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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
(Mark One)
    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For The Quarterly Period Ended March 31, 2021
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)

Delaware64-0844345
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,Texas77042
Address of Principal Executive OfficesZip 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 ClassTrading Symbol(s)Name of Each Exchange on Which Registered
Common Stock, $0.01 par valueCPENew 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 filerAccelerated filer
Non-accelerated filerSmaller reporting company
Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  No

The Registrant had 46,264,870 shares of common stock outstanding as of April 30, 2021.



Table of Contents

Part I. Financial Information
Item 1. Financial Statements (Unaudited)
Part II. Other Information

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, butane and natural gasoline that are extracted from natural gas production streams.
NYMEX:  New York Mercantile Exchange.
Oil: includes crude oil and condensate.
OPEC: Organization of Petroleum Exporting Countries.
Proved reserves: Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.
The area of the reservoir considered as proved includes all of the following:
a.The area identified by drilling and limited by fluid contacts, if any, and
b.Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:
a.Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and
b.The project has been approved for development by all necessary parties and entities, including governmental entities.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
3




Realized price: the cash market price less all expected quality, transportation and demand adjustments.
RSU: restricted stock units.
SEC:  United States Securities and Exchange Commission.
Waha: a delivery point in West Texas that serves as the benchmark for natural gas.
Working interest: an operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
WTI: West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.
With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 
4


Part I.  Financial Information
Item 1.  Financial Statements

Callon Petroleum Company
Consolidated Balance Sheets
(In thousands, except par and share amounts)
(Unaudited)
 March 31, 2021December 31, 2020
ASSETS 
Current assets:  
Cash and cash equivalents$24,350 $20,236 
Accounts receivable, net179,127 133,109 
Other current assets32,878 25,024 
Total current assets236,355 178,369 
Oil and natural gas properties, full cost accounting method:  
  Evaluated properties, net2,394,339 2,355,710 
Unevaluated properties1,754,768 1,733,250 
Total oil and natural gas properties, net4,149,107 4,088,960 
Other property and equipment, net31,435 31,640 
Deferred financing costs22,177 23,643 
Other assets, net37,792 40,256 
Total assets$4,476,866 $4,362,868 
LIABILITIES AND STOCKHOLDERS’ EQUITY  
Current liabilities:  
Accounts payable and accrued liabilities$374,749 $341,519 
Fair value of derivatives224,446 97,060 
Other current liabilities72,854 58,529 
Total current liabilities672,049 497,108 
Long-term debt2,937,239 2,969,264 
Asset retirement obligations55,935 57,209 
Fair value of derivatives1,400 88,046 
Other long-term liabilities42,221 40,239 
Total liabilities3,708,844 3,651,866 
Commitments and contingencies
Stockholders’ equity:  
Common stock, $0.01 par value, 52,500,000 shares authorized; 46,156,854 and 39,758,817 shares outstanding, respectively
462 398 
Capital in excess of par value3,360,322 3,222,959 
Accumulated deficit(2,592,762)(2,512,355)
Total stockholders’ equity768,022 711,002 
Total liabilities and stockholders’ equity$4,476,866 $4,362,868 



The accompanying notes are an integral part of these consolidated financial statements.
5



Callon Petroleum Company
Consolidated Statements of Operations
(In thousands, except per share amounts)
(Unaudited)
 Three Months Ended March 31,
 20212020
Operating Revenues:  
Oil$267,045 $265,767 
Natural gas24,220 6,029 
Natural gas liquids29,357 18,123 
Sales of purchased oil and gas39,259  
Total operating revenues359,881 289,919 
Operating Expenses:  
Lease operating40,453 52,383 
Production and ad valorem taxes18,439 19,680 
Gathering, transportation and processing17,981 14,378 
Cost of purchased oil and gas40,917  
Depreciation, depletion and amortization70,987 131,463 
General and administrative16,799 8,325 
Merger and integration 15,830 
Other operating929  
Total operating expenses206,505 242,059 
Income From Operations153,376 47,860 
Other (Income) Expenses:  
Interest expense, net of capitalized amounts24,416 20,478 
(Gain) loss on derivative contracts214,523 (251,969)
Other (income) expense(4,235)(1,262)
Total other (income) expense234,704 (232,753)
Income (Loss) Before Income Taxes(81,328)280,613 
Income tax benefit (expense)921 (64,048)
Net Income (Loss)($80,407)$216,565 
Net Income (Loss) Per Common Share (1):
  
