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 June 30, 2020

or

☐ 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 397,476,674 shares of common stock outstanding as of July 31, 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	31
Item 3.  Quantitative and Qualitative Disclosures about Market Risk	44
Item 4.  Controls and Procedures	46
Part II. Other Information
Item 1.  Legal Proceedings	47
Item 1A.  Risk Factors	47
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 3.  Defaults Upon Senior Securities	47
Item 4.  Mine Safety Disclosures	47
Item 5.  Other Information	47
Item 6.  Exhibits	48

2

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.

3

•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. 

4

Part I.  Financial Information

Item 1.  Financial Statements

Callon Petroleum Company

Consolidated Balance Sheets

(In thousands, except par and share amounts)

(Unaudited)

	June 30, 2020	December 31, 2019
ASSETS
Current assets:
Cash and cash equivalents	$7,500	$13,341
Accounts receivable, net	95,839	209,463
Fair value of derivatives	31,563	26,056
Other current assets	28,828	19,814
Total current assets	163,730	268,674
Oil and natural gas properties, full cost accounting method:
Evaluated properties	3,777,956	4,682,994
Unevaluated properties	1,762,860	1,986,124
Total oil and natural gas properties, net	5,540,816	6,669,118
Operating lease right-of-use assets	35,926	63,908
Other property and equipment, net	32,444	35,253
Deferred tax asset	—	115,720
Deferred financing costs	25,993	22,233
Other assets, net	11,224	19,932
Total assets	$5,810,133	$7,194,838
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$405,596	$511,622
Operating lease liabilities	24,355	42,858
Fair value of derivatives	32,683	71,197
Other current liabilities	15,053	26,570
Total current liabilities	477,687	652,247
Long-term debt	3,350,730	3,186,109
Operating lease liabilities	30,729	37,088
Asset retirement obligations	48,765	48,860
Fair value of derivatives	8,678	32,695
Other long-term liabilities	12,160	14,531
Total liabilities	3,928,749	3,971,530
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value, 525,000,000 shares authorized; 397,396,922 and 396,600,022 shares outstanding, respectively	3,974	3,966
Capital in excess of par value	3,204,310	3,198,076
Retained earnings (Accumulated deficit)	(1,326,900)	21,266
Total stockholders’ equity	1,881,384	3,223,308
Total liabilities and stockholders’ equity	$5,810,133	$7,194,838

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

5

Callon Petroleum Company

Consolidated Statements of Operations

(In thousands, except per share amounts)

(Unaudited)

	Three Months Ended June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
Operating revenues:
Oil	$130,513	$160,728	$396,280	$301,826
Natural gas	12,242	6,324	18,271	18,273
Natural gas liquids	14,479	—	32,602	—
Total operating revenues	157,234	167,052	447,153	320,099
Operating Expenses:
Lease operating	50,838	22,776	103,221	46,843
Production and ad valorem taxes	10,361	11,131	30,041	21,944
Gathering, transportation and processing	20,037	—	34,415	—
Depreciation, depletion and amortization	138,930	63,137	270,393	123,145
General and administrative	10,024	10,564	18,349	25,341
Impairment of evaluated oil and gas properties	1,276,518	—	1,276,518	—
Merger and integration expenses	8,067	—	23,897	—
Other operating	4,135	935	4,135	1,092
Total operating expenses	1,518,910	108,543	1,760,969	218,365
Income (Loss) From Operations	(1,361,676)	58,509	(1,313,816)	101,734
Other (Income) Expenses:
Interest expense, net of capitalized amounts	22,682	741	43,160	1,479
(Gain) loss on derivative contracts	126,965	(14,036)	(125,004)	53,224
Other (income) expense	2,157	(67)	895	(148)
Total other (income) expense	151,804	(13,362)	(80,949)	54,555
Income (Loss) Before Income Taxes	(1,513,480)	71,871	(1,232,867)	47,179
Income tax expense	(51,251)	(16,691)	(115,299)	(11,542)
Net Income (Loss)	(1,564,731)	55,180	(1,348,166)	35,637
Preferred stock dividends	—	(1,823)	—	(3,647)
Income (Loss) Available to Common Stockholders	($1,564,731)	$53,357	($1,348,166)	$31,990
Income (Loss) Available to Common Stockholders Per Common Share:
Basic	($3.94)	$0.23	($3.40)	$0.14
Diluted	($3.94)	$0.23	($3.40)	$0.14
Weighted Average Common Shares Outstanding:
Basic	397,084	228,051	396,884	227,917
Diluted	397,084	228,411	396,884	228,599

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

6

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	$	of Par	Deficit)	Equity
Balance at 12/31/2019	—	$—	396,600	$3,966	$3,198,076	$21,266	$3,223,308
Net income	—	—	—	—	—	216,565	216,565
Restricted stock	—	—	138	1	3,141	—	3,142
Other	—	—	—	—	(112)	—	(112)
Balance at 3/31/2020	—	$—	396,738	$3,967	$3,201,105	$237,831	$3,442,903
Net loss	—	—	—	—	—	(1,564,731)	(1,564,731)
Restricted stock	—	—	659	7	3,205	—	3,212
Balance at 6/30/2020	—	$—	397,397	$3,974	$3,204,310	($1,326,900)	$1,881,384

	Preferred		Common		Capital in		Total
	Stock		Stock		Excess	Accumulated	Stockholders’
	Shares	$	Shares	$	of Par	Deficit	Equity
Balance at 12/31/2018	1,459	$15	227,583	$2,276	$2,477,278	($34,361)	$2,445,208
Net loss	—	—	—	—	—	(19,543)	(19,543)
Shares issued pursuant to employee benefit plans	—	—	24	—	154	—	154
Restricted stock	—	—	277	3	4,447	—	4,450
Preferred stock dividend	—	—	—	—	—	(1,824)	(1,824)
Balance at 3/31/2019	1,459	$15	227,884	$2,279	$2,481,879	($55,728)	$2,428,445
Net income	—	—	—	—	—	55,180	55,180
Restricted stock	—	—	380	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	228,264	$2,283	$2,483,945	($2,371)	$2,483,872

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

7

Callon Petroleum Company

Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

	Six Months Ended June 30,
Cash flows from operating activities:	2020	2019
Net income (loss)	($1,348,166)	$35,637
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	270,393	125,503
Impairment of evaluated oil and gas properties	1,276,518	—
Amortization of non-cash debt related items	1,145	1,479
Deferred income tax expense	115,299	11,542
(Gain) loss on derivative contracts	(125,004)	53,224
Cash (paid) received for commodity derivative settlements	101,301	(1,447)
Loss on sale of other property and equipment	—	49
Non-cash expense related to equity share-based awards	4,817	6,299
Change in the fair value of liability share-based awards	(5,028)	1,031
Payments to settle asset retirement obligations	—	(771)
Payments for cash-settled restricted stock unit awards	(755)	(1,425)
Other, net	4,411	—
Changes in current assets and liabilities:
Accounts receivable	113,040	38,681
Other current assets	(4,348)	(6,101)
Current liabilities	(114,127)	(36,254)
Other	—	(2,401)
Net cash provided by operating activities	289,496	225,046
Cash flows from investing activities:
Capital expenditures	(430,569)	(359,430)
Acquisitions	—	(39,370)
Proceeds from sale of assets	10,079	274,296
Cash paid for settlements of contingent consideration arrangements, net	(40,000)	—
Other, net	6,834	—
Net cash used in investing activities	(453,656)	(124,504)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	4,775,500	360,000
Payments on senior secured revolving credit facility	(4,610,500)	(455,000)
Payment of preferred stock dividends	—	(3,647)
Payment of deferred financing costs	(6,011)	(31)
Tax withholdings related to restricted stock units	(388)	(1,858)
Other, net	(282)	(5)
Net cash provided by (used in) financing activities	158,319	(100,541)
Net change in cash and cash equivalents	(5,841)	1
Balance, beginning of period	13,341	16,051
Balance, end of period	$7,500	$16,052

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

8

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.	Leases
4.	Property and Equipment, Net	12.	Accounts Receivable, Net
5.	Earnings Per Share	13.	Accounts Payable and Accrued Liabilities
6.	Borrowings	14.	Supplemental Cash Flow
7.	Derivative Instruments and Hedging Activities	15.	Subsequent Events
8.	Fair Value Measurements

Note 1 - Description of Business and Basis of Presentation

Description of business

Callon 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.

9

Subsequent Events

The Company evaluates subsequent events through the date the financial statements are issued. See “Note 15 - Subsequent Events” for further discussion.

Note 2 - Revenue Recognition

Revenue from contracts with customers

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 six months ended June 30, 2019, $2.8 million and $5.2 million of gathering, transportation, and processing fees were recognized as a reduction to natural gas revenues in the consolidated statement of operations.

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 June 30, 2020 and December 31, 2019 of $74.6 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.

10

Note 3 - Acquisitions and Divestitures

2020 Acquisitions and Divestitures

The Company did not have any material acquisitions or divestitures for the six months ended June 30, 2020.

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	88,627
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	$2,364,277
Assets:
Accounts receivable, net	$48,479
Fair value of derivatives - current	17,451
Other current assets	11,137
Evaluated oil and natural gas properties	2,133,280
Unevaluated properties	683,366
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	$3,129,650

11

Approximately $86.9 million and $248.3 million of revenues and $47.7 million and $99.9 million of direct operating expenses attributed to the Carrizo Acquisition were included in the Company’s consolidated statements of operations for the three and six months ended June 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

During the three and six months ended June 30, 2020, in conjunction with the Carrizo Acquisition, the Company incurred costs totaling $8.1 million and $23.9 million, respectively, comprised of severance costs of $2.4 million and $5.4 million, respectively, and other merger and integration expenses of $5.7 million and $18.5 million, respectively. Through June 30, 2020, the Company has incurred cumulative costs associated with the Carrizo Acquisition of $98.3 million comprised of severance costs of $34.2 million and other merger and integration expenses of $64.1 million. As of June 30, 2020, $23.0 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.

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Note 4 - Property and Equipment, Net

As of June 30, 2020 and December 31, 2019, total property and equipment, net consisted of the following:

	June 30, 2020	December 31, 2019
Oil and natural gas properties, full cost accounting method	(In thousands)
Evaluated properties	$7,840,616	$7,203,482
Accumulated depreciation, depletion, amortization and impairments	(4,062,660)	(2,520,488)
Net evaluated oil and natural gas properties	3,777,956	4,682,994
Unevaluated properties
Unevaluated leasehold and seismic costs	1,596,662	1,843,725
Capitalized interest	166,198	142,399
Total unevaluated properties	1,762,860	1,986,124
Total oil and natural gas properties, net	$5,540,816	$6,669,118
Other property and equipment	$67,883	$67,202
Accumulated depreciation	(35,439)	(31,949)
Other property and equipment, net	$32,444	$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 $8.9 million and $8.4 million for the three months ended June 30, 2020 and 2019, respectively, and $16.4 million and $19.1 million for the six months ended June 30, 2020 and 2019.

The Company capitalized interest costs associated with its unproved properties totaling $20.9 million and $18.7 million for the three months ended June 30, 2020 and 2019, respectively, and $44.9 million and $38.6 million for the six months ended June 30, 2020 and 2019.

As a result of the recent 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 $43.9 million and $224.4 million from unevaluated leasehold to evaluated properties during the three and six months ended June 30, 2020, respectively, 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 June 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 months ended June 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 June 30,
	2020		2019
Impairment of evaluated oil and gas properties (in thousands)	$1,276,518		$—
Beginning of period 12-Month Average Realized Price ($/Bbl)	$54.63		$54.58
End of period 12-Month Average Realized Price ($/Bbl)	$45.87		$53.00
Percent decrease in 12-Month Average Realized Price	(16	%)	(3	%)

The Company expects to record an additional impairment in the carrying value of evaluated oil and gas properties in the third quarter of 2020 based on an estimated 12-Month Average Realized price of crude oil of approximately $43.45 as of September 30, 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 11 months and an estimate for the twelfth month 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.

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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 six months ended June 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 9.1 million and 9.2 million potentially dilutive common shares outstanding for the three and six months ended June 30, 2020, respectively. The following table sets forth the computation of basic and diluted earnings per share:

	Three Months Ended June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands, except per share amounts)
Net income (loss)	($1,564,731)	$55,180	($1,348,166)	$35,637
Preferred stock dividends (1)	—	(1,823)	—	(3,647)
Income (loss) available to common stockholders	($1,564,731)	$53,357	($1,348,166)	$31,990
Basic weighted average common shares outstanding	397,084	228,051	396,884	227,917
Dilutive impact of restricted stock	—	360	—	682
Diluted weighted average common shares outstanding	397,084	228,411	396,884	228,599
Income (Loss) Available to Common Stockholders Per Common Share
Basic	($3.94)	$0.23	($3.40)	$0.14
Diluted	($3.94)	$0.23	($3.40)	$0.14
Restricted stock (2)	9,066	641	9,169	498

(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 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:

	June 30, 2020	December 31, 2019
	(In thousands)
Senior Secured Revolving Credit Facility due 2024	$1,450,000	$1,285,000
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	3,350,000	3,185,000
Unamortized premium on 6.125% Senior Notes	4,781	5,344
Unamortized premium on 6.25% Senior Notes	4,163	4,838
Unamortized premium on 8.25% Senior Notes	4,809	5,286
Unamortized deferred financing costs for Senior Notes	(13,023)	(14,359)
Total carrying value of borrowings (1)	$3,350,730	$3,186,109

(1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $26.0 million and $22.2 million as of June 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 June 30, 2020, had a borrowing base of $1.7 billion, with an elected commitment amount of $1.7 billion, borrowings outstanding of $1.45 billion at a weighted-average interest rate of 3.01%, and letters of credit outstanding of $19.7 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%

14

Senior Notes are outstanding at such time and (ii) July 2, 2024 if the 6.125% Senior Notes are outstanding at such time), 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) establishes a new borrowing base as a result of the spring 2020 scheduled redetermination in the amount of $1.7 billion and reduces the elected commitments to $1.7 billion; (b) permits the incurrence of, among other things, new second lien notes exchanged for unsecured notes in an aggregate principal amount of up to $400 million (the “Second Lien Notes”) so long as any such Second Lien Notes are subject to an intercreditor agreement providing that the liens securing the Second Lien 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) provides that the testing of the Current Ratio, which is the ratio of current assets to current liabilities is 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.

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.

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 recommencing September 30, 2020, of not less than 1.00 to 1.00. The Company was in compliance with these covenants at June 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.

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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 June 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)	(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.

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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.

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 June 30, 2020
	Presented without		As Presented with
	Effects of Netting	Effects of Netting	Effects of Netting
ASSETS	(In thousands)
Commodity derivative instruments	$63,380	($31,890)	$31,490
Contingent consideration arrangements	73	—	73
Fair value of derivatives - current	$63,453	($31,890)	$31,563
Commodity derivative instruments	1,404	(952)	452
Contingent consideration arrangements	1,234	—	1,234
Other assets, net	$2,638	($952)	$1,686
LIABILITIES
Commodity derivative instruments	($64,122)	$31,890	($32,232)
Contingent consideration arrangements	(451)	—	(451)
Fair value of derivatives - current	($64,573)	$31,890	($32,683)
Commodity derivative instruments	(6,518)	952	(5,566)
Contingent consideration arrangements	(3,112)	—	(3,112)
Fair value of derivatives - non current	($9,630)	$952	($8,678)

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	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 June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands)
(Gain) loss on oil derivatives	$122,369	($8,849)	($134,954)	$59,520
(Gain) loss on natural gas derivatives	4,695	(1,874)	11,524	(2,983)
Gain on NGL derivatives	(4)	—	(4)	—
Gain on contingent consideration arrangements	(95)	(3,313)	(1,570)	(3,313)
(Gain) loss on derivative contracts	$126,965	($14,036)	($125,004)	$53,224

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 June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands)
Cash flows from operating activities
Cash (paid) received on oil derivatives	$100,470	($4,461)	$98,693	($6,003)
Cash (paid) received on natural gas derivatives	(1,782)	3,304	2,608	4,556
Cash (paid) received for commodity derivative settlements	$98,688	($1,157)	$101,301	($1,447)
Cash flows from investing activities
Cash paid for settlements of contingent consideration arrangements, net	$—	$—	($40,000)	$—

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Derivative positions

Listed in the tables below are the outstanding oil, natural gas and NGL derivative contracts as of June 30, 2020:  

	For the Remainder		For the Full Year
Oil contracts (WTI)	of 2020		of 2021
Swap contracts
Total volume (Bbls)	6,291,880		—
Weighted average price per Bbl	$42.08		$—
Collar contracts
Total volume (Bbls)	2,863,040		—
Weighted average price per Bbl
Ceiling (short call)	$45.00		$—
Floor (long put)	$35.00		$—
Short put contracts
Total volume (Bbls)	1,104,000		—
Weighted average price per Bbl	$42.50		$—
Long call contracts
Total volume (Bbls)	920,000		—
Weighted average price per Bbl	$67.50		$—
Short call contracts
Total volume (Bbls)	920,000	(1)	4,825,300	(1)
Weighted average price per Bbl	$55.00		$63.62
Oil contracts (WTI Calendar Month Average Roll)
Swap contracts
Total volume (Bbls)	3,864,000		—
Weighted average price per Bbl	($2.75)		$—
Oil contracts (Brent ICE)
Swap contracts
Total volume (Bbls)	184,000		1,272,450
Weighted average price per Bbl	$46.15		$38.24
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	4,609,200		4,015,100
Weighted average price per Bbl	($0.98)		$0.40
Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls)	3,256,004		—
Weighted average price per Bbl	$0.06		$—
Oil contracts (Argus Houston MEH swaps)
Swap contracts
Total volume (Bbls)	368,000		2,969,050
Weighted average price per Bbl	$57.71		$39.48

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

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	For the Remainder	For the Full Year
Natural gas contracts (Henry Hub)	of 2020	of 2021
Swap contracts
Total volume (MMBtu)	5,530,000	12,923,000
Weighted average price per MMBtu	$2.21	$2.66
Collar contracts (three-way collars)
Total volume (MMBtu)	2,755,000	1,350,000
Weighted average price per MMBtu
Ceiling (short call)	$2.73	$2.70
Floor (long put)	$2.47	$2.42
Floor (short put)	$2.00	$2.00
Collar contracts (two-way collars)
Total volume (MMBtu)	1,525,000	7,750,000
Weighted average price per MMBtu
Ceiling (short call)	$3.25	$2.93
Floor (long put)	$2.67	$2.55
Short call contracts
Total volume (MMBtu)	6,072,000	7,300,000
Weighted average price per MMBtu	$3.50	$3.09
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	12,885,000	—
Weighted average price per MMBtu	($0.92)	$—

	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

See “Note 15 - Subsequent Events” for additional information regarding derivative contracts entered into subsequent to June 30, 2020.

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

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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.

	June 30, 2020		December 31, 2019
	Principal Amount	Fair Value	Principal Amount	Fair Value
	(In thousands)
6.25% Senior Notes	$650,000	$240,500	$650,000	$658,125
6.125% Senior Notes	600,000	216,000	600,000	611,130
8.25% Senior Notes	250,000	87,500	250,000	256,250
6.375% Senior Notes	400,000	136,000	400,000	405,424
Total	$1,900,000	$680,000	$1,900,000	$1,930,929

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:

	June 30, 2020
	Level 1	Level 2	Level 3
	(In thousands)
Assets
Commodity derivative instruments	$—	$31,942	$—
Contingent consideration arrangements	—	1,307	—
Liabilities
Commodity derivative instruments	—	(37,798)	—
Contingent consideration arrangements	—	(3,563)	—
Total net assets (liabilities)	$—	($8,112)	$—
	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)	$—

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

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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 to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Income tax expense computed at the 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	(25	%)	—	%	(31	%)	—	%
Other discrete items (1)	—	%	1	%	—	%	2	%
Effective income tax rate, after discrete items	(3	%)	23	%	(9	%)	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 June 30, 2020, driven primarily by the impairment of evaluated oil and gas properties recognized for the three months ended June 30, 2020. This limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Based on the evaluation of the evidence available during the three months ended June 30, 2020, the Company concluded that it is more likely than not that the net deferred tax assets will not be realized and recorded a valuation allowance of $377.6 million, reducing the net deferred tax assets as of June 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.

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. The 2020 Plan provides that up to 13,250,000 shares of the Company’s common stock, plus the shares remaining available for awards under the Prior Incentive Plan, may be issued. As of June 30, 2020, there were 15,937,327 common shares remaining available for grant under the 2020 Plan.

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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 six months ended June 30, 2020 and 2019:

	Three Months Ended June 30,
	2020		2019
	RSU Equity Awards (in thousands)	Weighted Average Grant Date Fair Value	RSU Equity Awards (in thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	4,851	$6.95	3,406	$11.14
Granted (1)	3,257	$1.26	171	$7.87
Vested (2)	(900)	$10.06	(458)	$12.51
Forfeited	—	$—	(64)	$11.43
Unvested, end of the period	7,208	$3.99	3,055	$10.75

	Six Months Ended June 30,
	2020		2019
	RSU Equity Awards (in thousands)	Weighted Average Grant Date Fair Value	RSU Equity Awards (in thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	2,695	$10.25	2,103	$13.24
Granted (1)	5,575	$2.12	1,881	$8.60
Vested (2)	(1,062)	$10.02	(791)	$12.23
Forfeited	—	$—	(138)	$10.82
Unvested, end of the period	7,208	$3.99	3,055	$10.75

(1)Includes 0.3 million and zero target performance-based RSU Equity Awards during the three months ended June 30, 2020 and 2019, respectively, and 1.1 million and 0.4 million during the six months ended June 30, 2020 and 2019, respectively. The awards granted during the six months ended June 30, 2020 and 2019 will vest at a range of 0% to 300% and 0% to 200%, respectively.

(2)The fair value of shares vested was $0.6 million and $3.4 million during the three months ended June 30, 2020 and 2019, respectively, and $1.3 million and $6.0 million for the six months ended June 30, 2020 and 2019, respectively.

