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, 2022~~March 31, 2023

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

For the transition period from ____________ to ____________

Commission File Number 001-14039

Callon Petroleum Company


			(Exact Name of Registrant as Specified in Its Charter)


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

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


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

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

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

Title of Each Class

Trading Symbol(s)

Name of Each Exchange on Which Registered

Common Stock, $0.01 par value

CPE

New York Stock Exchange

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

The Registrant had ~~61,608,521~~61,869,812 shares of common stock outstanding as of ~~October~~April 28, ~~2022.~~2023.

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

Table of Contents

Part I. Financial Information

Item 1. Financial Statements

Callon Petroleum Company

Consolidated Balance Sheets

(In thousands, except par and share amounts)

(Unaudited)


		September 30, 2022	December 31, 2021		March 31, 2023	December 31, 2022*
ASSETS	ASSETS			ASSETS
Current assets:	Current assets:			Current assets:
Cash and cash equivalents	Cash and cash equivalents	$4,350	$9,882	Cash and cash equivalents	$3,370	$3,395
Accounts receivable, net	Accounts receivable, net	285,591	232,436	Accounts receivable, net	210,107	237,128
Fair value of derivatives	Fair value of derivatives	14,744	22,381	Fair value of derivatives	25,761	21,332
Other current assets	Other current assets	46,243	30,745	Other current assets	35,406	35,783
Total current assets	Total current assets	350,928	295,444	Total current assets	274,644	297,638
Oil and natural gas properties, full cost accounting method:
Oil and natural gas properties, successful efforts accounting method:				Oil and natural gas properties, successful efforts accounting method:

Evaluated properties, net		3,789,530	3,352,821
Unevaluated properties		1,847,912	1,812,827
Proved properties, net				Proved properties, net	4,999,527	4,851,529
Unproved properties				Unproved properties	1,227,575	1,225,768
Total oil and natural gas properties, net	Total oil and natural gas properties, net	5,637,442	5,165,648	Total oil and natural gas properties, net	6,227,102	6,077,297

Other property and equipment, net	Other property and equipment, net	26,071	28,128	Other property and equipment, net	28,719	26,152

Deferred income taxes				Deferred income taxes	45,669	—
Deferred financing costs	Deferred financing costs	13,504	18,125	Deferred financing costs	17,152	18,822

Other assets, net	Other assets, net	71,994	40,158	Other assets, net	58,379	68,560
Total assets	Total assets	$6,099,939	$5,547,503	Total assets	$6,651,665	$6,488,469
LIABILITIES AND STOCKHOLDERS’ EQUITY	LIABILITIES AND STOCKHOLDERS’ EQUITY			LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:	Current liabilities:			Current liabilities:
Accounts payable and accrued liabilities	Accounts payable and accrued liabilities	$594,279	$569,991	Accounts payable and accrued liabilities	$550,923	$536,233

Fair value of derivatives	Fair value of derivatives	48,697	185,977	Fair value of derivatives	570	16,197
Other current liabilities	Other current liabilities	151,021	116,523	Other current liabilities	146,195	150,384
Total current liabilities	Total current liabilities	793,997	872,491	Total current liabilities	697,688	702,814
Long-term debt	Long-term debt	2,373,358	2,694,115	Long-term debt	2,204,514	2,241,295

Asset retirement obligations	Asset retirement obligations	59,583	54,458	Asset retirement obligations	55,023	53,892

Fair value of derivatives	Fair value of derivatives	9,604	11,409	Fair value of derivatives	6,594	13,415
Other long-term liabilities	Other long-term liabilities	54,395	49,262	Other long-term liabilities	38,088	51,272
Total liabilities	Total liabilities	3,290,937	3,681,735	Total liabilities	3,001,907	3,062,688
Commitments and contingencies	Commitments and contingencies			Commitments and contingencies
Stockholders’ equity:	Stockholders’ equity:			Stockholders’ equity:
Common stock, $0.01 par value, 130,000,000 and 78,750,000 shares authorized; 61,607,450 and 61,370,684 shares outstanding, respectively		616	614
Common stock, $0.01 par value, 130,000,000 shares authorized; 61,625,170 and 61,621,518 shares outstanding, respectively				Common stock, $0.01 par value, 130,000,000 shares authorized; 61,625,170 and 61,621,518 shares outstanding, respectively	616	616
Capital in excess of par value	Capital in excess of par value	4,018,241	4,012,358	Capital in excess of par value	4,025,533	4,022,194
Accumulated deficit	Accumulated deficit	(1,209,855)	(2,147,204)	Accumulated deficit	(376,391)	(597,029)
Total stockholders’ equity	Total stockholders’ equity	2,809,002	1,865,768	Total stockholders’ equity	3,649,758	3,425,781
Total liabilities and stockholders’ equity	Total liabilities and stockholders’ equity	$6,099,939	$5,547,503	Total liabilities and stockholders’ equity	$6,651,665	$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,			Three Months Ended March 31,
		2022	2021	2022	2021		2023	2022*
Operating Revenues:	Operating Revenues:					Operating Revenues:
Oil	Oil	$575,852	$409,293	$1,748,913	$1,009,780	Oil	$409,556	$553,249
Natural gas	Natural gas	81,018	36,519	189,907	84,819	Natural gas	23,586	43,976
Natural gas liquids	Natural gas liquids	67,548	58,097	210,696	124,079	Natural gas liquids	43,370	67,618
Sales of purchased oil and gas	Sales of purchased oil and gas	111,459	48,653	377,199	134,164	Sales of purchased oil and gas	83,534	112,375
Total operating revenues	Total operating revenues	835,877	552,562	2,526,715	1,352,842	Total operating revenues	560,046	777,218

Operating Expenses:	Operating Expenses:					Operating Expenses:
Lease operating	Lease operating	76,121	42,706	216,389	129,619	Lease operating	75,102	67,328
Production and ad valorem taxes	Production and ad valorem taxes	43,290	26,070	125,841	66,467	Production and ad valorem taxes	32,721	37,678
Gathering, transportation and processing	Gathering, transportation and processing	27,575	20,875	71,617	58,887	Gathering, transportation and processing	25,977	20,775
Exploration						Exploration	2,232	1,885
Cost of purchased oil and gas	Cost of purchased oil and gas	111,439	49,392	378,107	139,558	Cost of purchased oil and gas	86,061	111,271
Depreciation, depletion and amortization	Depreciation, depletion and amortization	122,833	89,890	335,221	244,005	Depreciation, depletion and amortization	125,965	113,643
General and administrative	General and administrative	14,022	9,503	42,052	37,367	General and administrative	27,798	27,057

Merger, integration and transaction	Merger, integration and transaction	—	3,018	769	3,018	Merger, integration and transaction	—	769

Total operating expenses	Total operating expenses	395,280	241,454	1,169,996	678,921	Total operating expenses	375,856	380,406
Income From Operations	Income From Operations	440,597	311,108	1,356,719	673,921	Income From Operations	184,190	396,812

Other (Income) Expenses:	Other (Income) Expenses:					Other (Income) Expenses:
Interest expense, net of capitalized amounts		19,468	27,736	61,717	76,786
Interest expense						Interest expense	46,306	47,096
(Gain) loss on derivative contracts	(Gain) loss on derivative contracts	(134,850)	107,169	305,098	512,155	(Gain) loss on derivative contracts	(25,645)	358,300
(Gain) loss on extinguishment of debt		—	(2,420)	42,417	(2,420)

Other (income) expense	Other (income) expense	2,861	4,305	3,130	6,583	Other (income) expense	(6,414)	(782)
Total other (income) expense	Total other (income) expense	(112,521)	136,790	412,362	593,104	Total other (income) expense	14,247	404,614

Income Before Income Taxes		553,118	174,318	944,357	80,817
Income tax expense		(3,515)	(2,416)	(7,008)	(1,017)
Net Income		$549,603	$171,902	$937,349	$79,800
Income (Loss) Before Income Taxes						Income (Loss) Before Income Taxes	169,943	(7,802)
Income tax benefit						Income tax benefit	50,695	87
Net Income (Loss)						Net Income (Loss)	$220,638	($7,715)

Net Income Per Common Share:
Net Income (Loss) Per Common Share:						Net Income (Loss) Per Common Share:
Basic	Basic	$8.91	$3.71	$15.21	$1.77	Basic	$3.58	($0.13)
Diluted	Diluted	$8.88	$3.65	$15.14	$1.69	Diluted	$3.57	($0.13)

Weighted Average Common Shares Outstanding:	Weighted Average Common Shares Outstanding:					Weighted Average Common Shares Outstanding:
Basic	Basic	61,703	46,290	61,624	45,063	Basic	61,625	61,487
Diluted	Diluted	61,870	47,096	61,927	47,119	Diluted	61,874	61,487

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

Callon Petroleum Company

Consolidated Statements of Stockholders’ Equity

(In thousands)

(Unaudited)

Common Capital in Total
Stock Excess Accumulated Stockholders’
Shares $ of Par Deficit Equity
Balance at December 31, 2021 61,371 $614 $4,012,358 ($2,147,204) $1,865,768
Net income — — — 39,737 39,737
Restricted stock units 6 — 2,790 — 2,790
Common stock issued for Primexx Acquisition 117 1 6,294 — 6,295
Balance at March 31, 2022 61,494 $615 $4,021,442 ($2,107,467) $1,914,590
Net income — — — 348,009 348,009
Restricted stock units 244 2 (1,901) — (1,899)
Common stock issued for Primexx Acquisition (22) — (1,363) — (1,363)
Balance at June 30, 2022 61,716 $617 $4,018,178 ($1,759,458) $2,259,337
Net income — — — 549,603 549,603
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 ($1,209,855) $2,809,002


	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

Common Capital in Total
Stock Excess Accumulated Stockholders’
Shares $ of Par Deficit Equity
Balance at December 31, 2020 39,759 $398 $3,222,959 ($2,512,355) $711,002
Net loss — — — (80,407) (80,407)
Restricted stock units 13 — 2,609 — 2,609
Warrant exercises 6,385 64 134,754 — 134,818
Balance at March 31, 2021 46,157 $462 $3,360,322 ($2,592,762) $768,022
Net loss — — — (11,695) (11,695)
Restricted stock units 132 1 960 — 961
Balance at June 30, 2021 46,289 $463 $3,361,282 ($2,604,457) $757,288
Net income — — — 171,902 171,902
Restricted stock units 2 — 3,839 — 3,839
Balance at September 30, 2021 46,291 $463 $3,365,121 ($2,432,555) $933,029


	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

*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,			Three Months Ended March 31,
Cash flows from operating activities:	Cash flows from operating activities:	2022	2021	Cash flows from operating activities:	2023	2022*
Net income		$937,349	$79,800
Adjustments to reconcile net income to net cash provided by operating activities:
Net income (loss)				Net income (loss)	$220,638	($7,715)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:				Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	Depreciation, depletion and amortization	335,221	244,005	Depreciation, depletion and amortization	125,965	113,643

Amortization of non-cash debt related items, net	Amortization of non-cash debt related items, net	4,263	7,166	Amortization of non-cash debt related items, net	2,631	3,749
Deferred income tax expense		1,626	—
Deferred income tax benefit				Deferred income tax benefit	(51,977)	—
(Gain) loss on derivative contracts	(Gain) loss on derivative contracts	305,098	512,155	(Gain) loss on derivative contracts	(25,645)	358,300
Cash paid for commodity derivative settlements, net	Cash paid for commodity derivative settlements, net	(433,518)	(238,378)	Cash paid for commodity derivative settlements, net	(779)	(101,525)
(Gain) loss on extinguishment of debt		42,417	(2,420)

Non-cash expense related to share-based awards	Non-cash expense related to share-based awards	1,055	11,984	Non-cash expense related to share-based awards	1,881	6,043

Other, net	Other, net	8,704	11,006	Other, net	(1,184)	2,894
Changes in current assets and liabilities:	Changes in current assets and liabilities:			Changes in current assets and liabilities:
Accounts receivable	Accounts receivable	(58,915)	(83,227)	Accounts receivable	24,019	(109,830)
Other current assets	Other current assets	(12,229)	(8,701)	Other current assets	(1,618)	(4,180)
Accounts payable and accrued liabilities	Accounts payable and accrued liabilities	(8,693)	74,443	Accounts payable and accrued liabilities	(46,018)	(13,558)
Cash received for settlements of contingent consideration arrangements, net		6,492	—

Net cash provided by operating activities	Net cash provided by operating activities	1,128,870	607,833	Net cash provided by operating activities	247,913	247,821
Cash flows from investing activities:	Cash flows from investing activities:			Cash flows from investing activities:
Capital expenditures	Capital expenditures	(754,225)	(427,552)	Capital expenditures	(204,900)	(168,270)
Acquisition of oil and gas properties	Acquisition of oil and gas properties	(18,114)	(67,236)	Acquisition of oil and gas properties	(5,991)	(9,168)

Proceeds from sales of assets	Proceeds from sales of assets	9,313	35,415	Proceeds from sales of assets	2,054	4,484
Cash paid for settlement of contingent consideration arrangement	Cash paid for settlement of contingent consideration arrangement	(19,171)	—	Cash paid for settlement of contingent consideration arrangement	—	(19,171)
Other, net	Other, net	13,497	4,206	Other, net	(1,072)	3,635
Net cash used in investing activities	Net cash used in investing activities	(768,700)	(455,167)	Net cash used in investing activities	(209,909)	(188,490)
Cash flows from financing activities:	Cash flows from financing activities:			Cash flows from financing activities:
Borrowings on Prior Credit Facility		2,535,000	1,236,500
Payments on Prior Credit Facility		(2,684,000)	(1,498,500)
Issuance of 7.50% Senior Notes due 2030		600,000	—
Redemption of 6.125% Senior Notes due 2024		(467,287)	—
Redemption of 9.00% Second Lien Senior Secured Notes due 2025		(339,507)	—
Redemption of 6.25% Senior Notes		—	(542,755)
Issuance of 8.00% Senior Notes due 2028		—	650,000
Borrowings on credit facility				Borrowings on credit facility	669,500	673,000
Payments on credit facility				Payments on credit facility	(707,200)	(746,000)

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

Payment of deferred financing costs	Payment of deferred financing costs	(11,623)	(12,168)	Payment of deferred financing costs	(42)	—

Other, net	Other, net	(6,797)	(2,280)	Other, net	(287)	7,937
Net cash used in financing activities	Net cash used in financing activities	(365,702)	(169,203)	Net cash used in financing activities	(38,029)	(65,063)
Net change in cash and cash equivalents	Net change in cash and cash equivalents	(5,532)	(16,537)	Net change in cash and cash equivalents	(25)	(5,732)
Balance, beginning of period	Balance, beginning of period	9,882	20,236	Balance, beginning of period	3,395	9,882
Balance, end of period	Balance, end of period	$4,350	$3,699	Balance, end of period	$3,370	$4,150

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

Index to the Notes to the Consolidated Financial Statements


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

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

— Description of Business

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

The Company’s activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford in South Texas. The Company’s primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established, ~~and repeatable~~ cash flow-generating business in the Eagle Ford.

