Change	% Change		2023	2022	Change	% Change
Benchmark prices (1)
WTI (per Bbl)	$73.75	$76.11	($2.36)	(3	%)	$74.92	$101.44	($26.52)	(26	%)
Henry Hub (per Mcf)	2.32	2.77	(0.45)	(16	%)	2.55	6.04	(3.49)	(58	%)

Average realized sales price (excluding impact of derivative settlements)
Oil (per Bbl)
Permian	$73.45	$75.55	($2.10)	(3	%)	$74.45	$102.45	($28.00)	(27	%)
Eagle Ford	73.80	76.02	(2.22)	(3	%)	74.95	103.03	(28.08)	(27	%)
Total oil	73.52	75.65	(2.13)	(3	%)	74.55	102.59	(28.04)	(27	%)

Natural gas (per Mcf)
Permian	1.15	2.07	(0.92)	(44	%)	1.58	5.18	(3.60)	(69	%)
Eagle Ford	1.93	3.26	(1.33)	(41	%)	2.60	6.20	(3.60)	(58	%)
Total natural gas	1.23	2.22	(0.99)	(45	%)	1.70	5.33	(3.63)	(68	%)

NGL (per Bbl)
Permian	20.14	24.56	(4.42)	(18	%)	22.19	40.67	(18.48)	(45	%)
Eagle Ford	17.72	21.41	(3.69)	(17	%)	19.54	37.18	(17.64)	(47	%)
Total NGLs	19.87	24.18	(4.31)	(18	%)	21.88	40.20	(18.32)	(46	%)

Total average realized sales price (per Boe)
Permian	47.63	51.50	(3.87)	(8	%)	49.46	75.48	(26.02)	(34	%)
Eagle Ford	56.44	60.42	(3.98)	(7	%)	58.47	85.40	(26.93)	(32	%)
Total average realized sales price	$49.00	$53.07	($4.07)	(8	%)	$50.95	$77.45	($26.50)	(34	%)

(1) Reflects calendar average daily spot market prices.

Revenues

~~The following table reconciles the changes in oil, natural gas, NGLs, and total revenue for the period presented by reflecting the effect of changes in volume and in the underlying commodity prices:~~

Oil Natural Gas NGLs Total
(In thousands)
Revenues for the three months ended March 31, 2022 (1)
$553,249 $43,976 $67,618 $664,843
Volume increase (decrease) (24,322) 856 5,823 (17,643)
Price increase 90,885 20,081 2,089 113,055
Net increase 66,563 20,937 7,912 95,412
Revenues for the three months ended June 30, 2022 (1)
$619,812 $64,913 $75,530 $760,255
Percent of total revenues 81 % 9 % 10 %


	Oil		Natural Gas		NGLs		Total
	(In thousands)
Revenues for the three months ended March 31, 2023 (1)	$409,556		$23,586		$43,370		$476,512
Volume increase	24,441		2,391		6,068		32,900
Price decrease	(12,222)		(11,554)		(8,809)		(32,585)
Net increase (decrease)	12,219		(9,163)		(2,741)		315
Revenues for the three months ended June 30, 2023 (1)	$421,775		$14,423		$40,629		$476,827

Percent of total revenues	88	%	3	%	9	%

(1) Excludes sales of oil and gas purchased from third parties and sold to our customers.

Oil Natural Gas NGLs Total
(In thousands)
Revenues for the six months ended June 30, 2021(1)
$600,487 $48,300 $65,982 $714,769
Volume increase 101,401 10,716 17,515 129,632
Price increase 471,173 49,873 59,651 580,697
Net increase 572,574 60,589 77,166 710,329
Revenues for the six months ended June 30, 2022 (1)
$1,173,061 $108,889 $143,148 $1,425,098
Percent of total revenues 82 % 8 % 10 %
The increase in revenues for the three months ended June 30, 2023 compared to the three months ended March 31, 2023 was primarily due to a 7% increase in production, partially offset by an 8% decrease in the average realized sales price, which decreased to $49.00 per Boe from $53.07 per Boe, as shown above.


	Oil		Natural Gas		NGLs		Total
	(In thousands)
Revenues for the six months ended June 30, 2022(1)	$1,173,061		$108,889		$143,148		$1,425,098
Volume increase (decrease)	(29,134)		10,118		11,175		(7,841)
Price decrease	(312,596)		(80,998)		(70,324)		(463,918)
Net decrease	(341,730)		(70,880)		(59,149)		(471,759)
Revenues for the six months ended June 30, 2023 (1)	$831,331		$38,009		$83,999		$953,339

Percent of total revenues	87	%	4	%	9	%

(1) Excludes sales of oil and gas purchased from third parties and sold to our customers.

~~Revenues for the three months ended June 30, 2022 of $760.3 million increased $95.4 million, or 14%, compared to revenues of $664.8 million for the three months ended March 31, 2022.~~ The increase was primarily attributable to a 17% increase in the average realized sales price for oil, which rose to $110.90 per Bbl from $94.64 per Bbl, as well as a 45% increase in the average realized sales price for natural gas, which rose to $6.29 per Mcf from $4.35 per Mcf. The increase in the average realized price for oil and natural gas was partially offset by a 2% decrease in ~~production, as discussed above.~~

~~Revenues~~revenues for the six months ended June 30, ~~2022 of $1.4 billion increased $710.3 million, or 99%,~~2023 compared to ~~revenues of $714.8 million for~~ the same period of ~~2021. The increase~~2022 was primarily ~~attributable~~due to a ~~67% increase~~34% decrease in the average realized sales price, ~~of oil~~ which ~~rose~~decreased to ~~$102.59~~$50.95 per ~~Bbl~~Boe from ~~$61.38~~$77.45 per ~~Bbl as well as~~Boe, partially offset by a ~~20%~~2% increase in production, as ~~discussed~~shown above.

