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~~the quarterly period ended March 31, ~~2021~~2022

☐ 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 ~~46,264,870~~61,689,752 shares of common stock outstanding as of April ~~30, 2021.~~29, 2022.

For certain industry specific terms used in this Form 10-Q, please see “Glossary of Certain Terms” in our 2021 Annual Report on Form 10-K

Table of Contents

~~GLOSSARY OF CERTAIN TERMS~~

~~All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document:~~

•~~ASU: accounting standards update.~~

•~~Bbl: barrel or barrels of oil or natural gas liquids.~~

•~~Boe~~: barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas. The ratio of one barrel of oil or NGLs to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.

•~~Boe/d: Boe per day.~~

•~~Btu: a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.~~

•~~Completion~~: the process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

•~~Cushing: an oil delivery point that serves as the benchmark oil price for West Texas Intermediate.~~

•~~FASB: Financial Accounting Standards Board.~~

•~~GAAP: Generally Accepted Accounting Principles in the United States.~~

•~~Henry Hub: a natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.~~

•~~Horizontal drilling: a drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval.~~

•~~LOE: lease operating expense.~~

•~~MBbls: thousand barrels of oil.~~

•~~MBoe: thousand Boe.~~

•~~Mcf: thousand cubic feet of natural gas.~~

•~~MEH: Magellan East Houston, a delivery point in Houston, Texas that serves as a benchmark for crude oil.~~

•~~MMBoe: million Boe.~~

•~~MMBtu: million Btu.~~

•~~MMcf: million cubic feet of natural gas.~~

•~~NGL or NGLs: natural gas liquids, such as ethane, propane, butane and natural gasoline that are extracted from natural gas production streams.~~

•~~NYMEX: New York Mercantile Exchange.~~

•~~Oil: includes crude oil and condensate.~~

•~~OPEC: Organization of Petroleum Exporting Countries.~~

•~~Proved reserves~~: Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

~~The area of the reservoir considered as proved includes all of the following:~~

a.~~The area identified by drilling and limited by fluid contacts, if any, and~~

b.Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:

a.Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and

b.~~The project has been approved for development by all necessary parties and entities, including governmental entities.~~

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

•~~Realized price: the cash market price less all expected quality, transportation and demand adjustments.~~

•~~RSU: restricted stock units.~~

•~~SEC: United States Securities and Exchange Commission.~~

•~~Waha: a delivery point in West Texas that serves as the benchmark for natural gas.~~

•~~Working interest~~: an operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

•~~WTI: West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.~~

With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.

Part I. Financial Information

Item 1. Financial Statements

Callon Petroleum Company

Consolidated Balance Sheets

(In thousands, except par and share amounts)

(Unaudited)

March 31, 2021 December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents $24,350 $20,236
Accounts receivable, net 179,127 133,109
Other current assets 32,878 25,024
Total current assets 236,355 178,369
Oil and natural gas properties, full cost accounting method:
Evaluated properties, net 2,394,339 2,355,710
Unevaluated properties 1,754,768 1,733,250
Total oil and natural gas properties, net 4,149,107 4,088,960
Other property and equipment, net 31,435 31,640
Deferred financing costs 22,177 23,643
Other assets, net 37,792 40,256
Total assets $4,476,866 $4,362,868
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities $374,749 $341,519
Fair value of derivatives 224,446 97,060
Other current liabilities 72,854 58,529
Total current liabilities 672,049 497,108
Long-term debt 2,937,239 2,969,264
Asset retirement obligations 55,935 57,209
Fair value of derivatives 1,400 88,046
Other long-term liabilities 42,221 40,239
Total liabilities 3,708,844 3,651,866
Commitments and contingencies 0 0
Stockholders’ equity:
Common stock, $0.01 par value, 52,500,000 shares authorized; 46,156,854 and 39,758,817 shares outstanding, respectively 462 398
Capital in excess of par value 3,360,322 3,222,959
Accumulated deficit (2,592,762) (2,512,355)
Total stockholders’ equity 768,022 711,002
Total liabilities and stockholders’ equity $4,476,866 $4,362,868


	March 31, 2022	December 31, 2021
ASSETS
Current assets:
Cash and cash equivalents	$4,150	$9,882
Accounts receivable, net	347,593	232,436
Fair value of derivatives	—	22,381
Other current assets	33,249	30,745
Total current assets	384,992	295,444
Oil and natural gas properties, full cost accounting method:


Evaluated properties, net	3,426,156	3,352,821
Unevaluated properties	1,847,790	1,812,827
Total oil and natural gas properties, net	5,273,946	5,165,648

Other property and equipment, net	28,985	28,128

Deferred financing costs	16,543	18,125

Other assets, net	41,054	40,158
Total assets	$5,745,520	$5,547,503
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$516,440	$569,991


Fair value of derivatives	392,928	185,977
Other current liabilities	163,936	116,523
Total current liabilities	1,073,304	872,491
Long-term debt	2,623,282	2,694,115

Asset retirement obligations	55,160	54,458

Fair value of derivatives	34,434	11,409
Other long-term liabilities	44,750	49,262
Total liabilities	3,830,930	3,681,735
Commitments and contingencies	0	0
Stockholders’ equity:

Common stock, $0.01 par value, 78,750,000 shares authorized; 61,493,753 and 61,370,684 shares outstanding, respectively	615	614
Capital in excess of par value	4,021,442	4,012,358
Accumulated deficit	(2,107,467)	(2,147,204)
Total stockholders’ equity	1,914,590	1,865,768
Total liabilities and stockholders’ equity	$5,745,520	$5,547,503

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 March 31,
2021 2020
Operating Revenues:
Oil $267,045 $265,767
Natural gas 24,220 6,029
Natural gas liquids 29,357 18,123
Sales of purchased oil and gas 39,259 0
Total operating revenues 359,881 289,919
Operating Expenses:
Lease operating 40,453 52,383
Production and ad valorem taxes 18,439 19,680
Gathering, transportation and processing 17,981 14,378
Cost of purchased oil and gas 40,917 0
Depreciation, depletion and amortization 70,987 131,463
General and administrative 16,799 8,325
Merger and integration 0 15,830
Other operating 929 0
Total operating expenses 206,505 242,059
Income From Operations 153,376 47,860
Other (Income) Expenses:
Interest expense, net of capitalized amounts 24,416 20,478
(Gain) loss on derivative contracts 214,523 (251,969)
Other (income) expense (4,235) (1,262)
Total other (income) expense 234,704 (232,753)
Income (Loss) Before Income Taxes (81,328) 280,613
Income tax benefit (expense) 921 (64,048)
Net Income (Loss) ($80,407) $216,565
Net Income (Loss) Per Common Share (1):

Basic ($1.89) $5.46
Diluted ($1.89) $5.46
Weighted Average Common Shares Outstanding (1):

Basic 42,590 39,667
Diluted 42,590 39,684


	Three Months Ended March 31,
	2022	2021
Operating Revenues:
Oil	$553,249	$267,045
Natural gas	43,976	24,220
Natural gas liquids	67,618	29,357
Sales of purchased oil and gas	112,375	39,259
Total operating revenues	777,218	359,881

Operating Expenses:
Lease operating	67,328	40,453
Production and ad valorem taxes	37,678	18,439
Gathering, transportation and processing	20,775	17,981
Cost of purchased oil and gas	111,271	40,917
Depreciation, depletion and amortization	102,979	70,987
General and administrative	17,121	16,799

Merger, integration and transaction	769	—


Total operating expenses	357,921	205,576
Income From Operations	419,297	154,305

Other (Income) Expenses:
Interest expense, net of capitalized amounts	21,558	24,416
Loss on derivative contracts	358,300	214,523

Other income	(782)	(3,306)
Total other expense	379,076	235,633

Income (Loss) Before Income Taxes	40,221	(81,328)
Income tax benefit (expense)	(484)	921
Net Income (Loss)	$39,737	($80,407)

Net Income (Loss) Per Common Share:
Basic	$0.65	($1.89)
Diluted	$0.64	($1.89)

Weighted Average Common Shares Outstanding:
Basic	61,487	42,590
Diluted	62,065	42,590

~~(1) All share and per share amounts have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 10 -~~The accompanying notes are an integral part of these consolidated financial statements.

Callon Petroleum Company

Consolidated Statements of Stockholders’ ~~Equity” for additional information.~~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	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


	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	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

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

Callon Petroleum Company

Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)


	Three Months Ended March 31,
Cash flows from operating activities:	2022	2021
Net income (loss)	$39,737	($80,407)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	102,979	70,987

Amortization of non-cash debt related items, net	1,716	2,256

Loss on derivative contracts	358,300	214,523
Cash paid for commodity derivative settlements, net	(101,525)	(42,162)



Non-cash expense related to share-based awards	4,166	7,608


Other, net	2,894	1,217
Changes in current assets and liabilities:
Accounts receivable	(116,322)	(45,683)
Other current assets	(4,180)	(2,856)
Accounts payable and accrued liabilities	(12,987)	12,182
Cash received for settlements of contingent consideration arrangements, net	6,492	—

Net cash provided by operating activities	281,270	137,665
Cash flows from investing activities:
Capital expenditures	(201,478)	(101,341)
Acquisition of oil and gas properties	(9,409)	(768)

Proceeds from sales of assets	4,484	—
Cash paid for settlement of contingent consideration arrangement	(19,171)	—
Other, net	3,635	3,595
Net cash used in investing activities	(221,939)	(98,514)
Cash flows from financing activities:
Borrowings on Credit Facility	673,000	303,000
Payments on Credit Facility	(746,000)	(338,000)






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






Other, net	(575)	(37)
Net cash used in financing activities	(65,063)	(35,037)
Net change in cash and cash equivalents	(5,732)	4,114
Balance, beginning of period	9,882	20,236
Balance, end of period	$4,150	$24,350

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, 2020 39,759 $398 $3,222,959 ($2,512,355) $711,002
Net loss — — — (80,407) (80,407)
Restricted stock 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

Common Capital in Total
Stock Excess Retained Stockholders’
Shares (1)
$ of Par Earnings Equity
Balance at December 31, 2019 39,659 $3,966 $3,198,076 $21,266 $3,223,308
Net income — — — 216,565 216,565
Restricted stock 14 1 3,141 — 3,142
Other — — (112) — (112)
Balance at March 31, 2020 39,673 $3,967 $3,201,105 $237,831 $3,442,903

~~(1) All share amounts have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 10~~ ~~- Stockholders’ Equity” 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)~~

Three Months Ended March 31,
Cash flows from operating activities: 2021 2020
Net income (loss) ($80,407) $216,565
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 70,987 131,463
Amortization of non-cash debt related items, net 2,256 407
Deferred income tax expense 0 64,048
(Gain) loss on derivative contracts 214,523 (251,969)
Cash received (paid) for commodity derivative settlements, net (42,162) 2,613
Non-cash expense (benefit) related to share-based awards 7,608 (2,972)
Other, net 1,217 136
Changes in current assets and liabilities:
Accounts receivable (45,683) 115,873
Other current assets (2,856) (781)
Accounts payable and accrued liabilities 12,182 (83,688)
Net cash provided by operating activities 137,665 191,695
Cash flows from investing activities:
Capital expenditures (101,341) (213,459)
Acquisition of oil and gas properties (768) (10,989)
Proceeds from sale of assets 0 10,240
Cash paid for settlements of contingent consideration arrangements, net 0 (40,000)
Other, net 3,595 (158)
Net cash used in investing activities (98,514) (254,366)
Cash flows from financing activities:
Borrowings on Credit Facility 303,000 4,291,000
Payments on Credit Facility (338,000) (4,226,000)
Other, net (37) (870)
Net cash provided by (used in) financing activities (35,037) 64,130
Net change in cash and cash equivalents 4,114 1,459
Balance, beginning of period 20,236 13,341
Balance, end of period $24,350 $14,800

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

Index to the Notes to the Consolidated Financial Statements

1.
Description of Business and Basis of Presentation
8.
Income Taxes
2.
Revenue Recognition
9. Share-based Compensation
3. Property and Equipment, Net 10. Stockholders’ Equity
4.
Earnings Per Share
11. Accounts Receivable, Net
5.
Borrowings
12. Accounts Payable and Accrued Liabilities
6.
Derivative Instruments and Hedging Activities
13. Supplemental Cash Flow
7.
Fair Value Measurements
14. Subsequent Events


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

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.~~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~~flow-generating business in the Eagle Ford.

Basis of Presentation

The accompanying unaudited interim consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and ~~balances 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 ~~U.S.~~ GAAP. In the opinion of management, these financial statements ~~include~~reflect all ~~adjustments (consisting of~~ normal, recurring adjustments and accruals ~~and adjustments)~~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 2.2 - Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, ~~2020~~2021 (“~~2020~~2021 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 should be read in conjunction with the Company’s ~~2020~~2021 Annual Report.

Recently Adopted Accounting Standards

~~Income Taxes.~~Debt. In ~~December 2019,~~August 2020, the FASB ~~released~~issued ASU No. ~~2019-12~~2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU ~~2019-12”~~2020-06”), Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes, which removes certain exceptions for recognizing deferred taxes for investments, performing intraperiod allocation and calculating income taxes in interim periods. The. ASU ~~also adds guidance~~2020-06 was issued to reduce the complexity inassociated with accounting for certain ~~areas, including recognizing deferred taxes for tax goodwill~~financial instruments with characteristics of liabilities and ~~allocating taxes~~equity. The guidance is to ~~members of~~be applied using either a ~~consolidated group. The amended standard~~modified retrospective or a fully retrospective method. ASU 2020-06 is effective for fiscal years beginning after December 15, ~~2020,~~2021, with early adoption permitted. The Company adopted ASU ~~2019-12~~2020-06 on January 1, ~~2021.~~2022. The adoption of ASU ~~2019-12~~2020-06 did not have a material impact to the Company’s consolidated financial statements or disclosures.

Recently Issued Accounting ~~Pronouncements~~Standards

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed 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 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. In April 2022, the FASB proposed to defer the effective date from December 31, 2022 to December 31, 2024, however a final ruling has not been issued. As of March 31, ~~2021,~~2022, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to “Note 56 –

Borrowings” for discussion of the use of the adjusted LIBO rate in connection with borrowings under the Company’s senior secured revolving credit facility.

In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion 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 the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The guidance is to be applied using either a modified retrospective or a fully retrospective method. ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. As of March 31, 2021, the Company has not elected to early adopt and is evaluating the impact on the Company’s accompanying consolidated financial statements and related disclosures.

Subsequent Events

The Company evaluates subsequent events through the date the financial statements are issued. See “Note 1415 - Subsequent Events” for further discussion.

Note 2 - Revenue Recognition

Revenue from ~~contracts~~Contracts with ~~customers~~Customers

~~Oil sales~~

~~Under the Company’s~~The Company recognizes oil, ~~sales contracts it sells oil~~natural gas, and NGL production revenue at the point ~~of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue~~in time when control of the product transfers to the purchaser, atwhich differs depending on the ~~point~~applicable contractual terms. Transfer of ~~delivery at~~control also drives the ~~net price received. The Company has certain oil sales that occur at market locations downstream~~presentation of the production area. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees and other deductions incurred prior to control transfer as “Gathering,gathering, transportation and ~~processing”~~processing in ~~its~~the consolidated statements of operations.

~~Natural~~ See “Note 3 - Revenue Recognition” of the Notes to Consolidated Financial Statements in the 2021 Annual Report for more information regarding the types of contracts under which oil, natural gas, and NGL ~~sales~~

Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity which gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of NGLs and residue gas. The Company evaluates whether the processing entityproduction revenue is the principal or the agent in the transaction for each of the Company’s natural gas processing agreements and have concluded that the Company maintains control through processing or the Company has the right to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. The Company recognizes revenue when control transfers to the purchaser at the delivery point based on the contractual index price received.

The Company recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and processing” in its consolidated statements of operations as the Company maintains control throughout processing.

~~Oil and gas purchase and sale arrangements~~

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.generated.

Accounts ~~receivable~~Receivable from ~~revenues~~Revenues from ~~contracts~~Contracts with ~~customers~~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 March 31, ~~2021~~2022 and December 31, ~~2020~~2021 of ~~$125.6~~$262.4 million and ~~$100.3~~$171.8 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets.

~~Transaction price allocated to remaining performance obligations~~

For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Prior ~~period performance obligations~~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 - 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, as defined below. 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, 50% of the shares held in escrow were released six months after the closing date, which was on April 1, 2022, and the remaining shares will be released twelve months after the closing date, which will be on October 1, 2022, in each case subject to holdback for the satisfaction of any applicable indemnification claims that may be made under the Primexx PSAs.