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 ~~2021~~2022 Annual Report and are supplemented by the notes included in this ~~Quarterly Report on~~ Form 10-Q. The financial statements and related notes included in this ~~report~~Form 10-Q should be read in conjunction with the Company’s ~~2021~~2022 Annual Report.

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

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

~~Recently Issued Accounting Standards~~

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

Oil and ~~restatement thereof~~Gas Property

Proved oil and 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 ~~October 2022.~~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. There were no impairments of proved oil and gas properties for the three months ended March 31, 2023 or 2022.

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 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 the three months ended March 31, 2023 and 2022, the Company did not have any projects that met the thresholds, therefore, had no capitalized interest.

Subsequent Events

The Company evaluates subsequent events through the date the financial statements are issued. See “Note ~~14 -~~16 — Subsequent Events” for further discussion.

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

In the first quarter of 2023, the Company voluntarily changed its method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. In general, under successful efforts, exploration costs such as exploratory dry holes, exploratory geophysical and geological costs, delay rentals, unproved leasehold impairments and exploration overhead are expensed as incurred as opposed to being capitalized under the full cost method of accounting. The successful efforts method also provides for the assessment of potential proved oil and gas property impairments by comparing the net book value of proved oil and gas properties to associated estimated undiscounted future net cash flows. If the net book value exceeds the estimated undiscounted future net cash flows, an impairment is recorded to reduce the net book value to fair value. Under the full cost method of accounting, an impairment would be required if the net book value of oil and natural gas properties exceeds a full cost ceiling using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are recognized more frequently on the divestitures of oil and gas properties under the successful efforts method, as opposed to an adjustment to the net book value of the oil and gas properties under the full cost method.

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


	As of March 31, 2023
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands)
Oil and natural gas properties:
Proved properties	$10,647,471	($1,107,849)	$9,539,622
Accumulated depreciation, depletion, amortization and impairments	(6,464,299)	1,924,204	(4,540,095)
Unproved properties	1,744,649	(517,074)	1,227,575
Total oil and gas properties, net	5,927,821	299,281	6,227,102
Deferred income taxes	72,323	(26,654)	45,669
Total assets	$6,379,038	$272,627	$6,651,665
Stockholders’ equity:
Accumulated deficit	(649,018)	272,627	(376,391)
Total stockholders' equity	3,377,131	272,627	3,649,758
Total liabilities and stockholders' equity	$6,379,038	$272,627	$6,651,665


	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 March 31, 2023
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands, except per share data)
Operating Expenses:
Exploration	$—	$2,232	$2,232
Depreciation, depletion and amortization	122,900	3,065	125,965
General and administrative	17,140	10,658	27,798
Income From Operations	200,145	(15,955)	184,190

Other Expenses:
Interest expense	19,153	27,153	46,306

Income Before Income Taxes	213,050	(43,107)	169,943
Income tax benefit (expense)	75,320	(24,625)	50,695
Net Income	$288,370	($67,732)	$220,638
Net Income Per Common Share:
Basic	$4.68		$3.58
Diluted	$4.66		$3.57


	Three Months Ended March 31, 2022
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands, except per share data)
Operating Expenses:
Exploration	$—	$1,885	$1,885
Depreciation, depletion and amortization	102,979	10,664	113,643
General and administrative	17,121	9,936	27,057
Income From Operations	419,297	(22,485)	396,812

Other Expenses:
Interest expense	21,558	25,538	47,096

Income (Loss) Before Income Taxes	40,221	(48,023)	(7,802)
Income tax benefit (expense)	(484)	571	87
Net Income (Loss)	$39,737	($47,452)	($7,715)
Net Income (Loss) Per Common Share:
Basic	$0.65		($0.13)
Diluted	$0.64		($0.13)

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


	Three Months Ended March 31, 2023
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands)
Cash flows from operating activities:
Net income	$288,370	($67,732)	$220,638
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	122,900	3,065	125,965
Amortization of non-cash debt related items, net	1,088	1,543	2,631
Deferred income tax benefit	(76,602)	24,625	(51,977)
Non-cash expense related to share-based awards	757	1,124	1,881




Net cash provided by operating activities	285,288	(37,375)	247,913
Cash flows from investing activities:
Capital expenditures	(240,043)	35,143	(204,900)
Acquisition of oil and gas properties	(8,223)	2,232	(5,991)
Net cash used in investing activities	(247,284)	37,375	(209,909)
Net change in cash and cash equivalents	(25)	—	(25)
Balance, beginning of period	3,395	—	3,395
Balance, end of period	$3,370	$—	$3,370


	Three Months Ended March 31, 2022
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$39,737	($47,452)	($7,715)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	102,979	10,664	113,643
Amortization of non-cash debt related items, net	1,716	2,033	3,749

Non-cash expense related to share-based awards	4,166	1,877	6,043
Changes in current assets and liabilities:


Accounts payable and accrued liabilities	(12,987)	(571)	(13,558)
Net cash provided by operating activities	281,270	(33,449)	247,821
Cash flows from investing activities:
Capital expenditures	(201,478)	33,208	(168,270)
Acquisition of oil and gas properties	(9,409)	241	(9,168)
Net cash used in investing activities	(221,939)	33,449	(188,490)
Net change in cash and cash equivalents	(5,732)	—	(5,732)
Balance, beginning of period	9,882	—	9,882
Balance, end of period	$4,150	$—	$4,150

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


	As of March 31, 2023
	Under Full Cost	Changes	Under Successful Efforts
	(In thousands)
Accumulated deficit	($649,018)	$272,627	($376,391)
Total stockholders’ equity	$3,377,131	$272,627	$3,649,758


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

Note 4 — Revenue Recognition

Revenue from Contracts with Customers

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

Oil and Gas Purchase and Sale Arrangements

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

Accounts Receivable from Revenues from Contracts with Customers

Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 of ~~$219.7~~$153.4 million and ~~$171.8~~$174.1 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets.

Prior Period Performance Obligations

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

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

~~2021 Acquisitions and Divestitures~~

~~Primexx Acquisition~~

~~On October 1, 2021, the Company closed~~ on the acquisition of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin from Primexx Resource Development, LLC (“Primexx”) and BPP Acquisition, LLC (“BPP”) ~~for an adjusted purchase price of approximately $444.8 million in cash, inclusive of the deposit paid at signing, 8.84 million shares of the Company’s common stock~~ ~~and approximately $25.2 million paid upon final closing~~ ~~for total consideration of $880.8 million (the “Primexx Acquisition”), subject to potential adjustments for applicable indemnification claims as discussed below.~~ The Company funded the cash portion of the total consideration with borrowings under its credit facility. Of the 8.84 million shares of the Company’s common stock issued upon closing, 2.6 million shares were held in escrow pursuant to the purchase and sale agreements with Primexx and BPP (collectively, the “Primexx PSAs”)~~. Pursuant to the Primexx PSAs, 1.3 million of the shares held in escrow were released to the sellers six months after the closing date,~~ which was on April 1, 2022. In early October 2022, the remaining 1.2 million shares were released to the sellers, net of shares that were released to the Company for the satisfaction of indemnification claims made under the Primexx PSAs and subsequently retired.

Also, pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration structured similarly to the Primexx Acquisition, for an incremental purchase price totaling approximately $31.8 million, net of customary purchase price adjustments, of which $10.7 million closeddid not have any material acquisitions or divestitures during the ~~first quarter of 2022.~~

~~The Primexx Acquisition was accounted for as a business combination;~~three months ended 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. The Company does not anticipate any further changes to the purchase price allocation and expects to complete in the fourth quarter ofMarch 31, 2023 or 2022.

~~The following table sets forth the Company’s preliminary allocation of the total estimated consideration of $908.9 million to the assets acquired and liabilities assumed as of the acquisition date.~~


						Preliminary Purchase Price Allocation
						~~(In thousands)~~
~~Assets:~~
~~Other current assets~~						~~$8,174~~
~~Evaluated oil and natural gas properties~~						~~695,838~~
~~Unevaluated properties~~						~~278,370~~
~~Total assets acquired~~						~~$982,382~~

~~Liabilities:~~
~~Suspense payable~~						~~$16,447~~
~~Other current liabilities~~						~~45,745~~
~~Asset retirement obligation~~						~~1,898~~
~~Other long-term liabilities~~						~~9,425~~
~~Total liabilities assumed~~						~~$73,515~~

~~Total consideration~~						~~$908,867~~

Approximately $137.6 million and $446.1 million of revenues and $39.2 million and $104.9 million of direct operating expenses attributed to the Primexx Acquisition are included in the Company’s consolidated statements of operations for the three and nine months ended September 30, 2022, respectively.

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

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

~~For the Year Ended~~

~~December 31, 2021~~

~~(In thousands)~~

~~Revenues~~

~~$2,294,893~~

~~Income from operations~~

~~1,151,493~~

~~Net income~~

~~482,690~~

~~Basic earnings per common share~~

~~$8.37~~

~~Diluted earnings per common share~~

~~$8.13~~

~~Non-Core Asset Divestitures~~

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

912

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

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

September 30, 2022 December 31, 2021
Oil and natural gas properties, full cost accounting method (In thousands)
Evaluated properties $10,004,257 $9,238,823
Accumulated depreciation, depletion, amortization and impairments (6,214,727) (5,886,002)
Evaluated properties, net 3,789,530 3,352,821
Unevaluated properties
Unevaluated leasehold and seismic costs 1,525,085 1,557,453
Capitalized interest 322,827 255,374
Total unevaluated properties 1,847,912 1,812,827
Total oil and natural gas properties, net $5,637,442 $5,165,648
Other property and equipment $40,094 $58,367
Accumulated depreciation (14,023) (30,239)
Other property and equipment, net $26,071 $28,128


	March 31, 2023	December 31, 2022*
Oil and natural gas properties, successful efforts accounting method	(In thousands)
Proved properties	$9,539,622	$9,268,135
Accumulated depreciation, depletion, amortization and impairments	(4,540,095)	(4,416,606)
Proved properties, net	4,999,527	4,851,529
Unproved properties	1,227,575	1,225,768
Total oil and natural gas properties, net	$6,227,102	$6,077,297

Other property and equipment	$43,486	$40,530
Accumulated depreciation	(14,767)	(14,378)
Other property and equipment, net	$28,719	$26,152

The Company capitalized internal costs of employee compensation and benefits, including share-based compensation, directly associated with acquisition, exploration and development activities totaling $12.7 million and $10.4 million

*Financial information for the ~~three months ended September 30, 2022 and 2021, respectively, and $35.6 million and $33.7 million~~prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for ~~the nine months ended September 30, 2022 and 2021, respectively.~~

The Company capitalized interest costs to unproved properties totaling $27.5 million and $26.1 million for the three months ended September 30, 2022 and 2021, respectively, and $79.3 million and $74.0 million for the nine months ended September 30, 2022 and 2021, respectively.additional information.

Note ~~5 -~~7 — Earnings Per Share

Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted stock units ~~and unexercised warrants~~ outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. For the three months ended March 31, 2022, the Company reported a net loss. As a result, the calculation of diluted weighted average common shares outstanding excluded all potentially dilutive common shares outstanding.

