UNITED STATES
SECURITIES ANDEXCHANGE COMMISSION
Washington, D.C. 20549


FORM 10-Q

(Mark One)
☒Quarterly Report Pursuant to SectionQUARTERLY REPORT PURSUANT TO SECTION 13 orOR 15(d) of the Securities Exchange Act ofOF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period EndedSeptember 30, 20172020
ORor
☐Transition Report Pursuant to SectionTRANSITION REPORT PURSUANT TO SECTION 13 orOR 15(d) of the Securities Exchange Act ofOF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission File Number 001-14039


Callon Petroleum Company
Callon Petroleum Company
(Exact Name of Registrant as Specified in Its Charter)
໿

Delaware64-0844345
State or Other Jurisdiction of
Incorporation or Organization		I.R.S. Employer Identification No.
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
One Briarlake Plaza
64-0844345
(IRS Employer
Identification No.)
2000 W. Sam Houston Parkway S., Suite 2000
200 North Canal Street
Natchez, Mississippi
(Houston,
Texas77042
Address of Principal Executive Offices)Offices
39120
(Zip Code)
Code
601-442-1601
(Registrant’s Telephone Number, Including Area Code)
(281)589-5200
Registrant’s Telephone Number, Including Area Code
Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report


Not ApplicableSecurities registered pursuant to Section 12(b) of the Act:
(Former Name, Former Address and Former Fiscal Year, If Changed Since Last Report)
Title of Each ClassTrading Symbol(s)Name of Each Exchange on Which Registered
Common Stock, $0.01 par valueCPENew York Stock Exchange


Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐


Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post 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 (check one):
Act:
Large accelerated filer☒Accelerated filer☐Non-accelerated filer☐(Do not check if smaller reporting company)
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 201,836,17239,752,672 shares of common stock outstanding as of November 1, 2017.October 29, 2020.




Table of Contents


Part I. Financial Information
Part I. Financial Information
Item 1. Financial Statements (Unaudited)
Consolidated Balance Sheets 
45
Consolidated Statements of Operations
56
Consolidated Statements of Cash FlowsStockholders’ Equity
67
Consolidated Statements of Cash Flows
8
Notes to Consolidated Financial Statements
79
1934
3047
3149
Part II. Other Information
3250
3250
3250
3250
3250
3250
3351


DEFINITIONS
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:


ARO:  asset retirement obligation.
•ASU: accounting standards update.
•Bbl or Bbls:  barrel or barrels of oil or natural gas liquids.
BOE•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 NGLNGLs 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.
BBtu•Boe/d:  billion Btu.
BOE/d:  BOEBoe 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.
Cushing•Completion: Anthe 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: Aa natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.
LIBOR•Horizontal drilling: London Interbank Offered Rate.
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•MBoe:  thousand BOE.
Boe.
MMBOE: million 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: Thethe 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 I.1.  Financial Statements

Callon Petroleum Company
Consolidated Balance Sheets
(inIn thousands, except par and per share values andamounts)
(Unaudited)
 September 30, 2020December 31, 2019
ASSETS 
Current assets:  
Cash and cash equivalents$10,500 $13,341 
Accounts receivable, net112,536 209,463 
Fair value of derivatives9,821 26,056 
Other current assets27,049 19,814 
Total current assets159,906 268,674 
Oil and natural gas properties, full cost accounting method:  
Evaluated properties2,916,542 4,682,994 
Unevaluated properties1,758,132 1,986,124 
Total oil and natural gas properties, net4,674,674 6,669,118 
Operating lease right-of-use assets29,519 63,908 
Other property and equipment, net32,920 35,253 
Deferred tax asset0 115,720 
Deferred financing costs24,850 22,233 
Other assets, net15,472 19,932 
   Total assets$4,937,341 $7,194,838 
LIABILITIES AND STOCKHOLDERS’ EQUITY  
Current liabilities:  
Accounts payable and accrued liabilities$332,979 $490,442 
Operating lease liabilities19,458 42,858 
Fair value of derivatives34,950 71,197 
Other current liabilities30,013 47,750 
Total current liabilities417,400 652,247 
Long-term debt3,190,273 3,186,109 
Operating lease liabilities28,906 37,088 
Asset retirement obligations49,542 48,860 
Fair value of derivatives35,705 32,695 
Other long-term liabilities11,411 14,531 
Total liabilities3,733,237 3,971,530 
Commitments and contingencies
Stockholders’ equity:  
Common stock, $0.01 par value, 52,500,000 shares authorized; 39,749,985 and 39,659,001 shares outstanding, respectively (1)
397 3,966 
Capital in excess of par value3,210,991 3,198,076 
Retained earnings (Accumulated deficit)(2,007,284)21,266 
Total stockholders’ equity1,204,104 3,223,308 
Total liabilities and stockholders’ equity$4,937,341 $7,194,838 

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

 September 30, 2017 December 31, 2016
ASSETSUnaudited  
Current assets:   
Cash and cash equivalents$61,609
 $652,993
Accounts receivable81,973
 69,783
Fair value of derivatives3,333
 103
Other current assets2,583
 2,247
Total current assets149,498
 725,126
Oil and natural gas properties, full cost accounting method:   
Evaluated properties3,283,985
 2,754,353
Less accumulated depreciation, depletion, amortization and impairment(2,026,809) (1,947,673)
Net evaluated oil and natural gas properties1,257,176
 806,680
Unevaluated properties1,173,614
 668,721
Total oil and natural gas properties2,430,790
 1,475,401
Other property and equipment, net18,626
 14,114
Restricted investments3,362
 3,332
Deferred financing costs5,209
 3,092
Fair value of derivatives1,121
 —
Acquisition deposit—
 46,138
Prepaid4,650
 —
Other assets, net827
 384
Total assets$2,614,083
 $2,267,587
LIABILITIES AND STOCKHOLDERS’ EQUITY   
Current liabilities:   
Accounts payable and accrued liabilities$147,338
 $95,577
Accrued interest18,375
 6,057
Cash-settleable restricted stock unit awards4,158
 8,919
Asset retirement obligations1,841
 2,729
Fair value of derivatives6,380
 18,268
Total current liabilities178,092
 131,550
Senior secured revolving credit facility—
 —
6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs595,115
 390,219
Asset retirement obligations3,163
 3,932
Cash-settleable restricted stock unit awards2,626
 8,071
Deferred tax liability1,158
 90
Fair value of derivatives659
 28
Other long-term liabilities405
 295
Total liabilities781,218
 534,185
Commitments and contingencies
 
Stockholders’ equity:   
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized; 1,458,948 shares outstanding15
 15
Common stock, $0.01 par value, 300,000,000 shares authorized; 201,827,995 and 201,041,320 shares outstanding, respectively2,018
 2,010
Capital in excess of par value2,179,258
 2,171,514
Accumulated deficit(348,426) (440,137)
Total stockholders’ equity1,832,865
 1,733,402
Total liabilities and stockholders’ equity$2,614,083
 $2,267,587


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

5


Callon Petroleum Company
Consolidated Statements of Operations
(Unaudited; inIn thousands, except per share data)amounts)

(Unaudited)
 Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
Operating revenues:  
Oil$231,654 $148,210 $627,934 $450,036 
Natural gas15,034 7,168 33,305 25,441 
Natural gas liquids23,025 0 55,627 0 
Sales of purchased oil and gas20,313 0 21,469 0 
Total operating revenues290,026 155,378 738,335 475,477 
Operating Expenses:    
Lease operating45,870 19,668 149,091 66,511 
Production and ad valorem taxes16,110 11,866 46,151 33,810 
Gathering, transportation and processing22,200 0 56,615 0 
Cost of purchased oil and gas21,282 0 22,450 0 
Depreciation, depletion and amortization114,201 56,130 384,594 179,275 
General and administrative8,224 9,388 26,573 34,729 
Impairment of evaluated oil and gas properties684,956 0 1,961,474 0 
Merger and integration2,465 5,943 26,362 5,943 
Other operating4,425 (161)8,548 931 
Total operating expenses919,733 102,834 2,681,858 321,199 
Income (Loss) From Operations(629,707)52,544 (1,943,523)154,278 
Other (Income) Expenses:    
Interest expense, net of capitalized amounts24,683 739 67,843 2,218 
(Gain) loss on derivative contracts27,038 (21,809)(97,966)31,415 
Other (income) expense(1,044)(122)(149)(270)
Total other (income) expense50,677 (21,192)(30,272)33,363 
Income (Loss) Before Income Taxes(680,384)73,736 (1,913,251)120,915 
Income tax expense0 (17,902)(115,299)(29,444)
Net Income (Loss)(680,384)55,834 (2,028,550)91,471 
Preferred stock dividends0 (350)0 (3,997)
Loss on redemption of preferred stock0 (8,304)0 (8,304)
Income (Loss) Available to Common Stockholders($680,384)$47,180 ($2,028,550)$79,170 
Income (Loss) Available to Common Stockholders Per Common Share (1):
    
Basic($17.12)$2.07 ($51.09)$3.47 
Diluted($17.12)$2.07 ($51.09)$3.47 
Weighted Average Common Shares Outstanding (1):
   
Basic39,746 22,831 39,707 22,805 
Diluted39,746 22,846 39,707 22,841 
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Operating revenues:       
Oil sales$73,349
 $49,095
 $218,242
 $117,093
Natural gas sales11,265
 6,832
 30,019
 14,677
Total operating revenues84,614
 55,927
 248,261
 131,770
Operating expenses:       
Lease operating expenses11,624
 9,961
 36,708
 24,229
Production taxes5,444
 3,478
 16,168
 8,153
Depreciation, depletion and amortization28,525
 17,303
 79,172
 49,318
General and administrative7,259
 7,891
 18,894
 19,755
Settled share-based awards—
 —
 6,351
 —
Accretion expense131
 187
 523
 762
Write-down of oil and natural gas properties—
 —
 —
 95,788
Acquisition expense205
 456
 3,027
 2,410
Total operating expenses53,188
 39,276
 160,843
 200,415
Income (loss) from operations31,426
 16,651
 87,418
 (68,645)
Other (income) expenses:       
Interest expense, net of capitalized amounts444
 831
 1,698
 10,502
(Gain) loss on derivative contracts14,162
 (5,135) (11,636) 11,281
Other income(498) (122) (1,270) (299)
Total other (income) expense14,108
 (4,426) (11,208) 21,484
Income (loss) before income taxes17,318
 21,077
 98,626
 (90,129)
Income tax (benefit) expense237
 (62) 1,026
 (62)
Net income (loss)17,081
 21,139
 97,600
 (90,067)
Preferred stock dividends(1,824) (1,824) (5,471) (5,471)
Income (loss) available to common stockholders$15,257
 $19,315
 $92,129
 $(95,538)
Income (loss) per common share:       
Basic$0.08
 $0.14
 $0.46
 $(0.85)
Diluted$0.08
 $0.14
 $0.46
 $(0.85)
Shares used in computing income (loss) per common share:      
Basic201,827
 136,983
 201,422
 112,925
Diluted202,337
 137,483
 201,995
 112,925


