Callon Petroleum Co - Quarter Report: 2020 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For The Quarterly Period Ended September 30, 2020

☐ 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 39,752,672 shares of common stock outstanding as of October 29, 2020.

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			34

Item 3. Quantitative and Qualitative Disclosures about Market Risk			47

Item 4. Controls and Procedures			49

Part II. Other Information

Item 1. Legal Proceedings			50

Item 1A. Risk Factors			50

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			50

Item 3. Defaults Upon Senior Securities			50

Item 4. Mine Safety Disclosures			50

Item 5. Other Information			50

Item 6. Exhibits			51

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, butanes 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.

•Royalty interest: an interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.

•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, 2020	December 31, 2019
ASSETS
Current assets:
Cash and cash equivalents	$10,500	$13,341
Accounts receivable, net	112,536	209,463
Fair value of derivatives	9,821	26,056
Other current assets	27,049	19,814
Total current assets	159,906	268,674
Oil and natural gas properties, full cost accounting method:
Evaluated properties	2,916,542	4,682,994
Unevaluated properties	1,758,132	1,986,124
Total oil and natural gas properties, net	4,674,674	6,669,118
Operating lease right-of-use assets	29,519	63,908
Other property and equipment, net	32,920	35,253
Deferred tax asset	—	115,720
Deferred financing costs	24,850	22,233

Other assets, net	15,472	19,932
Total assets	$4,937,341	$7,194,838
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$332,979	$490,442
Operating lease liabilities	19,458	42,858

Fair value of derivatives	34,950	71,197
Other current liabilities	30,013	47,750
Total current liabilities	417,400	652,247
Long-term debt	3,190,273	3,186,109
Operating lease liabilities	28,906	37,088
Asset retirement obligations	49,542	48,860

Fair value of derivatives	35,705	32,695
Other long-term liabilities	11,411	14,531
Total liabilities	3,733,237	3,971,530
Commitments and contingencies
Stockholders’ equity:

Common stock, $0.01 par value, 52,500,000 shares authorized; 39,749,985 and 39,659,001 shares outstanding, respectively (1)	397	3,966
Capital in excess of par value	3,210,991	3,198,076
Retained earnings (Accumulated deficit)	(2,007,284)	21,266
Total stockholders’ equity	1,204,104	3,223,308
Total liabilities and stockholders’ equity	$4,937,341	$7,194,838

(1) All share amounts (except par value) have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 - Stockholders’ Equity” for additional information.

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

Callon Petroleum Company

Consolidated Statements of Operations

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
Operating revenues:
Oil	$231,654	$148,210	$627,934	$450,036
Natural gas	15,034	7,168	33,305	25,441
Natural gas liquids	23,025	—	55,627	—
Sales of purchased oil and gas	20,313	—	21,469	—
Total operating revenues	290,026	155,378	738,335	475,477

Operating Expenses:
Lease operating	45,870	19,668	149,091	66,511
Production and ad valorem taxes	16,110	11,866	46,151	33,810
Gathering, transportation and processing	22,200	—	56,615	—
Cost of purchased oil and gas	21,282	—	22,450	—
Depreciation, depletion and amortization	114,201	56,130	384,594	179,275
General and administrative	8,224	9,388	26,573	34,729
Impairment of evaluated oil and gas properties	684,956	—	1,961,474	—
Merger and integration	2,465	5,943	26,362	5,943

Other operating	4,425	(161)	8,548	931
Total operating expenses	919,733	102,834	2,681,858	321,199
Income (Loss) From Operations	(629,707)	52,544	(1,943,523)	154,278

Other (Income) Expenses:
Interest expense, net of capitalized amounts	24,683	739	67,843	2,218
(Gain) loss on derivative contracts	27,038	(21,809)	(97,966)	31,415
Other (income) expense	(1,044)	(122)	(149)	(270)
Total other (income) expense	50,677	(21,192)	(30,272)	33,363

Income (Loss) Before Income Taxes	(680,384)	73,736	(1,913,251)	120,915
Income tax expense	—	(17,902)	(115,299)	(29,444)
Net Income (Loss)	(680,384)	55,834	(2,028,550)	91,471
Preferred stock dividends	—	(350)	—	(3,997)
Loss on redemption of preferred stock	—	(8,304)	—	(8,304)
Income (Loss) Available to Common Stockholders	($680,384)	$47,180	($2,028,550)	$79,170

Income (Loss) Available to Common Stockholders Per Common Share (1):
Basic	($17.12)	$2.07	($51.09)	$3.47
Diluted	($17.12)	$2.07	($51.09)	$3.47

Weighted Average Common Shares Outstanding (1):
Basic	39,746	22,831	39,707	22,805
Diluted	39,746	22,846	39,707	22,841

(1) All share and per share amounts have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 - Stockholders’ Equity” for additional information.

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

Callon Petroleum Company

Consolidated Statements of Stockholders’ Equity

(In thousands, except per share amounts)

(Unaudited)


									Retained
	Preferred			Common			Capital in		Earnings		Total
	Stock			Stock			Excess		(Accumulated		Stockholders’
	Shares	$		Shares (1)	$		of Par		Deficit)		Equity
Balance at 12/31/2019	—	$—		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 3/31/2020	—	$—		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 6/30/2020	—	$—		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 9/30/2020	—	$	—	39,750	$	397	$	3,210,991	$	(2,007,284)	$	1,204,104


	Preferred			Common			Capital in				Total
	Stock			Stock			Excess		Accumulated		Stockholders’
	Shares	$		Shares (1)	$		of Par		Deficit		Equity
Balance at 12/31/2018	1,459	$15		22,757	$2,276		$2,477,278		($34,361)		$2,445,208
Net loss	—	—		—	—		—		(19,543)		(19,543)
Shares issued pursuant to employee benefit plans	—	—		2	—		154		—		154
Restricted stock	—	—		28	3		4,447		—		4,450
Preferred stock dividend	—	—		—	—		—		(1,824)		(1,824)
Balance at 3/31/2019	1,459	$15		22,787	$2,279		$2,481,879		($55,728)		$2,428,445
Net income	—	—		—	—		—		55,180		55,180
Restricted stock	—	—		38	4		2,071		—		2,075
Preferred stock dividend	—	—		—	—		—		(1,823)		(1,823)
Preferred stock redemption costs	—	—		—	—		(5)		—		(5)
Balance at 6/30/2019	1,459	$15		22,825	$2,283		$2,483,945		($2,371)		$2,483,872
Net income	—	—		—	—		—		55,834		55,834
Restricted stock	—	—		11	1		2,307		—		2,308

Preferred stock dividend	—	—		—	—		—		(350)		(350)
Preferred stock redemption	(1,459)	(15)		—	—		(64,693)		—		(64,708)
Loss on redemption of preferred stock	—	—		—	—		—		(8,304)		(8,304)
Balance at 9/30/2019	—	$	—	22,836	$	2,284	$	2,421,559	$	44,809	$	2,468,652

(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” 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:	2020	2019
Net income (loss)	($2,028,550)	$91,471
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	384,594	182,738
Impairment of evaluated oil and gas properties	1,961,474	—
Amortization of non-cash debt related items	1,582	2,218
Deferred income tax expense	115,299	29,444
(Gain) loss on derivative contracts	(97,966)	31,415
Cash (paid) received for commodity derivative settlements	101,754	(436)
Loss on sale of other property and equipment	—	36

Non-cash expense related to equity share-based awards	6,302	7,868
Change in the fair value of liability share-based awards	(6,607)	106
Payments to settle asset retirement obligations	—	(1,425)
Payments for cash-settled restricted stock unit awards	(770)	(1,425)
Other, net	6,510	—
Changes in current assets and liabilities:
Accounts receivable	96,110	17,600
Other current assets	(6,556)	(5,172)
Current liabilities	(107,979)	(13,038)
Other	—	(2,662)
Net cash provided by operating activities	425,197	338,738
Cash flows from investing activities:
Capital expenditures	(567,746)	(503,425)
Acquisitions	—	(40,788)

Proceeds from sale of assets	149,818	279,952
Cash paid for settlements of contingent consideration arrangements, net	(40,000)	—
Other, net	8,261	—
Net cash used in investing activities	(449,667)	(264,261)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	5,087,500	581,000
Payments on senior secured revolving credit facility	(5,347,500)	(581,000)



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 warrants	23,909	—


Payment of preferred stock dividends	—	(3,997)
Payment of deferred financing costs	(6,312)	(31)
Tax withholdings related to restricted stock units	(495)	(2,174)
Redemption of preferred stock	—	(73,017)
Other, net	(203)	—
Net cash provided by (used in) financing activities	21,629	(79,219)
Net change in cash and cash equivalents	(2,841)	(4,742)
Balance, beginning of period	13,341	16,051
Balance, end of period	$10,500	$11,309

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.	Leases
5.	Earnings Per Share	13.	Accounts Receivable, Net
6.	Borrowings	14.	Accounts Payable and Accrued Liabilities
7.	Derivative Instruments and Hedging Activities	15.	Supplemental Cash Flow
8.	Fair Value Measurements	16.	Subsequent Events

Note 1 - Description of Business and Basis of Presentation

Description of business

Callon 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 Shale, which the Company entered into through its acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”) in late 2019. The Company’s primary operations in the Permian Basin 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 Shale.

Basis of presentation

The accompanying unaudited interim consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and have been prepared pursuant to the rules and regulations of the SEC and therefore do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the 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 had no material impact on prior period financial statements. However, the comparability of certain 2020 amounts to prior periods could be impacted as a result of the Carrizo Acquisition in December 2019.

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, 2019 (“2019 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 2019 Annual Report.

Three-stream reporting. Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow the Company to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales and reserve volumes, prices, and revenues specifically associated with the Carrizo Acquisition, as defined below, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.

See “Note 2 - Revenue Recognition” for additional information regarding the impact of three-stream reporting on our current results.

Recently Adopted Accounting Standards

None that had a material impact on our financial statements.

Recently Issued Accounting Pronouncements

Income Taxes. In December 2019, the FASB released Accounting Standards Update 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. We do not expect the adoption of this standard to have a material impact on our financial statements.

Subsequent Events

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

Note 2 - Revenue Recognition

Revenue from contracts with customers

Oil sales

Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received.

Natural gas sales

Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow the Company to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.

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

Contractual fees associated with gathering, processing, treating and compression, as well as any transportation fees incurred to deliver the product to the purchaser, for the majority of the Company’s natural gas processing agreements were previously recorded as a reduction of revenue. As a result of the modifications to certain of the Company’s natural gas processing agreements, as well as the natural gas processing agreements assumed in the Carrizo Acquisition, the Company now recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and processing” in its consolidated statements of operations as the Company maintains control throughout processing. These changes impact the comparability of 2020 with prior periods. For the three and nine months ended September 30, 2019, $2.6 million and $7.8 million of gathering, transportation, and processing fees were recognized as a reduction to natural gas revenues in the consolidated statement of operations.

Oil and Gas Purchase and Sale Arrangements

Sales of purchased oil and gas represent revenues the Company receives from sales of commodities purchased from a third-party. The Company recognizes these revenues and the purchase of the third-party commodities, as well as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer.

Accounts receivable from revenues from contracts with customers

Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at September 30, 2020 and December 31, 2019 of $81.4 million and $165.3 million, respectively, 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 utilized the practical expedient in ASC 606, 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

2020 Acquisitions and Divestitures

ORRI Transaction. On September 30, 2020, the Company entered into a Purchase and Sale Agreement with Chambers Minerals, LLC, a private investment vehicle managed by Kimmeridge Energy, where the Company agreed to sell an undivided 2.0% (on an 8/8ths basis) overriding royalty interest, proportionately reduced to the Company’s net revenue interest, in and to the Company’s operated leases, excluding certain interests as defined in the Purchase and Sale Agreement, for an aggregate purchase price of $140.0 million (“ORRI Transaction”), with an effective date of October 1, 2020. After adjusting for costs associated with the sale, the net proceeds of $135.8 million were used to repay borrowings outstanding under the Company’s senior secured revolving credit facility. The net proceeds were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized.

Non-Operated Working Interest Transaction. On September 25, 2020, the Company entered into a Purchase and Sale Agreement to sell substantially all of its non-operated assets for estimated gross proceeds of approximately $30.0 million, with an effective date of September 1, 2020, subject to purchase price adjustments. The Company received $29.6 million at closing on November 2, 2020, subject to post-closing adjustments.