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


		Three Months Ended September 30,		Nine Months Ended September 30,			Three Months Ended March 31,
		2022	2021	2022	2021		2023	2022*
		(In thousands, except per share amounts)					(In thousands, except per share amounts)

Net Income		$549,603	$171,902	$937,349	$79,800
Net Income (Loss)						Net Income (Loss)	$220,638	($7,715)
Basic weighted average common shares outstanding	Basic weighted average common shares outstanding	61,703	46,290	61,624	45,063	Basic weighted average common shares outstanding	61,625	61,487
Dilutive impact of restricted stock units	Dilutive impact of restricted stock units	167	305	303	244	Dilutive impact of restricted stock units	249	—
Dilutive impact of warrants		—	501	—	1,812

Diluted weighted average common shares outstanding	Diluted weighted average common shares outstanding	61,870	47,096	61,927	47,119	Diluted weighted average common shares outstanding	61,874	61,487

Net Income Per Common Share
Net Income (Loss) Per Common Share						Net Income (Loss) Per Common Share
Basic	Basic	$8.91	$3.71	$15.21	$1.77	Basic	$3.58	($0.13)
Diluted	Diluted	$8.88	$3.65	$15.14	$1.69	Diluted	$3.57	($0.13)

Restricted stock units (1)	Restricted stock units (1)	100	8	28	28	Restricted stock units (1)	42	980
Warrants (1)	Warrants (1)	481	481	416	481	Warrants (1)	481	481

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

1013

Note ~~6 -~~8 — Borrowings

The Company’s borrowings consisted of the following:

September 30, 2022 December 31, 2021
(In thousands)
6.125% Senior Notes due 2024 $— $460,241
Senior Secured Revolving Credit Facility due 2024 (1)
636,000 785,000
9.00% Second Lien Senior Secured Notes due 2025 — 319,659
8.25% Senior Notes due 2025 187,238 187,238
6.375% Senior Notes due 2026 320,783 320,783
8.00% Senior Notes due 2028 650,000 650,000
7.50% Senior Notes due 2030 600,000 —
Total principal outstanding 2,394,021 2,722,921
Unamortized premium on 6.125% Senior Notes — 2,373
Unamortized discount on 9.00% Second Lien Notes — (14,852)
Unamortized premium on 8.25% Senior Notes 1,905 2,477
Unamortized deferred financing costs for 9.00% Second Lien Notes — (2,910)
Unamortized deferred financing costs for Senior Unsecured Notes (22,568) (15,894)
Total carrying value of borrowings (2)
$2,373,358 $2,694,115


	March 31, 2023	December 31, 2022
	(In thousands)
8.25% Senior Notes due 2025	$187,238	$187,238
6.375% Senior Notes due 2026	320,783	320,783
Senior Secured Revolving Credit Facility due 2027	465,300	503,000
8.0% Senior Notes due 2028	650,000	650,000
7.5% Senior Notes due 2030	600,000	600,000
Total principal outstanding	2,223,321	2,261,021
Unamortized premium on 8.25% Senior Notes	1,524	1,715
Unamortized deferred financing costs for Senior Notes	(20,331)	(21,441)
Total carrying value of borrowings (1)	$2,204,514	$2,241,295

(1) ~~On October 19, 2022, the Company entered into the Credit Agreement, as defined below, which extended the maturity date from 2024 to 2027. See below for additional details.~~

~~(2)~~ Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of ~~$13.5~~$17.2 million and ~~$18.1~~$18.8 million as of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets.

Senior Secured Revolving Credit Facility

~~As of September 30, 2022, the~~The Company ~~had~~has a senior secured revolving credit facility with a syndicate of lenders (the ~~“Prior Credit~~“Credit Facility”) that, as of March 31, 2023, had a maximum credit amount of $5.0 billion, a borrowing base of $2.0 billion and an elected commitment amount of ~~$1.6~~$1.5 billion, with borrowings outstanding of ~~$636.0~~$465.3 million at a weighted-average interest rate of ~~5.30%~~6.87%, and letters of credit outstanding of $16.4 million. The credit agreement governing the ~~Prior~~ Credit Facility ~~provided~~(the “Credit Agreement”) provides for interest-only payments until ~~December 20, 2024 when the credit agreement was to mature and any outstanding borrowings would have been due.~~

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

On ~~October 19, 2022~~, the Company entered into the Amended & Restated Credit Agreement (the “Credit Agreement” and the senior secured revolving credit facility thereunder, the “Credit Facility”) on substantially similar terms as those in the credit agreement governing the Prior Credit Facility. The Credit Agreement, among other things, extended the term to provide for interest-only payments untilOctober 19, 2027 w~~hen~~when the Credit Agreement matures and any outstanding borrowings are due, established a borrowing base of $2.0 billion, with an elected commitment amount of $1.5 billion, replaced all provisions and related definitions regarding LIBOR with a Secured Overnight Financing Rate based benchmark rate (“SOFR”), and decreased the maximum leverage ratio from 4.00 to 1.00 to 3.50 to 1.00.due.

Borrowings outstanding under the ~~credit agreement governing the~~ Credit ~~Facility~~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%. ~~There were no changes~~The Company also incurs commitment fees at rates ranging between 0.375% to ~~the commitment fee rates~~0.500% on the unused portion of lender commitments, which are included in “Interest expense” in the ~~Credit Agreement.~~consolidated statements of operations.

The borrowing base under the ~~credit agreement~~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,~~Credit Agreement, which in each case may reduce the amount of the borrowing base. ~~The Credit Facility is, and the Prior Credit Facility was, secured by first preferred mortgages covering~~On May 1, 2023, as part of the Company’s ~~major producing properties.~~

~~Issuance~~spring 2023 redetermination, the borrowing base of ~~7.50%~~$2.0 billion ~~Senior Notes~~ and ~~Redemption~~elected commitment amount of ~~6.125%~~$1.5 billion were reaffirmed. ~~Senior Notes and~~ ~~9.00%Second Lien Notes~~

On June 24, 2022, the Company issued and sold $600.0 million in aggregate principal amount of 7.50% senior unsecured notes due 2030 (the “7.50% Senior Notes”) in a private placement for proceeds of approximately $588.0 million, net of initial purchasers’ discounts and commissions. Also on June 24, 2022, the Company used the proceeds from the offering of the 7.50% Senior Notes, along with borrowings under its credit facility, to redeem all of its outstanding 6.125% Senior Notes and 9.00% Second Lien Notes (the “Second Lien Notes”). The Company recognized a loss on extinguishment of debt of approximately $42.4 million in its consolidated statements of operations as a result of the redemptions.

Covenants

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

Under the ~~credit agreement governing the~~ Credit ~~Facility,~~Agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter: (1) a Leverage Ratio (as defined in the ~~credit agreement governing the~~ Credit ~~Facility)~~Agreement) of no more than 3.50 to 1.00 and (2) a Current Ratio (as defined in the ~~credit agreement governing the~~ Credit ~~Facility)~~Agreement) of not less than 1.00 to 1.00. The Company was in compliance with these covenants at ~~September 30, 2022.~~March 31, 2023.

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

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

Objectives and Strategies for Using Derivative Instruments

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

Counterparty Risk and Offsetting

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

~~As of September 30, 2022,~~The Company strives to minimize its credit exposure to any individual counterparty and, as such, the Company has outstanding commodity derivative instruments with ~~nine~~ten counterparties ~~to minimize its credit exposure to any individual counterparty.~~as of March 31, 2023. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s ~~credit facility.~~Credit Facility. Therefore, each of the Company’s counterparties allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the ~~credit agreement,~~Credit Facility, thus eliminating the need for independent collateral posting.

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

While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument. See “Note ~~8 -~~10 — Fair Value Measurements” for further discussion.

1215

~~Contingent Consideration Arrangements~~

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

Financial Statement Presentation and Settlements

The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value, as 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, 2022				As of March 31, 2023
		Presented without		As Presented with		Presented without		As Presented with
		Effects of Netting	Effects of Netting	Effects of Netting		Effects of Netting	Effects of Netting	Effects of Netting
		(In thousands)				(In thousands)
Derivative Assets	Derivative Assets				Derivative Assets
Fair value of derivatives - current	Fair value of derivatives - current	$74,016	($59,272)	$14,744	Fair value of derivatives - current	$40,838	($15,077)	$25,761
Other assets, net	Other assets, net	$13,520	($12,131)	$1,389	Other assets, net	$307	($307)	$—

Derivative Liabilities	Derivative Liabilities				Derivative Liabilities
Fair value of derivatives - current	Fair value of derivatives - current	($107,969)	$59,272	($48,697)	Fair value of derivatives - current	($15,647)	$15,077	($570)
Fair value of derivatives - non-current	Fair value of derivatives - non-current	($21,735)	$12,131	($9,604)	Fair value of derivatives - non-current	($6,901)	$307	($6,594)

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


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

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

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

The components of “(Gain) loss on derivative contracts” are as follows for the respective periods:
Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 2022 2021
(In thousands)
(Gain) loss on oil derivatives ($157,731) $67,198 $243,527 $393,792
Loss on natural gas derivatives 22,881 33,026 56,800 48,539
Loss on NGL derivatives — 10,242 4,771 15,114
Gain on contingent consideration arrangements — (3,297) — (680)
Loss on September 2020 Warrants liability (1)
— — — 55,390
(Gain) loss on derivative contracts ($134,850) $107,169 $305,098 $512,155


	Three Months Ended March 31,
	2023	2022
	(In thousands)
(Gain) loss on oil derivatives	($23,344)	$325,348
(Gain) loss on natural gas derivatives	(2,301)	28,181
Loss on NGL derivatives	—	4,771


(Gain) loss on derivative contracts	($25,645)	$358,300

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

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


		Three Months Ended September 30,		Nine Months Ended September 30,			Three Months Ended March 31,
		2022	2021	2022	2021		2023	2022
		(In thousands)					(In thousands)
Cash flows from operating activities	Cash flows from operating activities					Cash flows from operating activities
Cash paid on oil derivatives	Cash paid on oil derivatives	($117,024)	($98,752)	($374,711)	($221,112)	Cash paid on oil derivatives	($7,398)	($95,353)
Cash paid on natural gas derivatives		(28,572)	(9,592)	(55,024)	(12,867)
Cash received (paid) on natural gas derivatives						Cash received (paid) on natural gas derivatives	6,619	(4,644)
Cash paid on NGL derivatives	Cash paid on NGL derivatives	—	(2,463)	(3,783)	(4,399)	Cash paid on NGL derivatives	—	(1,528)
Cash paid for commodity derivative settlements, net	Cash paid for commodity derivative settlements, net	($145,596)	($110,807)	($433,518)	($238,378)	Cash paid for commodity derivative settlements, net	($779)	($101,525)
Cash received for settlements of contingent consideration arrangements, net(1)	Cash received for settlements of contingent consideration arrangements, net(1)	$—	$—	$6,492	$—	Cash received for settlements of contingent consideration arrangements, net(1)	$—	$6,492

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

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

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

Derivative Positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of ~~September 30, 2022:~~March 31, 2023:


		For the Remainder	For the Full Year	For the Full Year		For the Remainder	For the Full Year
Oil Contracts (WTI)	Oil Contracts (WTI)	2022	2023	2024	Oil Contracts (WTI)	2023	2024
Swap Contracts	Swap Contracts				Swap Contracts
Total volume (Bbls)	Total volume (Bbls)	1,978,000	1,722,500	—	Total volume (Bbls)	866,500	—
Weighted average price per Bbl	Weighted average price per Bbl	$67.29	$81.46	$—	Weighted average price per Bbl	$80.41	$—
Collar Contracts (Three-Way Collars)	Collar Contracts (Three-Way Collars)				Collar Contracts (Three-Way Collars)
Total volume (Bbls)	Total volume (Bbls)	—	1,825,000	—	Total volume (Bbls)	1,375,000	—
Weighted average price per Bbl	Weighted average price per Bbl				Weighted average price per Bbl
Ceiling (short call)	Ceiling (short call)	$—	$90.00	$—	Ceiling (short call)	$90.00	$—
Floor (long put)	Floor (long put)	$—	$70.00	$—	Floor (long put)	$70.00	$—
Floor (short put)	Floor (short put)	$—	$50.00	$—	Floor (short put)	$50.00	$—
Collar Contracts (Two-Way Collars)	Collar Contracts (Two-Way Collars)				Collar Contracts (Two-Way Collars)
Total volume (Bbls)	Total volume (Bbls)	1,196,000	2,730,000	—	Total volume (Bbls)	1,555,000	—
Weighted average price per Bbl	Weighted average price per Bbl				Weighted average price per Bbl
Ceiling (short call)	Ceiling (short call)	$70.12	$87.15	$—	Ceiling (short call)	$86.35	$—
Floor (long put)	Floor (long put)	$60.00	$71.92	$—	Floor (long put)	$71.70	$—

Short Call Swaption Contracts (1)	Short Call Swaption Contracts (1)				Short Call Swaption Contracts (1)
Total volume (Bbls)	Total volume (Bbls)	—	—	1,830,000	Total volume (Bbls)	—	1,830,000
Weighted average price per Bbl	Weighted average price per Bbl	$—	$—	$80.30	Weighted average price per Bbl	$—	$80.30

Oil Contracts (Midland Basis Differential)
Swap Contracts
Total volume (Bbls)		598,000	—	—
Weighted average price per Bbl		$0.50	$—	$—

(1) The 2024 short call swaption contracts have exercise expiration dates of December 29, 2023.

