Callon Petroleum Co - Quarter Report: 2021 March (Form 10-Q)

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 March 31, 2021

☐ 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 shares of common stock outstanding as of April 30, 2021.

Table of Contents


Part I. Financial Information

Item 1. Financial Statements (Unaudited)

Consolidated Balance Sheets			5

Consolidated Statements of Operations			6

Consolidated Statements of Stockholders’ Equity			7

Consolidated Statements of Cash Flows			8

Notes to Consolidated Financial Statements			9

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			27

Item 3. Quantitative and Qualitative Disclosures about Market Risk			39

Item 4. Controls and Procedures			41

Part II. Other Information

Item 1. Legal Proceedings			41

Item 1A. Risk Factors			41

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			41

Item 3. Defaults Upon Senior Securities			41

Item 4. Mine Safety Disclosures			41

Item 5. Other Information			41

Item 6. Exhibits			42

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
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

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	—
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	—
Depreciation, depletion and amortization	70,987	131,463
General and administrative	16,799	8,325

Merger and integration	—	15,830

Other operating	929	—
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

(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 - Stockholders’ Equity” for additional information.

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	—	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	—	10,240
Cash paid for settlements of contingent consideration arrangements, net	—	(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

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. The Company’s primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable cash flow generating business in the Eagle Ford.

Basis of Presentation

The accompanying unaudited interim consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and 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 all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim financial position, results of operations and cash flows. However, the results of operations for the periods presented are not necessarily indicative of the results of operations that may be expected for the full year. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications did not have a material impact on prior period financial statements.

Significant Accounting Policies

The Company’s significant accounting policies are described in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2020 (“2020 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 Annual Report.

Recently Adopted Accounting Standards

Income Taxes. In December 2019, the FASB released ASU No. 2019-12 (“ASU 2019-12”), 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 to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The amended standard is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company adopted ASU 2019-12 on January 1, 2021. The adoption of ASU 2019-12 did not have a material impact to the Company’s consolidated financial statements or disclosures.

Recently Issued Accounting Pronouncements

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. As of March 31, 2021, 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 5 – 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 14 - Subsequent Events” for further discussion.

Note 2 - Revenue Recognition

Revenue from contracts with customers

Oil sales

Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received. The Company has certain oil sales that occur at market locations downstream 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, transportation and processing” in its consolidated statements of operations.

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 entity 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.

Accounts receivable from revenues from contracts with customers

Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at March 31, 2021 and December 31, 2020 of $125.6 million and $100.3 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

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 - Property and Equipment, Net

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


	March 31, 2021	December 31, 2020
Oil and natural gas properties, full cost accounting method	(In thousands)
Evaluated properties	$8,001,847	$7,894,513
Accumulated depreciation, depletion, amortization and impairments	(5,607,508)	(5,538,803)
Evaluated properties, net	2,394,339	2,355,710
Unevaluated properties
Unevaluated leasehold and seismic costs	1,530,897	1,532,304
Capitalized interest	223,871	200,946
Total 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	$60,388	$60,287
Accumulated depreciation	(28,953)	(28,647)
Other property and equipment, net	$31,435	$31,640

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 million and $7.5 million for the three months ended March 31, 2021 and 2020, respectively. The Company capitalized interest costs to unproved properties totaling $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 not recognize an impairment of evaluated oil and gas properties for the three months ended March 31, 2020.

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)	$—		$—
Beginning of period 12-Month Average Realized Price ($/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	—	%	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 4 - 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 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)	—	17
Dilutive impact of warrants (1)	—	—
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

(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 5 - 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

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

Senior secured revolving credit facility

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

weighted-average interest rate of 2.62%, and letters of credit outstanding of $24.0 million. The credit agreement governing the Credit Facility provides for interest-only payments until December 20, 2024 (subject to 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) if 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 6.125% Senior Notes, in each case, to 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. 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 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 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.