Also, pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration structured similarly to the Primexx Acquisition, for an incremental purchase price totaling approximately $33.1 million, net of customary purchase price adjustments, of which $10.7 million closed during the first quarter of 2022.

The Primexx Acquisition was accounted for as a business combination; therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a

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

The following table sets forth the Company’s preliminary allocation of the total estimated consideration of $914.0 million to the assets acquired and liabilities assumed as of the acquisition date.


						Preliminary Purchase Price Allocation
						(In thousands)
Assets:
Other current assets						$10,250
Evaluated oil and natural gas properties						686,393
Unevaluated properties						278,602
Total assets acquired						$975,245

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

Total consideration						$913,993

Approximately $138.1 million of revenues and $28.8 million of direct operating expenses attributed to the Primexx Acquisition are included in the Company’s consolidated statements of operations for the three months ended March 31, 2022.

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 $181.8 million, subject to post-closing adjustments. The aggregate net proceeds for each of the 2021 divestitures were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves. For additional discussion, see “Note 4 - Acquisitions and Divestitures” of the Notes to Consolidated Financial Statements in the 2021 Annual Report.

Note 34 - Property and Equipment, Net

As of March 31, ~~2021~~2022 and December 31, ~~2020,~~2021, total property and equipment, net consisted of the following:


		March 31, 2021	December 31, 2020		March 31, 2022	December 31, 2021
Oil and natural gas properties, full cost accounting method	Oil and natural gas properties, full cost accounting method	(In thousands)		Oil and natural gas properties, full cost accounting method	(In thousands)
Evaluated properties	Evaluated properties	$8,001,847	$7,894,513	Evaluated properties	$9,412,921	$9,238,823
Accumulated depreciation, depletion, amortization and impairments	Accumulated depreciation, depletion, amortization and impairments	(5,607,508)	(5,538,803)	Accumulated depreciation, depletion, amortization and impairments	(5,986,765)	(5,886,002)
Evaluated properties, net	Evaluated properties, net	2,394,339	2,355,710	Evaluated properties, net	3,426,156	3,352,821
Unevaluated properties	Unevaluated properties			Unevaluated properties
Unevaluated leasehold and seismic costs	Unevaluated leasehold and seismic costs	1,530,897	1,532,304	Unevaluated leasehold and seismic costs	1,567,076	1,557,453
Capitalized interest	Capitalized interest	223,871	200,946	Capitalized interest	280,714	255,374
Total unevaluated properties	Total unevaluated properties	1,754,768	1,733,250	Total unevaluated properties	1,847,790	1,812,827
Total oil and natural gas properties, net	Total oil and natural gas properties, net	$4,149,107	$4,088,960	Total oil and natural gas properties, net	$5,273,946	$5,165,648

Other property and equipment	Other property and equipment	$60,388	$60,287	Other property and equipment	$59,428	$58,367
Accumulated depreciation	Accumulated depreciation	(28,953)	(28,647)	Accumulated depreciation	(30,443)	(30,239)
Other property and equipment, net	Other property and equipment, net	$31,435	$31,640	Other property and equipment, net	$28,985	$28,128

The Company capitalized internal costs of employee compensation and benefits, including share-based compensation, directly associated with acquisition, exploration and development activities totaling ~~$11.2~~$11.6 million and ~~$7.5~~$11.2 million for the three months ended March 31, 2022 and 2021, ~~and 2020,~~ respectively.

The Company capitalized interest costs to unproved properties totaling $25.5 million and $24.0 million ~~for both the three months ended March 31, 2021 and 2020.~~

~~Impairment of Evaluated Oil and Gas Properties~~

For the three months ended March 31, 2021, the capitalized costs of oil and gas properties did not exceed the cost center ceiling. As a result, the Company did not recognize an impairment in the carrying value of evaluated oil and gas properties for the three months ended March 31, ~~2021. The Company also did 0t recognize an impairment of evaluated oil~~2022 and ~~gas properties for the three months ended March 31, 2020.~~2021, respectively.

Details of the average realized prices for sales of oil on the first calendar day of each month during the trailing 12-month period (“12-Month Average Realized Price”) of crude oil for the three months ended March 31, 2021 and 2020 are summarized in the table below:

Three Months Ended March 31,
2021 2020
Impairment of evaluated oil and gas properties (in thousands) $0 $0
Beginning of period 12-Month Average Realized Price ($/Bbl) $37.44 $53.90
End of period 12-Month Average Realized Price ($/Bbl) $37.51 $54.63
Percent increase in 12-Month Average Realized Price 0 % 1 %

The Company does not expect to record an impairment in the carrying value of evaluated oil and gas properties in the second quarter of 2021 based on an estimated 12-Month Average Realized Price of crude oil of approximately $49.35 per Bbl as of June 30, 2021, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 10 months and an estimate for the eleventh and twelfth months based on a quoted forward price. Declines in the 12-Month Average Realized Price of crude oil in subsequent quarters could result in a lower present value of the estimated future net revenues from proved oil and gas reserves and may result in impairments of evaluated oil and gas properties.

Note 45 - 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 ~~shares~~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, 2021, 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 March 31,
2021 2020
(In thousands, except per share amounts)
Net Income (Loss) ($80,407) $216,565
Basic weighted average common shares outstanding (1)
42,590 39,667
Dilutive impact of restricted stock (1)
0 17
Dilutive impact of warrants (1)
0 0
Diluted weighted average common shares outstanding (1)
42,590 39,684

Net Income (Loss) Per Common Share (1)
Basic ($1.89) $5.46
Diluted ($1.89) $5.46

Restricted stock (1)(2)
702 337
Warrants (1)(2)
5,826 481


	Three Months Ended March 31,
	2022	2021
	(In thousands, except per share amounts)



Net Income (Loss)	$39,737	($80,407)
Basic weighted average common shares outstanding	61,487	42,590
Dilutive impact of restricted stock units	578	—

Diluted weighted average common shares outstanding	62,065	42,590

Net Income (Loss) Per Common Share
Basic	$0.65	($1.89)
Diluted	$0.64	($1.89)

Restricted stock units (1)	3	702
Warrants (1)	327	5,826

(1) Shares and per share data have been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 10 - Stockholders’ Equity” for additional information.

~~(2)~~ Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

Note 56 - Borrowings

The Company’s borrowings consisted of the following:

March 31, 2021 December 31, 2020
(In thousands)
Senior Secured Revolving Credit Facility due 2024 $950,000 $985,000
9.00% Second Lien Senior Secured Notes due 2025 516,659 516,659
6.25% Senior Notes due 2023 542,720 542,720
6.125% Senior Notes due 2024 460,241 460,241
8.25% Senior Notes due 2025 187,238 187,238
6.375% Senior Notes due 2026 320,783 320,783
Total principal outstanding 2,977,641 3,012,641
Unamortized discount on Second Lien Notes (39,006) (41,820)
Unamortized premium on 6.25% Senior Notes 2,688 2,917
Unamortized premium on 6.125% Senior Notes 3,020 3,236
Unamortized premium on 8.25% Senior Notes 3,050 3,240
Unamortized deferred financing costs for Second Lien Notes (3,662) (3,931)
Unamortized deferred financing costs for Senior Notes (6,492) (7,019)
Total carrying value of borrowings (1)
$2,937,239 $2,969,264


	March 31, 2022	December 31, 2021
	(In thousands)
6.125% Senior Notes due 2024	$460,241	$460,241
Senior Secured Revolving Credit Facility due 2024	712,000	785,000
9.00% Second Lien Senior Secured Notes due 2025	319,659	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
Total principal outstanding	2,649,921	2,722,921
Unamortized premium on 6.125% Senior Notes	2,157	2,373
Unamortized discount on 9.00% Second Lien Senior Secured Notes	(13,591)	(14,852)
Unamortized premium on 8.25% Senior Notes	2,287	2,477
Unamortized deferred financing costs for Second Lien Notes	(2,663)	(2,910)
Unamortized deferred financing costs for Senior Notes	(14,829)	(15,894)
Total carrying value of borrowings (1)	$2,623,282	$2,694,115

(1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of ~~$22.2~~$16.5 million and ~~$23.6~~$18.1 million as of March 31, ~~2021~~2022 and December 31, ~~2020,~~2021, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets.

Senior ~~secured revolving credit facility~~Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility with a syndicate of lenders (the “Credit Facility”) that, as of March 31, ~~2021,~~2022, had a maximum credit amount of $5.0 billion, a borrowing base and elected commitment amount of $1.6 billion, with borrowings outstanding of ~~$950.0~~$712.0 million at a

weighted-average interest rate of ~~2.62%~~2.74%, and letters of credit outstanding of ~~$24.0~~$23.0 million. The credit agreement governing the Credit Facility provides for interest-only payments until December 20, 2024 ~~(subject~~when the credit agreement matures and any outstanding borrowings are due. The Credit Facility is subject to specified springing maturity dates ~~of (i) January 14, 2023~~ if the 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”) are outstanding at such time, (ii) July 2, 2024 if the 6.125% Senior Notes due 2024 (the “6.125% Senior Notes”) are outstanding at such time, and (iii) ifmore than $100.0 million principal amount of the 9.00% Second Lien Senior Secured Notes due 2025 (the “Second Lien Notes”) ~~are outstanding at such time, the date which is 182 days prior to the maturity of any of the 6.25% Senior Notes or the~~and 6.125% Senior Notes ~~in each case, to~~are outstanding. The Credit Facility is secured by first preferred mortgages covering the ~~extent a principal amount of more than $100.0 million with respect to each such issuance is outstanding as of such date), when the credit agreement matures and any outstanding borrowings are due.~~ Company’s major producing properties.

The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. ~~The Credit Facility is secured by first preferred mortgages covering~~On May 2, 2022, as part of the Company’s ~~major producing properties. The capitalized terms which are not defined in this description of the Credit Facility shall have the meaning given to such terms in the credit agreement.~~

~~On May 3, 2021, the Company entered into the fourth amendment to its credit agreement governing the Credit Facility which, among other things, reaffirmed~~spring 2022 redetermination, the borrowing base and elected commitment amount of $1.6 billion ~~as a result of the spring 2021 scheduled redetermination. See “Note 14 - Subsequent Events” for further discussion.~~were reaffirmed.

Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 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.

~~Restrictive covenants~~Covenants

The Company’s credit agreement ~~contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios.~~

Under the credit agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter: (1) a Secured Leverage Ratio of no more than 3.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. The Company was in compliance with these covenants at March 31, 2021.

~~The credit agreement and the indentures~~ governing the ~~Company’s 6.25% Senior Notes,~~Credit Facility, the 6.125% Senior Notes, the 8.25% Senior Notes, ~~due 2025, and~~the 6.375% Senior Notes ~~due 2026 (together~~and the 8.00% Senior Notes (collectively, the “Senior Unsecured Notes”) ~~also place restrictions on~~and the Second Lien 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.~~matters, along with maintenance of certain financial ratios.

Under the credit agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter: (1) a Leverage Ratio (as defined in the credit agreement governing the Credit Facility) of no more than 4.00 to 1.00 and (2) a Current Ratio (as defined in the credit agreement governing the Credit Facility) of not less than 1.00 to 1.00. The Company was in compliance with these covenants at March 31, 2022.

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

Note 67 - Derivative Instruments and Hedging Activities

Objectives and ~~strategies~~Strategies for ~~using derivative instruments~~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 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~~Risk and ~~offsetting~~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 (“ISDA 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 March 31, ~~2021,~~2022, the Company has outstanding commodity derivative instruments with 1510 counterparties to minimize its credit exposure to any individual counterparty. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s credit agreement. 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, 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 78 - Fair Value Measurements” for further discussion.

~~Financial statement presentation~~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 ~~settlements~~

~~Settlements~~Hedging Activities” of the ~~Company’s commodity derivative instruments are based on the difference between the contract price~~Notes to Consolidated Financial Statements in its 2021 Annual Report. Cash received or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “Note 7 - Fair Value Measurements” for additional information regarding fair value.

~~Contingent consideration arrangements~~

~~Ranger Divestiture.~~ In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Divestiture”). The Company’s Ranger Divestiture provided for potential contingent consideration to be received by the Company if commodity prices exceed specified thresholds. See “Note 7 - Fair Value Measurements” for further discussion. This contingent consideration arrangement is summarized in the table below (in thousands except for per Bbl amounts):

Year
Threshold (1)
Contingent Receipt - Annual
Threshold (1)
Contingent Receipt - Annual Period Cash Flow Occurs Statement of Cash Flows Presentation Remaining Contingent Receipt - Aggregate Limit
Remaining Potential Settlement 2021 Greater than $60/Bbl, less than $65/Bbl $9,000 Equal to or greater than $65/Bbl $20,833 (2) (2) $20,833

(1) The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group.

~~(2) Cash received~~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. ~~If either~~As a result, the Company received $20.8 million, of ~~the commodity price thresholds is reached in 2021,~~which $8.5 million ~~of the contingent receipt will be~~is presented in cash flows from financing activities with the ~~remainder~~remaining $12.3 million presented in cash flows from operating ~~activities.~~

~~As a result~~activities, and paid $25.0 million, of the acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”) in late 2019 (the “Carrizo Acquisition”), the Company assumed all contingent consideration arrangements previously entered into by Carrizo. Only one of the contingent consideration arrangements remain and is summarized below:

~~Contingent ExL Consideration~~

Year
Threshold (1)
Period
Cash Flow
Occurs Statement of
Cash Flows Presentation Contingent
Payment -
Annual Remaining Contingent
Payments -
Aggregate Limit
(In thousands)
Remaining Potential Settlement 2021 $50.00 (2) (2) ($25,000) ($25,000)

(1) The price used to determine whether the specified threshold for the year has been met is the average daily settlement price of the front month NYMEX WTI futures contract as published by the CME Group.

(2) Cash paid for settlements of contingent consideration arrangements are classified as cash flows from investing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. If the commodity price threshold is reached in 2021,which $19.2 million ~~of the contingent payment will be~~is presented in cash flows from investing activities with the ~~remainder~~remaining $5.8 million presented in cash flows from operating ~~activities.~~

~~Warrants~~

~~On September 30, 2020,~~activities, in the ~~Company issued $300.0 million in aggregate principal amount~~first quarter of ~~its Second Lien Notes and warrants for 7.3 million shares~~2022. Both of these contingent consideration arrangements expired at the ~~Company’s common stock exercisable only on a net share settlement basis (the “September 2020 Warrants”).~~end of 2021.

1412

The Company determined that the September 2020 Warrants are required to be accounted for as a derivative instrument. The Company recorded the September 2020 Warrants as a liability on its consolidated balance sheet measured at fair value as a component of “Fair value of derivatives” with gainsFinancial Statement Presentation and losses as a result of changes in the fair value of the September 2020 Warrants recorded as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 7 - Fair Value Measurements” for additional details.

In February 2021, holders of the September 2020 Warrants provided notice and exercised all of their outstanding warrants. As a result of this exercise, the Company issued 5.6 million shares of its common stock in exchange for all of the outstanding September 2020 Warrants. The exercise of the September 2020 Warrants resulted in settlement of the associated derivative liability, which was $134.8 million at the time of exercise, and the fair value of the September 2020 Warrants at exercise, less the par value of the shares of common stock issued in the exercise, was reclassified to “Capital in excess of par value” in the consolidated balance sheets.

~~Derivatives not designated as hedging instruments~~Settlements

The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value as “(Gain) loss on derivative contracts” in the consolidated statements of operations. Settlements are also recorded as ~~a gain or~~“(Gain) loss on derivative ~~contracts~~contracts” in the consolidated statements of operations. ~~As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements.~~ The ~~Company’s policy is to present~~Company presents the fair value of derivative contracts on a net basis in the consolidated balance ~~sheets.~~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 March 31, 2021
Presented without As Presented with
Effects of Netting Effects of Netting Effects of Netting
(In thousands)
Assets
Commodity derivative instruments $69,473 ($69,352) $121
Contingent consideration arrangements 5,375 0 5,375
Other current assets $74,848 ($69,352) $5,496
Commodity derivative instruments 3,790 (3,351) 439
Contingent consideration arrangements 0 0 0
Other assets, net $3,790 ($3,351) $439
Liabilities
Commodity derivative instruments (1)
($275,885) $69,352 ($206,533)
Contingent consideration arrangements (17,913) 0 (17,913)
Fair value of derivatives - current ($293,798) $69,352 ($224,446)
Commodity derivative instruments (2)
(4,751) 3,351 (1,400)
Contingent consideration arrangements 0 0 0
Fair value of derivatives - non-current ($4,751) $3,351 ($1,400)


	As of March 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	$10,939	($10,939)	$—
Other assets, net	$15,773	($15,773)	$—

Derivative Liabilities
Fair value of derivatives - current (1)	($403,867)	$10,939	($392,928)
Fair value of derivatives - non-current	($50,207)	$15,773	($34,434)

(1) Includes approximately ~~$14.1 million of deferred premiums, which the Company will pay as the applicable contracts settle.~~

~~(2) Includes approximately~~ $0.9 million of deferred premiums, which ~~the Company~~ will ~~pay~~be paid as the applicable contracts settle.