For the Remainder For the Full Year
Natural Gas Contracts (Henry Hub) 2022 2023
Swap Contracts
Total volume (MMBtu) 1,550,000 —
Weighted average price per MMBtu $3.62 $—
Collar Contracts
Total volume (MMBtu) 3,670,000 6,640,000
Weighted average price per MMBtu
Ceiling (short call) $6.91 $6.60
Floor (long put) $4.67 $4.48
Natural Gas Contracts (Waha Basis Differential)
Swap Contracts
Total volume (MMBtu) 1,220,000 6,080,000
Weighted average price per MMBtu ($0.75) ($0.75)


	For the Remainder	For the Full Year
Natural Gas Contracts (Henry Hub)	2023	2024
Swap Contracts
Total volume (MMBtu)	5,520,000	—
Weighted average price per MMBtu	$3.70	$—
Collar Contracts
Total volume (MMBtu)	4,900,000	1,820,000
Weighted average price per MMBtu
Ceiling (short call)	$5.62	$6.00
Floor (long put)	$3.56	$3.00




Natural Gas Contracts (Waha Basis Differential)
Swap Contracts
Total volume (MMBtu)	7,030,000	3,660,000
Weighted average price per MMBtu	($1.06)	($1.05)

Natural Gas Contracts (HSC Basis Differential)
Swap Contracts
Total volume (MMBtu)	8,250,000	14,640,000
Weighted average price per MMBtu	($0.29)	($0.42)

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

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

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

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

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

Fair Value of Financial Instruments

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

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

September 30, 2022 December 31, 2021
Principal Amount Fair Value Principal Amount Fair Value
(In thousands)
6.125% Senior Notes $— $— $460,241 $455,639
9.00% Second Lien Notes — — 319,659 343,633
8.25% Senior Notes 187,238 183,104 187,238 184,429
6.375% Senior Notes 320,783 289,112 320,783 309,556
8.00% Senior Notes 650,000 599,086 650,000 663,000
7.50% Senior Notes 600,000 525,696 — —
Total $1,758,021 $1,596,998 $1,937,921 $1,956,257


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


8.25% Senior Notes	$187,238	$186,459	$187,238	$186,719
6.375% Senior Notes	320,783	305,623	320,783	301,732
8.0% Senior Notes	650,000	644,111	650,000	616,935
7.5% Senior Notes	600,000	563,682	600,000	550,812
Total	$1,758,021	$1,699,875	$1,758,021	$1,656,198

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

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

derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and as there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note ~~7 -~~9 — Derivative Instruments and Hedging Activities” for further discussion.

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

~~September 30,~~March 31, 2023

Level 1

Level 2

Level 3

(In thousands)

Commodity derivative assets

$—

$25,761

$—

Commodity derivative liabilities

$—

($7,164)

$—

December 31, 2022

Level 1

Level 2

Level 3

(In thousands)

Commodity derivative assets

$—

$~~16,133~~21,786

$—

Commodity derivative liabilities

$—

($~~58,301)~~29,612)

$—

~~December 31, 2021~~

~~Level 1~~

~~Level 2~~

~~Level 3~~

~~(In thousands)~~

~~Assets~~

~~Commodity derivative instruments~~

$—

~~$1,798~~

$—

~~Contingent consideration arrangements~~

—

~~20,833~~

—

~~Liabilities~~

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

—

~~(172,386)~~

—

~~Contingent consideration arrangements~~

—

~~(25,000)~~

—

~~Total net assets (liabilities)~~

$—

~~($174,755)~~

$—

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

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

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

~~Acquisitions.~~ The fair value of assets acquired and liabilities assumed are measured as of the acquisition date by a third-party valuation specialist using a combination of income and market approaches, which are not observable in the market and are therefore designated

as Level 3 inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and costs to produce and develop reserves, oil and natural gas forward prices, and a risk-adjusted discount rate. See “Note 3 - Acquisitions and Divestitures” for additional discussion.

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

Note ~~9 -~~11 — Income Taxes

The Company provides for income taxes at the statutory rate of 21%. Reported income tax 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 ~~both~~ the three ~~and nine~~ months ended ~~September 30,~~March 31, 2023 and 2022, ~~and 2021,~~ the Company’s effective income tax rates were approximately 30% and 1%., respectively. The primary differences between the effective tax ~~rates for the three and nine months ended September 30, 2022 and 2021~~rate and the statutory rate for the three months ended March 31, 2023 resulted from the release of the valuation allowance recorded against the Company’s net deferred tax assets ~~beginning~~as discussed further below. For the three months ended March 31, 2022, the effective tax rate differed from the statutory rate as a result of the valuation allowance that was in ~~the second quarter of 2020~~place and the effect of state income taxes.

Deferred Tax Asset Valuation Allowance

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

the Company’s net deferred tax assets will be utilized prior to their expiration. ~~A significant item of objective negative evidence considered was~~As previously disclosed in the ~~cumulative historical three-year pre-tax loss and a net deferred tax asset position at September 30,~~Company’s 2022 ~~driven primarily by the impairments of evaluated oil and gas properties recognized~~Annual Report, beginning in the second quarter of 2020 and ~~continuing~~ through the fourth quarter of 2020. This limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Since the second quarter of 2020, based on the evaluation of the evidence available,2022, the Company ~~concluded that it is more likely than not that the~~maintained a valuation allowance against its net deferred tax ~~assets will not be realized.~~assets. As ~~a result,~~of March 31, 2023, considering all available evidence (both positive and negative), the Company ~~has recorded a valuation allowance, reducing the net deferred tax assets as of September 30, 2022 to zero.~~

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

~~Inflation Reduction Act~~

On August 16, 2022, the Inflation Reduction Act (the “IRA”) was enacted into law and includes significant changes relating to tax, climate change, energy, and health care. The provisions within the IRA, among other things, include (i) a new 15% corporate alternative minimum tax on corporations with average annual adjusted financial statement income over a three-year period in excessbenefit of ~~$1.0 billion, (ii) a new nondeductible 1% excise tax~~$52.0 million for the ~~value of certain stock that a company repurchases, and (iii) various tax incentives for energy and climate initiatives. Each of these provisions are effective for tax years beginning after December~~three months ended March 31, 2022. The Company is in the process of evaluating the provisions of the IRA and potential impacts, but does not currently believe this will have a material impact on our cash taxes for the 2023 tax year.2023.

1719

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

RSU Equity Awards

The following table summarizes activity for restricted stock units that may be settled in common stock (“RSU Equity Awards”) for the ~~nine~~three months ended ~~September 30, 2022:~~March 31, 2023:


		Nine Months Ended September 30, 2022			Three Months Ended March 31, 2023
		RSU Equity Awards (In thousands)	Weighted Average Grant Date Fair Value		RSU Equity Awards (In thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	Unvested, beginning of the period	968	$34.04	Unvested, beginning of the period	800	$44.79
Granted	Granted	358	$59.78	Granted	317	$34.02
Vested	Vested	(356)	$35.33	Vested	(6)	$49.23
Forfeited	Forfeited	(89)	$37.90	Forfeited	(21)	$43.81
Unvested, end of the period	Unvested, end of the period	881	$43.60	Unvested, end of the period	1,090	$41.65

Grant activity for the ~~nine~~three months ended ~~September 30, 2022~~March 31, 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 ~~$59.78~~$34.02.

The aggregate fair value of RSU Equity Awards that vested during the ~~nine~~three months ended ~~September 30, 2022~~March 31, 2023 was ~~$21.6~~$0.2 million. As of ~~September 30, 2022,~~March 31, 2023, unrecognized compensation costs related to unvested RSU Equity Awards were ~~$27.6~~$30.2 million and will be recognized over a weighted average period of ~~2.0~~2.1 years.

Cash-Settled Awards

NoAs of March 31, 2023 and December 31, 2022, the Company had a total liability of $4.2 million and $6.5 million, respectively, which, as of December 31, 2022, consisted of restricted stock ~~units~~unit awards that may be settled in cash (“Cash-Settled RSU Awards”) ~~or cash-settled~~and stock appreciation rights to be settled in cash (“Cash SARs” and, collectively with the Cash-Settled RSU Awards, the “Cash-Settled Awards”). As of March 31, 2023, there were granted to employees during the three or nine months ended September 30, 2022. The following table summarizes the Company’s liabilities for cash-settled awards and the classification in the consolidated balance sheets for the periods indicated:

September 30, 2022 December 31, 2021
(In thousands)
Cash SARs $4,861 $7,884
Cash-Settled RSU Awards 676 1,382
Other current liabilities 5,537 9,266
Cash-Settled RSU Awards 1,310 6,366
Other long-term liabilities 1,310 6,366
Total Cash-Settled RSU Awards $6,847 $15,632
no Cash-Settled RSU Awards outstanding.

Share-Based Compensation Expense (Benefit), Net

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2022 2021 2022 2021
(In thousands)
RSU Equity Awards $3,892 $3,839 $11,581 $9,689
Cash-Settled RSU Awards (706) (1,344) (4,131) 6,105
Cash SARs (1,445) (2,006) (3,023) 6,536
1,741 489 4,427 22,330
Less: amounts capitalized to oil and gas properties (1,642) (1,392) (3,372) (10,346)
Total share-based compensation expense (benefit), net $99 ($903) $1,055 $11,984


	Three Months Ended March 31,
	2023	2022*
	(In thousands)
RSU Equity Awards	$3,626	$3,366
Cash-Settled Awards	(1,745)	2,677
Total share-based compensation expense (benefit), net	$1,881	$6,043

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

Note 13 — Accounts Receivable, Net


	March 31, 2023	December 31, 2022
	(In thousands)
Oil and natural gas receivables	$153,362	$174,107
Joint interest receivables	22,575	16,778
Other receivables	36,204	48,277
Total	212,141	239,162
Allowance for credit losses	(2,034)	(2,034)
Total accounts receivable, net	$210,107	$237,128

Note ~~11 - Accounts Receivable, Net~~

September 30, 2022 December 31, 2021
(In thousands)
Oil and natural gas receivables $219,700 $171,837
Joint interest receivables 23,692 13,751
Other receivables 44,427 49,053
Total 287,819 234,641
Allowance for credit losses (2,228) (2,205)
Total accounts receivable, net $285,591 $232,436

~~Note 12 -~~14 — Accounts Payable and Accrued Liabilities


		September 30, 2022	December 31, 2021		March 31, 2023	December 31, 2022
		(In thousands)			(In thousands)
Accounts payable	Accounts payable	$170,975	$151,836	Accounts payable	$199,268	$191,133
Revenues and royalties payable	Revenues and royalties payable	304,321	294,143	Revenues and royalties payable	234,379	244,408
Accrued capital expenditures	Accrued capital expenditures	88,394	64,412	Accrued capital expenditures	85,540	58,395
Accrued interest	Accrued interest	30,589	59,600	Accrued interest	31,736	42,297
Total accounts payable and accrued liabilities	Total accounts payable and accrued liabilities	$594,279	$569,991	Total accounts payable and accrued liabilities	$550,923	$536,233

Note ~~13 -~~15 — Supplemental Cash Flow

Nine Months Ended September 30,
2022 2021
(In thousands)
Supplemental cash flow information:
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases $5,180 $20,224
Investing cash flows from operating leases 30,812 13,852
Non-cash investing and financing activities:
Change in accrued capital expenditures $13,966 $17,087
Change in asset retirement costs 3,665 3,381
ROU assets obtained in exchange for lease liabilities:
Operating leases $55,605 $9,710


	Three Months Ended March 31,
	2023	2022*
	(In thousands)
Supplemental cash flow information:
Interest paid	$54,233	$54,930
Income taxes paid (1)	—	—



Non-cash investing and financing activities:
Change in accrued capital expenditures	$67,460	($8,897)
Change in asset retirement costs	568	289

(1) The Company did not pay or receive a refund for any federal income tax for the periods presented above. For the three months ended March 31, 2023 and 2022, the Company received refunds of $0.2 million and $2.8 million, respectively, for state income taxes.

Note ~~14 -~~16 — Subsequent Events

~~Amended & Restated~~ Credit Agreement Reaffirmation

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

Divestiture of Eagle Ford Properties

On ~~October 19, 2022~~,May 3, 2023, the Company entered into an agreement with Ridgemar Energy Operating, LLC (“Ridgemar”) for the ~~Credit Agreement governing~~sale of all its oil and gas properties in the ~~Credit Facility.~~ ~~See “Note 6 – Borrowings”~~Eagle Ford for ~~additional details.~~cash consideration of $655.0 million, 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. Upon signing, Ridgemar paid approximately $49.1 million as a deposit into third-party escrow accounts. The transaction is structured as the acquisition by Ridgemar of 100% of the limited liability company interests of the Company’s wholly owned subsidiary, Callon (Eagle Ford) LLC.