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

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

6



Callon Petroleum Company
Consolidated Statements of Cash FlowsStockholders’ Equity
(Unaudited; in thousands)In thousands, except per share amounts)
໿(Unaudited)
Retained
PreferredCommonCapital inEarningsTotal
StockStockExcess(AccumulatedStockholders’
Shares$
Shares (1)
$of ParDeficit)Equity
Balance at 12/31/20190 $0 39,659 $3,966 $3,198,076 $21,266 $3,223,308 
Net income— — — — — 216,565 216,565 
   Restricted stock— — 14 1 3,141 — 3,142 
   Other— — — — (112)— (112)
Balance at 3/31/20200 $0 39,673 $3,967 $3,201,105 $237,831 $3,442,903 
Net loss— — — — — (1,564,731)(1,564,731)
   Restricted stock— — 66 7 3,205 — 3,212 
Balance at 6/30/20200 $0 39,739 $3,974 $3,204,310 ($1,326,900)$1,881,384 
Net loss— — — — — (680,384)(680,384)
   Restricted stock— — 11 1 3,008 — 3,009 
   Reverse stock split— — — (3,578)3,578 — 0 
Other— — — — 95 — 95 
Balance at 9/30/20200 $0 39,750 $397 $3,210,991 $(2,007,284)$1,204,104 
 Nine Months Ended September 30,
 2017 2016
Cash flows from operating activities:   
Net income (loss)$97,600
 $(90,067)
Adjustments to reconcile net income (loss) to cash provided by operating activities:   
Depreciation, depletion and amortization80,829
 50,560
Write-down of oil and natural gas properties—
 95,788
Accretion expense523
 762
Amortization of non-cash debt related items1,695
 2,371
Deferred income tax (benefit) expense1,026
 (62)
Net (gain) loss on derivatives, net of settlements(15,608) 27,105
Loss on sale of other property and equipment62
 —
Non-cash expense related to equity share-based awards7,014
 1,954
Change in the fair value of liability share-based awards2,423
 6,045
Payments to settle asset retirement obligations(1,831) (895)
Changes in current assets and liabilities:   
Accounts receivable(12,148) (16,444)
Other current assets(336) (251)
Current liabilities7,534
 19,815
Change in other long-term liabilities121
 86
Change in long-term prepaid(4,650) —
Change in other assets, net(1,376) (1,671)
Payments to settle vested liability share-based awards(13,173) (10,300)
Net cash provided by operating activities149,705
 84,796
Cash flows from investing activities:   
Capital expenditures(267,218) (122,698)
Acquisitions(714,504) (302,057)
Acquisition deposit46,138
 (32,700)
Proceeds from sales of mineral interests and equipment—
 22,923
Net cash used in investing activities(935,584) (434,532)
Cash flows from financing activities:   
Borrowings on senior secured revolving credit facility—
 217,000
Payments on senior secured revolving credit facility—
 (257,000)
Issuance of 6.125% senior unsecured notes due 2024200,000
 —
Premium on the issuance of 6.125% senior unsecured notes due 20248,250
 —
Issuance of common stock—
 722,715
Payment of preferred stock dividends(5,471) (5,471)
Payment of deferred financing costs(7,166) (640)
Tax withholdings related to restricted stock units(1,118) (2,207)
Net cash provided by financing activities194,495
 674,397
Net change in cash and cash equivalents(591,384) 324,661
Balance, beginning of period652,993
 1,224
Balance, end of period$61,609
 $325,885


PreferredCommonCapital inTotal
StockStockExcessAccumulatedStockholders’
Shares$
Shares (1)
$of ParDeficitEquity
Balance at 12/31/20181,459 $15 22,757 $2,276 $2,477,278 ($34,361)$2,445,208 
Net loss— — — — — (19,543)(19,543)
   Shares issued pursuant to employee
benefit plans		— — 2 — 154 — 154 
   Restricted stock— — 28 3 4,447 — 4,450 
   Preferred stock dividend— — — — — (1,824)(1,824)
Balance at 3/31/20191,459 $15 22,787 $2,279 $2,481,879 ($55,728)$2,428,445 
Net income— — — — — 55,180 55,180 
   Restricted stock— — 38 4 2,071 — 2,075 
   Preferred stock dividend— — — — — (1,823)(1,823)
Preferred stock redemption costs— — — — (5)— (5)
Balance at 6/30/20191,459 $15 22,825 $2,283 $2,483,945 ($2,371)$2,483,872 
Net income— — — — — 55,834 55,834 
   Restricted stock— — 11 1 2,307 — 2,308 
   Preferred stock dividend— — — — — (350)(350)
Preferred stock redemption(1,459)(15)— — (64,693)— (64,708)
Loss on redemption of preferred stock— — — — — (8,304)(8,304)
Balance at 9/30/20190 $0 22,836 $2,284 $2,421,559 $44,809 $2,468,652 

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

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

7
Callon Petroleum Company
Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per share and per unit data)
Table of Contents

Callon Petroleum Company
INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTSConsolidated Statements of Cash Flows
(In thousands)
(Unaudited)
 Nine Months Ended September 30,
Cash flows from operating activities:20202019
Net income (loss)($2,028,550)$91,471 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:  
Depreciation, depletion and amortization384,594 182,738 
Impairment of evaluated oil and gas properties1,961,474 0 
Amortization of non-cash debt related items1,582 2,218 
Deferred income tax expense115,299 29,444 
(Gain) loss on derivative contracts(97,966)31,415 
Cash (paid) received for commodity derivative settlements101,754 (436)
Loss on sale of other property and equipment0 36 
Non-cash expense related to equity share-based awards6,302 7,868 
Change in the fair value of liability share-based awards(6,607)106 
Payments to settle asset retirement obligations0 (1,425)
Payments for cash-settled restricted stock unit awards(770)(1,425)
Other, net6,510 0 
Changes in current assets and liabilities:
Accounts receivable96,110 17,600 
Other current assets(6,556)(5,172)
Current liabilities(107,979)(13,038)
Other0 (2,662)
Net cash provided by operating activities425,197 338,738 
Cash flows from investing activities:  
Capital expenditures(567,746)(503,425)
Acquisitions0 (40,788)
Proceeds from sale of assets149,818 279,952 
Cash paid for settlements of contingent consideration arrangements, net(40,000)0 
Other, net8,261 0 
Net cash used in investing activities(449,667)(264,261)
Cash flows from financing activities:  
Borrowings on senior secured revolving credit facility5,087,500 581,000 
Payments on senior secured revolving credit facility(5,347,500)(581,000)
Issuance of 9.00% Second Lien Senior Secured Notes due 2025300,000 0 
Discount on the issuance of 9.00% Second Lien Senior Secured Notes due 2025(35,270)0 
Issuance of warrants23,909 0 
Payment of preferred stock dividends0 (3,997)
Payment of deferred financing costs(6,312)(31)
Tax withholdings related to restricted stock units(495)(2,174)
Redemption of preferred stock0 (73,017)
Other, net(203)0 
Net cash provided by (used in) financing activities21,629 (79,219)
Net change in cash and cash equivalents(2,841)(4,742)
Balance, beginning of period13,341 16,051 
Balance, end of period$10,500 $11,309 


The accompanying notes are an integral part of these consolidated financial statements.
8
1.
Description of Business and Basis of Presentation
6.
Fair Value Measurements
2.
Acquisitions
7.
Income Taxes
3.
Earnings Per Share
8.
Asset Retirement Obligations
4.
Borrowings
9.
Equity Transactions
5.
Derivative Instruments and Hedging Activities
10.
Other


Index to the Notes to the Consolidated Financial Statements
1.
9.
2.
10.Share-based Compensation
3.11.Stockholders’ Equity
4.Property and Equipment, Net12.
5.13.Accounts Receivable, Net
6.14.Accounts Payable and Accrued Liabilities
7.15.Supplemental Cash Flow
8.16.Subsequent Events

Note 1 - Description of Business and Basis of Presentation

Description of business

Callon Petroleum Company is an independent oil and natural gas company establishedfocused on the acquisition, exploration and development of high-quality assets in 1950. The Company was incorporated under the lawsleading oil plays of the state of Delaware in 1994South and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company.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.

Callon isThe 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 development, exploration and exploitation of unconventional onshore, oil and natural gas reservesCarrizo Oil & Gas, Inc. (“Carrizo”) in late 2019. The Company’s primary operations in the Permian Basin. The Company’s operations to date have been predominantly focused on theBasin reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development of several prospective intervals including multiple levels ofand are complemented by a well-established and repeatable cash flow generating business in the Wolfcamp formation and the Lower Spraberry shales. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventory through delineation drilling of emerging zones on its existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. 

Eagle Ford Shale.
Basis of presentation

Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in thousands, except for per share and per unit data.

The accompanying unaudited interim consolidated financial statements of the Company have been prepared in accordance with (1) GAAP, (2) the SEC’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and include the accounts of Callon Petroleumthe Company after elimination of intercompany transactions and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore Production, Inc.balances and Mississippi Marketing, Inc.