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

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, 6.125% Senior Notes, 8.25% Senior Notes due 2025, and 6.375% Senior Notes due 2026 (together the “Senior Unsecured Notes”) also place restrictions on the Company and certain of its subsidiaries with respect to 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.

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 6 - Derivative Instruments and Hedging Activities

Objectives and strategies for using derivative instruments

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

Counterparty risk and offsetting

The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“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, the Company has outstanding commodity derivative instruments with fifteen 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 7 - Fair Value Measurements” for further discussion.

Financial statement presentation and settlements

Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price 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)

$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 for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the divestiture date fair value with any excess classified as cash flows from operating activities. If either of the commodity price thresholds is reached in 2021, $8.5 million of the contingent receipt will be presented in cash flows from financing activities with the remainder presented in cash flows from operating activities.

As a result 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, $19.2 million of the contingent payment will be presented in cash flows from investing activities with the remainder presented in cash flows from operating activities.

Warrants

On September 30, 2020, the Company issued $300.0 million in aggregate principal amount of its Second Lien Notes and warrants for 7.3 million shares of the Company’s common stock exercisable only on a net share settlement basis (the “September 2020 Warrants”).

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 gains 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

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 loss on derivative 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 the fair value of derivative contracts on a net basis in the consolidated balance sheets. 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	—	5,375
Other current assets	$74,848	($69,352)	$5,496
Commodity derivative instruments	3,790	(3,351)	439
Contingent consideration arrangements	—	—	—
Other assets, net	$3,790	($3,351)	$439

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

(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 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	—	—	—
Other current assets	$21,156	($20,235)	$921
Commodity derivative instruments	$—	$—	$—
Contingent consideration arrangements	1,816	—	1,816
Other assets, net	$1,816	$—	$1,816

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

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

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


	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	—
(Gain) loss on contingent consideration arrangements	5,737	(1,475)
(Gain) loss on September 2020 Warrants liability	55,390	—
(Gain) loss on derivative contracts	$214,523	($251,969)

The components of “Cash received (paid) for commodity derivative settlements, net” and “Cash 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)	—
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	$—	($40,000)

Derivative positions

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


	For the Remainder		For the Full Year
Oil contracts (WTI)	of 2021		of 2022
Swap contracts
Total volume (Bbls)	1,832,000		—
Weighted average price per Bbl	$43.24		$—
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)	—
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 December 31, 2021.

(3) In February 2021, the Company entered into certain offsetting ICE Brent swaps to reduce its exposure to rising oil prices. Those offsetting swaps resulted in a locked-in loss of 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		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)	—
Weighted average price per MMBtu	$3.09		$—

Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	12,375,000		—
Weighted average price per MMBtu	($0.42)		$—

(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

$—

Note 7 - 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 of financial instruments

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

Debt. The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s Second Lien Notes and Senior Unsecured Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “Note 5 - 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

Assets and liabilities measured at fair value on a recurring basis

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

Commodity derivative instruments. The fair value of commodity derivative instruments is derived using a third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and 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 6 - 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 and December 31, 2020:


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

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

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

(2) Includes approximately $11.2 million of deferred premiums which the Company will pay as the applicable contracts settle.

September 2020 Warrants. The fair value of the September 2020 Warrants was calculated using a Black Scholes-Merton option pricing model. As historical volatility is a significant input into the model, the September 2020 Warrants were designated as Level 3 within the valuation hierarchy.

In February 2021, holders of the September 2020 Warrants provided notice 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. See “Note 6 - Derivative Instruments and Hedging Activities” for additional details.

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						$—

(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. 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 8 - 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 the three months ended March 31, 2021 and 2020, the Company’s effective income tax rates were 1% and 23%, respectively. The primary differences between the effective tax rates for the three months ended March 31, 2021 and 2020 were a result of 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 pre-tax loss and a net deferred tax asset position at March 31, 2021, 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 to zero.

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 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.

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:


	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	—	$—
Unvested, end of the period	1,210	$36.02	485	$69.50

(1)Includes zero 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.