Acquisition of Delaware Basin Properties

On May 3, 2023, the Company entered into an agreement with Percussion Petroleum Operating,II, LLC (“Percussion”) for the purchase of its oil and gas properties in the Delaware Basin for cash consideration of $265.0 million and $210.0 million of shares of Company common stock. Additionally, the Company could have to pay up to $62.5 million of contingent consideration if the WTI price of oil exceeds certain thresholds in 2023, 2024, and 2025. Upon signing, the Company paid $36.0 million as a deposit into third-party escrow accounts. The transaction is structured as the acquisition by Callon Petroleum Operating Company of 100% of the limited liability company interests of Percussion’s wholly owned subsidiary, Percussion Petroleum Operating II, LLC.

Closing of both transactions is expected to occur early in July 2023, subject to completion of various customary conditions.

Approval of Share Repurchase Program

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, contingent upon the consummation of the transactions described above. 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.

1921

Special Note Regarding Forward-Looking Statements

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

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

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

•the amount and nature of our capital expenditures;

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

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

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

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

•business strategies and plans of management;

•our ability to efficiently integrate recent acquisitions; and

•prospect development and property acquisitions.

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

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

•general economic conditions, including the availability of credit, 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 ~~the COVID-19 pandemic and various governmental actions taken to mitigate its impact or~~ actions by, or disputes among, members of OPEC and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil;

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

•impairments;

•the impact of competition;

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

•our dependency on third-party service providers;

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

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

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

•physical risks arising from climate change;

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

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

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

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

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

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

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

•any increase in severance or similar taxes;

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

•the comparative cost of alternative fuels;

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

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

•weather conditions; and

•risks associated with acquisitions.

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

In addition, we caution that reserve engineering is a process of estimating oil and natural gas accumulated underground and cannot be measured exactly. Accuracy of reserve estimates depend on a number of factors including data available at the point in time, engineering interpretation of the data, and assumptions used by the reserve engineers as it relates to price and cost estimates and

recoverability. New results of drilling, testing, and production history may result in revisions of previous estimates and, if significant, would impact future development plans. As such, reserve estimates may differ from actual results of oil and natural gas quantities ultimately recovered.

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

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

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

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

General

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

Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals in the Permian, including multiple levels of the Wolfcamp formation and the ~~Lower~~ Spraberry shales, and in the Eagle Ford. We have assembled a multi-year 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 acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps.

~~Recent Developments~~

~~On October 19, 2022, we~~ entered into the Credit Agreement governing the Credit Facility on substantially similar terms as those in the credit agreement governing the Prior Credit Facility. The Credit Agreement, among other things, extended maturity unt~~il October 19, 2027, established~~ a borrowing base of $2.0 billion, with an elected commitment amount of $1.5 billion, replaced all provisions and related definitions regarding LIBOR with a SOFR based benchmark rate, and decreased the maximum leverage ratio from 4.00 to 1.00 to 3.50 to 1.00. ~~See “Note 6 – Borrowings” for additional details.~~

~~Third~~First Quarter ~~2022~~2023 Highlights

•Total production for the three months ended September 30, 2022 was 107.3 MBoe/d, an increase of 7% from the three months ended June 30, 2022, primarily due to new wells placed on production during the third quarter of 2022, partially offset by normal production decline. Total production for the nine months ended September 30, 2022 increased 15% from the nine months ended September 30, 2021, primarily due to new wells acquired in the Primexx Acquisition as well as new wells placed on production, partially offset by normal production decline as well as non-core asset divestitures which occurred primarily in the fourth quarter of 2021.

•Operated drilling and ~~completion~~turned in-line activity for the three months ended ~~September 30, 2022~~March 31, 2023 along with our drilled but uncompleted and producing wells as of ~~September 30, 2022~~March 31, 2023 are summarized in the table below.


		Three Months Ended September 30, 2022				As of September 30, 2022					Three Months Ended March 31, 2023				As of March 31, 2023
		Drilled		Completed		Drilled But Uncompleted		Producing			Drilled		Turned In-Line		Drilled But Uncompleted		Producing
Region	Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Permian	Permian	24	22.1	35	30.9	29	26.8	806	710.4	Permian	25	22.7	29	25.7	25	22.7	778	683.8
Eagle Ford	Eagle Ford	3	3.0	11	10.4	—	—	614	553.7	Eagle Ford	3	2.4	—	—	3	2.3	604	541.9
Total	Total	27	25.1	46	41.3	29	26.8	1,420	1,264.1	Total	28	25.1	29	25.7	28	25.0	1,382	1,225.7

•Operational capital expenditures, exclusive of leasehold, ~~and seismic,~~ for the ~~third~~first quarter of ~~2022~~2023 were ~~$254.6~~$270.1 million, of which approximately ~~85%~~95% were in the Permian with the remaining balance in the Eagle Ford. ~~See “—Liquidity and Capital Resources—2022 Capital Budget and Funding Strategy” for additional details.~~

•Recorded net income for the three months ended ~~September 30, 2022~~March 31, 2023 of ~~$549.6~~$220.6 million, or ~~$8.88~~$3.57 per diluted share, compared to net ~~income~~loss for the three months ended ~~September 30, 2021~~March 31, 2022 of ~~$171.9~~$7.7 million, or ~~$3.65~~$0.13 per diluted share. The variance between the periods was driven primarily by ~~an increase~~a gain on derivative contracts of $25.6 million during the first quarter of 2023 compared to a loss of approximately $358.3 million during the first quarter of 2022 as well as income tax benefit of $50.7 million during the first quarter of 2023 due to the release of our deferred tax asset valuation allowance, partially offset by a decrease in operating revenues in the ~~third~~first quarter of ~~2022~~2023 driven by an approximate ~~34% increase~~26% decrease in the total average realized sales price and ~~an increase~~a decrease of 8%3% in production volumes compared to the ~~third~~first quarter of ~~2021 as well as a gain on derivative contracts~~2022.

Results of ~~$134.9 million during~~Operations

Production


	Three Months Ended							Three Months Ended March 31,
	March 31, 2023		December 31, 2022		Change	% Change		2023		2022		Change	% Change
Total production
Oil (MBbls)
Permian	4,275		4,715		(440)	(9	%)	4,275		4,469		(194)	(4	%)
Eagle Ford	1,139		1,377		(238)	(17	%)	1,139		1,377		(238)	(17	%)
Total oil	5,414		6,092		(678)	(11	%)	5,414		5,846		(432)	(7	%)

Natural gas (MMcf)
Permian	9,288		9,013		275	3	%	9,288		8,590		698	8	%
Eagle Ford	1,336		1,530		(194)	(13	%)	1,336		1,525		(189)	(12	%)
Total natural gas	10,624		10,543		81	1	%	10,624		10,115		509	5	%

NGLs (MBbls)
Permian	1,572		1,645		(73)	(4	%)	1,572		1,455		117	8	%
Eagle Ford	222		285		(63)	(22	%)	222		252		(30)	(12	%)
Total NGLs	1,794		1,930		(136)	(7	%)	1,794		1,707		87	5	%

Total production (MBoe)
Permian	7,395		7,862		(467)	(6	%)	7,395		7,356		39	1	%
Eagle Ford	1,584		1,917		(333)	(17	%)	1,584		1,883		(299)	(16	%)
Total barrels of oil equivalent	8,979		9,779		(800)	(8	%)	8,979		9,239		(260)	(3	%)

Total daily production (Boe/d)	99,768		106,287		(6,519)	(6	%)	99,768		102,655		(2,887)	(3	%)
Percent of total daily production
Oil	60	%	62	%		(3	%)	60	%	63	%		(5	%)
Natural gas	20	%	18	%		11	%	20	%	18	%		11	%
NGLs	20	%	20	%		—	%	20	%	19	%		5	%

The decrease in production for three months ended March 31, 2023 compared to the ~~third~~three months ended December 31, 2022 was primarily to due decreased completion activity in the fourth quarter of 2022 and normal production decline on existing wells, partially offset by new wells turned in-line during the first quarter of 2023. The decrease in production for the three months ended March 31, 2023 compared to the three months ended March 31, 2022 was primarily due to normal production decline on existing wells, partially offset by new wells turned in-line during the first quarter of 2023.

2124

to a loss of approximately $107.2 million during the third quarter of 2021. This increase was partially offset by an increase in operating expenses. See “—Results of Operations” below for further details.Pricing

~~Results of Operations~~

~~The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated:~~

Three Months Ended Nine Months Ended September 30,
September 30, 2022 June 30, 2022 Change % Change 2022 2021 Change % Change
Total production
Oil (MBbls)
Permian 4,567 4,290 277 6 % 13,326 9,748 3,578 37 %
Eagle Ford 1,545 1,299 246 19 % 4,221 5,910 (1,689) (29 %)
Total oil 6,112 5,589 523 9 % 17,547 15,658 1,889 12 %
Natural gas (MMcf)
Permian 9,041 8,875 166 2 % 26,506 20,499 6,007 29 %
Eagle Ford 1,616 1,437 179 12 % 4,578 5,614 (1,036) (18 %)
Total natural gas 10,657 10,312 345 3 % 31,084 26,113 4,971 19 %
NGLs (MBbls)
Permian 1,702 1,622 80 5 % 4,779 3,606 1,173 33 %
Eagle Ford 283 232 51 22 % 767 940 (173) (18 %)
Total NGLs 1,985 1,854 131 7 % 5,546 4,546 1,000 22 %
Total production (MBoe)
Permian 7,776 7,391 385 5 % 22,523 16,771 5,752 34 %
Eagle Ford 2,097 1,771 326 18 % 5,751 7,785 (2,034) (26 %)
Total barrels of oil equivalent 9,873 9,162 711 8 % 28,274 24,556 3,718 15 %
Total daily production (Boe/d) 107,316 100,685 6,631 7 % 103,569 89,949 13,620 15 %
Oil as % of total daily production 62 % 61 % 62 % 64 %
Benchmark prices (1)
WTI (per Bbl) $91.64 $108.42 ($16.78) (15 %) $98.14 $64.83 $33.31 51 %
Henry Hub (per Mcf) 7.91 7.50 0.41 5 % 6.67 3.34 3.33 100 %
Average realized sales price (excluding impact of derivative settlements)

Oil (per Bbl)
Permian $94.19 $110.71 ($16.52) (15 %) $99.62 $64.00 $35.62 56 %
Eagle Ford 94.31 111.53 (17.22) (15 %) 99.84 65.29 34.55 53 %
Total oil 94.22 110.90 (16.68) (15 %) 99.67 64.49 35.18 55 %
Natural gas (per Mcf)
Permian 7.53 6.14 1.39 23 % 5.98 3.20 2.78 87 %
Eagle Ford 8.01 7.27 0.74 10 % 6.84 3.44 3.40 99 %
Total natural gas 7.60 6.29 1.31 21 % 6.11 3.25 2.86 88 %
NGL (per Bbl)
Permian 34.12 41.06 (6.94) (17 %) 38.34 27.64 10.70 39 %
Eagle Ford 33.49 38.53 (5.04) (13 %) 35.82 25.96 9.86 38 %
Total NGLs 34.03 40.74 (6.71) (16 %) 37.99 27.29 10.70 39 %
Total average realized sales price (per Boe)
Permian 71.54 80.64 (9.10) (11 %) 74.12 47.05 27.07 58 %
Eagle Ford 80.18 92.75 (12.57) (14 %) 83.50 55.18 28.32 51 %
Total average realized sales price $73.37 $82.98 ($9.61) (12 %) $76.02 $49.63 $26.39 53 %


		Three Months Ended					Nine Months Ended September 30,						Three Months Ended					Three Months Ended March 31,
		September 30, 2022	June 30, 2022	$ Change	% Change		2022	2021	$ Change	% Change			March 31, 2023	December 31, 2022	Change	% Change		2023	2022	Change	% Change
Revenues (in thousands)
Oil
Benchmark prices (1)												Benchmark prices (1)
WTI (per Bbl)												WTI (per Bbl)	$76.11	$82.76	($6.65)	(8	%)	$76.11	$94.38	($18.27)	(19	%)
Henry Hub (per Mcf)												Henry Hub (per Mcf)	2.77	6.14	(3.37)	(55	%)	2.77	4.57	(1.80)	(39	%)

Average realized sales price (excluding impact of derivative settlements)												Average realized sales price (excluding impact of derivative settlements)
Oil (per Bbl)												Oil (per Bbl)
Permian	Permian	$430,145	$474,936	($44,791)	(9	%)	$1,327,485	$623,889	$703,596	113	%	Permian	$75.55	$84.19	($8.64)	(10	%)	$75.55	$94.52	($18.97)	(20	%)
Eagle Ford	Eagle Ford	145,707	144,876	831	1	%	421,428	385,891	35,537	9	%	Eagle Ford	76.02	84.82	(8.80)	(10	%)	76.02	95.02	(19.00)	(20	%)
Total oil	Total oil	575,852	619,812	(43,960)	(7	%)	1,748,913	1,009,780	739,133	73	%	Total oil	75.65	84.33	(8.68)	(10	%)	75.65	94.64	(18.99)	(20	%)

Natural gas
Natural gas (per Mcf)												Natural gas (per Mcf)
Permian	Permian	68,075	54,469	13,606	25	%	158,613	65,507	93,106	142	%	Permian	2.07	3.83	(1.76)	(46	%)	2.07	4.20	(2.13)	(51	%)
Eagle Ford	Eagle Ford	12,943	10,444	2,499	24	%	31,294	19,312	11,982	62	%	Eagle Ford	3.26	5.38	(2.12)	(39	%)	3.26	5.18	(1.92)	(37	%)
Total natural gas	Total natural gas	81,018	64,913	16,105	25	%	189,907	84,819	105,088	124	%	Total natural gas	2.22	4.06	(1.84)	(45	%)	2.22	4.35	(2.13)	(49	%)