These interim consolidatedhave been prepared pursuant to the rules and regulations of the SEC and therefore do not include all disclosures required for financial statements shouldprepared 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 readexpected 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 conjunction withDecember 2019.
Significant Accounting Policies
The Company’s significant accounting policies are described in “Note 2. Summary of Significant Accounting Policies” of the Company’sNotes to Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2016.2019 (“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 16 - Subsequent Events” for further discussion.
Note 2 - Revenue Recognition
Revenue from contracts with customers
Oil sales
Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received.
Natural gas sales
Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow the Company to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.
Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity which gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of NGLs and residue gas. We evaluate whether the processing entity is the principal or the agent in the transaction for each of our natural gas processing agreements and have concluded that we maintain control through processing or we have the right to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. We recognize revenue when control transfers to the purchaser at the delivery point based on the contractual index price received.
Contractual fees associated with gathering, processing, treating and compression, as well as any transportation fees incurred to deliver the product to the purchaser, for the majority of the Company’s natural gas processing agreements were previously recorded as a reduction of revenue. As a result of the modifications to certain of the Company’s natural gas processing agreements, as well as the natural gas processing agreements assumed in the Carrizo Acquisition, the Company now recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and processing” in its consolidated statements of operations as the Company maintains control throughout processing. These changes impact the comparability of 2020 with prior periods. For the three and nine months ended September 30, 2019, $2.6 million and $7.8 million of gathering, transportation, and processing fees were recognized as a reduction to natural gas revenues in the consolidated statement of operations.
Oil and Gas Purchase and Sale Arrangements
Sales of purchased oil and gas represent revenues the Company receives from sales of commodities purchased from a third-party. The Company recognizes these revenues and the purchase of the third-party commodities, as well as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer.
Accounts receivable from revenues from contracts with customers
Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance sheet at September 30, 2020 and December 31, 20162019 of $81.4 million and $165.3 million, respectively, are presented in “Accounts receivable, net” in the consolidated balance sheets.
Transaction price allocated to remaining performance obligations
For the Company’s product sales that have a contract term greater than one year, it utilized the practical expedient in ASC 606, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Prior period performance obligations
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the
10

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 derived fromsignificant.
Note 3 - Acquisitions and Divestitures
2020 Acquisitions and Divestitures
ORRI Transaction. On September 30, 2020, the audited financial statementsCompany entered into a Purchase and Sale Agreement with Chambers Minerals, LLC, a private investment vehicle managed by Kimmeridge Energy, where the Company agreed to sell an undivided 2.0% (on an 8/8ths basis) overriding royalty interest, proportionately reduced to the Company’s net revenue interest, in and to the Company’s operated leases, excluding certain interests as defined in the Purchase and Sale Agreement, for an aggregate purchase price of $140.0 million (“ORRI Transaction”), with an effective date of October 1, 2020. After adjusting for costs associated with the sale, the net proceeds of $135.8 million were used to repay borrowings outstanding under the Company’s senior secured revolving credit facility. The net proceeds were recognized as a reduction of evaluated oil and gas properties with 0 gain or loss recognized.
Non-Operated Working Interest Transaction. On September 25, 2020, the Company entered into a Purchase and Sale Agreement to sell substantially all of its non-operated assets for estimated gross proceeds of approximately $30.0 million, with an effective date of September 1, 2020, subject to purchase price adjustments. The Company received $29.6 million at closing on November 2, 2020, subject to post-closing adjustments.
2019 Acquisitions and Divestitures
Carrizo Oil & Gas, Inc. Merger.On December 20, 2019, the Company completed its acquisition of Carrizo in an all-stock transaction (the “Merger” or the “Carrizo Acquisition”). Under the terms of the Merger, each outstanding share of Carrizo common stock was converted into 1.75 shares of the Company’s common stock. The Company issued approximately 168.2 million shares of common stock at a price of $4.55 per share, resulting in total consideration paid by the Company to the former Carrizo shareholders of approximately $765.4 million. In connection with the closing of the Merger, the Company funded the redemption of Carrizo’s 8.875% Preferred Stock, repaid the outstanding principal under Carrizo’s revolving credit facility and assumed all of Carrizo’s senior notes.
The Merger was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk-adjusted discount rate. Certain data necessary to complete the purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of Carrizo’s assets and liabilities. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date. Operating results
11

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 payable52,449 
Operating lease liabilities - current29,924 
Fair value of derivatives - current61,015 
Other current liabilities88,714 
Long-term debt1,984,135 
Operating lease liabilities - non-current30,070 
Asset retirement obligation26,151 
Fair value of derivatives - non-current26,960 
Other long-term liabilities17,260 
Common stock warrants10,029 
Total liabilities assumed$2,364,364 
Assets:
Accounts receivable, net$48,479 
Fair value of derivatives - current17,451 
Other current assets11,640 
Evaluated oil and natural gas properties2,133,280 
Unevaluated properties682,950 
Other property and equipment9,614 
Fair value of derivatives - non-current4,518 
Deferred tax asset159,320 
Operating lease right-of-use-assets59,907 
Other long term assets2,578 
Total assets acquired$3,129,737 
Approximately $160.5 million and $408.8 million of revenues and $51.6 million and $151.5 million of direct operating expenses attributed to the Carrizo Acquisition were included in the Company’s consolidated statements of operations for the periods presented are not necessarily indicative of the results that may be expectedthree and nine months ended September 30, 2020, respectively.
Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the year ended December 31, 2017.

In2019 was derived from the opinion of management, the accompanying unaudited consolidatedhistorical financial statements reflect allof the Company giving effect to the Merger, as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairlyfor the issuance of the Company’s financial position, the results of its operations and its cash flows for the periods indicated. Certain prior year amounts may have been reclassified to conform to current year presentation.

Recently issued accounting policies

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitledcommon stock in exchange for those goods or services. ASU 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for annual periods beginning on or after December 31, 2017, including interim periods within that reporting period. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption.

The Company has substantially completed its assessment of the adoption of this standard on its revenue-related contracts. The Company currently recognizes revenue under the entitlements method of accounting, and to date, has not identified any contracts that would require a change from the entitlements method. The Company continues to evaluate the impact of the standard’s provisions regarding gross-versus-net presentation. To date, the Company has not identified any material impact that the new standard will have on the Company’s
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Table of Contents

Consolidated Financial Statements with the exception of new disclosures. The Company intends to adopt the new standard on January 1, 2018 using the modified retrospective method at the date of adoption.

Recently adopted accounting policies

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. The Company adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements. The Company has elected to no longer estimate forfeitures.

Note 2 - Acquisitions 

Acquisitions were accounted for under the acquisition method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed under the income approach.

2017acquisitions

On February 13, 2017, the Company completed the acquisition of 29,175 gross (16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of $646,559, excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 9 for additional information regarding the equity offering). The Company obtained an 82% average working interest in the properties acquired in the Ameredev Transaction. In December 2016, in connection with the execution of the purchase and sale agreement for the Ameredev Transaction, the Company paid a deposit in the amount of $46,138 to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of December 31, 2016. The following table summarizes the estimated acquisition date fair values of the acquisition:
Evaluated oil and natural gas properties$137,368
Unevaluated oil and natural gas properties509,359
Asset retirement obligations(168)
Net assets acquired$646,559

The preliminary purchase price allocation is subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material.

On June 5, 2017, the Company completed the acquisition of 7,031 gross (2,488 net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Transaction discussed above, for total cash consideration of $52,500, excluding customary purchase price adjustments. The Company funded the cash purchase price with its available cash and proceeds from the issuance of an additional $200,000 of its 6.125% senior notes due 2024 (see Note 4 for additional information regarding the Company’s debt obligations).

2016 acquisitions

On October 20, 2016, the Company completed the acquisition of 6,904 gross (5,952 net) acres in the Midland Basin, primarily located in Howard County, Texas from Plymouth Petroleum, LLC and additional sellers that exercised their “tag-along” sales rights, for total cash consideration of $339,687, excluding customary purchase price adjustments (the “Plymouth Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 9 for additional information regarding the equity offering). The Company obtained an 82% average working interest (62% average net revenue interest) in the properties acquired in the Plymouth Transaction.

On May 26, 2016, the Company completed the acquisition of 17,298 gross (14,089 net) acres in the Midland Basin, primarily located in Howard County, Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of $220,000 and 9,333,333Carrizo’s outstanding shares of common stock, (at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date) for a total purchase price of $329,573, excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an 81% average working interest (61% average net revenue interest) in the properties acquired in the Big Star Transaction.

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Table of Contents

Unauditedas well as pro forma financial statements

The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Ameredev Transaction, Plymouth Transaction and Big Star Transaction had occurred as presented, or to project the Company’s results of operations for any future periods:
Three Months Ended September 30, Nine Months Ended September 30,
2017
(a) 
 2016
(a) 
 2017
(a) 
 2016
(a) 
Revenues$84,614
  $67,544
  $251,313
  $168,618
 
Income (loss) from operations31,426
  20,644
  90,076
  (61,918) 
Income (loss) available to common stockholders15,257
  23,322
  94,786
  (80,690) 
 
   
   
   
 
Net income (loss) per common share: 
   
   
   
 
Basic$0.08
  $0.13
  $0.47
  $(0.53) 
Diluted$0.08
  $0.13
  $0.47
  $(0.53) 

(a)The pro forma financial information was prepared assuming the Ameredev Transaction occurred as of January 1, 2016 and the Plymouth Transaction and Big Star Transaction occurred as of January 1, 2015.