Grant activity for the six months ended June 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 $0.5 million and zero for the three months ended June 30, 2020 and 2019, respectively, and $3.4 million and $4.3 million for the six months ended June 30, 2020 and 2019, respectively. The following table summarizes the assumptions used and the resulting grant date fair value per performance-based RSU Equity Award granted during the six months ended June 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	—	%	—	%	—	%
Grant date fair value per performance-based RSU Equity Award	$1.80		$3.39		$10.78

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As of June 30, 2020, unrecognized compensation costs related to unvested RSU Equity Awards were $19.7 million and will be recognized over a weighted average period of 2.1 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 six months ended June 30, 2020 and 2019:

	Three Months Ended June 30,
	2020		2019
	Cash-Settled RSU Awards (in thousands)	Weighted Average Grant Date Fair Value	Cash-Settled RSU Awards (in thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	1,707	$7.85	1,044	$11.69
Granted	386	$2.03	25	$8.1
Vested	(2)	$16.66	(17)	$11.06
Did not vest at end of performance period	(11)	$15.27	—	$—
Forfeited	—	$—	(21)	$16.38
Unvested, end of the period	2,080	$6.72	1,031	$11.52

	Six Months Ended June 30,
	2020		2019
	Cash-Settled RSU Awards (in thousands)	Weighted Average Grant Date Fair Value	Cash-Settled RSU Awards (in thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	855	$12.42	678	$12.36
Granted	1,249	$2.98	424	$10.62
Vested	(12)	$12.85	(17)	$11.06
Did not vest at end of performance period	(12)	$16.66	—	$—
Forfeited	—	$—	(54)	$15.21
Unvested, end of the period	2,080	$6.72	1,031	$11.52

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 and the resulting 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:

	June 30, 2020	December 31, 2019
	(In thousands)
Other current liabilities	$231	$966
Other long-term liabilities	674	2,089
Total Cash-Settled RSU Awards	$905	$3,055

As of June 30, 2020, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $2.2 million and will be recognized over a weighted average period of 2.3 years.

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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 June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands)
RSU Equity Awards	$3,212	$2,907	$7,160	$8,383
Cash-Settled RSU Awards	596	203	(1,400)	1,354
Cash SARs	1,115	—	(3,641)	—
	4,923	3,110	$2,119	$9,737
Less: amounts capitalized to oil and gas properties	(2,162)	(1,131)	(2,330)	(2,304)
Total share-based compensation expense (benefit), net	$2,761	$1,979	($211)	$7,433

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 - 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 June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands)		(In thousands)
Components of Lease Costs
Finance lease costs	$552	$—	$1,128	$—
Amortization of right-of-use assets (1)	510	—	1,020	—
Interest on lease liabilities (2)	42	—	108	—
Operating lease costs (3)	16,387	9,565	33,664	19,156
Impairment of Operating lease ROU assets (4)	1,982	—	3,575	—
Short-term lease costs (5)	38	1,849	1,726	3,347
Variable lease costs (6)	70	—	74	—
Total lease costs	$19,029	$11,414	$40,167	$22,503

(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.

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(3) For the three months ended June 30, 2020 and 2019, approximately $15.2 million and $7.0 million were costs associated with drilling rigs. For the six months ended June 30, 2020 and 2019, approximately $23.7 million and $13.9 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 six months ended June 30, 2020 of $2.0 million 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:

	June 30, 2020	December 31, 2019
	(In thousands)
Leases
Operating leases:
Operating lease ROU assets	$35,926	$63,908
Current operating lease liabilities	$24,355	$42,858
Long-term operating lease liabilities	30,729	37,088
Total operating lease liabilities	$55,084	$79,946
Financing leases:
Other property and equipment	$2,313	$2,197
Accumulated depreciation	(1,257)	(82)
Other property and equipment, net	$1,056	$2,115
Current financing lease liabilities	$463	$1,334
Long-term financing lease liabilities	572	807
Total financing lease liabilities	$1,035	$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 June 30, 2020
Weighted Average Remaining Lease Term (In years)
Operating leases	5.4
Financing leases	2.8
Weighted Average Discount Rate
Operating leases	5.4	%
Financing leases	7.1	%

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

	Operating Leases	Financing Leases
	(In thousands)
Remainder of 2020	$16,362	$363
2021	14,116	275
2022	5,453	234
2023	5,013	233
2024	4,937	38
Thereafter	18,097	—
Total lease payments	63,978	1,143
Less imputed interest	(8,894)	(108)
Total	$55,084	$1,035

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Note 12 - Accounts Receivable, Net

	June 30, 2020	December 31, 2019
	(In thousands)
Oil and natural gas receivables	$74,555	$165,275
Joint interest receivables	9,664	39,114
Other receivables	13,388	6,610
Total	97,607	210,999
Allowance for doubtful accounts	(1,768)	(1,536)
Total accounts receivable, net	$95,839	$209,463

Note 13 - Accounts Payable and Accrued Liabilities

	June 30, 2020	December 31, 2019
	(In thousands)
Accounts payable	$202,467	$238,758
Revenues payable	109,054	145,816
Accrued capital expenditures	29,926	61,950
Accrued interest	43,441	36,295
Accrued severance (1)	20,708	28,803
Total accounts payable and accrued liabilities	$405,596	$511,622

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

Note 14 - Supplemental Cash Flow

	Six Months Ended June 30,
	2020	2019
Supplemental cash flow information:
Interest paid, net of capitalized amounts	$31,649	$—
Income taxes paid	—	—
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$26,110	$1,293
Investing cash flows from operating leases	11,278	17,865
Non-cash investing and financing activities:
Change in accrued capital expenditures	($6,186)	($16,286)
Change in asset retirement costs	207	—
ROU assets obtained in exchange for lease liabilities:
Operating leases	$2,666	$2,462

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Note 15 - Subsequent Events

Hedging

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

	For the Remainder	For the Full Year
Oil contracts (WTI)	of 2020	of 2021
Swap contracts
Total volume (Bbls)	—	1,377,000
Weighted average price per Bbl	$—	$42.00
Collar contracts
Total volume (Bbls)	—	3,741,250
Weighted average price per Bbl
Ceiling (short call)	$—	$45.02
Floor (long put)	$—	$40.00
Short call swaption contracts
Total volume (Bbls)	—	730,000	(1)
Weighted average price per Bbl	$—	$47.00
Oil contracts (Midland basis differential)
Long swap contracts
Total volume (Bbls)	1,514,500	—
Weighted average price per Bbl	$0.60	$—
Natural gas contracts (Henry Hub)
Swap contracts
Total volume (MMBtu)	3,036,000	—
Weighted average price per MMBtu	$1.80	$—
Long call contracts
Total volume (MMBtu)	3,036,000	—
Weighted average price per MMBtu	$3.50	$—
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	—	6,387,500
Weighted average price per MMBtu	$—	($0.58)

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

Reverse Stock Split

On August 4, 2020, the Company announced that its Board of Directors approved a reverse stock split of Company’s outstanding shares of common stock at a ratio of 1-for-10 and a proportionate reduction of 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 will become effective as of the close of business on August 7, 2020 and the Company’s common stock will begin trading on a split-adjusted basis on the NYSE at market open on August 10, 2020. The par value of the common stock will not be adjusted in connection with the reverse stock split.

The reverse stock split is intended to, among other things, increase the per share trading price of the Company’s common shares to maintain compliance with the $1.00 minimum closing price requirement for continued listing on the NYSE and improve the opportunity for institutional ownership. Upon completion of the reverse stock split, each 10 pre-split shares of common stock outstanding will be automatically combined into one issued and outstanding share of common stock. The fractional shares that resulted from the reverse stock split were canceled, and shareholders who would otherwise hold fractional shares as a result of the reverse stock split will be entitled to receive cash (without interest and subject to applicable withholding taxes) in lieu of such fractional shares. The number of outstanding shares of common stock will be reduced from approximately 397,476,674 as of July 31, 2020 to approximately 39,747,667 shares (without giving effect to the liquidation of fractional shares). The total number of shares of common stock that the Company is authorized to issue will be reduced from 525,000,000 to 52,500,000 shares.

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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.

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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.

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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 imposing social distancing requirements on work sites, in accordance with the guidelines released by the Center for Disease Control. In addition, most of our non-operational employees are now working remotely. 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 borrowings under our 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. Previously deferred initial flowback was initiated from wells in the Wildhorse area in June, and all wells are now on production. 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.

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Overview

Second Quarter 2020 Highlights

•Total production for the three months ended June 30, 2020 was 108,664 Boe/d, an increase of 168% from the three months ended June 30, 2019, primarily due to production from the Carrizo Acquisition and new wells placed on production during 2020, partially offset by normal production decline and the sale of our Ranger assets in 2019.

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

	Three Months Ended June 30, 2020				As of June 30, 2020
	Drilled		Completed		Drilled But Uncompleted		Producing
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Permian Basin	19	17.1	16	15.0	36	33.4	840	729.7
Eagle Ford Shale	10	9.9	10	9.9	35	34.9	631	568.3
Total	29	27.0	26	24.9	71	68.3	1,471	1,298.0

▪Operational capital expenditures, inclusive of leasehold and seismic, for the second quarter of 2020 were $85.1 million, of which approximately 85% 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 do not currently have any active rigs or completion crews, but we do intend to resume development activity during the third quarter of 2020. Near-term operational activity will be focused on completing a drilled, but uncompleted inventory of approximately 70 wells in both the Permian Basin and Eagle Ford Shale with one dedicated completion crew. We also intend to return two to three drilling rigs to service later in the third quarter of 2020 for the balance of the year. As a result, we currently forecast total operational capital expenditures of approximately $140.0 to $165.0 million over the remaining two quarters of 2020 and expect operational capital expenditures to be approximately $500.0 to $525.0 million for the full year 2020. See “—Liquidity and Capital Resources—2020 Capital Plan and Outlook” for additional details.

•We recorded a loss available to common stockholders for the three months ended June 30, 2020 of $1.6 billion, or $3.94 per diluted share, as compared to net income available to common stockholders for the three months ended June 30, 2019 of $53.4 million, or $0.23 per diluted share. The change from net income available to common stockholders to net 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 $1.3 billion during the second quarter of 2020 as well as a loss on derivative contracts of approximately $127.0 million during the second quarter of 2020 compared to a gain on derivative contracts of approximately $14.0 million during the second quarter of 2019 and an approximate 65% decrease in total average realized sales prices between the two periods, partially offset by an approximate 168% increase in total production for the three months ended June 30, 2020 compared to the three months ended June 30, 2019. See “—Results of Operations” below for further details.

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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 June 30,							Six Months Ended June 30,
	2020		2019		Change	% Change		2020		2019		Change	% Change
Total production (1)
Oil (MBbls)	6,396		2,848		3,548	125	%	12,243		5,706		6,537	115	%
Natural gas (MMcf)	11,009		5,031		5,978	119	%	20,802		9,650		11,152	116	%
NGLs (MBbls)	1,657		—		1,657	100	%	3,364		—		3,364	100	%
Total barrels of oil equivalent (MBoe)	9,888		3,687		6,201	168	%	19,074		7,314		11,760	161	%
Total daily production (Boe/d)	108,664		40,516		68,148	168	%	104,802		40,409		64,393	159	%
Oil as % of total daily production	65	%	77	%				64	%	78	%
Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)	$20.41		$56.44		($36.03)	(64	%)	$32.37		$52.90		($20.53)	(39	%)
Natural gas (per Mcf)	1.11		1.26		(0.15)	(12	%)	0.88		1.89		(1.01)	(53	%)
NGLs (per Bbl)	8.74		—		8.74	100	%	9.69		—		9.69	100	%
Total (per Boe)	$15.90		$45.31		($29.41)	(65	%)	$23.44		$43.77		($20.33)	(46	%)
Revenues (in thousands)
Oil	$130,513		$160,728		($30,215)	(19	%)	$396,280		$301,826		$94,454	31	%
Natural gas	12,242		6,324		5,918	94	%	18,271		18,273		(2)	—	%
NGLs	14,479		—		14,479	100	%	32,602		—		32,602	100	%
Total revenues	$157,234		$167,052		($9,818)	(6	%)	$447,153		$320,099		$127,054	40	%
Benchmark prices (2)
WTI (per Bbl)	$27.85		$59.88		($32.03)	(53	%)	$36.97		$57.39		($20.42)	(36	%)
Henry Hub (per Mcf)	1.76		2.57		(0.81)	(32	%)	1.81		2.74		(0.93)	(34	%)

(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 June 30				Six Months Ended June 30
	Oil	Natural Gas	NGLs	Total	Oil	Natural Gas	NGLs	Total
	(In thousands)
Revenues for the periods ended in 2019	$160,728	$6,324	$—	$167,052	$301,826	$18,273	$—	$320,099
Volume increase (decrease)	199,104	7,516	14,479	221,099	344,725	21,117	32,602	398,444
Price increase (decrease)	(229,319)	(1,598)	—	(230,917)	(250,271)	(21,119)	—	(271,390)
Net increase (decrease)	(30,215)	5,918	14,479	(9,818)	94,454	(2)	32,602	127,054
Revenues for the periods ended in 2020 (1)	$130,513	$12,242	$14,479	$157,234	$396,280	$18,271	$32,602	$447,153

(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.

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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 six months ended June 30, 2020 as compared to June 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 June 30, 2020, oil revenues of $130.5 million decreased $30.2 million, or 19%, compared to revenues of $160.7 million for the same period of 2019. The decrease was primarily attributable to a 64% decline in the average realized sales price which fell to $20.41 per Bbl from $56.44 per Bbl. The decrease in pricing was partially offset by the 125% increase in production from the Carrizo Acquisition and our development efforts.

For the six months ended June 30, 2020, oil revenues of $396.3 million increased $94.5 million, or 31%, compared to revenues of $301.8 million for the same period of 2019. The increase was primarily attributable to the 115% increase in production from the Carrizo Acquisition and our development efforts. The increase was partially offset by a 39% decline in the average realized sales price which fell to $32.37 per Bbl from $52.90 per Bbl.

Natural gas revenue

For the three months ended June 30, 2020, natural gas revenues of $12.2 million increased $5.9 million, or 94%, compared to $6.3 million for the same period of 2019. The increase was primarily attributable to the 119% increase in production from the Carrizo Acquisition and our development efforts. The increase was partially offset by a 12% decline in the average realized sale price which fell to $1.11 per Mcf from $1.26 per Mcf.

For the six months ended June 30, 2020, natural gas revenues of $18.3 million remained relatively consistent despite a 53% decline in the average realize sales price, which fell to $0.88 per Mcf from $1.89 per Mcf. The price decrease was offset by a 116% increase in production from the Carrizo Acquisition and our development efforts.

NGL revenue

For the three and six months ended June 30, 2020, NGL revenues were $14.5 million and $32.6 million, or $8.74 and $9.69 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.

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Operating Expenses

	Three Months Ended June 30,
		Per		Per	Total Change			Boe Change
	2020	Boe	2019	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Lease operating expenses	$50,838	$5.14	$22,776	$6.18	$28,062	123	%	($1.04)	(17	%)
Production and ad valorem taxes	10,361	1.05	11,131	3.02	(770)	(7	%)	(1.97)	(65	%)
Gathering, transportation and processing	20,037	2.03	—	—	20,037	100	%	2.03	100	%
Depreciation, depletion and amortization	138,930	14.05	63,137	17.12	75,793	120	%	(3.07)	(18	%)
General and administrative	10,024	1.01	10,564	2.87	(540)	(5	%)	(1.86)	(65	%)
Impairment of evaluated oil and gas properties	1,276,518	129.10	—	—	1,276,518	100	%	129.10	100	%
Merger and integration expenses	8,067	0.82	—	—	8,067	100	%	0.82	100	%

	Six Months Ended June 30,
		Per		Per	Total Change			Boe Change
	2020	Boe	2019	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Lease operating expenses	$103,221	$5.41	$46,843	$6.40	$56,378	120	%	($0.99)	(15	%)
Production and ad valorem taxes	30,041	1.57	21,944	3.00	8,097	37	%	(1.43)	(48	%)
Gathering, transportation and processing	34,415	1.80	—	—	34,415	100	%	1.80	100	%
Depreciation, depletion and amortization	270,393	14.18	123,145	16.84	147,248	120	%	(2.66)	(16	%)
General and administrative	18,349	0.96	25,341	3.46	(6,992)	(28	%)	(2.50)	(72	%)
Impairment of evaluated oil and gas properties	1,276,518	66.92	—	—	1,276,518	100	%	66.92	100	%
Merger and integration expenses	23,897	1.25	—	—	23,897	100	%	1.25	100	%

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

Lease operating expenses for the three months ended June 30, 2020 increased to $50.8 million compared to $22.8 million for the same period of 2019. The increase in lease operating expense was primarily related to a 168% 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 $5.14 for the second quarter of 2020, which represents a decrease of $1.04 per Boe from the second quarter of 2019. The lower per unit metric reflects the distribution of fixed costs spread over higher production volumes.

Lease operating expenses for the six months ended June 30, 2020 increased to $103.2 million compared to $46.8 million for the same period of 2019. The increase in LOE was primarily related to a 161% 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 $5.41 for the six months ended June 30, 2020, which represents a decrease of $0.99 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 June 30, 2020 decreased 7% to $10.4 million compared to $11.1 million for the same period of 2019, which is primarily related to a 6% decrease in total revenues. Production and ad valorem taxes for the six months ended June 30, 2020 increased 37% to $30.0 million compared to $21.9 million for the same period of 2019, which is primarily related to a 40% increase in total revenues. Production and ad valorem taxes as a percentage of total revenues were consistent across the comparable periods at approximately 6.7%.

Gathering, transportation and processing expenses. Gathering, transportation and processing costs for the three and six months ended June 30, 2020 were $20.0 million and $34.4 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

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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 June 30,				Six Months Ended June 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	$136,218	$13.78	$62,915	$17.06	$265,654	$13.93	$122,673	$16.77
Depreciation of other property and equipment	1,129	0.11	6	—	2,072	0.11	15	0.01
Amortization of other assets	733	0.07	—	—	995	0.05	—	—
Accretion of asset retirement obligations	850	0.09	216	0.06	1,672	0.09	457	0.06
DD&A	$138,930	$14.05	$63,137	$17.12	$270,393	$14.18	$123,145	$16.84

For the three and six months ended June 30, 2020, DD&A expense was $138.9 million and $270.4 million compared to $63.1 million and $123.1 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 six months ended June 30, 2020, resulted from production increases of 168% and 161%, respectively, which were partially offset by lower DD&A rates between the periods. Those factors accounted for an $85.3 million increase and $12.0 million offsetting decrease, respectively, during the second quarter of 2020. Similarly, the increased production and decreased per unit rate accounted for a $163.7 million increase and $20.7 million offsetting decrease, respectively, for the six months ended June 30, 2020 as compared to 2019.

The decrease in DD&A on a per unit basis rates 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.

General and administrative, net of amounts capitalized (“G&A”). G&A for the three months ended June 30, 2020 was relatively consistent compared to the same period in 2019. We recorded a marginal decrease to $10.0 million compared to $10.6 million due to cost saving initiatives, which were partially offset by increased headcount of the combined companies. Additionally, G&A for the six months ended June 30, 2020 decreased $7.0 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 an impairment of evaluated oil and gas properties of $1.3 billion for the three and six months ended June 30, 2020 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 June 30, 2020. There was no impairment of evaluated oil and gas properties for the three or six months ended June 30, 2019.

Merger and integration expense. For the three and six months ended June 30, 2020, the Company incurred $8.1 million and $23.9 million of expenses associated with the Carrizo Acquisition. See “Note 3 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for additional information regarding the merger with Carrizo.

Other Income and Expenses

	Three Months Ended June 30,					Six Months Ended June 30,
	2020	2019	$ Change	% Change		2020	2019	$ Change	% Change
	(In thousands, except % amounts)
Interest expense	$43,606	$19,478	$24,128	124	%	$88,069	$40,059	$48,010	120	%
Capitalized interest	(20,924)	(18,737)	(2,187)	12	%	(44,909)	(38,580)	(6,329)	16	%
Interest expense, net of capitalized amounts	22,682	741	21,941	2,961	%	43,160	1,479	41,681	2,818	%
(Gain) loss on derivative contracts	$126,965	($14,036)	$141,001	(1,005	%)	($125,004)	$53,224	($178,228)	(335	%)

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.

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Interest expense, net of capitalized amounts, incurred during the three months ended June 30, 2020 increased $21.9 million to $22.7 million compared to $0.7 million for the same period of 2019. Additionally, interest expense, net of capitalized amounts, incurred during the six months ended June 30, 2020 increased $41.7 million to $43.2 million compared to $1.5 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 June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands)
(Gain) loss on oil derivatives	$122,369	($8,849)	($134,954)	$59,520
(Gain) loss on natural gas derivatives	4,695	(1,874)	11,524	(2,983)
Gain on NGL derivatives	(4)	—	(4)	—
Gain on contingent consideration arrangements	(95)	(3,313)	(1,570)	(3,313)
(Gain) loss on derivative contracts	$126,965	($14,036)	($125,004)	$53,224

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.

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

We recorded income tax expense of $51.3 million for the three months ended June 30, 2020, compared to $16.7 million for the same period of 2019. Additionally, we recorded income tax expense of $115.3 million for the six months ended June 30, 2020, compared to $11.5 million for the same period of 2019. The increase in expense is due to the recording of a valuation allowance during the three months ended June 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 June 30, 2020, driven primarily by the impairment of evaluated oil and gas properties recognized for the three months ended June 30, 2020, which limits the ability to consider other subjective evidence such as our potential for future growth. Based on the evaluation of the evidence available during the three months ended June 30, 2020, we concluded that it is more likely than not that the net deferred tax assets will not be realized and recorded a valuation allowance of $377.6 million, reducing the net deferred tax assets as of June 30, 2020 to zero. See “Note 9 - Income Taxes” of the Notes to our Consolidated Financial Statements for additional information on income tax.