Operating Expenses

Three Months Ended
June 30, 2022 Per March 31, 2022 Per Total Change Boe Change
Boe Boe $ % $ %
(In thousands, except per Boe and % amounts)
Lease operating $72,940 $7.96 $67,328 $7.29 $5,612 8 % $0.67 9 %
Production and ad valorem taxes 44,873 4.90 37,678 4.08 7,195 19 % 0.82 20 %
Gathering, transportation and processing 23,267 2.54 20,775 2.25 2,492 12 % 0.29 13 %
Depreciation, depletion and amortization 109,409 11.94 102,979 11.15 6,430 6 % 0.79 7 %
General and administrative 10,909 1.19 17,121 1.85 (6,212) (36 %) (0.66) (36 %)
Merger, integration and transaction — — 769 0.08 (769) (100 %) (0.08) (100 %)
Six Months Ended June 30,
Per Per Total Change Boe Change
2022 Boe 2021 Boe $ % $ %
(In thousands, except per Boe and % amounts)
Lease operating $140,268 $7.62 $86,913 $5.65 $53,355 61 % $1.97 35 %
Production and ad valorem taxes 82,551 4.49 40,397 2.63 42,154 104 % 1.86 71 %
Gathering, transportation and processing 44,042 2.39 38,012 2.47 6,030 16 % (0.08) (3 %)
Depreciation, depletion and amortization 212,388 11.54 154,115 10.02 58,273 38 % 1.52 15 %
General and administrative 28,030 1.52 27,864 1.81 166 1 % (0.29) (16 %)
Merger, integration and transaction 769 0.04 — — 769 — % 0.04 — %

Lease Operating ~~Expenses.~~Expenses ~~Lease~~


	Three Months Ended
	June 30, 2023	Per	March 31, 2023	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$61,021	$7.42	$58,215	$7.87	$2,806	5	%	($0.45)	(6	%)
Eagle Ford	15,767	10.44	16,887	10.66	(1,120)	(7	%)	(0.22)	(2	%)
Lease operating	$76,788	$7.89	$75,102	$8.36	$1,686	2	%	($0.47)	(6	%)

	Six Months Ended June 30,
		Per		Per	Total Change			Boe Change
	2023	Boe	2022	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$119,236	$7.64	$104,575	$7.09	$14,661	14	%	$0.55	8	%
Eagle Ford	32,654	10.55	35,693	9.77	(3,039)	(9	%)	0.78	8	%
Lease operating	$151,890	$8.12	$140,268	$7.62	$11,622	8	%	$0.50	7	%

The increase in lease operating expenses for the three months ended June 30, ~~2022 increased to $72.9 million~~2023 compared to ~~$67.3 million for~~ the three months ended March 31, ~~2022,~~2023 was primarily due to increases in ~~workover costs as well as~~ certain operating costs such as ~~fuel, power~~saltwater disposal and ~~equipment rentals. Lease~~repairs and maintenance. The decrease in lease operating ~~expense~~expenses per Boe for the three months ended June 30, ~~2022 increased to $7.96~~2023 compared to ~~$7.29 for~~ the three months ended March 31, ~~2022,~~2023 was primarily due to ~~the increases in operating costs mentioned above as well as~~ the distribution of fixed costs spread over ~~slightly lower~~higher production volumes.

~~Lease~~The increase in lease operating expenses, as well as the increase in lease operating expenses per Boe, for the six months ended June 30, ~~2022 increased to $140.3 million~~2023 compared to ~~$86.9 million for~~ the same period of ~~2021,~~2022 was primarily due to ~~the increase in production from wells acquired in the Primexx Acquisition as well as~~ increases in certain operating expenses such as fuel, power and ~~chemicals. Lease operating expense per Boe~~saltwater disposal and overall cost inflation.

Production and Ad Valorem Taxes


	Three Months Ended
	June 30, 2023		Per	March 31, 2023		Per	Total Change			Boe Change
			Boe			Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$19,739		$2.40	$25,397		$3.43	($5,658)	(22	%)	($1.03)	(30	%)
Eagle Ford	4,967		3.29	7,324		4.62	(2,357)	(32	%)	(1.33)	(29	%)
Production and ad valorem taxes	$24,706		$2.54	$32,721		$3.64	($8,015)	(24	%)	($1.10)	(30	%)

Percent of total revenues	5.2	%		6.9	%			(1.7	%)

	Six Months Ended June 30,
			Per			Per	Total Change			Boe Change
	2023		Boe	2022		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$45,136		$2.89	$63,051		$4.28	($17,915)	(28	%)	($1.39)	(32	%)
Eagle Ford	12,291		3.97	19,500		5.34	(7,209)	(37	%)	(1.37)	(26	%)
Production and ad valorem taxes	$57,427		$3.07	$82,551		$4.49	($25,124)	(30	%)	($1.42)	(32	%)

Percent of total revenues	6.0	%		5.8	%			0.2	%

The decrease in production and ad valorem taxes, as well as the decrease in production and ad valorem taxes as a percentage of total revenues, for the three months ended June 30, 2023 compared to the three months ended March 31, 2023 was primarily related to a decrease in ad valorem taxes due to lower estimated property tax valuations.

The decrease in production and ad valorem taxes for the six months ended June 30, ~~2022 increased to $7.62~~2023 compared to ~~$5.65 for~~ the same period of ~~2021, primarily due to the increase in certain operating expenses as discussed above as well as the increase in certain operating expenses associated with the Primexx Acquisition.~~

~~Production and Ad Valorem Taxes.~~ ~~For the three months ended June 30,~~ 2022 ~~production and ad valorem taxes increased 19% to $44.9 million compared to $37.7 million for the three months ended March 31, 2022, which is~~was primarily related to a ~~14% increase~~33% decrease in total revenues which ~~increased~~decreased production taxes, ~~as well as~~partially offset by an increase in ad valorem taxes due to higher expected property tax valuations as a result of higher commodity prices during ~~2021~~2022 compared to ~~2020. Production~~2021. The increase in production and ad valorem taxes as a percentage of total revenues increased to 5.9% for the second quarter of 2022 as compared to 5.7% of total revenues for the three months ended March 31, 2022, primarily due to an increase in ad valorem taxes during the second quarter of 2022 as discussed above.

For the six months ended June 30, 2022, production and ad valorem taxes increased 104% to $82.6 million compared to $40.4 million for the same period of 2021, which is primarily related to a 99% increase in total revenues which increased production taxes, as well as an increase in ad valorem taxes as discussed in the paragraph above. Production and ad valorem taxes as a percentage of total revenues increased to 5.8% for the six months ended June 30, ~~2022, as~~2023 compared to ~~5.7% of total revenues for~~ the same period of ~~2021,~~2022 was primarily due to an increase in ad valorem taxes during the six months ended June 30, ~~2022~~2023, as discussed ~~above.~~above, with a decrease in total revenues during the six months ended June 30, 2023.