Grant activity for the three months ended March 31, 2021 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 grant of long-term equity to only executives during the first quarter of 2020.

No performance-based RSU Equity Awards were granted 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 was 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 no 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	—	%

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

Cash-Settled RSU Awards

The table below summarizes the activity for 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	—	$—	86	$33.98
Vested	(1)	$107.80	(1)	$122.96
Did not vest at end of performance period	(1)	$107.80	—	$166.60
Forfeited	—	$—	—	$—
Unvested, end of the period	194	$47.15	171	$78.54

No Cash-Settled RSU Awards were granted during the three months ended March 31, 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 for Cash-Settled RSU 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.

Share-Based Compensation Expense (Benefit), Net

Share-based compensation expense associated with the RSU Equity Awards, Cash-Settled RSU Awards, 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,
	2021	2020
	(In thousands)
RSU Equity Awards	$2,608	$3,948
Cash-Settled RSU Awards	4,442	(1,996)
Cash SARs	4,866	(4,756)
	11,916	(2,804)
Less: amounts capitalized to oil and gas properties	(4,308)	(168)
Total share-based compensation expense (benefit), net	$7,608	($2,972)

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

Note 10 - 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”) 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” for additional details regarding the September 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 11 - 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

Note 12 - 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

Note 13 - 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	—	—
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

Note 14 - Subsequent Events

Fourth Amendment to 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 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.

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 and other risks include, but are not limited to, the risks described in Part I, Item 1A of our 2020 Annual Report and in all quarterly reports on Form 10-Q filed subsequently thereto. These factors include:

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

•weather conditions.

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 required by applicable law.

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

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

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

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

General

The following management’s discussion and analysis describes the principal factors affecting the Company’s 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 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.

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.

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 Highlights

•Total production for the three months ended March 31, 2021 was 81.0 MBoe/d, a decrease of 15% and 20% from the three months ended December 31, 2020 and March 31, 2020, respectively, primarily due to normal production decline and the shut-in of our operated production during the severe winter storms in February 2021.

•Operated drilling and completion activity for the three months ended March 31, 2021 along with our drilled but uncompleted and producing wells as of March 31, 2021 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

•Operational capital expenditures, exclusive of leasehold and seismic, for the first quarter of 2021 were $95.6 million, of which approximately 58% 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 Capital Budget and Funding Strategy” for additional details.

•Reduced borrowings outstanding under our Credit Facility by $35.0 million reflecting our continued emphasis on deleveraging our balance sheet.

•We recorded 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 million, or $5.46 per diluted share. The change from net

income to net loss 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 driven by an approximate 39% increase in the total average realized sales price compared to the first quarter of 2020 as well as a decrease in depreciation, depletion and amortization primarily driven by the recording of impairments of evaluated oil and gas properties during 2020. 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,
	March 31, 2021		December 31, 2020		$ Change	% Change		2021		2020		$ Change	% Change
Total production
Oil (MBbls)
Permian	3,088		3,445		(357)	(10	%)	3,088		3,594		(506)	(14	%)
Eagle Ford	1,593		1,980		(387)	(20	%)	1,593		2,253		(660)	(29	%)
Total oil (MBbls)	4,681		5,425		(744)	(14	%)	4,681		5,847		(1,166)	(20	%)

Natural gas (MMcf)
Permian	6,208		7,474		(1,266)	(17	%)	6,208		8,009		(1,801)	(22	%)
Eagle Ford	1,627		2,264		(637)	(28	%)	1,627		1,784		(157)	(9	%)
Total natural gas (MMcf)	7,835		9,738		(1,903)	(20	%)	7,835		9,793		(1,958)	(20	%)

NGLs (MBbls)
Permian	1,075		1,331		(256)	(19	%)	1,075		1,368		(293)	(21	%)
Eagle Ford	224		353		(129)	(37	%)	224		339		(115)	(34	%)
Total NGLs (MBbls)	1,299		1,684		(385)	(23	%)	1,299		1,707		(408)	(24	%)