As of December 31, 2020
Presented without As Presented with
Effects of Netting Effects of Netting Effects of Netting
(In thousands)
Assets
Commodity derivative instruments $21,156 ($20,235) $921
Contingent consideration arrangements 0 0 0
Other current assets $21,156 ($20,235) $921
Commodity derivative instruments $0 $0 $0
Contingent consideration arrangements 1,816 0 1,816
Other assets, net $1,816 $0 $1,816
Liabilities
Commodity derivative instruments (1)
($117,295) $20,235 ($97,060)
Contingent consideration arrangements 0 0 0
Fair value of derivatives - current ($117,295) $20,235 ($97,060)
Commodity derivative instruments $0 $0 $0
Contingent consideration arrangements (8,618) 0 (8,618)
September 2020 Warrants liability (79,428) 0 (79,428)
Fair value of derivatives - non-current ($88,046) $0 ($88,046)


	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)

(1) Includes approximately ~~$11.2~~$2.9 million of deferred premiums, which ~~the Company~~ will ~~pay~~be paid as the applicable contracts settle.

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


	Three Months Ended March 31,
	2022	2021
	(In thousands)
Loss on oil derivatives	$325,348	$149,561
Loss on natural gas derivatives	28,181	2,697
Loss on NGL derivatives	4,771	1,138
Loss on contingent consideration arrangements	—	5,737
Loss on September 2020 Warrants liability (1)	—	55,390
Loss on derivative contracts	$358,300	$214,523

Three Months Ended March 31,
2021 2020
(In thousands)
(Gain) loss on oil derivatives $149,561 ($257,323)
(Gain) loss on natural gas derivatives 2,697 6,829
(Gain) loss on NGL derivatives 1,138 0
(Gain) loss on contingent consideration arrangements 5,737 (1,475)
(Gain) loss on September 2020 Warrants liability 55,390 0
(Gain) loss on derivative contracts $214,523 ($251,969)

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

Three Months Ended March 31,
2021 2020
(In thousands)
Cash flows from operating activities
Cash received (paid) on oil derivatives ($39,947) ($1,777)
Cash received (paid) on natural gas derivatives (1,369) 4,390
Cash received (paid) on NGL derivatives (846) 0
Cash received (paid) for commodity derivative settlements, net ($42,162) $2,613
Cash flows from investing activities
Cash paid for settlements of contingent consideration arrangements, net $0 ($40,000)


	Three Months Ended March 31,
	2022	2021
	(In thousands)
Cash flows from operating activities
Cash paid on oil derivatives	($95,353)	($39,947)
Cash paid on natural gas derivatives	(4,644)	(1,369)
Cash paid on NGL derivatives	(1,528)	(846)
Cash paid for commodity derivative settlements, net	($101,525)	($42,162)
Cash received for settlements of contingent consideration arrangements, net	$6,492	$—

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

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

Derivative ~~positions~~Positions

Listed in the tables below are the outstanding oil, natural gas and NGL derivative contracts as of March 31, ~~2021:~~ 2022:

For the Remainder For the Full Year
Oil contracts (WTI) of 2021 of 2022
   Swap contracts
   Total volume (Bbls) 1,832,000 0
   Weighted average price per Bbl $43.24 $0
   Collar contracts
   Total volume (Bbls) 8,298,800 1,807,500
   Weighted average price per Bbl
   Ceiling (short call) $48.30 $60.63
   Floor (long put) $40.24 $46.25
   Short call contracts
   Total volume (Bbls) 2,432,480 (1) 0
   Weighted average price per Bbl $63.62 $0
Short call swaption contracts
   Total volume (Bbls) 0 1,825,000 (2)
   Weighted average price per Bbl $0 $52.18
Oil contracts (Brent ICE)
   Swap contracts
   Total volume (Bbls) 221,300 (3) 0
   Weighted average price per Bbl $37.35 $0
Collar contracts
Total volume (Bbls) 550,000 0
Weighted average price per Bbl
Ceiling (short call) $50.00 $0
Floor (long put) $45.00 $0
Oil contracts (Midland basis differential)
   Swap contracts
   Total volume (Bbls) 2,171,900 0
   Weighted average price per Bbl $0.24 $0
Oil contracts (Argus Houston MEH)
   Collar contracts
   Total volume (Bbls) 409,500 452,500
   Weighted average price per Bbl
Ceiling (short call) $47.00 $63.15
Floor (long put) $41.00 $51.25


	For the Remainder		For the Full Year
Oil Contracts (WTI)	2022		2023
Swap Contracts
Total volume (Bbls)	3,676,000	(1)	905,000
Weighted average price per Bbl	$62.77	(1)	$71.20
Collar Contracts
Total volume (Bbls)	4,712,500		2,096,500
Weighted average price per Bbl
Ceiling (short call)	$68.77		$80.25
Floor (long put)	$57.83		$69.48






Short Call Swaption Contracts (2)
Total volume (Bbls)	—		1,825,000
Weighted average price per Bbl	$—		$72.00











Oil Contracts (Midland Basis Differential)
Swap Contracts
Total volume (Bbls)	1,787,500		—
Weighted average price per Bbl	$0.50		$—

Oil Contracts (Argus Houston MEH)
Collar Contracts
Total volume (Bbls)	227,500		—
Weighted average price per Bbl
Ceiling (short call)	$63.15		$—
Floor (long put)	$51.25		$—

(1) ~~Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.~~

~~(2) The short call swaption contracts have an exercise expiration date of December 31, 2021.~~

~~(3)~~ In ~~February 2021,~~March 2022, the Company entered into certain offsetting ~~ICE Brent~~WTI swaps for the second quarter of 2022 to reduce its exposure to rising oil prices. Those offsetting swaps resulted in a ~~locked-in~~recognized loss of approximately ~~$2.9~~$39.3 million of which ~~$1.6 million~~ will be settled in the ~~third~~second quarter of ~~2021 with~~2022 as the ~~remaining $1.3 million to be settled in the fourth quarter~~applicable contracts settle.

(2) The 2023 short call swaption contracts have exercise expiration dates of ~~2021.~~December 30, 2022.

1714

For the Remainder For the Full Year
Natural gas contracts (Henry Hub) of 2021 of 2022
   Swap contracts
      Total volume (MMBtu) 11,123,000 0
      Weighted average price per MMBtu $2.60 $0
Collar contracts
      Total volume (MMBtu) 5,500,000 1,800,000
      Weighted average price per MMBtu
         Ceiling (short call) $2.80 $3.88
         Floor (long put) $2.50 $2.78
   Short call contracts
      Total volume (MMBtu) 5,500,000 (1) 0
      Weighted average price per MMBtu $3.09 $0
Natural gas contracts (Waha basis differential)
   Swap contracts
      Total volume (MMBtu) 12,375,000 0
      Weighted average price per MMBtu ($0.42) $0

~~(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.~~

For the Remainder For the Full Year
NGL contracts (OPIS Mont Belvieu Purity Ethane) of 2021 of 2022
   Swap contracts
      Total volume (Bbls) 1,375,000 0
      Weighted average price per Bbl $7.62 $0


	For the Remainder	For the Full Year
Natural Gas Contracts (Henry Hub)	2022	2023
Swap Contracts
Total volume (MMBtu)	10,700,000	—
Weighted average price per MMBtu	$3.62	$—
Collar Contracts
Total volume (MMBtu)	6,110,000	2,700,000
Weighted average price per MMBtu
Ceiling (short call)	$4.51	$5.56
Floor (long put)	$3.68	$4.58




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)

Note 78 - 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 which the Company makes its own assumptions about how market participants would price the assets and liabilities.

Fair ~~value~~Value of ~~financial instruments~~Financial Instruments

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

Debt. The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s Second Lien Notes and Senior Unsecured Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “Note 56 - Borrowings” for further discussion.

March 31, 2021 December 31, 2020
Principal Amount Fair Value Principal Amount Fair Value
(In thousands)
Second Lien Notes $516,659 $524,409 $516,659 $470,160
6.25% Senior Notes 542,720 483,021 542,720 344,627
6.125% Senior Notes 460,241 388,904 460,241 260,036
8.25% Senior Notes 187,238 161,961 187,238 100,172
6.375% Senior Notes 320,783 252,617 320,783 161,995
Total $2,027,641 $1,810,912 $2,027,641 $1,336,990


	March 31, 2022		December 31, 2021
	Principal Amount	Fair Value	Principal Amount	Fair Value
	(In thousands)
6.125% Senior Notes	$460,241	$456,789	$460,241	$455,639
9.00% Second Lien Notes	319,659	339,638	319,659	343,633
8.25% Senior Notes	187,238	189,110	187,238	184,429
6.375% Senior Notes	320,783	317,575	320,783	309,556
8.00% Senior Notes	650,000	684,125	650,000	663,000
Total	$1,937,921	$1,987,237	$1,937,921	$1,956,257

Assets and ~~liabilities measured~~Liabilities Measured at ~~fair value~~Fair Value on a ~~recurring basis~~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.~~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 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 67 - Derivative Instruments and Hedging Activities” for further discussion.

~~Contingent consideration arrangements - embedded derivative financial instruments.~~
The embedded options within the contingent consideration arrangements are considered financial instruments under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded options on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates undiscounted payouts, and risk adjusts for the discount rates inclusive of adjustments for each of the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered Level 2 inputs within the fair value hierarchy. See “Note 6 - 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 March 31, ~~2021~~2022 and December 31, ~~2020:~~2021:

March 31, 2021
Level 1 Level 2 Level 3
(In thousands)
Assets
Commodity derivative instruments $0 $560 $0
Contingent consideration arrangements 0 5,375 0
Liabilities
Commodity derivative instruments (1)
0 (207,933) 0
Contingent consideration arrangements 0 (17,913) 0
Total net assets (liabilities) $0 ($219,911) $0

December 31, 2020
Level 1 Level 2 Level 3
(In thousands)
Assets
Commodity derivative instruments $0 $921 $0
Contingent consideration arrangements 0 1,816 0
Liabilities
Commodity derivative instruments (2)
0 (97,060) 0
Contingent consideration arrangements 0 (8,618) 0
September 2020 Warrants 0 0 (79,428)
Total net assets (liabilities) $0 ($102,941) ($79,428)


	March 31, 2022
	Level 1	Level 2	Level 3
	(In thousands)
Commodity derivative assets	$—	$—	$—

Commodity derivative liabilities (1)	—	(427,362)	—


	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 (2)	—	(172,386)	—
Contingent consideration arrangements	—	(25,000)	—

Total net assets (liabilities)	$—	($174,755)	$—

(1) Includes approximately ~~$15.0~~$0.9 million of deferred premiums, which ~~the Company~~ will ~~pay~~be paid as the applicable contracts settle.

(2) Includes approximately ~~$11.2~~$2.9 million of deferred premiums, which ~~the Company~~ will ~~pay~~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

~~September 2020 Warrants.~~Acquisitions. The fair value of assets acquired and liabilities assumed are measured as of the ~~September 2020 Warrants was calculated~~acquisition date by a third-party valuation specialist using a ~~Black Scholes-Merton option pricing model. As historical volatility is a significant input into~~combination of income and market approaches, which are not observable in the ~~model, the September 2020 Warrants were~~market and are therefore designated as Level 3 ~~within the valuation hierarchy.~~

~~In February 2021, holders of the September 2020 Warrants provided notice~~inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and ~~exercised all of their outstanding warrants. The exercise of the September 2020 Warrants resulted in settlement of the associated derivative liability of $134.8 million.~~costs to produce and develop reserves, oil and natural gas forward prices, and a risk-adjusted discount rate. See “Note 63 - ~~Derivative Instruments~~Acquisitions and ~~Hedging Activities”~~Divestitures” for additional ~~details.~~

discussion.

The following table presents a reconciliation of the change in the fair value of the liability related to the September 2020 Warrants, which was designated as Level 3 within the valuation hierarchy, for the three months ended March 31, 2021.


						~~Three Months Ended March 31, 2021~~
						~~(In thousands)~~
~~Beginning of period~~						~~$79,428~~
~~(Gain) loss on changes in fair value~~ ~~(1)~~						~~55,390~~
~~Transfers into (out of) Level 3~~						~~(134,818)~~
~~End of period~~						$0

~~(1) Included in “(Gain) loss on derivative contracts” in the consolidated statements of operations.~~

~~Assets and liabilities measured at fair value on a nonrecurring basis~~

Asset ~~retirement obligations.~~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 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, ~~and~~ 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 89 - Income Taxes

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

For both the three months ended March 31, ~~2021~~2022 and ~~2020,~~2021, the Company’s effective income tax ~~rates were~~rate was approximately 1% ~~and 23%, respectively.~~. The primary differences between the effective tax rates for the three months ended March 31, 2022 and 2021 and ~~2020 were a result of~~the statutory rate resulted from the valuation allowance recorded against the Company’s net deferred tax assets beginning in the second quarter of 2020 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 the cumulative historical ~~three year~~three-year pre-tax loss and a net deferred tax asset position at March 31, ~~2021,~~2022, driven primarily by the impairments of evaluated oil and gas properties recognized 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, the Company concluded that it is more likely than not that the net deferred tax assets will not be realized. As a result, the Company has recorded a valuation allowance, reducing the net deferred tax assets as of March 31, ~~2021~~2022 to 0.zero. As long as the Company continues to conclude that the valuation

allowance against its net deferred tax assets is necessary, the Company does not expect to have no significant deferred income tax expense or benefit.

The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more ~~future potential~~ transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if ~~the Company~~it recognizes taxable income. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit.

Note ~~9 - Share-based Compensation~~

~~All share and per share numbers included in this footnote have been adjusted for the reverse stock split. See “Note~~ 10 - ~~Stockholders’ Equity” for discussion of the reverse stock split and reduction in authorized shares.~~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 three months ended March 31, ~~2021 and 2020:~~2022:

Three Months Ended March 31,
2021 2020
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 677 $34.57 269 $102.48
Granted (1)
570 $38.41 232 $33.19
Vested (2)
(21) $70.03 (16) $98.36
Forfeited (16) $15.42 0 $0
Unvested, end of the period 1,210 $36.02 485 $69.50

~~(1)Includes 0 and 85.4 thousand target performance-based RSU Equity Awards granted during the three months ended March 31, 2021 and 2020, respectively.~~

~~(2)The fair value of shares vested was $0.3 million and $0.7 million during the three months ended March 31, 2021 and 2020, respectively.~~


	Three Months Ended March 31, 2022
	RSU Equity Awards (In thousands)	Weighted Average Grant-Date Fair Value Per Share
Unvested at beginning of the period	968	$34.04
Granted	328	$60.63
Vested	(10)	$53.38
Forfeited	(11)	$33.36
Unvested at end of the period	1,275	$40.73

Grant activity for the three months ended March 31, ~~2021~~2022 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards ~~as compared to the annual~~with a weighted-average grant date fair value of ~~long-term equity to only executives during the first quarter of 2020.~~$60.63.

~~NaN performance-based~~The aggregate fair value of RSU Equity Awards ~~were granted~~that vested during the three months ended March 31, 2021. For the performance-based RSU Equity Awards granted in the first quarter of 2020, the number of outstanding performance-based RSU Equity Awards that can vest is based on a calculation that compares the Company’s total shareholder return (“TSR”) to the same calculated return of a group of peer companies selected by the Company and can range between 0% and 300% of the target units for the awards granted. These awards include an absolute TSR modifier, which 2022was added as a second factor in the calculation, which could increase the number of awards that vest or reduce the number of awards that vest if the absolute TSR is less than 5% over the performance period.

The Company recognizes expense for performance-based RSU Equity Awards based on the fair value of the awards at the grant date. Awards with a performance-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and 0 shares ultimately vest. The grant date fair value of performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $2.9 million for the three months ended March 31, 2020. The following table summarizes the assumptions used to calculate the grant date fair value of the performance-based RSU Equity Awards granted during the three months ended March 31, 2020:

~~Performance-based Awards~~

~~January 31, 2020~~

~~Expected term (in years)~~

~~2.9~~

~~Expected volatility~~

~~54.8~~

~~Risk-free interest rate~~

~~1.3~~

~~Dividend yield~~

$0.5 million. As of March 31, ~~2021,~~2022, unrecognized compensation costs related to unvested RSU Equity Awards were ~~$32.7~~$37.3 million and will be recognized over a weighted average period of 2.5 years.

