cpe-20230930

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 September 30, 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 67,773,848 shares of common stock outstanding as of October 27, 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, 2022 (“2022 Annual Report”).

Table of Contents


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			26

Item 3. Quantitative and Qualitative Disclosures about Market Risk			35

Item 4. Controls and Procedures			36

Part II. Other Information

Item 1. Legal Proceedings			36

Item 1A. Risk Factors			36

Item 2. Unregistered Sales of Equity Securities, Use of Proceeds and Issuer Purchases of Equity Securities			36

Item 3. Defaults Upon Senior Securities			36

Item 4. Mine Safety Disclosures			37

Item 5. Other Information			37

Item 6. Exhibits			37

Part I. Financial Information

Item 1. Financial Statements

Callon Petroleum Company

Consolidated Balance Sheets

(In thousands, except par and share amounts)

(Unaudited)


	September 30, 2023	December 31, 2022*
ASSETS
Current assets:
Cash and cash equivalents	$3,456	$3,395
Accounts receivable, net	262,394	237,128
Fair value of derivatives	1,196	21,332

Other current assets	29,665	35,783
Total current assets	296,711	297,638
Oil and natural gas properties, successful efforts accounting method:


Proved properties, net	4,815,776	4,851,529
Unproved properties	1,287,019	1,225,768
Total oil and natural gas properties, net	6,102,795	6,077,297

Other property and equipment, net	26,398	26,152
Deferred income taxes	199,734	—
Deferred financing costs	14,235	18,822
Fair value of derivatives	21,742	454
Other assets, net	66,908	68,106
Total assets	$6,728,523	$6,488,469
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$585,529	$536,233


Fair value of derivatives	61,189	16,197

Other current liabilities	103,077	150,384
Total current liabilities	749,795	702,814
Long-term debt	1,948,619	2,241,295

Asset retirement obligations	41,290	53,892

Fair value of derivatives	44,807	13,415
Other long-term liabilities	82,954	51,272
Total liabilities	2,867,465	3,062,688
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value, 130,000,000 shares authorized; 67,770,721 and 61,621,518 shares outstanding, respectively	678	616
Capital in excess of par value	4,225,183	4,022,194
Accumulated deficit	(364,803)	(597,029)
Total stockholders’ equity	3,861,058	3,425,781
Total liabilities and stockholders’ equity	$6,728,523	$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 September 30,		Nine Months Ended September 30,
	2023	2022*	2023	2022*
Operating Revenues:
Oil	$438,665	$575,852	$1,269,996	$1,748,913
Natural gas	25,045	81,018	63,054	189,907
Natural gas liquids	46,489	67,548	130,488	210,696
Sales of purchased oil and gas	109,099	111,459	278,089	377,199
Total operating revenues	619,298	835,877	1,741,627	2,526,715

Operating Expenses:
Lease operating	73,525	76,121	225,415	216,389
Production and ad valorem taxes	30,592	43,290	88,019	125,841
Gathering, transportation and processing	27,255	27,575	80,570	71,617
Exploration	3,588	2,942	7,702	7,237
Cost of purchased oil and gas	111,118	111,439	285,947	378,107
Depreciation, depletion and amortization	138,598	129,895	391,911	359,494
Impairment of oil and gas properties	—	—	406,898	—
Gain on sale of oil and gas properties	(20,570)	—	(20,570)	—
General and administrative	29,339	24,253	86,905	71,485
Merger, integration and transaction	4,925	—	6,468	769

Total operating expenses	398,370	415,515	1,559,265	1,230,939
Income From Operations	220,928	420,362	182,362	1,295,776

Other (Income) Expenses:
Interest expense	43,149	46,929	136,694	141,020
(Gain) loss on derivative contracts	55,804	(134,850)	24,218	305,098
(Gain) loss on extinguishment of debt	(1,238)	—	(1,238)	42,417
Other (income) expense	3,220	2,861	(3,140)	3,130
Total other (income) expense	100,935	(85,060)	156,534	491,665

Income Before Income Taxes	119,993	505,422	25,828	804,111
Income tax benefit (expense)	(509)	(3,383)	206,398	(6,536)
Net Income	$119,484	$502,039	$232,226	$797,575

Net Income Per Common Share:
Basic	$1.76	$8.14	$3.64	$12.94
Diluted	$1.75	$8.11	$3.63	$12.88

Weighted Average Common Shares Outstanding:
Basic	67,931	61,703	63,827	61,624
Diluted	68,083	61,870	64,016	61,927

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, 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
Net income	—	—	—	119,484	119,484
Restricted stock units	2	—	3,881	—	3,881
Common stock issued for Percussion Acquisition	6,267	63	209,937	—	210,000
Repurchase and retirement of common stock	(386)	(4)	(14,975)	—	(14,979)
Balance at September 30, 2023	67,771	$678	$4,225,183	($364,803)	$3,861,058


	Common		Capital in		Total
	Stock		Excess	Accumulated	Stockholders’
	Shares	$	of Par	Deficit	Equity
Previously reported at December 31, 2021	61,371	$614	$4,012,358	($2,147,204)	$1,865,768
Effect of change in accounting principle	—	—	—	530,732	530,732
Balance at December 31, 2021 as recast*	61,371	$614	$4,012,358	($1,616,472)	$2,396,500
Net loss	—	—	—	(7,715)	(7,715)
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	($1,624,187)	$2,397,870
Net income	—	—	—	303,251	303,251
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	($1,320,936)	$2,697,859
Net income	—	—	—	502,039	502,039
Restricted stock units	1	—	3,893	—	3,893
Common stock issued for Primexx Acquisition	(110)	(1)	(3,830)	—	(3,831)
Balance at September 30, 2022*	61,607	$616	$4,018,241	($818,897)	$3,199,960

*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)


	Nine Months Ended September 30,
Cash flows from operating activities:	2023	2022*
Net income	$232,226	$797,575
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	391,911	359,494
Impairment of oil and gas properties	406,898	—
Amortization of non-cash debt related items, net	7,979	9,680
Deferred income tax (benefit) expense	(206,041)	1,110
(Gain) loss on derivative contracts	24,218	305,098
Cash received (paid) for commodity derivative settlements, net	13,274	(433,518)
Gain on extinguishment of debt	(1,238)	42,417
Gain on sale of oil and gas properties	(20,570)	—
Non-cash expense related to share-based awards	9,524	4,427


Other, net	4,563	8,704
Changes in current assets and liabilities:
Accounts receivable	14,219	(52,423)
Other current assets	(13,178)	(12,229)
Accounts payable and accrued liabilities	(69,522)	(8,649)


Net cash provided by operating activities	794,263	1,021,686
Cash flows from investing activities:
Capital expenditures	(751,004)	(648,149)
Acquisition of oil and gas properties	(278,434)	(17,006)

Proceeds from sales of assets	551,446	9,313

Cash paid for settlement of contingent consideration arrangement	—	(19,171)
Other, net	(2,850)	13,497
Net cash used in investing activities	(480,842)	(661,516)
Cash flows from financing activities:
Borrowings on credit facility	2,629,500	2,535,000
Payments on credit facility	(2,736,500)	(2,684,000)
Issuance of 7.5% Senior Notes due 2030	—	600,000
Redemption of 8.25% Senior Notes due 2025	(187,238)	—
Redemption of 6.125% Senior Notes due 2024	—	(467,287)
Redemption of 9.0% Second Lien Senior Secured Notes due 2025	—	(339,507)







Payment of deferred financing costs	(560)	(11,623)


Cash paid to repurchase common stock	(14,980)	—
Other, net	(3,582)	1,715
Net cash used in financing activities	(313,360)	(365,702)
Net change in cash and cash equivalents	61	(5,532)
Balance, beginning of period	3,395	9,882
Balance, end of period	$3,456	$4,350

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

Index to the Notes to the Consolidated Financial Statements


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

Note 1 — 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 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.