Total Production (MBoe)
Permian	5,198		6,022		(824)	(14	%)	5,198		6,297		(1,099)	(17	%)
Eagle Ford	2,088		2,710		(622)	(23	%)	2,088		2,889		(801)	(28	%)
Total barrels of oil equivalent (MBoe)	7,286		8,732		(1,446)	(17	%)	7,286		9,186		(1,900)	(21	%)

Total daily production (Boe/d)	80,957		94,914		(13,957)	(15	%)	80,957		100,955		(19,998)	(20	%)
Oil as % of total daily production	64	%	62	%				64	%	64	%

Benchmark prices (1)
WTI (per Bbl)	$57.80		$42.60		$15.20	36	%	$57.80		$46.08		$11.72	25	%
Henry Hub (per Mcf)	2.72		2.76		(0.04)	(1	%)	2.72		1.87		0.85	45	%

Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)
Permian	$56.66		$41.02		$15.64	38	%	$56.66		$45.61		$11.05	24	%
Eagle Ford	57.80		41.12		16.68	41	%	57.80		45.21		12.59	28	%
Total oil (per Bbl)	57.05		41.06		15.99	39	%	57.05		45.45		11.60	26	%

Natural gas (per Mcf)
Permian	3.11		1.68		1.43	85	%	3.11		0.33		2.78	842	%
Eagle Ford	3.03		2.65		0.38	14	%	3.03		1.88		1.15	61	%
Total natural gas (per Mcf)	3.09		1.91		1.18	62	%	3.09		0.62		2.47	398	%

NGL (per Bbl)
Permian	22.68		15.00		7.68	51	%	22.68		11.02		11.66	106	%
Eagle Ford	22.24		16.16		6.08	38	%	22.24		9.00		13.24	147	%
Total NGLs (per Bbl)	22.60		15.24		7.36	48	%	22.60		10.62		11.98	113	%


	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	%

(1) Reflects calendar average daily spot market prices.

Revenues

The following table is intended to reconcile the change 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	%

(1) Excludes sales of oil and gas purchased from third parties.


	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	%

(1) Excludes sales of oil and gas purchased from third parties.

Oil revenue

For the three months ended March 31, 2021, oil revenues of $267.0 million increased $44.3 million, or 20%, compared to revenues of $222.7 million for the three months ended December 31, 2020. The increase was primarily attributable to a 39% increase in the average realized sales price which rose to $57.05 per Bbl from $41.06 per Bbl. The 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 $57.05 per Bbl from $45.45 per Bbl. The 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.

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
	March 31, 2021	Per	December 31, 2020	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Lease operating	$40,453	$5.55	$45,010	$5.15	($4,557)	(10	%)	$0.40	8	%
Production and ad valorem taxes	18,439	2.53	16,487	1.89	1,952	12	%	0.64	34	%
Gathering, transportation and processing	17,981	2.47	20,694	2.37	(2,713)	(13	%)	0.10	4	%
Depreciation, depletion and amortization	70,987	9.74	96,037	11.00	(25,050)	(26	%)	(1.26)	(11	%)
General and administrative	16,799	2.31	10,614	1.22	6,185	58	%	1.09	89	%
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	%)


	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	%)

Lease 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 decreased to $40.5 million compared to $45.0 million for the three months ended December 31, 2020, primarily due to production volumes decreasing 17%. Lease operating expense per Boe for the three months ended March 31, 2021 increased to $5.55 compared to $5.15 for the three months ended December 31, 2020, primarily due to increased workover costs as well as the distribution of fixed costs spread over lower production volumes.

Lease operating expenses for the three months ended March 31, 2021 decreased to $40.5 million compared to $52.4 million for the same period of 2020, primarily due to production volumes decreasing 21%. Lease operating expense per Boe for the three months ended March 31, 2021 decreased to $5.55 compared to $5.70 for the same period of 2020 primarily due to improved field practices and operational efficiencies.

Production and ad valorem taxes. In general, severance taxes are based upon current year commodity prices whereas ad valorem taxes are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage 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.

