cpe-20210930

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 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 55,850,147 shares of common stock outstanding as of October 29, 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			30

Item 3. Quantitative and Qualitative Disclosures about Market Risk			42

Item 4. Controls and Procedures			44

Part II. Other Information

Item 1. Legal Proceedings			44

Item 1A. Risk Factors			44

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			44

Item 3. Defaults Upon Senior Securities			44

Item 4. Mine Safety Disclosures			44

Item 5. Other Information			44

Item 6. Exhibits			45

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)


	September 30, 2021	December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents	$3,699	$20,236
Accounts receivable, net	216,116	133,109
Fair value of derivatives	18,605	921
Other current assets	30,110	24,103
Total current assets	268,530	178,369
Oil and natural gas properties, full cost accounting method:


Evaluated properties, net	2,565,601	2,355,710
Unevaluated properties	1,712,428	1,733,250
Total oil and natural gas properties, net	4,278,029	4,088,960

Other property and equipment, net	30,591	31,640

Deferred financing costs	19,274	23,643

Other assets, net	89,992	40,256
Total assets	$4,686,416	$4,362,868
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$442,053	$341,519


Fair value of derivatives	324,682	97,060
Other current liabilities	61,641	58,529
Total current liabilities	828,376	497,108
Long-term debt	2,809,610	2,969,264

Asset retirement obligations	58,703	57,209

Fair value of derivatives	15,250	88,046
Other long-term liabilities	41,448	40,239
Total liabilities	3,753,387	3,651,866
Commitments and contingencies
Stockholders’ equity:

Common stock, $0.01 par value, 78,750,000 and 52,500,000 shares authorized; 46,290,611 and 39,758,817 shares outstanding, respectively	463	398
Capital in excess of par value	3,365,121	3,222,959
Accumulated deficit	(2,432,555)	(2,512,355)
Total stockholders’ equity	933,029	711,002
Total liabilities and stockholders’ equity	$4,686,416	$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 September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020
Operating Revenues:
Oil	$409,293	$231,654	$1,009,780	$627,934
Natural gas	36,519	15,034	84,819	33,305
Natural gas liquids	58,097	23,025	124,079	55,627
Sales of purchased oil and gas	48,653	20,313	134,164	21,469
Total operating revenues	552,562	290,026	1,352,842	738,335

Operating Expenses:
Lease operating	42,706	45,870	129,619	149,091
Production and ad valorem taxes	26,070	16,110	66,467	46,151
Gathering, transportation and processing	20,875	22,200	58,887	56,615
Cost of purchased oil and gas	49,392	21,282	139,558	22,450
Depreciation, depletion and amortization	89,890	114,201	244,005	384,594
General and administrative	9,503	8,224	37,367	26,573
Impairment of evaluated oil and gas properties	—	684,956	—	1,961,474
Merger, integration and transaction	3,018	2,465	3,018	26,362

Other operating	—	4,425	3,366	8,548
Total operating expenses	241,454	919,733	682,287	2,681,858
Income (Loss) From Operations	311,108	(629,707)	670,555	(1,943,523)

Other (Income) Expenses:
Interest expense, net of capitalized amounts	27,736	24,683	76,786	67,843
(Gain) loss on derivative contracts	107,169	27,038	512,155	(97,966)
Gain on extinguishment of debt	(2,420)	—	(2,420)	—
Other (income) expense	4,305	(1,044)	3,217	(149)
Total other (income) expense	136,790	50,677	589,738	(30,272)

Income (Loss) Before Income Taxes	174,318	(680,384)	80,817	(1,913,251)
Income tax expense	(2,416)	—	(1,017)	(115,299)
Net Income (Loss)	$171,902	($680,384)	$79,800	($2,028,550)

Net Income (Loss) Per Common Share:
Basic	$3.71	($17.12)	$1.77	($51.09)
Diluted	$3.65	($17.12)	$1.69	($51.09)

Weighted Average Common Shares Outstanding:
Basic	46,290	39,746	45,063	39,707
Diluted	47,096	39,746	47,119	39,707

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
Net loss	—	—	—	(11,695)	(11,695)
Restricted stock	132	1	960	—	961

Balance at June 30, 2021	46,289	$463	$3,361,282	($2,604,457)	$757,288
Net income	—	—	—	171,902	171,902
Restricted stock	2	—	3,839	—	3,839

Balance at September 30, 2021	46,291	$463	$3,365,121	($2,432,555)	$933,029


				Retained
	Common		Capital in	Earnings	Total
	Stock		Excess	(Accumulated	Stockholders’
	Shares (1)	$	of Par	Deficit)	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
Net loss	—	—	—	(1,564,731)	(1,564,731)
Restricted stock	66	7	3,205	—	3,212

Balance at June 30, 2020	39,739	$3,974	$3,204,310	($1,326,900)	$1,881,384
Net loss	—	—	—	(680,384)	(680,384)
Restricted stock	11	1	3,008	—	3,009
Reverse stock split	—	(3,578)	3,578	—	—
Other	—	—	95	—	95
Balance at September 30, 2020	39,750	$397	$3,210,991	($2,007,284)	$1,204,104

(1) All share amounts have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 - Stockholders’ Equity” of the Notes to Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2020 for additional information.

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

Callon Petroleum Company

Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
Cash flows from operating activities:	2021	2020
Net income (loss)	$79,800	($2,028,550)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	244,005	384,594
Impairment of evaluated oil and gas properties	—	1,961,474
Amortization of non-cash debt related items, net	7,166	1,582
Deferred income tax expense	—	115,299
(Gain) loss on derivative contracts	512,155	(97,966)
Cash received (paid) for commodity derivative settlements, net	(238,378)	101,754
Gain on extinguishment of debt	(2,420)	—


Non-cash expense (benefit) related to share-based awards	11,984	(305)


Other, net	11,006	5,740
Changes in current assets and liabilities:
Accounts receivable	(83,227)	96,110
Other current assets	(8,701)	(6,556)
Accounts payable and accrued liabilities	74,443	(107,979)

Net cash provided by operating activities	607,833	425,197
Cash flows from investing activities:
Capital expenditures	(427,552)	(555,222)
Acquisition of oil and gas properties	(7,119)	(12,524)
Deposit for acquisition of oil and gas properties	(60,117)	—
Proceeds from sale of assets	35,415	149,818
Cash paid for settlements of contingent consideration arrangements, net	—	(40,000)
Other, net	4,206	8,261
Net cash used in investing activities	(455,167)	(449,667)
Cash flows from financing activities:
Borrowings on Credit Facility	1,236,500	5,087,500
Payments on Credit Facility	(1,498,500)	(5,347,500)

Redemption of 6.25% Senior Notes	(542,755)	—

Issuance of 8.00% Senior Notes due 2028	650,000	—
Issuance of 9.00% Second Lien Senior Secured Notes due 2025	—	300,000
Discount on the issuance of 9.00% Second Lien Senior Secured Notes due 2025	—	(35,270)
Issuance of September 2020 Warrants	—	23,909



Payment of deferred financing costs	(12,168)	(6,312)
Tax withholdings related to restricted stock units	(2,280)	(495)

Other, net	—	(203)
Net cash provided by (used in) financing activities	(169,203)	21,629
Net change in cash and cash equivalents	(16,537)	(2,841)
Balance, beginning of period	20,236	13,341
Balance, end of period	$3,699	$10,500

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

Note 1 - Description of Business and Basis of Presentation

Description of Business

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

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

Basis of Presentation

The accompanying unaudited interim consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances. These financial statements have been prepared pursuant to the rules and regulations of the SEC and therefore do not include all disclosures required for financial statements prepared in conformity with 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 September 30, 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 6 – 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 September 30, 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 15 - Subsequent Events” for further discussion.

Note 2 - Revenue Recognition

Revenue from Contracts with Customers

The Company recognizes oil, natural gas, and NGL production revenue at the point in time when control of the product transfers to the purchaser, which differs depending on the applicable contractual terms. Transfer of control also drives the presentation of gathering, transportation and processing in the consolidated statements of operations. See “Note 3 - Revenue Recognition” of the Notes to Consolidated Financial Statements in the 2020 Annual Report for more information regarding the types of contracts under which oil, natural gas, and NGL production revenue is generated.