Basic($1.89)$5.46 
Diluted($1.89)$5.46 
Weighted Average Common Shares Outstanding (1):
 
Basic42,590 39,667 
Diluted42,590 39,684 

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

The accompanying notes are an integral part of these consolidated financial statements.
6



Callon Petroleum Company
Consolidated Statements of Stockholders’ Equity
(In thousands)
(Unaudited)
CommonCapital inTotal
StockExcessAccumulatedStockholders’
Shares$of ParDeficitEquity
Balance at December 31, 202039,759 $398 $3,222,959 ($2,512,355)$711,002 
Net loss— — — (80,407)(80,407)
Restricted stock13 — 2,609 — 2,609 
Warrant exercises6,385 64 134,754 — 134,818 
Balance at March 31, 202146,157 $462 $3,360,322 ($2,592,762)$768,022 

CommonCapital inTotal
StockExcessRetainedStockholders’
Shares (1)
$of ParEarningsEquity
Balance at December 31, 201939,659 $3,966 $3,198,076 $21,266 $3,223,308 
Net income— — — 216,565 216,565 
   Restricted stock14 1 3,141 — 3,142 
   Other— — (112)— (112)
Balance at March 31, 202039,673 $3,967 $3,201,105 $237,831 $3,442,903 

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

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

7



Callon Petroleum Company
Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)
 Three Months Ended March 31,
Cash flows from operating activities:20212020
Net income (loss)($80,407)$216,565 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:  
Depreciation, depletion and amortization70,987 131,463 
Amortization of non-cash debt related items, net2,256 407 
Deferred income tax expense 64,048 
(Gain) loss on derivative contracts214,523 (251,969)
Cash received (paid) for commodity derivative settlements, net(42,162)2,613 
Non-cash expense (benefit) related to share-based awards7,608 (2,972)
Other, net1,217 136 
Changes in current assets and liabilities:
Accounts receivable(45,683)115,873 
Other current assets(2,856)(781)
Accounts payable and accrued liabilities12,182 (83,688)
Net cash provided by operating activities137,665 191,695 
Cash flows from investing activities:  
Capital expenditures(101,341)(213,459)
Acquisition of oil and gas properties(768)(10,989)
Proceeds from sale of assets 10,240 
Cash paid for settlements of contingent consideration arrangements, net (40,000)
Other, net3,595 (158)
Net cash used in investing activities(98,514)(254,366)
Cash flows from financing activities:  
Borrowings on Credit Facility303,000 4,291,000 
Payments on Credit Facility(338,000)(4,226,000)
Other, net(37)(870)
Net cash provided by (used in) financing activities(35,037)64,130 
Net change in cash and cash equivalents4,114 1,459 
Balance, beginning of period20,236 13,341 
Balance, end of period$24,350 $14,800 


The accompanying notes are an integral part of these consolidated financial statements.
8


Index to the Notes to the Consolidated Financial Statements
8.
2.
9.Share-based Compensation
3.Property and Equipment, Net10.Stockholders’ Equity
4.11.
Accounts Receivable, Net
5.12.Accounts Payable and Accrued Liabilities
6.13.Supplemental Cash Flow
7.14.Subsequent Events