Gathering, Transportation and Processing Expenses~~. For~~


	Three Months Ended
	June 30, 2023	Per	March 31, 2023	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$24,407	$2.97	$22,707	$3.07	$1,700	7	%	($0.10)	(3	%)
Eagle Ford	2,931	1.94	3,270	2.06	(339)	(10	%)	(0.12)	(6	%)
Gathering, transportation and processing	$27,338	$2.81	$25,977	$2.89	$1,361	5	%	($0.08)	(3	%)

	Six Months Ended June 30,
		Per		Per	Total Change			Boe Change
	2023	Boe	2022	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$47,114	$3.02	$37,016	$2.51	$10,098	27	%	$0.51	20	%
Eagle Ford	6,201	2.00	7,026	1.92	(825)	(12	%)	0.08	4	%
Gathering, transportation and processing	$53,315	$2.85	$44,042	$2.39	$9,273	21	%	$0.46	19	%

The increase in gathering, transportation and processing expenses for the three months ended June 30, ~~2022, gathering, transportation and processing expenses increased 12% to $23.3 million~~2023 compared to ~~$20.8 million for~~ the three months ended March 31, ~~2022, which is primarily related to an agreement entered into with a third party in the second quarter of 2022 which provides long-term processing assurance in the Permian.~~

~~For the six months ended June 30, 2022, gathering, transportation and processing expenses increased 16% to $44.0 million compared to $38.0 million for the same period of 2021, which~~2023 was primarily related to the ~~20%~~7% increase in production volumes between the two periods.

The increase in gathering, transportation and processing expenses for the six months ended June 30, 2023 compared to the same period of 2022 was primarily related to a new gathering agreement put into place during the six months ended June 30, 2023.

Exploration Expenses


	Three Months Ended
	June 30, 2023	Per	March 31, 2023	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Exploration	$1,882	$0.19	$2,232	$0.25	($350)	(16	%)	($0.06)	(24	%)

	Six Months Ended June 30,
		Per		Per	Total Change			Boe Change
	2023	Boe	2022	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Exploration	$4,114	$0.22	$4,295	$0.23	($181)	(4	%)	($0.01)	(4	%)

Depreciation, Depletion and Amortization (“DD&A”). The following table sets forth the components of our DD&A for the periods indicated:


		Three Months Ended				Six Months Ended June 30,					Three Months Ended				Six Months Ended June 30,
		June 30, 2022		March 31, 2022		2022		2021			June 30, 2023		March 31, 2023		2023		2022
		Amount	Per Boe	Amount	Per Boe	Amount	Per Boe	Amount	Per Boe		Amount	Per Boe	Amount	Per Boe	Amount	Per Boe	Amount	Per Boe
		(In thousands, except per Boe)									(In thousands, except per Boe)
DD&A of evaluated oil and gas properties		$107,400	$11.72	$100,763	$10.91	$208,163	$11.31	$149,538	$9.72
DD&A of proved oil and gas properties										DD&A of proved oil and gas properties	$125,394	$12.88	$123,489	$13.75	$248,883	$13.30	$225,374	$12.25
Depreciation of other property and equipment	Depreciation of other property and equipment	432	0.05	476	0.05	908	0.05	1,005	0.07	Depreciation of other property and equipment	352	0.04	390	0.04	742	0.04	908	0.05
Amortization of other assets	Amortization of other assets	598	0.06	780	0.08	1,378	0.07	1,722	0.11	Amortization of other assets	650	0.07	790	0.09	1,440	0.08	1,378	0.07
Accretion of asset retirement obligations	Accretion of asset retirement obligations	979	0.11	960	0.11	1,939	0.11	1,850	0.12	Accretion of asset retirement obligations	952	0.10	1,296	0.15	2,248	0.12	1,939	0.11
DD&A	DD&A	$109,409	$11.94	$102,979	$11.15	$212,388	$11.54	$154,115	$10.02	DD&A	$127,348	$13.09	$125,965	$14.03	$253,313	$13.54	$229,599	$12.48

~~For~~The increase in DD&A for the three months ended June 30, ~~2022, DD&A increased~~2023 compared to ~~$109.4 million from $103.0 million for~~ the three months ended March 31, ~~2022 primarily attributable to higher capital expenditures during the three months ended June 30, 2022 and increases in future development cost assumptions.~~

~~For the six months ended June 30, 2022, DD&A increased to $212.4 million from $154.1 million for the same period in 2021~~2023 was primarily attributable to a production increase of ~~20%~~7%, partially offset by the cessation of depreciation on the assets associated with the Eagle Ford Divestiture as ~~well~~a result of being classified as assets held for sale.

The increase in DD&A for the ~~addition~~six months ended June 30, 2023 compared to the same period in 2022 was primarily attributable to higher proved oil and gas property balances as a result of ~~properties acquired in~~ the ~~Primexx Acquisition.~~capital expenditures throughout 2022 and the six months ended June 30, 2023 and to a production increase of 2%, partially offset by the cessation of depreciation on the assets associated with the Eagle Ford Divestiture as a result of being classified as assets held for sale.

See “Note 5 — Acquisitions and Divestitures” for additional details regarding the Eagle Ford Divestiture.

General and Administrative ~~Net of Amounts Capitalized~~ (“G&A”).


	Three Months Ended
	June 30, 2023	Per	March 31, 2023	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
General and administrative	$29,768	$3.06	$27,798	$3.10	$1,970	7	%	($0.04)	(1	%)

	Six Months Ended June 30,
		Per		Per	Total Change			Boe Change
	2023	Boe	2022	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
General and administrative	$57,566	$3.08	$47,232	$2.57	$10,334	22	%	$0.51	20	%

The increase in G&A for the three months ended June 30, ~~2022 decreased to $10.9 million~~2023 compared to ~~$17.1 million for~~ the three months ended March 31, ~~2022,~~2023 was primarily due to ~~a decrease~~an increase in ~~the fair value of cash settled awards as a result of the decrease~~stock compensation expense.

The increase in ~~our stock price between the two periods.~~

G&A for the six months ended June 30, ~~2022 was effectively flat at $28.0 million~~2023 compared to ~~$27.9 million for~~ the same period in ~~2021.~~2022 was primarily due to an increase in employee-related costs as well as an increase in stock compensation expense between the two periods.

Impairment of Proved Oil and Gas Properties. We recognized an impairment of proved oil and gas properties for the three and six months ended June 30, 2023 of $406.9 million as the fair value less cost to sell was less than the carrying amount of the net assets

associated with the Eagle Ford Divestiture that were classified as assets held for sale. We did not recognize an impairment of proved oil and gas properties for the three or six months ended June 30, 2022.