Accounts Receivable from Revenues from Contracts with Customers

Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at September 30, 2021 and December 31, 2020 of $168.1 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 - Acquisitions and Divestitures

Primexx Acquisition

On August 3, 2021, the Company entered into purchase and sale agreements with Primexx Resource Development, LLC and BPP Acquisition, LLC (collectively, the “Primexx PSAs”) to purchase, effective as of July 1, 2021, certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin for total consideration of $440.0 million in cash and 9.19 million shares of the Company’s common stock, subject to customary purchase price adjustments (the “Primexx Acquisition”). Upon signing the Primexx PSAs, the Company paid approximately $60.1 million as a deposit into third-party escrow accounts, which is classified as cash flows from investing activities in the consolidated statements of cash flows.

On October 1, 2021, the Company closed the Primexx Acquisition for an adjusted purchase price of approximately $453.7 million in cash, inclusive of the deposit paid at signing, and 8.84 million shares of the Company’s common stock for total consideration of $864.6 million, subject to post-closing adjustments. The Company funded the cash portion of the total consideration with borrowings under its Credit Facility, as defined below. Of the 8.84 million shares of the Company’s common stock issued upon closing, 2.6 million shares were held in escrow pursuant to the Primexx PSAs. Additionally, 50% of the shares held in escrow will be released six months after the closing date, and the remaining shares will be released twelve months after the closing date, in each case subject to holdback for the satisfaction of any applicable indemnification claims that may be made under the Primexx PSAs. Also, pursuant to

the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration structured similarly to the Primexx Acquisition, for an incremental purchase price totaling approximately $37.5 million, net of customary purchase price adjustments.

The Primexx Acquisition will be accounted for as a business combination. The Company has not completed its initial allocation of the purchase price to the assets acquired and liabilities assumed based on their estimated acquisition date fair values. The Company will disclose the preliminary allocation of the purchase price as well as other related disclosures in its Annual Report on Form 10-K for the year ended December 31, 2021.

Non-Core Asset Divestitures

On September 27, 2021, the Company entered into a purchase and sale agreement for the divestiture of certain non-core assets in the Eagle Ford Shale. The transaction, which is comprised of producing properties as well as an undeveloped acreage position, has an agreed upon purchase price of approximately $100.0 million, subject to customary purchase price adjustments, and is expected to close during the fourth quarter of 2021. Upon signing the purchase and sale agreement, the purchaser paid $10.0 million as a deposit into a third-party escrow account which will be applied against the purchase price to be paid upon closing. The net proceeds will be recognized in the fourth quarter of 2021 as a reduction of evaluated oil and gas properties with no gain or loss recognized.

During the second quarter of 2021, the Company completed its divestitures of certain non-core assets in the Delaware Basin for aggregate net cash proceeds of $29.6 million. The divestitures were primarily comprised of natural gas producing properties in the Western Delaware Basin as well as a small undeveloped acreage position. The net proceeds were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized.

Note 4 - Property and Equipment, Net

As of September 30, 2021 and December 31, 2020, total property and equipment, net consisted of the following:


	September 30, 2021	December 31, 2020
Oil and natural gas properties, full cost accounting method	(In thousands)
Evaluated properties	$8,341,434	$7,894,513
Accumulated depreciation, depletion, amortization and impairments	(5,775,833)	(5,538,803)
Evaluated properties, net	2,565,601	2,355,710
Unevaluated properties
Unevaluated leasehold and seismic costs	1,453,255	1,532,304
Capitalized interest	259,173	200,946
Total unevaluated properties	1,712,428	1,733,250
Total oil and natural gas properties, net	$4,278,029	$4,088,960

Other property and equipment	$60,396	$60,287
Accumulated depreciation	(29,805)	(28,647)
Other property and equipment, net	$30,591	$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 $10.4 million and $10.3 million for the three months ended September 30, 2021 and 2020, respectively, and $33.7 million and $26.7 million for the nine months ended September 30, 2021 and 2020, respectively.

The Company capitalized interest costs to unproved properties totaling $26.1 million and $20.7 million for the three months ended September 30, 2021 and 2020, respectively, and $74.0 million and $65.6 million for the nine months ended September 30, 2021 and 2020, respectively.

Impairment of Evaluated Oil and Gas Properties

For the three and nine months ended September 30, 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 and nine months ended September 30, 2021.

Primarily due to declines in 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”) prior to September 30, 2020, the capitalized costs of oil and gas properties exceeded the cost center ceiling, resulting in an impairment in the carrying value of evaluated oil and gas properties for the three and nine months ended September 30, 2020.

Details of the 12-Month Average Realized Price of crude oil for the three and nine months ended September 30, 2021 and 2020 are summarized in the table below:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Impairment of evaluated oil and gas properties (in thousands)	$—		$684,956		$—		$1,961,474
Beginning of period 12-Month Average Realized Price ($/Bbl)	$48.06		$45.87		$37.44		$53.90
End of period 12-Month Average Realized Price ($/Bbl)	$56.47		$41.71		$56.47		$41.71
Percent increase (decrease) in 12-Month Average Realized Price	17	%	(9	%)	51	%	(23	%)

Note 5 - 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 and nine months ended September 30, 2020, the Company reported a net loss. As a result, the calculation of diluted weighted average common shares outstanding excluded all potentially dilutive common shares outstanding.

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020
	(In thousands, except per share amounts)



Net Income (Loss)	$171,902	($680,384)	$79,800	($2,028,550)
Basic weighted average common shares outstanding	46,290	39,746	45,063	39,707
Dilutive impact of restricted stock	305	—	244	—
Dilutive impact of warrants (1)	501	—	1,812	—
Diluted weighted average common shares outstanding	47,096	39,746	47,119	39,707

Net Income (Loss) Per Common Share
Basic	$3.71	($17.12)	$1.77	($51.09)
Diluted	$3.65	($17.12)	$1.69	($51.09)

Restricted stock (2)	8	703	28	506
Warrants (2)	481	560	481	508

(1) See “Note 15 - Subsequent Events” for discussion of warrants exercised.

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

Note 6 - Borrowings

The Company’s borrowings consisted of the following:


	September 30, 2021	December 31, 2020
	(In thousands)
6.25% Senior Notes due 2023	$—	$542,720
6.125% Senior Notes due 2024	460,241	460,241
Senior Secured Revolving Credit Facility due 2024	723,000	985,000
9.00% Second Lien Senior Secured Notes due 2025	516,659	516,659
8.25% Senior Notes due 2025	187,238	187,238
6.375% Senior Notes due 2026	320,783	320,783
8.00% Senior Notes due 2028	650,000	—
Total principal outstanding	2,857,921	3,012,641
Unamortized premium on 6.25% Senior Notes	—	2,917
Unamortized premium on 6.125% Senior Notes	2,589	3,236
Unamortized discount on Second Lien Notes	(33,524)	(41,820)
Unamortized premium on 8.25% Senior Notes	2,668	3,240
Unamortized deferred financing costs for Second Lien Notes	(3,142)	(3,931)
Unamortized deferred financing costs for Senior Notes	(16,902)	(7,019)
Total carrying value of borrowings (1)	$2,809,610	$2,969,264

(1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $19.3 million and $23.6 million as of September 30, 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 September 30, 2021, had a borrowing base and elected commitment amount of $1.6 billion, with borrowings outstanding of $723.0 million at a weighted-average interest rate of 2.35%, 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 remaining springing maturity dates of (i) July 2, 2024 if the 6.125% Senior Notes due 2024 (the “6.125% Senior Notes”) are outstanding at such time and (ii) 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 6.125% Senior Notes, 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.

On November 1, 2021, the Company entered into the fifth 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 fall 2021 scheduled redetermination.

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.

Issuance of 8.00% Senior Notes and Redemption of 6.25% Senior Notes

On June 21, 2021, the Company entered into a Purchase Agreement pursuant to which it agreed to issue and sell $650.0 million in aggregate principal amount of 8.00% senior unsecured notes due 2028 (the “8.00% Senior Notes”) in a private placement, which closed on July 6, 2021, for proceeds of approximately $638.1 million, net of underwriting discounts and commissions and offering costs. The 8.00% Senior Notes mature on August 1, 2028 and interest is payable semi-annually each February 1 and August 1, commencing on February 1, 2022.

At any time prior to August 1, 2024, the Company may, from time to time, redeem up to 35% of the aggregate principal amount of the 8.00% Senior Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 108.00% of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65% of the aggregate principal amount of the 8.00% Senior Notes remains outstanding after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to August 1, 2024, the Company may, at its option, on any one or

more occasions, redeem all or a portion of the 8.00% Senior Notes at 100.00% of the principal amount plus an applicable make-whole premium and accrued and unpaid interest. On or after August 1, 2024, the Company may redeem all or a portion of the 8.00% Senior Notes at redemption prices decreasing annually from 104.00% to 100.00% of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain kinds of change of control, the Company must make an offer to repurchase all or a portion of each holder’s 8.00% Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest.