Cash-Settled Awards

~~Cash-Settled RSU~~ A~~wards~~

~~The table below summarizes the activity for~~No restricted stock units that may be settled in cash (“Cash-Settled RSU Awards”) ~~for the three months ended March 31, 2021 and 2020:~~

Three Months Ended March 31,
2021 2020
Cash-Settled RSU Awards
(in thousands) Weighted Average Grant Date
Fair Value Cash-Settled RSU Awards
(in thousands) Weighted Average Grant Date
Fair Value
Unvested, beginning of the period 196 $47.56 86 $124.22
Granted 0 $0 86 $33.98
Vested (1) $107.80 (1) $122.96
Did not vest at end of performance period (1) $107.80 0 $166.60
Forfeited 0 $0 0 $0
Unvested, end of the period 194 $47.15 171 $78.54

~~NaN Cash-Settled RSU Awards~~or cash-settled stock appreciation rights (“Cash SARs”) were granted to employees during the three months ended March 31, 2022 and 2021. Grant activity in the first quarter of 2020 primarily consisted of Cash-Settled RSU Awards to executives as part of the annual grant of long-term equity incentive awards. These awards cliff vest after an approximate three-year performance period.

The Company’s outstanding Cash-Settled RSU Awards include the same performance-based vesting conditions as the performance-based RSU Equity Awards, which are described above. Additionally, the assumptions used to calculate the grant date fair value per Cash-Settled RSU Award granted during the three months ended March 31, 2020 are the same as the performance-based RSU Equity Awards presented above.

The following table summarizes the Company’s ~~liability~~liabilities for ~~Cash-Settled RSU Awards~~cash-settled awards and the classification in the consolidated balance sheets for the periods indicated:

March 31, 2021 December 31, 2020
(In thousands)
Other current liabilities $850 $182
Other long-term liabilities 4,928 1,336
Total Cash-Settled RSU Awards $5,778 $1,518

~~As of March 31, 2021, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $5.4 million and will be recognized over a weighted average period of 1.7 years.~~

~~Cash-Settled SARs~~

As a result of the Carrizo Acquisition, cash-settled stock appreciation rights (“Cash SARs”) previously granted by Carrizo that were outstanding at closing were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Carrizo Acquisition. The liabilities for Cash SARs as of March 31, 2021 and December 31, 2020 were $6.5 million and $1.7 million, respectively, all of which were classified as “Other current liabilities” in the consolidated balance sheets in the respective periods. Changes in the fair value of the Cash SARs are included in “General and administrative” in the consolidated statements of operations.


	March 31, 2022	December 31, 2021
	(In thousands)
Cash SARs	$10,324	$7,884
Cash-Settled RSU Awards	4,563	1,382
Other current liabilities	14,887	9,266

Cash-Settled RSU Awards	1,972	6,366
Other long-term liabilities	1,972	6,366
Total Cash-Settled RSU Awards	$16,859	$15,632

2217

Share-Based Compensation Expense (Benefit), Net

Share-based compensation expense associated with the RSU Equity Awards, 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 each respective period:


		Three Months Ended March 31,			Three Months Ended March 31,
		2021	2020				2022	2021
		(In thousands)		(In thousands)
RSU Equity Awards	RSU Equity Awards	$2,608	$3,948			RSU Equity Awards	$3,366	$2,608
Cash-Settled RSU Awards	Cash-Settled RSU Awards	4,442	(1,996)			Cash-Settled RSU Awards	237	4,442
Cash SARs	Cash SARs	4,866	(4,756)			Cash SARs	2,440	4,866
		11,916	(2,804)				6,043	11,916
Less: amounts capitalized to oil and gas properties	Less: amounts capitalized to oil and gas properties	(4,308)	(168)			Less: amounts capitalized to oil and gas properties	(1,877)	(4,308)
Total share-based compensation expense (benefit), net	Total share-based compensation expense (benefit), net	$7,608	($2,972)			Total share-based compensation expense (benefit), net	$4,166	$7,608

See “Note 10 - Share-Based Compensation” of the Notes to Consolidated Financial Statements in the ~~2020~~2021 Annual Report for details of the Company’s equity-based incentive plans.

Note 1011 - Stockholders’ Equity

Warrant Exercises

During the three months ended March 31, 2021, certain holders of the September 2020 Warrants and ~~warrants issued in conjunction with~~ the ~~exchange of Senior Unsecured Notes on~~ November 2, 2020 ~~(the “November 2020 Warrants”)~~Warrants provided notice and exercised all of their outstanding warrants. As a result of the exercises, the Company issued a total of 6.4 million shares of its common stock in exchange for 8.4 million outstanding warrants determined on a net share settlement basis. See “Note ~~6 - Derivative Instruments and Hedging Activities” and “Note~~ 7 - ~~Fair Value Measurements”~~Borrowings” of the Notes to Consolidated Financial Statements in the Company’s 2021 Annual Report for additional details regarding the September 2020 Warrants and the November 2020 Warrants.

~~As of March 31, 2021, 0.6 million November 2020 Warrants remain outstanding.~~

~~Reverse Stock Split~~

On August 7, 2020, the Board of Directors effected a reverse stock split of the Company’s outstanding shares of common stock at a ratio of 1-for-10 and reduced the total number of authorized shares of the Company’s common stock from 525,000,000 to 52,500,000 shares pursuant to an amendment to the Company’s Certificate of Incorporation, which was approved by the Company’s shareholders at the Company’s annual meeting of shareholders on June 8, 2020. The Company’s common stock began trading on a split-adjusted basis on August 10, 2020 upon opening of the markets. All share and per share amounts, except par value per share, in the consolidated financial statements and notes thereto for periods prior to August 2020 were retroactively adjusted to give effect to this reverse stock split.

Note 1112 - Accounts Receivable, Net

March 31, 2021 December 31, 2020
(In thousands)
Oil and natural gas receivables $125,648 $100,257
Joint interest receivables 21,185 11,530
Other receivables 35,163 24,191
Total 181,996 135,978
Allowance for credit losses (2,869) (2,869)
Total accounts receivable, net $179,127 $133,109


	March 31, 2022	December 31, 2021
	(In thousands)
Oil and natural gas receivables	$262,389	$171,837
Joint interest receivables	21,044	13,751
Other receivables	66,388	49,053
Total	349,821	234,641
Allowance for credit losses	(2,228)	(2,205)
Total accounts receivable, net	$347,593	$232,436

Note 1213 - Accounts Payable and Accrued Liabilities

March 31, 2021 December 31, 2020
(In thousands)
Accounts payable $78,869 $101,231
Revenues payable 187,261 162,762
Accrued capital expenditures 45,408 32,493
Accrued interest 63,211 45,033
Total accounts payable and accrued liabilities $374,749 $341,519


	March 31, 2022	December 31, 2021
	(In thousands)
Accounts payable	$134,690	$151,836
Revenues and royalties payable	277,368	294,143
Accrued capital expenditures	56,388	64,412
Accrued interest	47,994	59,600
Total accounts payable and accrued liabilities	$516,440	$569,991

2318

Note 1314 - Supplemental Cash Flow

Three Months Ended March 31,
2021 2020
Supplemental cash flow information:
Interest paid, net of capitalized amounts $12,983 $15,820
Income taxes paid 0 0
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases $8,065 $11,821
Investing cash flows from operating leases 6,005 5,716
Non-cash investing and financing activities:
Change in accrued capital expenditures $18,903 $84,594
Change in asset retirement costs 1,151 905
ROU assets obtained in exchange for lease liabilities:
Operating leases $6,476 $8,366


	Three Months Ended March 31,
	2022	2021
	(In thousands)
Supplemental cash flow information:
Interest paid, net of capitalized amounts	$25,144	$12,983
Income taxes paid	—	—
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$7,382	$8,065
Investing cash flows from operating leases	6,189	6,005
Non-cash investing and financing activities:
Change in accrued capital expenditures	($8,897)	$18,903
Change in asset retirement costs	289	1,151
ROU assets obtained in exchange for lease liabilities:
Operating leases	$8,505	$6,476

Note 1415 - Subsequent Events

Credit Agreement Reaffirmation

~~Fourth Amendment to~~On May 2, 2022, as part of the ~~Credit Agreement~~

~~On May 3, 2021, the Company entered into the fourth amendment to its credit agreement governing the Credit Facility. The amendment, among other things, (a) reaffirmed~~Company’s spring 2022 redetermination, the borrowing base and ~~the~~ elected commitment amount of $1.6 billion as a result of the spring 2021 scheduled redetermination; and (b) permits the prepayment, repurchase or redemption of Junior Debt (as defined in the credit agreement governing the Credit Facility), which includes the Senior Unsecured Notes and the Second Lien Notes, in an aggregate amount not to exceed $100.0 million, commencing April 1, 2021, if certain liquidity and free cash flow thresholds are met.

~~Non-Core Asset Divestitures~~

In April 2021, the Company entered into purchase and sale agreements for the divestiture of certain non-core assets in the Delaware Basin. The transactions, which are primarily comprised of natural gas producing properties in the Western Delaware Basin as well as a small undeveloped acreage position, have agreed upon purchase prices totaling approximately $40.0 million and are expected to close during the second quarter of 2021.were reaffirmed.

2419

Special Note Regarding Forward Looking Statements

This report 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 that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as:

•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 ~~consummate and~~ 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. ~~These~~We disclose these and other ~~risks include, but are not limited~~important factors that could cause our actual results to ~~the risks described~~differ materially from our expectations under “Risk Factors” in Part I, Item 1A of our ~~2020~~2021 Annual ~~Report and in all quarterly reports on Form 10-Q filed subsequently thereto.~~Report. These factors include:

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

•general economic conditions including the availability of credit and access to existing lines of credit;

•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 and other equipment, waste and water disposal infrastructure, and personnel;

•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;

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

•difficulties encountered in delivering oil and natural gas to commercial markets;

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

•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;

•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

•~~weather conditions.~~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,

2520

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

~~General~~

The following management’s discussion and analysis describes the principal factors affecting ~~the Company’s~~our results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and our ~~2020~~2021 Annual Report, ~~on Form 10-K,~~ which include additional information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results. ~~Our website address is~~ ~~www.callon.com~~. All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this Quarterly Report on Form 10-Q.

General

We are an independent oil and natural gas company ~~with roots that go back over 70 years to our establishment in 1950. We are~~ 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.~~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 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 and Overview~~

~~Fourth Amendment~~ ~~to the Credit Agreement~~

On May 3, 2021, we entered into the fourth amendment to our credit agreement governing the Credit Facility which, among other things, reaffirmed the borrowing base and elected commitment amount of $1.6 billion as a result of the spring 2021 scheduled redetermination. See “Note 14 - Subsequent Events” for further discussion.

~~Non-Core Asset Divestitures~~

In April 2021, we entered into purchase and sale agreements for the divestiture of certain non-core assets in the Delaware Basin. The transactions, which are primarily comprised of natural gas producing properties in the Western Delaware Basin as well as a small undeveloped acreage position, have agreed upon purchase prices totaling approximately $40.0 million and are expected to close during the second quarter of 2021.

First Quarter ~~2021~~2022 Highlights

•Total production for the three months ended March 31, ~~2021~~2022 was ~~81.0~~102.7 MBoe/d, a decrease of ~~15% and 20%~~9% from the three months ended December 31, ~~2020 and March 31, 2020, respectively,~~2021, primarily due to normal production decline ~~and the shut-in of our operated~~partially offset by new wells placed on production during the ~~severe winter storms~~first quarter of 2022. Total production for the three months ended March 31, 2022 increased 27% from the three months ended March 31, 2021, primarily due to new wells acquired in ~~February~~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 activity for the three months ended March 31, ~~2021~~2022 along with our drilled but uncompleted and producing wells as of March 31, ~~2021~~2022 are summarized in the table below.

Three Months Ended March 31, 2021 As of March 31, 2021
Drilled Completed Drilled But Uncompleted Producing
Region Gross Net Gross Net Gross Net Gross Net
Permian 10 8.4 9 8.2 28 23.8 850 741.8
Eagle Ford 8 8.0 10 9.8 35 35.0 660 592.1
Total 18 16.4 19 18.0 63 58.8 1,510 1,333.9


	Three Months Ended March 31, 2022				As of March 31, 2022
	Drilled		Completed		Drilled But Uncompleted		Producing
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Permian	22	19.2	16	14.3	27	23.4	588	533.0
Eagle Ford	9	7.2	—	—	15	13.0	756	671.3
Total	31	26.4	16	14.3	42	36.4	1,344	1,204.3

•Operational capital expenditures, exclusive of leasehold and seismic, for the first quarter of ~~2021~~2022 were ~~$95.6~~$157.4 million,, of which approximately ~~58%~~90% were in the Permian with the remaining balance in the Eagle Ford. We expect to operate an average of three drilling rigs throughout the remainder of 2021 and will average just over two completion crews through the second quarter before reducing to a single completion crew during the third quarter. See “—Liquidity and Capital Resources—~~2021~~2022 Capital Budget and Funding Strategy” for additional details.

•~~Reduced~~As of March 31, 2022, borrowings outstanding under our Credit Facility ~~by $35.0~~was $712.0 million ~~reflecting our continued emphasis on deleveraging our balance sheet.~~compared to $785.0 million as of December 31, 2021.

•~~We recorded~~Recorded net income for the three months ended March 31, 2022 of $39.7 million, or $0.64 per diluted share, compared to net loss for the three months ended March 31, 2021 of ~~$80.4 million, or~~ ~~$1.89~~ ~~per diluted share, as compared to net income for the three months ended March 31, 2020 of $216.6~~$80.4 million, or ~~$5.46~~$1.89 per diluted share. The ~~change from net~~

~~income to net loss~~variance between the respective periods was driven primarily by ~~a loss on derivative contracts of approximately~~ ~~$214.5 million during the first quarter of~~ ~~2021 compared to a gain on derivative contracts of approximately~~ ~~$252.0 million during the first quarter of~~ ~~2020, partially offset by~~ an increase in operating revenues ~~primarily~~in the first quarter of 2022 driven by an approximate ~~39%~~64% increase in the total average realized sales price and an increase of 27% in production volumes compared to the first quarter of ~~2020~~2021. This increase was partially offset by an increase in the loss on derivative contracts to approximately $358.3 million during the first quarter of 2022 compared to approximately $214.5 million during the first quarter of 2021, as well as ~~a decrease~~an increase in ~~depreciation, depletion and amortization primarily driven by the recording of impairments of evaluated oil and gas properties during 2020.~~operating expenses. See “—Results of Operations” below for further details.

•In February 2021, severe winter storms affected field operations in both the Permian and Eagle Ford resulting in the shut-in of nearly 100% of our operated production. While all of our wells returned to production by the end of February, the shut-in resulted in the deferral of approximately 7.6 MBoe/d for the quarter. The impact to our drilling and completion operations were not significant enough to alter our expectations for the full year development schedule and the impact to lease operating expenses was immaterial.