Other Income and Expenses

Interest ~~Expense, Net of Capitalized Amounts.~~Expense. The following table sets forth the components of our interest expense ~~net of capitalized amounts~~ for the periods indicated:

Three Months Ended Six Months Ended June 30,
June 30, 2022 March 31, 2022 Change 2022 2021 Change
(In thousands)
Interest expense on Senior Unsecured Notes $29,224 $29,022 $202 $58,246 $49,004 $9,242
Interest expense on Second Lien Notes 6,633 7,192 (559) 13,825 23,250 (9,425)
Interest expense on Credit Facility 7,754 7,110 644 14,864 15,787 (923)
Amortization of debt issuance costs, premiums and discounts 3,371 3,750 (379) 7,121 8,916 (1,795)
Other interest expense 13 22 (9) 35 58 (23)
Capitalized interest (26,304) (25,538) (766) (51,842) (47,965) (3,877)
Interest expense, net of capitalized amounts $20,691 $21,558 ($867) $42,249 $49,050 ($6,801)


	Three Months Ended			Six Months Ended June 30,
	June 30, 2023	March 31, 2023	Change	2023	2022	Change
	(In thousands)
Interest expense on Senior Notes	$33,224	$33,224	$—	$66,448	$58,246	$8,202
Interest expense on second lien notes	—	—	—	—	13,825	(13,825)
Interest expense on Credit Facility	11,397	10,447	950	21,844	14,864	6,980
Amortization of debt issuance costs, premiums and discounts	2,615	2,631	(16)	5,246	7,121	(1,875)
Other interest expense	3	4	(1)	7	35	(28)

Interest expense	$47,239	$46,306	$933	$93,545	$94,091	($546)

Interest expense ~~net of capitalized amounts, incurred during~~for the three months ended June 30, ~~2022 decreased $0.9~~2023 was $47.2 million, ~~to $20.7 million compared to $21.6 million for~~slightly higher than the three months ended March 31, ~~2022. The decrease is primarily due to an increase~~2023 as a result of increases in ~~capitalized~~ interest ~~compared to~~rates associated with our outstanding borrowings under the ~~three months ended March 31, 2022.~~Credit Facility.

Interest expense ~~net of capitalized amounts, incurred during~~for the six months ended June 30, 2023 was $93.5 million, slightly lower than the six months ended June 30, 2022 ~~decreased $6.8 million to $42.2 million compared to $49.1 million for the same period of 2021. The decrease is primarily due to the reduction in interest expense and the write-off~~as a result of the ~~discount associated with the Second Lien Notes exchange~~redemption of our 9.0% second lien notes in ~~November 2021, lower borrowings on the Credit Facility compared to the same period of 2021 and an increase in capitalized interest,~~June 2022, partially offset by an increase in interest expense ~~primarily related~~due to the issuance of ~~the 8.00%~~our 7.5% Senior Notes in ~~July 2021. See “Note 7 - Borrowings” of~~June 2022 as well as increases in interest rates associated with our outstanding borrowings under the ~~Notes to Consolidated Financial Statements in our 2021 Annual Report for further discussion of the Second Lien Notes exchange.~~

~~See “Note 6 - Borrowings” for details of the issuance of the 7.50% Senior Notes and redemptions of the 6.125% Senior Notes and Second Lien Notes.~~

Credit Facility.

(Gain) Loss on Derivative Contracts. The net (gain) loss on derivative contracts for the periods indicated includes the following:

Three Months Ended Six Months Ended June 30,
June 30, 2022 March 31, 2022 2022 2021
(In thousands)
Loss on oil derivatives $75,910 $325,348 $401,258 $326,594
Loss on natural gas derivatives 5,738 28,181 33,919 15,513
Loss on NGL derivatives — 4,771 4,771 4,872
Loss on contingent consideration arrangements — — — 2,617
Loss on September 2020 Warrants liability — — — 55,390
Loss on derivative contracts $81,648 $358,300 $439,948 $404,986


	Three Months Ended		Six Months Ended June 30,
	June 30, 2023	March 31, 2023	2023	2022
	(In thousands)
(Gain) loss on oil derivatives	($12,937)	($23,344)	($36,281)	$401,258
(Gain) loss on natural gas derivatives	6,996	(2,301)	4,695	33,919
Loss on NGL derivatives	—	—	—	4,771


(Gain) loss on derivative contracts	($5,941)	($25,645)	($31,586)	$439,948

See “Note ~~7 -~~9 — Derivative Instruments and Hedging Activities” and “Note ~~8 -~~10 — Fair Value Measurements” for additional information.

Income Tax Expense. We recorded income tax ~~expense~~benefit of ~~$3.0~~$156.2 million and ~~$0.5~~$206.9 million for the three ~~months ended June 30, 2022~~ and ~~March 31, 2022, respectively.~~

~~We recorded income tax expense of $3.5 million compared to income tax benefit of $1.4 million for the~~ six months ended June 30, ~~2022~~2023, respectively, compared to income tax expense of $3.2 million for both the three and ~~2021, respectively.~~

~~Since~~six months ended June 30, 2022. The income tax benefit for the ~~second quarter~~three and six months ended June 30, 2023 is a result of ~~2020, we have concluded~~releasing the valuation allowance that ~~it is more likely than not that the~~was in place against our net deferred tax ~~assets will not be realized and have recorded a full valuation allowance against our deferred tax~~ assets. ~~As long as we continue to conclude that the valuation allowance is necessary, we do not expect to have significant deferred income tax expense or benefit.~~ See “Note ~~9 -~~11 — Income Taxes” for further discussion.

Liquidity and Capital Resources

Outlook. Oil prices ~~steadily increased throughout 2021~~continue to remain volatile as the daily NYMEX benchmark price for oil ranged between approximately $67 and $83 per barrel during the second quarter of 2023. While we saw a similar range during the first quarter of 2023, the average price for the second quarter of 2023 decreased approximately 3% as compared to the first quarter of 2023 and remained ~~on an upward trajectory throughout~~significantly below the average for 2022. Additionally, during the second quarter of 2023, the daily NYMEX benchmark price for natural gas dropped to $2.32 per mcf, a 16% decrease as compared to the first ~~half~~quarter of ~~2022. As~~2023 and over a ~~result of rapid economic growth and improved industry fundamentals, we are experiencing inflationary cost pressures on many different service items including labor, materials, and equipment.~~65% decrease from the average for 2022. We expect to continue to ~~face inflationary pressure into 2023.~~see volatility in oil prices, as well as natural gas and NGL prices.