For the three months ended March 31, 2021, production and ad valorem taxes increased 12% to $18.4 million compared to $16.5 million for the three months ended December 31, 2020, which is primarily related to a 20% increase in total revenues which increased production taxes. Production and ad valorem taxes as a percentage of total revenues decreased to 5.8% 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 2021 as compared to 6.8% 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.

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

For the three months ended March 31, 2021, gathering, transportation and processing expenses increased 25% to $18.0 million compared to $14.4 million for the same period of 2020, which is primarily related to new oil transportation agreements which were executed subsequent to the three months ended March 31, 2020.

Depreciation, depletion and 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 for the periods indicated:


	Three Months Ended				Three Months Ended March 31,
	March 31, 2021		December 31, 2020		2021		2020
	Amount	Per Boe	Amount	Per Boe	Amount	Per Boe	Amount	Per Boe
	(In thousands, except per Boe)
DD&A of evaluated oil and gas properties	$68,705	$9.43	$93,721	$10.73	$68,705	$9.43	$129,436	$14.09
Depreciation of other property and equipment	516	0.07	640	0.07	516	0.07	943	0.10
Amortization of other assets	839	0.11	854	0.10	839	0.11	262	0.03
Accretion of asset retirement obligations	927	0.13	822	0.10	927	0.13	822	0.09
DD&A	$70,987	$9.74	$96,037	$11.00	$70,987	$9.74	$131,463	$14.31

For the three months ended March 31, 2021, DD&A decreased to $71.0 million from $96.0 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 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.

For the three months ended March 31, 2021, DD&A decreased to $71.0 million from $131.5 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 primarily attributable to a production decrease of 21% 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 $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.

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

G&A for the three months ended March 31, 2021 increased to $16.8 million compared to $8.3 million for the same period in 2020 primarily due 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 declines 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.

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 of 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,
	March 31, 2021	December 31, 2020	$ Change	2021	2020	$ Change
	(In thousands)
Interest expense on Credit Facility	$7,817	$8,411	($594)	$7,817	$12,574	($4,757)
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	4,478	4,176	302	4,478	948	3,530
Other interest expense	32	38	(6)	32	66	(34)
Capitalized interest	(24,038)	(23,015)	(1,023)	(24,038)	(23,985)	(53)
Interest expense, net of capitalized amounts	$24,416	$26,486	($2,070)	$24,416	$20,478	$3,938

Interest expense, net of capitalized amounts, incurred during the three months ended March 31, 2021 decreased $2.1 million to $24.4 million compared to $26.5 million for the three months ended December 31, 2020. 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 increase in interest expense associated with the Second Lien Notes which were outstanding during the entire first quarter of 2021.

Interest expense, net of capitalized amounts, incurred during the three months ended March 31, 2021 increased $3.9 million to $24.4 million compared to $20.5 million for the same period of 2020. The increase is primarily due to the issuance of the Second Lien Notes 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 associated with the Second Lien Notes, offset by the reduction in Senior Unsecured Notes outstanding as a result of the exchange and lower borrowings on the Credit Facility during the same period of 2020.

(Gain) loss on derivative contracts. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) (gain) loss related to fair value adjustments on our open derivative contracts and (ii)

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


	Three Months Ended		Three Months Ended March 31,
	March 31, 2021	December 31, 2020	2021	2020
	(In thousands)
(Gain) loss on oil derivatives	$149,561	$70,317	$149,561	($257,323)
(Gain) loss on natural gas derivatives	2,697	(3,936)	2,697	6,829
(Gain) loss on NGL derivatives	1,138	8	1,138	—
(Gain) loss on contingent consideration arrangements	5,737	3,831	5,737	(1,475)
(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)

See “Note 6 - Derivative Instruments and Hedging Activities” and “Note 7 - Fair Value Measurements” for additional information.

Income tax expense. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts 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.