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							Three Months Ended March 31,								Three Months Ended							Three Months Ended
		March 31, 2021		December 31, 2020		$ Change	% Change		2021		2020		$ Change	% Change			March 31, 2022		December 31, 2021		Change	% Change		March 31, 2022		March 31, 2021		Change	% Change
Total production	Total production															Total production
Oil (MBbls)	Oil (MBbls)															Oil (MBbls)
Permian	Permian	3,088		3,445		(357)	(10	%)	3,088		3,594		(506)	(14	%)	Permian	4,469		4,727		(258)	(5	%)	4,469		3,088		1,381	45	%
Eagle Ford	Eagle Ford	1,593		1,980		(387)	(20	%)	1,593		2,253		(660)	(29	%)	Eagle Ford	1,377		1,839		(462)	(25	%)	1,377		1,593		(216)	(14	%)
Total oil (MBbls)		4,681		5,425		(744)	(14	%)	4,681		5,847		(1,166)	(20	%)
Total oil																Total oil	5,846		6,566		(720)	(11	%)	5,846		4,681		1,165	25	%

Natural gas (MMcf)	Natural gas (MMcf)															Natural gas (MMcf)
Permian	Permian	6,208		7,474		(1,266)	(17	%)	6,208		8,009		(1,801)	(22	%)	Permian	8,590		9,183		(593)	(6	%)	8,590		6,208		2,382	38	%
Eagle Ford	Eagle Ford	1,627		2,264		(637)	(28	%)	1,627		1,784		(157)	(9	%)	Eagle Ford	1,525		2,090		(565)	(27	%)	1,525		1,627		(102)	(6	%)
Total natural gas (MMcf)		7,835		9,738		(1,903)	(20	%)	7,835		9,793		(1,958)	(20	%)
Total natural gas																Total natural gas	10,115		11,273		(1,158)	(10	%)	10,115		7,835		2,280	29	%

NGLs (MBbls)	NGLs (MBbls)															NGLs (MBbls)
Permian	Permian	1,075		1,331		(256)	(19	%)	1,075		1,368		(293)	(21	%)	Permian	1,455		1,549		(94)	(6	%)	1,455		1,075		380	35	%
Eagle Ford	Eagle Ford	224		353		(129)	(37	%)	224		339		(115)	(34	%)	Eagle Ford	252		344		(92)	(27	%)	252		224		28	13	%
Total NGLs (MBbls)		1,299		1,684		(385)	(23	%)	1,299		1,707		(408)	(24	%)
Total NGLs																Total NGLs	1,707		1,893		(186)	(10	%)	1,707		1,299		408	31	%

Total Production (MBoe)
Total production (MBoe)																Total production (MBoe)
Permian	Permian	5,198		6,022		(824)	(14	%)	5,198		6,297		(1,099)	(17	%)	Permian	7,356		7,806		(450)	(6	%)	7,356		5,198		2,158	42	%
Eagle Ford	Eagle Ford	2,088		2,710		(622)	(23	%)	2,088		2,889		(801)	(28	%)	Eagle Ford	1,883		2,532		(649)	(26	%)	1,883		2,088		(205)	(10	%)
Total barrels of oil equivalent (MBoe)		7,286		8,732		(1,446)	(17	%)	7,286		9,186		(1,900)	(21	%)
Total barrels of oil equivalent																Total barrels of oil equivalent	9,239		10,338		(1,099)	(11	%)	9,239		7,286		1,953	27	%

Total daily production (Boe/d)	Total daily production (Boe/d)	80,957		94,914		(13,957)	(15	%)	80,957		100,955		(19,998)	(20	%)	Total daily production (Boe/d)	102,655		112,365		(9,710)	(9	%)	102,655		80,957		21,698	27	%
Oil as % of total daily production	Oil as % of total daily production	64	%	62	%				64	%	64	%				Oil as % of total daily production	63	%	64	%				63	%	64	%

Benchmark prices (1)	Benchmark prices (1)															Benchmark prices (1)
WTI (per Bbl)	WTI (per Bbl)	$57.80		$42.60		$15.20	36	%	$57.80		$46.08		$11.72	25	%	WTI (per Bbl)	$94.38		$77.17		$17.21	22	%	$94.38		$57.80		$36.58	63	%
Henry Hub (per Mcf)	Henry Hub (per Mcf)	2.72		2.76		(0.04)	(1	%)	2.72		1.87		0.85	45	%	Henry Hub (per Mcf)	4.57		4.84		(0.27)	(6	%)	4.57		2.72		1.85	68	%

Average realized sales price (excluding impact of settled derivatives)
Average realized sales price (excluding impact of derivative settlements)																Average realized sales price (excluding impact of derivative settlements)
Oil (per Bbl)	Oil (per Bbl)															Oil (per Bbl)
Permian	Permian	$56.66		$41.02		$15.64	38	%	$56.66		$45.61		$11.05	24	%	Permian	$94.52		$76.86		$17.66	23	%	$94.52		$56.66		$37.86	67	%
Eagle Ford	Eagle Ford	57.80		41.12		16.68	41	%	57.80		45.21		12.59	28	%	Eagle Ford	95.02		77.84		17.18	22	%	95.02		57.80		37.22	64	%
Total oil (per Bbl)		57.05		41.06		15.99	39	%	57.05		45.45		11.60	26	%
Total oil																Total oil	94.64		77.13		17.51	23	%	94.64		57.05		37.59	66	%

Natural gas (per Mcf)	Natural gas (per Mcf)															Natural gas (per Mcf)
Permian	Permian	3.11		1.68		1.43	85	%	3.11		0.33		2.78	842	%	Permian	4.20		4.81		(0.61)	(13	%)	4.20		3.11		1.09	35	%
Eagle Ford	Eagle Ford	3.03		2.65		0.38	14	%	3.03		1.88		1.15	61	%	Eagle Ford	5.18		6.00		(0.82)	(14	%)	5.18		3.03		2.15	71	%
Total natural gas (per Mcf)		3.09		1.91		1.18	62	%	3.09		0.62		2.47	398	%
Total natural gas																Total natural gas	4.35		5.03		(0.68)	(14	%)	4.35		3.09		1.26	41	%

NGL (per Bbl)	NGL (per Bbl)															NGL (per Bbl)
Permian	Permian	22.68		15.00		7.68	51	%	22.68		11.02		11.66	106	%	Permian	40.25		37.50		2.75	7	%	40.25		22.68		17.57	77	%
Eagle Ford	Eagle Ford	22.24		16.16		6.08	38	%	22.24		9.00		13.24	147	%	Eagle Ford	35.93		34.00		1.93	6	%	35.93		22.24		13.69	62	%
Total NGLs (per Bbl)		22.60		15.24		7.36	48	%	22.60		10.62		11.98	113	%
Total NGLs																Total NGLs	39.61		36.86		2.75	7	%	39.61		22.60		17.01	75	%

Total average realized sales price (per Boe)																Total average realized sales price (per Boe)
Permian																Permian	70.29		59.64		10.65	18	%	70.29		42.06		28.23	67	%
Eagle Ford																Eagle Ford	78.50		66.10		12.40	19	%	78.50		48.85		29.65	61	%
Total average realized sales price																Total average realized sales price	$71.97		$61.22		$10.75	18	%	$71.97		$44.01		$27.96	64	%

2822

Three Months Ended Three Months Ended March 31,
March 31, 2021 December 31, 2020 $ Change % Change 2021 2020 $ Change % Change
Total average realized sales price (per Boe)
Permian 42.06 28.87 13.19 46 % 42.06 28.85 13.21 46 %
Eagle Ford 48.85 34.36 14.49 42 % 48.85 37.48 11.37 30 %
Total (per Boe) $44.01 $30.57 $13.44 44 % $44.01 $31.56 $12.45 39 %
Average realized sales price (including impact of settled derivatives)
Oil (per Bbl) $44.33 $39.62 $4.71 12 % $44.33 $48.90 ($4.57) (9 %)
Natural gas (per Mcf) 2.88 1.89 0.99 52 % 2.88 1.13 1.75 155 %
NGLs (per Bbl) 21.77 15.24 6.53 43 % 21.77 10.62 11.15 105 %
Total (per Boe) $35.46 $29.66 $5.80 20 % $35.46 $34.30 $1.16 3 %
Revenues (in thousands)
Oil
Permian $174,967 $141,320 $33,647 24 % $174,967 $163,906 $11,061 7 %
Eagle Ford 92,078 81,413 10,665 13 % 92,078 101,861 (9,783) (10 %)
Total oil 267,045 222,733 44,312 20 % 267,045 265,767 1,278 — %
Natural gas
Permian 19,290 12,560 6,730 54 % 19,290 2,675 16,615 621 %
Eagle Ford 4,930 6,001 (1,071) (18 %) 4,930 3,354 1,576 47 %
Total natural gas 24,220 18,561 5,659 30 % 24,220 6,029 18,191 302 %
NGLs
Permian 24,376 19,964 4,412 22 % 24,376 15,072 9,304 62 %
Eagle Ford 4,981 5,704 (723) (13 %) 4,981 3,051 1,930 63 %
Total NGLs 29,357 25,668 3,689 14 % 29,357 18,123 11,234 62 %
Total Revenues
Permian 218,633 173,844 44,789 26 % 218,633 181,653 36,980 20 %
Eagle Ford 101,989 93,118 8,871 10 % 101,989 108,266 (6,277) (6 %)
Total revenues $320,622 $266,962 $53,660 20 % $320,622 $289,919 $30,703 11 %
Additional per Boe data
Lease operating
Permian $4.31 $4.43 ($0.12) (3 %) $4.31 $5.00 ($0.69) (14 %)
Eagle Ford 8.65 6.77 1.88 28 % 8.65 7.24 1.41 19 %
Total lease operating $5.55 $5.15 $0.40 8 % $5.55 $5.70 ($0.15) (3 %)
Production and ad valorem taxes
Permian $2.32 $1.71 $0.61 36 % $2.32 $1.99 $0.33 17 %
Eagle Ford 3.07 2.29 0.78 34 % 3.07 2.47 0.60 24 %
Total production and ad valorem taxes $2.53 $1.89 $0.64 34 % $2.53 $2.14 $0.39 18 %
Gathering, transportation and processing
Permian $2.54 $2.42 $0.12 5 % $2.54 $1.87 $0.67 36 %
Eagle Ford 2.29 2.25 0.04 2 % 2.29 0.89 1.40 157 %
Total gathering, transportation and processing $2.47 $2.37 $0.10 4 % $2.47 $1.57 $0.90 57 %


	Three Months Ended					Three Months Ended
	March 31, 2022	December 31, 2021	$ Change	% Change		March 31, 2022	March 31, 2021	$ Change	% Change
Revenues (in thousands)
Oil
Permian	$422,404	$363,306	$59,098	16	%	$422,404	$174,967	$247,437	141	%
Eagle Ford	130,845	143,139	(12,294)	(9	%)	130,845	92,078	38,767	42	%
Total oil	553,249	506,445	46,804	9	%	553,249	267,045	286,204	107	%

Natural gas
Permian	36,069	44,133	(8,064)	(18	%)	36,069	19,290	16,779	87	%
Eagle Ford	7,907	12,541	(4,634)	(37	%)	7,907	4,930	2,977	60	%
Total natural gas	43,976	56,674	(12,698)	(22	%)	43,976	24,220	19,756	82	%

NGLs
Permian	58,563	58,085	478	1	%	58,563	24,376	34,187	140	%
Eagle Ford	9,055	11,697	(2,642)	(23	%)	9,055	4,981	4,074	82	%
Total NGLs	67,618	69,782	(2,164)	(3	%)	67,618	29,357	38,261	130	%

Total revenues
Permian	517,036	465,524	51,512	11	%	517,036	218,633	298,403	136	%
Eagle Ford	147,807	167,377	(19,570)	(12	%)	147,807	101,989	45,818	45	%
Total revenues	$664,843	$632,901	$31,942	5	%	$664,843	$320,622	$344,221	107	%

Additional per Boe data
Lease operating expense
Permian	$6.85	$7.22	($0.37)	(5	%)	$6.85	$4.31	$2.54	59	%
Eagle Ford	8.99	6.77	2.22	33	%	8.99	8.65	0.34	4	%
Total lease operating expense	$7.29	$7.11	$0.18	3	%	$7.29	$5.55	$1.74	31	%

Production and ad valorem taxes
Permian	$3.89	$3.15	$0.74	23	%	$3.89	$2.32	$1.57	68	%
Eagle Ford	4.82	3.60	1.22	34	%	4.82	3.07	1.75	57	%
Total production and ad valorem taxes	$4.08	$3.26	$0.82	25	%	$4.08	$2.53	$1.55	61	%

Gathering, transportation and processing
Permian	$2.33	$2.26	$0.07	3	%	$2.33	$2.54	($0.21)	(8	%)
Eagle Ford	1.92	1.76	0.16	9	%	1.92	2.29	(0.37)	(16	%)
Total gathering, transportation and processing	$2.25	$2.14	$0.11	5	%	$2.25	$2.47	($0.22)	(9	%)

(1) Reflects calendar average daily spot market prices.

2923

Revenues

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

Three Months Ended
Oil Natural Gas NGLs Total
(In thousands)
Revenues for the period ended in December 31, 2020 (1)
$222,733 $18,561 $25,668 $266,962
Volume increase (decrease) (30,546) (3,627) (5,868) (40,041)
Price increase (decrease) 74,858 9,286 9,557 93,701
Net increase (decrease) 44,312 5,659 3,689 53,660
Revenues for the period ended in March 31, 2021 (1)
$267,045 $24,220 $29,357 $320,622
Percent of total revenues 83 % 8 % 9 %


	Oil		Natural Gas		NGLs		Total
	(In thousands)
Revenues for the three months ended December 31, 2021 (1)	$506,445		$56,674		$69,782		$632,901
Volume increase (decrease)	(55,535)		(5,822)		(6,857)		(68,214)
Price increase (decrease)	102,339		(6,876)		4,693		100,156
Net increase (decrease)	46,804		(12,698)		(2,164)		31,942
Revenues for the three months ended March 31, 2022 (1)	$553,249		$43,976		$67,618		$664,843

Percent of total revenues	83	%	7	%	10	%

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

Three Months Ended March 31,
Oil Natural Gas NGLs Total
(In thousands)
Revenues for the period ended in 2020 $265,767 $6,029 $18,123 $289,919
Volume increase (decrease) (52,999) (1,205) (4,332) (58,536)
Price increase (decrease) 54,277 19,396 15,566 89,239
Net increase (decrease) 1,278 18,191 11,234 30,703
Revenues for the period ended in 2021 (1)
$267,045 $24,220 $29,357 $320,622
Percent of total revenues 83 % 8 % 9 %


	Oil		Natural Gas		NGLs		Total
	(In thousands)
Revenues for the three months ended March 31, 2021 (1)	$267,045		$24,220		$29,357		$320,622
Volume increase	66,462		7,048		9,221		82,731
Price increase	219,742		12,708		29,040		261,490
Net increase	286,204		19,756		38,261		344,221
Revenues for the three months ended March 31, 2022 (1)	$553,249		$43,976		$67,618		$664,843

Percent of total revenues	83	%	7	%	10	%

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

~~Oil revenue~~

~~For~~Revenues for the three months ended March 31, ~~2021, oil revenues~~2022 of ~~$267.0~~$664.8 million increased ~~$44.3~~$31.9 million, or ~~20%~~5%, compared to revenues of ~~$222.7~~$632.9 million for the three months ended December 31, ~~2020.~~2021. The increase was primarily attributable to a ~~39%~~23% increase in the average realized sales price for oil which rose to ~~$57.05~~$94.64 per Bbl from ~~$41.06~~$77.13 per Bbl. The increase in average realized price for oil was partially offset by a 9% decrease in production, as discussed above, as well as a 14% decrease in the average realized price for natural gas.

Revenues for the three months ended March 31, 2022 of $664.8 million increased $344.2 million, or 107%, compared to revenues of $320.6 million for the same period of 2021. The increase was primarily attributable to a 66% increase in the average realized sales price ~~was partially offset by a 14% decrease in production primarily as a result~~ of ~~normal production decline and the February 2021 winter storms.~~

~~For the three months ended March 31, 2021,~~ oil revenues of $267.0 million increased $1.3 million, or less than 1%, compared to revenues of $265.8 million for the same period of 2020. The slight increase was primarily attributable to a 26% increase in the average realized sales price which rose to $94.64 per Bbl from $57.05 per Bbl ~~from $45.45 per Bbl. The~~as well as a 27% increase in ~~the average realized sales price was almost completely offset by a 20% decrease in~~ production ~~primarily~~ as ~~a result of normal production decline and the February 2021 winter storms.~~

~~Natural gas revenue~~

For the three months ended March 31, 2021, natural gas revenues of $24.2 million increased $5.7 million, or 30%, compared to revenues of $18.6 million for the three months ended December 31, 2020. The increase was primarily attributable to the 62% increase in the average realized sales price which rose to $3.09 per Mcf from $1.91 per Mcf. The increase in the average realized sales price was partially offset by a 20% decrease in production primarily as a result of normal production decline and the February 2021 winter storms.

For the three months ended March 31, 2021, natural gas revenues of $24.2 million increased $18.2 million, or 302%, compared to revenues of $6.0 million for the same period of 2020. The increase was primarily attributable to a 398% increase in the average realized sales price which rose to $3.09 per Mcf from $0.62 per Mcf. The increase in the average realized sales price was partially offset by a 20% decrease in production primarily as a result of normal production decline and the February 2021 winter storms.discussed above.

3024

~~NGL revenue~~

For the three months ended March 31, 2021, NGL revenues of $29.4 million increased $3.7 million, or 14%, compared to revenues of $25.7 million for three months ended December 31, 2020. The increase was primarily attributable to a 48% increase in the average realized sales price which rose to $22.60 per Bbl from $15.24 per Bbl. The increase in the average realized sales price was partially offset by a 23% decrease in production primarily as a result of normal production decline and the February 2021 winter storms.