~~2022~~2023 Capital Budget and Funding Strategy. Our primary uses of capital are for the exploration and development of our oil and natural gas ~~properties. Our 2022 operational~~properties, where our 2023 planned capital ~~budget is $790.0~~expenditures are $960.0 million to ~~$810.0 million, with over 85% allocated towards development in the Permian with the balance towards development in the Eagle Ford.~~$980.0 million. Because we are the operator of a high percentage of our properties, we can control the well design and the development pace associated with our capital expenditures. ~~Our 2022~~We plan our capital expenditure program ~~was developed~~ to ~~reflect reduced~~achieve disciplined reinvestment rates ~~and balance capital deployment for more consistent cash flow generation and~~ to drive capital efficiency through an enhanced multi-zone, scaled development program.

~~The following table is a summary of our capital expenditures(1)~~ ~~for the three and six months ended June 30, 2022:~~

Three Months Ended Six Months Ended
March 31, 2022 June 30, 2022 June 30, 2022
(In millions)
Operational capital $157.4 $237.8 $395.2
Capitalized interest 25.5 26.3 51.8
Capitalized G&A 11.6 11.3 22.9
Total $194.5 $275.4 $469.9

~~(1) Capital expenditures, presented on an accrual basis, includes drilling, completions, facilities, and equipment, and excludes land, seismic, and asset retirement costs.~~

We believe that existing cash and cash equivalents, ~~any positive~~ cash flows from operations and available borrowings under our Credit Facility will be sufficient to support working capital, capital expenditures and other cash requirements for at least the next 12 months and, based on our current expectations, for the foreseeable future thereafter. Our future capital requirements, both near-term and long-term, will depend on many factors, including, but not limited to, commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of oil and gas properties, the availability of drilling rigs and completion crews, the cost of completion

services, success of drilling programs, land and industry partner issues, weather delays, the acquisition of leases with drilling commitments, and other factors.

Historically, our primary sources of capital have been cash flows from operations, borrowings under our ~~Credit Facility,~~credit facility, proceeds from the issuance of debt securities and public equity offerings, and ~~non-core~~ asset dispositions. We regularly consider which resources, including cash flows from operations and debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and liquidity requirements. In addition, we may consider divesting certain properties or assets that are not part of our core business or are

no longer deemed essential to our future growth or enter into joint venture agreements, provided we are able to divest such assets or enter into joint venture agreements on terms that are acceptable to us.

Depending upon our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may, from time to time, seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or through privately negotiated transactions or otherwise. The amounts involved in any such transactions, individually or in aggregate, may be material. See “Note 13 — Stockholders’ Equity” for information regarding our Share Repurchase Program.

Overview of Cash Flow Activities. ~~For the six months ended June 30, 2022, cash~~Cash and cash equivalents ~~decreased $3.8~~was $3.7 million ~~to $6.1~~and $3.4 million ~~compared to $9.9 million at~~as of June 30, 2023 and December 31, ~~2021.~~2022, respectively.


		Six Months Ended June 30,			Six Months Ended June 30,
		2022	2021		2023	2022
		(In thousands)			(In thousands)
Net cash provided by operating activities	Net cash provided by operating activities	$653,595	$313,268	Net cash provided by operating activities	$527,435	$583,906
Net cash used in investing activities	Net cash used in investing activities	(435,756)	(217,387)	Net cash used in investing activities	(548,572)	(366,067)
Net cash used in financing activities		(221,621)	(112,317)
Net cash provided by (used in) financing activities				Net cash provided by (used in) financing activities	21,392	(221,621)
Net change in cash and cash equivalents	Net change in cash and cash equivalents	($3,782)	($16,436)	Net change in cash and cash equivalents	$255	($3,782)

Operating Activities. For the six months ended June 30, ~~2022,~~2023, net cash provided by operating activities was ~~$653.6~~$527.4 million compared to ~~$313.3~~$583.9 million for the same period in ~~2021.~~2022. The change in net cash provided by operating activities was predominantly attributable to the following:

•~~An increase~~A decrease in revenue primarily driven by a ~~67% increase~~34% decrease in total average realized sales price, ~~as well as~~partially offset by a ~~20%~~2% increase in production volumes, ~~and~~largely offset by

•~~An offsetting increase~~A decrease in the cash paid for commodity derivative ~~settlements.~~settlements, and

•An increase in cash inflows of $117.9 million related to timing of working capital payments and receipts.

Production, realized prices, and operating expenses are discussed in Results of Operations. See “Note ~~7 -~~9 — Derivative Instruments and Hedging Activities” and “Note ~~8 -~~10 — Fair Value Measurements” for a reconciliation of the components of our derivative contracts and disclosures related to derivative instruments including their composition and valuation.

Investing Activities. For the six months ended June 30, ~~2022,~~2023, net cash used in investing activities was ~~$435.8~~$548.6 million compared to ~~$217.4~~$366.1 million for the same period in ~~2021.~~2022. The increase in net cash used in investing activities was primarily attributable to ~~the following:~~

•Anan increase in operational ~~capex,~~capital expenditures and

•~~An increase due to~~ a deposit paid for the Percussion Acquisition, partially offset by a decrease in cash ~~payment of $19.2 million in January 2022~~paid for the settlement of a contingent consideration ~~agreement.~~agreements.

Financing Activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under ~~the~~our Credit Facility, term debt and equity offerings. For the six months ended June 30, ~~2022,~~2023, net cash provided by financing activities was $21.4 million compared to net cash used in financing activities ~~was~~of $221.6 ~~million compared to $112.3~~ million for the same period of ~~2021.~~2022. The ~~increase in net cash used in financing activities~~change was primarily attributable to the ~~following:~~

•~~Redemptions~~redemptions of the 6.125% Senior Notes and Second Lien Notes, ~~and~~

•~~An offsetting cash inflow due to~~partially offset by the issuance of the 7.50% Senior ~~Notes.~~Notes during the six months ended June 30, 2022.

~~See “Note 6 – Borrowings” for additional information on our debt transactions.~~

Credit Facility. As of June 30, ~~2022,~~2023, our Credit Facility had a maximum credit amount of $5.0 billion, a borrowing base of ~~$1.6~~$2.0 billion ~~with~~and an elected commitment amount of ~~$1.6~~$1.5 billion, with borrowings outstanding of ~~$779.0~~$528.0 million at a weighted average interest rate of ~~4.16%~~7.26%, and $16.4 million in letters of credit outstanding. ~~On May 2, 2022, as a result of the spring 2022 redetermination, the borrowing base and elected commitment amount of $1.6 billion were reaffirmed.~~

See “Note ~~6 –~~8 — Borrowings” for additional information related to the Credit Facility.