Also on June 21, 2021, the Company delivered a redemption notice with respect to all $542.7 million of its outstanding 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”), which became redeemable on July 21, 2021. The Company used a portion of the net proceeds from the 8.00% Senior Notes to redeem all of its outstanding 6.25% Senior Notes and the remaining proceeds to partially repay amounts outstanding under the Credit Facility. The Company recognized a gain on extinguishment of debt of approximately $2.4 million in its consolidated statements of operations, which was primarily related to writing off the remaining unamortized premium associated with the 6.25% Senior Notes.

Second Lien Notes Exchange

On August 3, 2021, the Company entered into an agreement with Chambers Investments, LLC (“Kimmeridge”), a private investment vehicle managed by Kimmeridge Energy Management, LLC, to exchange $197.0 million of its outstanding Second Lien Notes for a notional amount of approximately $223.1 million of the Company’s common stock (the “Exchange”). The value of equity to be delivered is based on the optional redemption language in the indenture for the Second Lien Notes. The price of the Company’s common stock used to calculate the shares issued is based on the 10-day volume-weighted average price as of August 2, 2021 and equates to 5.5 million shares.

The Exchange was contingent upon, among other things, (i) the closing of the Primexx Acquisition, which occurred on October 1, 2021, and (ii) the approval of the Company’s shareholders, as required under New York Stock Exchange rules, of the issuance of approximately 5.5 million shares of the Company’s common stock to Kimmeridge in the Exchange. A special meeting of shareholders was held on November 3, 2021, at which time the requisite shareholder approval for the issuance was obtained. The exchange is anticipated to close on November 5, 2021. See “Note 15 - Subsequent Events” for further discussion.

Restrictive Covenants

The Company’s credit agreement governing the Credit Facility 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 (as defined in the credit agreement governing the Credit Facility) of no more than 3.00 to 1.00 and (2) a Current Ratio (as defined in the credit agreement governing the Credit Facility) of not less than 1.00 to 1.00. The Company was in compliance with these covenants at September 30, 2021.

The credit agreement governing the Credit Facility and the indentures governing the Company’s 6.125% Senior Notes, 8.25% Senior Notes due 2025, 6.375% Senior Notes due 2026 and 8.00% Senior Notes due 2028 (together with the 6.25% Senior Notes, 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 7 - 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 September 30, 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 8 - 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 8 - 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 8 - 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 in the first quarter of 2022.

Contingent ExL Consideration. 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. As of September 30, 2021, the Contingent ExL Consideration, as summarized below, is the only contingent consideration arrangement remaining from the Carrizo Acquisition.


	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 in the first quarter of 2022.

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 were 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 8 - 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 “(Gain) 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 September 30, 2021
	Presented without		As Presented with
	Effects of Netting	Effects of Netting	Effects of Netting
	(In thousands)
Assets
Commodity derivative instruments	$64,151	($64,113)	$38
Contingent consideration arrangements	18,567	—	18,567
Fair value of derivatives - current	$82,718	($64,113)	$18,605
Commodity derivative instruments	$7,278	($7,278)	$—
Contingent consideration arrangements	—	—	—
Other assets, net	$7,278	($7,278)	$—

Liabilities
Commodity derivative instruments (1)	($364,107)	$64,113	($299,994)
Contingent consideration arrangements	(24,688)	—	(24,688)
Fair value of derivatives - current	($388,795)	$64,113	($324,682)
Commodity derivative instruments	($22,528)	$7,278	($15,250)
Contingent consideration arrangements	—	—	—
Fair value of derivatives - non-current	($22,528)	$7,278	($15,250)

(1) Includes approximately $6.6 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	—	—	—
Fair value of derivatives - current	$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 September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020
	(In thousands)
(Gain) loss on oil derivatives	$67,198	$16,606	$393,792	($118,348)
(Gain) loss on natural gas derivatives	33,026	7,296	48,539	18,819
(Gain) loss on NGL derivatives	10,242	2,421	15,114	2,418
(Gain) loss on contingent consideration arrangements	(3,297)	715	(680)	(855)
(Gain) loss on September 2020 Warrants liability	—	—	55,390	—
(Gain) loss on derivative contracts	$107,169	$27,038	$512,155	($97,966)

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 September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020
	(In thousands)
Cash flows from operating activities
Cash received (paid) on oil derivatives	($98,752)	$2,130	($221,112)	$100,823
Cash received (paid) on natural gas derivatives	(9,592)	(1,677)	(12,867)	931
Cash received (paid) on NGL derivatives	(2,463)	—	(4,399)	—
Cash received (paid) for commodity derivative settlements, net	($110,807)	$453	($238,378)	$101,754

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 September 30, 2021:


	For the Remainder		For the Full Year		For the Full Year
Oil contracts (WTI)	2021		2022		2023
Swap contracts
Total volume (Bbls)	1,748,000		3,240,000		—
Weighted average price per Bbl	$56.87		$64.00		$—
Collar contracts
Total volume (Bbls)	2,290,450		7,097,500		—
Weighted average price per Bbl
Ceiling (short call)	$46.97		$67.70		$—
Floor (long put)	$39.37		$56.15		$—
Long put contracts
Total volume (Bbls)	414,000		—		—
Weighted average price per Bbl	$62.50		$—		$—
Short call contracts
Total volume (Bbls)	1,216,240	(1)	—		—
Weighted average price per Bbl	$63.62		$—		$—
Short call swaption contracts
Total volume (Bbls)	—		1,825,000	(2)	1,825,000	(2)
Weighted average price per Bbl	$—		$52.18		$72.00

Oil contracts (Brent ICE) (3)



Collar contracts
Total volume (Bbls)	184,000		—		—
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)	892,400		—		—
Weighted average price per Bbl	$0.33		$—		$—

Oil contracts (Argus Houston MEH)
Collar contracts
Total volume (Bbls)	—		452,500		—
Weighted average price per Bbl
Ceiling (short call)	$—		$63.15		$—
Floor (long put)	$—		$51.25		$—

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

(2) The 2022 and 2023 short call swaption contracts have exercise expiration dates of December 31, 2021 and December 30, 2022, respectively.

(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 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)	2021		2022
Swap contracts
Total volume (MMBtu)	4,357,000		7,320,000
Weighted average price per MMBtu	$2.96		$3.08
Collar contracts
Total volume (MMBtu)	1,840,000		5,740,000
Weighted average price per MMBtu
Ceiling (short call)	$2.80		$3.64
Floor (long put)	$2.50		$2.83
Short call contracts
Total volume (MMBtu)	1,840,000	(1)	—
Weighted average price per MMBtu	$3.09		$—

Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	4,140,000		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)	2021	2022
Swap contracts
Total volume (Bbls)	460,000	378,000
Weighted average price per Bbl	$7.62	$15.70

NGL contracts (OPIS Mont Belvieu Propane)
Swap contracts
Total volume (Bbls)	266,800	252,000
Weighted average price per Bbl	$52.15	$48.43

NGL contracts (OPIS Mont Belvieu Butane)
Swap contracts
Total volume (Bbls)	101,200	99,000
Weighted average price per Bbl	$59.43	$54.39

NGL contracts (OPIS Mont Belvieu Isobutane)
Swap contracts
Total volume (Bbls)	55,200	54,000
Weighted average price per Bbl	$58.96	$54.29

Note 8 - 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 6 - Borrowings” for further discussion.


	September 30, 2021		December 31, 2020
	Principal Amount	Fair Value	Principal Amount	Fair Value
	(In thousands)
6.25% Senior Notes	$—	$—	$542,720	$344,627
6.125% Senior Notes	460,241	456,789	460,241	260,036
9.00% Second Lien Notes	516,659	561,867	516,659	470,160
8.25% Senior Notes	187,238	185,366	187,238	100,172
6.375% Senior Notes	320,783	311,160	320,783	161,995
8.00% Senior Notes	650,000	651,625	—	—
Total	$2,134,921	$2,166,807	$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 7 - 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 7 - Derivative Instruments and Hedging Activities” for further discussion.

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2021 and December 31, 2020:


	September 30, 2021
	Level 1	Level 2	Level 3
	(In thousands)
Assets
Commodity derivative instruments	$—	$38	$—
Contingent consideration arrangements	—	18,567	—
Liabilities
Commodity derivative instruments (1)	—	(315,244)	—
Contingent consideration arrangements	—	(24,688)	—
Total net assets (liabilities)	$—	($321,327)	$—

	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 $6.6 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 7 - 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 nine months ended September 30, 2021.