Note 2 — Summary of 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 2022 Annual Report and are supplemented by the notes included in this Form 10-Q. The financial statements and related notes included in this Form 10-Q should be read in conjunction with the Company’s 2022 Annual Report.

Recast Financial Information for Change in Accounting Principle

In 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 Accounting Standards Codification (“ASC”) 932 “Extractive Activities — Oil and Gas.” Although the full cost method of accounting continues to be an accepted alternative, the successful efforts method of accounting is 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 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 prices and costs prescribed under the full cost method as of the balance sheet date. As required by ASC 250 “Accounting Changes and Error Corrections,” the Company has presented the accumulated effect of the change in accounting principle as a change in the beginning balance of retained earnings (accumulated deficit) of the earliest period presented in 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 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 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. See “Note 5 — Acquisitions and Divestitures” for details of the impairment recorded in the second quarter of 2023 associated with the sale of all 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 nine months ended September 30, 2023 and 2022, the Company did not have any projects that met the thresholds and, therefore, had no capitalized interest.

Share Repurchase Program

The Company repurchases shares of its common stock from time to time under a program authorized by the Board of Directors. The Company retires shares acquired through share repurchases and returns those shares to the status of authorized but unissued. The repurchased and retired shares are recorded as a reduction to “Common stock” and “Capital in excess of par value” in the consolidated balance sheets. See “Note 13 — Stockholders’ Equity” for further discussion.

Recently Issued Accounting Standards

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

Subsequent Events

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

Note 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 “Impairment of oil and gas properties” and “Gain on sale of oil and gas properties” line items presented in the tables below are in connection with the sale of 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 September 30, 2023
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands)


Oil and natural gas properties:
Proved properties	$11,191,350	($1,947,545)	$9,243,805
Accumulated depreciation, depletion, amortization and impairments	(6,734,174)	2,306,145	(4,428,029)
Unproved properties	1,807,300	(520,281)	1,287,019
Total oil and gas properties, net	6,264,476	(161,681)	6,102,795
Deferred income taxes	170,001	29,733	199,734
Total assets	$6,860,471	($131,948)	$6,728,523
Stockholders’ equity:
Accumulated deficit	(232,855)	(131,948)	(364,803)
Total stockholders' equity	3,993,006	(131,948)	3,861,058
Total liabilities and stockholders' equity	$6,860,471	($131,948)	$6,728,523


	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 September 30, 2023
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands, except per share amounts)
Operating Expenses:
Exploration	$—	$3,588	$3,588
Depreciation, depletion and amortization	138,313	285	138,598

Gain on sale of oil and gas properties	—	(20,570)	(20,570)
General and administrative	22,016	7,323	29,339
Income From Operations	211,554	9,374	220,928

Other Expenses:
Interest expense	14,145	29,004	43,149

Income Before Income Taxes	139,623	(19,630)	119,993
Income tax benefit (expense)	10,663	(11,172)	(509)
Net Income	$150,286	($30,802)	$119,484
Net Income Per Common Share:
Basic	$2.21		$1.76
Diluted	$2.21		$1.75


	Three Months Ended September 30, 2022
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands, except per share amounts)
Operating Expenses:
Exploration	$—	$2,942	$2,942
Depreciation, depletion and amortization	122,833	7,062	129,895
General and administrative	14,022	10,231	24,253
Income From Operations	440,597	(20,235)	420,362

Other Expenses:
Interest expense	19,468	27,461	46,929

Income Before Income Taxes	553,118	(47,696)	505,422
Income tax expense	(3,515)	132	(3,383)
Net Income	$549,603	($47,564)	$502,039
Net Income Per Common Share:
Basic	$8.91		$8.14
Diluted	$8.88		$8.11


	Nine Months Ended September 30, 2023
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands, except per share amounts)
Operating Expenses:
Exploration	$—	$7,702	$7,702
Depreciation, depletion and amortization	396,348	(4,437)	391,911
Impairment of oil and gas properties	—	406,898	406,898
Gain on sale of oil and gas properties	—	(20,570)	(20,570)
General and administrative	56,305	30,600	86,905
Income From Operations	602,555	(420,193)	182,362

Other Expenses:
Interest expense	52,818	83,876	136,694

Income Before Income Taxes	529,897	(504,069)	25,828
Income tax benefit	174,636	31,762	206,398
Net Income	$704,533	($472,307)	$232,226
Net Income Per Common Share:
Basic	$11.04		$3.64
Diluted	$11.01		$3.63


	Nine Months Ended September 30, 2022
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands, except per share amounts)
Operating Expenses:
Exploration	$—	$7,237	$7,237
Depreciation, depletion and amortization	335,221	24,273	359,494
General and administrative	42,052	29,433	71,485
Income From Operations	1,356,719	(60,943)	1,295,776

Other Expenses:
Interest expense	61,717	79,303	141,020

Income Before Income Taxes	944,357	(140,246)	804,111
Income tax expense	(7,008)	472	(6,536)
Net Income	$937,349	($139,774)	$797,575
Net Income Per Common Share:
Basic	$15.21		$12.94
Diluted	$15.14		$12.88

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


	Nine Months Ended September 30, 2023
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands)
Cash flows from operating activities:
Net income	$704,533	($472,307)	$232,226
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	396,348	(4,437)	391,911
Impairment of oil and gas properties	—	406,898	406,898
Amortization of non-cash debt related items, net	3,064	4,915	7,979
Deferred income tax benefit	(174,279)	(31,762)	(206,041)
Gain on sale of oil and gas properties	—	(20,570)	(20,570)
Non-cash expense related to share-based awards	3,848	5,676	9,524




Net cash provided by operating activities	905,850	(111,587)	794,263
Cash flows from investing activities:
Capital expenditures	(854,889)	103,885	(751,004)
Acquisition of oil and gas properties	(286,136)	7,702	(278,434)
Net cash used in investing activities	(592,429)	111,587	(480,842)
Net change in cash and cash equivalents	61	—	61
Balance, beginning of period	3,395	—	3,395
Balance, end of period	$3,456	$—	$3,456


	Nine Months Ended September 30, 2022
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands)
Cash flows from operating activities:
Net income	$937,349	($139,774)	$797,575
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	335,221	24,273	359,494
Amortization of non-cash debt related items, net	4,263	5,417	9,680
Deferred income tax expense	1,626	(516)	1,110
Non-cash expense related to share-based awards	1,055	3,372	4,427
Changes in current assets and liabilities:


Accounts payable and accrued liabilities	(8,693)	44	(8,649)
Net cash provided by operating activities	1,128,870	(107,184)	1,021,686
Cash flows from investing activities:
Capital expenditures	(754,225)	106,076	(648,149)
Acquisition of oil and gas properties	(18,114)	1,108	(17,006)
Net cash used in investing activities	(768,700)	107,184	(661,516)
Net change in cash and cash equivalents	(5,532)	—	(5,532)
Balance, beginning of period	9,882	—	9,882
Balance, end of period	$4,350	$—	$4,350

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


	As of September 30, 2023
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands)
Accumulated deficit	($232,855)	($131,948)	($364,803)
Total stockholders’ equity	$3,993,006	($131,948)	$3,861,058


	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 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 September 30, 2023 and December 31, 2022 of $169.3 million and $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 5 — Acquisitions and Divestitures

Eagle Ford Divestiture

On May 3, 2023, the Company entered into an agreement with Ridgemar Energy Operating, LLC (“Ridgemar”) for the sale of all its oil and gas properties in the Eagle Ford (the “Eagle Ford Divestiture”) for consideration of $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 (“Contingent Eagle Ford Consideration”). See “Note 9 — Derivative Instruments and Hedging Activities” for further discussion of the Contingent Eagle Ford Consideration. Upon signing, Ridgemar paid approximately $49.1 million as a deposit into a third-party escrow account. The transaction was 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.