Material Cash Requirements. As of June 30, ~~2022,~~2023, we have financial obligations associated with our outstanding long-term debt, including interest payments and principal repayments. See “Note 7 -— Borrowings” of the Notes to Consolidated Financial Statements in our ~~2021~~2022 Annual Report for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. Additionally, we have operational obligations associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and transportation service agreements and estimates of future asset retirement obligations. See “Note 14 -— Asset Retirement Obligations” and “Note 17 -— Commitments and Contingencies” of the Notes to Consolidated Financial Statements in our ~~2021~~2022 Annual Report for additional details.

2833

On May 3, 2023, we entered into the Percussion Agreement, pursuant to which we agreed to acquire Percussion’s oil and gas properties in the Delaware Basin for consideration of $475.0 million, which consisted of $255.0 million in cash, inclusive of the repayment of Percussion’s indebtedness of approximately $220.0 million, and $210.0 million of shares of our common stock, subject to customary purchase price adjustments. Additionally, we would assume Percussion Target’s existing hedges and transportation contract liabilities, and could have to pay up to $62.5 million of contingent consideration if the WTI price of oil exceeds certain thresholds in 2023, 2024, and 2025. On July 3, 2023, we completed the Percussion Acquisition for a purchase price of approximately $248.6 million in cash (inclusive of the repayment of Percussion Target’s indebtedness of approximately $220.0 million) and approximately 6.3 million shares of our common stock, subject to post-closing adjustments. We funded the cash portion of the purchase price with a portion of the proceeds from the Eagle Ford Divestiture. We received approximately $551.0 million in cash upon consummation of the Eagle Ford Divestiture on July 3, 2023.

Since December 31, ~~2021,~~2022, except as disclosed above, there have been no material changes from what was disclosed in our ~~2021~~2022 Annual Report other than ~~the following:~~

•~~Changes~~changes to the borrowings under our Credit ~~Facility,~~

•~~Amended frac service contract executed in the first quarter of 2022 through the remainder of 2022 with a remaining obligation of approximately $20.0 million as of June 30, 2022,~~

•~~Extensions of two drilling rigs executed in the second quarter of 2022~~Facility. See “Note 8 — Borrowings” for ~~the next 12 to 18 months for an incremental obligation of approximately $25.0 million as of June 30, 2022, and~~

•~~Issuance of the 7.50% Senior Notes due 2030 and redemptions of the 6.125% Senior Notes due 2024 and Second Lien Notes due 2025 in the second quarter of 2022.~~additional information.

Critical Accounting Estimates

The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets, liabilities, revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. Our policies and use of estimates are described in “Note 2 -— Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our ~~2021~~2022 Annual Report. Except as ~~set forth~~discussed below and in “Note 2 — Summary of Significant Accounting Policies,” of the Notes to Consolidated Financial Statements in this Form 10-Q, there have been no material changes to our critical accounting estimates since December 31, ~~2021,~~2022, which are disclosed in “Part II, Item 7A. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our ~~2021~~2022 Annual ~~Report~~Report.

Recast Financial Information for Change in Accounting Principle

In the first quarter of 2023, we voluntarily changed our method of accounting for our oil and gas exploration and development activities from the full cost method to the successful efforts method of accounting. Accordingly, the financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the FASB ASC 932 “Extractive Activities — Oil and Gas.” See “Note 2 — Summary of Significant Accounting Policies” and “Note 3 — Change in Accounting Principle” for additional discussion.

Impairment of Oil and Natural Gas Properties

~~The table below presents various pricing scenarios to demonstrate~~We assess our proved oil and gas properties for impairment on an asset group basis whenever events and circumstances indicate that there could be a possible decline in the ~~sensitivity~~recoverability of the net book value of such property. We estimate the expected future net cash flows of our proved oil and gas properties and compare these undiscounted cash flows to the net book value of the proved oil and gas properties to determine if the net book value is recoverable. If the net book value exceeds the estimated undiscounted future net cash flows, we will recognize an impairment to reduce the net book value of the proved oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future development costs and operating costs, and discount rates, which are based on a weighted average cost of capital. Fair value estimates are based on projected financial information which we believe to be reasonably likely to occur, as of the date that the impairment is measured. There were no impairments of proved oil and gas properties for the three or six months ended June 30, ~~2022 cost center ceiling~~2022. See “Note 5 — Acquisitions and Divestitures” for details of the impairment of $406.9 million recorded in the second quarter of 2023 associated with the assets held for sale classification resulting from the agreement to sell all of our interests of Callon (Eagle Ford) LLC to Ridgemar Energy Operating, LLC.

We evaluate significant unproved oil and gas property costs for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or changes in ~~12-month~~future plans to develop acreage. Unproved oil and gas properties that are not individually significant are aggregated by asset group, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average ~~benchmark crude~~holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data.

Income Taxes

Management monitors company-specific, oil and natural gas ~~prices underlying~~industry and worldwide economic factors and assesses the ~~12-Month Average Realized Prices. The sensitivity analysis~~likelihood that our net deferred tax assets will be utilized prior to their expiration. As previously disclosed in our 2022 Annual Report, beginning in the second quarter of 2020 and through the fourth quarter of 2022, we maintained a valuation allowance against our net deferred tax assets. Considering all available evidence (both positive and negative), we concluded that it is asmore likely than not that the deferred tax assets would be realized and released the valuation allowance in the first quarter of 2023. This release resulted in a deferred income tax benefit of $152.9 million and $204.8 million for the three and six months ended June 30, ~~2022 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions~~2023, respectively. As a result of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to June 30, 2022 that may require revisions to estimatesthe release of ~~proved reserves. See also “Part I, Item 1A. Risk Factors—If oil and natural gas prices remain depressed~~the valuation allowance, we will have no federal deferred income tax expense for ~~extended periods~~the remainder of ~~time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties” in our 2021 Annual Report.~~2023.

12-Month Average
Realized Prices Excess (deficit) of cost center ceiling over net book value, less related deferred income taxes Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes
Full Cost Pool Scenarios Crude Oil
($/Bbl) Natural Gas
($/Mcf) (In millions) (In millions)
June 30, 2022 Actual $85.62 $4.82 $4,819
Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10% $94.20 $5.34 $5,935 $1,116
Crude Oil and Natural Gas -10% $77.04 $4.31 $3,703 ($1,116)
Crude Oil Price Sensitivity
Crude Oil +10% $94.20 $4.82 $5,833 $1,014
Crude Oil -10% $77.04 $4.82 $3,805 ($1,014)
Natural Gas Price Sensitivity
Natural Gas +10% $85.62 $5.34 $4,920 $101
Natural Gas -10% $85.62 $4.31 $4,718 ($101)

Recently Adopted and Recently Issued Accounting Standards

See “Note ~~1 - Description~~2 — Summary of ~~Business and Basis~~Significant Accounting Policies” of ~~Presentation”~~the Notes to Consolidated Financial Statements in our 2022 Annual Report for discussion.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of commodity derivative instruments.