						Nine Months Ended September 30, 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, restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates.

Note 9 - 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 September 30, 2021 and 2020, the Company’s effective income tax rates were 1% and 0%, respectively, and for the nine months ended September 30, 2021 and 2020, the Company’s effective income tax rates were 1% and 6%, respectively. The primary differences between the effective tax rates for the three and nine months ended September 30, 2021 and 2020 and the statutory rate resulted from the valuation allowance recorded against the Company’s net deferred tax assets beginning in the second quarter of 2020 and the effect of state income taxes.

Deferred Tax Asset Valuation Allowance

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

the Company’s net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at September 30, 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 September 30, 2021 to zero. 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 10 - Share-Based Compensation

RSU Equity Awards

The following table summarizes activity for restricted stock units that may be settled in common stock (“RSU Equity Awards”) for the three and nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,
	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	1,035	$35.88	719	$39.99
Granted (1)	—	$—	6	$9.35
Vested (2)	(2)	$61.84	(14)	$99.88
Forfeited	(10)	$30.98	(12)	$46.51
Unvested, end of the period	1,023	$35.86	699	$38.46

	Nine Months Ended September 30,
	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)	636	$38.46	562	$21.07
Vested (2)	(207)	$39.51	(120)	$100.19
Forfeited	(83)	$36.18	(12)	$46.51
Unvested, end of the period	1,023	$35.86	699	$38.46

(1)Includes zero target performance-based RSU Equity Awards granted during both the three and nine months ended September 30, 2021 and zero and 111.2 thousand during the three and nine months ended September 30, 2020, respectively.

(2)The fair value of shares vested was $0.1 million during both the three months ended September 30, 2021 and 2020, and $7.9 million and $1.4 million for the nine months ended September 30, 2021 and 2020, respectively.

Grant activity for the nine months ended September 30, 2021 and 2020 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards.

No performance-based RSU Equity Awards were granted during the nine months ended September 30, 2021. For the performance-based RSU Equity Awards granted in the first half 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 zero and $3.4 million for the three and nine months ended September 30, 2020, respectively. The following table summarizes the assumptions used to calculate the grant date fair value of the performance-based RSU Equity Awards granted during the nine months ended September 30, 2020:


Performance-Based Awards	June 29, 2020		January 31, 2020
Expected term (in years)	2.5		2.9
Expected volatility	113.2	%	54.8	%
Risk-free interest rate	0.2	%	1.3	%
Dividend yield	—	%	—	%

As of September 30, 2021, unrecognized compensation costs related to unvested RSU Equity Awards were $25.4 million and will be recognized over a weighted average period of 2.2 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 and nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,
	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	174	$45.93	208	$67.20
Granted	—	$—	—	$—
Vested	—	$—	(1)	$131.54
Did not vest at end of performance period	—	$—	(2)	$133.95
Forfeited	—	$—	—	$—
Unvested, end of the period	174	$45.93	205	$66.28

	Nine Months Ended September 30,
	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 (1)	3	$36.71	125	$29.76
Vested	(1)	$110.48	(3)	$130.12
Did not vest at end of performance period	(1)	$110.48	(3)	$148.81
Forfeited	(23)	$54.57	—	$—
Unvested, end of the period	174	$45.93	205	$66.28

(1)Includes 3.2 thousand and 13.7 thousand units for the nine months ended September 30, 2021 and 2020, respectively, associated with deferrals of certain non-employee director compensation pursuant to the terms of the Amended and Restated Deferred Compensation Plan for Outside Directors.

No Cash-Settled RSU Awards were granted to employees during the nine months ended September 30, 2021. Grant activity in the first half 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 nine months ended September 30, 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:


	September 30, 2021	December 31, 2020
	(In thousands)
Other current liabilities	$661	$182
Other long-term liabilities	6,780	1,336
Total Cash-Settled RSU Awards	$7,441	$1,518

As of September 30, 2021, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $3.7 million and will be recognized over a weighted average period of 1.2 years.

Cash 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 September 30, 2021 and December 31, 2020 were $8.2 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 September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020
	(In thousands)
RSU Equity Awards	$3,839	$3,009	$9,689	$10,169
Cash-Settled RSU Awards	(1,344)	(566)	6,105	(1,966)
Cash SARs	(2,006)	(1,005)	6,536	(4,646)
	489	1,438	22,330	3,557
Less: amounts capitalized to oil and gas properties	(1,392)	(1,532)	(10,346)	(3,862)
Total share-based compensation expense (benefit), net	($903)	($94)	$11,984	($305)

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 11 - Stockholders’ Equity

Warrant Exercises

During the nine months ended September 30, 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 7 - Derivative Instruments and Hedging Activities” and “Note 8 - Fair Value Measurements” for additional details regarding the September 2020 Warrants. As of September 30, 2021, 0.6 million November 2020 Warrants were outstanding. See “Note 15 - Subsequent Events” for discussion of the exercise of the remaining November 2020 Warrants.

Note 12 - Accounts Receivable, Net


	September 30, 2021	December 31, 2020
	(In thousands)
Oil and natural gas receivables	$168,109	$100,257
Joint interest receivables	8,607	11,530
Other receivables	42,266	24,191
Total	218,982	135,978
Allowance for credit losses	(2,866)	(2,869)
Total accounts receivable, net	$216,116	$133,109

Note 13 - Accounts Payable and Accrued Liabilities


	September 30, 2021	December 31, 2020
	(In thousands)
Accounts payable	$74,881	$101,231
Revenues payable	259,842	162,762
Accrued capital expenditures	48,029	32,493
Accrued interest	59,301	45,033
Total accounts payable and accrued liabilities	$442,053	$341,519

Note 14 - Supplemental Cash Flow


	Nine Months Ended September 30,
	2021	2020
	(In thousands)
Supplemental cash flow information:
Interest paid, net of capitalized amounts	$62,638	$62,414
Income taxes paid	3,231	1,250
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$20,224	$35,919
Investing cash flows from operating leases	13,852	16,956
Non-cash investing and financing activities:
Change in accrued capital expenditures	$17,087	($72,782)
Change in asset retirement costs	3,381	1,208
ROU assets obtained in exchange for lease liabilities:
Operating leases	$9,710	$10,475

Note 15 - Subsequent Events

Fifth Amendment to the Credit Agreement

On November 1, 2021, the Company entered into the fifth amendment to its credit agreement governing the Credit Facility. See “Note 6 - Borrowings” for additional details.

Primexx Acquisition

On October 1, 2021, the Company closed the Primexx Acquisition. See “Note 3 - Acquisitions and Divestitures” for additional details.

Non-Core Asset Divestitures

On October 6, 2021, the Company entered into a purchase and sale agreement for the divestiture of certain non-core assets in the Midland Basin. The transaction, which is comprised of producing properties as well as an undeveloped acreage position, has an agreed upon purchase price of approximately $38.2 million, subject to customary purchase price adjustments, and is expected to close during the fourth quarter of 2021.

On October 28, 2021, the Company entered into an agreement to sell certain non-core water infrastructure for $30.0 million, subject to customary purchase price adjustments, as well as up to $18.0 million of contingent consideration.

Exercise of Warrants

On October 13, 2021, certain entities that were issued November 2020 Warrants provided notice and exercised all of their outstanding warrants. As a result of this exercise, the Company issued 0.5 million shares of its common stock in exchange for 0.6 million

outstanding warrants determined on a net share settlement basis. Subsequent to this exercise, there are no remaining outstanding November 2020 Warrants.

Second Lien Notes Exchange

On November 3, 2021, at a special meeting of shareholders, the Company obtained the requisite shareholder approval for the issuance of approximately 5.5 million shares of the Company’s common stock in the Exchange. The Exchange is expected to close on November 5, 2021. See “Note 6 - Borrowings” for additional details.

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.

In addition, there are risks and uncertainties related to the Primexx Acquisition, which include the following:

•the Primexx Acquisition may not be accretive, and may be dilutive, to the Company’s earnings per share, which may negatively affect the market price of the Company’s common stock; and

•the ultimate timing, outcome, and results of integrating the assets acquired in the Primexx Acquisition.

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

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

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

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

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 in South Texas.