Note 1 - Description of Business and Basis of Presentation
Description of Business
Callon Petroleum Company is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.
The Company’s activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford. The Company’s primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable cash flow generating business in the Eagle Ford.
Basis of Presentation
The accompanying unaudited interim consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and have been prepared pursuant to the rules and regulations of the SEC and therefore do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP. In the opinion of management, these financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim financial position, results of operations and cash flows. However, the results of operations for the periods presented are not necessarily indicative of the results of operations that may be expected for the full year. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications did not have a material impact on prior period financial statements.
Significant Accounting Policies
The Company’s significant accounting policies are described in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2020 (“2020 Annual Report”) and are supplemented by the notes included in this Quarterly Report on Form 10-Q. The financial statements and related notes included in this report should be read in conjunction with the Company’s 2020 Annual Report.
Recently Adopted Accounting Standards
Income Taxes. In December 2019, the FASB released ASU No. 2019-12 (“ASU 2019-12”), Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes, which removes certain exceptions for recognizing deferred taxes for investments, performing intraperiod allocation and calculating income taxes in interim periods. The ASU also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The amended standard is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company adopted ASU 2019-12 on January 1, 2021. The adoption of ASU 2019-12 did not have a material impact to the Company’s consolidated financial statements or disclosures.
Recently Issued Accounting Pronouncements
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. As of March 31, 2021, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to “Note 5 – Borrowings” for discussion of the use of the adjusted LIBO rate in connection with borrowings under the Company’s senior secured revolving credit facility.
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In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06”). ASU 2020-06 was issued to reduce the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The guidance is to be applied using either a modified retrospective or a fully retrospective method. ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. As of March 31, 2021, the Company has not elected to early adopt and is evaluating the impact on the Company’s accompanying consolidated financial statements and related disclosures.
Subsequent Events
The Company evaluates subsequent events through the date the financial statements are issued. See “Note 14 - Subsequent Events” for further discussion.
Note 2 - Revenue Recognition
Revenue from contracts with customers
Oil sales
Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received. The Company has certain oil sales that occur at market locations downstream of the production area. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees and other deductions incurred prior to control transfer as “Gathering, transportation and processing” in its consolidated statements of operations.
Natural gas and NGL sales
Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity which gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of NGLs and residue gas. The Company evaluates whether the processing entity is the principal or the agent in the transaction for each of the Company’s natural gas processing agreements and have concluded that the Company maintains control through processing or the Company has the right to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. The Company recognizes revenue when control transfers to the purchaser at the delivery point based on the contractual index price received.
The Company recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and processing” in its consolidated statements of operations as the Company maintains control throughout processing.
Oil and gas purchase and sale arrangements
Sales of purchased oil and gas represent revenues the Company receives from sales of commodities purchased from a third-party. The Company recognizes these revenues and the purchase of the third-party commodities, as well as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer.
Accounts receivable from revenues from contracts with customers
Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at March 31, 2021 and December 31, 2020 of $125.6 million and $100.3 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets.
Transaction price allocated to remaining performance obligations
For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Prior period performance obligations
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.
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Note 3 - Property and Equipment, Net
As of March 31, 2021 and December 31, 2020, total property and equipment, net consisted of the following:
March 31, 2021December 31, 2020
Oil and natural gas properties, full cost accounting method(In thousands)
Evaluated properties$8,001,847 $7,894,513 
Accumulated depreciation, depletion, amortization and impairments(5,607,508)(5,538,803)
Evaluated properties, net2,394,339 2,355,710 
Unevaluated properties
Unevaluated leasehold and seismic costs1,530,897 1,532,304 
Capitalized interest223,871 200,946 
Total unevaluated properties1,754,768 1,733,250 
Total oil and natural gas properties, net$4,149,107 $4,088,960 
Other property and equipment$60,388 $60,287 
Accumulated depreciation(28,953)(28,647)
Other property and equipment, net$31,435 $31,640 
The Company capitalized internal costs of employee compensation and benefits, including share-based compensation, directly associated with acquisition, exploration and development activities totaling $11.2 million and $7.5 million for the three months ended March 31, 2021 and 2020, respectively. The Company capitalized interest costs to unproved properties totaling $24.0 million for both the three months ended March 31, 2021 and 2020.
Impairment of Evaluated Oil and Gas Properties
For the three months ended March 31, 2021, the capitalized costs of oil and gas properties did not exceed the cost center ceiling. As a result, the Company did not recognize an impairment in the carrying value of evaluated oil and gas properties for the three months ended March 31, 2021. The Company also did not recognize an impairment of evaluated oil and gas properties for the three months ended March 31, 2020.
Details of the average realized prices for sales of oil on the first calendar day of each month during the trailing 12-month period (“12-Month Average Realized Price”) of crude oil for the three months ended March 31, 2021 and 2020 are summarized in the table below:
Three Months Ended March 31,
20212020
Impairment of evaluated oil and gas properties (in thousands)$$
Beginning of period 12-Month Average Realized Price ($/Bbl)$37.44$53.90
End of period 12-Month Average Realized Price ($/Bbl)$37.51$54.63
Percent increase in 12-Month Average Realized Price %1 %
The Company does not expect to record an impairment in the carrying value of evaluated oil and gas properties in the second quarter of 2021 based on an estimated 12-Month Average Realized Price of crude oil of approximately $49.35 per Bbl as of June 30, 2021, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 10 months and an estimate for the eleventh and twelfth months based on a quoted forward price. Declines in the 12-Month Average Realized Price of crude oil in subsequent quarters could result in a lower present value of the estimated future net revenues from proved oil and gas reserves and may result in impairments of evaluated oil and gas properties.
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Note 4 - Earnings Per Share
Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted shares and unexercised warrants outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. For the three months ended March 31, 2021, the Company reported a net loss. As a result, the calculation of diluted weighted average common shares outstanding excluded all potentially dilutive common shares outstanding.
The following table sets forth the computation of basic and diluted earnings per share:
Three Months Ended March 31,
 20212020
(In thousands, except per share amounts)
Net Income (Loss)($80,407)$216,565 
Basic weighted average common shares outstanding (1)
42,590 39,667 
Dilutive impact of restricted stock (1)
 17 
Dilutive impact of warrants (1)
  