During the second quarter of 2023, the Company classified the assets and liabilities associated with the Eagle Ford Divestiture as held for sale, and recorded an impairment of $406.9 million against 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. On July 3, 2023, the Company closed the Eagle Ford Divestiture. The Eagle Ford Divestiture has an adjusted purchase price of approximately $549.3 million in cash, inclusive of the deposit paid at signing, subject to customary post-closing purchase price adjustments. As a result, the Company recorded a gain on sale of assets of $20.6 million.

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. Upon signing, the Company paid $36.0 million as a deposit into a third-party escrow account. The transaction was 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 Operating”).

On July 3, 2023, the Company closed the Percussion Acquisition for an adjusted purchase price of approximately $248.5 million in cash, inclusive of the deposit paid at signing and the repayment of Percussion Operating’s indebtedness of approximately $220.0 million, and approximately 6.3 million shares of the Company’s common stock for total consideration of $458.5 million, subject to customary post-closing purchase price adjustments. The Company funded the cash portion of the total consideration with proceeds from the Eagle Ford Divestiture. Additionally, the Company assumed Percussion Operating’s (as defined below) existing hedges and transportation contract liabilities, and could have to pay up to $62.5 million if the WTI price of oil exceeds certain thresholds in 2023, 2024, and 2025 (“Percussion Earn-Out Obligation”).

The Percussion Acquisition was accounted for as a business combination; therefore, 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. The Company expects to complete 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 $458.5 million to the assets acquired and liabilities assumed as of the acquisition date.


						Preliminary Purchase Price Allocation
						(In thousands)
Assets:
Accounts receivable, net						$30,135
Proved properties, net						491,367
Unproved properties						52,590
Total assets acquired						$574,092

Liabilities:
Accounts payable and accrued liabilities						$42,585
Fair value of derivatives - current						20,660
Other current liabilities						11,471
Asset retirement obligations						2,323
Fair value of derivatives - long-term						27,979
Other long-term liabilities						10,619
Total liabilities assumed						$115,637

Total consideration						$458,455

Approximately $57.8 million of revenues and $16.3 million of direct operating expenses attributed to the assets acquired in the Percussion Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on July 3, 2023 through September 30, 2023.

Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the three and nine months ended September 30, 2023 and 2022 was derived from the historical financial statements of the Company and gives effect to the Percussion Acquisition, as if it had occurred on January 1, 2022. The below information reflects pro forma adjustments for the issuance of the Company’s common stock, 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 Percussion 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 Percussion Acquisition taken place on January 1, 2022 and is not intended to be a projection of future results.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022*	2023	2022*
	(In thousands, except per share amounts)
Revenues	$619,298	$928,218	$1,879,442	$2,815,342
Income from operations	220,928	480,459	252,809	1,490,205
Net income	119,484	708,355	360,850	856,610
Basic earnings per common share	$1.76	$10.42	$5.65	$12.62
Diluted earnings per common share	$1.75	$10.40	$5.64	$12.56

Note 6 — Property and Equipment, Net

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


	September 30, 2023	December 31, 2022*
Oil and natural gas properties, successful efforts accounting method	(In thousands)
Proved properties	$9,243,805	$9,268,135
Accumulated depreciation, depletion, amortization and impairments	(4,428,029)	(4,416,606)
Proved properties, net	4,815,776	4,851,529
Unproved properties	1,287,019	1,225,768
Total oil and natural gas properties, net	$6,102,795	$6,077,297

Other property and equipment	$40,243	$40,530
Accumulated depreciation	(13,845)	(14,378)
Other property and equipment, net	$26,398	$26,152

Note 7 — Earnings Per Share

Basic earnings per share is computed by dividing net income 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 outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive.

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022*	2023	2022*
	(In thousands, except per share amounts)



Net Income	$119,484	$502,039	$232,226	$797,575
Basic weighted average common shares outstanding	67,931	61,703	63,827	61,624
Dilutive impact of restricted stock units	152	167	189	303

Diluted weighted average common shares outstanding	68,083	61,870	64,016	61,927

Net Income Per Common Share
Basic	$1.76	$8.14	$3.64	$12.94
Diluted	$1.75	$8.11	$3.63	$12.88

Restricted stock units (1)	54	100	75	28
Warrants (1)	481	481	481	416

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

Note 8 — Borrowings

The Company’s borrowings consisted of the following:


	September 30, 2023	December 31, 2022
	(In thousands)
8.25% Senior Notes due 2025	$—	$187,238
6.375% Senior Notes due 2026	320,783	320,783
Senior Secured Revolving Credit Facility due 2027	396,000	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	1,966,783	2,261,021
Unamortized premium on 8.25% Senior Notes	—	1,715
Unamortized deferred financing costs for Senior Notes	(18,164)	(21,441)
Long-term debt (1)	$1,948,619	$2,241,295

(1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $14.2 million and $18.8 million as of September 30, 2023 and December 31, 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 September 30, 2023, had a maximum credit amount of $5.0 billion, a borrowing base of $2.0 billion and an elected commitment amount of $1.5 billion, with borrowings outstanding of $396.0 million at a weighted-average interest rate of 7.50%, and letters of credit outstanding of $21.4 million. The credit agreement governing the Credit Facility (the “Credit Agreement”) provides for interest-only payments until October 19, 2027 when the Credit Agreement matures and any outstanding borrowings are due.

Borrowings outstanding under the Credit Agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 0.75% to 1.75%, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50%, and the SOFR plus 0.1% (“Adjusted SOFR”) for a one month period plus 1.00%, or (ii) an Adjusted SOFR plus a margin between 1.75% to 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” in the consolidated statements of operations.

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 October 31, 2023, as part of the Company’s fall 2023 redetermination, the borrowing base of $2.0 billion and elected commitment amount of $1.5 billion were reaffirmed.

Redemption of 8.25% Senior Notes due 2025

On August 2, 2023, the Company used borrowings under the Credit Facility to redeem all $187.2 million of its outstanding 8.25% Senior Notes due 2025 (“8.25% Senior Notes”). The Company recognized a gain on extinguishment of debt of approximately $1.2 million in its consolidated statements of operations, which primarily related to the remaining unamortized premium.

Covenants

The Credit Agreement and the indentures governing the 6.375% Senior Notes due 2026, the 8.0% Senior Notes due 2028, and the 7.5% Senior Notes due 2030 (collectively, the “Senior 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, 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) of no more than 3.50 to 1.00 and (2) a Current Ratio (as defined in the Credit Agreement) of not less than 1.00 to 1.00. The Company was in compliance with these covenants at September 30, 2023.

The 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 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, 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.

The Company strives to minimize its credit exposure to any individual counterparty and, as such, the Company has outstanding commodity derivative instruments with nine counterparties as of September 30, 2023. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s 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 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 10 — Fair Value Measurements” for further discussion.

Contingent Consideration Arrangements

Percussion Earn-Out Obligation. As a result of the Percussion Acquisition, the Company assumed an earn-out obligation from Percussion Operating, where the Company could be required to pay up to $62.5 million in the aggregate if the average daily settlement price of WTI crude oil exceeds $60.00 per barrel for each of the 2023, 2024, and 2025 calendar years.

Contingent Eagle Ford Consideration. As a result of the Eagle Ford Divestiture, the Company received a contingent consideration arrangement from Ridgemar. The Company could receive up to $45.0 million if the average daily settlement price of WTI crude oil for 2024 is at least $80.00 per barrel. If the average daily settlement price of WTI crude oil for 2024 is less than $80.00 per barrel but at least $75.00 per barrel, then the Company would receive $20.0 million.