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 six months ended June 30, 2020. Preferred Stock dividends of $1.8 million and $3.6 million were paid during the three and six months ended June 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

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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 six months ended June 30, 2020, cash and cash equivalents decreased $5.8 million to $7.5 million compared to $13.3 million at December 31, 2019.

	Six Months Ended June 30,
	2020	2019
	(In thousands)
Net cash provided by operating activities	$289,496	$225,046
Net cash used in investing activities	(453,656)	(124,504)
Net cash provided by (used in) financing activities	158,319	(100,541)
Net change in cash and cash equivalents	($5,841)	$1

Operating activities. For the six months ended June 30, 2020, net cash provided by operating activities was $289.5 million compared to net cash provided by operating activities of $225.0 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 161% increase in production volumes predominantly as a result of the Carrizo Acquisition, which was partially offset by a decrease in realized pricing, 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” of the Notes to our Consolidated Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation. 

Investing activities. For the six months ended June 30, 2020, net cash used in investing activities was $453.7 million compared to $124.5 million for the same period in 2019.

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

	Six Months Ended June 30,
	2020	2019	$ Change
	(In thousands)
Capital expenditures	$430,569	$359,430	$71,139
Acquisitions	—	39,370	(39,370)
Proceeds from the sale of assets	(10,079)	(274,296)	264,217
Cash paid for settlements of contingent consideration arrangements, net	40,000	—	40,000
Additions to other assets	(6,834)	—	(6,834)
Total investing activities	$453,656	$124,504	$329,152

Cash used in investing activities increased by approximately $329.2 million for the six months ended June 30, 2020 compared to the same period in 2019 due primarily to lower proceeds from the sale of assets during the six months ended June 30, 2020. In 2019 Callon 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 six months ended June 30, 2020, net cash provided by financing activities was $158.3 million compared to net cash used in financing activities of $100.5 million for the same period of 2019.

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

	Six Months Ended June 30,
	2020	2019	$ Change
	(In thousands)
Net borrowings on Credit Facility	$165,000	($95,000)	$260,000
Payment of deferred financing costs	(6,011)	(31)	(5,980)
Payment of preferred stock dividends(1)	—	(3,647)	3,647
Tax withholdings related to restricted stock units	(388)	(1,858)	1,470
Other, net	(282)	(5)	(277)
Net cash provided by (used in) financing activities	$158,319	($100,541)	$258,860

(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” and “Note 10 - Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional information on our debt and equity transactions.

Senior Secured Revolving Credit Facility. We have a senior secured revolving credit facility with a syndicate of lenders that, as of June 30, 2020, had a borrowing base of $1.7 billion, with an elected commitment amount of $1.7 billion, borrowings outstanding of $1.45 billion at a weighted average interest rate of 3.01%, and $19.7 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. See “Note 6 - Borrowings” of the Notes to our Consolidated Financial Statements for further discussion of the first amendment. Primarily as a result of the recent downturn in commodity prices as well as demand as a result of COVID-19, our available liquidity has tightened, however, we expect to have sufficient liquidity to pay interest on our revolving credit facility and our Senior 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.

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Hedging. As of July 31, 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)	6,291,880		1,377,000
Weighted average price per Bbl	$42.08		$42.00
Collar contracts
Total volume (Bbls)	2,863,040		3,741,250
Weighted average price per Bbl
Ceiling (short call)	$45.00		$45.02
Floor (long put)	$35.00		$40.00
Short put contracts
Total volume (Bbls)	1,104,000		—
Weighted average price per Bbl	$42.50		$—
Long call contracts
Total volume (Bbls)	920,000		—
Weighted average price per Bbl	$67.50		$—
Short call contracts
Total volume (Bbls)	920,000	(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 (WTI Calendar Month Average Roll)
Swap contracts
Total volume (Bbls)	3,864,000		—
Weighted average price per Bbl	($2.75)		$—
Oil contracts (Brent ICE)
Swap contracts
Total volume (Bbls)	184,000		1,272,450
Weighted average price per Bbl	$46.15		$38.24
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	3,094,700		4,015,100
Weighted average price per Bbl	($1.75)		$0.40
Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls)	3,256,004		—
Weighted average price per Bbl	$0.06		$—
Oil contracts (Argus Houston MEH swaps)
Swap contracts
Total volume (Bbls)	368,000		2,969,050
Weighted average price per Bbl	$57.71		$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.

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	For the Remainder	For the Full Year
Natural gas contracts (Henry Hub)	of 2020	of 2021
Swap contracts
Total volume (MMBtu)	8,566,000	12,923,000
Weighted average price per MMBtu	$2.07	$2.66
Collar contracts (three-way collars)
Total volume (MMBtu)	2,755,000	1,350,000
Weighted average price per MMBtu
Ceiling (short call)	$2.73	$2.70
Floor (long put)	$2.47	$2.42
Floor (short put)	$2.00	$2.00
Collar contracts (two-way collars)
Total volume (MMBtu)	1,525,000	7,750,000
Weighted average price per MMBtu
Ceiling (short call)	$3.25	$2.93
Floor (long put)	$2.67	$2.55
Long call contracts
Total volume (MMBtu)	3,036,000	—
Weighted average price per MMBtu	$3.50	$—
Short call contracts
Total volume (MMBtu)	6,072,000	7,300,000
Weighted average price per MMBtu	$3.50	$3.09
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	12,885,000	6,387,500
Weighted average price per MMBtu	($0.92)	($0.58)

	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 do not currently have any active rigs or completion crews, but we do intend to resume development activity during the third quarter of 2020. Near-term operational activity will be focused on completing a drilled, but uncompleted inventory of approximately 70 wells in both the Permian Basin and Eagle Ford Shale with one dedicated completion crew. We also intend to return two to three drilling rigs to service later in the third quarter of 2020 for the balance of the year. As a result, we currently forecast total operational capital expenditures of approximately $140.0 to $165.0 million over the remaining two quarters of 2020 and expect operational capital expenditures to be approximately $500.0 to $525.0 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.

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Contractual Obligations

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

	Payments due by Period
	July - 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
Senior secured revolving credit facility (2)	—	—	—	—	1,450,000	1,450,000
Interest expense and other fees related to debt commitments (3)	133,059	154,245	154,245	133,933	183,934	759,416
Delivery commitments (4)	6,549	13,437	10,980	11,553	51,715	94,234
Operating leases	7,419	10,494	5,453	5,013	22,990	51,369
Asset retirement obligations (5)	2,330	22	374	194	48,175	51,095
Produced water disposal commitments (6)	9,055	14,968	11,933	4,387	3,410	43,753
Drilling rig leases (7)	9,047	3,562	—	—	—	12,609
Other commitments	731	845	508	392	39	2,515
Total contractual obligations	$168,190	$197,573	$183,493	$805,472	$3,010,263	$4,364,991

(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” of the Notes to our Consolidated Financial Statements 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, the Credit Facility and commitment fees calculated based on the unused portion of lender commitments as of June 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 June 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

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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 June 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 months ended June 30, 2020 as summarized in the table below:

	Three Months Ended June 30,
	2020		2019
Impairment of evaluated oil and gas properties (in thousands)	$1,276,518		$—
Beginning of period 12-Month Average Realized Price ($/Bbl)	$54.63		$54.58
End of period 12-Month Average Realized Price ($/Bbl)	$45.87		$53.00
Percent decrease in 12-Month Average Realized Price	(16)	%	(3)	%

The decrease in the 12-Month Average Realized Price as of June 30, 2020 reduced our proved oil and gas reserve volumes by 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. There were no proved undeveloped reserve locations that became uneconomic as a result of the decrease in the 12-Month Average Realized Price as of June 30, 2020. 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 11 months ended August 1, 2020 as well as forecasted costs, we anticipate recording an additional after-tax impairment in the carrying value of oil and gas properties in the third quarter of 2020 in the range of $750.0 million to $1.0 billion. We currently estimate that the forecasted decrease in the 12-Month Average Realized Price as of September 30, 2020 will result in a reduction of our proved oil and gas reserve volumes of less than 1% 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. Additionally, we estimate that none of our proved undeveloped reserve locations will be uneconomic and would need to be removed from proved 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 second and third 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.

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The table below presents various pricing scenarios to demonstrate the sensitivity of our June 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 June 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 June 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)
June 30, 2020 Actual	$45.87	$0.95	$—
Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$50.59	$1.16	$818	$818
Crude Oil and Natural Gas -10%	$41.15	$0.74	($818)	($818)
Crude Oil Price Sensitivity
Crude Oil +10%	$50.59	$0.95	$762	$762
Crude Oil -10%	$41.15	$0.95	($762)	($762)
Natural Gas Price Sensitivity
Natural Gas +10%	$45.87	$1.16	$56	$56
Natural Gas -10%	$45.87	$0.74	($56)	($56)

Income taxes

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

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

our net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at June 30, 2020, driven primarily by the impairment of evaluated oil and gas properties recognized for the three months ended June 30, 2020, which limits the ability to consider other subjective evidence such as our potential for future growth. Based on the evaluation of the evidence available during the three months ended June 30, 2020, we concluded that it is more likely than not that the net deferred tax assets will not be realized and recorded a valuation allowance of $377.6 million, reducing the net deferred tax assets as of June 30, 2020 to zero.

We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not 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” of the Notes to our Consolidated Financial Statements for additional information regarding income taxes.

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

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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 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 June 30, 2020, for the remainder of 2020, the Company had 9,706,920 Bbls of fixed price oil hedges across NYMEX WTI, ICE Brent and Argus WTI-Houston benchmarks. The Company also had 4,609,200 Bbls of WTI Midland-Cushing oil basis hedges and 3,256,004 Bbls of WTI Houston-Cushing oil basis hedges. Additionally, for the remainder of 2020, the Company had 9,810,000 MMBtus of fixed price NYMEX natural gas hedges and 12,885,000 MMBtus of Waha natural gas basis hedges. See “Note 7 - Derivative Instruments and Hedging Activities” of the Notes to our Consolidated Financial Statements for a description of the Company’s outstanding derivative contracts as of June 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 Credit Facility. As of June 30, 2020, the Company had $1.45 billion outstanding under the Credit Facility with a weighted average interest rate of 3.01%. 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 $14.5 million, based on the balance outstanding at June 30, 2020. See “Note 6 - Borrowings” of the Notes to our Consolidated Financial Statements for more information on the Company’s interest rates on our 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 June 30, 2020 our total receivables from the sale of our oil and natural gas production were approximately $74.6 million.

Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At June 30, 2020 our joint interest receivables were approximately $9.7 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 Credit Facility. We are likely to enter into additional commodity derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing ISDA Agreements with our commodity derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a commodity derivative, whereby the party not in default may offset all

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commodity derivative liabilities owed to the defaulting party against all commodity derivative asset receivables from the defaulting party. At June 30, 2020, we had a net commodity derivative liability position of $5.9 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 June 30, 2020.

Changes in internal control over financial reporting. In April 2020, the Company completed the implementation of Enertia Software (“Enertia”), which is an integrated enterprise solution for managing accounting and financial reporting information, and utilized Enertia for its accounting and reporting for the three and six months ended June 30, 2020. The Company believes the implementation of the system and related changes to internal controls will enhance internal controls over financial reporting. The Company has updated its internal controls, as applicable, to facilitate modifications to its business processes and accounting procedures and will continue to evaluate the operating effectiveness of related key controls during subsequent periods. The Company does not believe that the Enertia implementation has had an adverse effect on its internal control over financial reporting.

There were no other changes to our internal control over financial reporting during the three and six months ended June 30, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

46

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.

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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		Amended and Restated Bylaws of the Company	10-K	3.2	2/27/2019
10.1		First Amendment, dated May 7, 2020, to the Credit Agreement by and between Callon Petroleum Company and JPMorgan Chase Bank, N.A., as administrative agent, and the lender parties thereto	10-Q	10.1	5/11/2020
10.2	(c)	Callon Petroleum Company 2020 Omnibus Incentive Plan	DEF 14A	B	4/28/2020
10.3	(a)(c)	Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on June 8, 2020, under the 2020 Omnibus Incentive Plan
10.4	(a)(c)	Form of Callon Petroleum Company Director Restricted Stock Unit Award Agreement, adopted on June 8, 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.

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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	August 5, 2020
Joseph C. Gatto, Jr.	Chief Executive Officer

/s/ James P. Ulm, II	Senior Vice President and	August 5, 2020
James P. Ulm, II	Chief Financial Officer

49

EX-10.3

Exhibit 10.3

2020 EMPLOYEE RESTRICTED STOCK UNIT AWARD AGREEMENT

(NON-OFFICER)

CALLON PETROLEUM COMPANY

2020 OMNIBUS INCENTIVE PLAN

THIS AGREEMENT (“Agreement”) is effective as of ______________, ______ (the “Grant Date”), by and between Callon Petroleum Company, a Delaware corporation (the “Company”), and ____________________ (the “Grantee”).

The Company has adopted the 2020 Omnibus Incentive Plan, effective June 8, 2020 (as may be amended from time to time the “Plan”), which by this reference is made a part hereof, for the benefit of eligible employees, directors and independent contractors of the Company and its Subsidiaries. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.

Pursuant to the Plan, the Committee, which has generally been assigned responsibility for administering the Plan, has determined that it would be in the interest of the Company and its stockholders to grant the restricted stock units provided herein in order to provide Grantee with additional remuneration for services rendered, to encourage Grantee to remain in the employ of the Company or its Subsidiaries and to increase Grantee’s personal interest in the continued success and progress of the Company.

The Company and Grantee therefore agree as follows:

1.Grant of Restricted Stock Units. Subject to the terms and conditions herein, effective as of the Grant Date, the Company hereby awards to the Grantee, pursuant to the Plan, a right to receive __________ shares of Common Stock of the Company, par value $.01 per share (“Restricted Stock Units”).

2.Vesting Schedule and Settlement.

Subject to the provisions of Section 3 hereof, the Restricted Stock Units shall vest in one-third increments (rounded up to the nearest whole number) on each of [DATE], [DATE] and [DATE] (each, a “Vesting Date”); provided that the Grantee remains in continuous employment with the Company through the applicable Vesting Date. For purposes of this Agreement, references to employment with the Company include employment with any successor to the Company as well as employment with any Subsidiary.

As soon as practicable (but in no event later than thirty (30) days) following the occurrence of the Vesting Date or vesting pursuant to Section 3, the Company shall deliver to the Grantee or, as applicable, the Grantee’s legal representative, estate, beneficiary or heir, certificates representing the applicable number shares of Common Stock or cause the applicable number of shares of Common Stock to be evidenced in book entry form in the Grantee’s name in the stock register of the Company maintained by the Company’s transfer agent.

3.Termination of Employment; Forfeiture.

(a)Death and Disability. Upon termination of the Grantee’s employment with the Company as a result of the death or Disability of the Grantee, the Restricted Stock Units shall immediately vest. For purposes hereof, “Disability” shall mean the physical or mental inability of Grantee to carry out the normal and usual duties of his position on a full-time basis for an entire period of six (6) continuous months together with the reasonable likelihood, as determined by the Company, that Grantee, upon the advice of a qualified physician, will be unable to carry out the normal and usual duties of his position.

(b)Qualified Separation from Service. If the Grantee’s employment is terminated due to a Qualified Separation from Service, the Committee may determine, in its sole discretion, that all remaining unvested Restricted Stock Units shall be 100% vested a of such termination date.  For purposes hereof, a “Qualified Separation from Service” is defined as a termination of Grantee’s employment with the Company, other than for Cause, provided that, as of the date of such termination (i) Grantee has attained a minimum of ten (10) years of employment with the Company, and (ii) Grantee has attained the age of fifty-five (55).

For purposes hereof, “Cause” is defined as: (i) the conviction of the Grantee by a court of competent jurisdiction as to which no further appeal can be taken of a crime involving moral turpitude or a felony or entering the plea of nolo contendere to such crime by the Grantee; (ii) the commission by the Grantee of a material act of fraud upon the Company, any Subsidiary or Affiliate; (iii) the material misappropriation by the Grantee of any funds or other property of the Company, any Subsidiary or Affiliate; (iv) the knowing engagement by the Grantee without the written approval of the Company, in any material activity which directly competes with the business of the Company, any Subsidiary or Affiliate, or which would directly result in material injury to the business or reputation of the Company or any Subsidiary or Affiliate; (v)(1) a material breach by the Grantee during the Grantee’s employment with the Company of any of the restrictive covenants set out in the Grantee’s employment agreement with the Company, if applicable, or (2) the material nonperformance of the Grantee’s duties to the Company or any Subsidiary or Affiliate (other than by reason of the Grantee’s illness or incapacity); (vi) any breach of the Grantee's fiduciary duties to the Company, including, without limitation, the duties of care, loyalty and obedience to the law; and (vii) the intentional failure of the Grantee to comply with the Company's Code of Business Conduct and Ethics, or to otherwise discharge his duties in good faith and in a manner that the Grantee reasonably believes to be in the best interests of the Company, and with the care an ordinarily prudent person in a like position would exercise under similar circumstances.

(c)Termination following a Change in Control. In the event of the Grantee’s termination of employment by the Company for any reason other than Cause within the two-year period immediately following the effective date of a Change in Control, all remaining unvested Restricted Stock Units shall be 100% vested a of such termination date.

(d)Company Equity Acceleration Benefits and Carrizo CIC Plan Inapplicable. Notwithstanding anything to the contrary contained herein, but subject to Section 4(c), the Carrizo Oil & Gas Inc. Change in Control Severance Plan (as may be amended from time to time) (the

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"Carrizo CIC Plan") and any other potential rights to equity acceleration benefits in connection with a termination of employment related to the merger of Carrizo Oil & Gas, Inc. with and into the Company (the "Other Acceleration Benefits") shall not apply to the Restricted Stock Units granted hereunder. As a condition of receiving this Award, Grantee hereby expressly acknowledges and agrees that, notwithstanding anything set forth in the Carrizo CIC Plan to the contrary, the Change in Control Benefits (as defined in the Carrizo CIC Plan), the Severance Benefits (as set forth in Section 3.02(c)(3) of the Carrizo CIC Plan) and the Other Acceleration Benefits shall not apply to the Restricted Stock Units granted hereunder, and hereby waives any right to any equity acceleration benefits provided for under the Carrizo CIC Plan or the Other Acceleration Benefits with respect to this award of Restricted Stock Units. In the event this Section 4(d) should be held by a court of competent jurisdiction to be unenforceable, this Agreement shall be terminated and of no further force or effect and all Restricted Stock Units (whether vested or unvested) shall be immediately forfeited to the Company without any consideration.

(e)Forfeiture. Upon termination of the Grantee’s employment with the Company for any reason other than death, Disability, Qualified Separation from Service with accelerated vesting by the Committee, or a termination without Cause following a Change in Control, all unvested Restricted Stock Units shall be immediately forfeited to the Company.

4.Clawback Policy. The Grantee hereby acknowledges and agrees that all rights with respect to the Restricted Stock Units are subject to the Company's Clawback Policy, as may be in effect from time to time. The Grantee further acknowledges and agrees that the Restricted Stock Units and amounts received with respect to the Restricted Stock Units are subject to recoupment pursuant to the terms of the Company Clawback Policy.

5.No Ownership Rights Prior to Issuance of Shares of Common Stock; Dividend Equivalents. Neither the Grantee nor any other person shall become the beneficial owner of the shares of Common Stock underlying the Restricted Stock Units, nor have any rights of a shareholder (including, without limitation, dividend and voting rights) with respect to any such shares of Common Stock, unless and until and after such shares of Common Stock have been delivered to the Grantee as described in Section 2. Notwithstanding the foregoing, prior to the vesting of the underlying Restricted Stock Units, Dividend Equivalents shall be accrued, without interest, for the benefit of the Grantee. Dividend Equivalents shall be subject to the same vesting schedule as the underlying Restricted Stock Units and shall be payable in cash at the same time as the Restricted Stock Units are settled pursuant to Section 2.

6.Mandatory Withholding ofTaxes. Grantee acknowledges and agrees that the Company shall deduct from the shares of Common Stock otherwise deliverable a number of shares of Common Stock (valued at their Fair Market Value) on the applicable date that is equal to the amount of all federal, state and local taxes required to be withheld by the Company. In the event the Company, in its sole discretion, determines that the Grantee’s tax obligations will not be satisfied under the method otherwise expressly described above and the Grantee does not provide payment to the Company in the form of shares of Common Stock (valued at their Fair Market Value) sufficient to satisfy any withholding obligations, then the Grantee, subject to compliance

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with the Company’s insider trading policies, authorizes the Company or the Company’s Stock Plan Administrator, currently Fidelity, to (i) sell a number of shares of Common Stock issued or outstanding pursuant to the Award, which number of shares of Common Stock the Company determines has at least the market value sufficient to meet the tax withholding obligations, plus additional shares of Common Stock to account for rounding and market fluctuations and (ii) pay such tax withholding to the Company. The Grantee may elect to have the Company withhold or purchase, as applicable, from shares of Common Stock or cash that would otherwise payable or deliverable an amount of cash and/or number of shares of Common Stock (valued at their Fair Market Value) equal to the product of the maximum federal marginal rate that could be applicable to the Grantee and the Fair Market Value of the shares of Common Stock or cash otherwise payable or deliverable, as applicable.

7.Restrictions Imposed by Law. Without limiting the generality of Section 16 of the Plan, the Grantee agrees that the Company will not be obligated to deliver any shares of Common Stock if counsel to the Company determines that such delivery would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the issuance or delivery of shares of Common Stock to comply with any such law, rule, regulation or agreement.

8.Notice. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be delivered personally or sent by first class mail, postage prepaid to the following address:

Callon Petroleum Company

2000 W. Sam Houston Parkway South, Ste. 2000

Houston, Texas 77042

Attention: Human Resources

with a copy to:

Callon Petroleum Company

2000 W. Sam Houston Parkway South, Ste. 2000

Houston, Texas 77042

Attention: Law Department

Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, and (i) shall be sent by first class mail, postage prepaid, to Grantee’s address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address, or (ii) shall be sent to the Grantee’s e-mail address specified in the Company’s records or e-mail address provided by the Grantee to the Company’s Stock Plan Administrator.