For the three months ended March 31, 2021, NGL revenues of $29.4 million increased $11.2 million, or 62%, compared to revenues of $18.1 million for the same period of 2020. The increase was primarily attributable to a 113% increase in the average realized sales price which rose to $22.60 per Bbl from $10.62 per Bbl. The increase in the average realized sales price was partially offset by a 24% decrease in production primarily as a result of normal production decline and the February 2021 winter storms.

Operating Expenses


		Three Months Ended																	Three Months Ended
		March 31, 2021		Per	December 31, 2020		Per		Total Change					Boe Change					March 31, 2022		Per	December 31, 2021		Per		Total Change					Boe Change
			Boe			Boe		$		%			$		%					Boe			Boe		$		%			$		%
			(In thousands, except per Boe and % amounts)																	(In thousands, except per Boe and % amounts)
Lease operating	Lease operating	$40,453		$5.55	$45,010		$5.15		($4,557)		(10	%)		$0.40		8	%	Lease operating	$67,328		$7.29	$73,522		$7.11		($6,194)		(8	%)		$0.18		3	%
Production and ad valorem taxes	Production and ad valorem taxes	18,439		2.53	16,487		1.89		1,952		12	%		0.64		34	%	Production and ad valorem taxes	37,678		4.08	33,693		3.26		3,985		12	%		0.82		25	%
Gathering, transportation and processing	Gathering, transportation and processing	17,981		2.47	20,694		2.37		(2,713)		(13	%)		0.10		4	%	Gathering, transportation and processing	20,775		2.25	22,083		2.14		(1,308)		(6	%)		0.11		5	%
Depreciation, depletion and amortization	Depreciation, depletion and amortization	70,987		9.74	96,037		11.00		(25,050)		(26	%)		(1.26)		(11	%)	Depreciation, depletion and amortization	102,979		11.15	112,551		10.89		(9,572)		(9	%)		0.26		2	%
General and administrative	General and administrative	16,799		2.31	10,614		1.22		6,185		58	%		1.09		89	%	General and administrative	17,121		1.85	13,116		1.27		4,005		31	%		0.58		46	%
Impairment of evaluated oil and gas properties		—		—	585,767		67.08		(585,767)		(100	%)		(67.08)		(100	%)
Merger and integration		—		—	2,120		0.24		(2,120)		(100	%)		(0.24)		(100	%)

Merger, integration and transaction																		Merger, integration and transaction	769		0.08	11,271		1.09		(10,502)		(93	%)		(1.01)		(93	%)

Three Months Ended March 31,
Per Per Total Change Boe Change
2021 Boe 2020 Boe $ % $ %
(In thousands, except per Boe and % amounts)
Lease operating $40,453 $5.55 $52,383 $5.70 ($11,930) (23 %) ($0.15) (3 %)
Production and ad valorem taxes 18,439 2.53 19,680 2.14 (1,241) (6 %) 0.39 18 %
Gathering, transportation and processing 17,981 2.47 14,378 1.57 3,603 25 % 0.90 57 %
Depreciation, depletion and amortization 70,987 9.74 131,463 14.31 (60,476) (46 %) (4.57) (32 %)
General and administrative 16,799 2.31 8,325 0.91 8,474 102 % 1.40 154 %
Merger and integration — — 15,830 1.72 (15,830) (100 %) (1.72) (100 %)


	Three Months Ended
	March 31, 2022	Per	March 31, 2021	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Lease operating	$67,328	$7.29	$40,453	$5.55	$26,875	66	%	$1.74	31	%
Production and ad valorem taxes	37,678	4.08	18,439	2.53	19,239	104	%	1.55	61	%
Gathering, transportation and processing	20,775	2.25	17,981	2.47	2,794	16	%	(0.22)	(9	%)
Depreciation, depletion and amortization	102,979	11.15	70,987	9.74	31,992	45	%	1.41	14	%
General and administrative	17,121	1.85	16,799	2.31	322	2	%	(0.46)	(20	%)

Merger, integration and transaction	769	0.08	—	—	769	—	%	0.08	—	%

Lease ~~operating expenses.~~Operating Expenses. These are daily costs incurred to extract oil, natural gas and NGLs and maintain our producing properties. Such costs also include maintenance, repairs, salt water disposal, insurance and workover expenses related to our oil and natural gas properties.

Lease operating expenses for the three months ended March 31, ~~2021~~2022 decreased to ~~$40.5~~$67.3 million compared to ~~$45.0~~$73.5 million for the three months ended December 31, ~~2020,~~2021, primarily due to a 9% decrease in production, ~~volumes decreasing 17%.~~as discussed above, as well as changing service providers and improving the efficiency of operations, partially offset by an increase in workover expenses as well as an increase in certain operating expenses such as repairs and maintenance. Lease operating expense per Boe for the three months ended March 31, ~~2021~~2022 increased to ~~$5.55~~$7.29 compared to ~~$5.15~~$7.11 for the three months ended December 31, ~~2020,~~2021, primarily due to ~~increased~~higher workover costs ~~as well as~~and the distribution of fixed costs spread over lower production volumes.

Lease operating expenses for the three months ended March 31, ~~2021 decreased~~2022 increased to ~~$40.5~~$67.3 million compared to ~~$52.4~~$40.5 million for the same period of ~~2020,~~2021, primarily due to the increase in production ~~volumes decreasing 21%.~~from wells acquired in the Primexx Acquisition as well as increases in certain operating expenses such as repairs and maintenance. Lease operating expense per Boe for the three months ended March 31, ~~2021 decreased~~2022 increased to ~~$5.55~~$7.29 compared to ~~$5.70~~$5.55 for the same period of ~~2020~~2021, primarily due to ~~improved field practices~~the increase in certain operating expenses as discussed above as well as the increase in certain operating expenses associated with the Primexx Acquisition.

Production and ~~operational efficiencies.~~

Ad Valorem Taxes. For the three months ended March 31, 2022, production and ad valorem taxes increased 12% to $37.7 million compared to $33.7 million for the three months ended December 31, 2021, which is primarily related to a 5% increase in total revenues which increased production taxes, as well as an increase in ad valorem taxes due to higher expected property tax valuations for the first quarter of 2022 as a result of higher commodity prices during 2021 compared to 2020. Production and ad valorem ~~taxes.~~ ~~In general, severance~~ taxes ~~are based upon current year commodity prices whereas~~as a percentage of total revenues increased to 5.7% for the first quarter of 2022 as compared to 5.3% of total revenues for the three months ended December 31, 2021, primarily due to an increase in ad valorem taxes ~~are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage~~during the first quarter of revenues from products sold at fixed rates established by federal, state or local taxing authorities. We benefit from tax credits and exemptions in our various taxing jurisdictions where available and applicable. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties.2022 as discussed above.

For the three months ended March 31, ~~2021,~~2022, production and ad valorem taxes increased ~~12%~~104% to $37.7 million compared to $18.4 million ~~compared to $16.5 million~~ for the ~~three months ended December 31, 2020,~~same period of 2021, which is primarily related to a ~~20%~~107% increase in total revenues which increased production ~~taxes.~~taxes, as well as an increase in ad valorem taxes as discussed in the paragraph above. Production and ad valorem taxes as a percentage of total revenues decreased to ~~5.8%~~5.7% for ~~the first quarter of 2021 as~~

compared to 6.2% of total revenues for the three months ended December 31, 2020, primarily due to lower expected property tax valuations for the first quarter of 2021 as a result of lower commodity prices during 2020.

~~For~~ the three months ended March 31, 2021, production and ad valorem taxes decreased 6% to $18.4 million compared to $19.7 million for the same period of 2020, which is primarily related to lower expected property tax valuations for the first quarter of 2021 as a result of lower commodity prices during 2020 compared to higher property tax valuations for the first quarter of 2020 as a result of higher commodity prices during 2019. The impact of the lower expected property tax valuations for the first quarter of 2021 is partially offset by a 11% increase in total revenues which led to higher production taxes. Production and ad valorem taxes as a percentage of total revenues decreased to 5.8% for the first quarter of 20212022, as compared to ~~6.8%~~5.8% of total revenues for the same period of ~~2020, primarily due to lower expected property tax valuations for the first quarter of~~ 2021, as ~~a result of lower commodity prices during 2020.~~the 107% increase in total revenues was greater than the increase in ad valorem taxes, which does not increase proportionately with revenues.

Gathering, ~~transportation~~Transportation and ~~processing expenses~~Processing Expenses. For the three months ended March 31, ~~2021,~~2022, gathering, transportation and processing expenses decreased ~~13%~~6% to ~~$18.0~~$20.8 million compared to ~~$20.7~~$22.1 million for the three months ended December 31, ~~2020,~~2021, which is primarily related to the ~~17%~~9% decrease in production volumes between the two periods.

For the three months ended March 31, ~~2021,~~2022, gathering, transportation and processing expenses increased ~~25%~~16% to ~~$18.0~~$20.8 million compared to ~~$14.4~~$18.0 million for the same period of ~~2020,~~2021, which iswas primarily related to ~~new oil transportation agreements which were executed subsequent to~~ the ~~three months ended March 31, 2020.~~27% increase in production volumes between the two periods.

Depreciation, ~~depletion~~Depletion and ~~amortization~~Amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically amortize those costs on an equivalent unit-of-production method based on production and estimated proved oil and gas reserve quantities. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to twenty years. The following table sets forth the components of our ~~depreciation, depletion and amortization~~DD&A for the periods indicated:


		Three Months Ended				Three Months Ended March 31,					Three Months Ended				Three Months Ended
		March 31, 2021		December 31, 2020		2021		2020				March 31, 2022		December 31, 2021		March 31, 2022		March 31, 2021
		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	DD&A of evaluated oil and gas properties	$68,705	$9.43	$93,721	$10.73	$68,705	$9.43	$129,436	$14.09				DD&A of evaluated oil and gas properties	$100,763	$10.91	$110,169	$10.66	$100,763	$10.91	$68,705	$9.43
Depreciation of other property and equipment	Depreciation of other property and equipment	516	0.07	640	0.07	516	0.07	943	0.10				Depreciation of other property and equipment	476	0.05	473	0.05	476	0.05	516	0.07
Amortization of other assets	Amortization of other assets	839	0.11	854	0.10	839	0.11	262	0.03				Amortization of other assets	780	0.08	980	0.09	780	0.08	839	0.11
Accretion of asset retirement obligations	Accretion of asset retirement obligations	927	0.13	822	0.10	927	0.13	822	0.09				Accretion of asset retirement obligations	960	0.11	929	0.09	960	0.11	927	0.13
DD&A	DD&A	$70,987	$9.74	$96,037	$11.00	$70,987	$9.74	$131,463	$14.31				DD&A	$102,979	$11.15	$112,551	$10.89	$102,979	$11.15	$70,987	$9.74

For the three months ended March 31, ~~2021,~~2022, DD&A decreased to ~~$71.0~~$103.0 million from ~~$96.0~~$112.6 million for the three months ended December 31, ~~2020. The decrease in DD&A was primarily related to DD&A of evaluated oil and gas properties, which was~~2021 primarily attributable to a production decrease of 17% and lower DD&A rates between the periods. For the three months ended March 31, 2021, DD&A per Boe decreased to $9.74 compared to $11.00 for the three months ended December 31, 2020, primarily as a result of the impairment of evaluated oil and gas properties that was recognized during the three months ended December 31, 2020.9%.

For the three months ended March 31, ~~2021,~~2022, DD&A ~~decreased~~increased to ~~$71.0~~$103.0 million from ~~$131.5~~$71.0 million for the same period in ~~2020. The decrease in DD&A was primarily related to DD&A of evaluated oil and gas properties, which was~~2021 primarily attributable to a production ~~decrease~~increase of ~~21% and lower DD&A rates between~~27% as well as the ~~periods. For~~addition of properties acquired in the three months ended March 31, 2021, DD&A per Boe decreased to $9.74 compared to $14.31 for the same period in 2020, primarily as a result of the impairments of evaluated oil and gas properties that were recognized during 2020.Primexx Acquisition.

General and ~~administrative, net~~Administrative, Net of ~~amounts capitalized~~Amounts Capitalized (“G&A”). G&A for the three months ended March 31, ~~2021~~2022 increased to ~~$16.8~~$17.1 million compared to ~~$10.6~~$13.1 million for the three months ended December 31, ~~2020,~~2021, primarily ~~as a result of~~due to an increase in the fair value of ~~Cash-Settled RSU Awards and~~ Cash SARs ~~due to~~as a result of the increase in our stock price ~~during~~between the ~~first quarter of 2021.~~two periods.

G&A for the three months ended March 31, ~~2021~~2022 increased to ~~$16.8~~$17.1 million compared to ~~$8.3~~$16.8 million for the same period in ~~2020~~2021 primarily due to an increase in compensation costs as we increased headcount during 2021, partially offset by a reduction in expense associated with the Cash-Settled RSU Awards and Cash SARs as a result of a smaller increase in the fair value associated with these awards during the first quarter of 2022 as compared to the same ~~reason discussed above.~~

~~Impairment of evaluated oil and gas properties.~~ We did not recognize an impairment of evaluated oil and gas properties for the three months ended March 31, 2021, compared to an impairment of evaluated oil and gas properties of $585.8 million for the three months ended December 31, 2020, which was due primarily to declinesperiod in the 12-Month Average Realized Price of crude oil. There was no impairment of evaluated oil and gas properties for the three months ended March 31, 2020. See “Note 3 - Property and Equipment, Net” for further discussion.

~~Merger and integration expense.~~ For the three months ended March 31, 2021, the Company incurred no merger and integration expenses compared to $2.1 million and $15.8 million for the three months ended December 31, 2020 and March 31, 2020, respectively, which were related to the Carrizo Acquisition.2021.

Other Income and Expenses

Three Months Ended Three Months Ended March 31,
March 31, 2021 December 31, 2020 $ Change % Change 2021 2020 $ Change % Change
(In thousands, except % amounts)
Interest expense $48,454 $49,501 ($1,047) (2 %) $48,454 $44,463 $3,991 9 %
Capitalized interest (24,038) (23,015) (1,023) 4 % (24,038) (23,985) (53) — %
Interest expense, net of capitalized amounts 24,416 26,486 (2,070) (8 %) 24,416 20,478 3,938 19 %
(Gain) loss on derivative contracts $214,523 $125,739 $88,784 71 % $214,523 ($251,969) $466,492 (185 %)

Interest ~~expense, net~~Expense, Net of ~~capitalized amounts~~Capitalized Amounts.. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees, and interest from our financing leases in interest expense. The following table sets forth the components of our interest expense, net of capitalized amounts for the periods indicated:


		Three Months Ended			Three Months Ended March 31,				Three Months Ended			Three Months Ended
		March 31, 2021	December 31, 2020	$ Change	2021	2020	$ Change		March 31, 2022	December 31, 2021	Change	March 31, 2022	March 31, 2021	Change
		(In thousands)							(In thousands)
Interest expense on Senior Unsecured Notes								Interest expense on Senior Unsecured Notes	$29,022	$29,022	$—	$29,022	$24,502	$4,520
Interest expense on Second Lien Notes								Interest expense on Second Lien Notes	7,192	8,916	(1,724)	7,192	11,625	(4,433)
Interest expense on Credit Facility	Interest expense on Credit Facility	$7,817	$8,411	($594)	$7,817	$12,574	($4,757)	Interest expense on Credit Facility	7,110	8,613	(1,503)	7,110	7,817	(707)
Interest expense on Second Lien Notes		11,625	9,188	2,437	11,625	—	11,625
Interest expense on Senior Unsecured Notes		24,502	27,688	(3,186)	24,502	30,875	(6,373)
Amortization of debt issuance costs, premiums and discounts	Amortization of debt issuance costs, premiums and discounts	4,478	4,176	302	4,478	948	3,530	Amortization of debt issuance costs, premiums and discounts	3,750	4,235	(485)	3,750	4,478	(728)
Other interest expense	Other interest expense	32	38	(6)	32	66	(34)	Other interest expense	22	32	(10)	22	32	(10)
Capitalized interest	Capitalized interest	(24,038)	(23,015)	(1,023)	(24,038)	(23,985)	(53)	Capitalized interest	(25,538)	(25,592)	54	(25,538)	(24,038)	(1,500)
Interest expense, net of capitalized amounts	Interest expense, net of capitalized amounts	$24,416	$26,486	($2,070)	$24,416	$20,478	$3,938	Interest expense, net of capitalized amounts	$21,558	$25,226	($3,668)	$21,558	$24,416	($2,858)

Interest expense, net of capitalized amounts, incurred during the three months ended March 31, ~~2021~~2022 decreased ~~$2.1~~$3.7 million to ~~$24.4~~$21.6 million compared to ~~$26.5~~$25.2 million for the three months ended December 31, ~~2020.~~2021. The decrease is primarily due to ~~a decrease in borrowings on~~ the Credit Facility, lower average principal balances on our Senior Unsecured Notes as a portion was exchanged for Second Lien Notes during the three months ended December 31, 2020, as well as an increase in capitalized interest. The decrease in interest expense was offset by an increasereduction in interest expense associated with the Second Lien Notes ~~which were~~as a result of our exchange of $197.0 million of our outstanding ~~during~~Second Lien Notes for a notional amount of approximately $223.1 million of our common stock in November 2021, as well as lower borrowings on the ~~entire first quarter of~~Credit Facility compared to the three months ended December 31, 2021.