The Company determined that the Percussion Earn-Out Obligation and Contingent Eagle Ford Consideration receipt were not clearly and closely related to the Percussion Acquisition and Eagle Ford Divestiture membership interest purchase agreements, and therefore bifurcated these embedded features and recorded these derivatives at their acquisition date fair value and divestiture date fair value of $34.9 million and $10.9 million, respectively, in the consolidated financial statements. As of September 30, 2023, the estimated fair values of the Percussion Earn-Out Obligation and Contingent Eagle Ford Consideration were $46.4 million and $21.7 million, respectively, and are presented in “Fair value of derivatives” in the consolidated balance sheets.

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 well as settlements during the 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 September 30, 2023
	Presented without		As Presented with
	Effects of Netting	Effects of Netting	Effects of Netting
	(In thousands)
Derivative Assets
Commodity derivative instruments	$9,792	($8,596)	$1,196
Fair value of derivatives - current	$9,792	($8,596)	$1,196
Commodity derivative instruments	$4,270	($4,208)	$62
Contingent consideration arrangements	21,680	—	21,680
Fair value of derivatives - non-current	$25,950	($4,208)	$21,742

Derivative Liabilities
Commodity derivative instruments	($57,575)	$8,596	($48,979)
Contingent consideration arrangements	(12,210)	—	(12,210)
Fair value of derivatives - current	($69,785)	$8,596	($61,189)
Commodity derivative instruments	($14,805)	$4,208	($10,597)
Contingent consideration arrangements	(34,210)	—	(34,210)
Fair value of derivatives - non-current	($49,015)	$4,208	($44,807)


	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
Fair value of derivatives - non-current	$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)

The components of “(Gain) loss on derivative contracts” are as follows for the respective periods:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
	(In thousands)
(Gain) loss on oil derivatives	$54,446	($157,731)	$18,165	$243,527
(Gain) loss on natural gas derivatives	(2,315)	22,881	2,380	56,800
Loss on NGL derivatives	2,933	—	2,933	4,771
Loss on contingent consideration arrangements	740	—	740	—

(Gain) loss on derivative contracts	$55,804	($134,850)	$24,218	$305,098

The components of “Cash 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 September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
	(In thousands)
Cash flows from operating activities
Cash received (paid) on oil derivatives	$1,680	($117,024)	($4,450)	($374,711)
Cash received (paid) on natural gas derivatives	(560)	(28,572)	17,816	(55,024)
Cash paid on NGL derivatives	(92)	—	(92)	(3,783)
Cash received (paid) for commodity derivative settlements, net	$1,028	($145,596)	$13,274	($433,518)
Cash received for settlements of contingent consideration arrangements, net (1)	$—	$—	$—	$6,492

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

Cash flows from financing activities
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 contingent consideration arrangements.

Derivative Positions

Listed in the tables below are the outstanding oil, natural gas, and NGL derivative contracts as of September 30, 2023:


	For the Remainder	For the Full Year
Oil Contracts (WTI)	2023	2024
Swap Contracts
Total volume (Bbls)	—	1,076,300
Weighted average price per Bbl	$—	$81.66
Collar Contracts (Three-Way Collars)
Total volume (Bbls)	541,528	3,963,025
Weighted average price per Bbl
Ceiling (short call)	$70.95	$78.86
Floor (long put)	$55.00	$58.16
Floor (short put)	$45.00	$48.16
Collar Contracts (Two-Way Collars)
Total volume (Bbls)	993,455	—
Weighted average price per Bbl
Ceiling (short call)	$87.20	$—
Floor (long put)	$72.04	$—









CMA Roll Swap Contracts
Total volume (Bbls)	838,828	—
Weighted average price per Bbl	$0.30	$—


	For the Remainder	For the Full Year
Natural Gas Contracts (Henry Hub)	2023	2024
Swap Contracts
Total volume (MMBtu)	620,000	—
Weighted average price per MMBtu	$3.00	$—
Collar Contracts
Total volume (MMBtu)	2,201,104	8,598,557
Weighted average price per MMBtu
Ceiling (short call)	$5.37	$3.89
Floor (long put)	$3.14	$3.00




Natural Gas Contracts (Waha Basis Differential)
Swap Contracts
Total volume (MMBtu)	2,460,000	7,320,000
Weighted average price per MMBtu	($1.49)	($1.06)

Natural Gas Contracts (HSC Basis Differential)
Swap Contracts
Total volume (MMBtu)	2,760,000	14,640,000
Weighted average price per MMBtu	($0.29)	($0.42)


	For the Remainder	For the Full Year
NGL Contracts (Mont Belvieu Natural Gasoline)	2023	2024
Swap Contracts
Total volume (Bbls)	43,105	—
Weighted average price per Bbl	$56.38	$—
NGL Contracts (Mont Belvieu Propane)
Swap Contracts
Total volume (Bbls)	35,754	—
Weighted average price per Bbl	$31.27	$—
NGL Contracts (Mont Belvieu Purity Ethane)
Swap Contracts
Total volume (Bbls)	35,095	—
Weighted average price per Bbl	$9.54	$—
NGL Contracts (Mont Belvieu Normal Butane)
Swap Contracts
Total volume (Bbls)	33,470	72,105
Weighted average price per Bbl	$35.56	$33.18
NGL Contracts (Mont Belvieu Isobutane)
Swap Contracts
Total volume (Bbls)	10,967	23,462
Weighted average price per Bbl	$35.42	$33.18

Note 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 Senior Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy.


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


8.25% Senior Notes	$—	$—	$187,238	$186,719
6.375% Senior Notes	320,783	314,634	320,783	301,732
8.0% Senior Notes	650,000	650,800	650,000	616,935
7.5% Senior Notes	600,000	581,754	600,000	550,812
Total	$1,570,783	$1,547,188	$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 9 — Derivative Instruments and Hedging Activities” for further discussion.

Contingent Consideration Arrangements - Embedded Derivative Financial Instruments. The embedded options within the contingent consideration arrangements are considered financial instruments under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded options on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates undiscounted payouts, and risk adjusts for the discount rates inclusive of adjustments for each of the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered Level 2 inputs within the fair value hierarchy. See “Note 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 September 30, 2023 and December 31, 2022:


	September 30, 2023
	Level 1	Level 2	Level 3
	(In thousands)
Derivative Assets
Commodity derivative instruments	$—	$1,258	$—
Contingent consideration arrangements	—	21,680	—
Total net assets	$—	$22,938	$—
Derivative Liabilities
Commodity derivative instruments	$—	($59,576)	$—
Contingent consideration arrangements	—	(46,420)	—
Total net liabilities	$—	($105,996)	$—

	December 31, 2022
	Level 1	Level 2	Level 3
	(In thousands)
Commodity derivative assets	$—	$21,786	$—
Commodity derivative liabilities	$—	($29,612)	$—

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 5 –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 11 — Income Taxes

The Company provides for income taxes at the statutory rate of 21%. Reported income tax expense differs from the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax 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 and nine months ended September 30, 2023, the Company recognized income tax expense of $0.5 million and income tax benefit of $206.4 million, respectively, as a result of the release of the valuation allowance recorded against the Company’s net deferred tax assets as discussed further below. For the three and nine months ended September 30, 2022, the Company recognized

income tax expense of $3.4 million and $6.5 million, respectively, as a result of the full valuation allowance that was in 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. As previously disclosed in the Company’s 2022 Annual Report, beginning in the second quarter of 2020 and through the fourth quarter of 2022, the Company maintained a valuation allowance against its net deferred tax assets. Considering all available evidence (both positive and negative), the Company concluded that it was more 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 deferred income tax benefit of $0.7 million and $206.1 million for the three and nine months ended September 30, 2023, respectively.