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9.Grantee Employment. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the employ of the Company or interfere in any way with the right of the Company to terminate the Grantee’s employment at any time, with or without cause; subject, however, to the provisions of the Grantee’s employment agreement, if applicable.

10.Governing Law. This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Delaware. Any suit, action or other legal proceeding arising out of this Agreement shall be brought in the United States District Court for the Southern District of Texas, Houston Division, or, if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Harris County, Texas. Each of the Grantee and the Company consents to the jurisdiction of any such court in any such suit, action, or proceeding and waives any objection that it may have to the laying of venue of any such suit, action, or proceeding in any such court.

11.Construction. References in this Agreement to “this Agreement” and the words “herein,” “hereof,” “hereunder” and similar terms include all exhibits and schedules appended hereto, including the Plan. This Agreement is entered into, and the Award evidenced hereby is granted, pursuant to the Plan and shall be governed by and construed in accordance with the Plan and the administrative interpretations adopted by the Committee thereunder. All decisions of the Committee upon questions regarding the Plan or this Agreement shall be conclusive. Unless otherwise expressly stated herein, in the event of any inconsistency between the terms of the Plan and this Agreement, the terms of the Plan shall control. The headings of the sections of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.

12.Code Section 409A. Restricted Stock Units under this Agreement are designed to be exempt from or comply with Section 409A of the Code and the related Treasury Regulations thereunder and the provisions of this Agreement will be administered, interpreted and construed accordingly (or disregarded to the extent such provision cannot be so administered, interpreted, or construed). If the Grantee is identified by the Company as a “specified employee” within the meaning of Code Section 409A(a)(2)(B)(i) on the date on which the Grantee has a “separation from service” (other than due to death) within the meaning of Treasury Regulation § 1.409A-1(h), any amount payable or settled under this Agreement on account of a separation from service that is deferred compensation subject to Section 409A of the Code shall be paid or settled on the earliest of (1) the first business day following the expiration of six months from the Grantee’s separation from service, (2) the date of the Grantee’s death, or (3) such earlier date as complies with the requirements of Section 409A of the Code.

13.Excise Taxes. Notwithstanding anything to the contrary in this Agreement, if the Grantee is a “disqualified individual” (as defined in Code Section 280G(c)), and the payments and benefits provided for under this Agreement, together with any other payments and benefits which the Grantee has the right to receive from the Company or any of its affiliates or any party to a transaction with the Company or any of its affiliates, would constitute a “parachute payment” (as defined in Code Section 280G(b)(2)), then the payments and benefits provided for under this

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Agreement shall be either (a) reduced (but not below zero) so that the present value of such total amounts and benefits received by the Grantee from the Company and its affiliates will be one dollar ($1.00) less than three times the Grantee’s “base amount” (as defined in Code Section 280G(b)(3)) and so that no portion of such amounts and benefits received by the Grantee shall be subject to the excise tax imposed by Code Section 4999 or (b) paid in full, whichever produces the better net after-tax position to the Grantee (taking into account any applicable excise tax under Code Section 4999 and any other applicable taxes). The reduction of payments and benefits hereunder, if applicable, shall be made by reducing payments or benefits to be paid hereunder in the order in which such payment or benefit would be paid or provided (beginning with such payment or benefit that would be made last in time and continuing, to the extent necessary, through to such payment or benefit that would be made first in time). The determination as to whether any such reduction in the amount of the payments and benefits provided hereunder is necessary shall be made by a nationally recognized accounting firm selected by the Company. If a reduced payment or benefit is made or provided and through error or otherwise that payment or benefit, when aggregated with other payments and benefits from the Company (or its affiliates) used in determining if a parachute payment exists, exceeds one dollar ($1.00) less than three times the Grantee’s base amount, then the Grantee shall immediately repay such excess to the Company upon notification that an overpayment has been made.

14.Grantee Acceptance. The Grantee shall accept the terms and conditions of this Agreement through the online acceptance procedures set forth by the Company’s Stock Plan Administrator. By electronically accepting this Agreement the Grantee acknowledges receipt of a copy of the Plan and hereby accepts this Award subject to all the terms and provisions hereof and thereof.

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EX-10.4

Exhibit 10.4

DIRECTOR RESTRICTED STOCK UNIT AWARD AGREEMENT

CALLON PETROLEUM COMPANY

2020 OMNIBUS INCENTIVE PLAN

THIS AGREEMENT (“Agreement”) is effective as of _________, _____ (the “Grant Date”), by and between Callon Petroleum Company, a Delaware corporation (the “Company”), and ____________________ (the “Grantee”).

The Company has adopted the Callon Petroleum Company 2020 Omnibus Incentive Plan, as effective June 8, 2020 (as may be amended from time to time, the “Plan”), which by this reference is made a part hereof, for the benefit of eligible employees, directors and independent contractors of the Company and its Subsidiaries. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.

Pursuant to the Plan, the Board, which has generally been assigned responsibility for administering the Plan with respect to awards made to Nonemployee Directors, has determined that it would be in the interest of the Company and its stockholders to grant the restricted stock units provided herein in order to provide Grantee with additional remuneration for services rendered, to encourage Grantee to remain in the service of the Company as a Nonemployee Director and to increase Grantee’s personal interest in the continued success and progress of the Company.

The Company and Grantee therefore agree as follows:

1.Grant of Restricted Stock Units. Subject to the terms and conditions herein, effective as of the Grant Date, the Company hereby awards to the Grantee, pursuant to the Plan, a right to receive ______ shares of Common Stock of the Company, par value $.01 per share (“Restricted Stock Units”).

2.Vesting Schedule and Settlement. Subject to the provisions of Section ‎3 hereof, the Restricted Stock Units shall vest on the first anniversary of the Grant Date or, if earlier, the date of the Company’s ________ Annual Meeting of Shareholders (the “Vesting Date”); provided that the Grantee remains in continuous service as a Nonemployee Director with the Company through the Vesting Date.

Notwithstanding the foregoing, upon a Change in Control while the Grantee remains in continuous service as a Nonemployee Director with the Company, all unvested Restricted Stock Units shall immediately vest and such occurrence shall be deemed a Vesting Date for purposes of this Agreement.

As soon as practicable but in no event later than thirty (30) days following the occurrence of the Vesting Date or vesting pursuant to Section ‎3, the Company shall deliver to the Grantee or, as applicable, the Grantee’s legal representative, estate, beneficiary or heir, certificates representing the applicable number shares of Common Stock or cause the applicable number of shares of Common Stock to be evidenced in book entry form in the Grantee’s name in the stock register of the Company maintained by the Company’s transfer agent.

3.Termination of Service; Forfeiture.

(a)Death and Disability. Upon termination of the Grantee’s service as a Nonemployee Director with the Company as a result of the death or Disability of the Grantee, the Restricted Stock Units shall immediately vest. For purposes hereof, “Disability” shall mean the physical or mental inability of Grantee to carry out the normal and usual duties of his or her position on a full-time basis for an entire period of six (6) continuous months together with the reasonable likelihood, as determined by the Board (excluding Grantee), that Grantee, upon the advice of a qualified physician, will be unable to carry out the normal and usual duties of his or her position.

(b)Retirement. If the Grantee’s service as a Nonemployee Director with the Company is terminated as a result of the Grantee’s retirement, the Board (excluding Grantee) may determine, in its sole discretion, that the Restricted Stock Units shall immediately vest.

(c)Forfeiture. Upon termination of the Grantee’s serviceas a Nonemployee Director of the Company for any reason other than due to death or Disability, all Restricted Stock Units that have not previously vested (or that the Board does not determine to vest in its discretion pursuant to Section 3(b)) shall be immediately forfeited to the Company.

4.No Ownership Rights Prior to Issuance of Shares of Common Stock; Dividend Equivalents. Neither the Grantee nor any other person shall become the beneficial owner of the shares of Common Stock underlying the Restricted Stock Units, nor have any rights of a shareholder (including, without limitation, dividend and voting rights) with respect to any such shares of Common Stock, unless and until and after such shares of Common Stock have been delivered to the Grantee as described in Section ‎2. Notwithstanding the foregoing, prior to the vesting of the underlying Restricted Stock Units, Dividend Equivalents shall be accrued, without interest, for the benefit of the Grantee. Dividend Equivalents shall be subject to the same vesting schedule as the underlying Restricted Stock Units and shall be payable in cash at the same time as the Restricted Stock Units are settled pursuant to Section 2.

5.Restrictions Imposed by Law. Without limiting the generality of Section 16 of the Plan, the Grantee agrees that the Company will not be obligated to deliver any shares of Common Stock if counsel to the Company determines that such delivery would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the issuance or delivery of shares of Common Stock to comply with any such law, rule, regulation or agreement.

6.Notice. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be delivered personally or sent by first class mail, postage prepaid to the following address:

Callon Petroleum Company

2000 W. Sam Houston Parkway South, Suite 2000

Houston, Texas 77042

Attention: Human Resources

with a copy to:

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Callon Petroleum Company

2000 W. Sam Houston Parkway South, Suite 2000

Houston, Texas 77042

Attention: Law Department

Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, and (i) shall be sent by first class mail, postage prepaid, to Grantee’s address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address, or (ii) shall be sent to the Grantee’s e mail address specified in the Company’s records or e-mail address provided by Grantee to the Company’s Stock Plan Administrator, currently Fidelity.

7.Grantee Service. Nothing contained in this Agreement, and no action of the Company or the Board with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the service of the Company as a Nonemployee Director.

8.Governing Law. This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Delaware. Any suit, action or other legal proceeding arising out of this Agreement shall be brought in the United States District Court for the Southern District of Texas, Houston Division, or, if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Harris County, Texas. Each of the Grantee and the Company consents to the jurisdiction of any such court in any such suit, action, or proceeding and waives any objection that it may have to the laying of venue of any such suit, action, or proceeding in any such court.

9.Construction. References in this Agreement to “this Agreement” and the words “herein,” “hereof,” “hereunder” and similar terms include all exhibits and schedules appended hereto, including the Plan. This Agreement is entered into, and the Award evidenced hereby is granted, pursuant to the Plan and shall be governed by and construed in accordance with the Plan and the administrative interpretations adopted by the Board thereunder. All decisions of the Board upon questions regarding the Plan or this Agreement shall be conclusive. Unless otherwise expressly stated herein, in the event of any inconsistency between the terms of the Plan and this Agreement, the terms of the Plan shall control. The headings of the sections of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.

10.Code Section 409A. Restricted Stock Units under this Agreement are designed to be exempt from or comply with Section 409A of the Code and the related Treasury Regulations thereunder and the provisions of this Agreement will be administered, interpreted and construed accordingly (or disregarded to the extent such provision cannot be so administered, interpreted, or construed).

11.Grantee Acceptance. The Grantee shall accept the terms and conditions of this Agreement through the online acceptance procedures set forth by the Company’s Stock Plan Administrator. By electronically accepting this Agreement the Grantee acknowledges receipt of a copy of the Plan and hereby accepts this Award subject to all the terms and provisions hereof and thereof.

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EX-31.1

Exhibit31.1

CERTIFICATIONS

I, Joseph C. Gatto, Jr., certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Callon Petroleum Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	August 5, 2020	/s/ Joseph C. Gatto, Jr.
		Joseph C. Gatto, Jr.
		President and Chief Executive Officer
		(Principal executive officer)

EX-31.2

Exhibit31.2

CERTIFICATIONS

I, James P. Ulm, II, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Callon Petroleum Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	August 5, 2020	/s/ James P. Ulm, II
		James P. Ulm, II
		Senior Vice President and Chief Financial Officer
		(Principal financial officer)

EX-32

Exhibit32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Quarterly Report on Form 10-Q of Callon Petroleum Company for the quarterly period ended June 30, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacities and on the dates indicated below, each hereby certify pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Report fully complies with requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	August 5, 2020	/s/ Joseph C. Gatto, Jr.
		Joseph C. Gatto, Jr.
		(Principal executive officer)
Date:	August 5, 2020	/s/ James P. Ulm, II
		James P. Ulm, II
		(Principal financial officer)

The foregoing certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

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Cover Page - shares	6 Months Ended
	Jun. 30, 2020	Jul. 31, 2020
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2020
Document Transition Report	false
Entity File Number	001-14039
Entity Registrant Name	Callon Petroleum Co
Entity Central Index Key	0000928022
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	64-0844345
Entity Address, Address Line One	One Briarlake Plaza
Entity Address, Address Line Two	2000 W. Sam Houston Parkway S., Suite 2000
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77042
City Area Code	(281)
Local Phone Number	589-5200
Title of 12(b) Security	Common Stock, $0.01 par value
Trading Symbol	CPE
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		397,476,674
Former Address
Entity Information [Line Items]
Entity Address, Address Line One
Entity Address, Address Line Two
Entity Address, City or Town
Entity Address, State or Province
Entity Address, Postal Zip Code

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 7,500	$ 13,341
Accounts receivable, net	95,839	209,463
Fair value of derivatives	31,563	26,056
Other current assets	28,828	19,814
Total current assets	163,730	268,674
Oil and natural gas properties, full cost accounting method:
Evaluated properties	3,777,956	4,682,994
Unevaluated properties	1,762,860	1,986,124
Total oil and natural gas properties, net	5,540,816	6,669,118
Operating lease right-of-use assets	35,926	63,908
Other property and equipment, net	32,444	35,253
Deferred tax asset	0	115,720
Deferred financing costs	25,993	22,233
Other assets, net	11,224	19,932
Total assets	5,810,133	7,194,838
Current liabilities:
Accounts payable and accrued liabilities	405,596	511,622
Operating lease liabilities	24,355	42,858
Fair value of derivatives	32,683	71,197
Other current liabilities	15,053	26,570
Total current liabilities	477,687	652,247
Long-term debt	3,350,730	3,186,109
Operating lease liabilities	30,729	37,088
Asset retirement obligations	48,765	48,860
Fair value of derivatives	8,678	32,695
Other long-term liabilities	12,160	14,531
Total liabilities	3,928,749	3,971,530
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value, 525,000,000 shares authorized; 396,738,180 and 396,600,022 shares outstanding, respectively	3,974	3,966
Capital in excess of par value	3,204,310	3,198,076
Retained earnings (Accumulated deficit)	(1,326,900)	21,266
Total stockholders’ equity	1,881,384	3,223,308
Total liabilities and stockholders’ equity	$ 5,810,133	$ 7,194,838

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Jun. 30, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	525,000,000	525,000,000
Common stock, shares outstanding (in shares)	397,396,922	396,600,022

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Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Operating revenues:
Total operating revenues	$ 157,234,000	$ 167,052,000	$ 447,153,000	$ 320,099,000
Operating Expenses:
Lease operating	50,838,000	22,776,000	103,221,000	46,843,000
Production and ad valorem taxes	10,361,000	11,131,000	30,041,000	21,944,000
Gathering, transportation and processing	20,037,000	0	34,415,000	0
Depreciation, depletion and amortization	138,930,000	63,137,000	270,393,000	123,145,000
General and administrative	10,024,000	10,564,000	18,349,000	25,341,000
Impairment of evaluated oil and gas properties	1,276,518,000	0	1,276,518,000	0
Merger and integration expenses	8,067,000	0	23,897,000	0
Other operating	4,135,000	935,000	4,135,000	1,092,000
Total operating expenses	1,518,910,000	108,543,000	1,760,969,000	218,365,000
Income (Loss) From Operations	(1,361,676,000)	58,509,000	(1,313,816,000)	101,734,000
Other (Income) Expenses:
Interest expense, net of capitalized amounts	22,682,000	741,000	43,160,000	1,479,000
(Gain) loss on derivative contracts	126,965,000	(14,036,000)	(125,004,000)	53,224,000
Other (income) expense	2,157,000	(67,000)	895,000	(148,000)
Total other (income) expense	151,804,000	(13,362,000)	(80,949,000)	54,555,000
Income (Loss) Before Income Taxes	(1,513,480,000)	71,871,000	(1,232,867,000)	47,179,000
Income tax expense	(51,251,000)	(16,691,000)	(115,299,000)	(11,542,000)
Net Income (Loss)	(1,564,731,000)	55,180,000	(1,348,166,000)	35,637,000
Preferred stock dividends	0	(1,823,000)	0	(3,647,000)
Income (Loss) Available to Common Stockholders	$ (1,564,731,000)	$ 53,357,000	$ (1,348,166,000)	$ 31,990,000
Income (Loss) Available to Common Stockholders Per Common Share:
Basic (in dollars per share)	$ (3.94)	$ 0.23	$ (3.40)	$ 0.14
Diluted (in dollars per share)	$ (3.94)	$ 0.23	$ (3.40)	$ 0.14
Weighted Average Common Shares Outstanding:
Basic (in shares)	397,084	228,051	396,884	227,917
Diluted (in shares)	397,084	228,411	396,884	228,599
Oil
Operating revenues:
Total operating revenues	$ 130,513,000	$ 160,728,000	$ 396,280,000	$ 301,826,000
Natural gas
Operating revenues:
Total operating revenues	12,242,000	6,324,000	18,271,000	18,273,000
Natural gas liquids
Operating revenues:
Total operating revenues	$ 14,479,000	$ 0	$ 32,602,000	$ 0

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Consolidated Statements of Stockholders' Equity (Unaudited) - USD ($) shares in Thousands, $ in Thousands	Total	Preferred Stock	Common Stock	Capital in Excess of Par	Retained Earnings (Accumulated Deficit)
Balance (in shares) at Dec. 31, 2018		1,459	227,583
Balance at Dec. 31, 2018	$ 2,445,208	$ 15	$ 2,276	$ 2,477,278	$ (34,361)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(19,543)				(19,543)
Shares issued pursuant to employee benefit plans (in shares)			24
Shares issued pursuant to employee benefit plans	154			154
Restricted stock (in shares)			277
Restricted stock	4,450		$ 3	4,447
Preferred stock dividend	(1,824)				(1,824)
Balance (in shares) at Mar. 31, 2019		1,459	227,884
Balance at Mar. 31, 2019	2,428,445	$ 15	$ 2,279	2,481,879	(55,728)
Balance (in shares) at Dec. 31, 2018		1,459	227,583
Balance at Dec. 31, 2018	2,445,208	$ 15	$ 2,276	2,477,278	(34,361)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	35,637
Balance (in shares) at Jun. 30, 2019		1,459	228,264
Balance at Jun. 30, 2019	2,483,872	$ 15	$ 2,283	2,483,945	(2,371)
Balance (in shares) at Mar. 31, 2019		1,459	227,884
Balance at Mar. 31, 2019	2,428,445	$ 15	$ 2,279	2,481,879	(55,728)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	55,180				55,180
Restricted stock (in shares)			380
Restricted stock	2,075		$ 4	2,071
Preferred stock dividend	(1,823)				(1,823)
Preferred stock redemption costs	(5)			(5)
Balance (in shares) at Jun. 30, 2019		1,459	228,264
Balance at Jun. 30, 2019	2,483,872	$ 15	$ 2,283	2,483,945	(2,371)
Balance (in shares) at Dec. 31, 2019		0	396,600
Balance at Dec. 31, 2019	3,223,308	$ 0	$ 3,966	3,198,076	21,266
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	216,565				216,565
Restricted stock (in shares)			138
Restricted stock	3,142		$ 1	3,141
Other	(112)			(112)
Balance (in shares) at Mar. 31, 2020		0	396,738
Balance at Mar. 31, 2020	3,442,903	$ 0	$ 3,967	3,201,105	237,831
Balance (in shares) at Dec. 31, 2019		0	396,600
Balance at Dec. 31, 2019	3,223,308	$ 0	$ 3,966	3,198,076	21,266
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(1,348,166)
Balance (in shares) at Jun. 30, 2020		0	397,397
Balance at Jun. 30, 2020	1,881,384	$ 0	$ 3,974	3,204,310	(1,326,900)
Balance (in shares) at Mar. 31, 2020		0	396,738
Balance at Mar. 31, 2020	3,442,903	$ 0	$ 3,967	3,201,105	237,831
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(1,564,731)				(1,564,731)
Restricted stock (in shares)			659
Restricted stock	3,212		$ 7	3,205
Balance (in shares) at Jun. 30, 2020		0	397,397
Balance at Jun. 30, 2020	$ 1,881,384	$ 0	$ 3,974	$ 3,204,310	$ (1,326,900)

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Consolidated Statements of Cash Flows (Unaudited) - USD ($)	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019
Cash flows from operating activities:
Net income (loss)	$ (1,348,166,000)	$ 35,637,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	270,393,000	125,503,000
Impairment of evaluated oil and gas properties	1,276,518,000	0
Amortization of non-cash debt related items	1,145,000	1,479,000
Deferred income tax expense	115,299,000	11,542,000
(Gain) loss on derivative contracts	(125,004,000)	53,224,000
Cash (paid) received for commodity derivative settlements	101,301,000	(1,447,000)
Loss on sale of other property and equipment	0	49,000
Non-cash expense related to equity share-based awards	4,817,000	6,299,000
Change in the fair value of liability share-based awards	(5,028,000)	1,031,000
Payments to settle asset retirement obligations	0	(771,000)
Payments for cash-settled restricted stock unit awards	(755,000)	(1,425,000)
Other, net	4,411,000	0
Changes in current assets and liabilities:
Accounts receivable	113,040,000	38,681,000
Other current assets	(4,348,000)	(6,101,000)
Current liabilities	(114,127,000)	(36,254,000)
Other	0	(2,401,000)
Net cash provided by operating activities	289,496,000	225,046,000
Cash flows from investing activities:
Capital expenditures	(430,569,000)	(359,430,000)
Acquisitions	0	(39,370,000)
Proceeds from sale of assets	10,079,000	274,296,000
Cash paid for settlements of contingent consideration arrangements, net	(40,000,000)	0
Other, net	6,834,000	0
Net cash used in investing activities	(453,656,000)	(124,504,000)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	4,775,500,000	360,000,000
Payments on senior secured revolving credit facility	(4,610,500,000)	(455,000,000)
Payment of preferred stock dividends	0	(3,647,000)
Payment of deferred financing costs	(6,011,000)	(31,000)
Tax withholdings related to restricted stock units	(388,000)	(1,858,000)
Other, net	(282,000)	(5,000)
Net cash provided by (used in) financing activities	158,319,000	(100,541,000)
Net change in cash and cash equivalents	(5,841,000)	1,000
Balance, beginning of period	13,341,000	16,051,000
Balance, end of period	$ 7,500,000	$ 16,052,000

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Description of Business and Basis of Presentation

6 Months Ended

Jun. 30, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of Business and Basis of Presentation

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 15 - Subsequent Events” for further discussion.