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

Recent Developments and Overview

Primexx Acquisition

On October 1, 2021, we closed the Primexx Acquisition for total consideration of $864.6 million, subject to post-closing adjustments, comprised of approximately $453.7 million in cash and 8.84 million shares of the Company’s common stock. Additionally, pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to us for consideration structured similarly to the Primexx Acquisition. This incremental purchase price totaled approximately $37.5 million, net of customary purchase price adjustments, and provided an increase in the acreage included in the Primexx Acquisition to approximately 36,500 net acres. See “Note 3 - Acquisitions and Divestitures” for additional details.

Second Lien Notes Exchange

On November 3, 2021, at a special meeting of shareholders, we obtained the requisite shareholder approval for the issuance of approximately 5.5 million shares of our common stock in exchange for $197.0 million in aggregate principal amount of our Second Lien Notes. The Exchange is anticipated to close on November 5, 2021. See “Note 6 - Borrowings” and “Note 15 - Subsequent Events” for further discussion.

Non-Core Asset Divestitures

On September 27, 2021, we entered into a purchase and sale agreement for the divestiture of certain non-core assets in the Eagle Ford Shale. The transaction, which is comprised of producing properties as well as an undeveloped acreage position, has an agreed upon purchase price of approximately $100.0 million, subject to customary purchase price adjustments, and is expected to close during the fourth quarter of 2021.

On October 6, 2021, we entered into a purchase and sale agreement for the divestiture of certain non-core assets in the Midland Basin. The transaction, which is comprised of producing properties as well as an undeveloped acreage position, has an agreed upon purchase price of approximately $38.2 million, subject to customary purchase price adjustments, and is expected to close during the fourth quarter of 2021.

On October 28, 2021, we entered into an agreement to sell certain non-core water infrastructure for $30.0 million, subject to customary purchase price adjustments, as well as up to $18.0 million of contingent consideration.

Fifth Amendment to the Credit Facility

On November 1, 2021, we entered into the fifth 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 fall 2021 scheduled redetermination. See “Note 6 - Borrowings” for additional details.

Third Quarter 2021 Highlights

•Total production for the three months ended September 30, 2021 was 99.7 MBoe/d, an increase of 12% from the three months ended June 30, 2021, primarily due to new wells placed on production during the third quarter of 2021 partially offset by normal production decline. Total production for the nine months ended September 30, 2021 was 89.9 MBoe/d, a decrease

of 13% from the nine months ended September 30, 2020, primarily due to the divestitures that occurred during the nine months ended September 30, 2021 as well as normal production decline partially offset by new wells placed on production during 2021.

•Operated drilling and completion activity for the three months ended September 30, 2021 along with our drilled but uncompleted and producing wells as of September 30, 2021 are summarized in the table below.


	Three Months Ended September 30, 2021				As of September 30, 2021
	Drilled		Completed		Drilled But Uncompleted		Producing
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Permian	15	13.5	16	12.8	13	11.6	867	755.7
Eagle Ford	—	—	6	6.0	—	—	695	627.1
Total	15	13.5	22	18.8	13	11.6	1,562	1,382.8

•Operational capital expenditures, exclusive of leasehold and seismic, for the third quarter of 2021 were $115.0 million, of which approximately 82% were in the Permian with the remaining balance in the Eagle Ford. See “—Liquidity and Capital Resources—2021 Capital Budget and Funding Strategy” for additional details.

•On July 6, 2021, we closed on the issuance and sale of $650.0 million in aggregate principal amount of 8.00% Senior Notes in a private placement for proceeds of approximately $638.1 million, net of underwriting discounts and commissions and offering costs. On July 21, 2021, we used a portion of the net proceeds from the 8.00% Senior Notes to redeem all $542.7 million of our outstanding 6.25% Senior Notes due 2023 and the remaining proceeds to partially repay amounts outstanding under our Credit Facility.

•As of September 30, 2021, borrowings outstanding under our Credit Facility was $723.0 million compared to $875.0 million as of June 30, 2021. As discussed above, the cash portion of the total consideration for the Primexx Acquisition was funded by borrowings under our Credit Facility.

•Recorded net income for the three months ended September 30, 2021 of $171.9 million, or $3.65 per diluted share, compared to net loss for the three months ended September 30, 2020 of $680.4 million, or $17.12 per diluted share. The variance between the respective periods was driven primarily by the impairment of evaluated properties of $685.0 million during the third quarter of 2020 as well as an increase in operating revenues in the third quarter of 2021 driven by an approximate 91% increase in the total average realized sales price compared to the third quarter of 2020. This increase was partially offset by an increase in the loss on derivative contracts to approximately $107.2 million during the third quarter of 2021 compared to approximately $27.0 million during the third quarter of 2020. See “—Results of Operations” below for further details.

Results of Operations

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


	Three Months Ended							Nine Months Ended September 30,
	September 30, 2021		June 30, 2021		Change	% Change		2021		2020		Change	% Change
Total production
Oil (MBbls)
Permian	3,428		3,232		196	6	%	9,748		10,668		(920)	(9	%)
Eagle Ford	2,447		1,870		577	31	%	5,910		7,450		(1,540)	(21	%)
Total oil (MBbls)	5,875		5,102		773	15	%	15,658		18,118		(2,460)	(14	%)

Natural gas (MMcf)
Permian	7,153		7,138		15	—	%	20,499		24,613		(4,114)	(17	%)
Eagle Ford	2,242		1,745		497	28	%	5,614		6,451		(837)	(13	%)
Total natural gas (MMcf)	9,395		8,883		512	6	%	26,113		31,064		(4,951)	(16	%)

NGLs (MBbls)
Permian	1,315		1,216		99	8	%	3,606		4,059		(453)	(11	%)
Eagle Ford	417		299		118	39	%	940		1,107		(167)	(15	%)
Total NGLs (MBbls)	1,732		1,515		217	14	%	4,546		5,166		(620)	(12	%)

Total Production (MBoe)
Permian	5,936		5,637		299	5	%	16,771		18,829		(2,058)	(11	%)
Eagle Ford	3,237		2,460		777	32	%	7,785		9,632		(1,847)	(19	%)
Total barrels of oil equivalent (MBoe)	9,173		8,097		1,076	13	%	24,556		28,461		(3,905)	(14	%)

Total daily production (Boe/d)	99,703		88,981		10,722	12	%	89,949		103,873		(13,924)	(13	%)
Oil as % of total daily production	64	%	63	%				64	%	64	%

Benchmark prices (1)
WTI (per Bbl)	$70.50		$66.06		$4.44	7	%	$64.83		$38.30		$26.53	69	%
Henry Hub (per Mcf)	4.31		2.97		1.34	45	%	3.34		1.92		1.42	74	%

Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)
Permian	$69.60		$65.08		$4.52	7	%	$64.00		$36.00		$28.00	78	%
Eagle Ford	69.76		65.83		3.93	6	%	65.29		32.73		32.56	99	%
Total oil (per Bbl)	69.67		65.36		4.31	7	%	64.49		34.66		29.83	86	%

Natural gas (per Mcf)
Permian	3.78		2.68		1.10	41	%	3.20		0.86		2.34	272	%
Eagle Ford	4.22		2.82		1.40	50	%	3.44		1.87		1.57	84	%
Total natural gas (per Mcf)	3.89		2.71		1.18	44	%	3.25		1.07		2.18	204	%

NGL (per Bbl)
Permian	34.41		24.71		9.70	39	%	27.64		10.90		16.74	154	%
Eagle Ford	30.81		22.00		8.81	40	%	25.96		10.29		15.67	152	%
Total NGLs (per Bbl)	33.54		24.17		9.37	39	%	27.29		10.77		16.52	153	%


	Three Months Ended					Nine Months Ended September 30,
	September 30, 2021	June 30, 2021	$ Change	% Change		2021	2020	$ Change	% Change
Total average realized sales price (per Boe)
Permian	$52.37	$46.04	$6.33	14	%	$47.05	$23.88	$23.17	97	%
Eagle Ford	59.63	54.72	4.91	9	%	55.18	27.75	27.43	99	%
Total (per Boe)	$54.93	$48.68	$6.25	13	%	$49.63	$25.19	$24.44	97	%



Average realized sales price (including impact of settled derivatives)
Oil (per Bbl)	$54.00	$46.82	$7.18	15	%	$48.77	$40.36	$8.41	21	%
Natural gas (per Mcf)	2.21	2.25	(0.04)	(2	%)	2.42	1.09	1.33	122	%
NGLs (per Bbl)	31.71	23.21	8.50	37	%	26.04	10.77	15.27	142	%
Total (per Boe)	$42.84	$36.31	$6.53	18	%	$38.50	$28.83	$9.67	34	%