The pro forma adjustments are based on available information and certain assumptions that managementthe Company believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation,(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 amortization expense, accretion expense, interest expensenatural gas properties and capitalized interest.(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.
12

The propertiespro 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 operations614,668 
Net income369,777 
Basic earnings per common share0.89 
Diluted earnings per common share0.89 
In conjunction with the Carrizo Acquisition, the Company incurred costs totaling $2.5 million and $26.4 million for the three and nine months ended September 30, 2020, respectively, comprised of severance costs of $0.8 million and $6.2 million for the three and nine months ended September 30, 2020, respectively, and other merger and integration expenses of $1.7 million and $20.2 million for the three and nine months ended September 30, 2020, respectively. Through September 30, 2020, the Company has incurred cumulative costs associated with the Ameredev Transaction, Plymouth TransactionCarrizo Acquisition of $100.8 million comprised of severance costs of $35.8 million and Big Star Transaction have been commingledother merger and integration expenses of $65.0 million. As of September 30, 2020, $5.6 million remained accrued and is included as a component of “Accounts payable and accrued liabilities” in the consolidated balance sheets.
Ranger Divestiture. In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Asset Divestiture”) for net cash proceeds of $244.9 million. The transaction also provided for potential additional contingent consideration in payments of up to $60.0 million based on West Texas Intermediate average annual pricing over a three-year period. See “Note 7 - Derivative Instruments and Hedging Activities” and “Note 8 - Fair Value Measurements” for further discussion of this contingent consideration arrangement. The divestiture encompasses the Ranger operating area in the southern Midland Basin which includes approximately 9,850 net Wolfcamp acres with our existingan average 66% working interest. The net cash proceeds were recognized as a reduction of evaluated oil and gas properties with 0 gain or loss recognized.
Note 4 - Property and itEquipment, Net
As of September 30, 2020 and December 31, 2019, total property and equipment, net consisted of the following:
September 30, 2020December 31, 2019
Oil and natural gas properties, full cost accounting method(In thousands)
Evaluated properties$7,775,858 $7,203,482 
Accumulated depreciation, depletion, amortization and impairments(4,859,316)(2,520,488)
Net evaluated oil and natural gas properties2,916,542 4,682,994 
Unevaluated properties
Unevaluated leasehold and seismic costs1,574,451 1,843,725 
Capitalized interest183,681 142,399 
Total unevaluated properties1,758,132 1,986,124 
Total oil and natural gas properties, net$4,674,674 $6,669,118 
Other property and equipment$66,365 $67,202 
Accumulated depreciation(33,445)(31,949)
Other property and equipment, net$32,920 $35,253 
The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $10.3 million and $8.2 million for the three months ended September 30, 2020 and 2019, respectively, and $26.7 million and $27.4 million for the nine months ended September 30, 2020 and 2019.
The Company capitalized interest costs associated with its unproved properties totaling $20.7 million and $18.1 million for the three months ended September 30, 2020 and 2019, respectively, and $65.6 million and $56.7 million for the nine months ended September 30, 2020 and 2019.
As a result of the downturn in the oil and gas industry as well as in the broader macroeconomic environment, the Company analyzed its unevaluated leasehold giving consideration to its updated exploration program as well as to the remaining lease term of certain unevaluated leaseholds. The Company transferred $235.9 million from unevaluated leasehold to evaluated properties during the nine months ended September 30, 2020 primarily as a result of the analysis described above.
13

Impairment of Evaluated Oil and Gas Properties
Primarily due to declines in the average realized prices for sales of oil on the first calendar day of each month during the trailing 12-month period (“12-Month Average Realized Price”) prior to September 30, 2020, the capitalized costs of oil and gas properties exceeded the cost center ceiling resulting in an impairment in the carrying value of evaluated oil and gas properties for the three and nine months ended September 30, 2020. An impairment of evaluated oil and gas properties recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices in the future increase the cost center ceiling applicable to the subsequent period. There were 0 impairments of evaluated oil and gas properties for the three months ended March 31, 2020 or for the corresponding prior year periods.
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Impairment of evaluated oil and gas properties (in thousands)$684,956$0$1,961,474$0
Beginning of period 12-Month Average Realized Price ($/Bbl)$45.87$53.00$53.90$58.40
End of period 12-Month Average Realized Price ($/Bbl)$41.71$52.44$41.71$52.44
Percent decrease in 12-Month Average Realized Price(9 %)(1 %)(23 %)(10 %)
The Company expects to record an additional impairment in the carrying value of evaluated oil and gas properties in the fourth quarter of 2020 based on an estimated 12-Month Average Realized price of crude oil of approximately $39.65 per Bbl as of December 31, 2020, which is impractical to providebased on the stand-alone operational results related to theseaverage realized price for sales of crude oil on the first calendar day of each month for the first 10 months and an estimate for the eleventh and twelfth months based on a quoted forward price. Declines in the 12-Month Average Realized Price of crude oil in subsequent quarters could result in a lower present value of the estimated future net revenues from proved oil and gas reserves and may result in additional impairments of evaluated oil and gas properties.

Note 35 - EarningsPer Share

Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted shares outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. For the three and nine months ended September 30, 2020, the Company reported a loss available to common stockholders. As a result, the calculation of diluted weighted average common shares outstanding excluded the anti-dilutive effect of 1.3 million and 1.0 million potentially dilutive common shares outstanding for the three and nine months ended September 30, 2020, respectively. The following table sets forth the computation of basic and diluted earnings per share:
Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
(In thousands, except per share amounts)
Net income (loss)($680,384)$55,834 ($2,028,550)$91,471 
Preferred stock dividends (1)
0 (350)0 (3,997)
Loss on redemption of preferred stock0 (8,304)0 (8,304)
Income (loss) available to common stockholders($680,384)$47,180 ($2,028,550)$79,170 
    
Basic weighted average common shares outstanding (2)
39,746 22,831 39,707 22,805 
Dilutive impact of restricted stock (2)
0 15 — 36 
Diluted weighted average common shares outstanding (2)
39,746 22,846 39,707 22,841 
    
Income (Loss) Available to Common Stockholders Per Common Share (2)
Basic($17.12)$2.07 ($51.09)$3.47 
Diluted($17.12)$2.07 ($51.09)$3.47 
    
Restricted stock (2)(3)
1,263 249 1,014 191 
(share amounts in thousands)Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Net income (loss)$17,081
 $21,139
 $97,600
 $(90,067)
Preferred stock dividends(1,824) (1,824) (5,471) (5,471)
Income (loss) available to common stockholders$15,257
 $19,315
 $92,129
 $(95,538)
       
Weighted average shares outstanding201,827
 136,983
 201,422
 112,925
Dilutive impact of restricted stock510
 500
 573
 —
Weighted average shares outstanding for diluted income (loss) per share202,337
 137,483
 201,995
 112,925
       
Basic income (loss) per share$0.08
 $0.14
 $0.46
 $(0.85)
Diluted income (loss) per share$0.08
 $0.14
 $0.46
 $(0.85)
       
Stock options (a)
—
 15
 —
 15
Restricted stock (a)
51
 25
 51
 25

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


Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
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(1)    The Company redeemed all outstanding shares of its 10% Series A Cumulative Preferred Stock (“Preferred Stock”) on July 18, 2019 and all dividends ceased to accrue upon redemption.
(2)    Shares and per share data have been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 - Stockholders’ Equity” for additional information.
(3)    Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.
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Note 46 - Borrowings

The Company’s borrowings consisted of the following at:໿following:
September 30, 2020December 31, 2019
(In thousands)
Senior Secured Revolving Credit Facility due 2024$1,025,000 $1,285,000 
9.00% Second Lien Senior Secured Notes due 2025300,000 0 
6.25% Senior Notes due 2023650,000 650,000 
6.125% Senior Notes due 2024600,000 600,000 
8.25% Senior Notes due 2025250,000 250,000 
6.375% Senior Notes due 2026400,000 400,000 
Total principal outstanding3,225,000 3,185,000 
Unamortized premium on 6.125% Senior Notes4,500 5,344 
Unamortized premium on 6.25% Senior Notes3,818 4,838 
Unamortized premium on 8.25% Senior Notes4,571 5,286 
Unamortized discount on 9.00% Second Lien Notes(35,270)0 
Unamortized deferred financing costs for Senior Notes(12,346)(14,359)
Total carrying value of borrowings (1)
$3,190,273 $3,186,109 
 September 30, 2017 December 31, 2016
Principal components:   
Senior secured revolving credit facility$—
 $—
6.125% senior unsecured notes due 2024600,000
 400,000
Total principal outstanding600,000
 400,000
Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization7,875
 —
Unamortized deferred financing costs(12,760) (9,781)
Total carrying value of borrowings$595,115
 $390,219


(1)    Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $24.9 million and $22.2 million as of September 30, 2020 and December 31, 2019, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets.
Senior secured revolving credit facility
The Company has a senior secured revolving credit facility with a syndicate of lenders that, as of September 30, 2020, had a borrowing base of $1.6 billion, with an elected commitment amount of $1.6 billion, borrowings outstanding of $1.03 billion at a weighted-average interest rate of 2.93%, and letters of credit outstanding of $24.2 million. The credit agreement governing the revolving credit facility provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25% Senior Notes due 2023 (the “Credit Facility”“6.25% Senior Notes”)