NGLs
NGL (per Bbl)												NGL (per Bbl)
Permian	Permian	58,069	66,592	(8,523)	(13	%)	183,224	99,672	83,552	84	%	Permian	24.56	25.99	(1.43)	(6	%)	24.56	40.25	(15.69)	(39	%)
Eagle Ford	Eagle Ford	9,479	8,938	541	6	%	27,472	24,407	3,065	13	%	Eagle Ford	21.41	24.67	(3.26)	(13	%)	21.41	35.93	(14.52)	(40	%)
Total NGLs	Total NGLs	67,548	75,530	(7,982)	(11	%)	210,696	124,079	86,617	70	%	Total NGLs	24.18	25.79	(1.61)	(6	%)	24.18	39.61	(15.43)	(39	%)

Total revenues
Total average realized sales price (per Boe)												Total average realized sales price (per Boe)
Permian	Permian	556,289	595,997	(39,708)	(7	%)	1,669,322	789,068	880,254	112	%	Permian	51.50	60.32	(8.82)	(15	%)	51.50	70.29	(18.79)	(27	%)
Eagle Ford	Eagle Ford	168,129	164,258	3,871	2	%	480,194	429,610	50,584	12	%	Eagle Ford	60.42	68.89	(8.47)	(12	%)	60.42	78.50	(18.08)	(23	%)
Total revenues		$724,418	$760,255	($35,837)	(5	%)	$2,149,516	$1,218,678	$930,838	76	%

Additional per Boe data
Lease operating expense
Permian		$7.55	$7.33	$0.22	3	%	$7.25	$4.36	$2.89	66	%
Eagle Ford		8.31	10.59	(2.28)	(22	%)	9.24	7.25	1.99	27	%
Total lease operating expense		$7.71	$7.96	($0.25)	(3	%)	$7.65	$5.28	$2.37	45	%

Production and ad valorem taxes
Permian		$4.27	$4.66	($0.39)	(8	%)	$4.29	$2.56	$1.73	68	%
Eagle Ford		4.79	5.89	(1.10)	(19	%)	5.14	3.01	2.13	71	%
Total production and ad valorem taxes		$4.38	$4.90	($0.52)	(11	%)	$4.45	$2.70	$1.75	65	%

Gathering, transportation and processing
Permian		$3.06	$2.69	$0.37	14	%	$2.70	$2.67	$0.03	1	%
Eagle Ford		1.80	1.93	(0.13)	(7	%)	1.88	1.82	0.06	3	%
Total gathering, transportation and processing		$2.79	$2.54	$0.25	10	%	$2.53	$2.40	$0.13	5	%
Total average realized sales price												Total average realized sales price	$53.07	$62.00	($8.93)	(14	%)	$53.07	$71.97	($18.90)	(26	%)

(1) Reflects calendar average daily spot market prices.

Revenues

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

Oil Natural Gas NGLs Total
(In thousands)
Revenues for the three months ended June 30, 2022 (1)
$619,812 $64,913 $75,530 $760,255
Volume increase (decrease) 58,000 2,172 5,337 65,509
Price increase (decrease) (101,960) 13,933 (13,319) (101,346)
Net increase (43,960) 16,105 (7,982) (35,837)
Revenues for the three months ended September 30, 2022 (1)
$575,852 $81,018 $67,548 $724,418
Percent of total revenues 80 % 11 % 9 %


	Oil		Natural Gas		NGLs		Total
	(In thousands)
Revenues for the three months ended December 31, 2022 (1)	$513,734		$42,774		$49,776		$606,284
Volume increase (decrease)	(57,183)		328		(3,508)		(60,363)
Price decrease	(46,995)		(19,516)		(2,898)		(69,409)
Net decrease	(104,178)		(19,188)		(6,406)		(129,772)
Revenues for the three months ended March 31, 2023 (1)	$409,556		$23,586		$43,370		$476,512

Percent of total revenues	86	%	5	%	9	%

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

Oil Natural Gas NGLs Total
(In thousands)
Revenues for the nine months ended September 30, 2021(1)
$1,009,780 $84,819 $124,079 $1,218,678
Volume increase 121,821 16,147 27,294 165,262
Price increase 617,312 88,941 59,323 765,576
Net increase 739,133 105,088 86,617 930,838
Revenues for the nine months ended September 30, 2022 (1)
$1,748,913 $189,907 $210,696 $2,149,516
Percent of total revenues 81 % 9 % 10 %
The decrease in revenues for the three months ended March 31, 2023 compared to the three months ended December 31, 2022 was primarily due to a 14% decrease in the average realized sales price, which decreased to $53.07 per Bbl from $62.00 per Bbl, as well as a 6% decrease in production, as shown above.


	Oil		Natural Gas		NGLs		Total
	(In thousands)
Revenues for the three months ended March 31, 2022(1)	$553,249		$43,976		$67,618		$664,843
Volume increase (decrease)	(40,892)		2,212		3,446		(35,234)
Price decrease	(102,801)		(22,602)		(27,694)		(153,097)
Net decrease	(143,693)		(20,390)		(24,248)		(188,331)
Revenues for the three months ended March 31, 2023 (1)	$409,556		$23,586		$43,370		$476,512

Percent of total revenues	86	%	5	%	9	%

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

~~Revenues~~The decrease in revenues for the three months ended ~~September 30, 2022 of $724.4 million decreased $35.8 million, or 5%,~~March 31, 2023 compared to ~~revenues~~the same period of ~~$760.3 million for the three months ended June 30, 2022. The decrease~~2022 was primarily ~~attributable~~due to a ~~15%~~26% decrease in the average realized sales price, ~~for oil,~~ which decreased to ~~$94.22~~$53.07 per Bbl from $110.90 per Bbl, partially offset by a 21% increase in the average realized sales price for natural gas, which rose to $7.60 per Mcf from $6.29 per Mcf. The decrease in the average realized price for oil was also partially offset by a 7% increase in production, as discussed above.

Revenues for the nine months ended September 30, 2022 of $2.1 billion increased $930.8 million, or 76%, compared to revenues of $1.2 billion for the same period of 2021. The increase was primarily attributable to a 55% increase in the average realized sales price of oil, which rose to $99.67 per Bbl from $64.49$71.97 per Bbl, as well as a ~~15% increase~~3% decrease in production, as ~~discussed~~shown above.

Operating Expenses

Three Months Ended
September 30, 2022 Per June 30, 2022 Per Total Change Boe Change
Boe Boe $ % $ %
(In thousands, except per Boe and % amounts)
Lease operating $76,121 $7.71 $72,940 $7.96 $3,181 4 % ($0.25) (3 %)
Production and ad valorem taxes 43,290 4.38 44,873 4.90 (1,583) (4 %) (0.52) (11 %)
Gathering, transportation and processing 27,575 2.79 23,267 2.54 4,308 19 % 0.25 10 %
Depreciation, depletion and amortization 122,833 12.44 109,409 11.94 13,424 12 % 0.50 4 %
General and administrative 14,022 1.42 10,909 1.19 3,113 29 % 0.23 19 %
Nine Months Ended September 30,
Per Per Total Change Boe Change
2022 Boe 2021 Boe $ % $ %
(In thousands, except per Boe and % amounts)
Lease operating $216,389 $7.65 $129,619 $5.28 $86,770 67 % $2.37 45 %
Production and ad valorem taxes 125,841 4.45 66,467 2.71 59,374 89 % 1.74 64 %
Gathering, transportation and processing 71,617 2.53 58,887 2.40 12,730 22 % 0.13 5 %
Depreciation, depletion and amortization 335,221 11.86 244,005 9.94 91,216 37 % 1.92 19 %
General and administrative 42,052 1.49 37,367 1.52 4,685 13 % (0.03) (2 %)
Merger, integration and transaction 769 0.03 3,018 0.12 (2,249) (75 %) (0.09) (75 %)

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


	Three Months Ended
	March 31, 2023	Per	December 31, 2022	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$58,215	$7.87	$54,768	$6.97	$3,447	6	%	$0.90	13	%
Eagle Ford	16,887	10.66	19,329	10.08	(2,442)	(13	%)	0.58	6	%
Lease operating	$75,102	$8.36	$74,097	$7.58	$1,005	1	%	$0.78	10	%

	Three Months Ended March 31,
		Per		Per	Total Change			Boe Change
	2023	Boe	2022	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$58,215	$7.87	$50,391	$6.85	$7,824	16	%	$1.02	15	%
Eagle Ford	16,887	10.66	16,937	8.99	(50)	—	%	1.67	19	%
Lease operating	$75,102	$8.36	$67,328	$7.29	$7,774	12	%	$1.07	15	%

The increase in lease operating expenses, as well as lease operating expenses per Boe, for the three months ended ~~September 30, 2022 increased to $76.1 million~~March 31, 2023 compared to ~~$72.9 million for~~ the three months ended ~~June 30,~~December 31, 2022 was primarily due to increases in certain operating costs such as fuel, power and ~~repairs and maintenance and overall cost inflation. Lease~~equipment rental, as well as the distribution of fixed costs spread over lower production volumes.

The increase in lease operating ~~expense~~expenses, as well as lease operating expenses per Boe, for the three months ended ~~September 30, 2022 decreased to $7.71~~March 31, 2023 compared to ~~$7.96 for the three months ended June 30, 2022, primarily due to the distribution of fixed costs spread over higher production volumes.~~

~~Lease operating expenses for the nine months ended September 30, 2022 increased to $216.4 million compared to $129.6 million for~~ the same period of ~~2021,~~2022 was primarily due to ~~the increase in production from wells acquired in the Primexx Acquisition,~~ increases in certain operating expenses such as fuel, power and ~~chemicals,~~equipment rental and overall cost inflation. Lease operating expense per Boe for the nine months ended September 30, 2022 increased to $7.65 compared to $5.28 for the same period of 2021, primarily due to the increase in certain operating expenses as discussed aboveinflation, as well as the ~~increase in certain operating expenses associated with the Primexx Acquisition.~~distribution of fixed costs spread over lower production volumes.

Production and Ad Valorem ~~Taxes.~~ ~~For the three months ended September 30, 2022,~~Taxes


	Three Months Ended
	March 31, 2023		Per	December 31, 2022		Per	Total Change			Boe Change
			Boe			Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$25,397		$3.43	$26,668		$3.39	($1,271)	(5	%)	$0.04	1	%
Eagle Ford	7,324		4.62	7,411		3.87	(87)	(1	%)	0.75	19	%
Production and ad valorem taxes	$32,721		$3.64	$34,079		$3.48	($1,358)	(4	%)	$0.16	5	%

Percent of total revenues	6.9	%		5.6	%			1.3	%

	Three Months Ended March 31,
			Per			Per	Total Change			Boe Change
	2023		Boe	2022		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$25,397		$3.43	$28,604		$3.89	($3,207)	(11	%)	($0.46)	(12	%)
Eagle Ford	7,324		4.62	9,074		4.82	(1,750)	(19	%)	(0.20)	(4	%)
Production and ad valorem taxes	$32,721		$3.64	$37,678		$4.08	($4,957)	(13	%)	($0.44)	(11	%)

Percent of total revenues	6.9	%		5.7	%			1.2	%

The decrease in production and ad valorem taxes ~~decreased 4% to $43.3 million compared to $44.9 million~~ for the three months ended ~~June 30,~~March 31, 2023 compared to the three months ended December 31, 2022 ~~which is~~was primarily related to a 5%21% 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 ~~2021~~2022 compared to ~~2020. Production~~2021. The increase in production and ad valorem taxes as a percentage of total revenues ~~increased to 6.0%~~ for the ~~third~~first quarter of ~~2022 as~~2023 compared to ~~5.9% of total revenues for~~ the three months ended ~~June 30,~~December 31, 2022 was primarily due to an increase in ad valorem taxes, as discussed above, with a decrease in total revenues during the ~~third~~first quarter of ~~2022 as discussed above.~~2023.

~~For the nine months ended September 30, 2022,~~The decrease in production and ad valorem taxes ~~increased 89% to $125.8 million~~for the three months ended March 31, 2023 compared to ~~$66.5 million for~~ the same period of ~~2021, which is~~2022 was primarily related to a ~~76% increase~~28% decrease in total revenues which ~~increased~~decreased production taxes, ~~as well as~~partially offset by an increase in ad valorem taxes as discussed in the paragraph above. ~~Production~~The increase in production and ad valorem taxes as a percentage of total revenues ~~increased to 5.9%~~ for the ~~nine~~three months ended ~~September 30, 2022, as~~March 31, 2023 compared to ~~5.5% of total revenues for~~ the same period of ~~2021,~~2022 was primarily due to an increase in ad valorem taxes during the ~~nine~~three months ended ~~September 30, 2022~~March 31, 2023, as discussed ~~above.~~above, with a decrease in total revenues during the first quarter of 2023.