Revenues (in thousands)
Oil
Permian	$238,582	$210,340	$28,242	13	%	$623,889	$384,092	$239,797	62	%
Eagle Ford	170,711	123,102	47,609	39	%	385,891	243,842	142,049	58	%
Total oil	409,293	333,442	75,851	23	%	1,009,780	627,934	381,846	61	%

Natural gas
Permian	27,065	19,152	7,913	41	%	65,507	21,255	44,252	208	%
Eagle Ford	9,454	4,928	4,526	92	%	19,312	12,050	7,262	60	%
Total natural gas	36,519	24,080	12,439	52	%	84,819	33,305	51,514	155	%

NGLs
Permian	45,249	30,047	15,202	51	%	99,672	44,237	55,435	125	%
Eagle Ford	12,848	6,578	6,270	95	%	24,407	11,390	13,017	114	%
Total NGLs	58,097	36,625	21,472	59	%	124,079	55,627	68,452	123	%

Total Revenues
Permian	310,896	259,539	51,357	20	%	789,068	449,584	339,484	76	%
Eagle Ford	193,013	134,608	58,405	43	%	429,610	267,282	162,328	61	%
Total revenues	$503,909	$394,147	$109,762	28	%	$1,218,678	$716,866	$501,812	70	%

Additional per Boe data
Lease operating
Permian	$4.19	$4.60	($0.41)	(9	%)	$4.36	$4.80	($0.44)	(9	%)
Eagle Ford	5.51	8.34	(2.83)	(34	%)	7.25	6.10	1.15	19	%
Total lease operating	$4.66	$5.74	($1.08)	(19	%)	$5.28	$5.24	$0.04	1	%

Production and ad valorem taxes
Permian	$2.80	$2.53	$0.27	11	%	$2.56	$1.56	$1.00	64	%
Eagle Ford	2.89	3.12	(0.23)	(7	%)	3.01	1.75	1.26	72	%
Total production and ad valorem taxes	$2.84	$2.71	$0.13	5	%	$2.70	$1.62	$1.08	67	%

Gathering, transportation and processing
Permian	$2.70	$2.75	($0.05)	(2	%)	$2.67	$2.24	$0.43	19	%
Eagle Ford	1.49	1.84	(0.35)	(19	%)	1.82	1.49	0.33	22	%
Total gathering, transportation and processing	$2.28	$2.47	($0.19)	(8	%)	$2.40	$1.99	$0.41	21	%

(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 June 30, 2021 (1)	$333,442		$24,080		$36,625		$394,147
Volume increase (decrease)	50,520		1,387		5,246		57,153
Price increase (decrease)	25,331		11,052		16,226		52,609
Net increase (decrease)	75,851		12,439		21,472		109,762
Revenues for the period ended in September 30, 2021 (1)	$409,293		$36,519		$58,097		$503,909

Percent of total revenues	81	%	7	%	12	%

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


	Nine Months Ended September 30,
	Oil		Natural Gas		NGLs		Total
	(In thousands)
Revenues for the period ended in 2020 (1)	$627,934		$33,305		$55,627		$716,866
Volume increase (decrease)	(85,259)		(5,308)		(6,676)		(97,243)
Price increase (decrease)	467,105		56,822		75,128		599,055
Net increase (decrease)	381,846		51,514		68,452		501,812
Revenues for the period ended in 2021 (1)	$1,009,780		$84,819		$124,079		$1,218,678

Percent of total revenues	83	%	7	%	10	%

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

Revenues for the three months ended September 30, 2021 of $503.9 million increased $109.8 million, or 28%, compared to revenues of $394.1 million for the three months ended June 30, 2021. The increase was primarily attributable to a 13% increase in the average realized sales price which rose to $54.93 per Boe from $48.68 per Boe as well as a 12% increase in production as discussed above.

Revenues for the nine months ended September 30, 2021 of $1.2 billion increased $501.8 million, or 70%, compared to revenues of $716.9 million for the same period of 2020. The increase was primarily attributable to a 97% increase in the average realized sales price which rose to $49.63 per Boe from $25.19 per Boe. The increase in the average realized sales price was partially offset by a 13% decrease in production as discussed above.

Operating Expenses


	Three Months Ended
	September 30, 2021	Per	June 30, 2021	Per	Total Change			Boe Change
		Boe		Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Lease operating	$42,706	$4.66	$46,460	$5.74	($3,754)	(8	%)	($1.08)	(19	%)
Production and ad valorem taxes	26,070	2.84	21,958	2.71	4,112	19	%	0.13	5	%
Gathering, transportation and processing	20,875	2.28	20,031	2.47	844	4	%	(0.19)	(8	%)
Depreciation, depletion and amortization	89,890	9.80	83,128	10.27	6,762	8	%	(0.47)	(5	%)
General and administrative	9,503	1.04	11,065	1.37	(1,562)	(14	%)	(0.33)	(24	%)

Merger, integration and transaction	3,018	0.33	—	—	3,018	100	%	0.33	100	%


	Nine Months Ended September 30,
		Per		Per	Total Change			Boe Change
	2021	Boe	2020	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Lease operating	$129,619	$5.28	$149,091	$5.24	($19,472)	(13	%)	$0.04	1	%
Production and ad valorem taxes	66,467	2.71	46,151	1.62	20,316	44	%	1.09	67	%
Gathering, transportation and processing	58,887	2.40	56,615	1.99	2,272	4	%	0.41	21	%
Depreciation, depletion and amortization	244,005	9.94	384,594	13.51	(140,589)	(37	%)	(3.57)	(26	%)
General and administrative	37,367	1.52	26,573	0.93	10,794	41	%	0.59	63	%
Impairment of evaluated oil and gas properties	—	—	1,961,474	68.92	(1,961,474)	(100	%)	(68.92)	(100	%)
Merger, integration and transaction	3,018	0.12	26,362	0.93	(23,344)	(89	%)	(0.81)	(87	%)

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 September 30, 2021 decreased to $42.7 million compared to $46.5 million for the three months ended June 30, 2021, primarily due to a reduction in workover expenses as well as a reduction in certain operating expenses such as saltwater disposal and compression. Lease operating expense per Boe for the three months ended September 30, 2021 decreased to $4.66 compared to $5.74 for the three months ended June 30, 2021, primarily due to the distribution of fixed costs spread over higher production volumes as well as a reduction in certain operating expenses as discussed above.

Lease operating expenses for the nine months ended September 30, 2021 decreased to $129.6 million compared to $149.1 million for the same period of 2020, primarily due to a reduction in certain operating expenses such as repairs and maintenance and equipment rentals. Lease operating expense per Boe for the nine months ended September 30, 2021 increased to $5.28 compared to $5.24 for the same period of 2020, primarily due to the distribution of fixed costs spread over lower production volumes, partially offset by a reduction in certain operating expenses as discussed above.

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. 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 September 30, 2021, production and ad valorem taxes increased 19% to $26.1 million compared to $22.0 million for the three months ended June 30, 2021, which is primarily related to a 28% increase in total revenues which increased production taxes. The impact of the increase in production taxes was partially offset by a decrease in ad valorem taxes due to lower property tax valuations received during the third quarter of 2021. Production and ad valorem taxes as a percentage of total revenues decreased to 5.2% for the third quarter of 2021 as compared to 5.6% of total revenues for the three months ended June 30, 2021, primarily due to a decrease in ad valorem taxes during the third quarter of 2021 as discussed above.

For the nine months ended September 30, 2021, production and ad valorem taxes increased 44% to $66.5 million compared to $46.2 million for the same period of 2020, which is primarily related to a 70% increase in total revenues which increased production taxes. The impact of the increase in production taxes was partially offset by a decrease in ad valorem taxes due to lower property tax valuations for 2021 as a result of lower commodity prices during 2020 compared to higher property tax valuations for 2020 as a result of higher commodity prices during 2019. Production and ad valorem taxes as a percentage of total revenues decreased to 5.5% for the

nine months ended September 30, 2021, as compared to 6.4% of total revenues for the same period of 2020, primarily due to lower property tax valuations for 2021 as a result of lower commodity prices during 2020.

Gathering, Transportation and Processing Expenses. For the three months ended September 30, 2021, gathering, transportation and processing expenses increased 4% to $20.9 million compared to $20.0 million for the three months ended June 30, 2021, which is primarily related to the 12% increase in production volumes between the two periods.

For the nine months ended September 30, 2021, gathering, transportation and processing expenses increased 4% to $58.9 million compared to $56.6 million for the same period of 2020, which was primarily related to new oil transportation agreements which were executed subsequent to the six months ended June 30, 2020, partially offset by a 13% decrease in production volumes between the two periods.