On May 31, 2017, are outstanding at such time, (ii) July 2, 2024 if the Company entered into6.125% Senior Notes due 2024 (the “6.125% Senior Notes”) are outstanding at such time, and (iii) if the Sixth Amended and Restated Credit AgreementSecond Lien Notes, defined below, are outstanding at such time, the date which is 182 days prior to the Credit Facilitymaturity of any of the 6.25% Senior Notes or the 6.125% Senior Notes, in each case, to the extent a principal amount of more than $100.0 million with a maturity daterespect to each such issuance is outstanding as of May 25, 2022. JPMorgan Chase Bank, N.A. is Administrative Agent,such date), when the credit agreement matures and participants include 17 institutional lenders.any outstanding borrowings are due. The total notional amount availableborrowing base under the Credit Facilitycredit agreement is $2,000,000. Amounts borrowed undersubject to regular redeterminations in the Credit Facilityspring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may not exceedreduce the amount of the borrowing base, which is generally reviewed on a semi-annual basis.base. The Credit Facilityrevolving credit facility is secured by first preferred mortgages covering the Company’s major producing properties. ConcurrentThe capitalized terms which are not defined in this description of the revolving credit facility shall have the meaning given to such terms in the credit agreement.
On May 7, 2020, the Company entered into the first amendment to its credit agreement governing the revolving credit facility. The amendment, among other things, (a) established a new borrowing base as a result of the spring 2020 scheduled redetermination in the amount of $1.7 billion and reduced the elected commitments to $1.7 billion, which were subsequently revised as described below; (b) permits the incurrence of, among other things, new second lien notes in 2020 exchanged for unsecured notes in an aggregate principal amount of up to $400.0 million (the “Exchange Notes”) without triggering a reduction in the borrowing base so long as any such Exchange Notes are subject to an intercreditor agreement providing that the liens securing the Exchange Notes rank junior to the liens securing the credit agreement; (c) provides that testing of the Leverage Ratio, which is the ratio of consolidated total debt to Adjusted EBITDAX on a quarterly basis is suspended until March 31, 2022, as of which testing date and the last day of each fiscal quarter ending thereafter, such ratio may not exceed 4.00 to 1.00; (d) provides a new financial covenant testing the Secured Leverage Ratio, which is the ratio of the consolidated total secured debt to Adjusted EBITDAX and provides that such ratio on a quarterly basis as of the last day of each quarter beginning with March 31, 2020 up to and including the quarter ending December 31, 2021 may not exceed 3.00 to 1.00; (e) provided that the testing of the Current Ratio, which is the ratio of current assets to current liabilities was suspended until September 30, 2020, as of which testing date and the last day of each fiscal quarter ending thereafter, such ratio may not be less than 1.00 to 1.00; (f) increases the applicable margins for borrowings under the credit agreement for both LIBOR loans and base rate loans by 75 basis points across all commitment utilization ranges; (g) introduces customary anti-cash hoarding protections tested weekly, which restrict the Company’s ability to maintain unrestricted cash on its balance sheet in amounts in the excess of the lesser of (i) $125.0 million or (ii) 7.5% of the then current borrowing base; (h) requires the Company to enter into and maintain minimum hedges for the 12 month period starting January 1, 2021 through December 31, 2021, for which the net notional volumes on a barrel of oil equivalent basis are not less than 40% of the reasonably anticipated production from the Company’s oil and gas properties which are classified as proved developed producing reserves as of April 1, 2020; (i) requires mortgage and title coverage on at least 90% of
15

the total value of proved oil and gas properties evaluated in the most recently delivered reserve report; and (j) restricts the Company’s ability to make certain investments and cash distributions by lowering the maximum leverage ratio required to make such distributions to 2.50 to 1.00.
On September 30, 2020, the Company entered into the second amendment to its credit agreement governing the revolving credit facility. The amendment, among other things, reaffirmed the $1.7 billion borrowing base as a result of the fall 2020 scheduled redetermination.
Also on September 30, 2020, the Company entered into the third amendment to its credit agreement governing the revolving credit facility. The amendment, among other things, (a) established a new borrowing base of $1.6 billion and reduced the elected commitments to $1.6 billion in connection with the executionissuance of the Sixth AmendedSecond Lien Notes and Restated CreditWarrants, described below, and ORRI Transaction; (b) permitted the issuance of the $300.0 million of Second Lien Notes as contemplated by the Purchase Agreement described below without triggering a reduction in the Credit Facility’s borrowing base increasedbase; (c) extends through the end of 2021 the time period during which Exchange Notes may be issued without triggering a reduction in the borrowing base; and (d) if the Second Lien Notes are outstanding at such time, caused the maturity of the revolving credit facility to $650,000, butspring forward to a date which is 182 days prior to the Company elected an aggregate commitmentmaturity of any of the 6.25% Senior Notes or the 6.125% Senior Notes, in each case, to the extent a principal amount of $500,000. Asmore than $100.0 million with respect to each such issuance is outstanding as of September 30, 2017,such date.
Borrowings outstanding under the Company continuedcredit 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 maintain2.00%, where the Credit Facility’s borrowing base at $500,000.

As of September 30, 2017, there was no balance outstanding on the Credit Facility. For the quarter ended September 30, 2017, the Credit Facility had a weighted-average interest rate of 3.23%, calculatedis defined as the LIBORgreatest 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 tiered rate ranging frommargin between 2.00% to 3.00%, which is determined based on utilization of the facility. In addition, the Credit Facility carries a. The Company also incurs commitment fee offees at rates ranging between 0.375% per annum, payable quarterly,to 0.500% on the unused portion of lender commitments, which are included in “Interest expense, net” in the borrowing base.consolidated statements of operations.

6.125% senior notes due 2024 (“6.125% Senior Notes”)

Second Lien Notes and Warrants
On October 3, 2016,September 30, 2020, the Company entered into a Purchase Agreement (the “Purchase Agreement”) where it issued $400,000 aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391,270. The 6.125% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.

On May 19, 2017, the Company issued an additional $200,000(i) $300.0 million in aggregate principal amount of its 6.125%9.00% Second Lien Senior Secured Notes which with the existing $400,000 aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture. The net proceedsdue 2025 (the “Second Lien Notes”) and (ii) warrants for 7.3 million of the offering, includingCompany’s common stock, with a premium issueterm of five years and an exercise price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $206,139.$5.60 per share, exercisable only on a net share settlement basis (the “Warrants”), for aggregate consideration of $294.0 million. The Company used the proceeds, net of issuance costs, of approximately $288.6 million to repay borrowings outstanding under its senior secured revolving credit facility. The Company also entered into a registration rights agreement with the purchaser of the Second Lien Notes.
Net proceeds were allocated to the Warrants based on their fair value on the date of issuance with the remaining net proceeds allocated to the Second Lien Notes. The fair value of the Warrants was calculated by a third-party valuation specialist using a Black Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date:
Issuance Date Fair Value Assumptions
Exercise price$5.60
Expected term (in years)5.0
Expected volatility116.3 %
Risk-free interest rate0.3 %
Dividend yield0 %
See “Note 8 - Fair Value Measurements” for further discussion.
Second Lien Notes. The Second Lien Notes will mature on the earlier of (i) April 1, 2025 and (ii) 91 days prior to the maturity date of any outstanding unsecured notes in part, to fund an acquisition completeda principal amount at or greater than $100.0 million and have interest payable semi-annually each April 1 and October 1, commencing on June 5, 2017 (discussed further in Note 2) and for general corporate purposes.

April 1, 2021.
The Company may redeem the 6.125% SeniorSecond Lien Notes in accordance with the following terms: (1) prior to October 1, 2019,2022, a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.125%109.00% of principal, plus accrued and unpaid interest, if any, to, but excluding, the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to October 1, 2019,2022, a redemption of all or part of the principal at a price of 100% of the principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to, but excluding, the date of the redemption; and (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to, but excluding, the date of the redemption, of (i) of 104.594%105.00% of principal if the redemption occurs on or after October 1, 2019,2022, but before October 1, 2020,2023, and (ii) of 103.063%102.50% of principal if the redemption occurs on or after October 1, 2020,2023, but before October 1, 2021,2024, and (iii) of 101.531% of principal if the redemption occurs on or after October 1, 2021, but before October 1, 2022, and (iv) of 100% of principal if the redemption occurs on or after October 1, 2022.2024.

Following aUpon the occurrence of certain change of control events, each holder of the 6.125% SeniorSecond Lien Notes may require the Company to repurchase all or a portion of the 6.125% SeniorSecond Lien Notes at a price of 101% of the principal of the amount repurchased, plus accrued and unpaid interest, if any, to, but excluding, the date of repurchase.

16
Callon Petroleum Company
Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per share and per unit data)
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Restrictive covenants

The Company’s Credit Facility and the indenture governing our 6.125% Senior Notes contain variouscredit agreement contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios.
Under the credit agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter, each as described above: (1) a Secured Leverage Ratio of no more than 3.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. The Company was in compliance with these covenants at September 30, 2017.2020.

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 57 - Derivative Instruments and Hedging Activities

Objectives and strategies for using derivative instruments

The Company is exposed to fluctuations in oil, and 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, and natural gas and NGL production. The Company utilizes a mix of collars, swaps, and put and call options and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.

Counterparty risk and offsetting

The use ofCompany typically has numerous commodity derivative instruments exposesoutstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.
As of September 30, 2020, the Company has outstanding commodity derivative instruments with fifteen counterparties to minimize its credit exposure to any individual counterparty. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s credit agreement. Therefore, each of the Company’s counterparties allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting.
Because each of the Company’s counterparties has an investment grade credit rating, the Company believes it does not have significant credit risk that a counterparty will be unableand accordingly does not currently require its counterparties to meetpost collateral to support the net asset positions of its commitments. 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 6instrument. See “Note 8 - Fair Value Measurements” for additional information regarding fair value.

The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting assets against liabilities. 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.
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 6“Note 8 - Fair Value Measurements” for additional information regarding fair value.

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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 - AnnualPeriod Cash Flow OccursStatement of Cash Flows Presentation
Remaining Contingent Receipt - Aggregate Limit (3)
Divestiture Date Fair Value
$8,512 
Actual Settlement2019Greater than $60/Bbl, less than $65/Bbl$0Equal to or greater than $65/Bbl$01Q20N/A
Remaining Potential Settlements2020-2021Greater than $60/Bbl, less than $65/Bbl$9,000Equal to or greater than $65/Bbl$20,833(2)(2)$41,666 

(1)    The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc.
(2)    Cash received for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the divestiture date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, $8.5 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.
(3)    The specified pricing threshold for 2019 was not met. As such, approximately $41.7 million remains for potential settlements in future years.
As a result of the Carrizo Acquisition, the Company assumed all contingent consideration arrangements previously entered into by Carrizo. These contingent consideration arrangements are summarized below:
Contingent ExL Consideration
Year
Threshold (1)
Period
Cash Flow
Occurs		Statement of
Cash Flows Presentation		Contingent
Payment -
Annual		Remaining Contingent
Payments -
Aggregate Limit		Acquisition
Date
Fair Value
(In thousands)
($69,171)
Actual Settlement(2)(3)
2019$50.00 1Q20Investing($50,000)
Remaining Potential Settlements2020-2021$50.00 (2)(2)($25,000)($25,000)

(1)    The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration (“U.S. EIA”).
(2)    Cash paid for settlements related to 2019 are classified as cash flows used in investing activities as the cash payment was made soon after the acquisition date. Due to the extended time frame over which the 2020 and 2021 contingent arrangements could settle, any future payments would be considered financing arrangements. As such, cash settlements of those contingent consideration arrangements would be classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold were reached, $19.2 million of the final contingent payment would be presented in cash flows used in financing activities with the remainder presented in operating cash flows.
(3)    In January 2020, the Company paid $50.0 million as the specified pricing threshold was met. Only $25.0 million remains for potential settlements in future years.
Additionally, as part of the Carrizo Acquisition, the Company acquired contingent consideration arrangements where the Company could receive payments if certain pricing thresholds are met in 2020, which range between $53.00 - $60.00 per barrel of oil or $3.18 - $3.30 per MMBtu of natural gas. In January 2020, the Company received $10.0 million as the specified pricing thresholds were met for certain of the contingent consideration arrangements. As such, the aggregate limit of the remaining contingent receipts is $13.0 million and would be settled in January 2021 based on the specified pricing thresholds for 2020.
Warrants
The Company determined that the Warrants issued with the Second Lien Notes are required to be accounted for as a derivative instrument. The Company records the Warrants as a liability on its consolidated balance sheet measured at fair value as a component of “Fair value of derivatives” with gains and losses as a result of changes in the fair value of the Warrants recorded as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur.
Derivatives not designated as hedging instruments

The Company records its derivative contractsinstruments 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
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derivative contracts in the consolidated statements of operations. Cash settlements are also recorded as gain or loss on derivative contracts in the consolidated statements of operations.