Except as set forth below, there have been no material changes to the sources and effects of our market risk since December 31, ~~2021,~~2022, which are disclosed in “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of our ~~2021~~2022 Annual ~~Report on Form 10-K.~~Report.

Commodity Price Risk

Our revenues are derived from the sale of our oil, natural gas and NGL production. The prices for oil, natural gas and NGLs remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, government actions, economic conditions, and weather conditions. We enter into commodity derivative instruments to manage oil, natural gas and NGL price risk, related both to NYMEX benchmark prices and regional basis differentials.

The following table sets forth the fair values of our commodity derivative instruments as of June 30, ~~2022~~2023 as well as the impact on the fair values assuming a 10% increase and decrease in the underlying forward oil and gas price curves as of June 30, ~~2022:~~2023:


		Three Months Ended June 30, 2022				Three Months Ended June 30, 2023
		Oil	Natural Gas	Total		Oil	Natural Gas	Total
		(In thousands)				(In thousands)
Fair value liability as of June 30, 2022 (1)		($255,404)	($4,808)	($260,212)
Fair value asset (liability) as of June 30, 2023 (1)					Fair value asset (liability) as of June 30, 2023 (1)	$11,488	($5,363)	$6,125

Impact of a 10% increase in forward commodity prices	Impact of a 10% increase in forward commodity prices	($358,950)	($10,820)	($369,770)	Impact of a 10% increase in forward commodity prices	$3,996	($5,886)	($1,890)
Impact of a 10% decrease in forward commodity prices	Impact of a 10% decrease in forward commodity prices	($154,241)	$1,161	($153,080)	Impact of a 10% decrease in forward commodity prices	$21,695	($4,789)	$16,906

(1)Spot prices for oil and natural gas were ~~$104.83~~$70.69 and ~~$5.42,~~$2.80, respectively, as of June 30, ~~2022~~.2023.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of June 30, ~~2022,~~2023, we had ~~$779.0~~$528.0 million outstanding under the Credit Facility with a weighted average interest rate of ~~4.16%~~7.26%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual interest expense of approximately ~~$7.8~~$5.3 million, based on the balance outstanding as of June 30, ~~2022.~~2023. See “Note ~~6 -~~8 — Borrowings” for more information on our Credit Facility.

Item 4. Controls and Procedures

Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our management, with the participation of ~~the Chief Executive Officer~~our principal executive and ~~Chief Financial Officer,~~principal financial officers, performed an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of June 30, ~~2022.~~2023.

Changes in Internal Control Over Financial Reporting. There were no changes in our internal ~~control~~controls over financial reporting (as such term is defined in ~~Rule~~Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the second quarter of ~~2022~~2023 that ~~have~~has materially affected, or ~~are~~is reasonably likely to materially affect, ~~the Company’s~~our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

We are a party in various legal proceedings and claims, which arise in the ordinary course of our business. While the outcome of these events cannot be predicted with certainty, we believe that the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations.

As previously reported in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2022, in January 2022, we received a Notice of Violation from the United States Environmental Protection Agency (the “EPA”) related to the Clean Air Act. To resolve the

alleged violations, on June 9, 2023, we agreed to a Consent Agreement and Final Order (“CAFO”) with the EPA, which became effective June 20, 2023. The CAFO assessed a civil penalty in the amount of approximately $1.3 million and requires us to perform certain actions over the course of the next year, including facility reviews, additional monitoring, and the submission of a final letter report in June 2024. We have begun implementing the requirements of the CAFO. We believe that the settlement was in the best interests of the Company and its shareholders to avoid the uncertainty, risk, expense, and distraction of protracted litigation.

Item 1A. Risk Factors

There have been no material changes to the risk factors set forth under the heading “Part I, Item 1A. Risk Factors” included in our ~~2021~~2022 Annual ~~Report on Form 10-K.~~Report. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

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

~~None.~~

Pursuant to the Percussion Agreement, on May 3, 2023, the Company agreed to issue $210.0 million in shares of the Company’s common stock (determined by reference to a price per share designated pursuant to the terms of the Percussion Agreement), subject to customary purchase price adjustments, as a portion of the total consideration for the Percussion Acquisition. On July 3, 2023, the Company completed the Percussion Acquisition and issued approximately 6.3 million shares of its common stock to Percussion as partial consideration for the Percussion Acquisition, subject to customary post-closing purchase price adjustments. The shares were issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) of the Securities Act as sales by an issuer not involving any public offering. The issuance of such shares did not involve a public offering for purposes of Section 4(a)(2) because of, among other things, its being made only to the seller in the Percussion Acquisition, such person’s status as an accredited investor and the manner of the issuance, including that the Company did not engage in general solicitation or advertising with regard to the issuance of such shares.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

The following exhibits are filed as part of this Form 10-Q.
Incorporated by reference (File No. 001-14039, unless otherwise indicated)
Exhibit Number Description Form Exhibit Filing Date
3.1
Certificate of Incorporation of the Company, as amended through May 12, 2016
10-Q 3.1 11/3/2016
3.2
Certificate of Amendment to the Certificate of Incorporation of Callon, effective December 20, 2019
8-K 3.1 12/20/2019
3.3
Certificate of Amendment to the Certificate of Incorporation of Callon, effective August 7, 2020
8-K 3.1 8/7/2020
3.4
Certificate of Amendment to the Certificate of Incorporation of Callon, effective May 14, 2021
8-K 3.1 5/14/2021
3.5
Certificate of Amendment to the Certificate of Incorporation of Callon, effective May 25, 2022
8-K 3.1 5/25/2022
3.6
Amended and Restated Bylaws of the Company
10-K 3.2 2/27/2019
4.1
Indenture, dated as of June 24, 2022, by and among the Company, Callon Petroleum Operating Company, Callon (Permian) LLC, Callon (Eagle Ford) LLC, Callon (Permian) Minerals LLC, Callon (Niobrara) LLC, Callon (Utica) LLC and Callon Marcellus Holding, Inc. and U.S. Bank Trust Company, National Association, as trustee.
8-K 4.1 6/24/2022
10.1
Purchase Agreement dated as of June 9, 2022, among Callon Petroleum Company, the Guarantors and Wells Fargo Securities, LLC, as representative of the several initial purchasers.
8-K 10.1 6/9/2022
31.1 (a)
Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)
31.2 (a)
Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)
32.1 (b)
Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b)
101.INS (a) 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 (a) Inline XBRL Taxonomy Extension Schema Document
101.CAL (a) Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF (a) Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB (a) Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE (a) Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104 (a) Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

Incorporated by reference (File No. 001-14039, unless otherwise indicated)

Exhibit Number

Description

Form

Exhibit

Filing Date

2.1

(c)

Membership Interest Purchase Agreement by and among Percussion Petroleum Management II, LLC, Percussion Petroleum Operating II, LLC, Callon Petroleum Operating Company and Callon Petroleum Company dated May 3, 2023.