2019 Acquisitions and Divestitures

Carrizo Oil & Gas, Inc. Merger. On December 20, 2019, the Company completed its acquisition of Carrizo in an all-stock transaction (the “Merger” or the “Carrizo Acquisition”). Under the terms of the Merger, each outstanding share of Carrizo common stock was converted into 1.75 shares of the Company’s common stock. The Company issued approximately 168.2 million shares of common stock at a price of $4.55 per share, resulting in total consideration paid by the Company to the former Carrizo shareholders of approximately $765.4 million. In connection with the closing of the Merger, the Company funded the redemption of Carrizo’s 8.875% Preferred Stock, repaid the outstanding principal under Carrizo’s revolving credit facility and assumed all of Carrizo’s senior notes.

The Merger was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk-adjusted discount rate. Certain data necessary to complete the purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of Carrizo’s assets and liabilities. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date.

The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.


						Preliminary Purchase Price Allocation
						(In thousands)
Consideration:
Fair value of the Company’s common stock issued						$765,373
Total consideration						$765,373

Liabilities:
Accounts payable						$37,657
Revenues and royalties payable						52,449
Operating lease liabilities - current						29,924
Fair value of derivatives - current						61,015
Other current liabilities						88,714
Long-term debt						1,984,135
Operating lease liabilities - non-current						30,070
Asset retirement obligation						26,151
Fair value of derivatives - non-current						26,960
Other long-term liabilities						17,260
Common stock warrants						10,029
Total liabilities assumed						$2,364,364

Assets:
Accounts receivable, net						$48,479
Fair value of derivatives - current						17,451
Other current assets						11,640
Evaluated oil and natural gas properties						2,133,280
Unevaluated properties						682,950
Other property and equipment						9,614
Fair value of derivatives - non-current						4,518
Deferred tax asset						159,320
Operating lease right-of-use-assets						59,907
Other long term assets						2,578
Total assets acquired						$3,129,737

Approximately $160.5 million and $408.8 million of revenues and $51.6 million and $151.5 million of direct operating expenses attributed to the Carrizo Acquisition were included in the Company’s consolidated statements of operations for the three and nine months ended September 30, 2020, respectively.

Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the year ended December 31, 2019 was derived from the historical financial statements of the Company giving effect to the Merger, as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Carrizo’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Carrizo’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Carrizo’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments.

Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $58.8 million for the year ended December 31, 2019 and acquisition-related costs incurred by Carrizo that totaled approximately $15.6 million for the year ended December 31, 2019. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Carrizo assets. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.

The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results.


						For the Year Ended
						December 31, 2019
						(In thousands)
Revenues						$1,620,357
Income from operations						614,668
Net income						369,777
Basic earnings per common share						0.89
Diluted earnings per common share						0.89

In conjunction with the Carrizo Acquisition, the Company incurred costs totaling $2.5 million and $26.4 million for the three and nine months ended September 30, 2020, respectively, comprised of severance costs of $0.8 million and $6.2 million for the three and nine months ended September 30, 2020, respectively, and other merger and integration expenses of $1.7 million and $20.2 million for the three and nine months ended September 30, 2020, respectively. Through September 30, 2020, the Company has incurred cumulative costs associated with the Carrizo Acquisition of $100.8 million comprised of severance costs of $35.8 million and other merger and integration expenses of $65.0 million. As of September 30, 2020, $5.6 million remained accrued and is included as a component of “Accounts payable and accrued liabilities” in the consolidated balance sheets.

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 Asset Divestiture”) for net cash proceeds of $244.9 million. The transaction also provided for potential additional contingent consideration in payments of up to $60.0 million based on West Texas Intermediate average annual pricing over a three-year period. See “Note 7 - Derivative Instruments and Hedging Activities” and “Note 8 - Fair Value Measurements” for further discussion of this contingent consideration arrangement. The divestiture encompasses the Ranger operating area in the southern Midland Basin which includes approximately 9,850 net Wolfcamp acres with an average 66% working interest. The net cash 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, 2020 and December 31, 2019, total property and equipment, net consisted of the following:


	September 30, 2020	December 31, 2019
Oil and natural gas properties, full cost accounting method	(In thousands)
Evaluated properties	$7,775,858	$7,203,482
Accumulated depreciation, depletion, amortization and impairments	(4,859,316)	(2,520,488)
Net evaluated oil and natural gas properties	2,916,542	4,682,994
Unevaluated properties
Unevaluated leasehold and seismic costs	1,574,451	1,843,725
Capitalized interest	183,681	142,399
Total unevaluated properties	1,758,132	1,986,124
Total oil and natural gas properties, net	$4,674,674	$6,669,118

Other property and equipment	$66,365	$67,202
Accumulated depreciation	(33,445)	(31,949)
Other property and equipment, net	$32,920	$35,253

The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $10.3 million and $8.2 million for the three months ended September 30, 2020 and 2019, respectively, and $26.7 million and $27.4 million for the nine months ended September 30, 2020 and 2019.

The Company capitalized interest costs associated with its unproved properties totaling $20.7 million and $18.1 million for the three months ended September 30, 2020 and 2019, respectively, and $65.6 million and $56.7 million for the nine months ended September 30, 2020 and 2019.

As a result of the downturn in the oil and gas industry as well as in the broader macroeconomic environment, the Company analyzed its unevaluated leasehold giving consideration to its updated exploration program as well as to the remaining lease term of certain unevaluated leaseholds. The Company transferred $235.9 million from unevaluated leasehold to evaluated properties during the nine months ended September 30, 2020 primarily as a result of the analysis described above.

Impairment of Evaluated Oil and Gas Properties

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. An impairment of evaluated oil and gas properties recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices in the future increase the cost center ceiling applicable to the subsequent period. There were no impairments of evaluated oil and gas properties for the three months ended March 31, 2020 or for the corresponding prior year periods.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Impairment of evaluated oil and gas properties (in thousands)	$684,956		$—		$1,961,474		$—
Beginning of period 12-Month Average Realized Price ($/Bbl)	$45.87		$53.00		$53.90		$58.40
End of period 12-Month Average Realized Price ($/Bbl)	$41.71		$52.44		$41.71		$52.44
Percent decrease in 12-Month Average Realized Price	(9	%)	(1	%)	(23	%)	(10	%)

The Company expects to record an additional impairment in the carrying value of evaluated oil and gas properties in the fourth quarter of 2020 based on an estimated 12-Month Average Realized price of crude oil of approximately $39.65 per Bbl as of December 31, 2020, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 10 months and an estimate for the eleventh and twelfth months based on a quoted forward price. Declines in the 12-Month Average Realized Price of crude oil in subsequent quarters could result in a lower present value of the estimated future net revenues from proved oil and gas reserves and may result in additional impairments of evaluated oil and gas properties.

Note 5 - Earnings Per Share

Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders 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 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 loss available to common stockholders. As a result, the calculation of diluted weighted average common shares outstanding excluded the anti-dilutive effect of 1.3 million and 1.0 million potentially dilutive common shares outstanding for the three and nine months ended September 30, 2020, respectively. The following table sets forth the computation of basic and diluted earnings per share:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
	(In thousands, except per share amounts)
Net income (loss)	($680,384)	$55,834	($2,028,550)	$91,471
Preferred stock dividends (1)	—	(350)	—	(3,997)
Loss on redemption of preferred stock	—	(8,304)	—	(8,304)
Income (loss) available to common stockholders	($680,384)	$47,180	($2,028,550)	$79,170

Basic weighted average common shares outstanding (2)	39,746	22,831	39,707	22,805
Dilutive impact of restricted stock (2)	—	15	—	36
Diluted weighted average common shares outstanding (2)	39,746	22,846	39,707	22,841

Income (Loss) Available to Common Stockholders Per Common Share (2)
Basic	($17.12)	$2.07	($51.09)	$3.47
Diluted	($17.12)	$2.07	($51.09)	$3.47

Restricted stock (2)(3)	1,263	249	1,014	191

(1) The Company redeemed all outstanding shares of its 10% Series A Cumulative Preferred Stock (“Preferred Stock”) on July 18, 2019 and all dividends ceased to accrue upon redemption.

(2) Shares and per share data have been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 - Stockholders’ Equity” for additional information.

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

Note 6 - Borrowings

The Company’s borrowings consisted of the following:


	September 30, 2020	December 31, 2019
	(In thousands)
Senior Secured Revolving Credit Facility due 2024	$1,025,000	$1,285,000
9.00% Second Lien Senior Secured Notes due 2025	300,000	—
6.25% Senior Notes due 2023	650,000	650,000
6.125% Senior Notes due 2024	600,000	600,000
8.25% Senior Notes due 2025	250,000	250,000
6.375% Senior Notes due 2026	400,000	400,000
Total principal outstanding	3,225,000	3,185,000
Unamortized premium on 6.125% Senior Notes	4,500	5,344
Unamortized premium on 6.25% Senior Notes	3,818	4,838
Unamortized premium on 8.25% Senior Notes	4,571	5,286
Unamortized discount on 9.00% Second Lien Notes	(35,270)	—
Unamortized deferred financing costs for Senior Notes	(12,346)	(14,359)
Total carrying value of borrowings (1)	$3,190,273	$3,186,109

(1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $24.9 million and $22.2 million as of September 30, 2020 and December 31, 2019, 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 that, as of September 30, 2020, had a borrowing base of $1.6 billion, with an elected commitment amount of $1.6 billion, borrowings outstanding of $1.03 billion at a weighted-average interest rate of 2.93%, and letters of credit outstanding of $24.2 million. The credit agreement governing the revolving credit facility provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”) are outstanding at such time, (ii) July 2, 2024 if the 6.125% Senior Notes due 2024 (the “6.125% Senior Notes”) are outstanding at such time, and (iii) if the Second Lien Notes, defined below, are outstanding at such time, the date which is 182 days prior to the maturity of any of the 6.25% Senior Notes or the 6.125% Senior Notes, in each case, to the extent a principal amount of more than $100.0 million with respect to each such issuance is outstanding as of such date), when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The revolving credit facility is secured by first preferred mortgages covering the Company’s major producing properties. The capitalized terms which are not defined in this description of the revolving credit facility shall have the meaning given to such terms in the credit agreement.

On May 7, 2020, the Company entered into the first amendment to its credit agreement governing the revolving credit facility. The amendment, among other things, (a) established a new borrowing base as a result of the spring 2020 scheduled redetermination in the amount of $1.7 billion and reduced the elected commitments to $1.7 billion, which were subsequently revised as described below; (b) permits the incurrence of, among other things, new second lien notes in 2020 exchanged for unsecured notes in an aggregate principal amount of up to $400.0 million (the “Exchange Notes”) without triggering a reduction in the borrowing base so long as any such Exchange Notes are subject to an intercreditor agreement providing that the liens securing the Exchange Notes rank junior to the liens securing the credit agreement; (c) provides that testing of the Leverage Ratio, which is the ratio of consolidated total debt to Adjusted EBITDAX on a quarterly basis is suspended until March 31, 2022, as of which testing date and the last day of each fiscal quarter ending thereafter, such ratio may not exceed 4.00 to 1.00; (d) provides a new financial covenant testing the Secured Leverage Ratio, which is the ratio of the consolidated total secured debt to Adjusted EBITDAX and provides that such ratio on a quarterly basis as of the last day of each quarter beginning with March 31, 2020 up to and including the quarter ending December 31, 2021 may not exceed 3.00 to 1.00; (e) provided that the testing of the Current Ratio, which is the ratio of current assets to current liabilities was suspended until September 30, 2020, as of which testing date and the last day of each fiscal quarter ending thereafter, such ratio may not be less than 1.00 to 1.00; (f) increases the applicable margins for borrowings under the credit agreement for both LIBOR loans and base rate loans by 75 basis points across all commitment utilization ranges; (g) introduces customary anti-cash hoarding protections tested weekly, which restrict the Company’s ability to maintain unrestricted cash on its balance sheet in amounts in the excess of the lesser of (i) $125.0 million or (ii) 7.5% of the then current borrowing base; (h) requires the Company to enter into and maintain minimum hedges for the 12 month period starting January 1, 2021 through December 31, 2021, for which the net notional volumes on a barrel of oil equivalent basis are not less than 40% of the reasonably anticipated production from the Company’s oil and gas properties which are classified as proved developed producing reserves as of April 1, 2020; (i) requires mortgage and title coverage on at least 90% of

the total value of proved oil and gas properties evaluated in the most recently delivered reserve report; and (j) restricts the Company’s ability to make certain investments and cash distributions by lowering the maximum leverage ratio required to make such distributions to 2.50 to 1.00.

On September 30, 2020, the Company entered into the second amendment to its credit agreement governing the revolving credit facility. The amendment, among other things, reaffirmed the $1.7 billion borrowing base as a result of the fall 2020 scheduled redetermination.