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Revenue Recognition

6 Months Ended

Jun. 30, 2020

Revenue from Contract with Customer [Abstract]

Revenue Recognition

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 six months ended June 30, 2019, $2.8 million and $5.2 million of gathering, transportation, and processing fees were recognized as a reduction to natural gas revenues in the consolidated statement of operations.

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 June 30, 2020 and December 31, 2019 of $74.6 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.

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Acquisitions and Divestitures

6 Months Ended

Jun. 30, 2020

Business Combinations [Abstract]

Acquisitions and Divestiture

Acquisitions and Divestitures

2020 Acquisitions and Divestitures

The Company did not have any material acquisitions or divestitures for the six months ended June 30, 2020.

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	88,627
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	$2,364,277
Assets:
Accounts receivable, net	$48,479
Fair value of derivatives - current	17,451
Other current assets	11,137
Evaluated oil and natural gas properties	2,133,280
Unevaluated properties	683,366
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	$3,129,650

Approximately $86.9 million and $248.3 million of revenues and $47.7 million and $99.9 million of direct operating expenses attributed to the Carrizo Acquisition were included in the Company’s consolidated statements of operations for the three and six months ended June 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

During the three and six months ended June 30, 2020, in conjunction with the Carrizo Acquisition, the Company incurred costs totaling $8.1 million and $23.9 million, respectively, comprised of severance costs of $2.4 million and $5.4 million, respectively, and other merger and integration expenses of $5.7 million and $18.5 million, respectively. Through June 30, 2020, the Company has incurred cumulative costs associated with the Carrizo Acquisition of $98.3 million comprised of severance costs of $34.2 million and other merger and integration expenses of $64.1 million. As of June 30, 2020, $23.0 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.

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Property and Equipment, Net

6 Months Ended

Jun. 30, 2020

Property, Plant and Equipment [Abstract]

Property and Equipment, Net

Property and Equipment, Net

As of June 30, 2020 and December 31, 2019, total property and equipment, net consisted of the following:

	June 30, 2020	December 31, 2019
Oil and natural gas properties, full cost accounting method	(In thousands)
Evaluated properties	$7,840,616	$7,203,482
Accumulated depreciation, depletion, amortization and impairments	(4,062,660)	(2,520,488)
Net evaluated oil and natural gas properties	3,777,956	4,682,994
Unevaluated properties
Unevaluated leasehold and seismic costs	1,596,662	1,843,725
Capitalized interest	166,198	142,399
Total unevaluated properties	1,762,860	1,986,124
Total oil and natural gas properties, net	$5,540,816	$6,669,118
Other property and equipment	$67,883	$67,202
Accumulated depreciation	(35,439)	(31,949)
Other property and equipment, net	$32,444	$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 $8.9 million and $8.4 million for the three months ended June 30, 2020 and 2019, respectively, and $16.4 million and $19.1 million for the six months ended June 30, 2020 and 2019.

The Company capitalized interest costs associated with its unproved properties totaling $20.9 million and $18.7 million for the three months ended June 30, 2020 and 2019, respectively, and $44.9 million and $38.6 million for the six months ended June 30, 2020 and 2019.

As a result of the recent 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 $43.9 million and $224.4 million from unevaluated leasehold to evaluated properties during the three and six months ended June 30, 2020, respectively, 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 June 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 months ended June 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 June 30,
	2020		2019
Impairment of evaluated oil and gas properties (in thousands)	$1,276,518		$—
Beginning of period 12-Month Average Realized Price ($/Bbl)	$54.63		$54.58
End of period 12-Month Average Realized Price ($/Bbl)	$45.87		$53.00
Percent decrease in 12-Month Average Realized Price	(16	%)	(3	%)

The Company expects to record an additional impairment in the carrying value of evaluated oil and gas properties in the third quarter of 2020 based on an estimated 12-Month Average Realized price of crude oil of approximately $43.45 as of September 30, 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 11 months and an estimate for the twelfth month 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.

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Earnings Per Share

6 Months Ended

Jun. 30, 2020

Earnings Per Share [Abstract]

Earnings Per Share

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 six months ended June 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 9.1 million and 9.2 million potentially dilutive common shares outstanding for the three and six months ended June 30, 2020, respectively. The following table sets forth the computation of basic and diluted earnings per share:

	Three Months Ended June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands, except per share amounts)
Net income (loss)	($1,564,731)	$55,180	($1,348,166)	$35,637
Preferred stock dividends (1)	—	(1,823)	—	(3,647)
Income (loss) available to common stockholders	($1,564,731)	$53,357	($1,348,166)	$31,990
Basic weighted average common shares outstanding	397,084	228,051	396,884	227,917
Dilutive impact of restricted stock	—	360	—	682
Diluted weighted average common shares outstanding	397,084	228,411	396,884	228,599
Income (Loss) Available to Common Stockholders Per Common Share
Basic	($3.94)	$0.23	($3.40)	$0.14
Diluted	($3.94)	$0.23	($3.40)	$0.14
Restricted stock (2)	9,066	641	9,169	498

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

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Borrowings

6 Months Ended

Jun. 30, 2020

Debt Disclosure [Abstract]

Borrowings

Borrowings

The Company’s borrowings consisted of the following:

	June 30, 2020	December 31, 2019
	(In thousands)
Senior Secured Revolving Credit Facility due 2024	$1,450,000	$1,285,000
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	3,350,000	3,185,000
Unamortized premium on 6.125% Senior Notes	4,781	5,344
Unamortized premium on 6.25% Senior Notes	4,163	4,838
Unamortized premium on 8.25% Senior Notes	4,809	5,286
Unamortized deferred financing costs for Senior Notes	(13,023)	(14,359)
Total carrying value of borrowings (1)	$3,350,730	$3,186,109

(1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $26.0 million and $22.2 million as of June 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 June 30, 2020, had a borrowing base of $1.7 billion, with an elected commitment amount of $1.7 billion, borrowings outstanding of $1.45 billion at a weighted-average interest rate of 3.01%, and letters of credit outstanding of $19.7 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 are outstanding at such time and (ii) July 2, 2024 if the 6.125% Senior Notes are outstanding at such time), 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) establishes a new borrowing base as a result of the spring 2020 scheduled redetermination in the amount of $1.7 billion and reduces the elected commitments to $1.7 billion; (b) permits the incurrence of, among other things, new second lien notes exchanged for unsecured notes in an aggregate principal amount of up to $400 million (the “Second Lien Notes”) so long as any such Second Lien Notes are subject to an intercreditor agreement providing that the liens securing the Second Lien 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) provides that the testing of the Current Ratio, which is the ratio of current assets to current liabilities is 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.

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.

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 recommencing September 30, 2020, of not less than 1.00 to 1.00. The Company was in compliance with these covenants at June 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).

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Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

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 June 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)	(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.

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 June 30, 2020
	Presented without		As Presented with
	Effects of Netting	Effects of Netting	Effects of Netting
ASSETS	(In thousands)
Commodity derivative instruments	$63,380	($31,890)	$31,490
Contingent consideration arrangements	73	—	73
Fair value of derivatives - current	$63,453	($31,890)	$31,563
Commodity derivative instruments	1,404	(952)	452
Contingent consideration arrangements	1,234	—	1,234
Other assets, net	$2,638	($952)	$1,686
LIABILITIES
Commodity derivative instruments	($64,122)	$31,890	($32,232)
Contingent consideration arrangements	(451)	—	(451)
Fair value of derivatives - current	($64,573)	$31,890	($32,683)
Commodity derivative instruments	(6,518)	952	(5,566)
Contingent consideration arrangements	(3,112)	—	(3,112)
Fair value of derivatives - non current	($9,630)	$952	($8,678)

	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 June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands)
(Gain) loss on oil derivatives	$122,369	($8,849)	($134,954)	$59,520
(Gain) loss on natural gas derivatives	4,695	(1,874)	11,524	(2,983)
Gain on NGL derivatives	(4)	—	(4)	—
Gain on contingent consideration arrangements	(95)	(3,313)	(1,570)	(3,313)
(Gain) loss on derivative contracts	$126,965	($14,036)	($125,004)	$53,224

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 June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands)
Cash flows from operating activities
Cash (paid) received on oil derivatives	$100,470	($4,461)	$98,693	($6,003)
Cash (paid) received on natural gas derivatives	(1,782)	3,304	2,608	4,556
Cash (paid) received for commodity derivative settlements	$98,688	($1,157)	$101,301	($1,447)
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 June 30, 2020:  

	For the Remainder		For the Full Year
Oil contracts (WTI)	of 2020		of 2021
Swap contracts
Total volume (Bbls)	6,291,880		—
Weighted average price per Bbl	$42.08		$—
Collar contracts
Total volume (Bbls)	2,863,040		—
Weighted average price per Bbl
Ceiling (short call)	$45.00		$—
Floor (long put)	$35.00		$—
Short put contracts
Total volume (Bbls)	1,104,000		—
Weighted average price per Bbl	$42.50		$—
Long call contracts
Total volume (Bbls)	920,000		—
Weighted average price per Bbl	$67.50		$—
Short call contracts
Total volume (Bbls)	920,000	(1)	4,825,300	(1)
Weighted average price per Bbl	$55.00		$63.62
Oil contracts (WTI Calendar Month Average Roll)
Swap contracts
Total volume (Bbls)	3,864,000		—
Weighted average price per Bbl	($2.75)		$—
Oil contracts (Brent ICE)
Swap contracts
Total volume (Bbls)	184,000		1,272,450
Weighted average price per Bbl	$46.15		$38.24
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	4,609,200		4,015,100
Weighted average price per Bbl	($0.98)		$0.40
Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls)	3,256,004		—
Weighted average price per Bbl	$0.06		$—
Oil contracts (Argus Houston MEH swaps)
Swap contracts
Total volume (Bbls)	368,000		2,969,050
Weighted average price per Bbl	$57.71		$39.48

(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)	5,530,000	12,923,000
Weighted average price per MMBtu	$2.21	$2.66
Collar contracts (three-way collars)
Total volume (MMBtu)	2,755,000	1,350,000
Weighted average price per MMBtu
Ceiling (short call)	$2.73	$2.70
Floor (long put)	$2.47	$2.42
Floor (short put)	$2.00	$2.00
Collar contracts (two-way collars)
Total volume (MMBtu)	1,525,000	7,750,000
Weighted average price per MMBtu
Ceiling (short call)	$3.25	$2.93
Floor (long put)	$2.67	$2.55
Short call contracts
Total volume (MMBtu)	6,072,000	7,300,000
Weighted average price per MMBtu	$3.50	$3.09
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	12,885,000	—
Weighted average price per MMBtu	($0.92)	$—

	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

See “Note 15 - Subsequent Events” for additional information regarding derivative contracts entered into subsequent to June 30, 2020.

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Fair Value Measurements

6 Months Ended

Jun. 30, 2020

Fair Value Disclosures [Abstract]

Fair Value Measurements

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.

	June 30, 2020		December 31, 2019
	Principal Amount	Fair Value	Principal Amount	Fair Value
	(In thousands)
6.25% Senior Notes	$650,000	$240,500	$650,000	$658,125
6.125% Senior Notes	600,000	216,000	600,000	611,130
8.25% Senior Notes	250,000	87,500	250,000	256,250
6.375% Senior Notes	400,000	136,000	400,000	405,424
Total	$1,900,000	$680,000	$1,900,000	$1,930,929

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:

	June 30, 2020
	Level 1	Level 2	Level 3
	(In thousands)
Assets
Commodity derivative instruments	$—	$31,942	$—
Contingent consideration arrangements	—	1,307	—
Liabilities
Commodity derivative instruments	—	(37,798)	—
Contingent consideration arrangements	—	(3,563)	—
Total net assets (liabilities)	$—	($8,112)	$—
	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)	$—

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.

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Income Taxes

6 Months Ended

Jun. 30, 2020

Income Tax Disclosure [Abstract]

Income Taxes

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 to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Income tax expense computed at the 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	(25	%)	—	%	(31	%)	—	%
Other discrete items (1)	—	%	1	%	—	%	2	%
Effective income tax rate, after discrete items	(3	%)	23	%	(9	%)	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 June 30, 2020, driven primarily by the impairment of evaluated oil and gas properties recognized for the three months ended June 30, 2020. This limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Based on the evaluation of the evidence available during the three months ended June 30, 2020, the Company concluded that it is more likely than not that the net deferred tax assets will not be realized and recorded a valuation allowance of $377.6 million, reducing the net deferred tax assets as of June 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.

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Share-Based Compensation

6 Months Ended

Jun. 30, 2020

Share-based Payment Arrangement [Abstract]

Share-based Compensation

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. The 2020 Plan provides that up to 13,250,000 shares of the Company’s common stock, plus the shares remaining available for awards under the Prior Incentive Plan, may be issued. As of June 30, 2020, there were 15,937,327 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 six months ended June 30, 2020 and 2019:

	Three Months Ended June 30,
	2020		2019
	RSU Equity Awards (in thousands)	Weighted Average Grant Date Fair Value	RSU Equity Awards (in thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	4,851	$6.95	3,406	$11.14
Granted (1)	3,257	$1.26	171	$7.87
Vested (2)	(900)	$10.06	(458)	$12.51
Forfeited	—	$—	(64)	$11.43
Unvested, end of the period	7,208	$3.99	3,055	$10.75

	Six Months Ended June 30,
	2020		2019
	RSU Equity Awards (in thousands)	Weighted Average Grant Date Fair Value	RSU Equity Awards (in thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	2,695	$10.25	2,103	$13.24
Granted (1)	5,575	$2.12	1,881	$8.60
Vested (2)	(1,062)	$10.02	(791)	$12.23
Forfeited	—	$—	(138)	$10.82
Unvested, end of the period	7,208	$3.99	3,055	$10.75

(1)Includes 0.3 million and zero target performance-based RSU Equity Awards during the three months ended June 30, 2020 and 2019, respectively, and 1.1 million and 0.4 million during the six months ended June 30, 2020 and 2019, respectively. The awards granted during the six months ended June 30, 2020 and 2019 will vest at a range of 0% to 300% and 0% to 200%, respectively.

(2)The fair value of shares vested was $0.6 million and $3.4 million during the three months ended June 30, 2020 and 2019, respectively, and $1.3 million and $6.0 million for the six months ended June 30, 2020 and 2019, respectively.

Grant activity for the six months ended June 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 $0.5 million and zero for the three months ended June 30, 2020 and 2019, respectively, and $3.4 million and $4.3 million for the six months ended June 30, 2020 and 2019, respectively. The following table summarizes the assumptions used and the resulting grant date fair value per performance-based RSU Equity Award granted during the six months ended June 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	—	%	—	%	—	%
Grant date fair value per performance-based RSU Equity Award	$1.80		$3.39		$10.78

As of June 30, 2020, unrecognized compensation costs related to unvested RSU Equity Awards were $19.7 million and will be recognized over a weighted average period of 2.1 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 six months ended June 30, 2020 and 2019:

	Three Months Ended June 30,
	2020		2019
	Cash-Settled RSU Awards (in thousands)	Weighted Average Grant Date Fair Value	Cash-Settled RSU Awards (in thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	1,707	$7.85	1,044	$11.69
Granted	386	$2.03	25	$8.1
Vested	(2)	$16.66	(17)	$11.06
Did not vest at end of performance period	(11)	$15.27	—	$—
Forfeited	—	$—	(21)	$16.38
Unvested, end of the period	2,080	$6.72	1,031	$11.52

	Six Months Ended June 30,
	2020		2019
	Cash-Settled RSU Awards (in thousands)	Weighted Average Grant Date Fair Value	Cash-Settled RSU Awards (in thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	855	$12.42	678	$12.36
Granted	1,249	$2.98	424	$10.62
Vested	(12)	$12.85	(17)	$11.06
Did not vest at end of performance period	(12)	$16.66	—	$—
Forfeited	—	$—	(54)	$15.21
Unvested, end of the period	2,080	$6.72	1,031	$11.52

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 and the resulting 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:

	June 30, 2020	December 31, 2019
	(In thousands)
Other current liabilities	$231	$966
Other long-term liabilities	674	2,089
Total Cash-Settled RSU Awards	$905	$3,055

As of June 30, 2020, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $2.2 million and will be recognized over a weighted average period of 2.3 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 June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands)
RSU Equity Awards	$3,212	$2,907	$7,160	$8,383
Cash-Settled RSU Awards	596	203	(1,400)	1,354
Cash SARs	1,115	—	(3,641)	—
	4,923	3,110	$2,119	$9,737
Less: amounts capitalized to oil and gas properties	(2,162)	(1,131)	(2,330)	(2,304)
Total share-based compensation expense (benefit), net	$2,761	$1,979	($211)	$7,433

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.

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Leases

6 Months Ended

Jun. 30, 2020

Leases [Abstract]

Leases

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 June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands)		(In thousands)
Components of Lease Costs
Finance lease costs	$552	$—	$1,128	$—
Amortization of right-of-use assets (1)	510	—	1,020	—
Interest on lease liabilities (2)	42	—	108	—
Operating lease costs (3)	16,387	9,565	33,664	19,156
Impairment of Operating lease ROU assets (4)	1,982	—	3,575	—
Short-term lease costs (5)	38	1,849	1,726	3,347
Variable lease costs (6)	70	—	74	—
Total lease costs	$19,029	$11,414	$40,167	$22,503

(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 June 30, 2020 and 2019, approximately $15.2 million and $7.0 million were costs associated with drilling rigs. For the six months ended June 30, 2020 and 2019, approximately $23.7 million and $13.9 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 six months ended June 30, 2020 of $2.0 million 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:

	June 30, 2020	December 31, 2019
	(In thousands)
Leases
Operating leases:
Operating lease ROU assets	$35,926	$63,908
Current operating lease liabilities	$24,355	$42,858
Long-term operating lease liabilities	30,729	37,088
Total operating lease liabilities	$55,084	$79,946
Financing leases:
Other property and equipment	$2,313	$2,197
Accumulated depreciation	(1,257)	(82)
Other property and equipment, net	$1,056	$2,115
Current financing lease liabilities	$463	$1,334
Long-term financing lease liabilities	572	807
Total financing lease liabilities	$1,035	$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 June 30, 2020
Weighted Average Remaining Lease Term (In years)
Operating leases	5.4
Financing leases	2.8
Weighted Average Discount Rate
Operating leases	5.4	%
Financing leases	7.1	%

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

	Operating Leases	Financing Leases
	(In thousands)
Remainder of 2020	$16,362	$363
2021	14,116	275
2022	5,453	234
2023	5,013	233
2024	4,937	38
Thereafter	18,097	—
Total lease payments	63,978	1,143
Less imputed interest	(8,894)	(108)
Total	$55,084	$1,035

Leases

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 June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands)		(In thousands)
Components of Lease Costs
Finance lease costs	$552	$—	$1,128	$—
Amortization of right-of-use assets (1)	510	—	1,020	—
Interest on lease liabilities (2)	42	—	108	—
Operating lease costs (3)	16,387	9,565	33,664	19,156
Impairment of Operating lease ROU assets (4)	1,982	—	3,575	—
Short-term lease costs (5)	38	1,849	1,726	3,347
Variable lease costs (6)	70	—	74	—
Total lease costs	$19,029	$11,414	$40,167	$22,503

(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 June 30, 2020 and 2019, approximately $15.2 million and $7.0 million were costs associated with drilling rigs. For the six months ended June 30, 2020 and 2019, approximately $23.7 million and $13.9 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 six months ended June 30, 2020 of $2.0 million 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:

	June 30, 2020	December 31, 2019
	(In thousands)
Leases
Operating leases:
Operating lease ROU assets	$35,926	$63,908
Current operating lease liabilities	$24,355	$42,858
Long-term operating lease liabilities	30,729	37,088
Total operating lease liabilities	$55,084	$79,946
Financing leases:
Other property and equipment	$2,313	$2,197
Accumulated depreciation	(1,257)	(82)
Other property and equipment, net	$1,056	$2,115
Current financing lease liabilities	$463	$1,334
Long-term financing lease liabilities	572	807
Total financing lease liabilities	$1,035	$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 June 30, 2020
Weighted Average Remaining Lease Term (In years)
Operating leases	5.4
Financing leases	2.8
Weighted Average Discount Rate
Operating leases	5.4	%
Financing leases	7.1	%

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

	Operating Leases	Financing Leases
	(In thousands)
Remainder of 2020	$16,362	$363
2021	14,116	275
2022	5,453	234
2023	5,013	233
2024	4,937	38
Thereafter	18,097	—
Total lease payments	63,978	1,143
Less imputed interest	(8,894)	(108)
Total	$55,084	$1,035

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Accounts Receivable, Net

6 Months Ended

Jun. 30, 2020

Receivables [Abstract]

Accounts Receivable, Net

Accounts Receivable, Net

	June 30, 2020	December 31, 2019
	(In thousands)
Oil and natural gas receivables	$74,555	$165,275
Joint interest receivables	9,664	39,114
Other receivables	13,388	6,610
Total	97,607	210,999
Allowance for doubtful accounts	(1,768)	(1,536)
Total accounts receivable, net	$95,839	$209,463

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Accounts Payable and Accrued Liabilities

6 Months Ended

Jun. 30, 2020

Payables and Accruals [Abstract]

Accounts Payable and Accrued Liabilities

Accounts Payable and Accrued Liabilities

	June 30, 2020	December 31, 2019
	(In thousands)
Accounts payable	$202,467	$238,758
Revenues payable	109,054	145,816
Accrued capital expenditures	29,926	61,950
Accrued interest	43,441	36,295
Accrued severance (1)	20,708	28,803
Total accounts payable and accrued liabilities	$405,596	$511,622

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

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Supplemental Cash Flow

6 Months Ended

Jun. 30, 2020

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow

Supplemental Cash Flow

	Six Months Ended June 30,
	2020	2019
Supplemental cash flow information:
Interest paid, net of capitalized amounts	$31,649	$—
Income taxes paid	—	—
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$26,110	$1,293
Investing cash flows from operating leases	11,278	17,865
Non-cash investing and financing activities:
Change in accrued capital expenditures	($6,186)	($16,286)
Change in asset retirement costs	207	—
ROU assets obtained in exchange for lease liabilities:
Operating leases	$2,666	$2,462

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Subsequent Events

6 Months Ended

Jun. 30, 2020

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

Hedging

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

	For the Remainder	For the Full Year
Oil contracts (WTI)	of 2020	of 2021
Swap contracts
Total volume (Bbls)	—	1,377,000
Weighted average price per Bbl	$—	$42.00
Collar contracts
Total volume (Bbls)	—	3,741,250
Weighted average price per Bbl
Ceiling (short call)	$—	$45.02
Floor (long put)	$—	$40.00
Short call swaption contracts
Total volume (Bbls)	—	730,000	(1)
Weighted average price per Bbl	$—	$47.00
Oil contracts (Midland basis differential)
Long swap contracts
Total volume (Bbls)	1,514,500	—
Weighted average price per Bbl	$0.60	$—
Natural gas contracts (Henry Hub)
Swap contracts
Total volume (MMBtu)	3,036,000	—
Weighted average price per MMBtu	$1.80	$—
Long call contracts
Total volume (MMBtu)	3,036,000	—
Weighted average price per MMBtu	$3.50	$—
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	—	6,387,500
Weighted average price per MMBtu	$—	($0.58)

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

Reverse Stock Split

On August 4, 2020, the Company announced that its Board of Directors approved a reverse stock split of Company’s outstanding shares of common stock at a ratio of 1-for-10 and a proportionate reduction of 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 will become effective as of the close of business on August 7, 2020 and the Company’s common stock will begin trading on a split-adjusted basis on the NYSE at market open on August 10, 2020. The par value of the common stock will not be adjusted in connection with the reverse stock split.