Interest expense, net of capitalized amounts, incurred during the three months ended March 31, ~~2021 increased $3.9~~2022 decreased $2.9 million to ~~$24.4~~$21.6 million compared to ~~$20.5~~$24.4 million for the same period of ~~2020.~~2021. The ~~increase~~decrease is primarily due to the ~~issuance of the Second Lien Notes~~reduction in ~~exchange for a portion of our outstanding Senior Unsecured Notes during the three months ended December 31, 2020 as well as amortization of the discount~~interest expense associated with the Second Lien Notes ~~offset by the reduction in Senior Unsecured Notes outstanding as a result of the~~ exchange ~~and~~discussed above, lower borrowings on the Credit Facility ~~during~~compared to the same period of ~~2020.~~

~~(Gain) loss on derivative contracts.~~ ~~We utilize commodity derivative financial instruments to reduce our exposure to fluctuations~~2021 and an increase in ~~commodity prices. This amount represents the (i) (gain) loss~~capitalized interest, partially offset by an increase in interest expense related to ~~fair value adjustments on our open derivative contracts and (ii)~~the issuance of the 8.00% Senior Notes in July 2021.

3326

~~(gains) losses~~(Gain) Loss on ~~settlements of derivative contracts for positions that have settled within the period.~~Derivative Contracts. The net ~~(gain)~~ loss on derivative ~~instruments~~contracts for the periods indicated includes the following:


		Three Months Ended		Three Months Ended March 31,		Three Months Ended		Three Months Ended
		March 31, 2021	December 31, 2020	2021	2020			March 31, 2022	December 31, 2021	March 31, 2022	March 31, 2021
		(In thousands)						(In thousands)
(Gain) loss on oil derivatives		$149,561	$70,317	$149,561	($257,323)
Loss on oil derivatives							Loss on oil derivatives	$325,348	$35,364	$325,348	$149,561
(Gain) loss on natural gas derivatives	(Gain) loss on natural gas derivatives	2,697	(3,936)	2,697	6,829		(Gain) loss on natural gas derivatives	28,181	(14,918)	28,181	2,697
(Gain) loss on NGL derivatives	(Gain) loss on NGL derivatives	1,138	8	1,138	—		(Gain) loss on NGL derivatives	4,771	(8,346)	4,771	1,138
(Gain) loss on contingent consideration arrangements	(Gain) loss on contingent consideration arrangements	5,737	3,831	5,737	(1,475)		(Gain) loss on contingent consideration arrangements	—	(1,955)	—	5,737
(Gain) loss on September 2020 Warrants liability		55,390	55,519	55,390	—
(Gain) loss on derivative contracts		$214,523	$125,739	$214,523	($251,969)
Loss on September 2020 Warrants liability							Loss on September 2020 Warrants liability	—	—	—	55,390
Loss on derivative contracts							Loss on derivative contracts	$358,300	$10,145	$358,300	$214,523

See “Note 67 - Derivative Instruments and Hedging Activities” and “Note 78 - Fair Value Measurements” for additional information.

Income ~~tax expense.~~Tax Expense. We ~~use the asset and liability method~~recorded income tax expense of ~~accounting for~~$0.5 million compared to income ~~taxes, under which deferred~~ tax ~~assets and liabilities are recognized~~benefit of $0.8 million for the ~~future tax consequences of (1) temporary differences between the financial statement carrying amounts~~three months ended March 31, 2022 and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate, based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized.December 31, 2021, respectively.

We recorded anincome tax expense of $0.5 million compared to income tax benefit of $0.9 million for the three months ended March 31, 2022 and 2021, ~~compared to income tax expense of $6.8 million for~~respectively.

Since the ~~three months ended December 31, 2020. The decrease in income tax expense is due to an increase in the fourth~~second quarter of 2020, inwe have concluded that it is more likely than not that the deferred tax assets acquired in the Carrizo Acquisition due to the filing of the final tax returns which provided the underlying tax basis of Carrizo’s assets and liabilities and the subsequent valuation allowance against those deferred tax assets.

~~As a result of the valuation allowance that we recorded 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 ~~recorded an income tax benefit of $0.9 million for~~continue to conclude that the ~~three months ended March 31, 2021 compared~~valuation allowance is necessary, we do not expect to anhave significant deferred income tax expense ~~of $64.0 million for the same period of 2020.~~or benefit. See “Note 89 - Income Taxes” for further discussion.

Liquidity and Capital Resources

2022 Outlook. Oil prices steadily increased throughout 2021 and into the first quarter of 2022, reaching a 13-year high in March 2022. As a result of a corresponding increase in industry drilling and completion activity over that period, combined with the supply chain and labor constraints, we have begun to experience inflationary cost pressures on many different service items including labor, materials, and equipment. We expect to continue to face inflationary pressure throughout the remainder of 2022.

2022 Capital Budget and Funding Strategy. Our primary uses of capital are for the exploration and development of our oil and natural gas properties. Our ~~2021 Capital Budget~~2022 capital budget has been established at ~~up to $430.0~~$725.0 million, with ~~approximately 80% directed towards drilling, completion, and equipment expenditures. Approximately 70% of the 2021 Capital Budget is~~over 85% allocated towards development in the Permian with the ~~remaining 30%~~balance towards development in the Eagle Ford. ~~As part of our 2021 operated horizontal drilling program, we expect to drill approximately 55 to 65 gross operated wells and complete approximately 90 to 100 gross operated wells.~~

During the three months ended March 31, 2021, we drilled 18 gross (16.4 net) and completed 19 gross (18.0 net) wells approximately evenly split between the Permian and Eagle Ford in each category, effectively maintaining the drilled but uncompleted inventory that we had as of December 31, 2020. We expect to operate an average of three drilling rigs throughout the remainder of 2021 and will average just over two completion crews through the second quarter before reducing to a single completion crew during the third quarter.

~~The following table is a summary of our capital expenditures(1)~~ ~~for the three months ended March 31, 2021:~~


						~~Three Months Ended March 31, 2021~~
						~~(In millions)~~
~~Operational capital~~						~~$95.6~~
~~Capitalized interest~~						~~24.0~~
~~Capitalized G&A~~						~~11.2~~
~~Total~~						~~$130.8~~

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

~~We continually evaluate our capital expenditure needs and compare them to our capital resources.~~ Because we are the operator of a high percentage of our properties, we can control the amount and timing of our capital expenditures. We ~~can choose~~plan to ~~defer or accelerate~~execute a ~~portion~~moderated capital expenditure program through reduced reinvestment rates and balanced capital deployment for a more consistent cash flow generation and will be focused to further enhance our multi-zone, scaled development program to drive capital efficiency.

The following table is a summary of our ~~planned~~capital expenditures(1) for the three months ended March 31, 2022:

Three Months Ended

March 31, 2022

(In millions)

Operational capital

$157.4

Capitalized interest

25.5

Capitalized G&A

11.6

Total

$194.5

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

We believe that existing cash and cash equivalents, any positive cash flows from operations and available borrowings under our revolving credit facility will be sufficient to support working capital, capital expenditures ~~depending~~and other cash requirements for at least the next 12 months and, based on ~~various~~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, ~~depressed~~ 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. ~~We plan to execute a more~~

moderated capital expenditure program through reduced reinvestment rates and balanced capital deployment for a more consistent cash flow generation and will be focused to further enhance our multi-zone, scale development program while leveraging a robust drilled, but uncompleted backlog to drive capital efficiency.

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 debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and

liquidity requirements. In addition, ~~depending~~we may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth or enter into joint venture agreements, provided we are able to divest such assets or enter into joint venture agreements on terms that are acceptable to us.

Depending upon our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may, from time to time, seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or through privately negotiated transactions or otherwise. The amounts involved in any such transactions, individually or in aggregate, may be material.

We also may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth or enter into joint venture agreements, provided we are able to divest such assets or enter into joint venture agreements on terms that are acceptable to us.

~~CommodityPrices~~

~~Prices of oil, natural gas, and NGLs remain volatile and will affect the following aspects of our business:~~

•~~our revenues, cash flows and earnings;~~

•~~the amount of oil and natural gas that we are economically able to produce;~~

•~~our ability to attract capital to finance our operations and cost of the capital;~~

•~~the amount we are allowed to borrow under the Credit Facility; and~~

•~~the value of our oil and natural gas properties.~~

Overview of Cash Flow Activities. For the three months ended March 31, ~~2021,~~2022, cash and cash equivalents ~~increased $4.2~~decreased $5.7 million to ~~$24.4~~$4.2 million compared to ~~$20.2~~$9.9 million at December 31, ~~2020.~~2021.


		Three Months Ended March 31,			Three Months Ended March 31,
		2021	2020		2022	2021
		(In thousands)			(In thousands)
Net cash provided by operating activities	Net cash provided by operating activities	$137,665	$191,695	Net cash provided by operating activities	$281,270	$137,665
Net cash used in investing activities	Net cash used in investing activities	(98,514)	(254,366)	Net cash used in investing activities	(221,939)	(98,514)
Net cash provided by (used in) financing activities		(35,037)	64,130
Net cash used in financing activities				Net cash used in financing activities	(65,063)	(35,037)
Net change in cash and cash equivalents	Net change in cash and cash equivalents	$4,114	$1,459	Net change in cash and cash equivalents	($5,732)	$4,114

Operating ~~activities.~~Activities. For the three months ended March 31, ~~2021,~~2022, net cash provided by operating activities was ~~$137.7~~$281.3 million compared to ~~$191.7~~$137.7 million for the same period in ~~2020.~~2021. The change in net cash provided by operating activities was predominantly attributable to the following:

•~~A decrease in the cash received from commodity derivative settlements,~~

•~~Changes in working capital as accounts receivable has increased from December 31, 2020 as a result of the increase in the price of oil,~~

•An ~~offsetting~~ increase in revenue primarily driven by a ~~26%~~66% increase in realized oil price, ~~partially offset by~~as well as a ~~decrease~~27% increase in production volumes, and

•An offsetting ~~decrease~~increase in ~~operating expenses as a result of lower production volumes as well as our continued improvement of managing our field operating costs.~~the cash paid for commodity derivative settlements.

Production, realized prices, and operating expenses are discussed in Results of Operations. See “Note 67 - Derivative Instruments and Hedging Activities” and “Note 78 - 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.~~Activities. For the three months ended March 31, ~~2021,~~2022, net cash used in investing activities was ~~$98.5~~$221.9 million compared to ~~$254.4~~$98.5 million for the same period in ~~2020.~~2021. The ~~decrease~~increase in net cash used in investing activities was primarily attributed to the following:

•~~A decrease~~An increase in operational capex, ~~in the first quarter of 2021 compared to the same period in 2020,~~ and

•~~A decrease~~An increase in cash paid for the settlement of contingent consideration agreements as ~~net~~a cash ~~payments~~payment of ~~$40.0~~$19.2 million ~~were~~was paid in January ~~2020 related to contingent considerations acquired in the Carrizo Acquisition.~~2022.

Financing ~~activities.~~Activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under the Credit Facility, term debt and equity offerings. For the three months ended March 31, ~~2021,~~2022, net cash used in financing activities was ~~$35.0~~$65.1 million compared to ~~net cash provided by financing activities of $64.1~~$35.0 million for the same period of ~~2020.~~2021. This change was primarily attributable to repayment of approximately ~~$35.0~~$73.0 million on the Credit Facility during the three months ended March 31, ~~2021,~~2022, which reflects our continued commitment and focus on deleveraging.

~~See “Note 5 - Borrowings” for additional information on our debt transactions.~~

~~Contractual Obligations.~~ Our contractual obligations primarily consist of long-term debt, operating leases, asset retirement obligations, produced water disposal commitments, and gathering, processing and transportation service commitments. Since December 31, 2020, there have been no material changes to our contractual obligations other than the changes to the borrowings under our Credit Facility as discussed further in “Note 5 - Borrowings”.

Credit Facility. As of March 31, ~~2021,~~2022, our Credit Facility had a borrowing base of $1.6 billion, with an elected commitment amount of $1.6 billion, borrowings outstanding of ~~$950.0~~$712.0 million at a weighted average interest rate of ~~2.62%~~2.74%, and ~~$24.0~~$23.0 million in letters of credit outstanding. ~~The borrowing base under the credit agreement is subject to regular redeterminations in~~On May 2, 2022, as a result of the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering our major producing properties. Upon a2022 redetermination, if any borrowings in excess of the revised borrowing base were outstanding, we could be forced to immediately repay a portion of the borrowings outstanding under the credit agreement. On May 3, 2021, the Company entered into the fourth amendment to its credit agreement governing the Credit Facility which, among other things, reaffirmed the borrowing base and elected commitment amount of $1.6 billion ~~as a result of the spring 2021 scheduled redetermination.~~were reaffirmed.

Our Credit Facility contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. Under the Credit Facility, we must maintain the following financial covenants determined as of the last day of the ~~quarter, each as described above:~~quarter: (1) a ~~Secured~~ Leverage Ratio of no more than ~~3.00~~4.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. We were in compliance with these covenants at March 31, 2021. If the commodity price environment reverted back to levels the industry saw in 2020 and were to persist for an extended period, our ability to remain in compliance with our restrictive financial covenants could be challenged. If we are unable to remain in compliance with our restrictive financial covenants, we could be subject to lender elections for default resolution. However, we expect to have sufficient liquidity to pay interest on our Credit Facility (as well as on the Second Lien Notes and our Senior Unsecured Notes and to fund our development program).2022.

The Credit Facility also places restrictions on us and certain of our subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of our common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.

See “Note 56 – Borrowings” for additional information related to the Credit ~~Facility~~Facility.

Material Cash Requirements. As of March 31, 2022, we have financial obligations associated with our outstanding long-term debt, including interest payments and principal repayments. See “Note 147 - ~~Subsequent Events”~~Borrowings” of the Notes to Consolidated Financial Statements in our 2021 Annual Report for further discussion of the ~~fourth amendment to~~contractual commitments under our debt agreements, including the ~~credit agreement governing the Credit Facility.~~

timing of

3628

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 Annual Report for additional details.

~~Hedging.~~ ~~As of April 30, 2021, the Company had the following outstanding oil, natural gas and NGL derivative contracts:~~

For the Remainder For the Full Year
Oil contracts (WTI) of 2021 of 2022
   Swap contracts
   Total volume (Bbls) 1,832,000 225,000
   Weighted average price per Bbl $43.24 $60.00
   Collar contracts
   Total volume (Bbls) 8,298,800 2,032,500
   Weighted average price per Bbl
   Ceiling (short call) $48.30 $61.11
   Floor (long put) $40.24 $47.22
   Short call contracts
   Total volume (Bbls) 2,432,480 (1) —
   Weighted average price per Bbl $63.62 $—
Short call swaption contracts
   Total volume (Bbls) — 1,825,000 (2)
   Weighted average price per Bbl $— $52.18
Oil contracts (Brent ICE)
   Swap contracts
   Total volume (Bbls) 221,300 (3) —
   Weighted average price per Bbl $37.35 $—
Collar contracts
Total volume (Bbls) 550,000 —
Weighted average price per Bbl
Ceiling (short call) $50.00 $—
Floor (long put) $45.00 $—
Oil contracts (Midland basis differential)
   Swap contracts
   Total volume (Bbls) 2,171,900 —
   Weighted average price per Bbl $0.24 $—
Oil contracts (Argus Houston MEH)
   Collar contracts
   Total volume (Bbls) 409,500 452,500
   Weighted average price per Bbl
Ceiling (short call) $47.00 $63.15
Floor (long put) $41.00 $51.25

~~(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.~~

~~(2) The short call swaption contracts have an exercise expiration date of~~Since December 31, ~~2021.~~

~~(3) In February~~ 2021, there have been no material changes from what was disclosed in our 2021 Annual Report other than the ~~Company entered into certain offsetting ICE Brent swaps~~changes to ~~reduce its exposure to rising oil prices. Those offsetting swaps resulted in a locked-in loss~~the borrowings under our Credit Facility as well as an amended frac service contract through the remainder of 2022 for approximately ~~$2.9 million, of which $1.6 million will be settled in the third quarter of 2021 with the remaining $1.3 million to be settled in the fourth quarter of 2021.~~

For the Remainder For the Full Year
Natural gas contracts (Henry Hub) of 2021 of 2022
   Swap contracts
      Total volume (MMBtu) 11,123,000 —
      Weighted average price per MMBtu $2.60 $—
Collar contracts
      Total volume (MMBtu) 5,500,000 2,700,000
      Weighted average price per MMBtu
         Ceiling (short call) $2.80 $3.75
         Floor (long put) $2.50 $2.77
   Short call contracts
      Total volume (MMBtu) 5,500,000 (1) —
      Weighted average price per MMBtu $3.09 $—
Natural gas contracts (Waha basis differential)
   Swap contracts
      Total volume (MMBtu) 12,375,000 5,475,000
      Weighted average price per MMBtu ($0.42) ($0.21)

~~(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.~~

~~For the Remainder~~

~~For the Full Year~~

~~NGL contracts (OPIS Mont Belvieu Purity Ethane)~~

~~of 2021~~

~~of 2022~~

~~Swap contracts~~

~~Total volume (Bbls)~~

~~1,375,000~~

—

~~Weighted average price per Bbl~~

~~$7.62~~

$—

$30.0 million.