Also on September 30, 2020, the Company entered into the third amendment to its credit agreement governing the revolving credit facility. The amendment, among other things, (a) established a new borrowing base of $1.6 billion and reduced the elected commitments to $1.6 billion in connection with the issuance of the Second Lien Notes and Warrants, described below, and ORRI Transaction; (b) permitted the issuance of the $300.0 million of Second Lien Notes as contemplated by the Purchase Agreement described below without triggering a reduction in the borrowing base; (c) extends through the end of 2021 the time period during which Exchange Notes may be issued without triggering a reduction in the borrowing base; and (d) if the Second Lien Notes are outstanding at such time, caused the maturity of the revolving credit facility to spring forward to a date which is 182 days prior to the maturity of any of the 6.25% Senior Notes or the 6.125% Senior Notes, in each case, to the extent a principal amount of more than $100.0 million with respect to each such issuance is outstanding as of such date.

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” in the consolidated statements of operations.

Second Lien Notes and Warrants

On September 30, 2020, the Company entered into a Purchase Agreement (the “Purchase Agreement”) where it issued (i) $300.0 million in aggregate principal amount of its 9.00% Second Lien Senior Secured Notes due 2025 (the “Second Lien Notes”) and (ii) warrants for 7.3 million of the Company’s common stock, with a term of five years and an exercise price of $5.60 per share, exercisable only on a net share settlement basis (the “Warrants”), for aggregate consideration of $294.0 million. The Company used the proceeds, net of issuance costs, of approximately $288.6 million to repay borrowings outstanding under its senior secured revolving credit facility. The Company also entered into a registration rights agreement with the purchaser of the Second Lien Notes.

Net proceeds were allocated to the Warrants based on their fair value on the date of issuance with the remaining net proceeds allocated to the Second Lien Notes. The fair value of the Warrants was calculated by a third-party valuation specialist using a Black Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date:


	Issuance Date Fair Value Assumptions
Exercise price	$5.60
Expected term (in years)	5.0
Expected volatility	116.3	%
Risk-free interest rate	0.3	%
Dividend yield	—	%

See “Note 8 - Fair Value Measurements” for further discussion.

Second Lien Notes. The Second Lien Notes will mature on the earlier of (i) April 1, 2025 and (ii) 91 days prior to the maturity date of any outstanding unsecured notes in a principal amount at or greater than $100.0 million and have interest payable semi-annually each April 1 and October 1, commencing on April 1, 2021.

The Company may redeem the Second Lien Notes in accordance with the following terms: (1) prior to October 1, 2022, a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 109.00% of principal, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to October 1, 2022, a redemption of all or part of the principal at a price of 100% of the principal amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to, but excluding, the date of redemption; and (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to, but excluding, the date of the redemption, of (i) 105.00% of principal if the redemption occurs on or after October 1, 2022, but before October 1, 2023, and (ii) 102.50% of principal if the redemption occurs on or after October 1, 2023, but before October 1, 2024, and (iii) 100% of principal if the redemption occurs on or after October 1, 2024.

Upon the occurrence of certain change of control events, each holder of the Second Lien Notes may require the Company to repurchase all or a portion of the Second Lien Notes at a price of 101% of the principal amount repurchased, plus accrued and unpaid interest, if any, to, but excluding, the date of repurchase.

Restrictive covenants

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

Under the credit agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter, 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. The Company was in compliance with these covenants at September 30, 2020.

The credit agreement also places 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 is subject to customary events of default. If an event of default occurs and is continuing, the lenders may elect to accelerate amounts due under the credit agreement (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, 2020, 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. The Company’s Ranger Divestiture provides for potential contingent consideration to be received by the Company if commodity prices exceed specified thresholds in each of the next several years. See “Note 3 - Acquisitions and Divestitures” and “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 (3)

Divestiture Date Fair Value

$8,512

Actual Settlement

2019

Greater than $60/Bbl, less than $65/Bbl

$—

Equal to or greater than $65/Bbl

$—

1Q20

N/A

Remaining Potential Settlements

2020-2021

Greater than $60/Bbl, less than $65/Bbl

$9,000

Equal to or greater than $65/Bbl

$20,833

(2)

$41,666

(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 Inc.

(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. Therefore, if the commodity price threshold is reached, $8.5 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.

(3) The specified pricing threshold for 2019 was not met. As such, approximately $41.7 million remains for potential settlements in future years.

As a result of the Carrizo Acquisition, the Company assumed all contingent consideration arrangements previously entered into by Carrizo. These contingent consideration arrangements are summarized below:

Contingent ExL Consideration


	Year	Threshold (1)	Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Payment - Annual	Remaining Contingent Payments - Aggregate Limit	Acquisition Date Fair Value
					(In thousands)
							($69,171)
Actual Settlement(2)(3)	2019	$50.00	1Q20	Investing	($50,000)
Remaining Potential Settlements	2020-2021	$50.00	(2)	(2)	($25,000)	($25,000)

(1) The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration (“U.S. EIA”).

(2) Cash paid for settlements related to 2019 are classified as cash flows used in investing activities as the cash payment was made soon after the acquisition date. Due to the extended time frame over which the 2020 and 2021 contingent arrangements could settle, any future payments would be considered financing arrangements. As such, cash settlements of those contingent consideration arrangements would be classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold were reached, $19.2 million of the final contingent payment would be presented in cash flows used in financing activities with the remainder presented in operating cash flows.

(3) In January 2020, the Company paid $50.0 million as the specified pricing threshold was met. Only $25.0 million remains for potential settlements in future years.

Additionally, as part of the Carrizo Acquisition, the Company acquired contingent consideration arrangements where the Company could receive payments if certain pricing thresholds are met in 2020, which range between $53.00 - $60.00 per barrel of oil or $3.18 - $3.30 per MMBtu of natural gas. In January 2020, the Company received $10.0 million as the specified pricing thresholds were met for certain of the contingent consideration arrangements. As such, the aggregate limit of the remaining contingent receipts is $13.0 million and would be settled in January 2021 based on the specified pricing thresholds for 2020.

Warrants

The Company determined that the Warrants issued with the Second Lien Notes are required to be accounted for as a derivative instrument. The Company records the 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 Warrants recorded as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur.

Derivatives not designated as hedging instruments

The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value as “(Gain) loss on derivative contracts” in the consolidated statements of operations. Settlements are also recorded as a gain or loss on

derivative contracts in the consolidated statements of operations. As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheets. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:


	As of September 30, 2020
	Presented without		As Presented with
	Effects of Netting	Effects of Netting	Effects of Netting
ASSETS	(In thousands)
Commodity derivative instruments	$34,362	($24,541)	$9,821
Contingent consideration arrangements	—	—	—
Fair value of derivatives - current	$34,362	($24,541)	$9,821
Commodity derivative instruments	5,689	(5,457)	232
Contingent consideration arrangements	1,089	—	1,089
Other assets, net	$6,778	($5,457)	$1,321
LIABILITIES
Commodity derivative instruments	($59,488)	$24,541	($34,947)
Contingent consideration arrangements	(3)	—	(3)
Fair value of derivatives - current	($59,491)	$24,541	($34,950)
Commodity derivative instruments	(13,195)	5,457	(7,738)
Contingent consideration arrangements	(4,058)	—	(4,058)
Warrant liability	(23,909)	—	(23,909)
Fair value of derivatives - non current	($41,162)	$5,457	($35,705)


	As of December 31, 2019
	Presented without		As Presented with
	Effects of Netting	Effects of Netting	Effects of Netting
ASSETS	(In thousands)
Commodity derivative instruments	$26,849	($17,511)	$9,338
Contingent consideration arrangements	16,718	—	16,718
Fair value of derivatives - current	$43,567	($17,511)	$26,056
Commodity derivative instruments	—	—	—
Contingent consideration arrangements	9,216	—	9,216
Other assets, net	$9,216	$—	$9,216
LIABILITIES
Commodity derivative instruments	($38,708)	$17,511	($21,197)
Contingent consideration arrangements	(50,000)	—	(50,000)
Fair value of derivatives - current	($88,708)	$17,511	($71,197)
Commodity derivative instruments	(12,935)	—	(12,935)
Contingent consideration arrangements	(19,760)	—	(19,760)
Fair value of derivatives - non current	($32,695)	$—	($32,695)

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,
	2020	2019	2020	2019
	(In thousands)
(Gain) loss on oil derivatives	$16,606	($24,722)	($118,348)	$34,798
(Gain) loss on natural gas derivatives	7,296	(1,323)	18,819	(4,306)
(Gain) loss on NGL derivatives	2,421	—	2,418	—
(Gain) loss on contingent consideration arrangements	715	4,236	(855)	923
(Gain) loss on derivative contracts	$27,038	($21,809)	($97,966)	$31,415

The components of “Cash (paid) received for commodity derivative settlements” 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,
	2020	2019	2020	2019
	(In thousands)
Cash flows from operating activities
Cash (paid) received on oil derivatives	$2,130	($1,045)	$100,823	($7,048)
Cash (paid) received on natural gas derivatives	(1,677)	2,056	931	6,612
Cash (paid) received for commodity derivative settlements	$453	$1,011	$101,754	($436)

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, 2020:


	For the Remainder		For the Full Year
Oil contracts (WTI)	of 2020		of 2021
Swap contracts
Total volume (Bbls)	2,496,880		1,377,000
Weighted average price per Bbl	$42.10		$42.00
Collar contracts
Total volume (Bbls)	1,501,440		4,653,750
Weighted average price per Bbl
Ceiling (short call)	$45.00		$45.31
Floor (long put)	$35.00		$40.00
Short put contracts
Total volume (Bbls)	552,000		—
Weighted average price per Bbl	$42.50		$—
Long call contracts
Total volume (Bbls)	460,000		—
Weighted average price per Bbl	$67.50		$—
Short call contracts
Total volume (Bbls)	460,000	(1)	4,825,300	(1)
Weighted average price per Bbl	$55.00		$63.62
Short call swaption contracts
Total volume (Bbls)	—		730,000	(2)
Weighted average price per Bbl	$—		$47.00

Oil contracts (Brent ICE)
Swap contracts
Total volume (Bbls)	—		1,272,450
Weighted average price per Bbl	$—		$38.24
Collar contracts
Total volume (Bbls)	—		730,000
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)	1,380,000		3,022,900
Weighted average price per Bbl	($1.89)		$0.26

Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls)	1,435,202		—
Weighted average price per Bbl	$0.03		$—
Oil contracts (Argus Houston MEH swaps)
Swap contracts
Total volume (Bbls)	—		2,969,050
Weighted average price per Bbl	$—		$39.48

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

(2) The short call swaption contract has an exercise expiration date of October 30, 2020.


	For the Remainder	For the Full Year
Natural gas contracts (Henry Hub)	of 2020	of 2021
Swap contracts
Total volume (MMBtu)	1,633,000	11,123,000
Weighted average price per MMBtu	$2.05	$2.60
Collar contracts (three-way collars)
Total volume (MMBtu)	1,525,000	1,350,000
Weighted average price per MMBtu
Ceiling (short call)	$2.72	$2.70
Floor (long put)	$2.45	$2.42
Floor (short put)	$2.00	$2.00
Collar contracts (two-way collars)
Total volume (MMBtu)	1,525,000	9,550,000
Weighted average price per MMBtu
Ceiling (short call)	$3.25	$3.04
Floor (long put)	$2.67	$2.59
Short call contracts
Total volume (MMBtu)	2,013,000	7,300,000
Weighted average price per MMBtu	$3.50	$3.09

Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	4,421,000	12,775,000
Weighted average price per MMBtu	($0.91)	($0.47)

For the Remainder

For the Full Year

NGL contracts (OPIS Mont Belvieu Purity Ethane)

of 2020

of 2021

Swap contracts

Total volume (Bbls)

—

1,825,000

Weighted average price per Bbl

$—

$7.62

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 approximate 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 senior 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, 2020		December 31, 2019
	Principal Amount	Fair Value	Principal Amount	Fair Value
	(In thousands)
6.25% Senior Notes	$650,000	$273,000	$650,000	$658,125
6.125% Senior Notes	600,000	240,000	600,000	611,130
8.25% Senior Notes	250,000	92,500	250,000	256,250
6.375% Senior Notes	400,000	140,000	400,000	405,424
Total	$1,900,000	$745,500	$1,900,000	$1,930,929

Second Lien Notes. The fair value measurements of the Second Lien Notes are measured by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and are designated as Level 3 inputs. Significant inputs to the valuation of the Second Lien Notes include redemption premiums and redemption assumptions provided by the Company. The following table presents the principal amount of the Company’s Second Lien Notes with the fair value measured using the Level 3 inputs mentioned above. See “Note 6 - Borrowings” for details regarding the allocation of the net proceeds to the Second Lien Notes and Warrants.