The reverse stock split is intended to, among other things, increase the per share trading price of the Company’s common shares to maintain compliance with the $1.00 minimum closing price requirement for continued listing on the NYSE and improve the opportunity for institutional ownership. Upon completion of the reverse stock split, each 10 pre-split shares of common stock outstanding will be automatically combined into one issued and outstanding share of common stock. The fractional shares that resulted from the reverse stock split were canceled, and shareholders who would otherwise hold fractional shares as a result of the reverse stock split will be entitled to receive cash (without interest and subject to applicable withholding taxes) in lieu of such fractional shares. The number of outstanding shares of common stock will be reduced from approximately 397,476,674 as of July 31, 2020 to approximately 39,747,667 shares (without giving effect to the liquidation of fractional shares). The total number of shares of common stock that the Company is authorized to issue will be reduced from 525,000,000 to 52,500,000 shares.

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Description of Business and Basis of Presentation (Policies)

6 Months Ended

Jun. 30, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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.

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 15 - Subsequent Events” for further discussion.

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Acquisitions and Divestitures (Tables)

6 Months Ended

Jun. 30, 2020

Business Combinations [Abstract]

Fair Value of Net Assets Acquired

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	88,627
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	$2,364,277
Assets:
Accounts receivable, net	$48,479
Fair value of derivatives - current	17,451
Other current assets	11,137
Evaluated oil and natural gas properties	2,133,280
Unevaluated properties	683,366
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	$3,129,650

Business Acquisition, Pro Forma Information

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

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Property and Equipment, Net (Tables)

6 Months Ended

Jun. 30, 2020

Property, Plant and Equipment [Abstract]

Schedule of Property and Equipment

As of June 30, 2020 and December 31, 2019, total property and equipment, net consisted of the following:

	June 30, 2020	December 31, 2019
Oil and natural gas properties, full cost accounting method	(In thousands)
Evaluated properties	$7,840,616	$7,203,482
Accumulated depreciation, depletion, amortization and impairments	(4,062,660)	(2,520,488)
Net evaluated oil and natural gas properties	3,777,956	4,682,994
Unevaluated properties
Unevaluated leasehold and seismic costs	1,596,662	1,843,725
Capitalized interest	166,198	142,399
Total unevaluated properties	1,762,860	1,986,124
Total oil and natural gas properties, net	$5,540,816	$6,669,118
Other property and equipment	$67,883	$67,202
Accumulated depreciation	(35,439)	(31,949)
Other property and equipment, net	$32,444	$35,253

Schedule of Impairment of Evaluated Oil and Gas Properties

	Three Months Ended June 30,
	2020		2019
Impairment of evaluated oil and gas properties (in thousands)	$1,276,518		$—
Beginning of period 12-Month Average Realized Price ($/Bbl)	$54.63		$54.58
End of period 12-Month Average Realized Price ($/Bbl)	$45.87		$53.00
Percent decrease in 12-Month Average Realized Price	(16	%)	(3	%)

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2020

Earnings Per Share [Abstract]

Computation of Basic and Diluted Earnings Per Share

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands, except per share amounts)
Net income (loss)	($1,564,731)	$55,180	($1,348,166)	$35,637
Preferred stock dividends (1)	—	(1,823)	—	(3,647)
Income (loss) available to common stockholders	($1,564,731)	$53,357	($1,348,166)	$31,990
Basic weighted average common shares outstanding	397,084	228,051	396,884	227,917
Dilutive impact of restricted stock	—	360	—	682
Diluted weighted average common shares outstanding	397,084	228,411	396,884	228,599
Income (Loss) Available to Common Stockholders Per Common Share
Basic	($3.94)	$0.23	($3.40)	$0.14
Diluted	($3.94)	$0.23	($3.40)	$0.14
Restricted stock (2)	9,066	641	9,169	498

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

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Borrowings (Tables)

6 Months Ended

Jun. 30, 2020

Debt Disclosure [Abstract]

Schedule of Borrowings

The Company’s borrowings consisted of the following:

	June 30, 2020	December 31, 2019
	(In thousands)
Senior Secured Revolving Credit Facility due 2024	$1,450,000	$1,285,000
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	3,350,000	3,185,000
Unamortized premium on 6.125% Senior Notes	4,781	5,344
Unamortized premium on 6.25% Senior Notes	4,163	4,838
Unamortized premium on 8.25% Senior Notes	4,809	5,286
Unamortized deferred financing costs for Senior Notes	(13,023)	(14,359)
Total carrying value of borrowings (1)	$3,350,730	$3,186,109

(1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $26.0 million and $22.2 million as of June 30, 2020 and December 31, 2019, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets.

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Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Price Risk Derivatives

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)	(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.

Fair Value of Derivative Instruments

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.

Schedule of Offsetting Assets

The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:

	As of June 30, 2020
	Presented without		As Presented with
	Effects of Netting	Effects of Netting	Effects of Netting
ASSETS	(In thousands)
Commodity derivative instruments	$63,380	($31,890)	$31,490
Contingent consideration arrangements	73	—	73
Fair value of derivatives - current	$63,453	($31,890)	$31,563
Commodity derivative instruments	1,404	(952)	452
Contingent consideration arrangements	1,234	—	1,234
Other assets, net	$2,638	($952)	$1,686
LIABILITIES
Commodity derivative instruments	($64,122)	$31,890	($32,232)
Contingent consideration arrangements	(451)	—	(451)
Fair value of derivatives - current	($64,573)	$31,890	($32,683)
Commodity derivative instruments	(6,518)	952	(5,566)
Contingent consideration arrangements	(3,112)	—	(3,112)
Fair value of derivatives - non current	($9,630)	$952	($8,678)

	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)

Schedule of Offsetting Liabilities

The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:

	As of June 30, 2020
	Presented without		As Presented with
	Effects of Netting	Effects of Netting	Effects of Netting
ASSETS	(In thousands)
Commodity derivative instruments	$63,380	($31,890)	$31,490
Contingent consideration arrangements	73	—	73
Fair value of derivatives - current	$63,453	($31,890)	$31,563
Commodity derivative instruments	1,404	(952)	452
Contingent consideration arrangements	1,234	—	1,234
Other assets, net	$2,638	($952)	$1,686
LIABILITIES
Commodity derivative instruments	($64,122)	$31,890	($32,232)
Contingent consideration arrangements	(451)	—	(451)
Fair value of derivatives - current	($64,573)	$31,890	($32,683)
Commodity derivative instruments	(6,518)	952	(5,566)
Contingent consideration arrangements	(3,112)	—	(3,112)
Fair value of derivatives - non current	($9,630)	$952	($8,678)

	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)

Schedule of Gain or Loss on Derivative Contracts

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands)
(Gain) loss on oil derivatives	$122,369	($8,849)	($134,954)	$59,520
(Gain) loss on natural gas derivatives	4,695	(1,874)	11,524	(2,983)
Gain on NGL derivatives	(4)	—	(4)	—
Gain on contingent consideration arrangements	(95)	(3,313)	(1,570)	(3,313)
(Gain) loss on derivative contracts	$126,965	($14,036)	($125,004)	$53,224

Schedule of Derivative Instruments

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 June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands)
Cash flows from operating activities
Cash (paid) received on oil derivatives	$100,470	($4,461)	$98,693	($6,003)
Cash (paid) received on natural gas derivatives	(1,782)	3,304	2,608	4,556
Cash (paid) received for commodity derivative settlements	$98,688	($1,157)	$101,301	($1,447)
Cash flows from investing activities
Cash paid for settlements of contingent consideration arrangements, net	$—	$—	($40,000)	$—

Schedule of Outstanding Oil and Natural Gas Derivative Contracts

Listed in the tables below are the outstanding oil, natural gas and NGL derivative contracts as of June 30, 2020:  

	For the Remainder		For the Full Year
Oil contracts (WTI)	of 2020		of 2021
Swap contracts
Total volume (Bbls)	6,291,880		—
Weighted average price per Bbl	$42.08		$—
Collar contracts
Total volume (Bbls)	2,863,040		—
Weighted average price per Bbl
Ceiling (short call)	$45.00		$—
Floor (long put)	$35.00		$—
Short put contracts
Total volume (Bbls)	1,104,000		—
Weighted average price per Bbl	$42.50		$—
Long call contracts
Total volume (Bbls)	920,000		—
Weighted average price per Bbl	$67.50		$—
Short call contracts
Total volume (Bbls)	920,000	(1)	4,825,300	(1)
Weighted average price per Bbl	$55.00		$63.62
Oil contracts (WTI Calendar Month Average Roll)
Swap contracts
Total volume (Bbls)	3,864,000		—
Weighted average price per Bbl	($2.75)		$—
Oil contracts (Brent ICE)
Swap contracts
Total volume (Bbls)	184,000		1,272,450
Weighted average price per Bbl	$46.15		$38.24
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	4,609,200		4,015,100
Weighted average price per Bbl	($0.98)		$0.40
Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls)	3,256,004		—
Weighted average price per Bbl	$0.06		$—
Oil contracts (Argus Houston MEH swaps)
Swap contracts
Total volume (Bbls)	368,000		2,969,050
Weighted average price per Bbl	$57.71		$39.48

(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)	5,530,000	12,923,000
Weighted average price per MMBtu	$2.21	$2.66
Collar contracts (three-way collars)
Total volume (MMBtu)	2,755,000	1,350,000
Weighted average price per MMBtu
Ceiling (short call)	$2.73	$2.70
Floor (long put)	$2.47	$2.42
Floor (short put)	$2.00	$2.00
Collar contracts (two-way collars)
Total volume (MMBtu)	1,525,000	7,750,000
Weighted average price per MMBtu
Ceiling (short call)	$3.25	$2.93
Floor (long put)	$2.67	$2.55
Short call contracts
Total volume (MMBtu)	6,072,000	7,300,000
Weighted average price per MMBtu	$3.50	$3.09
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	12,885,000	—
Weighted average price per MMBtu	($0.92)	$—

	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

See “Note 15 - Subsequent Events” for additional information regarding derivative contracts entered into subsequent to June 30, 2020.

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

	For the Remainder	For the Full Year
Oil contracts (WTI)	of 2020	of 2021
Swap contracts
Total volume (Bbls)	—	1,377,000
Weighted average price per Bbl	$—	$42.00
Collar contracts
Total volume (Bbls)	—	3,741,250
Weighted average price per Bbl
Ceiling (short call)	$—	$45.02
Floor (long put)	$—	$40.00
Short call swaption contracts
Total volume (Bbls)	—	730,000	(1)
Weighted average price per Bbl	$—	$47.00
Oil contracts (Midland basis differential)
Long swap contracts
Total volume (Bbls)	1,514,500	—
Weighted average price per Bbl	$0.60	$—
Natural gas contracts (Henry Hub)
Swap contracts
Total volume (MMBtu)	3,036,000	—
Weighted average price per MMBtu	$1.80	$—
Long call contracts
Total volume (MMBtu)	3,036,000	—
Weighted average price per MMBtu	$3.50	$—
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	—	6,387,500
Weighted average price per MMBtu	$—	($0.58)

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

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2020

Fair Value Disclosures [Abstract]

Summary of Financial Instruments at Carrying and Fair Value

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.

	June 30, 2020		December 31, 2019
	Principal Amount	Fair Value	Principal Amount	Fair Value
	(In thousands)
6.25% Senior Notes	$650,000	$240,500	$650,000	$658,125
6.125% Senior Notes	600,000	216,000	600,000	611,130
8.25% Senior Notes	250,000	87,500	250,000	256,250
6.375% Senior Notes	400,000	136,000	400,000	405,424
Total	$1,900,000	$680,000	$1,900,000	$1,930,929

Fair Value of Assets and Liabilities Measured on Recurring Basis

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:

	June 30, 2020
	Level 1	Level 2	Level 3
	(In thousands)
Assets
Commodity derivative instruments	$—	$31,942	$—
Contingent consideration arrangements	—	1,307	—
Liabilities
Commodity derivative instruments	—	(37,798)	—
Contingent consideration arrangements	—	(3,563)	—
Total net assets (liabilities)	$—	($8,112)	$—
	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)	$—

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2020

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Income tax expense computed at the 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	(25	%)	—	%	(31	%)	—	%
Other discrete items (1)	—	%	1	%	—	%	2	%
Effective income tax rate, after discrete items	(3	%)	23	%	(9	%)	24	%

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

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Share-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2020

Share-based Payment Arrangement [Abstract]

Schedule of Restricted Stock Unit Activity

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

	Three Months Ended June 30,
	2020		2019
	RSU Equity Awards (in thousands)	Weighted Average Grant Date Fair Value	RSU Equity Awards (in thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	4,851	$6.95	3,406	$11.14
Granted (1)	3,257	$1.26	171	$7.87
Vested (2)	(900)	$10.06	(458)	$12.51
Forfeited	—	$—	(64)	$11.43
Unvested, end of the period	7,208	$3.99	3,055	$10.75

	Six Months Ended June 30,
	2020		2019
	RSU Equity Awards (in thousands)	Weighted Average Grant Date Fair Value	RSU Equity Awards (in thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	2,695	$10.25	2,103	$13.24
Granted (1)	5,575	$2.12	1,881	$8.60
Vested (2)	(1,062)	$10.02	(791)	$12.23
Forfeited	—	$—	(138)	$10.82
Unvested, end of the period	7,208	$3.99	3,055	$10.75

(1)Includes 0.3 million and zero target performance-based RSU Equity Awards during the three months ended June 30, 2020 and 2019, respectively, and 1.1 million and 0.4 million during the six months ended June 30, 2020 and 2019, respectively. The awards granted during the six months ended June 30, 2020 and 2019 will vest at a range of 0% to 300% and 0% to 200%, respectively.

(2)The fair value of shares vested was $0.6 million and $3.4 million during the three months ended June 30, 2020 and 2019, respectively, and $1.3 million and $6.0 million for the six months ended June 30, 2020 and 2019, respectively.

Schedule of Fair Value Inputs

The following table summarizes the assumptions used and the resulting grant date fair value per performance-based RSU Equity Award granted during the six months ended June 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	—	%	—	%	—	%
Grant date fair value per performance-based RSU Equity Award	$1.80		$3.39		$10.78

Schedule of Cash-Settleable Vesting Period 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 six months ended June 30, 2020 and 2019:

	Three Months Ended June 30,
	2020		2019
	Cash-Settled RSU Awards (in thousands)	Weighted Average Grant Date Fair Value	Cash-Settled RSU Awards (in thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	1,707	$7.85	1,044	$11.69
Granted	386	$2.03	25	$8.1
Vested	(2)	$16.66	(17)	$11.06
Did not vest at end of performance period	(11)	$15.27	—	$—
Forfeited	—	$—	(21)	$16.38
Unvested, end of the period	2,080	$6.72	1,031	$11.52

	Six Months Ended June 30,
	2020		2019
	Cash-Settled RSU Awards (in thousands)	Weighted Average Grant Date Fair Value	Cash-Settled RSU Awards (in thousands)	Weighted Average Grant Date Fair Value
Unvested, beginning of the period	855	$12.42	678	$12.36
Granted	1,249	$2.98	424	$10.62
Vested	(12)	$12.85	(17)	$11.06
Did not vest at end of performance period	(12)	$16.66	—	$—
Forfeited	—	$—	(54)	$15.21
Unvested, end of the period	2,080	$6.72	1,031	$11.52

Schedule of Cash-Settleable Restricted Stock Units Awards

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:

	June 30, 2020	December 31, 2019
	(In thousands)
Other current liabilities	$231	$966
Other long-term liabilities	674	2,089
Total Cash-Settled RSU Awards	$905	$3,055

Schedule of Cost by Plan

The following table presents share-based compensation expense (benefit), net for each respective period:

	Three Months Ended June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands)
RSU Equity Awards	$3,212	$2,907	$7,160	$8,383
Cash-Settled RSU Awards	596	203	(1,400)	1,354
Cash SARs	1,115	—	(3,641)	—
	4,923	3,110	$2,119	$9,737
Less: amounts capitalized to oil and gas properties	(2,162)	(1,131)	(2,330)	(2,304)
Total share-based compensation expense (benefit), net	$2,761	$1,979	($211)	$7,433

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Leases (Tables)

6 Months Ended

Jun. 30, 2020

Leases [Abstract]

Lease, Cost

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
	(In thousands)		(In thousands)
Components of Lease Costs
Finance lease costs	$552	$—	$1,128	$—
Amortization of right-of-use assets (1)	510	—	1,020	—
Interest on lease liabilities (2)	42	—	108	—
Operating lease costs (3)	16,387	9,565	33,664	19,156
Impairment of Operating lease ROU assets (4)	1,982	—	3,575	—
Short-term lease costs (5)	38	1,849	1,726	3,347
Variable lease costs (6)	70	—	74	—
Total lease costs	$19,029	$11,414	$40,167	$22,503

(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 June 30, 2020 and 2019, approximately $15.2 million and $7.0 million were costs associated with drilling rigs. For the six months ended June 30, 2020 and 2019, approximately $23.7 million and $13.9 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 six months ended June 30, 2020 of $2.0 million 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.