Gathering, Transportation and Processing Expenses~~. For the three months ended September 30, 2022,~~


	Three Months Ended
	March 31, 2023	Per	December 31, 2022	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$22,707	$3.07	$21,648	$2.75	$1,059	5	%	$0.32	12	%
Eagle Ford	3,270	2.06	3,637	1.90	(367)	(10	%)	0.16	8	%
Gathering, transportation and processing	$25,977	$2.89	$25,285	$2.59	$692	3	%	$0.30	12	%

	Three Months Ended March 31,
		Per		Per	Total Change			Boe Change
	2023	Boe	2022	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Permian	$22,707	$3.07	$17,167	$2.33	$5,540	32	%	$0.74	32	%
Eagle Ford	3,270	2.06	3,608	1.92	(338)	(9	%)	0.14	7	%
Gathering, transportation and processing	$25,977	$2.89	$20,775	$2.25	$5,202	25	%	$0.64	28	%

The increase in gathering, transportation and processing expenses ~~increased 19% to $27.6 million compared to $23.3 million~~ for the three months ended ~~June 30,~~March 31, 2023 compared to the three months ended December 31, 2022, ~~which is~~as well as the three months ended March 31, 2022, was primarily related to ~~the 7% increase in production volumes between the two periods as well as an annual~~a contractual increase in rates for certain agreements.

For the nine months ended September 30, 2022, gathering, transportation and processing expenses increased 22% to $71.6 million compared to $58.9 million for the same period of 2021, which was primarily related to the same items discussed above.

2527

Exploration Expenses


	Three Months Ended
	March 31, 2023	Per	December 31, 2022	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Exploration	$2,232	$0.25	$2,466	$0.25	($234)	(9	%)	$—	—	%

	Three Months Ended March 31,
		Per		Per	Total Change			Boe Change
	2023	Boe	2022	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Exploration	$2,232	$0.25	$1,885	$0.20	$347	18	%	$0.05	25	%

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,					Three Months Ended				Three Months Ended March 31,
		September 30, 2022		June 30, 2022		2022		2021			March 31, 2023		December 31, 2022		2023		2022
		Amount	Per Boe	Amount	Per Boe	Amount	Per Boe	Amount	Per Boe		Amount	Per Boe	Amount	Per Boe	Amount	Per Boe	Amount	Per Boe
		(In thousands, except per Boe)									(In thousands, except per Boe)
DD&A of evaluated oil and gas properties		$120,562	$12.21	$107,400	$11.72	$328,725	$11.63	$237,030	$9.65
DD&A of proved oil and gas properties										DD&A of proved oil and gas properties	$123,489	$13.75	$132,587	$13.56	$123,489	$13.75	$111,427	$12.06
Depreciation of other property and equipment	Depreciation of other property and equipment	405	0.04	432	0.05	1,313	0.05	1,477	0.06	Depreciation of other property and equipment	390	0.04	372	0.04	390	0.04	476	0.05
Amortization of other assets	Amortization of other assets	822	0.08	598	0.06	2,200	0.08	2,684	0.11	Amortization of other assets	790	0.09	762	0.08	790	0.09	780	0.08
Accretion of asset retirement obligations	Accretion of asset retirement obligations	1,044	0.11	979	0.11	2,983	0.10	2,814	0.12	Accretion of asset retirement obligations	1,296	0.15	1,014	0.10	1,296	0.15	960	0.11
DD&A	DD&A	$122,833	$12.44	$109,409	$11.94	$335,221	$11.86	$244,005	$9.94	DD&A	$125,965	$14.03	$134,735	$13.78	$125,965	$14.03	$113,643	$12.30

~~For the three months ended September 30, 2022,~~The decrease in DD&A ~~increased to $122.8 million from $109.4 million~~ for the three months ended ~~June 30, 2022 primarily attributable~~March 31, 2023 compared to ~~higher capital expenditures during~~ the three months ended ~~September 30, 2022.~~

~~For the nine months ended September 30,~~December 31, 2022 ~~DD&A increased to $335.2 million from $244.0 million for the same period in 2021~~was primarily attributable to a production decrease of 6%.

The increase in DD&A for the three months ended March 31, 2023 compared to the same period in 2022 was primarily attributable to higher proved oil and gas property balances as a result of ~~15% as well as~~ the ~~addition of properties acquired in~~capital expenditures throughout 2022 and the ~~Primexx Acquisition.~~three months ended March 31, 2023.

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


	Three Months Ended
	March 31, 2023	Per	December 31, 2022	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
General and administrative	$27,798	$3.10	$26,511	$2.71	$1,287	5	%	$0.39	14	%

	Three Months Ended March 31,
		Per		Per	Total Change			Boe Change
	2023	Boe	2022	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
General and administrative	$27,798	$3.10	$27,057	$2.93	$741	3	%	$0.17	6	%

The increase in G&A for the three months ended September 30, 2022 increased to $14.0 million compared to $10.9 million for the three months ended June 30, 2022, primarily due to a lower benefit associated with cash settled awards recorded in the third quarter of 2022 as a result of a smaller decrease in the fair value associated with these awards during the three months ended September 30, 2022 asMarch 31, 2023 compared to the three months ended ~~June 30, 2022.~~December 31, 2022 was primarily due to an increase in employee-related costs between the two periods.

The increase in G&A for the ~~nine~~three months ended ~~September 30, 2022 increased to $42.1 million~~March 31, 2023 compared to ~~$37.4 million for~~ the same period in ~~2021,~~2022 was primarily due to an increase in employee-related costs between the two periods, partially offset by a decrease in the fair value of cash settled awards as a result of the decrease in our stock price between the two periods.

Other Income and Expenses

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

Three Months Ended Nine Months Ended September 30,
September 30, 2022 June 30, 2022 Change 2022 2021 Change
(In thousands)
Interest expense on Senior Unsecured Notes $33,224 $29,224 $4,000 $91,470 $78,762 $12,708
Interest expense on Second Lien Notes — 6,633 (6,633) 13,825 34,875 (21,050)
Interest expense on Prior Credit Facility 11,125 7,754 3,371 25,989 23,034 2,955
Amortization of debt issuance costs, premiums and discounts 2,559 3,371 (812) 9,680 14,074 (4,394)
Other interest expense 21 13 8 56 96 (40)
Capitalized interest (27,461) (26,304) (1,157) (79,303) (74,055) (5,248)
Interest expense, net of capitalized amounts $19,468 $20,691 ($1,223) $61,717 $76,786 ($15,069)


	Three Months Ended			Three Months Ended March 31,
	March 31, 2023	December 31, 2022	Change	2023	2022	Change
	(In thousands)
Interest expense on Senior Notes	$33,224	$33,224	$—	$33,224	$29,022	$4,202
Interest expense on second lien notes	—	—	—	—	7,192	(7,192)
Interest expense on Credit Facility	10,447	10,871	(424)	10,447	7,110	3,337
Amortization of debt issuance costs, premiums and discounts	2,631	2,653	(22)	2,631	3,750	(1,119)
Other interest expense	4	24	(20)	4	22	(18)

Interest expense	$46,306	$46,772	($466)	$46,306	$47,096	($790)

Interest ~~expense, net of capitalized amounts, incurred during the three months ended September 30, 2022 decreased $1.2 million to $19.5 million compared to $20.7 million~~expenses for the three months ended ~~June 30, 2022. The decrease is primarily due to the reduction in interest expense and the write-off of the discount associated~~March 31, 2023 was $46.3 million, which was consistent with ~~the redemption of the 6.125% Senior Notes and the Second Lien Notes at the end of the second quarter of 2022 and an increase in capitalized interest compared to~~ the three months ended ~~June 30, 2022, partially offset by an increase in interest expense related to the issuance of the 7.50% Senior Notes in June~~December 31, 2022 and ~~an increase in interest expense on~~ the ~~Prior Credit Facility due to higher interest rates.~~

~~Interest expense, net of capitalized amounts, incurred during the nine~~three months ended September 30, 2022 decreased $15.1 million to $61.7 million compared to $76.8 million for the same period of 2021. The decrease is primarily due to the reduction in interest expense and the write-off of the discount associated with the Second Lien Notes exchange in November 2021 and an increase in capitalized interest, partially offset by an increase in interest expense related to the issuance of the 8.00% Senior Notes in July 2021 and the issuance of the 7.50% Senior Notes in JuneMarch 31, 2022. ~~See “Note 7 - Borrowings” of the Notes to Consolidated Financial Statements in our 2021 Annual Report for further discussion of the Second Lien Notes exchange.~~

(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,			Three Months Ended		Three Months Ended March 31,
		September 30, 2022	June 30, 2022	2022	2021		March 31, 2023	December 31, 2022	2023	2022
		(In thousands)					(In thousands)
(Gain) loss on oil derivatives	(Gain) loss on oil derivatives	($157,731)	$75,910	$243,527	$393,792	(Gain) loss on oil derivatives	($23,344)	$43,852	($23,344)	$325,348
Loss on natural gas derivatives		22,881	5,738	56,800	48,539
(Gain) loss on natural gas derivatives						(Gain) loss on natural gas derivatives	(2,301)	(17,997)	(2,301)	28,181
Loss on NGL derivatives	Loss on NGL derivatives	—	—	4,771	15,114	Loss on NGL derivatives	—	—	—	4,771
Gain on contingent consideration arrangements		—	—	—	(680)
Loss on September 2020 Warrants liability		—	—	—	55,390

(Gain) loss on derivative contracts	(Gain) loss on derivative contracts	($134,850)	$81,648	$305,098	$512,155	(Gain) loss on derivative contracts	($25,645)	$25,855	($25,645)	$358,300

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

Income Tax Expense. We recorded income tax ~~expense~~benefit of ~~$3.5~~$50.7 million and ~~$3.0~~$0.1 million for the three months ended ~~September 30,~~March 31, 2023 and 2022, respectively, and ~~June 30, 2022, respectively. We recorded~~ income tax expense of ~~$7.0 million and $1.0~~$7.3 million for the ~~nine~~three months ended ~~September 30, 2022 and 2021, respectively.~~

~~Since~~December 31, 2022. The income tax benefit for the ~~second quarter~~three months ended March 31, 2023 is a result of ~~2020, we have concluded~~releasing the valuation allowance that ~~it is more likely than not that the~~was in place against our net deferred tax ~~assets will not be realized and have recorded a full valuation allowance against our deferred tax~~ assets. ~~As long as we continue to conclude that the valuation allowance is necessary, we do not expect to have significant deferred income tax expense or benefit.~~ See “Note ~~9 -~~11 — Income Taxes” for further discussion.

Liquidity and Capital Resources

Outlook. Oil prices continue to remain volatile, aswith the average NYMEX benchmark price for oil ~~decreased~~decreasing in the ~~third~~first quarter of ~~2022~~2023 as compared to the prices seen during the ~~first six months~~majority of ~~the year.~~2022. We expect to continue to see volatility in oil prices, as well as natural gas and NGL prices. We also expect to continue to experience inflationary cost pressures in 2023 on many different service items including labor, materials, power and ~~equipment and expect to continue to face inflationary pressure into 2023.~~equipment.

~~2022~~2023 Capital Budget and Funding Strategy. Our primary uses of capital are for the exploration and development of our oil and natural gas properties. Our ~~2022 operational capital budget~~2023 Capital Budget is ~~$830.0 million to $845.0 million,~~$1.0 billion, with over ~~85%~~80% allocated towards development in the Permian with the balance towards development in the Eagle Ford. Because we are the operator of a high percentage of our properties, we can control the well design and the development pace associated with our capital expenditures. ~~Our 2022~~We plan to execute a moderated capital expenditure program ~~was developed to reflect~~through reduced reinvestment rates and ~~balance~~balanced capital deployment for more consistent cash flow generation and to drive capital efficiency through an enhanced multi-zone, scaled development program.

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

Three Months Ended Nine Months Ended
March 31, 2022 June 30, 2022 September 30, 2022 September 30, 2022
(In millions)
Operational capital $157.4 $237.8 $254.6 $649.8
Capitalized interest 25.5 26.3 27.5 79.3
Capitalized G&A 11.6 11.3 12.7 35.6
Total $194.5 $275.4 $294.8 $764.7

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

We believe that existing cash and cash equivalents, 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 non-core asset dispositions. We regularly consider which resources, including cash flows from operations and debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and liquidity requirements. In addition, we may consider divesting certain properties or assets that are not part of

2729

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.

Overview of Cash Flow Activities. ~~For the nine months ended September 30, 2022, cash~~Cash and cash equivalents ~~decreased $5.5~~was $3.4 million ~~to $4.4 million compared to $9.9 million at~~as of both March 31, 2023 and December 31, ~~2021.~~2022.