Diluted weighted average common shares outstanding (1)
42,590 39,684 
  
Net Income (Loss) Per Common Share (1)
Basic($1.89)$5.46 
Diluted($1.89)$5.46 
  
Restricted stock (1)(2)
702 337 
Warrants (1)(2)
5,826 481 

(1)    Shares and per share data have been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 10 - Stockholders’ Equity” for additional information.
(2)    Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.
Note 5 - Borrowings
The Company’s borrowings consisted of the following:
March 31, 2021December 31, 2020
(In thousands)
Senior Secured Revolving Credit Facility due 2024$950,000 $985,000 
9.00% Second Lien Senior Secured Notes due 2025
516,659 516,659 
6.25% Senior Notes due 2023
542,720 542,720 
6.125% Senior Notes due 2024
460,241 460,241 
8.25% Senior Notes due 2025
187,238 187,238 
6.375% Senior Notes due 2026
320,783 320,783 
Total principal outstanding2,977,641 3,012,641 
Unamortized discount on Second Lien Notes(39,006)(41,820)
Unamortized premium on 6.25% Senior Notes
2,688 2,917 
Unamortized premium on 6.125% Senior Notes
3,020 3,236 
Unamortized premium on 8.25% Senior Notes
3,050 3,240 
Unamortized deferred financing costs for Second Lien Notes(3,662)(3,931)
Unamortized deferred financing costs for Senior Notes(6,492)(7,019)
Total carrying value of borrowings (1)
$2,937,239 $2,969,264 

(1)    Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $22.2 million and $23.6 million as of March 31, 2021 and December 31, 2020, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets.
Senior secured revolving credit facility
The Company has a senior secured revolving credit facility with a syndicate of lenders (the “Credit Facility”) that, as of March 31, 2021, had a borrowing base and elected commitment amount of $1.6 billion, with borrowings outstanding of $950.0 million at a
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weighted-average interest rate of 2.62%, and letters of credit outstanding of $24.0 million. The credit agreement governing the Credit Facility provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”) are outstanding at such time, (ii) July 2, 2024 if the 6.125% Senior Notes due 2024 (the “6.125% Senior Notes”) are outstanding at such time, and (iii) if the 9.00% Second Lien Senior Secured Notes due 2025 (the “Second Lien Notes”) are outstanding at such time, the date which is 182 days prior to the maturity of any of the 6.25% Senior Notes or the 6.125% Senior Notes, in each case, to the extent a principal amount of more than $100.0 million with respect to each such issuance is outstanding as of such date), when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. The capitalized terms which are not defined in this description of the Credit Facility shall have the meaning given to such terms in the credit agreement.
On May 3, 2021, the Company entered into the fourth amendment to its credit agreement governing the Credit Facility which, among other things, reaffirmed the borrowing base and elected commitment amount of $1.6 billion as a result of the spring 2021 scheduled redetermination. See “Note 14 - Subsequent Events” for further discussion.
Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 1.00% to 2.00%, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00%, or (ii) an adjusted LIBO rate for a Eurodollar loan plus a margin between 2.00% to 3.00%. The Company also incurs commitment fees at rates ranging between 0.375% to 0.500% on the unused portion of lender commitments, which are included in “Interest expense, net of capitalized amounts” in the consolidated statements of operations.
Restrictive covenants
The Company’s credit agreement contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios.
Under the credit agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter: (1) a Secured Leverage Ratio of no more than 3.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. The Company was in compliance with these covenants at March 31, 2021.
The credit agreement and the indentures governing the Company’s 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes due 2025, and 6.375% Senior Notes due 2026 (together the “Senior Unsecured Notes”) also place restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
The credit agreement and indentures are subject to customary events of default. If an event of default occurs and is continuing, the holders or lenders may elect to accelerate amounts due (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).
Note 6 - Derivative Instruments and Hedging Activities
Objectives and strategies for using derivative instruments
The Company is exposed to fluctuations in oil, natural gas and NGL prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil, natural gas and NGL production. The Company utilizes a mix of collars, swaps, and put and call options to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.
Counterparty risk and offsetting
The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.
As of March 31, 2021, the Company has outstanding commodity derivative instruments with fifteen counterparties to minimize its credit exposure to any individual counterparty. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s credit agreement. Therefore, each of the Company’s counterparties allow the Company to satisfy any
13