September 30, 2020

December 31, 2019

Principal Amount

Fair Value

Principal Amount

Fair Value

(In thousands)

9.00% Second Lien Notes

$300,000

$260,966

$—

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 sheet. 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:


	September 30, 2020
	Level 1	Level 2	Level 3
	(In thousands)
Assets
Commodity derivative instruments	$—	$10,053	$—
Contingent consideration arrangements	—	1,089	—
Liabilities
Commodity derivative instruments	—	(42,685)	—
Contingent consideration arrangements	—	(4,061)	—
Total net assets (liabilities)	$—	($35,604)	$—

	December 31, 2019
	Level 1	Level 2	Level 3
	(In thousands)
Assets
Commodity derivative instruments	$—	$9,338	$—
Contingent consideration arrangements	—	25,934	—
Liabilities
Commodity derivative instruments	—	(34,132)	—
Contingent consideration arrangements	—	(69,760)	—
Total net assets (liabilities)	$—	($68,620)	$—

Warrants. The fair value of the Warrants was calculated by a third-party valuation specialist using a Black Scholes-Merton option pricing model. As historical volatility is a significant input into the model, the Warrants are designated as Level 3 within the valuation hierarchy. See “Note 6 - Borrowings” and “Note 7 - Derivative Instruments and Hedging Activities” for additional details regarding the Warrants.

The following table presents a reconciliation of the change in the fair value of the liability related to the Warrants for the nine months ended September 30, 2020.


						Nine Months Ended September 30, 2020
Beginning of period						$—
Recognition of issuance date fair value						23,909
Gain (loss) on changes in fair value						—
Transfers into (out of) Level 3						—
End of period						$23,909

Assets and liabilities measured at fair value on a nonrecurring basis

Acquisitions. The fair value of assets acquired and liabilities assumed, other than the contingent consideration arrangements which are discussed above, are measured as of the acquisition date by a third-party valuation specialist using a combination of income and market approaches, which are not observable in the market and are therefore designated as Level 3 inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and costs to produce and develop reserves, oil and natural gas forward prices, and a risk-adjusted discount rate. See “Note 3 - Acquisitions and Divestitures” for additional discussion.

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

Note 9 - Income Taxes

The Company provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls, and state income taxes. The following

table presents a reconciliation of the reported amount of income tax expense (benefit) to the amount of income tax expense (benefit) that would result from applying domestic federal statutory tax rates to pretax income (loss) from continuing operations:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019

Income tax provision computed at statutory federal income tax rate	21	%	21	%	21	%	21	%

State taxes net of federal expense	1	%	1	%	1	%	1	%

Section 162(m)	—	%	—	%	—	%	—	%

Effective income tax rate, before discrete items	22	%	22	%	22	%	22	%
Valuation allowance	(22	%)	—	%	(28	%)	—	%
Other discrete items (1)	—	%	2	%	—	%	2	%
Effective income tax rate, after discrete items	—	%	24	%	(6	%)	24	%

(1) Accounts for the potential impact of periodic volatility of stock-based compensation tax deductions on future effective tax rates.

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, 2020, driven primarily by the impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the three months ended September 30, 2020. This limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Beginning in the second quarter of 2020 and continuing through the third 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 of $520.8 million, reducing the net deferred tax assets as of September 30, 2020 to zero.

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

Due to the issuance of common stock associated with the Carrizo acquisition, the Company incurred a cumulative ownership change and as such, the Company’s net operating losses (“NOLs”) prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382. At September 30, 2020, the Company had approximately $897.0 million of NOLs, including $288.2 million acquired from Carrizo, of which approximately $496.5 million expire between 2035 and 2037 and $400.5 million have an indefinite carryforward life.

Note 10 - Share-based Compensation

Stock-Based Compensation Plans

At the Company’s annual meeting of shareholders on June 8, 2020, shareholders approved the 2020 Omnibus Incentive Plan (the “2020 Plan”), which replaced the 2018 Omnibus Incentive Plan (the “Prior Incentive Plan”). From the effective date of the 2020 Plan, no further awards may be granted under the Prior Incentive Plan, however, awards previously granted under the Prior Incentive Plan will remain outstanding in accordance with their terms. Effective August 7, 2020, in connection with the reverse stock split and reduction in authorized shares, the Board of Directors approved and adopted an amendment to the 2020 Plan to proportionately adjust the limitations on awards that may be granted. See “Note 11 - Stockholders’ Equity” for discussion of the reverse stock split and reduction in authorized shares. As of September 30, 2020, there were 1,967,782 common shares remaining available for grant under the 2020 Plan.

RSU Equity Awards

The following table summarizes activity for restricted stock units may be settled in common stock (“RSU Equity Awards”) for the three and nine months ended September 30, 2020 and 2019:


	Three Months Ended September 30,
	2020		2019
	RSU Equity Awards (in thousands) (1)	Weighted Average Grant Date Fair Value (1)	RSU Equity Awards (in thousands) (1)	Weighted Average Grant Date Fair Value (1)
Unvested, beginning of the period	719	$39.99	305	$105.86
Granted (2)	6	$9.35	—	$—
Vested (3)	(14)	$99.88	(17)	$131.20
Forfeited	(12)	$46.51	(8)	$110.81
Unvested, end of the period	699	$38.46	280	$104.17


	Nine Months Ended September 30,
	2020		2019
	RSU Equity Awards (in thousands) (1)	Weighted Average Grant Date Fair Value (1)	RSU Equity Awards (in thousands) (1)	Weighted Average Grant Date Fair Value (1)
Unvested, beginning of the period	269	$102.48	210	$130.39
Granted (2)	562	$21.07	188	$85.89
Vested (3)	(120)	$100.19	(96)	$124.24
Forfeited	(12)	$46.51	(22)	$116.20
Unvested, end of the period	699	$38.46	280	$104.17

(1)Shares and per share data have been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 - Stockholders’ Equity” for additional information.

(2)Includes zero target performance-based RSU Equity Awards during the three months ended September 30, 2020 and 2019, respectively, and 111.2 thousand and 38.8 thousand during the nine months ended September 30, 2020 and 2019, respectively. The performance-based RSU Equity Awards granted during the nine months ended September 30, 2020 and 2019 will vest at a range of 0% to 300% and 0% to 200%, respectively.

(3)The fair value of shares vested was $0.1 million and $0.8 million during the three months ended September 30, 2020 and 2019, respectively, and $1.4 million and $6.8 million for the nine months ended September 30, 2020 and 2019, respectively.

Grant activity for the nine months ended September 30, 2020 and 2019 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards in January and June 2020, respectively, as compared to the annual grant of long-term equity to executives and employees during the first quarter of 2019.

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 in 2020 and between 0% and 200% of the target units for the awards granted in 2018 and 2019. The increase in the maximum amount of performance-based RSU Equity Awards that can vest for the awards granted in 2020 is due to an absolute TSR modifier, which was added as a second factor in the calculation, in addition to the relative TSR multiplier. While the absolute TSR modifier could increase the number of awards that vest, the number of awards that vest could also be reduced 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 for the three months ended September 30, 2020 and 2019, respectively, and $3.4 million and $4.3 million for the nine months ended September 30, 2020 and 2019, 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 and 2019:


Performance-based Awards	June 29, 2020		January 31, 2020		January 31, 2019
Expected term (in years)	2.5		2.9		2.9
Expected volatility	113.2	%	54.8	%	47.9	%
Risk-free interest rate	0.2	%	1.3	%	2.4	%
Dividend yield	—	%	—	%	—	%

As of September 30, 2020, unrecognized compensation costs related to unvested RSU Equity Awards were $16.4 million and will be recognized over a weighted average period of 1.9 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, 2020 and 2019:


	Three Months Ended September 30,
	2020		2019
	Cash-Settled RSU Awards (in thousands) (1)	Weighted Average Grant Date Fair Value (1)	Cash-Settled RSU Awards (in thousands) (1)	Weighted Average Grant Date Fair Value (1)
Unvested, beginning of the period	208	$67.20	103	$129.67
Granted	—	$—	—	$—
Vested	(1)	$131.54	—	$—
Did not vest at end of performance period	(2)	$133.95	—	$—
Forfeited	—	$—	(3)	$132.86
Unvested, end of the period	205	$66.28	100	$129.58


	Nine Months Ended September 30,
	2020		2019
	Cash-Settled RSU Awards (in thousands) (1)	Weighted Average Grant Date Fair Value (1)	Cash-Settled RSU Awards (in thousands) (1)	Weighted Average Grant Date Fair Value (1)
Unvested, beginning of the period	86	$124.22	66	$147.59
Granted	125	$29.76	44	$105.08
Vested	(3)	$130.12	(2)	$108.10
Did not vest at end of performance period	(3)	$148.81	—	$—
Forfeited	—	$—	(8)	$145.65
Unvested, end of the period	205	$66.28	100	$129.58

Grant activity primarily consisted of Cash-Settled RSU Awards to executives as part of the annual grant of long-term equity incentive awards that occurred in the first half of each of the years presented in the table above. 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 for each of the respective periods presented 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, 2020	December 31, 2019
	(In thousands)
Other current liabilities	$49	$966
Other long-term liabilities	275	2,089
Total Cash-Settled RSU Awards	$324	$3,055

As of September 30, 2020, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $0.5 million and will be recognized over a weighted average period of 2.0 years.

Share-Based Compensation Expense, Net

Share-based compensation expense associated with the RSU Equity Awards, Cash-Settled RSU Awards, and cash-settled stock appreciation rights (“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,
	2020	2019	2020	2019
	(In thousands)
RSU Equity Awards	$3,009	$2,649	$10,169	$11,032
Cash-Settled RSU Awards	(566)	(1,116)	(1,966)	238
Cash SARs	(1,005)	—	(4,646)	—
	1,438	1,533	$3,557	$11,270
Less: amounts capitalized to oil and gas properties	(1,532)	(866)	(3,862)	(3,170)
Total share-based compensation expense (benefit), net	($94)	$667	($305)	$8,100

See “Note 10 - Stock-Based Compensation” of the Notes to Consolidated Financial Statements in the 2019 Annual Report for details of the Company’s equity-based incentive plans.

Note 11 - Stockholders’ Equity

Reverse Stock Split

On August 7, 2020, the Board of Directors effected a reverse stock split of the Company’s outstanding shares of common stock at a ratio of 1-for-10 and reduced the total number of authorized shares of the Company’s common stock pursuant to an amendment to the Company’s Certificate of Incorporation, which was approved by the Company’s shareholders at the Company’s annual meeting of shareholders on June 8, 2020. The reverse stock split became effective as of the close of business on August 7, 2020. The Company’s common stock began trading on a split-adjusted basis on the New York Stock Exchange (“NYSE”) at the market open on August 10, 2020. The par value of the common stock was not adjusted as a result of the reverse stock split.

The reverse stock split was intended to, among other things, increase the per share trading price of the Company’s common shares to satisfy the $1.00 minimum closing price requirement for continued listing on the NYSE. As a result of the reverse stock split, each 10 pre-split shares of common stock outstanding were automatically combined into one issued and outstanding share of common stock. The fractional shares that resulted from the reverse stock split were canceled by paying cash in lieu of the fair value. The number of outstanding shares of common stock were reduced from 397,479,684 as of August 7, 2020 to 39,746,967 shares. The total number of shares of common stock that the Company is authorized to issue was reduced from 525,000,000 to 52,500,000 shares. All share and per share amounts, except par value per share, in the accompanying consolidated financial statements and notes thereto were retroactively adjusted for all periods presented to give effect to this reverse stock split, including reclassifying an amount equal to the reduction in par value of common stock to additional paid-in capital in the current period.

Note 12 - Leases

The Company determines if an arrangement is a lease at inception of the contract. If the contract is determined to be a lease the Company classifies the lease as an operating or financing lease. The Company recognizes an operating or financing lease on its consolidated balance sheets as a lease liability, which represents the present value of the Company’s obligation to make lease payments arising from the lease. The Company also records a corresponding right-of-use (“ROU”) asset, which represents the Company’s right to use the underlying asset for the lease term. The Company’s operating leases typically do not provide an implicit interest rate, therefore, the Company utilizes its incremental borrowing rate to calculate the present value of the lease payments based on information available at inception of the contract.

Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease expense for financing leases is comprised of interest expense on the financing lease liability and the amortization of the associated ROU asset, which is also recognized on a straight-line basis over the lease term. Variable lease expense that is not dependent on an index or rate is not included in the operating or financing lease liability or ROU asset and is recognized in the period in which the obligation for those payments is incurred.

The majority of the lease liability on the Company’s consolidated balance sheets is comprised of its drilling rig and office lease contracts.

The tables below, which present the components of lease costs and supplemental balance sheet information are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment.