Note 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 nine months ended September 30, 2023:


	Nine Months Ended September 30, 2023
	RSU Equity Awards (In thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	800	$44.79
Granted	539	$34.54
Vested	(369)	$39.89
Forfeited	(128)	$44.00
Unvested, end of the period	842	$40.49

Grant activity for the nine months ended September 30, 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 $34.54.

The aggregate fair value of RSU Equity Awards that vested during the nine months ended September 30, 2023 was $12.3 million. As of September 30, 2023, unrecognized compensation costs related to unvested RSU Equity Awards were $25.3 million and will be recognized over a weighted average period of 2.0 years.

Cash-Settled Awards

As of September 30, 2023 and December 31, 2022, the Company had a total liability of $3.4 million and $6.5 million, respectively, for outstanding Cash-Settled Awards (as defined below). As of December 31, 2022, Cash-Settled Awards consisted of restricted stock unit awards that may be settled in cash (“Cash-Settled RSU Awards”) and stock appreciation rights to be settled in cash (“Cash SARs” and, collectively with the Cash-Settled RSU Awards, the “Cash-Settled Awards”). As of September 30, 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 Awards 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 September 30,		Nine Months Ended September 30,
	2023	2022*	2023	2022*
	(In thousands)
RSU Equity Awards	$3,906	$3,892	$11,613	$11,581
Cash-Settled Awards	49	(2,151)	(2,089)	(7,154)
Total share-based compensation expense (benefit), net	$3,955	$1,741	$9,524	$4,427

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

Note 13 - Stockholders’ Equity

On May 2, 2023, the board of directors (the “Board”) of the Company 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 outstanding common stock through the second quarter of 2025. Repurchases under the Share Repurchase Program may be made, from time to 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 Board at any time without prior notice.

During the three months ended September 30, 2023, the Company repurchased and retired 386,719 shares of common stock at a weighted average purchase price of $38.72 per common share for a total cost of approximately $15.0 million. As of September 30, 2023, the remaining authorized repurchase amount under the Share Repurchase Program was $285.0 million.

Note 14 — Accounts Receivable, Net


	September 30, 2023	December 31, 2022
	(In thousands)
Oil and natural gas receivables	$169,254	$174,107
Joint interest receivables	35,777	16,778
Other receivables	58,531	48,277
Total	263,562	239,162
Allowance for credit losses	(1,168)	(2,034)
Total accounts receivable, net	$262,394	$237,128

Note 15 — Accounts Payable and Accrued Liabilities


	September 30, 2023	December 31, 2022
	(In thousands)
Accounts payable	$254,568	$191,133
Revenues and royalties payable	230,918	244,408
Accrued capital expenditures	71,678	58,395
Accrued interest	28,365	42,297
Total accounts payable and accrued liabilities	$585,529	$536,233

Note 16 — Supplemental Cash Flow


	Nine Months Ended September 30,
	2023	2022*
	(In thousands)
Supplemental cash flow information:
Interest paid	$142,616	$159,832
Income taxes paid (1)	4,477	—



Non-cash investing and financing activities:
Change in accrued capital expenditures	$41,505	$13,966
Change in asset retirement costs	5,956	3,665

(1) The Company did not pay or receive a refund for any federal income tax for the nine months ended September 30, 2022. For the nine months ended September 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

Credit Agreement Reaffirmation

See “Note 8 — Borrowings” for discussion of the results of the Company’s fall 2023 borrowing base redetermination.

Special Note Regarding Forward-Looking Statements

This 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 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 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 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, access to existing lines of credit, inflation and rising interest rates;

•changes in the supply of and demand for oil and natural gas, including as a result of 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 drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services;

•our dependency on third-party service providers;

•restrictions on our ability to obtain, recycle and 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 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, 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 depends 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 our consolidated financial statements and accompanying notes included under Part I, Item I, “Financial Statements” of this Form 10-Q, as well as our consolidated financial statements, accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our 2022 Annual Report.

Financial information for all prior periods has been recast to reflect the retrospective application of the successful efforts method of accounting, as discussed under “Note 2 — Summary of Significant Accounting Policies” of the 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 Permian Basin in West 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 layers of the Wolfcamp and Bone Springs formations and the Spraberry shale. We have assembled a 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.

Recent Developments and Overview

Share Repurchase Program

During the three months ended September 30, 2023, we repurchased and retired 386,719 shares of common stock at a weighted average purchase price of $38.72 per common share for a total cost of $15.0 million. See “Note 13 — Stockholders’ Equity” for additional details.

Acquisition and Divestiture

On July 3, 2023, we closed the Percussion Acquisition for total consideration of approximately $458.5 million and the Eagle Ford Divestiture for cash consideration of approximately $549.3 million, both subject to customary post-closing purchase price adjustments. See “Note 5 — Acquisitions and Divestitures” for additional details.

Redemption of 8.25% Senior Notes due 2025

On July 3, 2023, we delivered a redemption notice with respect to all $187.2 million of our outstanding 8.25% Senior Notes, which were redeemed on August 2, 2023 using borrowings under our Credit Facility.

Third Quarter 2023 Highlights

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

Three Months Ended September 30, 2023

As of September 30, 2023

Drilled

Turned In-Line

Drilled But Uncompleted

Producing

Region

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Permian

19.6

30.0

21.1

917

809.5

•Operational capital expenditures, exclusive of leasehold, for the third quarter of 2023 were $251.0 million.

•Recorded net income for the three months ended September 30, 2023 of $119.5 million, or $1.75 per diluted share, compared to net income for the three months ended September 30, 2022 of $502.0 million, or $8.11 per diluted share. The variance between the periods was primarily due to a decrease in operating revenues in the third quarter of 2023 as a result of an approximate 26% decrease in the total average realized sales price and an approximate 5% decrease in production, as well as a loss on derivative contracts of $55.8 million during the third quarter of 2023 compared to a gain of approximately $134.9 million during the third quarter of 2022.

Results of Operations

This section discusses the material changes in the Company’s results of operations for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023 and for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022. Detailed financial information with respect to the Company’s results of operations for the three months ended June 30, 2023 can be found in Part I, Item 1, “Financial Statements” of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2023.

Production


	Three Months Ended							Nine Months Ended September 30,
	September 30, 2023		June 30, 2023		Change	% Change		2023		2022		Change	% Change
Total production
Oil (MBbls)
Permian	5,310		4,671		639	14	%	14,256		13,326		930	7	%
Eagle Ford	28		1,066		(1,038)	(97	%)	2,233		4,221		(1,988)	(47	%)
Total oil	5,338		5,737		(399)	(7	%)	16,489		17,547		(1,058)	(6	%)

Natural gas (MMcf)
Permian	11,644		10,409		1,235	12	%	31,341		26,506		4,835	18	%
Eagle Ford	44		1,292		(1,248)	(97	%)	2,672		4,578		(1,906)	(42	%)
Total natural gas	11,688		11,701		(13)	—	%	34,013		31,084		2,929	9	%

NGLs (MBbls)
Permian	2,069		1,816		253	14	%	5,457		4,779		678	14	%
Eagle Ford	6		229		(223)	(97	%)	457		767		(310)	(40	%)
Total NGLs	2,075		2,045		30	1	%	5,914		5,546		368	7	%

Total production (MBoe)
Permian	9,320		8,222		1,098	13	%	24,937		22,523		2,414	11	%
Eagle Ford	41		1,510		(1,469)	(97	%)	3,135		5,751		(2,616)	(45	%)
Total barrels of oil equivalent	9,361		9,732		(371)	(4	%)	28,072		28,274		(202)	(1	%)

Total daily production (Boe/d)	101,741		106,948		(5,207)	(5	%)	102,826		103,569		(743)	(1	%)
Percent of total daily production
Oil	57	%	59	%		(3	%)	59	%	62	%		(5	%)
Natural gas	21	%	20	%		5	%	20	%	18	%		11	%
NGLs	22	%	21	%		5	%	21	%	20	%		5	%

The decreases in production for both the three months ended September 30, 2023 and the nine months ended September 30, 2023 compared to the three months ended June 30, 2023 and the nine months ended September 30, 2022, respectively, were primarily due to the Eagle Ford Divestiture, as well as oil volumes that were negatively impacted by weather-related power and midstream disruptions in the third quarter and a lower-than-expected oil mix from recent completions in the western portion of our Permian acreage, partially offset by the Percussion Acquisition.