need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting.
Because each of the Company’s counterparties has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each counterparty.
While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument. See “Note 7 - Fair Value Measurements” for further discussion.
Financial statement presentation and settlements
Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “Note 7 - Fair Value Measurements” for additional information regarding fair value.
Contingent consideration arrangements
Ranger Divestiture. In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Divestiture”). The Company’s Ranger Divestiture provided for potential contingent consideration to be received by the Company if commodity prices exceed specified thresholds. See “Note 7 - Fair Value Measurements” for further discussion. This contingent consideration arrangement is summarized in the table below (in thousands except for per Bbl amounts):
Year
Threshold (1)
Contingent Receipt - Annual
Threshold (1)
Contingent Receipt - AnnualPeriod Cash Flow OccursStatement of Cash Flows PresentationRemaining Contingent Receipt - Aggregate Limit
Remaining Potential Settlement2021
Greater than $60/Bbl, less than $65/Bbl
$9,000
Equal to or greater than $65/Bbl
$20,833
(2)
(2)
$20,833 

(1)    The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group.
(2)    Cash received for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the divestiture date fair value with any excess classified as cash flows from operating activities. If either of the commodity price thresholds is reached in 2021, $8.5 million of the contingent receipt will be presented in cash flows from financing activities with the remainder presented in cash flows from operating activities.
As a result of the acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”) in late 2019 (the “Carrizo Acquisition”), the Company assumed all contingent consideration arrangements previously entered into by Carrizo. Only one of the contingent consideration arrangements remain and is summarized below:
Contingent ExL Consideration
Year
Threshold (1)
Period
Cash Flow
Occurs
Statement of
Cash Flows Presentation
Contingent
Payment -
Annual
Remaining Contingent
Payments -
Aggregate Limit
(In thousands)
Remaining Potential Settlement2021$50.00 
(2)
(2)
($25,000)($25,000)

(1)    The price used to determine whether the specified threshold for the year has been met is the average daily settlement price of the front month NYMEX WTI futures contract as published by the CME Group.
(2)    Cash paid for settlements of contingent consideration arrangements are classified as cash flows from investing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. If the commodity price threshold is reached in 2021, $19.2 million of the contingent payment will be presented in cash flows from investing activities with the remainder presented in cash flows from operating activities.
Warrants
On September 30, 2020, the Company issued $300.0 million in aggregate principal amount of its Second Lien Notes and warrants for 7.3 million shares of the Company’s common stock exercisable only on a net share settlement basis (the “September 2020 Warrants”).
14