The table below presents the components of the Company’s lease costs for the periods indicated:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
	(In thousands)		(In thousands)
Components of Lease Costs
Finance lease costs	$252	$—	$1,380	$—
Amortization of right-of-use assets (1)	233	—	1,253	—
Interest on lease liabilities (2)	19	—	127	—
Operating lease costs (3)	9,347	7,964	39,251	27,122
Impairment of Operating lease ROU assets (4)	—	—	3,575	—
Short-term lease costs (5)	19	293	1,736	3,640
Variable lease costs (6)	116	—	190	—
Total lease costs	$9,734	$8,257	$46,132	$30,762

(1) Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations.

(2) Included as a component of “Interest expense, net of capitalized amounts” in the consolidated statements of operations.

(3) For the three months ended September 30, 2020 and 2019, approximately $6.1 million and $7.6 million were costs associated with drilling rigs. For the nine months ended September 30, 2020 and 2019, approximately $29.7 million and $21.5 million were costs associated with drilling rigs. and were capitalized to “Evaluated properties” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations.

(4) As a result of the downturn in economic conditions in conjunction with our ongoing effort to consolidate various office locations due to the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment. Upon evaluation, the Company recorded impairments of certain of its Operating lease ROU assets for the three and nine months ended September 30, 2020 of zero and $3.6 million which is a component of “Merger and integration expenses” in the consolidated statements of operations.

(5) Short-term lease costs exclude expenses related to leases with a contract term of one month or less.

(6) Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs.

The table below presents supplemental balance sheet information for the Company’s leases as of the periods indicated:


	September 30, 2020	December 31, 2019
	(In thousands)
Leases
Operating leases:
Operating lease ROU assets	$29,519	$63,908

Current operating lease liabilities	$19,458	$42,858
Long-term operating lease liabilities	28,906	37,088
Total operating lease liabilities	$48,364	$79,946

Financing leases:
Other property and equipment	$1,285	$2,197
Accumulated depreciation	(395)	(82)
Other property and equipment, net	$890	$2,115

Current financing lease liabilities	$321	$1,334
Long-term financing lease liabilities	543	807
Total financing lease liabilities	$864	$2,141

The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases for the period indicated:


	As of September 30, 2020
Weighted Average Remaining Lease Term (In years)
Operating leases	5.6
Financing leases	3.1

Weighted Average Discount Rate
Operating leases	5.5	%
Financing leases	6.8	%

The table below presents the maturity of the Company’s lease liabilities as of September 30, 2020:


	Operating Leases	Financing Leases
	(In thousands)
Remainder of 2020	$8,375	$120
2021	14,777	314
2022	5,438	250
2023	5,011	233
2024	4,935	39
Thereafter	18,098	—
Total lease payments	56,634	956
Less imputed interest	(8,270)	(92)
Total	$48,364	$864

Note 13 - Accounts Receivable, Net


	September 30, 2020	December 31, 2019
	(In thousands)
Oil and natural gas receivables	$81,364	$165,275
Joint interest receivables	15,700	39,114
Other receivables	17,240	6,610
Total	114,304	210,999
Allowance for doubtful accounts	(1,768)	(1,536)
Total accounts receivable, net	$112,536	$209,463

Note 14 - Accounts Payable and Accrued Liabilities


	September 30, 2020	December 31, 2019
	(In thousands)
Accounts payable	$104,665	$217,578
Revenues payable	148,387	145,816
Accrued capital expenditures	27,875	61,950
Accrued interest	49,370	36,295
Accrued severance (1)	2,682	28,803
Total accounts payable and accrued liabilities	$332,979	$490,442

(1) See “Note 3 - Acquisitions and Divestitures” for further information regarding the Carrizo Acquisition.

Note 15 - Supplemental Cash Flow


	Nine Months Ended September 30,
	2020	2019
Supplemental cash flow information:
Interest paid, net of capitalized amounts	$62,414	$—
Income taxes paid	—	—
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$35,919	$1,667
Investing cash flows from operating leases	16,956	25,455
Non-cash investing and financing activities:
Change in accrued capital expenditures	($72,782)	($15,032)
Change in asset retirement costs	1,208	(393)
ROU assets obtained in exchange for lease liabilities:
Operating leases	$10,475	$2,588

Note 16 - Subsequent Events

Hedging

Subsequent to September 30, 2020, the Company entered into the following derivative contracts:

For the Full Year

Oil contracts (WTI)

of 2021

Collar contracts

Total volume (Bbls)

4,769,525

Weighted average price per Bbl

Ceiling (short call)

$48.22

Floor (long put)

$38.44

For the Full Year

Natural gas contracts (Waha basis differential)

of 2021

Swap contracts

Total volume (MMBtu)

3,650,000

Weighted average price per MMBtu

($0.25)

Additionally, subsequent to September 30, 2020, the Company terminated 1,908,675 Bbls of Argus WTI-Houston fixed price oil swaps at a weighted average price of $39.78 per Bbl, certain of which were terminated contemporaneously with entering into the WTI collars above. The Company also terminated 424,150 Bbls of ICE Brent fixed price oil swaps at a weighted average price of $40.00 per Bbl, resulting in neither cash receipts or payments.

Non-operated sale

On November 2, 2020, the Company closed the sale of substantially all of its non-operated assets. See “Note 3 - Acquisitions and Divestitures” for additional details.

Senior Note Exchange

On November 2, 2020, the Company entered into an Exchange Agreement (the “Exchange Agreement”) with certain holders (the “Holders”) of the Company’s 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”), and 6.375% Senior Notes due 2026 (the “6.375% Senior Notes”, and together with the 6.25% Senior Notes, 6.125% Senior Notes, and 8.25% Senior Notes, the “Senior Unsecured Notes”). Pursuant to the Exchange Agreement, the Company has agreed to exchange $286.0 million of aggregate principal amount of Senior Unsecured Notes held by the Holders for $158.5 million aggregate principal amount of newly issued 9.00% Second Lien Senior Secured Notes due 2025 (the “New Notes”) at exchange ratios of $650, $575, $480 and $460 per $1,000 principal amount of 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes, and 6.375% Senior Notes, respectively, tendered (the “Exchange Ratios”).

Pursuant to the Exchange Agreement, the Company has also agreed to issue to the Holders approximately 1.16 million warrants exercisable for shares of common stock, with a term of 5 years and an exercise price of $5.60 per share, exercisable only on a net share settlement basis. The Holders and their affiliates may elect to include in the exchange up to an additional $104.0 million of Senior Unsecured Notes for New Notes at the Exchange Ratios set forth above. In the event the aggregate principal amount of Senior Unsecured Notes exchanged for New Notes at closing is greater than $286.0 million, the Company will increase proportionally the number of warrants to be issued to the Holders up to a warrant eligibility cap of $375.3 million. The maximum number of warrants issuable to the Holders is approximately 1.76 million.

Special Note Regarding Forward Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, 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:

•matters relating to the Carrizo Acquisition;

•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.

Some of the risks, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements, include:

•volatility of oil, natural gas and natural gas liquids (“NGLs”) prices or a prolonged period of low oil, natural gas or NGLs prices and the effects of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”), such as Saudi Arabia 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;

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

•the effects of excess supply of oil and natural gas resulting from the reduced demand caused by the COVID-19 pandemic and the actions by certain oil and natural gas producing countries;

•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;

•changes in customer demand and producers’ supply;

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

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

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

•any increase in severance or similar taxes;

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

•the comparative cost of alternative fuels;

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

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

•weather conditions;

•our ability to maintain compliance with the NYSE continued listing requirements and avert delisting of our common stock;

•risks associated with acquisitions, including the Carrizo Acquisition;

•failure to realize the expected benefits of the Carrizo Acquisition;

•any litigation relating to the Carrizo Acquisition; and

•any other factors listed in the reports we have filed and may file with the SEC.

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 risks include, but are not limited to, the risks described in Item 1A of our 2019 Annual Report and all quarterly reports on Form 10-Q filed subsequently thereto.

Should one or more of these risks or uncertainties described above or in our 2019 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Additional risks or uncertainties that are not currently known to us, that we currently deem to be immaterial, or that could apply to any company could also materially adversely affect our business, financial condition, or future results. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except required by applicable law.

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

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

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

General

The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and our 2019 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 incorporated in the State of Delaware in 1994, but our roots go back 70 years to our Company’s 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 Shale, which we entered into through the Carrizo Acquisition in late 2019.

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 Basin, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales, and more recently as a result of the Carrizo Acquisition, the Eagle Ford Shale. 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

COVID-19 Outbreak and Global Industry Downturn

The recent worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. As a result, there is an excess supply of oil in the United States, which could continue for a sustained period; this is in addition to recent and continued excess supply of natural gas in the United States. This excess supply has, in turn, resulted in transportation and storage capacity constraints in the United States, and may even cause the elimination of available storage, including in the Permian Basin.

The COVID-19 outbreak and its development into a pandemic in March 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers and the communities in which we operate. Our operational employees are currently still able to work on site. However, we have taken various precautionary measures with respect to such operational employees such as requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site, being prepared to quarantine any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected), and, while at the work site, imposing safety protocols in accordance with the guidelines released by the Center for Disease Control. In addition, a large portion of our non-operational employees are now working remotely, and we have established COVID-19 specific safety protocols for those working from the office. We have not yet experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of the COVID-19 outbreak. Due to the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we reduced our operations in order to preserve capital. We expect to fund the remainder of our 2020 capital expenditures with cash flows from operations and, if necessary, borrowings under our senior secured revolving credit facility. As substantially all of our revenues are generated by the production and sale of hydrocarbons, if it became necessary to curtail or shut-in a significant portion of our production, it could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.

We have resumed production from wells that were curtailed as a result of field level economic decisions in the second quarter, and we do not forecast additional shut-ins at this time. We have various firm transportation agreements on pipelines in both the Permian Basin as well as the Eagle Ford Shale to help manage delivery risk of our production and provide us with the ability to deliver to various regional markets where we have the potential to receive more favorable pricing as compared to selling to purchasers at the wellhead. See “—Contractual Obligations” below for further details.

Overview

Third Quarter 2020 Highlights

•Total production for the three months ended September 30, 2020 was 102,029 Boe/d, an increase of 170% from the three months ended September 30, 2019, primarily due to production from the Carrizo Acquisition and new wells placed on production during 2020, partially offset by normal production decline.

•Operated drilling and completion activity for the three months ended September 30, 2020 along with our drilled but uncompleted and producing wells as of September 30, 2020 are summarized in the table below.


	Three Months Ended September 30, 2020				As of September 30, 2020
	Drilled		Completed		Drilled But Uncompleted		Producing
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Permian Basin	—	—	6	5.5	30	27.4	842	731.7
Eagle Ford Shale	—	—	6	5.9	29	29.0	637	574.2
Total	—	—	12	11.4	59	56.4	1,479	1,305.9

▪Operational capital expenditures, inclusive of leasehold and seismic, for the third quarter of 2020 were $38.4 million, of which approximately 70% were in the Permian Basin with the remaining balance in the Eagle Ford. In response to the decline in commodity prices for oil and natural gas, we reduced activity relative to our original plan, including the suspension of all completion activity in April and transition to one active drilling rig in mid-May. We resumed activity during the third quarter and expect to operate three drilling rigs and one completion crew during the fourth quarter. Near-term operational activity will consist of drilling and completion activity in all three core asset areas in the fourth quarter while maintaining our drilled but uncompleted inventory. As a result, we currently forecast total operational capital expenditures to be approximately $500.0 to $510.0 million for the full year 2020. See “—Liquidity and Capital Resources—2020 Capital Plan and Outlook” for additional details.

•On August 7, 2020 and following approval by our shareholders at the June 8, 2020 annual meeting of shareholders of an amendment to our Certificate of Incorporation to effect a reverse stock split, our Board of Directors approved a reverse stock split of our common stock at a ratio of 1-for-10 and a reduction in the number of authorized shares of our common stock. Our common stock began trading on a split-adjusted basis on August 10, 2020 upon opening of the markets. See “Note 11 - Stockholders’ Equity” for additional information.

•On September 25, 2020, we entered into a Purchase and Sale Agreement to sell substantially all of our non-operated assets. We received $29.6 million on November 2, 2020 at closing, subject to post-closing adjustments, which was used to repay borrowings outstanding under our senior secured revolving credit facility. See “Note 3 - Acquisitions and Divestitures” for further discussion.

•On September 30, 2020, we entered into the ORRI Transaction where we sold an undivided 2.0% (on an 8/8ths basis) overriding royalty interest, proportionately reduced to our net revenue interest, in and to our operated leases, excluding certain interests as defined in the Purchase and Sale Agreement, for net proceeds of approximately $135.8 million, net of transaction costs. See “Note 3 - Acquisitions and Divestitures” for further discussion.