The following table reflects the fair value of the Company’s derivative instruments for the periods presented: 
  Balance Sheet Presentation Asset Fair Value Liability Fair Value Net Derivative Fair Value
Commodity Classification Line Description 9/30/2017 12/31/2016 9/30/2017 12/31/2016 9/30/2017 12/31/2016
Natural gas Current Fair value of derivatives $431
 $—
 $—
 $(593) $431
 $(593)
Oil Current Fair value of derivatives 2,902
 103
 (6,380) (17,675) (3,478) (17,572)
Oil Non-current Fair value of derivatives 1,121
 —
 (659) (28) 462
 (28)
  Totals   $4,454
 $103
 $(7,039) $(18,296) $(2,585) $(18,193)

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 sheet.sheets. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:
As of September 30, 2020
Presented without As Presented with
Effects of NettingEffects of NettingEffects of Netting
ASSETS(In thousands)
Commodity derivative instruments$34,362 ($24,541)$9,821 
Contingent consideration arrangements0 0 0 
Fair value of derivatives - current$34,362 ($24,541)$9,821 
Commodity derivative instruments5,689 (5,457)232 
Contingent consideration arrangements1,089 0 1,089 
Other assets, net$6,778 ($5,457)$1,321 
LIABILITIES   
Commodity derivative instruments($59,488)$24,541 ($34,947)
Contingent consideration arrangements(3)0 (3)
Fair value of derivatives - current($59,491)$24,541 ($34,950)
Commodity derivative instruments(13,195)5,457 (7,738)
Contingent consideration arrangements(4,058)0 (4,058)
Warrant liability(23,909)0 (23,909)
Fair value of derivatives - non current($41,162)$5,457 ($35,705)

As of December 31, 2019
Presented without As Presented with
Effects of NettingEffects of NettingEffects of Netting
ASSETS(In thousands)
Commodity derivative instruments$26,849 ($17,511)$9,338 
Contingent consideration arrangements16,718 0 16,718 
Fair value of derivatives - current$43,567 ($17,511)$26,056 
Commodity derivative instruments0 0 0 
Contingent consideration arrangements9,216 0 9,216 
Other assets, net$9,216 $0 $9,216 
LIABILITIES   
Commodity derivative instruments($38,708)$17,511 ($21,197)
Contingent consideration arrangements(50,000)0 (50,000)
Fair value of derivatives - current($88,708)$17,511 ($71,197)
Commodity derivative instruments(12,935)0 (12,935)
Contingent consideration arrangements(19,760)0 (19,760)
Fair value of derivatives - non current($32,695)$0 ($32,695)
19
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
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 September 30, 2017
 Presented without   As Presented with
 Effects of Netting Effects of Netting Effects of Netting
Current assets: Fair value of derivatives$5,441
 $(2,108) $3,333
Long-term assets: Fair value of derivatives1,388
 (267) 1,121
     
Current liabilities: Fair value of derivatives$(8,488) $2,108
 $(6,380)
Long-term liabilities: Fair value of derivatives(926) 267
 (659)

 December 31, 2016
 Presented without   As Presented with
 Effects of Netting Effects of Netting Effects of Netting
Current assets: Fair value of derivatives$1,836
 $(1,733) $103
      
Current liabilities: Fair value of derivatives$(20,001) $1,733
 $(18,268)
Long-term liabilities: Fair value of derivatives(28) —
 (28)

For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statementThe components of operations as gain or“(Gain) loss on derivative contracts:contracts” are as follows for the respective periods:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In thousands)
(Gain) loss on oil derivatives$16,606 ($24,722)($118,348)$34,798 
(Gain) loss on natural gas derivatives7,296 (1,323)18,819 (4,306)
(Gain) loss on NGL derivatives2,421 0 2,418 0 
(Gain) loss on contingent consideration arrangements715 4,236 (855)923 
(Gain) loss on derivative contracts$27,038 ($21,809)($97,966)$31,415 
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Oil derivatives       
Net gain (loss) on settlements$(1,373) $4,252
 $(4,213) $15,467
Net gain (loss) on fair value adjustments(12,811) 699
 14,584
 (26,904)
Total gain (loss) on oil derivatives$(14,184) $4,951
 $10,371
 $(11,437)
Natural gas derivatives       
Net gain (loss) on settlements$159
 $(161) $241
 $357
Net gain (loss) on fair value adjustments(137) 345
 1,024
 (201)
Total gain on natural gas derivatives$22
 $184
 $1,265
 $156
        
Total gain (loss) on oil & natural gas derivatives$(14,162) $5,135
 $11,636
 $(11,281)
The components of “Cash (paid) received for commodity derivative settlements” and “Cash paid for settlements of contingent consideration arrangements, net” are as follows for the respective periods:

Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In thousands)
Cash flows from operating activities    
Cash (paid) received on oil derivatives$2,130 ($1,045)$100,823 ($7,048)
Cash (paid) received on natural gas derivatives(1,677)2,056 931 6,612 
Cash (paid) received for commodity derivative settlements$453 $1,011 $101,754 ($436)
Cash flows from investing activities    
Cash paid for settlements of contingent consideration arrangements, net$0 $0 ($40,000)$0 
20
Callon Petroleum Company
Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per share and per unit data)
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Derivative positions

Listed in the tables below are the outstanding oil, and natural gas and NGL derivative contracts as of September 30, 2017:  2020:
For the RemainderFor the Full Year
Oil contracts (WTI)of 2020of 2021
   Swap contracts
   Total volume (Bbls)2,496,880 1,377,000 
   Weighted average price per Bbl$42.10 $42.00 
   Collar contracts
   Total volume (Bbls)1,501,440 4,653,750 
   Weighted average price per Bbl
   Ceiling (short call)$45.00 $45.31 
   Floor (long put)$35.00 $40.00 
   Short put contracts
      Total volume (Bbls)552,000 0 
      Weighted average price per Bbl$42.50 $0 
   Long call contracts
    Total volume (Bbls)460,000 0 
    Weighted average price per Bbl$67.50 $0 
   Short call contracts
   Total volume (Bbls)460,000 (1)4,825,300 (1)
   Weighted average price per Bbl$55.00 $63.62 
Short call swaption contracts
   Total volume (Bbls)0 730,000 (2)
   Weighted average price per Bbl$0 $47.00 
Oil contracts (Brent ICE)  
   Swap contracts
   Total volume (Bbls)0 1,272,450 
   Weighted average price per Bbl$0 $38.24 
Collar contracts
Total volume (Bbls)0 730,000 
Weighted average price per Bbl
Ceiling (short call)$0 $50.00 
Floor (long put)$0 $45.00 
Oil contracts (Midland basis differential)
   Swap contracts
   Total volume (Bbls)1,380,000 3,022,900 
   Weighted average price per Bbl($1.89)$0.26 
Oil contracts (Argus Houston MEH basis differential)
   Swap contracts
   Total volume (Bbls)1,435,202 0 
   Weighted average price per Bbl$0.03 $0 
Oil contracts (Argus Houston MEH swaps)
   Swap contracts
   Total volume (Bbls)0 2,969,050 
   Weighted average price per Bbl$0 $39.48 
 For the Remainder of For the Full Year of
Oil contracts (WTI)2017 2018
Swap contracts combined with short puts (enhanced swaps)   
Total volume (MBbls)184
 —
Weighted average price per Bbl   
Swap$44.50
 $—
Short put option$30.00
 $—
Swap contracts   
Total volume (MBbls)184
 1,460
Weighted average price per Bbl$45.74
 $50.93
Deferred premium put spread option   
Total volume (MBbls)253
 —
Premium per Bbl$2.45
 $—
Weighted average price per Bbl   
Long put option$50.00
 $—
Short put option$40.00
 $—
Collar contracts (two-way collars)   
Total volume (MBbls)340
 —
Weighted average price per Bbl   
Ceiling (short call)$58.19
 $—
Floor (long put)$47.50
 $—
Call option contracts   
Total volume (MBbls)169
 —
   Premium per Bbl$1.82
 $—
Weighted average price per Bbl   
Short call strike price (a)
$50.00
 $—
     Long call strike price (a)
$50.00
 $—
Collar contracts combined with short puts (three-way collars)   
Total volume (MBbls)—
 3,468
Weighted average price per Bbl   
Ceiling (short call option)$—
 $60.86
Floor (long put option)$—
 $48.95
Short put option$—
 $39.21

(a)Offsetting contracts.