The Company determined that the September 2020 Warrants are required to be accounted for as a derivative instrument. The Company recorded the September 2020 Warrants as a liability on its consolidated balance sheet measured at fair value as a component of “Fair value of derivatives” with gains and losses as a result of changes in the fair value of the September 2020 Warrants recorded as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 7 - Fair Value Measurements” for additional details.
In February 2021, holders of the September 2020 Warrants provided notice and exercised all of their outstanding warrants. As a result of this exercise, the Company issued 5.6 million shares of its common stock in exchange for all of the outstanding September 2020 Warrants. The exercise of the September 2020 Warrants resulted in settlement of the associated derivative liability, which was $134.8 million at the time of exercise, and the fair value of the September 2020 Warrants at exercise, less the par value of the shares of common stock issued in the exercise, was reclassified to “Capital in excess of par value” in the consolidated balance sheets.
Derivatives not designated as hedging instruments
The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value as “(Gain) loss on derivative contracts” in the consolidated statements of operations. Settlements are also recorded as a gain or loss on derivative contracts in the consolidated statements of operations. As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheets. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:
As of March 31, 2021
Presented without As Presented with
Effects of NettingEffects of NettingEffects of Netting
(In thousands)
Assets
Commodity derivative instruments$69,473 ($69,352)$121 
Contingent consideration arrangements5,375  5,375 
Other current assets$74,848 ($69,352)$5,496 
Commodity derivative instruments3,790 (3,351)439 
Contingent consideration arrangements   
Other assets, net$3,790 ($3,351)$439 
Liabilities   
Commodity derivative instruments (1)
($275,885)$69,352 ($206,533)
Contingent consideration arrangements(17,913) (17,913)
Fair value of derivatives - current($293,798)$69,352 ($224,446)
Commodity derivative instruments (2)
(4,751)3,351 (1,400)
Contingent consideration arrangements   
Fair value of derivatives - non-current($4,751)$3,351 ($1,400)

(1)    Includes approximately $14.1 million of deferred premiums, which the Company will pay as the applicable contracts settle.
(2)    Includes approximately $0.9 million of deferred premiums, which the Company will pay as the applicable contracts settle.
15



As of December 31, 2020
Presented without As Presented with
Effects of NettingEffects of NettingEffects of Netting
(In thousands)
Assets
Commodity derivative instruments$21,156 ($20,235)$921 
Contingent consideration arrangements   
Other current assets$21,156 ($20,235)$921 
Commodity derivative instruments$ $ $ 
Contingent consideration arrangements1,816  1,816 
Other assets, net$1,816 $ $1,816 
Liabilities   
Commodity derivative instruments (1)
($117,295)$20,235 ($97,060)
Contingent consideration arrangements   
Fair value of derivatives - current($117,295)$20,235 ($97,060)
Commodity derivative instruments$ $ $ 
Contingent consideration arrangements(8,618) (8,618)
September 2020 Warrants liability(79,428) (79,428)
Fair value of derivatives - non-current($88,046)$ ($88,046)

(1)    Includes approximately $11.2 million of deferred premiums, which the Company will pay as the applicable contracts settle.
The components of “(Gain) loss on derivative contracts” are as follows for the respective periods:
Three Months Ended March 31,
20212020
(In thousands)
(Gain) loss on oil derivatives$149,561 ($257,323)
(Gain) loss on natural gas derivatives2,697 6,829 
(Gain) loss on NGL derivatives1,138  
(Gain) loss on contingent consideration arrangements5,737 (1,475)
(Gain) loss on September 2020 Warrants liability55,390  
(Gain) loss on derivative contracts$214,523 ($251,969)
The components of “Cash received (paid) for commodity derivative settlements, net” and “Cash paid for settlements of contingent consideration arrangements, net” are as follows for the respective periods:
Three Months Ended March 31,
20212020
(In thousands)
Cash flows from operating activities  
Cash received (paid) on oil derivatives($39,947)($1,777)
Cash received (paid) on natural gas derivatives(1,369)4,390 
Cash received (paid) on NGL derivatives(846) 
Cash received (paid) for commodity derivative settlements, net($42,162)$2,613 
Cash flows from investing activities  
Cash paid for settlements of contingent consideration arrangements, net$ ($40,000)
16



Derivative positions
Listed in the tables below are the outstanding oil, natural gas and NGL derivative contracts as of March 31, 2021:  
For the RemainderFor the Full Year
Oil contracts (WTI)of 2021of 2022
   Swap contracts
   Total volume (Bbls)1,832,000  
   Weighted average price per Bbl$43.24 $ 
   Collar contracts
   Total volume (Bbls)8,298,800 1,807,500 
   Weighted average price per Bbl
   Ceiling (short call)$48.30 $60.63 
   Floor (long put)$40.24 $46.25 
   Short call contracts
   Total volume (Bbls)2,432,480 
(1)
 
   Weighted average price per Bbl$63.62 $ 
Short call swaption contracts
   Total volume (Bbls) 1,825,000 
(2)
   Weighted average price per Bbl$ $52.18 
Oil contracts (Brent ICE)  
   Swap contracts
   Total volume (Bbls)221,300 
(3)
 