		Nine Months Ended September 30,			Three Months Ended March 31,
		2022	2021		2023	2022
		(In thousands)			(In thousands)
Net cash provided by operating activities	Net cash provided by operating activities	$1,128,870	$607,833	Net cash provided by operating activities	$247,913	$247,821
Net cash used in investing activities	Net cash used in investing activities	(768,700)	(455,167)	Net cash used in investing activities	(209,909)	(188,490)
Net cash used in financing activities	Net cash used in financing activities	(365,702)	(169,203)	Net cash used in financing activities	(38,029)	(65,063)
Net change in cash and cash equivalents	Net change in cash and cash equivalents	($5,532)	($16,537)	Net change in cash and cash equivalents	($25)	($5,732)

Operating Activities. For the ~~nine~~three months ended ~~September 30, 2022,~~March 31, 2023, net cash provided by operating activities of $247.9 million was ~~$1.1 billion~~effectively flat compared to ~~$607.8 million for~~ the same period in ~~2021.~~2022. The change in net cash provided by operating activities was predominantly attributable to the following:

•~~An increase~~A decrease in revenue primarily driven by a ~~53% increase~~26% decrease in total average realized sales price, as well as a ~~15% increase~~3% decrease in production volumes, ~~and~~largely offset by

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

•An increase in cash inflows of $104.0 million related to timing of working capital payments and receipts.

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

Investing Activities. For the ~~nine~~three months ended ~~September 30, 2022,~~March 31, 2023, net cash used in investing activities was ~~$768.7~~$209.9 million compared to ~~$455.2~~$188.5 million for the same period in ~~2021.~~2022. The increase in net cash used in investing activities was primarily attributable to an increase in operational capital ~~expenditures.~~expenditures, partially offset by 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,~~Credit Facility, term debt and equity offerings. For the ~~nine~~three months ended ~~September 30, 2022,~~March 31, 2023, net cash used in financing activities was ~~$365.7~~$38.0 million compared to ~~$169.2~~$65.1 million for the same period of ~~2021.~~2022. The ~~increase in net cash used in financing activities~~change was primarily attributable to the ~~following:~~

•~~Redemptions~~repayment of approximately $37.7 million on the ~~6.125% Senior Notes and Second Lien Notes, and~~

•~~An offsetting cash inflow due~~Credit Facility during the three months ended March 31, 2023 as compared to repayments of approximately $73.0 million during the ~~issuance of the 7.50% Senior Notes.~~three months ended March 31, 2022.

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

Credit Facility. As of ~~September 30, 2022,~~March 31, 2023, our ~~Prior~~ Credit Facility had a maximum credit amount of $5.0 billion, a borrowing base of $2.0 billion and an elected commitment amount of ~~$1.6~~$1.5 billion, with borrowings outstanding of ~~$636.0~~$465.3 million at a weighted average interest rate of ~~5.30%~~6.87%, and $16.4 million in letters of credit outstanding.

On ~~October 19, 2022, the Company entered into the Credit Agreement, which amended and restated the credit agreement governing the Prior Credit Facility.~~

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

Material Cash Requirements. As of ~~September 30, 2022,~~March 31, 2023, we have financial obligations associated with our outstanding long-term debt, including interest payments and principal repayments. See “Note 7 -— Borrowings” of the Notes to Consolidated Financial Statements in our ~~2021~~2022 Annual Report ~~and “Note 6 - Borrowings” of the Notes to Consolidated Financial Statements in our Form 10-Q for the period ended June 30, 2022~~ for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. Additionally, we have operational obligations associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and transportation service agreements and estimates of future asset retirement obligations. See “Note 14 -— Asset Retirement Obligations” and “Note 17 -— Commitments and Contingencies” of the Notes to Consolidated Financial Statements in our ~~2021~~2022 Annual Report for additional details.

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

•~~Changes~~changes to the borrowings under our ~~credit facility,~~

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

•~~Extended and entered into certain drilling rig contracts with remaining obligations as of September 30, 2022 of approximately $15.0 million and $60.0 million~~Credit Facility. See “Note 8 — Borrowings” for ~~the remainder of 2022 and for 2023, respectively, and~~

•Amended and entered into certain frac service contracts with remaining obligations as of September 30, 2022 of approximately $20.0 million and $175.0 million for the remainder of 2022 and for 2023, respectively.additional information.

Critical Accounting Estimates

The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets, liabilities, revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. Our policies and use of estimates are described in “Note 2 -— Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our ~~2021~~2022 Annual

Report. Except as ~~set forth~~discussed below and in “Note 2 — Summary of Significant Accounting Policies,” of the Notes to Consolidated Financial Statements in this Form 10-Q, there have been no material changes to our critical accounting estimates since December 31, ~~2021,~~2022, which are disclosed in “Part II, Item 7A. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our ~~2021~~2022 Annual ~~Report~~Report.

Recast Financial Information for Change in Accounting Principle

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

Impairment of Oil and Natural Gas Properties

~~The table below presents various pricing scenarios to demonstrate~~We assess our proved oil and gas properties for impairment on an asset group basis whenever events and circumstances indicate that there could be a possible decline in the ~~sensitivity~~recoverability of the net book value of such property. We estimate the expected future net cash flows of our ~~September 30, 2022~~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 ~~center ceiling~~of capital. Fair value estimates are based on projected financial information which we believe to be reasonably likely to occur, as of the date that the impairment is measured. There were no impairments of proved oil and gas properties for the three months ended March 31, 2023 or 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 ~~12-month~~future plans to develop acreage. Unproved oil and gas properties that are not individually significant are aggregated by asset group, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average ~~benchmark crude~~holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data.

Income Taxes

Management monitors company-specific, oil and natural gas ~~prices underlying~~industry and worldwide economic factors and assesses the 12-Month Average Realized Prices. The sensitivity analysis is as of September 30, 2022 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequentlikelihood that our net deferred tax assets will be utilized prior to September 30, 2022 that may require revisions to estimates of proved reserves. See also “Part I, Item 1A. Risk Factors—If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties”their expiration. As previously disclosed in our ~~2021~~2022 Annual ~~Report.~~

12-Month Average
Realized Prices Excess (deficit) of cost center ceiling over net book value, less related deferred income taxes Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes
Full Cost Pool Scenarios Crude Oil
($/Bbl) Natural Gas
($/Mcf) (In millions) (In millions)
September 30, 2022 Actual $92.50 $5.68 $5,400
Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10% $101.67 $6.29 $6,618 $1,218
Crude Oil and Natural Gas -10% $83.33 $5.07 $4,182 ($1,218)
Crude Oil Price Sensitivity
Crude Oil +10% $101.67 $5.68 $6,496 $1,096
Crude Oil -10% $83.33 $5.68 $4,304 ($1,096)
Natural Gas Price Sensitivity
Natural Gas +10% $92.50 $6.29 $5,521 $121
Natural Gas -10% $92.50 $5.07 $5,279 ($121)
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. As of March 31, 2023, 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. This release resulted in a deferred income tax benefit of $52.0 million for the three months ended March 31, 2023. As a result of the release of the valuation allowance, we will have no federal deferred income tax expense for the remainder of 2023.

Recently Adopted and Recently Issued Accounting Standards

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

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

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, 2022~~March 31, 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, 2022:~~March 31, 2023:


		Three Months Ended September 30, 2022				Three Months Ended March 31, 2023
		Oil	Natural Gas	Total		Oil	Natural Gas	Total
		(In thousands)				(In thousands)
Fair value asset (liability) as of September 30, 2022 (1)		($19,821)	$1,557	($18,264)
Fair value asset (liability) as of March 31, 2023 (1)					Fair value asset (liability) as of March 31, 2023 (1)	$1,956	$11,601	$13,557

Impact of a 10% increase in forward commodity prices	Impact of a 10% increase in forward commodity prices	($84,841)	($1,631)	($86,472)	Impact of a 10% increase in forward commodity prices	($22,160)	$10,851	($11,309)
Impact of a 10% decrease in forward commodity prices	Impact of a 10% decrease in forward commodity prices	$42,564	$4,649	$47,213	Impact of a 10% decrease in forward commodity prices	$15,637	$12,402	$28,039

(1)Spot prices for oil and natural gas were ~~$79.23~~$75.71 and ~~$6.77,~~$2.22, respectively, as of ~~September 30, 2022~~.March 31, 2023.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our ~~credit facility.~~Credit Facility. As of ~~September 30, 2022,~~March 31, 2023, we had ~~$636.0~~$465.3 million outstanding under the ~~Prior~~ Credit Facility with a weighted average interest rate of ~~5.30%~~6.87%. 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 ~~$6.4~~$4.7 million, based on the balance outstanding as of ~~September 30, 2022.~~March 31, 2023. See “Note ~~6 -~~8 — Borrowings” for more information on our ~~Prior Credit Facility and~~ Credit Facility.

Item 4. Controls and Procedures

Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our management, with the participation of the Chief Executive Officer and Chief Financial Officer, 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, 2022.~~March 31, 2023.

Changes in Internal Control Over Financial Reporting. In the quarter ended March 31, 2023, Callon modified certain policies, procedures, and related internal controls that were impacted by the change in accounting principle from the full cost method to the successful efforts method of accounting. There ~~were~~was no ~~changes~~other change in our internal ~~control~~controls over financial reporting (as such term is defined in ~~Rule~~Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the ~~third~~first quarter of ~~2022~~2023 that ~~have~~has materially affected, or ~~are~~is reasonably likely to materially affect, ~~the Company’s~~our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

The following exhibits are filed as part of this Form 10-Q.
Incorporated by reference (File No. 001-14039, unless otherwise indicated)
Exhibit Number Description Form Exhibit Filing Date
3.1
Certificate of Incorporation of the Company, as amended through May 12, 2016
10-Q 3.1 11/3/2016
3.2
Certificate of Amendment to the Certificate of Incorporation of Callon, effective December 20, 2019
8-K 3.1 12/20/2019
3.3
Certificate of Amendment to the Certificate of Incorporation of Callon, effective August 7, 2020
8-K 3.1 8/7/2020
3.4
Certificate of Amendment to the Certificate of Incorporation of Callon, effective May 14, 2021
8-K 3.1 5/14/2021
3.5
Certificate of Amendment to the Certificate of Incorporation of Callon, effective May 25, 2022
8-K 3.1 5/25/2022
3.6
Amended and Restated Bylaws of the Company
10-K 3.2 2/27/2019
10.1 (a)(c)
Callon Petroleum Company Executive Severance Pay Plan
10.2 (a)(c)
Callon Executive Change in Control Severance Compensation Plan
10.3 (a)(c)
Form of Amendment , adopted on September 21, 2022, to Callon Petroleum Company Cash Performance Unit Award Agreement , originally adopted on March 12, 2021 under the 2020 Omnibus Incentive Plan
10.4 (a)(c)
Form of Amendment , adopted on September 21, 2022, to Callon Petroleum Company Returns Program Cash Incentive Award Agreement , orig inally ado pted on March 9, 2022 under the 2020 Omnibus Incentive Plan
10.5 (a)(c)
Form of Amendment , adopted on September 21, 2022, to Callon Petroleum Company Bus iness Sustainability Cash Incentive Award Agreement , originally adopted on March 9, 2022 under the 2020 Omnibus Ince nti ve Plan
31.1 (a)
Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)
31.2 (a)
Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)
32.1 (b)
Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b)
101.INS (a) XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH (a) Inline XBRL Taxonomy Extension Schema Document
101.CAL (a) Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF (a) Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB (a) Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE (a) Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104 (a) Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

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

Exhibit Number

Description

Form

Exhibit

Filing Date

3.1

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

10-Q

3.1

11/3/2016

3.2

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

8-K

3.1

12/20/2019

3.3

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

8-K

3.1

8/7/2020

3.4

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

8-K

3.1

5/14/2021

3.5

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

8-K

3.1

5/25/2022

3.6

Amended and Restated Bylaws of the Company

10-K

3.2

2/27/2019

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)Indicates management compensatory plan, contract, or arrangement.~~

3133

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~~May 3, ~~2022~~2023
Joseph C. Gatto, Jr.	Chief Executive Officer


/s/ Kevin Haggard	Senior Vice President and	~~November~~May 3, ~~2022~~2023
Kevin Haggard	Chief Financial Officer

3234


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			2123

Item 3. Quantitative and Qualitative Disclosures about Market Risk			2931

Item 4. Controls and Procedures			3032

Part II. Other Information

Item 1. Legal Proceedings			3032

Item 1A. Risk Factors			3032

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			3032

Item 3. Defaults Upon Senior Securities			3032

Item 4. Mine Safety Disclosures			3132

Item 5. Other Information			3133

Item 6. Exhibits			3133


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

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

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


	Three Months Ended			Nine Months Ended
	March 31, 2022	June 30, 2022	September 30, 2022	September 30, 2022
	(In millions)
Operational capital	$157.4	$237.8	$254.6	$649.8
Capitalized interest	25.5	26.3	27.5	79.3
Capitalized G&A	11.6	11.3	12.7	35.6
Total	$194.5	$275.4	$294.8	$764.7


	12-Month Average Realized Prices		Excess (deficit) of cost center ceiling over net book value, less related deferred income taxes	Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes
Full Cost Pool Scenarios	Crude Oil ($/Bbl)	Natural Gas ($/Mcf)	(In millions)	(In millions)
September 30, 2022 Actual	$92.50	$5.68	$5,400

Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$101.67	$6.29	$6,618	$1,218
Crude Oil and Natural Gas -10%	$83.33	$5.07	$4,182	($1,218)

Crude Oil Price Sensitivity
Crude Oil +10%	$101.67	$5.68	$6,496	$1,096
Crude Oil -10%	$83.33	$5.68	$4,304	($1,096)

Natural Gas Price Sensitivity
Natural Gas +10%	$92.50	$6.29	$5,521	$121
Natural Gas -10%	$92.50	$5.07	$5,279	($121)