8-K

10.1

5/8/2023

2.2

(c)

Membership Interest Purchase Agreement by and among Callon Petroleum Operating Company, Callon (Eagle Ford) LLC and Ridgemar Energy Operating, LLC dated May 3, 2023.

8-K

10.2

5/8/2023

3.1

Certificate of Incorporation of the Company, as amended through May 12, 2016

10-Q

3.1

11/3/2016

3.2

Certificate of Amendment to the Certificate of Incorporation of Callon, effective December 20, 2019

8-K

3.1

12/20/2019

3.3

Certificate of Amendment to the Certificate of Incorporation of Callon, effective August 7, 2020

8-K

3.1

8/7/2020

3.4

Certificate of Amendment to the Certificate of Incorporation of Callon, effective May 14, 2021

8-K

3.1

5/14/2021

3.5

Certificate of Amendment to the Certificate of Incorporation of Callon, effective May 25, 2022

8-K

3.1

5/25/2022

3.6

Amended and Restated Bylaws of the Company

10-K

3.2

2/27/2019

4.1

Registration Rights Agreement by and between Callon Petroleum Company and Percussion Petroleum Management II, LLC, dated July 3, 2023

8-K

4.1

7/7/2023

4.2

(a)

Second Supplemental Indenture of 6.375% Senior Notes Due 2026, dated July 3, 2023, among Callon Petroleum Company, Callon Permian II, LLC and U.S. Bank Trust Company, National Association, as Trustee

4.3

(a)

First Supplemental Indenture of 8.00% Senior Notes Due 2028, dated July 3, 2023, among Callon Petroleum Company, Callon Permian II, LLC and U.S. Bank Trust Company, National Association, as Trustee

4.4

(a)

First Supplemental Indenture of 7.500% Senior Notes Due 2030, dated July 3, 2023, among Callon Petroleum Company, Callon Permian II, LLC and U.S. Bank Trust Company, National Association, as Trustee

10.1

(a)(b)

Form of Callon Petroleum Company Market Stock Unit Award Agreement, adopted on April 26, 2023, under the 2020 Omnibus Incentive Plan

31.1

(a)

Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)

31.2

(a)

Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)

32.1

(b)

Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b)

101.INS

(a)

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

(a)

Inline XBRL Taxonomy Extension Schema Document

101.CAL

(a)

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

(a)

Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

(a)

Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE

(a)

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104

(a)

Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

(a)Filed herewith.

(b)Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act, except to the extent that the registrant specifically incorporates it by reference.

(c)Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. Callon agrees to furnish a supplemental copy of any omitted schedule or attachment to the SEC upon request.

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.

Callon Petroleum Company


Signature	Title	Date

/s/ Joseph C. Gatto, Jr.	President and	August ~~4, 2022~~2, 2023
Joseph C. Gatto, Jr.	Chief Executive Officer


/s/ Kevin Haggard	Senior Vice President and	August ~~4, 2022~~2, 2023
Kevin Haggard	Chief Financial Officer

3238


Part I. Financial Information

Item 1. Financial Statements (Unaudited)

Consolidated Balance Sheets			3

Consolidated Statements of Operations			4

Consolidated Statements of Stockholders’ Equity			5

Consolidated Statements of Cash Flows			6

Notes to Consolidated Financial Statements			7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			2126

Item 3. Quantitative and Qualitative Disclosures about Market Risk			2935

Item 4. Controls and Procedures			3035

Part II. Other Information

Item 1. Legal Proceedings			3035

Item 1A. Risk Factors			3036

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			3036

Item 3. Defaults Upon Senior Securities			3136

Item 4. Mine Safety Disclosures			3136

Item 5. Other Information			3136

Item 6. Exhibits			3137


	As of December 31, 2021
	Presented without		As Presented with
	Effects of Netting	Effects of Netting	Effects of Netting
	(In thousands)
Assets
Commodity derivative instruments	$25,469	($23,921)	$1,548
Contingent consideration arrangements	20,833	—	20,833
Fair value of derivatives - current	$46,302	($23,921)	$22,381
Commodity derivative instruments	$1,119	($869)	$250
Contingent consideration arrangements	—	—	—
Other assets, net	$1,119	($869)	$250

Liabilities
Commodity derivative instruments (1)	($184,898)	$23,921	($160,977)
Contingent consideration arrangements	(25,000)	—	(25,000)
Fair value of derivatives - current	($209,898)	$23,921	($185,977)
Commodity derivative instruments	($12,278)	$869	($11,409)
Contingent consideration arrangements	—	—	—

Fair value of derivatives - non-current	($12,278)	$869	($11,409)


	Three Months Ended		Six Months Ended
	March 31, 2022	June 30, 2022		June 30, 2022
	(In millions)
Operational capital	$157.4	$237.8		$395.2
Capitalized interest	25.5	26.3		51.8
Capitalized G&A	11.6	11.3		22.9
Total	$194.5	$275.4		$469.9


	12-Month Average Realized Prices		Excess (deficit) of cost center ceiling over net book value, less related deferred income taxes	Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes
Full Cost Pool Scenarios	Crude Oil ($/Bbl)	Natural Gas ($/Mcf)	(In millions)	(In millions)
June 30, 2022 Actual	$85.62	$4.82	$4,819

Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$94.20	$5.34	$5,935	$1,116
Crude Oil and Natural Gas -10%	$77.04	$4.31	$3,703	($1,116)

Crude Oil Price Sensitivity
Crude Oil +10%	$94.20	$4.82	$5,833	$1,014
Crude Oil -10%	$77.04	$4.82	$3,805	($1,014)

Natural Gas Price Sensitivity
Natural Gas +10%	$85.62	$5.34	$4,920	$101
Natural Gas -10%	$85.62	$4.31	$4,718	($101)