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				Nine Months Ended September 30,
	September 30, 2021		June 30, 2021		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	$87,492	$9.54	$80,833	$9.98	$237,030	$9.65	$377,353	$13.26
Depreciation of other property and equipment	472	0.05	489	0.06	1,477	0.06	2,908	0.10
Amortization of other assets	962	0.10	883	0.11	2,684	0.11	1,832	0.06
Accretion of asset retirement obligations	964	0.11	923	0.12	2,814	0.12	2,501	0.09
DD&A	$89,890	$9.80	$83,128	$10.27	$244,005	$9.94	$384,594	$13.51

For the three months ended September 30, 2021, DD&A increased to $89.9 million from $83.1 million for the three months ended June 30, 2021. The increase in DD&A was primarily attributable to a production increase of 12%.

For the nine months ended September 30, 2021, DD&A decreased to $244.0 million from $384.6 million for the same period in 2020. The decrease in DD&A was primarily attributable to a production decrease of 13% and 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 September 30, 2021 decreased to $9.5 million compared to $11.1 million for the three months ended June 30, 2021, primarily due to the decrease in share-based compensation expense, net as the fair value of Cash-Settled RSU Awards and Cash SARs decreased in the third quarter of 2021.

G&A for the nine months ended September 30, 2021 increased to $37.4 million compared to $26.6 million for the same period in 2020 primarily due to an increase in the fair value of Cash-Settled RSU Awards and Cash SARs, partially offset by lower compensation costs.

Impairment of Evaluated Oil and Gas Properties. We did not recognize an impairment of evaluated oil and gas properties for the three or nine months ended September 30, 2021. An impairment of evaluated oil and gas properties of $685.0 million and $2.0 billion was recognized for the three and nine months ended September 30, 2020, respectively, which was due primarily to declines in the 12-Month Average Realized Price of crude oil. See “Note 4 - Property and Equipment, Net” for further discussion.

Merger, Integration and Transaction Expense. For the three and nine months ended September 30, 2021, we incurred $3.0 million of merger, integration and transaction expenses, which were related to the Primexx Acquisition, compared to $26.4 million for the nine months ended September 30, 2020, which were related to the Carrizo Acquisition. We did not incur any merger, integration and transaction expenses during the three months ended June 30, 2021.

Other Income and Expenses

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			Nine Months Ended September 30,
	September 30, 2021	June 30, 2021	$ Change	2021	2020	$ Change
	(In thousands)
Interest expense on Credit Facility	$7,247	$7,970	($723)	$23,034	$37,501	($14,467)
Interest expense on Second Lien Notes	11,625	11,625	—	34,875	—	34,875
Interest expense on Senior Unsecured Notes	29,758	24,502	5,256	78,762	92,625	(13,863)
Amortization of debt issuance costs, premiums and discounts	5,158	4,438	720	14,074	3,149	10,925
Other interest expense	38	26	12	96	152	(56)
Capitalized interest	(26,090)	(23,927)	(2,163)	(74,055)	(65,584)	(8,471)
Interest expense, net of capitalized amounts	$27,736	$24,634	$3,102	$76,786	$67,843	$8,943

Interest expense, net of capitalized amounts, incurred during the three months ended September 30, 2021 increased $3.1 million to $27.7 million compared to $24.6 million for the three months ended June 30, 2021. The increase is primarily due to the issuance of the 8.00% Senior Notes in the third quarter of 2021, offset by the reduction in interest expense associated with the redemption of the 6.25% Senior Notes in the third quarter of 2021, an increase in capitalized interest and lower borrowings on the Credit Facility compared to the three months ended June 30, 2021.

Interest expense, net of capitalized amounts, incurred during the nine months ended September 30, 2021 increased $8.9 million to $76.8 million compared to $67.8 million for the same period of 2020. The increase is primarily due to the issuance of the Second Lien Notes at the end of the third quarter of 2020 as well as amortization of the discount associated with those Second Lien Notes, offset by the reduction in Senior Unsecured Notes outstanding as a result of the exchange which occurred during the fourth quarter of 2020 and lower borrowings on the Credit Facility compared to 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. (Gain) loss on derivative contracts 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		Nine Months Ended September 30,
	September 30, 2021	June 30, 2021	2021	2020
	(In thousands)
(Gain) loss on oil derivatives	$67,198	$177,033	$393,792	($118,348)
(Gain) loss on natural gas derivatives	33,026	12,816	48,539	18,819
(Gain) loss on NGL derivatives	10,242	3,734	15,114	2,418
(Gain) loss on contingent consideration arrangements	(3,297)	(3,120)	(680)	(855)
(Gain) loss on September 2020 Warrants liability	—	—	55,390	—
(Gain) loss on derivative contracts	$107,169	$190,463	$512,155	($97,966)

See “Note 7 - Derivative Instruments and Hedging Activities” and “Note 8 - 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 income tax expense of $2.4 million compared to income tax benefit of $0.5 million for the three months ended September 30, 2021 and June 30, 2021, respectively. Since the second quarter of 2020, we have concluded that it is more likely than not that the net deferred tax assets will not be realized and have recorded a full valuation allowance against our deferred tax assets. As long as we continue to conclude that the valuation allowance is necessary, we will not have significant deferred tax expense or benefit.

We recorded income tax expense of $1.0 million and $115.3 million for the nine months ended September 30, 2021 and 2020, respectively. The income tax expense for the nine month period in 2020 is due to the recording of the valuation allowance during the three months ended June 30, 2020, which still remained as of September 30, 2021. See “Note 9 - 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. Primarily as a result of the Primexx Acquisition, our 2021 capital budget has been updated from $430.0 million to $515.0 million. For the fourth quarter of 2021, the majority of our remaining 2021 capital budget is allocated towards development in the Permian. As part of our updated 2021 operated horizontal drilling program, we expect to drill approximately 70 to 72 gross operated wells and complete approximately 103 to 105 gross operated wells.

During the three months ended September 30, 2021, we drilled 15 gross (13.5 net) wells, all in the Permian, and completed 22 gross (18.8 net) wells, with 6.0 net wells completed in Eagle Ford and 12.8 net wells completed in the Permian. We expect to operate six drilling rigs and an average of 1.5 completion crews during the fourth quarter of 2021, reflecting the incorporation of capital activity related to the recent Primexx Acquisition.

The following table is a summary of our capital expenditures(1) for the three and nine months ended September 30, 2021:


	Three Months Ended			Nine Months Ended
	March 31, 2021	June 30, 2021	September 30, 2021	September 30, 2021
	(In millions)
Operational capital	$95.6	$138.3	$115.0	$348.9
Capitalized interest	24.0	23.9	26.1	74.0
Capitalized G&A	11.2	12.1	10.4	33.7
Total	$130.8	$174.3	$151.5	$456.6

(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, scaled development program while leveraging our 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 may continue to 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.

Overview of Cash Flow Activities. For the nine months ended September 30, 2021, cash and cash equivalents decreased $16.5 million to $3.7 million compared to $20.2 million at December 31, 2020.


	Nine Months Ended September 30,
	2021	2020
	(In thousands)
Net cash provided by operating activities	$607,833	$425,197
Net cash used in investing activities	(455,167)	(449,667)
Net cash provided by (used in) financing activities	(169,203)	21,629
Net change in cash and cash equivalents	($16,537)	($2,841)

Operating Activities. For the nine months ended September 30, 2021, net cash provided by operating activities was $607.8 million compared to $425.2 million for the same period in 2020. The change in net cash provided by operating activities was predominantly attributable to the following:

•An increase in revenue primarily driven by a 86% increase in realized oil price, partially offset by a 13% decrease in production volumes, and

•An offsetting decrease in the cash received from commodity derivative settlements.

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

Investing Activities. For the nine months ended September 30, 2021, net cash used in investing activities was $455.2 million compared to $449.7 million for the same period in 2020. The increase in net cash used in investing activities was primarily attributed to the following:

•A decrease in cash received from the sale of assets, and

•An increase in deposits paid for the acquisition of oil and gas properties, partially offset by

•A decrease in operational capex, 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 nine months ended September 30, 2021, net cash used in financing activities was $169.2 million compared to net cash provided by financing activities of $21.6 million for the same period of 2020. This change was primarily attributable to repayment of approximately $262.0 million on the Credit Facility during the nine months ended September 30, 2021, which reflects our continued commitment and focus on deleveraging as well as the redemption of all of the outstanding 6.25% Senior Notes, partially offset by the issuance of the 8.00% Senior Notes.