   Weighted average price per Bbl$37.35 $ 
Collar contracts
Total volume (Bbls)550,000  
Weighted average price per Bbl
Ceiling (short call)$50.00 $ 
Floor (long put)$45.00 $ 
Oil contracts (Midland basis differential)
   Swap contracts
   Total volume (Bbls)2,171,900  
   Weighted average price per Bbl$0.24 $ 
Oil contracts (Argus Houston MEH)
   Collar contracts
   Total volume (Bbls)409,500 452,500 
   Weighted average price per Bbl
Ceiling (short call)$47.00 $63.15 
Floor (long put)$41.00 $51.25 

(1)    Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.
(2)    The short call swaption contracts have an exercise expiration date of December 31, 2021.
(3)    In February 2021, the Company entered into certain offsetting ICE Brent swaps to reduce its exposure to rising oil prices. Those offsetting swaps resulted in a locked-in loss of approximately $2.9 million, of which $1.6 million will be settled in the third quarter of 2021 with the remaining $1.3 million to be settled in the fourth quarter of 2021.
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For the RemainderFor the Full Year
Natural gas contracts (Henry Hub)of 2021of 2022
   Swap contracts
      Total volume (MMBtu)11,123,000  
      Weighted average price per MMBtu$2.60 $ 
Collar contracts
      Total volume (MMBtu)5,500,000 1,800,000 
      Weighted average price per MMBtu
         Ceiling (short call)$2.80 $3.88 
         Floor (long put)$2.50 $2.78 
   Short call contracts
      Total volume (MMBtu)5,500,000 
(1)
 
      Weighted average price per MMBtu$3.09 $ 
Natural gas contracts (Waha basis differential)
   Swap contracts
      Total volume (MMBtu)12,375,000  
      Weighted average price per MMBtu($0.42)$ 

(1)    Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.
For the RemainderFor the Full Year
NGL contracts (OPIS Mont Belvieu Purity Ethane)of 2021of 2022
   Swap contracts
      Total volume (Bbls)1,375,000  
      Weighted average price per Bbl$7.62 $ 

Note 7 - Fair Value Measurements
Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.
Level 2 – Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3 – Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.
Fair value of financial instruments
Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.
Debt. The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s Second Lien Notes and Senior Unsecured Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “Note 5 - Borrowings” for further discussion.
March 31, 2021December 31, 2020
Principal AmountFair ValuePrincipal AmountFair Value
(In thousands)
Second Lien Notes$516,659 $524,409 $516,659 $470,160 
6.25% Senior Notes
542,720 483,021 542,720 344,627 
6.125% Senior Notes
460,241 388,904 460,241 260,036 
8.25% Senior Notes
187,238 161,961 187,238 100,172 
6.375% Senior Notes
320,783 252,617 320,783 161,995 
Total$2,027,641 $1,810,912 $2,027,641 $1,336,990 
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Assets and liabilities measured at fair value on a recurring basis
Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheets. The following methods and assumptions were used to estimate fair value:
Commodity derivative instruments. The fair value of commodity derivative instruments is derived using a third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note 6 - Derivative Instruments and Hedging Activities” for further discussion.
Contingent consideration arrangements - embedded derivative financial instruments. The embedded options within the contingent consideration arrangements are considered financial instruments under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded options on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates undiscounted payouts, and risk adjusts for the discount rates inclusive of adjustments for each of the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered Level 2 inputs within the fair value hierarchy. See “Note 6 - Derivative Instruments and Hedging Activities” for further discussion.
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2021 and December 31, 2020:
March 31, 2021
Level 1Level 2Level 3
(In thousands)
Assets   
Commodity derivative instruments$ $560 $ 
Contingent consideration arrangements 5,375  
Liabilities   
Commodity derivative instruments (1)
 (207,933) 
Contingent consideration arrangements (17,913) 
Total net assets (liabilities)$ ($219,911)$ 
   
December 31, 2020
Level 1Level 2Level 3
(In thousands)
Assets   
Commodity derivative instruments$ $921 $ 
Contingent consideration arrangements 1,816  
Liabilities   
Commodity derivative instruments (2)
 (97,060) 
Contingent consideration arrangements (8,618) 
September 2020 Warrants