•On September 30, 2020, we issued $300.0 million in aggregate principal amount of Second Lien Notes and 7.3 million Warrants for proceeds, net of issuance costs, of approximately $288.6 million. See “Note 6 - Borrowings” and “Note 7 - Derivative Instruments and Hedging Activities” for further discussion.

•On September 30, 2020, we entered into the second amendment to our credit agreement governing the revolving credit facility which, among other things, reaffirmed the $1.7 billion borrowing base as a result of the fall 2020 scheduled redetermination. Also on September 30, 2020, we entered into the third amendment to our credit agreement governing the revolving credit facility which, among other things, (a) established a new borrowing base of $1.6 billion and reduced the elected commitments to $1.6 billion in connection with the issuance of the Second Lien Notes and Warrants and ORRI Transaction; (b) permitted the issuance of the $300.0 million of Second Lien Notes as contemplated by the Purchase Agreement without triggering a reduction in the borrowing base; (c) extended through the end of 2021 the time period during which Exchange Notes may be issued without triggering a reduction in the borrowing base; and (d) if the Second Lien Notes are outstanding at such time, caused the maturity of the revolving credit facility to spring forward to a date which is 182 days prior to the maturity of any of the 6.25% Senior Notes or the 6.125% Senior Notes, in each case, to the extent a principal amount of more than $100.0 million with respect to each such issuance is outstanding as of such date. See “Note 6 - Borrowings” for further discussion.

•We recorded a loss available to common stockholders for the three months ended September 30, 2020 of $680.4 million, or $17.12 per diluted share, as compared to income available to common stockholders for the three months ended September 30,

2019 of $47.2 million, or $2.07 per diluted share. The change from income available to common stockholders to loss available to common stockholders between the respective periods was driven primarily by the recording of an impairment of evaluated oil and gas properties of $685.0 million during the third quarter of 2020 as well as a loss on derivative contracts of approximately $27.0 million during the third quarter of 2020 compared to a gain on derivative contracts of approximately $21.8 million during the third quarter of 2019. 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 September 30,							Nine Months Ended September 30,
	2020		2019		Change	% Change		2020		2019		Change	% Change
Total production (1)
Oil (MBbls)	5,875		2,725		3,150	116	%	18,118		8,431		9,687	115	%
Natural gas (MMcf)	10,261		4,538		5,723	126	%	31,064		14,188		16,876	119	%
NGLs (MBbls)	1,802		—		1,802	100	%	5,166		—		5,166	100	%
Total barrels of oil equivalent (MBoe)	9,387		3,481		5,906	170	%	28,461		10,796		17,665	164	%
Total daily production (Boe/d)	102,029		37,837		64,192	170	%	103,873		39,546		64,327	163	%
Oil as % of total daily production	63	%	78	%				64	%	78	%

Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)	$39.43		$54.39		($14.96)	(28	%)	$34.66		$53.38		($18.72)	(35	%)
Natural gas (per Mcf)	1.47		1.58		(0.11)	(7	%)	1.07		1.79		(0.72)	(40	%)
NGLs (per Bbl)	12.78		—		12.78	100	%	10.77		—		10.77	100	%
Total (per Boe)	$28.73		$44.64		($15.91)	(36	%)	$25.19		$44.04		($18.85)	(43	%)







Revenues (in thousands)
Oil	$231,654		$148,210		$83,444	56	%	$627,934		$450,036		$177,898	40	%
Natural gas	15,034		7,168		7,866	110	%	33,305		25,441		7,864	31	%
NGLs	23,025		—		23,025	100	%	55,627		—		55,627	100	%
Total	$269,713		$155,378		$114,335	74	%	$716,866		$475,477		$241,389	51	%

Benchmark prices (2)
WTI (per Bbl)	$40.94		$56.34		($15.40)	(27	%)	$38.30		$57.04		($18.74)	(33	%)
Henry Hub (per Mcf)	2.13		2.38		(0.25)	(11	%)	1.92		2.62		(0.70)	(27	%)

(1) Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, we presented our sales and reserves volumes, prices, and revenues for NGLs with natural gas.

(2) 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 September 30				Nine Months Ended September 30
	Oil	Natural Gas	NGLs	Total	Oil	Natural Gas	NGLs	Total
	(In thousands)
Revenues for the periods ended in 2019	$148,210	$7,168	$—	$155,378	$450,036	$25,441	$—	$475,477
Volume increase (decrease)	171,325	9,040	23,025	203,390	517,080	30,261	55,627	602,968
Price increase (decrease)	(87,881)	(1,174)	—	(89,055)	(339,182)	(22,397)	—	(361,579)
Net increase (decrease)	83,444	7,866	23,025	114,335	177,898	7,864	55,627	241,389
Revenues for the periods ended in 2020 (1)	$231,654	$15,034	$23,025	$269,713	$627,934	$33,305	$55,627	$716,866

Commodity Prices

The prices for oil, natural gas, and NGLs remain extremely volatile primarily due to the underlying supply and demand concerns as a result of COVID-19 as well as the actions taken by OPEC and other countries as described above. Prices of oil, natural gas, and NGLs will affect the following aspects of our business:

•our revenues, cash flows and earnings;

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

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

•the amount we are allowed to borrow under the revolving credit facility; and

•the value of our oil and natural gas properties.

Period over Period Variances

The change in absolute value for the three and nine months ended September 30, 2020 as compared to September 30, 2019 can be primarily attributed to the Carrizo Acquisition which closed in December 2019. The Carrizo Acquisition had a material impact to our reported results of operations. In order to provide a more meaningful basis for comparison, we focused our discussion on per unit metrics and only expanded on changes in absolute value where appropriate.

Oil revenue

For the three months ended September 30, 2020, oil revenues of $231.7 million increased $83.4 million, or 56%, compared to revenues of $148.2 million for the same period of 2019. The increase was primarily attributable to a 116% increase in production as a result of the Carrizo Acquisition and our development efforts. The increase in production was partially offset by the 28% decline in the average realized sales price which fell to $39.43 per Bbl from $54.39 per Bbl.

For the nine months ended September 30, 2020, oil revenues of $627.9 million increased $177.9 million, or 40%, compared to revenues of $450.0 million for the same period of 2019. The increase was primarily attributable to the 115% increase in production as a result of the Carrizo Acquisition and our development efforts. The increase was partially offset by a 35% decline in the average realized sales price which fell to $34.66 per Bbl from $53.38 per Bbl.

Natural gas revenue

For the three months ended September 30, 2020, natural gas revenues of $15.0 million increased $7.9 million, or 110%, compared to $7.2 million for the same period of 2019. The increase was primarily attributable to the 126% increase in production as a result of the Carrizo Acquisition and our development efforts. The increase was partially offset by a 7% decline in the average realized sale price which fell to $1.47 per Mcf from $1.58 per Mcf.

For the nine months ended September 30, 2020, natural gas revenues of $33.3 million increased $7.9 million, or 31%, compared to $25.4 million for the same period in 2019. The increase was primarily attributable to the 119% increase in production as a result of the Carrizo Acquisition and our development efforts. The increase was partially offset by a 40% decline in the average realize sales price, which fell to $1.07 per Mcf from $1.79 per Mcf.

NGL revenue

For the three and nine months ended September 30, 2020, NGL revenues were $23.0 million and $55.6 million, or $12.78 and $10.77 per Bbl, compared to no revenues for the same period of 2019. The increase was due to the modification of certain of our natural gas processing agreements, which allowed us to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, we presented our sales and reserves volumes, prices, and revenues for NGLs with natural gas.

Operating Expenses


	Three Months Ended September 30,
		Per		Per	Total Change			Boe Change
	2020	Boe	2019	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Lease operating expenses	$45,870	$4.89	$19,668	$5.65	$26,202	133	%	($0.76)	(13	%)
Production and ad valorem taxes	16,110	1.72	11,866	3.41	4,244	36	%	(1.69)	(50	%)
Gathering, transportation and processing	22,200	2.36	—	—	22,200	100	%	2.36	100	%
Depreciation, depletion and amortization	114,201	12.17	56,130	16.12	58,071	103	%	(3.95)	(25	%)
General and administrative	8,224	0.88	9,388	2.70	(1,164)	(12	%)	(1.82)	(67	%)
Impairment of evaluated oil and gas properties	684,956	72.97	—	—	684,956	100	%	72.97	100	%
Merger and integration	2,465	0.26	5,943	1.71	(3,478)	(59	%)	(1.45)	(85	%)


	Nine Months Ended September 30,
		Per		Per	Total Change			Boe Change
	2020	Boe	2019	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Lease operating expenses	$149,091	$5.24	$66,511	$6.16	$82,580	124	%	($0.92)	(15	%)
Production and ad valorem taxes	46,151	1.62	33,810	3.13	12,341	37	%	(1.51)	(48	%)
Gathering, transportation and processing	56,615	1.99	—	—	56,615	100	%	1.99	100	%
Depreciation, depletion and amortization	384,594	13.51	179,275	16.61	205,319	115	%	(3.10)	(19	%)
General and administrative	26,573	0.93	34,729	3.22	(8,156)	(23	%)	(2.29)	(71	%)
Impairment of evaluated oil and gas properties	1,961,474	68.92	—	—	1,961,474	100	%	68.92	100	%
Merger and integration	26,362	0.93	5,943	0.55	20,419	344	%	0.38	69	%

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, 2020 increased to $45.9 million compared to $19.7 million for the same period of 2019. The increase in lease operating expense was primarily related to a 170% increase in production over the comparative periods, which carries a variable component for each unit of production.

Lease operating expense on a per unit basis decreased to $4.89 for the third quarter of 2020, which represents a decrease of $0.76 per Boe from the third quarter of 2019. The lower per unit metric reflects the distribution of fixed costs spread over higher production volumes.

Lease operating expenses for the nine months ended September 30, 2020 increased to $149.1 million compared to $66.5 million for the same period of 2019. The increase in LOE was primarily related to a 164% increase in production over the comparative periods, which carries a variable component for each unit of production.

Lease operating expenses on a per unit basis decreased to $5.24 for the nine months ended September 30, 2020, which represents a decrease of $0.92 per Boe from the comparable period in 2019. The lower per unit metric reflects the distribution of fixed costs spread over higher production volumes.

Production and ad valorem taxes. In general, production taxes are based upon current year commodity prices whereas ad valorem taxes are based upon prior year commodity prices. Production 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. We benefit from tax credits and exemptions in our various taxing jurisdictions where available.

Production and ad valorem taxes for the three months ended September 30, 2020 increased 36% to $16.1 million compared to $11.9 million for the same period of 2019, which is primarily related to a 74% increase in total revenues. Production and ad valorem taxes as a percentage of total revenues decreased to 6.0% for the third quarter of 2020 as compared to 7.6% of revenues for the same period of 2019 primarily due to the contribution of the Carrizo Acquisition assets which carried lower effective production tax rates as a result of the impacts of natural gas and NGL marketing deductions and exemptions.

Production and ad valorem taxes for the nine months ended September 30, 2020 increased 37% to $46.2 million compared to $33.8 million for the same period of 2019, which is primarily related to a 51% increase in total revenues. Production and ad valorem taxes as a percentage of total revenues decreased to 6.4% for the nine months ended September 30, 2020 as compared to 7.1% of revenues for the same period of 2019 primarily due to the contribution of the Carrizo Acquisition assets which carried lower effective production tax rates as a result of the impacts of natural gas and NGL marketing deductions and exemptions.

Gathering, transportation and processing expenses. Gathering, transportation and processing costs for the three and nine months ended September 30, 2020 were $22.2 million and $56.6 million, respectively. No expense was recognized for gathering, transportation and processing costs during the same period of 2019. The change is due to the assumption of the processing agreements assumed in the Carrizo acquisition and certain contract modifications effective January 1, 2020. As such, the Company now records contractual fees associated with gathering, processing, treating and compression, as well as any transportation fees incurred to deliver the product to the purchaser, as gathering, transportation and processing expense. These fees were historically recorded as a reduction of revenue depending on when control transferred to the purchaser.

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 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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(In thousands, except per Boe amounts)
	Amount	Per Boe	Amount	Per Boe	Amount	Per Boe	Amount	Per Boe
DD&A of evaluated oil and gas properties	$111,699	$11.90	$56,000	$16.09	$377,353	$13.26	$178,673	$16.55
Depreciation of other property and equipment	836	0.09	2	—	2,908	0.10	17	0.01
Amortization of other assets	837	0.09	—	—	1,832	0.06	—	—
Accretion of asset retirement obligations	829	0.09	128	0.03	2,501	0.09	585	0.05
DD&A	$114,201	$12.17	$56,130	$16.12	$384,594	$13.51	$179,275	$16.61

For the three and nine months ended September 30, 2020, DD&A expense was $114.2 million and $384.6 million compared to $56.1 million and $179.3 million for the same periods of 2019. The additional DD&A was primarily related to DD&A of evaluated oil and gas properties, which is determined using the units of production method. The increase in DD&A of evaluated oil and gas properties for the three and nine months ended September 30, 2020, resulted from production increases of 170% and 164%, respectively, which were partially offset by lower DD&A rates between the periods. Those factors accounted for a $70.3 million increase and $14.6 million offsetting decrease, respectively, during the third quarter of 2020. Similarly, the increased production and decreased per unit rate accounted for a $234.2 million increase and $35.5 million offsetting decrease, respectively, for the nine months ended September 30, 2020 as compared to 2019.

