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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 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)
5
6
7
8
9
31
44
46
Part II. Other Information
47
47
47
47
47
47
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      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      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      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      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)    
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.
9.
2.
10. Share-based Compensation
3. 11.
4. Property and Equipment, Net 12.
Accounts Receivable, Net
5. 13. Accounts Payable and Accrued Liabilities
6. 14. Supplemental Cash Flow
7. 15. Subsequent Events
8.

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.
12


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.
13


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
21


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 % % % %
Section 162(m) —  % —  % —  % —  %
Effective income tax rate, before discrete items 22  % 22  % 22  % 22  %
Valuation allowance (25  %) —  % (31  %) —  %
Other discrete items (1)
—  % % —  % %
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.
29


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      —    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
37


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
44


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
45


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.
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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 10-Q 3.1 11/03/2016
3.2 8-K 3.1 11/20/2019
3.3 10-K 3.2 2/27/2019
10.1 10-Q 10.1 5/11/2020
10.2 (c) DEF 14A B 4/28/2020
10.3 (a)(c)
10.4 (a)(c)
31.1 (a)
31.2 (a)
32.1 (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

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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 of Taxes. 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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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 service as 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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Exhibit 31.1


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)



Exhibit 31.2

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)



Exhibit 32.1

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.