 For the Remainder of For the Full Year of
Oil contracts (Midland basis differential)2017 2018
Swap contracts   
Volume (MBbls)552
 4,563
Weighted average price per Bbl$(0.52) $(0.98)


Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Table of Contents

(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.
21

 For the Remainder of For the Full Year of
Natural gas contracts2017 2018
Collar contracts combined with short puts (Henry Hub, three-way collars)   
Total volume (BBtu)368
 —
Weighted average price per MMBtu   
Ceiling (short call option)$3.71
 $—
Floor (long put option)$3.00
 $—
Short put option$2.50
 $—
Collar contracts (Henry Hub, two-way collars)   
Total volume (BBtu)856
 720
Weighted average price per MMBtu   
Ceiling (short call option)$3.77
 $3.84
Floor (long put option)$3.23
 $3.40
Swap contracts 
  
Total volume (BBtu)124
 —
Weighted average price per MMBtu$3.39
 $—


For the RemainderFor the Full Year
Natural gas contracts (Henry Hub)of 2020of 2021
   Swap contracts
      Total volume (MMBtu)1,633,000 11,123,000 
      Weighted average price per MMBtu$2.05 $2.60 
   Collar contracts (three-way collars)
      Total volume (MMBtu)1,525,000 1,350,000 
      Weighted average price per MMBtu
         Ceiling (short call)$2.72 $2.70 
         Floor (long put)$2.45 $2.42 
         Floor (short put)$2.00 $2.00 
Collar contracts (two-way collars)
      Total volume (MMBtu)1,525,000 9,550,000 
      Weighted average price per MMBtu
         Ceiling (short call)$3.25 $3.04 
         Floor (long put)$2.67 $2.59 
   Short call contracts
      Total volume (MMBtu)2,013,000 7,300,000 
      Weighted average price per MMBtu$3.50 $3.09 
Natural gas contracts (Waha basis differential)
   Swap contracts
      Total volume (MMBtu)4,421,000 12,775,000 
      Weighted average price per MMBtu($0.91)($0.47)
Subsequent event

For the RemainderFor the Full Year
NGL contracts (OPIS Mont Belvieu Purity Ethane)of 2020of 2021
   Swap contracts
      Total volume (Bbls)0 1,825,000 
      Weighted average price per Bbl$0 $7.62 
The following derivative contracts were executed subsequent to September 30, 2017:໿
 For the Remainder of For the Full Year of
Oil contracts (Midland basis differential)2017 2018
Swap contracts   
Volume (MBbls)—
 546
Weighted average price per Bbl$—
 $(0.23)
   
 For the Remainder of For the Full Year of
Oil contracts (WTI)2017 2018
Swap contracts   
Volume (MBbls)—
 365
Weighted average price per Bbl$—
 $53.40

Note 68 - Fair Value Measurements

TheAccounting guidelines for measuring fair value establish a three-level valuation hierarchy includedfor 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 GAAP gives the highest priority to measurement. The three levels are defined as follows:
Level 1 – Observable inputs which consist of unadjustedsuch as quoted prices in active markets at the measurement date for identical, instruments in active markets. unrestricted assets or liabilities.
Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from– Other inputs that are significantobservable 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 unobservable,which the Company makes its own assumptions about how market participants would price the assets and these valuations have the lowest priority.liabilities.

Fair value offinancial instruments

Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximatedapproximate fair value due to the short-term nature or maturity of the instruments.

Debt. The carrying amount of borrowings outstanding under the Company’s floating-rate debt approximatedCredit Facility approximate fair value becauseas the borrowings bear interest at variable rates were variable and are reflective of market rates.
September 30, 2017 December 31, 2016
Carrying Value Fair Value Carrying Value Fair Value
Credit Facility (a)
$—
 $—
 $—
 $—
6.125% Senior Notes (b)
595,115
 621,000
 390,219
 412,000
Total$595,115
 $621,000
 $390,219
 $412,000

໿
(a)Floating-rate debt.
(b)The fair value was based upon Level 2 inputs. See Note 4 for additional information about the Company’s 6.125% Senior Notes.

The following table presents the principal amounts of the Company’s senior notes
22
Callon Petroleum Company
Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per share and per unit data)
Table of Contents

with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “Note 6 - Borrowings” for further discussion.
September 30, 2020December 31, 2019
Principal AmountFair ValuePrincipal AmountFair Value
(In thousands)
6.25% Senior Notes$650,000 $273,000 $650,000 $658,125 
6.125% Senior Notes600,000 240,000 600,000 611,130 
8.25% Senior Notes250,000 92,500 250,000 256,250 
6.375% Senior Notes400,000 140,000 400,000 405,424 
Total$1,900,000 $745,500 $1,900,000 $1,930,929 
Second Lien Notes. The fair value measurements of the Second Lien Notes are measured by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and are designated as Level 3 inputs. Significant inputs to the valuation of the Second Lien Notes include redemption premiums and redemption assumptions provided by the Company. The following table presents the principal amount of the Company’s Second Lien Notes with the fair value measured using the Level 3 inputs mentioned above. See “Note 6 - Borrowings” for details regarding the allocation of the net proceeds to the Second Lien Notes and Warrants.
September 30, 2020December 31, 2019
Principal AmountFair ValuePrincipal AmountFair Value
(In thousands)
9.00% Second Lien Notes$300,000 $260,966 $0 $0 
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 ana 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. The Company believes that the majority ofAs the inputs used to calculatein the model are substantially observable over the term of the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on thecontract and there is a wide availability of quoted market prices for similar commodity derivative contracts.contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See Note 5“Note 7 - Derivative Instruments and Hedging Activities” for additional information regardingfurther discussion.
Contingent consideration arrangements - embedded derivative financial instruments. The embedded options within the Company’s derivative instruments.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.
23

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:
September 30, 2020
Level 1Level 2Level 3
(In thousands)
Assets   
Commodity derivative instruments$0 $10,053 $0 
Contingent consideration arrangements0 1,089 0 
Liabilities   
Commodity derivative instruments0 (42,685)0 
Contingent consideration arrangements0 (4,061)0 
Total net assets (liabilities)$0 ($35,604)$0 
   
December 31, 2019
Level 1Level 2Level 3
(In thousands)
Assets   
Commodity derivative instruments$0 $9,338 $0 
Contingent consideration arrangements0 25,934 0 
Liabilities   
Commodity derivative instruments0 (34,132)0 
Contingent consideration arrangements0 (69,760)— 
Total net assets (liabilities)$0 ($68,620)$0 
September 30, 2017Classification Level 1 Level 2 Level 3 Total
Assets         
Derivative financial instrumentsFair value of derivatives $—
 $4,454
 $—
 $4,454
Liabilities         
Derivative financial instrumentsFair value of derivatives —
 (7,039) —
 (7,039)
Total net liabilities  $—
 $(2,585) $—
 $(2,585)
         
December 31, 2016Classification Level 1 Level 2 Level 3 Total
Assets         
Derivative financial instrumentsFair value of derivatives $—
 $103
 $—
 $103
Liabilities         
Derivative financial instrumentsFair value of derivatives —
 (18,296) —
 (18,296)
Total net liabilities  $—
 $(18,193) $—
 $(18,193)
Warrants. The fair value of the Warrants was calculated by a third-party valuation specialist using a Black Scholes-Merton option pricing model. As historical volatility is a significant input into the model, the Warrants are designated as Level 3 within the valuation hierarchy. See “Note 6 - Borrowings” and “Note 7 - Derivative Instruments and Hedging Activities” for additional details regarding the Warrants.

Assets andliabilitiesmeasured atfairvalue onThe following table presents anonrecurringbasis

Acquisitions. The Company determines reconciliation of the change in the fair value of the liability related to the Warrants for the nine months ended September 30, 2020.
Nine Months Ended September 30, 2020
Beginning of period$0 
Recognition of issuance date fair value23,909 
Gain (loss) on changes in fair value0 
Transfers into (out of) Level 30 
End of period$23,909 
Assets and liabilities measured at fair value on a nonrecurring basis
Acquisitions. The fair value of assets acquired and liabilities assumed, other than the contingent consideration arrangements which are discussed above, are measured as of the acquisition date by a third-party valuation specialist using a combination of income and market approaches, which are not observable in the income approach based onmarket 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, and oil and natural gas forward prices.prices, and a risk-adjusted discount rate. See “Note 3 - Acquisitions and Divestitures” for additional discussion.
Asset retirement obligations. The future net revenuesCompany measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are discountedinstalled using a weighted average cost of capital. The discounted future net revenues of proved undevelopedcash flow model based on inputs that are not observable in the market and probable reservestherefore are reduced by an additional reserve adjustment factordesignated as Level 3 within the valuation hierarchy. Significant inputs to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 2measurement of asset retirement obligations include estimates of the costs of plugging and Level 3 inputs.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 79 - Income Taxes

The Company typically provides for income taxes at athe statutory rate of 35%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. AsThe following
24

table presents a resultreconciliation of the write-downreported amount of income tax expense (benefit) to the amount of income tax expense (benefit) that would result from applying domestic federal statutory tax rates to pretax income (loss) from continuing operations:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Income tax provision computed at statutory federal income tax rate21 %21 %21 %21 %
State taxes net of federal expense1 %1 %1 %1 %
Section 162(m)0 %0 %0 %0 %
Effective income tax rate, before discrete items22 %22 %22 %22 %
Valuation allowance(22 %)0 %(28 %)0 %
Other discrete items (1)
0 %2 %0 %2 %
Effective income tax rate, after discrete items0 %24 %(6 %)24 %

(1)    Accounts for the potential impact of periodic volatility of stock-based compensation tax deductions on future effective tax rates.
Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that
the Company’s net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at September 30, 2020, driven primarily by the impairments of evaluated oil and gas properties recognized beginning in the latter partsecond quarter of 20152020 and continuing through the first halfthree months ended September 30, 2020. This limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Beginning in the second quarter of 2016,2020 and continuing through the third quarter of 2020, based on the evaluation of the evidence available, the Company concluded that it is more likely than not that the net deferred tax assets will not be realized. As a result, the Company has recorded a valuation allowance of $520.8 million, reducing the net deferred tax assets as of September 30, 2020 to 0.
The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more future potential transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes taxable income. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit.
Due to the issuance of common stock associated with the Carrizo acquisition, the Company incurred a cumulative three year loss. Becauseownership change and as such, the Company’s net operating losses (“NOLs”) prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382. At September 30, 2020, the Company had approximately $897.0 million of NOLs, including $288.2 million acquired from Carrizo, of which approximately $496.5 million expire between 2035 and 2037 and $400.5 million have an indefinite carryforward life.
Note 10 - Share-based Compensation
Stock-Based Compensation Plans
At the Company’s annual meeting of shareholders on June 8, 2020, shareholders approved the 2020 Omnibus Incentive Plan (the “2020 Plan”), which replaced the 2018 Omnibus Incentive Plan (the “Prior Incentive Plan”). From the effective date of the impact2020 Plan, no further awards may be granted under the cumulative loss hasPrior Incentive Plan, however, awards previously granted under the Prior Incentive Plan will remain outstanding in accordance with their terms. Effective August 7, 2020, in connection with the reverse stock split and reduction in authorized shares, the Board of Directors approved and adopted an amendment to the 2020 Plan to proportionately adjust the limitations on the determinationawards that may be granted. See “Note 11 - Stockholders’ Equity” for discussion of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a full valuation allowance for the net U.S. federal deferred tax assetreverse stock split and reduction in 2015. In subsequent periods where the Company has recorded pre-tax income, it has reversed a portion of the U.S. federal valuation allowance, net of discrete items, to the extent necessary to offset U.S. federal income tax expense on pre-tax income recorded for the period. Income tax expense recorded in this period relates to deferred State of Texas gross margin tax. The valuation allowance was $109,815 asauthorized shares. As of September 30, 2017. 2020, there were 1,967,782 common shares remaining available for grant under the 2020 Plan.