Assets and Liabilities, Lessee

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

	June 30, 2020	December 31, 2019
	(In thousands)
Leases
Operating leases:
Operating lease ROU assets	$35,926	$63,908
Current operating lease liabilities	$24,355	$42,858
Long-term operating lease liabilities	30,729	37,088
Total operating lease liabilities	$55,084	$79,946
Financing leases:
Other property and equipment	$2,313	$2,197
Accumulated depreciation	(1,257)	(82)
Other property and equipment, net	$1,056	$2,115
Current financing lease liabilities	$463	$1,334
Long-term financing lease liabilities	572	807
Total financing lease liabilities	$1,035	$2,141

Lease Term and Discount Rate, Lessee

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 June 30, 2020
Weighted Average Remaining Lease Term (In years)
Operating leases	5.4
Financing leases	2.8
Weighted Average Discount Rate
Operating leases	5.4	%
Financing leases	7.1	%

Lessee, Operating Lease, Liability, Maturity

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

	Operating Leases	Financing Leases
	(In thousands)
Remainder of 2020	$16,362	$363
2021	14,116	275
2022	5,453	234
2023	5,013	233
2024	4,937	38
Thereafter	18,097	—
Total lease payments	63,978	1,143
Less imputed interest	(8,894)	(108)
Total	$55,084	$1,035

Finance Lease, Liability, Maturity

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

	Operating Leases	Financing Leases
	(In thousands)
Remainder of 2020	$16,362	$363
2021	14,116	275
2022	5,453	234
2023	5,013	233
2024	4,937	38
Thereafter	18,097	—
Total lease payments	63,978	1,143
Less imputed interest	(8,894)	(108)
Total	$55,084	$1,035

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Accounts Receivable, Net (Tables)

6 Months Ended

Jun. 30, 2020

Receivables [Abstract]

Schedule of Accounts Receivable, Net

	June 30, 2020	December 31, 2019
	(In thousands)
Oil and natural gas receivables	$74,555	$165,275
Joint interest receivables	9,664	39,114
Other receivables	13,388	6,610
Total	97,607	210,999
Allowance for doubtful accounts	(1,768)	(1,536)
Total accounts receivable, net	$95,839	$209,463

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Accounts Payable and Accrued Liabilities (Tables)

6 Months Ended

Jun. 30, 2020

Payables and Accruals [Abstract]

Schedule of Accounts Payable and Accrued Liabilities

	June 30, 2020	December 31, 2019
	(In thousands)
Accounts payable	$202,467	$238,758
Revenues payable	109,054	145,816
Accrued capital expenditures	29,926	61,950
Accrued interest	43,441	36,295
Accrued severance (1)	20,708	28,803
Total accounts payable and accrued liabilities	$405,596	$511,622

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

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Supplemental Cash Flow (Tables)

6 Months Ended

Jun. 30, 2020

Supplemental Cash Flow Elements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

	Six Months Ended June 30,
	2020	2019
Supplemental cash flow information:
Interest paid, net of capitalized amounts	$31,649	$—
Income taxes paid	—	—
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$26,110	$1,293
Investing cash flows from operating leases	11,278	17,865
Non-cash investing and financing activities:
Change in accrued capital expenditures	($6,186)	($16,286)
Change in asset retirement costs	207	—
ROU assets obtained in exchange for lease liabilities:
Operating leases	$2,666	$2,462

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Subsequent Events (Tables)

6 Months Ended

Jun. 30, 2020

Subsequent Events [Abstract]

Schedule of Outstanding Oil and Natural Gas Derivative Contracts

Listed in the tables below are the outstanding oil, natural gas and NGL derivative contracts as of June 30, 2020:  

	For the Remainder		For the Full Year
Oil contracts (WTI)	of 2020		of 2021
Swap contracts
Total volume (Bbls)	6,291,880		—
Weighted average price per Bbl	$42.08		$—
Collar contracts
Total volume (Bbls)	2,863,040		—
Weighted average price per Bbl
Ceiling (short call)	$45.00		$—
Floor (long put)	$35.00		$—
Short put contracts
Total volume (Bbls)	1,104,000		—
Weighted average price per Bbl	$42.50		$—
Long call contracts
Total volume (Bbls)	920,000		—
Weighted average price per Bbl	$67.50		$—
Short call contracts
Total volume (Bbls)	920,000	(1)	4,825,300	(1)
Weighted average price per Bbl	$55.00		$63.62
Oil contracts (WTI Calendar Month Average Roll)
Swap contracts
Total volume (Bbls)	3,864,000		—
Weighted average price per Bbl	($2.75)		$—
Oil contracts (Brent ICE)
Swap contracts
Total volume (Bbls)	184,000		1,272,450
Weighted average price per Bbl	$46.15		$38.24
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	4,609,200		4,015,100
Weighted average price per Bbl	($0.98)		$0.40
Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls)	3,256,004		—
Weighted average price per Bbl	$0.06		$—
Oil contracts (Argus Houston MEH swaps)
Swap contracts
Total volume (Bbls)	368,000		2,969,050
Weighted average price per Bbl	$57.71		$39.48

(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)	5,530,000	12,923,000
Weighted average price per MMBtu	$2.21	$2.66
Collar contracts (three-way collars)
Total volume (MMBtu)	2,755,000	1,350,000
Weighted average price per MMBtu
Ceiling (short call)	$2.73	$2.70
Floor (long put)	$2.47	$2.42
Floor (short put)	$2.00	$2.00
Collar contracts (two-way collars)
Total volume (MMBtu)	1,525,000	7,750,000
Weighted average price per MMBtu
Ceiling (short call)	$3.25	$2.93
Floor (long put)	$2.67	$2.55
Short call contracts
Total volume (MMBtu)	6,072,000	7,300,000
Weighted average price per MMBtu	$3.50	$3.09
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	12,885,000	—
Weighted average price per MMBtu	($0.92)	$—

	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

See “Note 15 - Subsequent Events” for additional information regarding derivative contracts entered into subsequent to June 30, 2020.

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

	For the Remainder	For the Full Year
Oil contracts (WTI)	of 2020	of 2021
Swap contracts
Total volume (Bbls)	—	1,377,000
Weighted average price per Bbl	$—	$42.00
Collar contracts
Total volume (Bbls)	—	3,741,250
Weighted average price per Bbl
Ceiling (short call)	$—	$45.02
Floor (long put)	$—	$40.00
Short call swaption contracts
Total volume (Bbls)	—	730,000	(1)
Weighted average price per Bbl	$—	$47.00
Oil contracts (Midland basis differential)
Long swap contracts
Total volume (Bbls)	1,514,500	—
Weighted average price per Bbl	$0.60	$—
Natural gas contracts (Henry Hub)
Swap contracts
Total volume (MMBtu)	3,036,000	—
Weighted average price per MMBtu	$1.80	$—
Long call contracts
Total volume (MMBtu)	3,036,000	—
Weighted average price per MMBtu	$3.50	$—
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	—	6,387,500
Weighted average price per MMBtu	$—	($0.58)

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

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Revenue Recognition (Gathering and Treating Fees) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019	Jun. 30, 2020	Dec. 31, 2019
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Accounts receivable			$ 97,607	$ 210,999
Natural Gas, Gathering and Treating Fees | Natural Gas Revenue
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cost of goods and services sold	$ 2,800	$ 5,200
Oil and natural gas receivables
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Accounts receivable			$ 74,555	$ 165,275

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Revenue Recognition (Performance Obligation) (Details)	6 Months Ended
	Jun. 30, 2020
Revenue from Contract with Customer [Abstract]
Performance obligation, description of timing	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.

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Acquisitions and Divestitures (Narrative - Acquisitions) (Details) $ / shares in Units, $ in Thousands, shares in Millions		3 Months Ended		6 Months Ended			12 Months Ended
	Dec. 20, 2019 USD ($) $ / shares shares	Jun. 30, 2020 USD ($)	Jun. 30, 2019 USD ($)	Jun. 30, 2020 USD ($)	Jun. 30, 2020 USD ($)	Jun. 30, 2019 USD ($)	Dec. 31, 2019 USD ($)
Business Acquisition [Line Items]
Revenues		$ 157,234	$ 167,052	$ 447,153		$ 320,099
Total operating expenses		1,518,910	$ 108,543	1,760,969		$ 218,365
Carrizo Oil & Gas, Inc.
Business Acquisition [Line Items]
Acquisition related costs							$ 15,600
8.875% Preferred Stock | Carrizo Oil & Gas, Inc.
Business Acquisition [Line Items]
Preferred stock cumulative cash dividends rate	8.875%
Carrizo Oil & Gas, Inc.
Business Acquisition [Line Items]
Share conversion ratio	1.75
Equity interest issued, number of shares (in shares) | shares	168.2
Equity interest issued, price per share (in dollars per share) | $ / shares	$ 4.55
Total consideration	$ 765,373
Revenues		86,900		248,300
Total operating expenses		47,700		99,900
Acquisition related costs							$ 58,800
Restructuring charges		8,100		23,900	$ 98,300
Carrizo Oil & Gas, Inc. | Accounts Payable and Accrued Liabilities
Business Acquisition [Line Items]
Restructuring reserve		23,000		23,000	23,000
Carrizo Oil & Gas, Inc. | Employee Severance
Business Acquisition [Line Items]
Restructuring charges		2,400		5,400	34,200
Carrizo Oil & Gas, Inc. | Acquisition & Integration
Business Acquisition [Line Items]
Restructuring charges		$ 5,700		$ 18,500	$ 64,100

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Acquisitions and Divestitures (Assets Acquired and Liabilities Assumed) (Details) - Carrizo Oil & Gas, Inc. $ in Thousands	Dec. 20, 2019 USD ($)
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	88,627
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	2,364,277
Assets:
Accounts receivable, net	48,479
Fair value of derivatives - current	17,451
Other current assets	11,137
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	3,129,650
Evaluated oil and natural gas properties
Assets:
Oil and natural gas properties	2,133,280
Unevaluated oil and natural gas properties
Assets:
Oil and natural gas properties	$ 683,366

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Acquisitions and Divestitures (Unaudited Pro Forma Financial Information) (Details) - Carrizo Oil & Gas, Inc. $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($) $ / shares
Business Acquisition [Line Items]
Revenues	$ 1,620,357
Income from operations	614,668
Income available to common stockholders	$ 369,777
Net income per common share:
Basic (in dollars per share) | $ / shares	$ 0.89
Diluted (in dollars per share) | $ / shares	$ 0.89

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Acquisitions and Divestitures (Narrative - Dispositions) (Details) - Certain Non-core Assets in the Midland Basin	3 Months Ended
	Jun. 30, 2019 USD ($) a
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration	$ 244,900,000
Potential contingency payments	$ 60,000,000.0
Potential contingency payments, period	3 years
Area of land | a	9,850
Working interest	66.00%
Gain (loss) on disposal	$ 0

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Property and Equipment, Net (Schedule of Property and Equipment) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Oil and natural gas properties, full cost accounting method
Evaluated properties	$ 7,840,616	$ 7,203,482
Accumulated depreciation, depletion, amortization and impairments	(4,062,660)	(2,520,488)
Net evaluated oil and natural gas properties	3,777,956	4,682,994
Unevaluated properties
Unevaluated leasehold and seismic costs	1,596,662	1,843,725
Capitalized interest	166,198	142,399
Total unevaluated properties	1,762,860	1,986,124
Total oil and natural gas properties, net	5,540,816	6,669,118
Other property and equipment	67,883	67,202
Accumulated depreciation	(35,439)	(31,949)
Other property and equipment, net	$ 32,444	$ 35,253

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Property and Equipment, Net (Narrative) (Details)	3 Months Ended					6 Months Ended
	Sep. 30, 2020 $ / bbl	Jun. 30, 2020 USD ($) $ / bbl	Mar. 31, 2020 USD ($)	Jun. 30, 2019 USD ($) $ / bbl	Mar. 31, 2019 USD ($)	Jun. 30, 2020 USD ($)	Jun. 30, 2019 USD ($)
Property, Plant and Equipment [Abstract]
Internal costs capitalized		$ 8,900,000		$ 8,400,000		$ 16,400,000	$ 19,100,000
Interest costs capitalized		20,900,000		18,700,000		44,900,000	38,600,000
Amount transferred from unevaluated properties into evaluated properties		43,900,000				224,400,000
Property, Plant and Equipment [Line Items]
Impairment of evaluated oil and gas properties		$ 1,276,518,000	$ 0	$ 0	$ 0	$ 1,276,518,000	$ 0
Beginning of period 12-Month Average Realized Price ($/Bbl) | $ / bbl		54.63		54.58
Forecast
Property, Plant and Equipment [Line Items]
Beginning of period 12-Month Average Realized Price ($/Bbl) | $ / bbl	43.45

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Property and Equipment, Net (Impairment) (Details)	3 Months Ended				6 Months Ended
	Jun. 30, 2020 USD ($) $ / bbl	Mar. 31, 2020 USD ($)	Jun. 30, 2019 USD ($) $ / bbl	Mar. 31, 2019 USD ($)	Jun. 30, 2020 USD ($)	Jun. 30, 2019 USD ($)
Property, Plant and Equipment [Abstract]
Impairment of proved oil and gas properties | $	$ 1,276,518,000	$ 0	$ 0	$ 0	$ 1,276,518,000	$ 0
Beginning of period 12-Month Average Realized Price ($/Bbl)	54.63		54.58
End of period 12-Month Average Realized Price ($/Bbl)	45.87		53.00
Percent decrease in 12-Month Average Realized Price	(16.00%)		(3.00%)

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2020	Mar. 31, 2020	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2020	Jun. 30, 2019	Jul. 18, 2019
Earnings Per Share, Basic and Diluted [Line Items]
Net income (loss)	$ (1,564,731)	$ 216,565	$ 55,180	$ (19,543)	$ (1,348,166)	$ 35,637
Preferred stock dividends	0		(1,823)		0	(3,647)
Income (Loss) Available to Common Stockholders	$ (1,564,731)		$ 53,357		$ (1,348,166)	$ 31,990
Basic weighted average common shares outstanding (in shares)	397,084		228,051		396,884	227,917
Dilutive impact of restricted stock (in shares)	0		360		0	682
Diluted weighted average common shares outstanding (in shares)	397,084		228,411		396,884	228,599
Income (Loss) Available to Common Stockholders Per Common Share
Basic (in dollars per share)	$ (3.94)		$ 0.23		$ (3.40)	$ 0.14
Diluted (in dollars per share)	$ (3.94)		$ 0.23		$ (3.40)	$ 0.14
10% Series A Cumulative Preferred Stock
Income (Loss) Available to Common Stockholders Per Common Share
Debt instrument, interest rate, stated (as a percent)							10.00%
Restricted Stock
Income (Loss) Available to Common Stockholders Per Common Share
Restricted stock (in shares)	9,066		641		9,169	498

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Borrowings (Schedule of Borrowings) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019	Oct. 03, 2016
Principal components:
Total principal outstanding	$ 3,350,000	$ 3,185,000
Premium on senior unsecured notes, net of accumulated amortization	4,781	5,344
Unamortized deferred financing costs for Senior Notes	(13,023)	(14,359)
Total carrying value of borrowings	3,350,730	3,186,109
Deferred financing costs	25,993	22,233
Senior Secured Revolving Credit Facility due 2024
Principal components:
Total principal outstanding	1,450,000	1,285,000
Deferred financing costs	$ 26,000	22,200
6.25% Senior Notes due 2023
Principal components:
Debt instrument, interest rate, stated (as a percent)	6.25%		6.25%
Total principal outstanding	$ 650,000	650,000
Premium on senior unsecured notes, net of accumulated amortization	$ 4,163	4,838
6.125% Senior Notes due 2024
Principal components:
Debt instrument, interest rate, stated (as a percent)	6.125%		6.125%
Total principal outstanding	$ 600,000	600,000
8.25% Senior Notes due 2025
Principal components:
Debt instrument, interest rate, stated (as a percent)	8.25%
Total principal outstanding	$ 250,000	250,000
Premium on senior unsecured notes, net of accumulated amortization	4,809	5,286
6.375% Senior Unsecured Notes due 2026
Principal components:
Total principal outstanding	$ 400,000	$ 400,000
6.375% Senior Unsecured Notes due 2026 | Unsecured debt
Principal components:
Debt instrument, interest rate, stated (as a percent)	6.375%

XML

Borrowings (Credit Facility) (Details) - USD ($)	May 07, 2020	Dec. 31, 2021	Jun. 30, 2020	Dec. 31, 2019	Oct. 03, 2016
Line of Credit Facility [Line Items]
Total principal outstanding			$ 3,350,000,000	$ 3,185,000,000
New Credit Facility
Line of Credit Facility [Line Items]
Credit facility borrowing base	$ 1,700,000,000
Increase limit	$ 1,700,000,000
Total principal outstanding			$ 1,450,000,000
Interest rate at period end (as a percent)			3.01%
Letters of credit outstanding			$ 19,700,000
New Credit Facility | LIBOR
Line of Credit Facility [Line Items]
Debt instrument interest rate (as a percent)	1.00%
New Credit Facility | Federal Funds Rate
Line of Credit Facility [Line Items]
Debt instrument interest rate (as a percent)	0.50%
New Credit Facility | Maximum
Line of Credit Facility [Line Items]
Leverage ratio	300.00%
Unused capacity, commitment fee (as a percent)	0.50%
New Credit Facility | Maximum | Base Rate
Line of Credit Facility [Line Items]
Debt instrument interest rate (as a percent)	2.00%
New Credit Facility | Maximum | Eurodollar
Line of Credit Facility [Line Items]
Debt instrument interest rate (as a percent)	3.00%
New Credit Facility | Minimum
Line of Credit Facility [Line Items]
Leverage ratio	100.00%
Unused capacity, commitment fee (as a percent)	0.375%
New Credit Facility | Minimum | Base Rate
Line of Credit Facility [Line Items]
Debt instrument interest rate (as a percent)	1.00%
New Credit Facility | Minimum | Eurodollar
Line of Credit Facility [Line Items]
Debt instrument interest rate (as a percent)	2.00%
6.25% Senior Notes due 2023
Line of Credit Facility [Line Items]
Total principal outstanding			$ 650,000,000	650,000,000
Debt instrument, interest rate, stated (as a percent)			6.25%		6.25%
6.125% Senior Notes due 2024
Line of Credit Facility [Line Items]
Total principal outstanding			$ 600,000,000	$ 600,000,000
Debt instrument, interest rate, stated (as a percent)			6.125%		6.125%
Second Lien Notes
Line of Credit Facility [Line Items]
Debt instrument aggregate principal amount	$ 400,000,000
First Amendment to the Credit Agreement
Line of Credit Facility [Line Items]
Amount of cash held to lesser	$ 125,000,000.0
Percent of borrowing base	7.50%
Period required for entering into and maintain minimum hedges	12 months
First Amendment to the Credit Agreement | LIBOR
Line of Credit Facility [Line Items]
Increase in applicable margins	0.75%
First Amendment to the Credit Agreement | Base Rate
Line of Credit Facility [Line Items]
Increase in applicable margins	0.75%
First Amendment to the Credit Agreement | Maximum
Line of Credit Facility [Line Items]
Total funded debt to EBITDAX ratio	400.00%
Leverage ratio	100.00%
Leverage ratio for certain investments and cash distributions	250.00%
First Amendment to the Credit Agreement | Maximum | Forecast
Line of Credit Facility [Line Items]
Total funded debt to EBITDAX ratio		300.00%
First Amendment to the Credit Agreement | Minimum
Line of Credit Facility [Line Items]
Net notional volumes, percent of reasonably anticipated production	40.00%
Mortgage and title coverage as percent of total value of proved oil and gas properties	90.00%

XML

Borrowings (Restrictive Covenants) (Details) - New Credit Facility	May 07, 2020
Maximum
Debt Instrument [Line Items]
Leverage ratio	300.00%
Minimum
Debt Instrument [Line Items]
Leverage ratio	100.00%

XML

Derivative Instruments and Hedging Activities (Narrative) (Details) - Acquired Contingent Consideration	Jun. 30, 2020 $ / bbl $ / MMBTU	Jan. 31, 2020 USD ($)
Derivative [Line Items]
Contingent payment received | $		$ 10,000,000.0
Aggregate settlements limit | $		$ 13,000,000.0
Minimum
Derivative [Line Items]
Threshold | $ / bbl	53.00
Weighted average price (in dollars per share) | $ / MMBTU	3.18
Maximum
Derivative [Line Items]
Threshold | $ / bbl	60.00
Weighted average price (in dollars per share) | $ / MMBTU	3.30

XML

Derivative Instruments and Hedging Activities (Contingent Consideration Arrangement) (Details) $ in Thousands	Jun. 30, 2020 USD ($) $ / bbl	Jan. 31, 2020 USD ($)
Actual Settlement 2019
Derivative [Line Items]
Threshold | $ / bbl	65
Remaining Potential Settlements 2020-2021
Derivative [Line Items]
Threshold | $ / bbl	65
Divestiture, Ranger
Derivative [Line Items]
Divestiture Date Fair Value	$ 8,512
Payment to be presented in cash flows	8,500
Remaining potential settlements, receipts in future years	41,700
Divestiture, Ranger | Actual Settlement 2019
Derivative [Line Items]
Contingent Receipt - Annual	0
Contingent Receipt - Annual	0
Divestiture, Ranger | Remaining Potential Settlements 2020-2021
Derivative [Line Items]
Contingent Receipt - Annual	9,000
Contingent Receipt - Annual	20,833
Remaining Contingent Receipt - Aggregate Limit	41,666
Merger, Contingent ExL Consideration
Derivative [Line Items]
Payment to be presented in cash flows	19,200
Acquisition Date Fair Value	$ (69,171)
Contingent payment made		$ 50,000
Remaining potential settlements, payments in future years		$ 25,000
Merger, Contingent ExL Consideration | Actual Settlement 2019
Derivative [Line Items]
Threshold | $ / bbl	50.00
Contingent Payment - Annual	$ (50,000)
Merger, Contingent ExL Consideration | Remaining Potential Settlements 2020-2021
Derivative [Line Items]
Threshold | $ / bbl	50.00
Contingent Payment - Annual	$ (25,000)
Remaining Contingent Payments - Aggregate Limit	$ (25,000)

XML

Derivative Instruments and Hedging Activities (Schedule of Derivative Instruments in Statement of Financial Position, Fair Value) (Details) - Not Designated as Hedging Instrument - USD ($)	Jun. 30, 2020	Dec. 31, 2019
Fair value of derivatives - current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	$ 63,453,000	$ 43,567,000
Effects of Netting	(31,890,000)	(17,511,000)
As Presented with Effects of Netting	31,563,000	26,056,000
Fair value of derivatives - current | Contingent Consideration Arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	73,000	16,718,000
Effects of Netting	0	0
As Presented with Effects of Netting	73,000	16,718,000
Fair value of derivatives - current | Contingent consideration arrangement
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	63,380,000	26,849,000
Effects of Netting	(31,890,000)	(17,511,000)
As Presented with Effects of Netting	31,490,000	9,338,000
Other assets, net
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	2,638,000	9,216,000
Effects of Netting	(952,000)	0
As Presented with Effects of Netting	1,686,000	9,216,000
Other assets, net | Contingent Consideration Arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	1,234,000	9,216,000
Effects of Netting	0	0
As Presented with Effects of Netting	1,234,000	9,216,000
Other assets, net | Contingent consideration arrangement
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	1,404,000	0
Effects of Netting	(952,000)	0
As Presented with Effects of Netting	452,000	0
Fair value of derivatives - current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(64,573,000)	(88,708,000)
Effects of Netting	31,890,000	17,511,000
As Presented with Effects of Netting	(32,683,000)	(71,197,000)
Fair value of derivatives - current | Contingent Consideration Arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(451,000)	(50,000,000)
Effects of Netting	0	0
As Presented with Effects of Netting	(451,000)	(50,000,000)
Fair value of derivatives - current | Contingent consideration arrangement
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(64,122,000)	(38,708,000)
Effects of Netting	31,890,000	17,511,000
As Presented with Effects of Netting	(32,232,000)	(21,197,000)
Fair value of derivatives - non current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(9,630,000)	(32,695,000)
Effects of Netting	952,000	0
As Presented with Effects of Netting	(8,678,000)	(32,695,000)
Fair value of derivatives - non current | Contingent Consideration Arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(3,112,000)	(19,760,000)
Effects of Netting	0	0
As Presented with Effects of Netting	(3,112,000)	(19,760,000)
Fair value of derivatives - non current | Contingent consideration arrangement
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(6,518,000)	(12,935,000)
Effects of Netting	952,000	0
As Presented with Effects of Netting	$ (5,566,000)	$ (12,935,000)