Critical Accounting ~~Policies~~Estimates

The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions ~~that affect the~~for reported amounts of assets, ~~and~~ liabilities, ~~and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of~~ revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. ~~We have identified the following critical accounting~~Our policies and ~~estimates used in the preparation of our financial statements:~~ use of ~~estimates, oil and gas properties, oil and gas reserve estimates, derivative instruments, contingent consideration arrangements, income taxes, and commitments and contingencies. These policies and~~ estimates are described in “Note 2 - Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our ~~2020~~2021 Annual Report. ~~See “Note 6 - Derivative Instruments~~Except as set forth below, there have been no material changes to our critical accounting estimates since December 31, 2021, which are disclosed in “Part II, Item 7A. Management’s Discussion and ~~Hedging Activities”~~Analysis of Financial Condition and ~~“Note 7 - Fair Value Measurements” for details~~Results of ~~the contingent consideration arrangements. We evaluate subsequent events through the date the financial statements are issued.~~Operations” of our 2021 Annual Report

Oil and Natural Gas Properties

The table below presents various pricing scenarios to demonstrate the sensitivity of our March 31, ~~2021~~2022 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the ~~12-month average realized prices.~~12-Month Average Realized Prices. The sensitivity analysis is as of March 31, ~~2021~~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 subsequent to March 31, ~~2021~~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” in our ~~2020~~2021 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)
March 31, 2021 Actual $37.51 $1.31 $89
Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10% $41.51 $1.53 $612 $523
Crude Oil and Natural Gas -10% $33.52 $1.09 ($552) ($641)
Crude Oil Price Sensitivity
Crude Oil +10% $41.51 $1.31 $568 $479
Crude Oil -10% $33.52 $1.31 ($496) ($585)
Natural Gas Price Sensitivity
Natural Gas +10% $37.51 $1.53 $133 $44
Natural Gas -10% $37.51 $1.09 $45 ($44)

~~Income taxes~~

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards.

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

our net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at March 31, 2021, driven primarily by impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the fourth quarter of 2020, which limits the ability to consider other subjective evidence such as our potential for future growth. Since the second quarter of 2020, based on the evaluation of the evidence available, we concluded that it is more likely than not that the net deferred tax assets will not be realized. As a result, we recorded a valuation allowance, reducing the net deferred tax assets as of March 31, 2021 to zero.

We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude us from utilizing the tax attributes if we recognize taxable income. As long as we continue to conclude that the valuation allowance against our net deferred tax assets is necessary, we will have no significant deferred income tax expense or benefit. See “Note 8 - Income Taxes” for additional discussion.


	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)
March 31, 2022 Actual	$74.41	$4.02	$3,749

Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$81.94	$4.43	$4,724	$975
Crude Oil and Natural Gas -10%	$66.89	$3.61	$2,774	($975)

Crude Oil Price Sensitivity
Crude Oil +10%	$81.94	$4.02	$4,643	$894
Crude Oil -10%	$66.89	$4.02	$2,855	($894)

Natural Gas Price Sensitivity
Natural Gas +10%	$74.41	$4.43	$3,829	$80
Natural Gas -10%	$74.41	$3.61	$3,669	($80)

Recently Adopted and Recently Issued Accounting ~~Pronouncements~~Standards

See “Note 1 - Description of Business and Basis of Presentation” 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, which are disclosed in “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of our 2021 Annual Report on Form 10-K.

Commodity ~~price risk~~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.

The following table sets forth oil, natural gas and NGL revenues for the three months ended March 31, 2021 as well as the impact on the oil, natural gas and NGL revenues assuming a 10% increase or decrease in our average realized sales prices for oil, natural gas and NGLs, excluding the impact ofWe enter into commodity derivative ~~settlements:~~

Three Months Ended March 31, 2021
Oil Natural Gas NGLs Total
(In thousands)
Revenues $267,045 $24,220 $29,357 $320,622
Impact of a 10% fluctuation in average realized prices $26,704 $2,422 $2,936 $32,062

~~From time to time, we enter into derivative financial~~ instruments to manage oil, natural gas and NGL price risk, related both to NYMEX benchmark prices and regional basis differentials.

The ~~total volumes we hedge through use~~following table sets forth the fair values of our commodity derivative instruments ~~varies from period to period. Generally our objective is to hedge approximately~~ ~~60%~~ of our anticipated internally forecasted production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices.

~~As of March 31, 2021, for the remainder of 2021, we had~~ ~~11,311,600~~ ~~Bbls of fixed price oil hedges across NYMEX WTI, ICE Brent and Argus WTI-Houston benchmarks. We also had~~ ~~2,171,900~~ ~~Bbls of WTI Midland-Cushing oil basis hedges. Additionally, for the remainder of 2021, we had~~ ~~16,623,000~~ ~~MMBtus of fixed price NYMEX natural gas hedges and~~ ~~12,375,000~~ ~~MMBtus of Waha natural gas basis hedges. See “Note 6 - Derivative Instruments and Hedging Activities” for a description of our outstanding derivative contracts~~ as of March 31, ~~2021.~~2022, excluding deferred premium obligations, 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 March 31, 2022:

~~We may utilize fixed price swaps, which reduce our exposure to decreases in commodity~~


	Three Months Ended March 31, 2022
	Oil	Natural Gas	Total
	(In thousands)
Fair value liability as of March 31, 2022 (1)	($339,160)	($23,881)	($363,041)

Impact of a 10% increase in forward commodity prices	($451,638)	($32,264)	($483,902)
Impact of a 10% decrease in forward commodity prices	($229,700)	($15,607)	($245,307)

(1)Spot prices but limits the benefit we might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales.

~~We also may utilize price collars to reduce the risk of changes in~~for oil and natural gas ~~prices. Under these arrangements, no payments are due by either party~~were $99.66 and $5.64, respectively, as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counterparty to the collar pays the difference to us, and if the price rises above the ceiling, the counterparty receives the difference from us. Additionally, we may sell put options at a price lower than the floor price in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of ~~the sold put option (or above the ceiling price of the sold call option), our net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis.~~

We may purchase put options, which reduce our exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to us.

We enter into these various agreements from time to time to reduce the effects of volatile oil, natural gas and NGL prices and do not enter into derivative transactions for speculative or trading purposes. Presently, none of our derivative positions are designated as hedges for accounting purposes.March 31, 2022.

Interest ~~rate risk~~Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of March 31, ~~2021,~~2022, we had ~~$950.0~~$712.0 million outstanding under the Credit Facility with a weighted average interest rate of ~~2.62%~~2.74%. 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 ~~$9.5~~$7.1 million, based on the balance outstanding as of March 31, ~~2021.~~2022. See “Note 56 - Borrowings” for more information on our Credit Facility.

~~Counterparty and customer credit risk~~

Our principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts.

We market our oil, natural gas and NGL production to energy marketing companies and are subject to credit risk due to the concentration of our oil, natural gas and NGL receivables with several significant customers. The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. At March 31, 2021, our total receivables from the sale of our oil, natural gas and NGL production were approximately ~~$125.6 million~~.

Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. We generally have the right to withhold future revenue distributions to recover past due receivables from joint interest owners. The allowance for credit losses related to our joint interest receivables is immaterial. At March 31, 2021, our joint interest receivables were approximately ~~$21.2 million~~.

Our oil, natural gas and NGL commodity derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. All of the counterparties of our commodity derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional commodity derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing ISDA Agreements with our commodity derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a commodity derivative, whereby the party not in default may offset all commodity derivative liabilities owed to the defaulting party against all commodity derivative asset receivables from the defaulting party. At March 31, 2021, we had a net commodity derivative liability position of ~~$207.4 million~~.

Item 4. Controls and Procedures

Disclosure ~~controls~~Controls and ~~procedures.~~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 March 31, ~~2021.~~2022.

Changes in ~~internal control over financial reporting~~Internal Control Over Financial Reporting. There were no changes in our internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred during the first quarter of ~~2021~~2022 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

We are ~~not currently~~ a party ~~to, nor is our property currently subject to, any material~~in various legal proceedings ~~other than~~and claims, which arise in the ordinary ~~routine litigation incidental to~~course of our business. While the ~~business, and~~outcome of these events cannot be predicted with certainty, we ~~are not aware~~believe that the ultimate resolution of any such ~~proceedings contemplated by governmental authorities.~~actions will not have a material effect on our financial position or results of operations.

In January 2022, we received a Notice of Violation from the United States Environmental Protection Agency related to the Clean Air Act. The enforcement action will likely result in monetary sanctions yet-to-be specified and corrective actions, which may increase our development costs and/or operating costs. We are unable to predict the ultimate outcome of this matter at this time, however, we believe that any penalties, mitigation costs, or corrective actions that may result from this matter will not have a material adverse effect on our consolidated financial position, results of operations, or cash flows.

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 ~~2020~~2021 Annual Report on Form 10-K. 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

On January 20, 2021, we issued 0.5 million shares of common stock upon the cashless exercise of a portion of the outstanding November 2020 Warrants by the holders thereof. On February 23, 2021, we issued 5.6 million shares of common stock upon the cashless exercise of all of the September 2020 Warrants by the holders thereof. Also on February 23, 2021, we issued 0.3 million shares of common stock upon the cashless exercise of a portion of the outstanding November 2020 Warrants by the holders thereof. These warrant exercises were exempt from registration pursuant to Section 3(a)(9) of the Securities Act.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 11/03/2016
3.2
Certificate of Amendment to the Certificate of Incorporation of Callon, effective December 20, 2019
8-K 3.1 11/20/2019
3.3
Certificate of Amendment to the Certificate of Incorporation of Callon, effective August 7, 2020
8-K 3.1 8/07/2020
3.4
Amended and Restated Bylaws of the Company
10-K 3.2 2/27/2019
10.1 (c)
Form of Callon Petroleum Company Restricted Stock Unit Agreement, adopted on March 12, 2021 under the 2020 Omnibus Incentive Plan.
8-K 10.1 4/16/2021
10.2 (c)
Form of Callon Petroleum Company Cash Performance Unit Agreement, adopted on March 12, 2021 under the 2020 Omnibus Incentive Plan.
8-K 10.2 4/16/2021
10.3 (c)
Form of Change in Control Severance Compensation Agreement, dated as of April 16, 2021, by and between Callon Petroleum Company and its executive officers.
8-K 10.3 4/16/2021
10.4 (c)
Change in Control Severance Compensation Agreement, dated as of April 16, 2021, by and between Callon Petroleum Company and Joseph C. Gatto, Jr.
8-K 10.4 4/16/2021
10.5 (c)
First Amendment to Callon Petroleum Company 2020 Omnibus Incentive Plan.
8-K 10.5 4/16/2021
10.6 (a)
Fourth Amendment, dated May 3, 2021, to the Credit Agreement by and between Callon Petroleum Company and JP Morgan Chase Bank N.A., as administrative agent, and the lender parties thereto.
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

Amended and Restated Bylaws of the Company

10-K

3.2

2/27/2019

10.1

(a)(c)

Form of Callon Petroleum Company Returns Program Cash Incentive Award Agreement, adopted on March 9, 2022 under the 2020 Omnibus Incentive Plan

10.2

(a)(c)

Form of Callon Petroleum Company Business Sustainability Cash Incentive Award Agreement, adopted on March 9, 2022 under the 2020 Omnibus Incentive Plan

31.1

(a)

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

31.2

(a)

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

32.1

(b)

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

101.INS

(a)

XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH

(a)

Inline XBRL Taxonomy Extension Schema Document

101.CAL

(a)

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

(a)

Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

(a)

Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE

(a)

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104

(a)

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

(a)Filed herewith.

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

(c)Indicates management compensatory plan, contract, or arrangement.

4231

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	May ~~6, 2021~~5, 2022
Joseph C. Gatto, Jr.	Chief Executive Officer


/s/ ~~James P. Ulm, II~~Kevin Haggard	Senior Vice President and	May ~~6, 2021~~5, 2022
~~James P. Ulm, II~~Kevin Haggard	Chief Financial Officer

4332


Part I. Financial Information

Item 1. Financial Statements (Unaudited)

Consolidated Balance Sheets			53

Consolidated Statements of Operations			64

Consolidated Statements of Stockholders’ Equity			75

Consolidated Statements of Cash Flows			86

Notes to Consolidated Financial Statements			97

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			2721

Item 3. Quantitative and Qualitative Disclosures about Market Risk			3929

Item 4. Controls and Procedures			4130

Part II. Other Information

Item 1. Legal Proceedings			4130

Item 1A. Risk Factors			4130

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			4131

Item 3. Defaults Upon Senior Securities			4131

Item 4. Mine Safety Disclosures			4131

Item 5. Other Information			4131

Item 6. Exhibits			4231


	Year	Threshold (1)	Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Payment - Annual	Remaining Contingent Payments - Aggregate Limit
					(In thousands)
Remaining Potential Settlement	2021	$50.00	(2)	(2)	($25,000)	($25,000)


	As of March 31, 2021
	Presented without		As Presented with
	Effects of Netting	Effects of Netting	Effects of Netting
	(In thousands)
Assets
Commodity derivative instruments	$69,473	($69,352)	$121
Contingent consideration arrangements	5,375	0	5,375
Other current assets	$74,848	($69,352)	$5,496
Commodity derivative instruments	3,790	(3,351)	439
Contingent consideration arrangements	0	0	0
Other assets, net	$3,790	($3,351)	$439

Liabilities
Commodity derivative instruments (1)	($275,885)	$69,352	($206,533)
Contingent consideration arrangements	(17,913)	0	(17,913)
Fair value of derivatives - current	($293,798)	$69,352	($224,446)
Commodity derivative instruments (2)	(4,751)	3,351	(1,400)
Contingent consideration arrangements	0	0	0
Fair value of derivatives - non-current	($4,751)	$3,351	($1,400)


	As of December 31, 2020
	Presented without		As Presented with
	Effects of Netting	Effects of Netting	Effects of Netting
	(In thousands)
Assets
Commodity derivative instruments	$21,156	($20,235)	$921
Contingent consideration arrangements	0	0	0
Other current assets	$21,156	($20,235)	$921
Commodity derivative instruments	$0	$0	$0
Contingent consideration arrangements	1,816	0	1,816
Other assets, net	$1,816	$0	$1,816

Liabilities
Commodity derivative instruments (1)	($117,295)	$20,235	($97,060)
Contingent consideration arrangements	0	0	0
Fair value of derivatives - current	($117,295)	$20,235	($97,060)
Commodity derivative instruments	$0	$0	$0
Contingent consideration arrangements	(8,618)	0	(8,618)
September 2020 Warrants liability	(79,428)	0	(79,428)
Fair value of derivatives - non-current	($88,046)	$0	($88,046)


	Three Months Ended March 31, 2021				As of March 31, 2021
	Drilled		Completed		Drilled But Uncompleted		Producing
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Permian	10	8.4	9	8.2	28	23.8	850	741.8
Eagle Ford	8	8.0	10	9.8	35	35.0	660	592.1
Total	18	16.4	19	18.0	63	58.8	1,510	1,333.9