Pricing


	Three Months Ended					Nine Months Ended September 30,
	September 30, 2023	June 30, 2023	Change	% Change		2023	2022	Change	% Change
Benchmark prices (1)
WTI (per Bbl)	$82.18	$73.75	$8.43	11	%	$77.37	$98.14	($20.77)	(21	%)
Henry Hub (per Mcf)	2.66	2.32	0.34	15	%	2.58	6.67	(4.09)	(61	%)

Average realized sales price (excluding impact of derivative settlements)
Oil (per Bbl)
Permian	$82.19	$73.45	$8.74	12	%	$77.34	$99.62	($22.28)	(22	%)
Eagle Ford	79.61	73.80	5.81	8	%	75.01	99.84	(24.83)	(25	%)
Total oil	82.18	73.52	8.66	12	%	77.02	99.67	(22.65)	(23	%)

Natural gas (per Mcf)
Permian	2.13	1.15	0.98	85	%	1.79	5.98	(4.19)	(70	%)
Eagle Ford	4.82	1.93	2.89	150	%	2.64	6.84	(4.20)	(61	%)
Total natural gas	2.14	1.23	0.91	74	%	1.85	6.11	(4.26)	(70	%)

NGL (per Bbl)
Permian	22.25	20.14	2.11	10	%	22.22	38.34	(16.12)	(42	%)
Eagle Ford	74.33	17.72	56.61	319	%	20.26	35.82	(15.56)	(43	%)
Total NGLs	22.40	19.87	2.53	13	%	22.06	37.99	(15.93)	(42	%)

Total average realized sales price (per Boe)
Permian	54.43	47.63	6.80	14	%	51.32	74.12	(22.80)	(31	%)
Eagle Ford	70.41	56.44	13.97	25	%	58.63	83.50	(24.87)	(30	%)
Total average realized sales price	$54.50	$49.00	$5.50	11	%	$52.14	$76.02	($23.88)	(31	%)

(1) Reflects calendar average daily spot market prices.

Revenues


	Oil		Natural Gas		NGLs		Total
	(In thousands)
Revenues for the three months ended June 30, 2023 (1)	$421,775		$14,423		$40,629		$476,827
Volume increase (decrease)	(29,407)		(16)		596		(28,827)
Price increase	46,297		10,638		5,264		62,199
Net increase	16,890		10,622		5,860		33,372
Revenues for the three months ended September 30, 2023 (1)	$438,665		$25,045		$46,489		$510,199

Percent of total revenues	86	%	5	%	9	%

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

The increase in revenues for the three months ended September 30, 2023 compared to the three months ended June 30, 2023 was primarily due to an 11% increase in the average realized sales price, which increased to $54.50 per Boe from $49.00 per Boe, as shown above, partially offset by a 5% decrease in production as described above.


	Oil		Natural Gas		NGLs		Total
	(In thousands)
Revenues for the nine months ended September 30, 2022(1)	$1,748,913		$189,907		$210,696		$2,149,516
Volume increase (decrease)	(105,451)		17,895		13,981		(73,575)
Price decrease	(373,466)		(144,748)		(94,189)		(612,403)
Net decrease	(478,917)		(126,853)		(80,208)		(685,978)
Revenues for the nine months ended September 30, 2023 (1)	$1,269,996		$63,054		$130,488		$1,463,538

Percent of total revenues	87	%	4	%	9	%

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

The decrease in revenues for the nine months ended September 30, 2023 compared to the same period of 2022 was primarily due to a 31% decrease in the average realized sales price, which decreased to $52.14 per Boe from $76.02 per Boe, as well as a 1% decrease in production, as shown above.

Operating Expenses

Lease Operating Expenses


	Three Months Ended
	September 30, 2023	Per	June 30, 2023	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$73,685	$7.91	$61,021	$7.42	$12,664	21	%	$0.49	7	%
Eagle Ford	(160)	(3.90)	15,767	10.44	(15,927)	(101	%)	(14.34)	(137	%)
Lease operating	$73,525	$7.85	$76,788	$7.89	($3,263)	(4	%)	($0.04)	(1	%)

	Nine Months Ended September 30,
		Per		Per	Total Change			Boe Change
	2023	Boe	2022	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$192,921	$7.74	$163,273	$7.25	$29,648	18	%	$0.49	7	%
Eagle Ford	32,494	10.36	53,116	9.24	(20,622)	(39	%)	1.12	12	%
Lease operating	$225,415	$8.03	$216,389	$7.65	$9,026	4	%	$0.38	5	%

The decrease in lease operating expenses for the three months ended September 30, 2023 compared to the three months ended June 30, 2023 was primarily due to lower operating expenses associated with properties acquired in the Percussion Acquisition as compared to the properties disposed of in the Eagle Ford Divestiture as well as lower chemical costs and workover expense, partially offset by increases in other certain operating costs such as saltwater disposal and fuel and power. The decrease in lease operating expenses per Boe for the three months ended September 30, 2023 compared to the three months ended June 30, 2023 was primarily driven by the reduction in operating costs described above.

The increase in lease operating expenses, as well as the increase in lease operating expenses per Boe, for the nine months ended September 30, 2023 compared to the same period of 2022 was primarily due to increases in certain operating expenses such as saltwater disposal and fuel and power.

Production and Ad Valorem Taxes


	Three Months Ended
	September 30, 2023		Per	June 30, 2023		Per	Total Change			Boe Change
			Boe			Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$30,407		$3.26	$19,739		$2.40	$10,668	54	%	$0.86	36	%
Eagle Ford	185		4.51	4,967		3.29	(4,782)	(96	%)	1.22	37	%
Production and ad valorem taxes	$30,592		$3.27	$24,706		$2.54	$5,886	24	%	$0.73	29	%

Percent of total revenues	6.0	%		5.2	%			0.8	%

	Nine Months Ended September 30,
			Per			Per	Total Change			Boe Change
	2023		Boe	2022		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$75,543		$3.03	$96,289		$4.29	($20,746)	(22	%)	($1.26)	(29	%)
Eagle Ford	12,476		3.98	29,552		5.14	(17,076)	(58	%)	(1.16)	(23	%)
Production and ad valorem taxes	$88,019		$3.14	$125,841		$4.45	($37,822)	(30	%)	($1.31)	(29	%)

Percent of total revenues	6.0	%		5.9	%			0.1	%

The increase in production and ad valorem taxes for the three months ended September 30, 2023 compared to the three months ended June 30, 2023 was primarily related to a 7% increase in total revenues which increased production taxes.

The decrease in production and ad valorem taxes for the nine months ended September 30, 2023 compared to the same period of 2022 was primarily related to a 32% decrease in total revenues which decreased production taxes, partially offset by an increase in ad valorem taxes due to higher expected property tax valuations as a result of higher commodity prices during 2022 compared to 2021. The increase in production and ad valorem taxes as a percentage of total revenues for the nine months ended September 30, 2023 compared to the same period of 2022 was primarily due to an increase in ad valorem taxes during the nine months ended September 30, 2023, as discussed above, with a decrease in total revenues during the nine months ended September 30, 2023.