We recorded an income tax benefit of $0.9 million for the three months ended March 31, 2021 compared to income tax expense of $6.8 million for the three months ended December 31, 2020. The decrease in income tax expense is due to an increase in the fourth quarter of 2020 in 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, we recorded an income tax benefit of $0.9 million for the three months ended March 31, 2021 compared to an income tax expense of $64.0 million for the same period of 2020. See “Note 8 - Income Taxes” for further discussion.

Liquidity and Capital Resources

2021 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 has been established at up to $430.0 million, with approximately 80% directed towards drilling, completion, and equipment expenditures. Approximately 70% of the 2021 Capital Budget is allocated towards development in the Permian with the remaining 30% 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 to defer or accelerate a portion of our planned capital expenditures depending on various 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 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.

Commodity Prices

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, cash and cash equivalents increased $4.2 million to $24.4 million compared to $20.2 million at December 31, 2020.


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

Operating activities. For the three months ended March 31, 2021, net cash provided by operating activities was $137.7 million compared to $191.7 million for the same period in 2020. The change in 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% increase in realized oil price, partially offset by a decrease in production volumes, and

•An offsetting decrease in operating expenses as a result of lower production volumes as well as our continued improvement of managing our field operating costs.

Production, realized prices, and operating expenses are discussed in Results of Operations. See “Note 6 - Derivative Instruments and Hedging Activities” and “Note 7 - Fair Value Measurements” for a reconciliation of the components of our derivative contracts and disclosures related to derivative instruments including their composition and valuation.

Investing activities. For the three months ended March 31, 2021, net cash used in investing activities was $98.5 million compared to $254.4 million for the same period in 2020. The decrease in investing activities was primarily attributed to the following:

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

•A decrease in cash paid for the settlement of contingent consideration agreements as net cash payments of $40.0 million were paid in January 2020 related to contingent considerations acquired in the Carrizo Acquisition.

Financing 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, net cash used in financing activities was $35.0 million compared to net cash provided by financing activities of $64.1 million for the same period of 2020. This change was primarily attributable to repayment of approximately $35.0 million on the Credit Facility during the three months ended March 31, 2021, 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, 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 million at a weighted average interest rate of 2.62%, and $24.0 million in letters of credit outstanding. 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 our major producing properties. Upon a 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.

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: (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. 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).

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 5 – Borrowings” for additional information related to the Credit Facility and “Note 14 - Subsequent Events” for further discussion of the fourth amendment to the credit agreement governing the Credit Facility.

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 December 31, 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

$—

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the 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 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 Annual Report. See “Note 6 - Derivative Instruments and Hedging Activities” and “Note 7 - Fair Value Measurements” for details of the contingent consideration arrangements. We evaluate subsequent events through the date the financial statements are issued.

The table below presents various pricing scenarios to demonstrate the sensitivity of our March 31, 2021 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-month average realized prices. The sensitivity analysis is as of March 31, 2021 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 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 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.

Recently Adopted and Recently Issued Accounting Pronouncements

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.

Commodity price risk

Our revenues are derived from the sale of our oil, natural gas and NGL production. The prices for oil, natural gas and NGLs remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, government actions, economic conditions, and weather conditions.

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 of 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 of our 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.

We may utilize fixed price swaps, which reduce our exposure to decreases in commodity 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 oil and natural gas prices. Under these arrangements, no payments are due by either party 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.

Interest rate risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of March 31, 2021, we had $950.0 million outstanding under the Credit Facility with a weighted average interest rate of 2.62%. 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 million, based on the balance outstanding as of March 31, 2021. See “Note 5 - 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 and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our management, with the participation of the Chief Executive Officer and Chief Financial Officer, performed an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2021.

Changes in 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 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 legal proceedings other than ordinary routine litigation incidental to the business, and we are not aware of any such proceedings contemplated by governmental authorities.

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 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.

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.

(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.

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
Joseph C. Gatto, Jr.	Chief Executive Officer


/s/ James P. Ulm, II	Senior Vice President and	May 6, 2021
James P. Ulm, II	Chief Financial Officer