The decrease in DD&A rates on a per unit basis across both periods was primarily a result of the Carrizo Acquisition which contributed to a significant increase in our proved reserves at a lower relative cost per Boe than our historical DD&A rate as well as the impairment of evaluated oil and gas properties that was recognized during the second quarter of 2020.

General and administrative, net of amounts capitalized (“G&A”). G&A for the three months ended September 30, 2020 was $8.2 million compared to $9.4 million for the comparative period in 2019 due to cost saving initiatives, which were partially offset by increased headcount of the combined companies. Additionally, G&A for the nine months ended September 30, 2020 decreased $8.2 million compared to 2019 primarily due to cost saving initiatives and a decrease in the fair value of the Cash-Settled RSU Awards and Cash SARs.

Impairment of evaluated oil and gas properties. We recognized impairments of evaluated oil and gas properties of $685.0 million and $2.0 billion for the three and nine months ended September 30, 2020, respectively, due primarily to declines in the 12-Month Average

Realized Price of crude oil. There was no impairment of evaluated oil and gas properties for the three or nine months ended September 30, 2019. See “Note 4 - Property and Equipment, Net” for further discussion.

Merger and integration expense. For the three and nine months ended September 30, 2020, the Company incurred expenses associated with the Carrizo Acquisition of $2.5 million and $26.4 million, respectively, as compared to $5.9 million for both the three and nine months ended September 30, 2019. See “Note 3 - Acquisitions and Divestitures” for additional information regarding the merger with Carrizo.

Other Income and Expenses


	Three Months Ended September 30,					Nine Months Ended September 30,
	2020	2019	$ Change	% Change		2020	2019	$ Change	% Change
	(In thousands, except % amounts)
Interest expense	$45,358	$18,869	$26,489	140	%	$133,427	$58,929	$74,498	126	%
Capitalized interest	(20,675)	(18,130)	(2,545)	14	%	(65,584)	(56,711)	(8,873)	16	%
Interest expense, net of capitalized amounts	24,683	739	23,944	3,240	%	67,843	2,218	65,625	2,959	%
(Gain) loss on derivative contracts	$27,038	($21,809)	$48,847	(224	%)	($97,966)	$31,415	($129,381)	(412	%)

Interest expense, net of capitalized amounts. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our revolving 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, annual agency fees, and interest from our financing leases in interest expense.

Interest expense, net of capitalized amounts, incurred during the three months ended September 30, 2020 increased $23.9 million to $24.7 million compared to $0.7 million for the same period of 2019. Additionally, interest expense, net of capitalized amounts, incurred during the nine months ended September 30, 2020 increased $65.6 million to $67.8 million compared to $2.2 million for the same period of 2019. The increase is primarily due to debt that was assumed as a result of the Carrizo Acquisition.

(Gain) loss on derivative contracts. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) (gain) loss related to fair value adjustments on our open derivative contracts and (ii) (gains) losses on settlements of derivative contracts for positions that have settled within the period. The net (gain) loss on derivative instruments for the periods indicated includes the following:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
	(In thousands)
(Gain) loss on oil derivatives	$16,606	($24,722)	($118,348)	$34,798
(Gain) loss on natural gas derivatives	7,296	(1,323)	18,819	(4,306)
(Gain) loss on NGL derivatives	2,421	—	2,418	—
(Gain) loss on contingent consideration arrangements	715	4,236	(855)	923
(Gain) loss on derivative contracts	$27,038	($21,809)	($97,966)	$31,415

See “Note 7 - Derivative Instruments and Hedging Activities” and “Note 8 - Fair Value Measurements” of the Notes to our Consolidated Financial Statements for additional information.

Sales and cost of purchased oil and gas. For the three and nine months ended September 30, 2020, we recorded sales of purchased oil and gas of $20.3 million and $21.5 million, respectively, and cost of purchased oil and gas of $21.3 million and $22.5 million, respectively, related to commodities purchased from third parties and sold to our customers. No sales or cost of purchased oil and gas occurred during the same periods of 2019.

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.

As a result of the valuation allowance that we recorded against our net deferred tax assets, we did not have any income tax expense for the three months ended September 30, 2020, compared to $17.9 million for the same period of 2019. Additionally, we recorded income tax expense of $115.3 million for the nine months ended September 30, 2020, compared to $29.4 million for the same period of 2019. The increase in expense is due to the recording of a valuation allowance during the nine months ended September 30, 2020.

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, 2020, driven primarily by impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the three months ended September 30, 2020, which limits the ability to consider other subjective evidence such as our potential for future growth. Beginning in the second quarter of 2020 and continuing through the third 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 of $520.8 million, reducing the net deferred tax assets as of September 30, 2020 to zero. See “Note 9 - Income Taxes” for further discussion.

Preferred stock dividends. On July 18, 2019, we redeemed all outstanding shares of Preferred Stock, after which, the Preferred Stock was no longer deemed outstanding and dividends ceased to accrue. As such, we did not make any Preferred Stock dividend payments during the three and nine months ended September 30, 2020. Preferred Stock dividends of $0.4 million and $4.0 million were paid during the three and nine months ended September 30, 2019.

Liquidity and Capital Resources

Our primary uses of capital have historically been for the acquisition, development, and exploration of oil and natural gas properties. Our capital program could vary depending upon factors, including, but not limited to, continued 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. 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.

Historically, our primary sources of capital have been cash flows from operations, borrowings under our revolving 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.

Overview of Cash Flow Activities. For the nine months ended September 30, 2020, cash and cash equivalents decreased $2.8 million to $10.5 million compared to $13.3 million at December 31, 2019.


	Nine Months Ended September 30,
	2020	2019
	(In thousands)
Net cash provided by operating activities	$425,197	$338,738
Net cash used in investing activities	(449,667)	(264,261)
Net cash provided by (used in) financing activities	21,629	(79,219)
Net change in cash and cash equivalents	($2,841)	($4,742)

Operating activities. For the nine months ended September 30, 2020, net cash provided by operating activities was $425.2 million compared to net cash provided by operating activities of $338.7 million for the same period in 2019. The change in operating activities was predominantly attributable to the following:

•An increase in revenue due to a 164% increase in production volumes predominantly as a result of the Carrizo Acquisition, which was partially offset by a decrease in realized pricing,

•An increase in the cash received from commodity derivative settlements, and

•An offsetting increase in operating expenses as a result of higher production volumes.

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, 2020, net cash used in investing activities was $449.7 million compared to $264.3 million for the same period in 2019.

Net cash used in investing activities for the following periods included:


	Nine Months Ended September 30,
	2020	2019	$ Change
	(In thousands)




Capital expenditures	$567,746	$503,425	$64,321
Acquisitions	—	40,788	(40,788)
Proceeds from the sale of assets	(149,818)	(279,952)	130,134
Cash paid for settlements of contingent consideration arrangements, net	40,000	—	40,000
Other, net	(8,261)	—	(8,261)
Total investing activities	$449,667	$264,261	$185,406

Cash used in investing activities increased by approximately $185.4 million for the nine months ended September 30, 2020 compared to the same period in 2019 due primarily to lower proceeds from the sale of assets during the nine months ended September 30, 2020. In 2019, we sold certain non-core assets in the southern Midland Basin (the “Ranger Asset Divestiture”) for net cash proceeds of $244.9 million. See Note 3 - “Acquisitions and Divestitures” for further discussion of this divestiture.

Financing activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our credit facility, term debt and equity offerings. For the nine months ended September 30, 2020, net cash provided by financing activities was $21.6 million compared to net cash used in financing activities of $79.2 million for the same period of 2019.

Net cash provided by (used in) financing activities for the following periods included:


	Nine Months Ended September 30,
	2020	2019	$ Change
	(In thousands)
Net borrowings on senior secured revolving credit facility	($260,000)	$—	($260,000)







Issuance of Second Lien Notes, net of discount	264,730	—	264,730
Issuance of warrants	23,909	—	23,909
Payment of deferred financing costs	(6,312)	(31)	(6,281)
Payment of preferred stock dividends(1)	—	(3,997)	3,997
Tax withholdings related to restricted stock units and other	(698)	(2,174)	1,476
Redemption of preferred stock	—	(73,017)	73,017

Net cash provided by (used in) financing activities	$21,629	($79,219)	$100,848

(1) On July 18, 2019, we redeemed all outstanding shares of the Preferred Stock, after which, the Preferred Stock were no longer deemed outstanding and dividends on the Preferred Stock ceased to accrue.

See “Note 6 - Borrowings”, “Note 7 - Derivative Instruments and Hedging Activities” and “Note 10 - Share-based Compensation” for additional information on our debt, derivative instruments and equity transactions.

We have a senior secured revolving credit facility with a syndicate of lenders that, as of September 30, 2020, had a borrowing base of $1.6 billion, with an elected commitment amount of $1.6 billion, borrowings outstanding of $1.03 billion at a weighted average interest rate of 2.93%, and $24.2 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 revolving credit facility is secured by first preferred mortgages covering our major producing properties.

On May 7, 2020, we entered into the first amendment to our credit agreement governing the revolving credit facility and on September 30, 2020, we entered into the second and third amendments to our credit agreement governing the revolving credit facility. See “Note 6 - Borrowings” for further discussion of these amendments. On September 30, 2020, we issued $300.0 million in aggregate principal amount of Second Lien Notes and 7.3 million Warrants for proceeds, net of issuance costs, of approximately $288.6 million, which we used to repay borrowings outstanding under our senior secured revolving credit facility.

On November 2, 2020, we entered into a privately negotiated agreement with certain holders of our Senior Unsecured Notes to exchange $286.0 million of principal of our Senior Unsecured Notes for $158.5 million aggregate principal of newly issued 9.00% Second Lien Secured Notes due 2025 at a weighted average exchange ratio of approximately $555 per $1,000 of principal exchanged. See “Note 16 - Subsequent Events” for further discussion.

Even with the downturn in commodity prices as well as a drop in demand as a result of COVID-19, we expect to have sufficient liquidity to pay interest on our revolving credit facility, Second Lien Notes, and our Senior Unsecured Notes as well as to fund our

development program. 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. Additionally, if the current commodity price environment were to persist for an extended period, our ability to remain in compliance with our restrictive financial covenants could be challenged. If we are unable to remain in compliance with our restrictive financial covenants, we could be subject to lender elections for default resolution.

Hedging. As of October 29, 2020, the Company had the following outstanding oil, natural gas and NGL derivative contracts:


	For the Remainder		For the Full Year
Oil contracts (WTI)	of 2020		of 2021
Swap contracts
Total volume (Bbls)	2,496,880		1,377,000
Weighted average price per Bbl	$42.10		$42.00
Collar contracts
Total volume (Bbls)	1,501,440		9,423,275
Weighted average price per Bbl
Ceiling (short call)	$45.00		$46.78
Floor (long put)	$35.00		$39.21
Short put contracts
Total volume (Bbls)	552,000		—
Weighted average price per Bbl	$42.50		$—
Long call contracts
Total volume (Bbls)	460,000		—
Weighted average price per Bbl	$67.50		$—
Short call contracts
Total volume (Bbls)	460,000	(1)	4,825,300	(1)
Weighted average price per Bbl	$55.00		$63.62

Oil contracts (Brent ICE)
Swap contracts
Total volume (Bbls)	—		848,300
Weighted average price per Bbl	$—		$37.36
Collar contracts
Total volume (Bbls)	—		730,000
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)	1,380,000		3,022,900
Weighted average price per Bbl	($1.89)		$0.26

Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls)	1,435,202		—
Weighted average price per Bbl	$0.03		$—
Oil contracts (Argus Houston MEH swaps)
Swap contracts
Total volume (Bbls)	—		1,060,375
Weighted average price per Bbl	$—		$38.94

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


	For the Remainder	For the Full Year
Natural gas contracts (Henry Hub)	of 2020	of 2021
Swap contracts
Total volume (MMBtu)	1,633,000	11,123,000
Weighted average price per MMBtu	$2.05	$2.60
Collar contracts (three-way collars)
Total volume (MMBtu)	1,525,000	1,350,000
Weighted average price per MMBtu
Ceiling (short call)	$2.72	$2.70
Floor (long put)	$2.45	$2.42
Floor (short put)	$2.00	$2.00
Collar contracts (two-way collars)
Total volume (MMBtu)	1,525,000	9,550,000
Weighted average price per MMBtu
Ceiling (short call)	$3.25	$3.04
Floor (long put)	$2.67	$2.59
Short call contracts
Total volume (MMBtu)	2,013,000	7,300,000
Weighted average price per MMBtu	$3.50	$3.09

Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	4,421,000	16,425,000
Weighted average price per MMBtu	($0.91)	($0.42)

For the Remainder

For the Full Year

NGL contracts (OPIS Mont Belvieu Purity Ethane)

of 2020

of 2021

Swap contracts

Total volume (Bbls)

—

1,825,000

Weighted average price per Bbl

$—

$7.62

2020 Capital Plan and Outlook

Our original operational capital budget for 2020 was established at $975.0 million, which included running an average of eight to nine drilling rigs and an average of three completion crews. In response to the decline in commodity prices for oil and natural gas, we reduced activity relative to our original plan, including the suspension of all completion activity in April and transition to one active drilling rig in mid-May. We resumed activity during the third quarter and expect to operate three drilling rigs and one completion crew during the fourth quarter. Near-term operational activity will consist of drilling and completion activity in all three core asset areas in the fourth quarter while maintaining our drilled but uncompleted inventory. As a result, we currently forecast total operational capital expenditures to be approximately $500.0 to $510.0 million for the full year 2020.