Gathering, Transportation and Processing Expenses


	Three Months Ended
	September 30, 2023	Per	June 30, 2023	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$27,209	$2.92	$24,407	$2.97	$2,802	11	%	($0.05)	(2	%)
Eagle Ford	46	1.12	2,931	1.94	(2,885)	(98	%)	(0.82)	(42	%)
Gathering, transportation and processing	$27,255	$2.91	$27,338	$2.81	($83)	—	%	$0.10	4	%

	Nine Months Ended September 30,
		Per		Per	Total Change			Boe Change
	2023	Boe	2022	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$74,323	$2.98	$60,805	$2.70	$13,518	22	%	$0.28	10	%
Eagle Ford	6,247	1.99	10,812	1.88	(4,565)	(42	%)	0.11	6	%
Gathering, transportation and processing	$80,570	$2.87	$71,617	$2.53	$8,953	13	%	$0.34	13	%

The decrease in gathering, transportation and processing expenses for the three months ended September 30, 2023 compared to the three months ended June 30, 2023 was primarily related to the 5% decrease in production volumes between the two periods. The increase in gathering, transportation and processing expenses per Boe between the third quarter of 2023 and the second quarter of 2023 was immaterial.

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

Exploration Expenses


	Three Months Ended
	September 30, 2023	Per	June 30, 2023	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Exploration	$3,588	$0.38	$1,882	$0.19	$1,706	91	%	$0.19	100	%

	Nine Months Ended September 30,
		Per		Per	Total Change			Boe Change
	2023	Boe	2022	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Exploration	$7,702	$0.27	$7,237	$0.26	$465	6	%	$0.01	4	%

The increase in exploration expense for the three months ended September 30, 2023 compared to the three months ended June 30, 2023 was primarily attributable to the purchase of additional seismic data associated with acreage acquired in the Percussion Acquisition.

For the nine months ended September 30, 2023 compared to the same period in 2022, exploration expense increased by an immaterial amount.

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


	Three Months Ended				Nine Months Ended September 30,
	September 30, 2023		June 30, 2023		2023		2022
	Amount	Per Boe	Amount	Per Boe	Amount	Per Boe	Amount	Per Boe
	(In thousands, except per Boe)
DD&A of proved oil and gas properties	$136,980	$14.64	$125,394	$12.88	$385,863	$13.75	$352,998	$12.48
Depreciation of other property and equipment	338	0.04	352	0.04	1,080	0.03	1,313	0.05
Amortization of other assets	487	0.05	650	0.07	1,927	0.07	2,200	0.08
Accretion of asset retirement obligations	793	0.08	952	0.10	3,041	0.11	2,983	0.10
DD&A	$138,598	$14.81	$127,348	$13.09	$391,911	$13.96	$359,494	$12.71

The increase in DD&A and DD&A per Boe for the three months ended September 30, 2023 compared to the three months ended June 30, 2023 was primarily attributable to the cessation of depletion on the assets disposed of with the Eagle Ford Divestiture as a result of being classified as assets held for sale during the second quarter of 2023 and the inclusion of the assets acquired in the Percussion Acquisition for all of the third quarter of 2023.

The increase in DD&A and DD&A per Boe for the nine months ended September 30, 2023 compared to the same period in 2022 was primarily attributable to higher proved oil and gas property balances as a result of the capital expenditures throughout 2022 and the nine months ended September 30, 2023, partially offset by the cessation of depletion on the assets associated with the Eagle Ford Divestiture as a result of being classified as assets held for sale during the second quarter of 2023.

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

General and Administrative (“G&A”)


	Three Months Ended
	September 30, 2023	Per	June 30, 2023	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
General and administrative	$29,339	$3.13	$29,768	$3.06	($429)	(1	%)	$0.07	2	%

	Nine Months Ended September 30,
		Per		Per	Total Change			Boe Change
	2023	Boe	2022	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
General and administrative	$86,905	$3.10	$71,485	$2.53	$15,420	22	%	$0.57	23	%

For the three months ended September 30, 2023 compared to the three months ended June 30, 2023, G&A decreased by an immaterial amount.

The increase in G&A for the nine months ended September 30, 2023 compared to the same period in 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 Oil and Gas Properties. We recognized an impairment of oil and gas properties in the second quarter of 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 oil and gas properties for the three months ended September 30, 2023 or the nine months ended September 30, 2022.

Other Income and Expenses

Interest Expense. The following table sets forth the components of our interest expense for the periods indicated:


	Three Months Ended			Nine Months Ended September 30,
	September 30, 2023	June 30, 2023	Change	2023	2022	Change
	(In thousands)
Interest expense on Senior Notes	$30,765	$33,224	($2,459)	$97,213	$91,470	$5,743
Interest expense on second lien notes	—	—	—	—	13,825	(13,825)
Interest expense on Credit Facility	9,627	11,397	(1,770)	31,471	25,989	5,482
Amortization of debt issuance costs, premiums and discounts	2,733	2,615	118	7,979	9,680	(1,701)
Other interest expense	24	3	21	31	56	(25)

Interest expense	$43,149	$47,239	($4,090)	$136,694	$141,020	($4,326)

Interest expense for the three months ended September 30, 2023 was $43.1 million, a decrease as compared to the three months ended June 30, 2023 as a result of the redemption of our 8.25% Senior Notes during the third quarter of 2023 as well as decreased borrowings under the Credit Facility.

Interest expense for the nine months ended September 30, 2023 was $136.7 million, a decrease as compared to the nine months ended September 30, 2022 as a result of the redemption of our 9.0% second lien notes in June 2022 and our 8.25% Senior Notes, partially offset by an increase in interest expense due to the issuance of our 7.5% Senior Notes due 2030 in June 2022 as well as increases in interest rates on our outstanding borrowings under the Credit Facility.

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


	Three Months Ended		Nine Months Ended September 30,
	September 30, 2023	June 30, 2023	2023	2022
	(In thousands)
(Gain) loss on oil derivatives	$54,446	($12,937)	$18,165	$243,527
(Gain) loss on natural gas derivatives	(2,315)	6,996	2,380	56,800
Loss on NGL derivatives	2,933	—	2,933	4,771
Gain on contingent consideration arrangements	740	—	740	—

(Gain) loss on derivative contracts	$55,804	($5,941)	$24,218	$305,098

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

Income Tax Expense. We recorded income tax expense of $0.5 million and income tax benefit of $206.4 million for the three and nine months ended September 30, 2023, respectively, compared to income tax expense of $3.4 million and $6.5 million for the three and nine months ended September 30, 2022, respectively. The changes from the statutory income tax rate for the three and nine months ended September 30, 2023 is a result of releasing the valuation allowance that was in place against our net deferred tax assets. See “Note 11 — Income Taxes” for further discussion.

Liquidity and Capital Resources

Pricing Outlook. Oil prices continue to remain volatile as the daily NYMEX benchmark price for oil ranged between approximately $70 and $94 per barrel during the third quarter of 2023. While we saw a wide range during the second quarter of 2023 and the average price for the third quarter of 2023 increased approximately 17% as compared to the second quarter of 2023, the average price for the third quarter of 2023 remained significantly below the average for 2022. Additionally, during the third quarter of 2023, the daily

NYMEX benchmark price for natural gas was $2.66 per mcf, a 15% increase as compared to the second quarter of 2023, but over a 59% decrease from the average for 2022. We expect to continue to see volatility in oil prices, as well as natural gas and NGL prices.

Capital Efficiency Outlook. We recently transitioned to a business unit design in our operations group to improve focus on capital efficiency and capital allocation. We have identified structural drilling efficiency gains from well design changes and expect to continue to identify incremental structural efficiency gains as we move into 2024. The identified improvements are expected to reduce our 2024 average total well costs, including facilities, by over 15%.