See “Note 6 - 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 well as the issuance of our 8.00% Senior Notes and the redemption of all of our 6.25% Senior Notes as discussed further in “Note 6 - Borrowings.”

Credit Facility. As of September 30, 2021, our Credit Facility had a borrowing base of $1.6 billion, with an elected commitment amount of $1.6 billion, borrowings outstanding of $723.0 million at a weighted average interest rate of 2.35%, 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.

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 September 30, 2021. 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 6 – Borrowings” for additional information related to the Credit Facility.

Hedging. As of October 29, 2021, the Company had the following outstanding oil, natural gas and NGL derivative contracts:


	For the Remainder		For the Full Year			For the Full Year
Oil contracts (WTI)	2021 (1)		2022 (1)			2023
Swap contracts
Total volume (Bbls)	1,748,000		4,066,000			315,000
Weighted average price per Bbl	$56.87		$65.84			$70.01
Collar contracts
Total volume (Bbls)	2,290,450		7,097,500			—
Weighted average price per Bbl
Ceiling (short call)	$46.97		$67.70			$—
Floor (long put)	$39.37		$56.15			$—
Long put contracts
Total volume (Bbls)	414,000		—			—
Weighted average price per Bbl	$62.50		$	—		$	—
Short call contracts
Total volume (Bbls)	1,216,240	(2)	—			—
Weighted average price per Bbl	$63.62		$—			$—
Short call swaption contracts
Total volume (Bbls)	—		1,825,000		(3)	1,825,000		(3)
Weighted average price per Bbl	$—		$52.18			$72.00

Oil contracts (Brent ICE) (4)



Collar contracts
Total volume (Bbls)	184,000		—			—
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)	892,400		—			—
Weighted average price per Bbl	$0.33		$—			$—

Oil contracts (Argus Houston MEH)
Collar contracts
Total volume (Bbls)	—		452,500			—
Weighted average price per Bbl
Ceiling (short call)	$—		$63.15			$—
Floor (long put)	$—		$51.25			$—

(1) We have approximately $6.6 million of deferred premiums, of which $3.7 million are associated with contracts that will settle in 2021 and $2.9 million for contracts that will settle in 2022.

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

(3) The 2022 and 2023 short call swaption contracts have exercise expiration dates of December 31, 2021 and December 30, 2022, respectively.

(4) In February 2021, we entered into certain offsetting ICE Brent swaps to reduce our exposure to rising oil prices. Those offsetting swaps resulted in a locked-in loss of approximately $2.9 million, of which $1.6 million 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)	2021		2022
Swap contracts
Total volume (MMBtu)	4,357,000		7,320,000
Weighted average price per MMBtu	$2.96		$3.08
Collar contracts
Total volume (MMBtu)	1,840,000		5,740,000
Weighted average price per MMBtu
Ceiling (short call)	$2.80		$3.64
Floor (long put)	$2.50		$2.83
Short call contracts
Total volume (MMBtu)	1,840,000	(1)	—
Weighted average price per MMBtu	$3.09		$—

Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	4,140,000		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)	2021	2022
Swap contracts
Total volume (Bbls)	460,000	378,000
Weighted average price per Bbl	$7.62	$15.70

NGL contracts (OPIS Mont Belvieu Propane)
Swap contracts
Total volume (Bbls)	266,800	252,000
Weighted average price per Bbl	$52.15	$48.43

NGL contracts (OPIS Mont Belvieu Butane)
Swap contracts
Total volume (Bbls)	101,200	99,000
Weighted average price per Bbl	$59.43	$54.39

NGL contracts (OPIS Mont Belvieu Isobutane)
Swap contracts
Total volume (Bbls)	55,200	54,000
Weighted average price per Bbl	$58.96	$54.29

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: 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 7 - Derivative Instruments and Hedging Activities” and “Note 8 - 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 September 30, 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 September 30, 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 September 30, 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)
September 30, 2021 Actual	$56.47	$2.51	$2,429

Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$62.24	$2.81	$3,172	$743
Crude Oil and Natural Gas -10%	$50.70	$2.22	$1,689	($740)

Crude Oil Price Sensitivity
Crude Oil +10%	$62.24	$2.51	$3,114	$685
Crude Oil -10%	$50.70	$2.51	$1,745	($684)

Natural Gas Price Sensitivity
Natural Gas +10%	$56.47	$2.81	$2,487	$58
Natural Gas -10%	$56.47	$2.22	$2,373	($56)

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 September 30, 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 September 30, 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 9 - 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 tables set forth oil, natural gas and NGL revenues for the three and nine months ended September 30, 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 September 30, 2021
	Oil	Natural Gas	NGLs	Total
	(In thousands)
Revenues	$409,293	$36,519	$58,097	$503,909

Impact of a 10% fluctuation in average realized prices	$40,929	$3,652	$5,810	$50,391

	Nine Months Ended September 30, 2021
	Oil	Natural Gas	NGLs	Total
	(In thousands)
Revenues	$1,009,780	$84,819	$124,079	$1,218,678

Impact of a 10% fluctuation in average realized prices	$100,978	$8,482	$12,408	$121,868

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.

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 September 30, 2021, we had $723.0 million outstanding under the Credit Facility with a weighted average interest rate of 2.35%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual interest expense of approximately $7.2 million, based on the balance outstanding as of September 30, 2021. See “Note 6 - 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 September 30, 2021, our total receivables from the sale of our oil, natural gas and NGL production were approximately $168.1 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 September 30, 2021, our joint interest receivables were approximately $8.6 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 September 30, 2021, we had a net commodity derivative liability position of $315.2 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 September 30, 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 third 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

Pursuant to the closing of the Primexx Acquisition, the Company issued 8.84 million shares of the Company’s common stock as a portion of the total consideration for the assets acquired. The shares were issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) of the Securities Act as sales by an issuer not involving any public offering. The issuance of such shares did not involve a public offering for purposes of Section 4(a)(2) because of, among other things, its being made only to the sellers in the Primexx Acquisition, such persons’ status as accredited investors and the manner of the issuance, including that the Company did not, and will not, engage in general solicitation or advertising with regard to the issuance of such shares.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

The following exhibits are filed as part of this Form 10-Q.

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

Exhibit Number

Description

Form

Exhibit

Filing Date

2.1

(c)

Purchase and Sale Agreement by and among Callon Petroleum Company, Callon Petroleum Operating Company, and Primexx Resource Development, LLC dated August 3, 2021

8-K

10.1

8/5/2021

2.2

(c)

Purchase and Sale Agreement by and among Callon Petroleum Company, Callon Petroleum Operating Company, and BPP Acquisition, LLC dated August 3, 2021

8-K

10.2

8/5/2021

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

12/20/2019

3.3

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

8-K

3.1

8/7/2020

3.4

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

8-K

3.1

5/14/2021

3.5

Amended and Restated Bylaws of the Company

10-K

3.2

2/27/2019

4.1

Indenture, dated as of July 6, 2021, by and among the Company, Callon Petroleum Operating Company, Callon (Eagle Ford) LLC, Callon (Niobrara) LLC, Callon (Permian) LLC, Callon (Permian) Minerals LLC, Callon (Utica) LLC, Callon Marcellus Holding, Inc. and U.S. Bank National Association, as trustee.

8-K

4.1

7/7/2021

10.1

(a)

Separation Agreement, dated July 22, 2021, by and between James “Jim” Ulm, II and Callon Petroleum Company .

10.2

(a)

Consulting Agreement, dated July 22, 2021, by and between James “Jim” Ulm, II and Callon Petroleum Company .

10.3

(a)

Fifth Amendment, dated November 1, 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.

10.4

Exchange Agreement, among the Company and Chambers Investments, LLC, dated August 3, 2021.

8-K

10.1

8/5/2021

10.5

Form of Voting Agreement between the Company and the executive officer or director named therein, dated as of August 3, 2021.

8-K

10.2

8/5/2021

31.1

(a)

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

31.2

(a)

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

32.1

(b)

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

101.INS

(a)

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

101.SCH

(a)

Inline XBRL Taxonomy Extension Schema Document

101.CAL

(a)

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

(a)

Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

(a)

Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE

(a)

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104

(a)

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

(a)Filed herewith.

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

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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Callon Petroleum Company


Signature	Title	Date

/s/ Joseph C. Gatto, Jr.	President and	November 4, 2021
Joseph C. Gatto, Jr.	Chief Executive Officer


/s/ Kevin Haggard	Senior Vice President and	November 4, 2021
Kevin Haggard	Chief Financial Officer