XML

Derivative Instruments and Hedging Activities (Schedule of Gain or Loss on Derivative Contracts) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative contracts	$ (126,965)	$ 14,036	$ 125,004	$ (53,224)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative contracts	126,965	(14,036)	(125,004)	53,224
Not Designated as Hedging Instrument | Gain on contingent consideration arrangements
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative contracts	(95)	(3,313)	(1,570)	(3,313)
Not Designated as Hedging Instrument | Commodity - Oil
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative contracts	122,369	(8,849)	(134,954)	59,520
Not Designated as Hedging Instrument | Commodity - Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative contracts	4,695	(1,874)	11,524	(2,983)
Not Designated as Hedging Instrument | Commodity - Natural gas liquids
Derivative Instruments, Gain (Loss) [Line Items]
(Gain) loss on derivative contracts	$ (4)	$ 0	$ (4)	$ 0

XML

Derivative Instruments and Hedging Activities (Schedule of Cash Paid (Received)) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Cash flows from operating activities
Cash (paid) received for commodity derivative settlements	$ 98,688	$ (1,157)	$ 101,301	$ (1,447)
Not Designated as Hedging Instrument | Gain on contingent consideration arrangements
Cash flows from investing activities
Cash paid for settlements of contingent consideration arrangements, net	0	0	(40,000)	0
Commodity - Oil | Not Designated as Hedging Instrument
Cash flows from operating activities
Cash (paid) received for commodity derivative settlements	100,470	(4,461)	98,693	(6,003)
Commodity - Natural gas | Not Designated as Hedging Instrument
Cash flows from operating activities
Cash (paid) received for commodity derivative settlements	$ (1,782)	$ 3,304	$ 2,608	$ 4,556

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Derivative Instruments and Hedging Activities (Schedule of Outstanding Oil and Natural Gas Derivative Contracts) (Details) - Forecast - Not Designated as Hedging Instrument	3 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2022 bbl	Dec. 31, 2020 MMBTU $ / bbl $ / MMBTU bbl	Dec. 31, 2020 $ / bbl $ / MMBTU bbl	Dec. 31, 2021 MMBTU $ / MMBTU $ / bbl bbl
Commodity - Oil | Call option | Short
Derivative [Line Items]
Total volume (Bbls) | bbl		920,000		4,825,300
Weighted average price (in dollars per share)		55.00	55.00	63.62
Commodity - Oil | Call option | Long
Derivative [Line Items]
Total volume (Bbls) | bbl	0		920,000
Weighted average price (in dollars per share) | $ / bbl		67.50	67.50	0
Commodity - Oil | Put option | Short
Derivative [Line Items]
Total volume (Bbls) | bbl	0		1,104,000
Weighted average price (in dollars per share) | $ / bbl		42.50	42.50	0
Commodity - Oil | Collar Contracts
Derivative [Line Items]
Total volume (Bbls) | bbl	0		2,863,040
Commodity - Oil | Collar Contracts | Call option | Short
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl		45.00	45.00	0
Commodity - Oil | Collar Contracts | Put option | Long
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl		35.00	35.00	0
Commodity - Oil | Swap contracts
Derivative [Line Items]
Total volume (Bbls) | bbl		6,291,880		0
Weighted average price (in dollars per share)		42.08	42.08	0
Commodity - Oil | Swap contracts | Oil contracts (WTI Calendar Month Average Roll)
Derivative [Line Items]
Total volume (Bbls) | bbl		3,864,000		0
Weighted average price (in dollars per share)		(2.75)	(2.75)	0
Commodity - Oil | Swap contracts | Oil contracts (Brent ICE)
Derivative [Line Items]
Total volume (Bbls) | bbl		184,000		1,272,450
Weighted average price (in dollars per share) | $ / bbl		46.15	46.15	38.24
Commodity - Oil | Swap contracts | Oil contracts (Midland basis differential)
Derivative [Line Items]
Total volume (Bbls) | bbl		4,609,200		4,015,100
Weighted average price (in dollars per share) | $ / bbl				0.40
Weighted average price (in dollars per share) | $ / bbl		(0.98)	(0.98)
Commodity - Oil | Swap contracts | Oil contracts (Argus Houston MEH basis differential)
Derivative [Line Items]
Total volume (Bbls) | bbl		3,256,004		0
Weighted average price (in dollars per share)		0.06	0.06	0
Commodity - Oil | Swap contracts | Oil contracts (Argus Houston MEH swaps)
Derivative [Line Items]
Total volume (Bbls) | bbl		368,000		2,969,050
Weighted average price (in dollars per share)		57.71	57.71	39.48
Commodity - Natural gas | Call option | Short
Derivative [Line Items]
Weighted average price (in dollars per share)		3.50	3.50	3.09
Total volume (MMBtu) | MMBTU		6,072,000		7,300,000
Commodity - Natural gas | Collar contracts (three-way collars)
Derivative [Line Items]
Total volume (MMBtu) | MMBTU		2,755,000		1,350,000
Commodity - Natural gas | Collar contracts (three-way collars) | Call option | Short
Derivative [Line Items]
Weighted average price (in dollars per share)		2.73	2.73	2.70
Commodity - Natural gas | Collar contracts (three-way collars) | Put option | Short
Derivative [Line Items]
Weighted average price (in dollars per share)		2.00	2.00	2.00
Commodity - Natural gas | Collar contracts (three-way collars) | Put option | Long
Derivative [Line Items]
Weighted average price (in dollars per share)		2.47	2.47	2.42
Commodity - Natural gas | Collar contracts (two-way collars)
Derivative [Line Items]
Total volume (MMBtu) | MMBTU		1,525,000		7,750,000
Commodity - Natural gas | Collar contracts (two-way collars) | Call option | Short
Derivative [Line Items]
Weighted average price (in dollars per share)		3.25	3.25	2.93
Commodity - Natural gas | Collar contracts (two-way collars) | Put option | Long
Derivative [Line Items]
Weighted average price (in dollars per share)		2.67	2.67	2.55
Commodity - Natural gas | Swap contracts
Derivative [Line Items]
Weighted average price (in dollars per share)		2.21	2.21	2.66
Total volume (MMBtu) | MMBTU		5,530,000		12,923,000
Commodity - Natural gas | Swap contracts | Waha Basis Differential
Derivative [Line Items]
Total volume (MMBtu) | MMBTU		12,885,000		0
Weighted average price (in dollars per share)		(0.92)	(0.92)	0
Commodity - Natural gas liquids | Swap contracts | NGL contracts (OPIS Mont Belvieu Purity Ethane)
Derivative [Line Items]
Total volume (Bbls) | bbl		0		1,825,000
Weighted average price (in dollars per share)		0	0	7.62

XML

Fair Value Measurements (Summary of Financial Instruments at Carrying and Fair Value) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019	Oct. 03, 2016
6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.25%		6.25%
6.125% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%		6.125%
8.25% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	8.25%
Unsecured debt | 6.375% Senior Unsecured Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%
Carrying Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	$ 1,900,000	$ 1,900,000
Carrying Value | Unsecured debt | 6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	650,000	650,000
Carrying Value | Unsecured debt | 6.125% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	600,000	600,000
Carrying Value | Unsecured debt | 8.25% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	250,000	250,000
Carrying Value | Unsecured debt | 6.375% Senior Unsecured Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	400,000	400,000
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	680,000	1,930,929
Fair Value | Unsecured debt | 6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	240,500	658,125
Fair Value | Unsecured debt | 6.125% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	216,000	611,130
Fair Value | Unsecured debt | 8.25% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	87,500	256,250
Fair Value | Unsecured debt | 6.375% Senior Unsecured Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	$ 136,000	$ 405,424

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Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - Recurring Basis - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Level 1
Assets
Derivative financial instruments	$ 0	$ 0
Contingent consideration arrangements	0	0
Liabilities
Derivative financial instruments	0	0
Contingent consideration arrangements	0	0
Net Derivative Fair Value	0	0
Level 2
Assets
Derivative financial instruments	31,942	9,338
Contingent consideration arrangements	1,307	25,934
Liabilities
Derivative financial instruments	(37,798)	(34,132)
Contingent consideration arrangements	(3,563)	(69,760)
Net Derivative Fair Value	(8,112)	(68,620)
Level 3
Assets
Derivative financial instruments	0	0
Contingent consideration arrangements	0	0
Liabilities
Derivative financial instruments	0	0
Contingent consideration arrangements	0	0
Net Derivative Fair Value	$ 0	$ 0

XML

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Income tax expense computed at the statutory federal income tax rate	21.00%	21.00%	21.00%	21.00%
State taxes net of federal expense	1.00%	1.00%	1.00%	1.00%
Section 162(m)	0.00%	0.00%	0.00%	0.00%
Effective income tax rate, before discrete items	22.00%	22.00%	22.00%	22.00%
Valuation allowance	(25.00%)	0.00%	(31.00%)	0.00%
Other discrete items	0.00%	1.00%	0.00%	2.00%
Effective income tax rate, after discrete items	(3.00%)	23.00%	(9.00%)	24.00%
Deferred tax assets, valuation allowance	$ 377.6		$ 377.6

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Share-Based Compensation (Narrative) (Details) - USD ($)	3 Months Ended			6 Months Ended
	Jun. 30, 2020	Mar. 31, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Jun. 08, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized (in shares)						13,250,000
RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
TSR, maximum percent of performance period	5.00%			5.00%
Vested (in shares)	(900,000)		(458,000)	(1,062,000)	(791,000)
Grant date fair value	$ 600,000		$ 3,400,000	$ 1,300,000	$ 6,000,000.0
Unrecognized compensation costs	19,700,000			$ 19,700,000
Period for recognition				2 years 1 month 6 days
RSUs | Vesting Percentage, Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights				0.00%	0.00%
RSUs | Vesting Percentage, Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights				300.00%	200.00%
Performance-based Equity Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested (in shares)				0
Grant date fair value	$ 500,000		$ 0	$ 3,400,000	$ 4,300,000
Performance-based Equity Awards | Vesting Percentage, Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights	0.00%	0.00%
Performance-based Equity Awards | Vesting Percentage, Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights	30000.00%	200.00%
Cash-Settled RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested (in shares)	(2,000)		(17,000)	(12,000)	(17,000)
Unrecognized compensation costs	$ 2,200,000			$ 2,200,000
Period for recognition				2 years 3 months 18 days
Award vesting period				3 years
2020 Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of common stock available for grant (in shares)	15,937,327			15,937,327

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Share-Based Compensation (RSU Equity Awards (Details) - RSUs - USD ($) $ / shares in Units, $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2020	Mar. 31, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
RSU Equity Awards
Unvested, beginning of the period (in shares)	4,851,000	2,695,000	3,406,000	2,695,000	2,103,000
Granted (in shares)	3,257,000		171,000	5,575,000	1,881,000
Vested (in shares)	(900,000)		(458,000)	(1,062,000)	(791,000)
Forfeited (in shares)	0		(64,000)	0	(138,000)
Unvested, end of the period (in shares)	7,208,000	4,851,000	3,055,000	7,208,000	3,055,000
Weighted Average Grant Date Fair Value
Unvested, beginning of the period (in dollars per share)	$ 6.95	$ 10.25	$ 11.14	$ 10.25	$ 13.24
Granted (in dollars per share)	1.26		7.87	2.12	8.60
Vested (in dollars per share)	10.06		12.51	10.02	12.23
Forfeited (in dollars per share)	0		11.43	0	10.82
Unvested, end of the period (in dollars per share)	$ 3.99	$ 6.95	$ 10.75	$ 3.99	$ 10.75
Grant date fair value	$ 0.6		$ 3.4	$ 1.3	$ 6.0
Vesting Percentage Range of 0 and 300
RSU Equity Awards
Granted (in shares)	300,000			1,100,000
Vesting Percentage Range of 0 and 200
RSU Equity Awards
Granted (in shares)			0		400,000
Vesting Percentage, Minimum
Weighted Average Grant Date Fair Value
Award vesting rights				0.00%	0.00%
Vesting Percentage, Maximum
Weighted Average Grant Date Fair Value
Award vesting rights				300.00%	200.00%

XML

Share-Based Compensation (Fair Value Inputs) (Details) - Performance-Based Cash-Settled RSUs - $ / shares	1 Months Ended
	Jun. 29, 2020	Jan. 31, 2020	Jan. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term (in years)	2 years 6 months	2 years 10 months 24 days	2 years 10 months 24 days
Expected volatility	113.20%	54.80%	47.90%
Risk-free interest rate	0.20%	1.30%	2.40%
Dividend yield	0.00%	0.00%	0.00%
Grant date fair value per performance-based RSU Equity Award	$ 1.80	$ 3.39	$ 10.78

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Share-Based Compensation (Cash-Settled RSU Awards) (Details) - Cash-Settled RSUs - $ / shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
RSU Equity Awards (in thousands)
Unvested, beginning of the period (in shares)	1,707	1,044	855	678
Granted (in shares)	386	25	1,249	424
Vested (in shares)	(2)	(17)	(12)	(17)
Did not vest at end of performance period (in shares)	(11)	0	(12)	0
Forfeited (in shares)	0	(21)	0	(54)
Unvested, end of the period (in shares)	2,080	1,031	2,080	1,031
Weighted Average Grant Date Fair Value
Unvested, beginning of the period (in dollars per share)	$ 7.85	$ 11.69	$ 12.42	$ 12.36
Granted (in dollars per share)	2.03	8.1	2.98	10.62
Vested (in dollars per share)	16.66	11.06	12.85	11.06
Did not vest at end of performance period (in dollars per share)	15.27	0	16.66	0
Forfeited (in dollars per share)	0	16.38	0	15.21
Unvested, end of the period (in dollars per share)	$ 6.72	$ 11.52	$ 6.72	$ 11.52

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Share-Based Compensation (Summary of Liability for Cash-Settled RSU Awards) (Details) - Cash-Settled RSUs - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Other current liabilities	$ 231	$ 966
Other long-term liabilities	674	2,089
Total Cash-Settled RSU Awards	$ 905	$ 3,055

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Share-Based Compensation (Schedule of Share-based Compensation Expense) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-based compensation expense (benefit), net	$ 4,923	$ 3,110	$ 2,119	$ 9,737
Less: amounts capitalized to oil and gas properties	(2,162)	(1,131)	(2,330)	(2,304)
Total share-based compensation expense (benefit), net	2,761	1,979	(211)	7,433
RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-based compensation expense (benefit), net	3,212	2,907	7,160	8,383
Cash-Settled RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-based compensation expense (benefit), net	596	203	(1,400)	1,354
Cash SARs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-based compensation expense (benefit), net	$ 1,115	$ 0	$ (3,641)	$ 0

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Leases (Cost) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
ROU assets obtained in exchange for lease liabilities:
Finance lease costs	$ 552	$ 0	$ 1,128	$ 0
Amortization of right-of-use assets	510	0	1,020	0
Interest on lease liabilities	42	0	108	0
Operating lease costs	16,387	9,565	33,664	19,156
Impairment of Operating lease ROU assets	1,982	0	3,575	0
Short-term lease cost	38	1,849	1,726	3,347
Variable lease costs	70	0	74	0
Total lease costs	19,029	11,414	40,167	22,503
Capitalized exploratory well costs	15,200	$ 7,000	23,700	$ 13,900
Carrizo Oil & Gas, Inc.
ROU assets obtained in exchange for lease liabilities:
Impairment of Operating lease ROU assets	$ 2,000		$ 3,600

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Leases (Assets and Liabilities) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Operating leases:
Operating lease right-of-use assets	$ 35,926	$ 63,908
Operating lease liabilities	24,355	42,858
Operating lease liabilities	30,729	37,088
Total operating lease liabilities	55,084	79,946
Financing leases:
Other property and equipment	2,313	2,197
Accumulated depreciation	(1,257)	(82)
Other property and equipment, net	1,056	2,115
Current financing lease liabilities	463	1,334
Long-term financing lease liabilities	572	807
Total financing lease liabilities	$ 1,035	$ 2,141

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Leases (Lease Term and Discount Rate) (Details)	Jun. 30, 2020
Weighted Average Remaining Lease Term (In years)
Operating leases	5 years 4 months 24 days
Financing leases	2 years 9 months 18 days
Weighted Average Discount Rate
Operating leases	5.40%
Financing leases	7.10%

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Leases (Maturities) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
Remainder of 2020	$ 16,362
2021	14,116
2022	5,453
2023	5,013
2024	4,937
Thereafter	18,097
Total lease payments	63,978
Less imputed interest	(8,894)
Total operating lease liabilities	55,084	$ 79,946
Finance Lease, Liability, Payment, Due [Abstract]
Remainder of 2020	363
2021	275
2022	234
2023	233
2024	38
Thereafter	0
Total lease payments	1,143
Less imputed interest	(108)
Total financing lease liabilities	$ 1,035	$ 2,141

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Accounts Receivable, Net (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total	$ 97,607	$ 210,999
Allowance for doubtful accounts	(1,768)	(1,536)
Total accounts receivable, net	95,839	209,463
Joint interest receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total	9,664	39,114
Other receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total	13,388	6,610
Oil and natural gas receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total	$ 74,555	$ 165,275

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Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Payables and Accruals [Abstract]
Accounts payable	$ 202,467	$ 238,758
Revenues payable	109,054	145,816
Accrued capital expenditures	29,926	61,950
Accrued interest	43,441	36,295
Accrued severance	20,708	28,803
Total accounts payable and accrued liabilities	$ 405,596	$ 511,622

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Supplemental Cash Flow (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019
Supplemental cash flow information:
Interest paid, net of capitalized amounts	$ 31,649	$ 0
Income taxes paid	0	0
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	26,110	1,293
Investing cash flows from operating leases	11,278	17,865
Non-cash investing and financing activities:
Change in accrued capital expenditures	(6,186)	(16,286)
Change in asset retirement costs	207	0
ROU assets obtained in exchange for lease liabilities:
Operating leases	$ 2,666	$ 2,462

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Subsequent Events (Hedging) (Details) - Forecast - Not Designated as Hedging Instrument	3 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2022 bbl	Dec. 31, 2020 MMBTU $ / MMBTU $ / bbl bbl	Dec. 31, 2020 $ / MMBTU $ / bbl bbl	Dec. 31, 2021 MMBTU $ / MMBTU $ / bbl bbl
Commodity - Oil | Short | Call option
Subsequent Event [Line Items]
Total volume (Bbls) | bbl		920,000		4,825,300
Weighted average price (in dollars per share) | $ / MMBTU		55.00	55.00	63.62
Commodity - Oil | Short | Put option
Subsequent Event [Line Items]
Total volume (Bbls) | bbl	0		1,104,000
Weighted average price (in dollars per share) | $ / bbl		42.50	42.50	0
Commodity - Oil | Long | Call option
Subsequent Event [Line Items]
Total volume (Bbls) | bbl	0		920,000
Weighted average price (in dollars per share) | $ / bbl		67.50	67.50	0
Commodity - Oil | Swap contracts
Subsequent Event [Line Items]
Total volume (Bbls) | bbl		6,291,880		0
Weighted average price (in dollars per share) | $ / MMBTU		42.08	42.08	0
Commodity - Oil | Oil contracts (WTI) | Swap contracts
Subsequent Event [Line Items]
Total volume (Bbls) | bbl		0		1,377,000
Weighted average price (in dollars per share) | $ / bbl		0	0	42.00
Commodity - Oil | Collar contracts
Subsequent Event [Line Items]
Total volume (Bbls) | bbl	3,741,250		0
Commodity - Oil | Collar contracts | Short | Call option
Subsequent Event [Line Items]
Weighted average price (in dollars per share) | $ / bbl		0	0	45.02
Commodity - Oil | Collar contracts | Long | Put option
Subsequent Event [Line Items]
Weighted average price (in dollars per share) | $ / bbl		0	0	40.00
Commodity - Oil | Short call swaption contracts | Swap contracts
Subsequent Event [Line Items]
Total volume (Bbls) | bbl		0		730,000
Weighted average price (in dollars per share) | $ / MMBTU		0	0	47.00
Commodity - Oil | Midland basis differential | Swap contracts
Subsequent Event [Line Items]
Total volume (Bbls) | bbl		1,514,500		0
Weighted average price (in dollars per share) | $ / bbl		0.60	0.60	0
Commodity - Natural gas | Short | Call option
Subsequent Event [Line Items]
Weighted average price (in dollars per share) | $ / MMBTU		3.50	3.50	3.09
Total volume (MMBtu) | MMBTU		6,072,000		7,300,000
Commodity - Natural gas | Swap contracts
Subsequent Event [Line Items]
Weighted average price (in dollars per share) | $ / MMBTU		2.21	2.21	2.66
Total volume (MMBtu) | MMBTU		5,530,000		12,923,000
Commodity - Natural gas | Natural gas contracts (Henry Hub)
Subsequent Event [Line Items]
Weighted average price (in dollars per share) | $ / MMBTU		3.50	3.50	0
Total volume (MMBtu) | MMBTU		3,036,000		0
Commodity - Natural gas | Natural gas contracts (Henry Hub) | Swap contracts
Subsequent Event [Line Items]
Weighted average price (in dollars per share) | $ / MMBTU		1.80	1.80	0
Total volume (MMBtu) | MMBTU		3,036,000		0
Commodity - Natural gas | Waha basis differential | Swap contracts
Subsequent Event [Line Items]
Total volume (MMBtu) | MMBTU		0		6,387,500
Weighted average price (in dollars per share) | $ / MMBTU		0	0	(0.58)

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Subsequent Events (Reverse Stock Split) (Details)	Aug. 04, 2020 shares	Jul. 31, 2020 shares	Jun. 30, 2020 shares	Dec. 31, 2019 shares
Subsequent Event [Line Items]
Common stock, shares outstanding (in shares)			397,396,922	396,600,022
Common stock, shares authorized (in shares)			525,000,000	525,000,000
Subsequent Event
Subsequent Event [Line Items]
Stock split, conversion ratio	0.1
Common stock, shares outstanding (in shares)	39,747,667	397,476,674
Common stock, shares authorized (in shares)	52,500,000	525,000,000