Our revenues, earnings, liquidity, and ability to deliver returns to our shareholders are substantially dependent on the prices we receive for, and our ability to develop our proved reserves. We monitor current and expected market conditions including the commodity price environment and our liquidity needs, and we may adjust our capital investment plan accordingly. Additionally, we may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to divest such assets on terms that are acceptable to us.

Contractual Obligations

The following table includes our current contractual obligations and purchase commitments as of September 30, 2020:


	Payments due by Period
	October - December 2020	2021	2022	2023	2024 and Thereafter	Total
	(In thousands)
6.25% Senior Notes (1)	$—	$—	$—	$650,000	$—	$650,000
6.125% Senior Notes (1)	—	—	—	—	600,000	600,000
8.25% Senior Notes (1)	—	—	—	—	250,000	250,000
6.375% Senior Notes (1)	—	—	—	—	400,000	400,000
Second Lien Notes (1)					300,000	300,000
Senior secured revolving credit facility (2)	—	—	—	—	1,025,000	1,025,000
Interest expense and other fees related to debt commitments (3)	46,885	183,286	183,286	162,974	226,798	803,229
Delivery commitments (4)	3,469	13,437	10,980	11,553	51,715	91,154
Operating leases	3,639	10,460	5,438	5,011	23,033	47,581
Asset retirement obligations (5)	2,857	23	380	197	48,942	52,399
Produced water disposal commitments (6)	7,687	21,355	18,321	10,775	12,983	71,121
Drilling rig leases (7)	4,736	4,317	—	—	—	9,053
Other commitments	290	884	524	392	39	2,129
Total contractual obligations	$69,563	$233,762	$218,929	$840,902	$2,938,510	$4,301,666

(1)Includes the outstanding principal amount only.

(2)The revolving credit facility has a maturity date of December 20, 2024, subject to springing maturity dates as discussed above. See “Note 6 – Borrowings” for additional information.

(3)Includes estimated cash payments on the 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes, 6.375% Senior Notes, Second Lien Notes, the revolving credit facility and commitment fees calculated based on the unused portion of lender commitments as of September 30, 2020, at the applicable commitment fee rate.

(4)Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil and natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas.

(5)Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment.

(6)Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water.

(7)Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on September 30, 2020. The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our consolidated financial statements as incurred.

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: use of estimates, oil and gas properties, oil and gas reserve estimates, derivative instruments, contingent consideration arrangements, income taxes, and commitments and contingencies. These policies and estimates are described in “Note 2 - Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our 2019 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.

Impairment of Evaluated Oil and Gas Properties

Capitalized costs, less accumulated amortization and related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (A) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures

to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (B) the costs of unevaluated properties not being amortized, and (C) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. If the net capitalized costs exceed the cost center ceiling, the excess is recognized as an impairment of evaluated oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices in the future increase the cost center ceiling applicable to the subsequent period.

The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period (“12-Month Average Realized Price”). Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of derivative instruments because we elected not to meet the criteria to qualify our derivative instruments for hedge accounting treatment.

Due primarily to declines in the average realized prices for sales of oil and gas on the first calendar day of each month during the trailing 12-month period 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 as summarized in the table below:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Impairment of evaluated oil and gas properties (in thousands)	$684,956		$—		$1,961,474		$—
Beginning of period 12-Month Average Realized Price ($/Bbl)	$45.87		$53.00		$53.90		$58.40
End of period 12-Month Average Realized Price ($/Bbl)	$41.71		$52.44		$41.71		$52.44
Percent decrease in 12-Month Average Realized Price	(9	%)	(1	%)	(23	%)	(10	%)

The decrease in the 12-Month Average Realized Price as of September 30, 2020 reduced our proved oil and gas reserve volumes by approximately 9.6 MMBoe, or less than 2% of our December 31, 2019 proved oil and gas reserves volumes. This reduction was primarily attributable to proved developed reserves of producing wells and proved undeveloped reserves with shorter economic lives. Volumes associated with locations of proved undeveloped reserves that were no longer economic and removed from proved reserves as a result of the decrease in the 12-Month Average Realized Price as of September 30, 2020 were less than 0.5% of our December 31, 2019 proved oil and gas reserves. There were no impairments of evaluated oil and gas properties for the three months ended March 31, 2020 or for the corresponding prior year periods.

Based on the first calendar day of each month oil and gas prices available for the 10 months ended October 1, 2020 and an estimate for the eleventh and twelfth months based on a quoted forward price, we anticipate recording an additional impairment in the carrying value of evaluated oil and gas properties in the fourth quarter of 2020 in the range of $500.0 million to $750.0 million. We currently estimate that the forecasted decrease in the 12-Month Average Realized Price as of December 31, 2020 will result in a reduction of our proved oil and gas reserve volumes of less than 2% of our December 31, 2019 proved oil and gas reserves volumes. This estimated reduction is primarily attributable to proved developed reserves of producing wells and proved undeveloped reserves with shorter economic lives. We estimate that volumes associated with locations of proved undeveloped reserves that would no longer be economic and would be removed from proved reserves would be less than 0.5% of our December 31, 2019 proved oil and gas reserves based on these estimated prices. Further impairments in subsequent quarters may occur if the trailing 12-month commodity prices continue to be lower than the comparable trailing 12-month commodity prices applicable to the first three quarters of 2020. Based on the current outlook for future commodity prices, we do not believe that those prices, if realized, would have a significant adverse impact on our proved oil and gas reserves volumes.

The table below presents various pricing scenarios to demonstrate the sensitivity of our September 30, 2020 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, 2020 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, 2020 that may require revisions to estimates of proved reserves.


	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, 2020 Actual	$41.71	$1.08	$—

Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$46.04	$1.28	$715	$715
Crude Oil and Natural Gas -10%	$37.37	$0.88	($721)	($721)

Crude Oil Price Sensitivity
Crude Oil +10%	$46.04	$1.08	$674	$674
Crude Oil -10%	$37.37	$1.08	($672)	($672)

Natural Gas Price Sensitivity
Natural Gas +10%	$41.71	$1.28	$49	$49
Natural Gas -10%	$41.71	$0.88	($49)	($49)

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

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 its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more 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 its 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. 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 forecast production for the next 12 to 24 months, subject to the covenants under our senior secured revolving credit facility. Given the current commodity price environment, we have increased our hedge coverage for 2020 and 2021, however, our hedge policies and objectives may change significantly with movements in commodities prices or futures prices.

As of September 30, 2020, for the remainder of 2020, the Company had 3,998,320 Bbls of fixed price oil hedges across NYMEX WTI, ICE Brent and Argus WTI-Houston benchmarks. The Company also had 1,380,000 Bbls of WTI Midland-Cushing oil basis hedges and 1,435,202 Bbls of WTI Houston-Cushing oil basis hedges. Additionally, for the remainder of 2020, the Company had 4,683,000 MMBtus of fixed price NYMEX natural gas hedges and 4,421,000 MMBtus of Waha natural gas basis hedges. See “Note 7 - Derivative Instruments and Hedging Activities” for a description of the Company’s outstanding derivative contracts as of September 30, 2020.

The Company may utilize fixed price swaps, which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company 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.

The Company 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 the Company, and if the price rises above the ceiling, the counterparty receives the difference from the Company. Additionally, the Company 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), the Company’s net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis.

The Company may purchase puts, which reduce the Company’s 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 the Company.

The Company enters into these various agreements from time to time to reduce the effects of volatile oil and natural gas prices and does not enter into derivative transactions for speculative purposes. Presently, none of the Company’s derivative positions are designated as hedges for accounting purposes.

Interest rate risk

The Company is subject to market risk exposure related to changes in interest rates on our indebtedness under our senior secured revolving credit facility. As of September 30, 2020, the Company had $1.03 billion outstanding under the senior secured revolving credit facility with a weighted average interest rate of 2.93%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $10.3 million, based on the balance outstanding at September 30, 2020. See “Note 6 - Borrowings” for more information on the Company’s interest rates on our senior secured revolving credit facility.

Counterparty and customer credit risk

The Company’s 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.

The Company markets its oil, natural gas and NGL production to energy marketing companies. We 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, 2020 our total receivables from the sale of our oil and natural gas production were approximately $81.4 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. At September 30, 2020 our joint interest receivables were approximately $15.7 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 on our commodity derivative instruments currently in place are lenders under our senior secured revolving credit facility. We are likely to enter into additional commodity derivative instruments with these or other lenders under our senior secured revolving 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, 2020, we had a net commodity derivative liability position of $32.6 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 Chief Executive Officer and Chief Financial Officer performed an evaluation 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, 2020.

Changes in internal control over financial reporting. There were no changes in 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 2020 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 a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. While the outcome of these events cannot be predicted with certainty, we believe that the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations.

Item 1A. Risk Factors

Except as set forth in “Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020, there have been no material changes to the risk factors set forth under the heading “Item 1A. Risk Factors” included in our 2019 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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

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

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

Exhibit Number

Description

Form

Exhibit

Filing Date

3.1

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

10-Q

3.1

11/03/2016

3.2

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

8-K

3.1

11/20/2019

3.3

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

8-K

3.1

8/07/2020

3.4

Amended and Restated Bylaws of the Company

10-K

3.2

2/27/2019

4.1

Indenture among the Company, the guarantors named therein and U.S. Bank National Association, as trustee and collateral agent, dated September 30, 2020

8-K

4.1

10/01/2020

4.2

Registration Rights Agreement between the Company and Chambers Investments, LLC, dated September 30, 2020

8-K

4.2

10/01/2020

4.3

Warrant Agreement between the Company and American Stock Transfer and Trust Company, LLC, as warrant agent, dated September 30, 2020

8-K

4.3

10/01/2020

10.1

Purchase Agreement among the Company, Chambers Investments, LLC and the guarantors named therein, dated September 30, 2020

8-K

10.1

10/01/2020

10.2

Second Amendment to Credit Agreement among the Company, the lenders named therein and JPMorgan Chase Bank, N.A., dated September 30, 2020

8-K

10.2

10/01/2020

10.3

Third Amendment to Credit Agreement among the Company, the lenders named therein and JPMorgan Chase Bank, N.A., dated September 30, 2020

8-K

10.3

10/01/2020

10.4

(a)(c)

Form of Callon Petroleum Company Officer Cash Retention Award Agreement, adopted on September 30, 2020 under the 2020 Omnibus Incentive Plan

10.5

(a)(c)

Form of Callon Petroleum Company Officer Cash Incentive Award Agreement, adopted on September 30, 2020 under the 2020 Omnibus Incentive Plan

31.1

(a)

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

31.2

(a)

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

32.1

(b)

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

101.INS

(a)

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

101.SCH

(a)

Inline XBRL Taxonomy Extension Schema Document

101.CAL

(a)

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

(a)

Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

(a)

Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE

(a)

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104

(a)

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

(a)Filed herewith.

(b)Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference.

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

SIGNATURES

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

Callon Petroleum Company


Signature	Title	Date

/s/ Joseph C. Gatto, Jr.	President and	November 3, 2020
Joseph C. Gatto, Jr.	Chief Executive Officer


/s/ James P. Ulm, II	Senior Vice President and	November 3, 2020
James P. Ulm, II	Chief Financial Officer