2023 Capital Budget and Funding Strategy. Our primary uses of capital are for the exploration and development of our oil and natural gas properties, where our 2023 planned capital expenditures are $960.0 million to $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. We plan our capital expenditure program to achieve disciplined reinvestment rates to drive capital efficiency through an enhanced multi-zone, scaled development program.

We believe that existing cash and cash equivalents, 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, proceeds from the issuance of debt securities and public equity offerings, and 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. Cash and cash equivalents was $3.5 million and $3.4 million as of September 30, 2023 and December 31, 2022, respectively.


	Nine Months Ended September 30,
	2023	2022
	(In thousands)
Net cash provided by operating activities	$794,263	$1,021,686
Net cash used in investing activities	(480,842)	(661,516)
Net cash provided by (used in) financing activities	(313,360)	(365,702)
Net change in cash and cash equivalents	$61	($5,532)

Operating Activities. For the nine months ended September 30, 2023, net cash provided by operating activities was $794.3 million compared to $1,021.7 million for the same period in 2022. The change in net cash provided by operating activities was predominantly attributable to the following:

•A decrease in revenue primarily driven by a 31% decrease in total average realized sales price, and a 1% decrease in production volumes, largely offset by

•A decrease in the cash paid for commodity derivative settlements.

Production, realized prices, and operating expenses are discussed in Results of Operations. See “Note 9 — Derivative Instruments and Hedging Activities” and “Note 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 nine months ended September 30, 2023, net cash used in investing activities was $480.8 million compared to $661.5 million for the same period in 2022. The change in net cash used in investing activities was primarily attributable to cash paid for the Percussion Acquisition and an increase in operational capital expenditures, partially offset by proceeds from the Eagle Ford Divestiture and a decrease in cash paid for the settlement of contingent consideration agreements.

Financing Activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility, term debt and equity offerings. For the nine months ended September 30, 2023, net cash used in financing

activities was $313.4 million compared to net cash used in financing activities of $365.7 million for the same period of 2022. The change was primarily attributable to the redemption of the 8.25% Senior Notes and the initiation of our Share Repurchase Program during the nine months ended September 30, 2023 compared to the redemptions of the 6.125% Senior Notes and Second Lien Notes, partially offset by the issuance of the 7.50% Senior Notes during the nine months ended September 30, 2022.

Credit Facility. As of September 30, 2023, our Credit Facility had a maximum credit amount of $5.0 billion, a borrowing base of $2.0 billion and an elected commitment amount of $1.5 billion, with borrowings outstanding of $396.0 million at a weighted average interest rate of 7.50%, and $21.4 million in letters of credit outstanding. See “Note 8 — Borrowings” for additional information related to the Credit Facility.

Redemption of 8.25% Senior Notes. On August 2, 2023, we redeemed all $187.2 million of our outstanding 8.25% Senior Notes using borrowings under our Credit Facility. See “Note 8 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information on our long-term debt.

Material Cash Requirements. As of September 30, 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 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 2022 Annual Report for additional details.

On July 3, 2023, we completed the Percussion Acquisition and acquired Percussion’s oil and gas properties in the Delaware Basin for a purchase price of approximately $248.5 million in cash (inclusive of the repayment of Percussion Operating’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 where we received approximately $549.3 million in cash upon consummation on July 3, 2023. As part of the Percussion Acquisition, we also assumed Percussion Operating’s existing hedges and transportation contract liabilities and potential earn-out obligations. Pursuant to such assumed earn-out obligations, if the average daily settlement price of WTI crude oil exceeds $60.00 per barrel for 2023, 2024 and 2025 calendar years, we would be required to remit payments of $12.5 million, $25.0 million and $25.0 million, respectively, in January of 2024, 2025 and 2026, respectively. We expect to fund such earn-out obligations with cash provided by operating activities, potential cash received from the Contingent Eagle Ford Consideration, or borrowings under our Credit Facility.

Since December 31, 2022, except as disclosed above, there have been no material changes from what was disclosed in our 2022 Annual Report other than changes to the borrowings under our Credit Facility. See “Note 8 — Borrowings” for 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 2022 Annual Report. Except as 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, 2022, which are disclosed in “Part II, Item 7A. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2022 Annual 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

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 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. 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. There were no impairments of proved oil and gas properties during 2022.

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 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 our historical experience or other information, including current drilling plans and existing geological data.

Income Taxes

Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the 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 more 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 deferred income tax benefit of $0.7 million and $206.1 million for the three and nine months ended September 30, 2023, respectively. As a result of the release of the valuation allowance, we will have no federal deferred income tax expense for fiscal year 2023.

Recently Adopted and Recently Issued Accounting Standards

See “Note 2 — Summary of Significant Accounting Policies” of 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, 2022, which are disclosed in “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of our 2022 Annual 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 September 30, 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 September 30, 2023:


	Three Months Ended September 30, 2023
	Oil	Natural Gas	NGLs	Total
	(In thousands)
Fair value asset (liability) as of September 30, 2023 (1)	($45,172)	($7,711)	($1,036)	($53,919)

Impact of a 10% increase in forward commodity prices	($85,631)	($9,015)	($1,984)	($96,630)
Impact of a 10% decrease in forward commodity prices	($10,678)	($6,319)	($88)	($17,085)

(1)Spot prices for oil and natural gas were $90.16 and $2.93, respectively, as of September 30, 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 September 30, 2023, we had $396.0 million outstanding under the Credit Facility with a weighted average interest rate of 7.50%. 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 $4.0 million, based on the balance outstanding as of September 30, 2023. See “Note 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 our principal executive and 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 September 30, 2023.

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

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 2022 Annual 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, Use of Proceeds and Issuer Purchases of Equity Securities

Unregistered Sales of Equity Securities

On July 3, 2023, the Company completed the Percussion Acquisition pursuant to which it acquired Percussion’s oil and gas properties in the Delaware Basin (through the acquisition of all of Percussion Operating’s equity interests) and issued 6,267,385 shares of the Company’s common stock as partial consideration, 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.

Issuer Repurchases of Equity Securities

Our common stock repurchase activity for the three months ended September 30, 2023 was as follows:


Period	Total Number of Shares Purchased	Average Price Paid Per Share(1)	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(2)
July 1 - July 31, 2023	—	$—	—	$300,000,000
August 1 - August 31, 2023	81,574	$36.22	81,574	$297,045,600
September 1 - September 30, 2023	305,145	$39.38	305,145	$285,027,986
Total	386,719	$38.72	386,719

(1) The average price paid per share excludes any fees, commissions and expenses paid to repurchase stock.

(2) On May 2, 2023, the Board approved the Share Repurchase Program pursuant to which we are authorized to repurchase up to $300.0 million of our outstanding common stock through the second quarter of 2025. Repurchases under the Share Repurchase Program may be made, from time to time, in amounts and at prices we deem appropriate and will be subject to a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. The Share Repurchase Program will expire on June 30, 2025 but may be suspended, modified or discontinued by the Board at any time without prior notice.

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

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

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

10-Q

4.2

8/2/2023

4.3

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

10-Q

4.3

8/2/2023

4.4

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-Q

4.4

8/2/2023

10.1

(a)

Separation Agreement, dated July 5, 2023, by and between Jeffrey S. Balmer and Callon Petroleum Company

10.2

(a)

Consulting Agreement, dated July 5, 2023, by and between Jeffrey S. Balmer and Callon Petroleum Company

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	November 1, 2023
Joseph C. Gatto, Jr.	Chief Executive Officer


/s/ Kevin Haggard	Senior Vice President and	November 1, 2023
Kevin Haggard	Chief Financial Officer