25

RSU Equity Awards
The Company recently adopted a new accounting standard that simplifiedfollowing table summarizes activity for restricted stock units may be settled in common stock (“RSU Equity Awards”) for the accounting for stock-based compensation. As a result, the Company recorded a cumulative-effect adjustment to retained earnings as of January 1, 2017 for all windfall tax benefits that were not previously recognized because the related tax deduction had not reduced current taxes payable. Due to the Company’s valuation allowance position, a cumulative-effect adjustment was recorded to retained earnings as of January 1, 2017,three and therefore, the net effect of this new accounting standard was zero. See Note 1 for additional information about this new accounting standard.nine months ended September 30, 2020 and 2019:

Three Months Ended September 30,
20202019
RSU Equity Awards
(in thousands) (1)
Weighted Average Grant Date
Fair Value (1)
RSU Equity Awards
(in thousands) (1)
Weighted Average Grant Date
Fair Value (1)
Unvested, beginning of the period719 $39.99 305 $105.86 
Granted (2)
6 $9.35 0 $0 
Vested (3)
(14)$99.88 (17)$131.20 
Forfeited(12)$46.51 (8)$110.81 
Unvested, end of the period699 $38.46 280 $104.17 

Nine Months Ended September 30,
20202019
RSU Equity Awards
(in thousands) (1)
Weighted Average Grant Date
Fair Value (1)
RSU Equity Awards
(in thousands) (1)
Weighted Average Grant Date
Fair Value (1)
Unvested, beginning of the period269 $102.48 210 $130.39 
Granted (2)
562 $21.07 188 $85.89 
Vested (3)
(120)$100.19 (96)$124.24 
Forfeited(12)$46.51 (22)$116.20 
Unvested, end of the period699 $38.46 280 $104.17 

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Table of Contents

(1)Shares and per share data have been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 - Stockholders’ Equity” for additional information.
(2)Includes 0 target performance-based RSU Equity Awards during the three months ended September 30, 2020 and 2019, respectively, and 111.2 thousand and 38.8 thousand during the nine months ended September 30, 2020 and 2019, respectively. The performance-based RSU Equity Awards granted during the nine months ended September 30, 2020 and 2019 will vest at a range of 0% to 300% and 0% to 200%, respectively.
Note 8 - Asset Retirement Obligations(3)The fair value of shares vested was $0.1 million and $0.8 million during the three months ended September 30, 2020 and 2019, respectively, and $1.4 million and $6.8 million for the nine months ended September 30, 2020 and 2019, respectively.

Grant activity for the nine months ended September 30,2020 and 2019primarily 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 0 shares ultimately vest. The grant date fair value of performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was 0 for the three months ended September 30, 2020 and 2019, respectively, and $3.4 million and $4.3 million for the nine months ended September 30, 2020 and 2019, respectively. The following table summarizes the assumptions
26

used to calculate the grant date fair value of the performance-based RSU Equity Awards granted during the nine months ended September 30, 2020 and 2019:
Performance-based AwardsJune 29, 2020January 31, 2020January 31, 2019
Expected term (in years)2.52.92.9
Expected volatility113.2 %54.8 %47.9 %
Risk-free interest rate0.2 %1.3 %2.4 %
Dividend yield0 %0 %0 %
As of September 30, 2020, unrecognized compensation costs related to unvested RSU Equity Awards were $16.4 million and will be recognized over a weighted average period of 1.9 years.
Cash-Settled RSU Awards
The table below summarizes the activity for restricted stock units that may be settled in cash (“Cash-Settled RSU Awards”) for the three and nine months ended September 30, 2020 and 2019:
Three Months Ended September 30,
20202019
Cash-Settled RSU Awards
(in thousands) (1)
Weighted Average Grant Date
Fair Value (1)
Cash-Settled RSU Awards
(in thousands) (1)
Weighted Average Grant Date
Fair Value (1)
Unvested, beginning of the period208 $67.20 103 $129.67 
Granted0 $0 0 $0 
Vested(1)$131.54 0 $0 
Did not vest at end of performance period(2)$133.95 0 $0 
Forfeited0 $0 (3)$132.86 
Unvested, end of the period205 $66.28 100 $129.58 

Nine Months Ended September 30,
20202019
Cash-Settled RSU Awards
(in thousands) (1)
Weighted Average Grant Date
Fair Value (1)
Cash-Settled RSU Awards
(in thousands) (1)
Weighted Average Grant Date
Fair Value (1)
Unvested, beginning of the period86 $124.22 66 $147.59 
Granted125 $29.76 44 $105.08 
Vested(3)$130.12 (2)$108.10 
Did not vest at end of performance period(3)$148.81 0 $0 
Forfeited0 $0 (8)$145.65 
Unvested, end of the period205 $66.28 100 $129.58 

(1)Shares and per share data have been retroactively adjusted to reflect the Company’s asset retirement obligations:1-for-10 reverse stock split effective August 7, 2020. See “Note 11 - Stockholders’ Equity” for additional information.
Grant activity primarily consisted of Cash-Settled RSU Awards to executives as part of the annual grant of long-term equity incentive awards that occurred in the first half of each of the years presented in the table above. These awards cliff vest after an approximate three-year performance period.
The Company’s outstanding Cash-Settled RSU Awards include the same performance-based vesting conditions as the performance-based RSU Equity Awards, which are described above. Additionally, the assumptions used to calculate the grant date fair value per Cash-Settled RSU Award granted for each of the respective periods presented are the same as the performance-based RSU Equity Awards presented above.
The following table summarizes the Company’s liability for Cash-Settled RSU Awards and the classification in the consolidated balance sheets for the periods indicated:
September 30, 2020December 31, 2019
(In thousands)
Other current liabilities$49 $966 
Other long-term liabilities275 2,089 
Total Cash-Settled RSU Awards$324 $3,055 
27

For The Nine Months Ended
September 30, 2017
Asset retirement obligations at January 1, 2017$6,661
Accretion expense523
Liabilities incurred224
Liabilities settled(227)
Revisions to estimate (a)
(2,177)
Asset retirement obligations at end of period5,004
Less: Current asset retirement obligations(1,841)
Long-term asset retirement obligations at September 30, 2017$3,163
As of September 30, 2020, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $0.5 million and will be recognized over a weighted average period of 2.0 years.

Share-Based Compensation Expense, Net
CertainShare-based compensation expense associated with the RSU Equity Awards, Cash-Settled RSU Awards, and cash-settled stock appreciation rights (“Cash SARs”), net of amounts capitalized, is included in “General and administrative” in the consolidated statements of operations. The following table presents share-based compensation expense (benefit), net for each respective period:
Three Months Ended September 30,Nine Months Ended
September 30,
2020201920202019
(In thousands)
RSU Equity Awards$3,009 $2,649 $10,169 $11,032 
Cash-Settled RSU Awards(566)(1,116)(1,966)238 
Cash SARs(1,005)0 (4,646)0 
1,438 1,533 $3,557 $11,270 
Less: amounts capitalized to oil and gas properties(1,532)(866)(3,862)(3,170)
Total share-based compensation expense (benefit), net($94)$667 ($305)$8,100 
See “Note 10 - Stock-Based Compensation” of the Notes to Consolidated Financial Statements in the 2019 Annual Report for details of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded inequity-based incentive plans. 
Note 11 - Stockholders’ Equity
Reverse Stock Split
On August 7, 2020, the Consolidated Balance Sheets at September 30, 2017 as long-term restricted investments were $3,362. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for severalBoard of Directors effected a reverse stock split of the Company’s oiloutstanding shares of common stock at a ratio of 1-for-10 and natural gas properties.

Note 9 - Equity Transactions

10% Series A Cumulative Preferred Stock (“Preferred Stock”)

Holdersreduced the total number of authorized shares of the Company’s Preferredcommon stock pursuant to an amendment to the Company’s Certificate of Incorporation, which was approved by the Company’s shareholders at the Company’s annual meeting of shareholders on June 8, 2020. The reverse stock split became effective as of the close of business on August 7, 2020. The Company’s common stock began trading on a split-adjusted basis on the New York Stock are entitledExchange (“NYSE”) at the market open on August 10, 2020. The par value of the common stock was not adjusted as a result of the reverse stock split.
The reverse stock split was intended to, receive, when,among other things, increase the per share trading price of the Company’s common shares to satisfy the $1.00 minimum closing price requirement for continued listing on the NYSE. As a result of the reverse stock split, each 10 pre-split shares of common stock outstanding were automatically combined into one issued and outstanding share of common stock. The fractional shares that resulted from the reverse stock split were canceled by paying cash in lieu of the fair value. The number of outstanding shares of common stock were reduced from 397,479,684 as of August 7, 2020 to 39,746,967 shares. The total number of shares of common stock that the Company is authorized to issue was reduced from 525,000,000 to 52,500,000 shares. All share and per share amounts, except par value per share, in the accompanying consolidated financial statements and notes thereto were retroactively adjusted for all periods presented to give effect to this reverse stock split, including reclassifying an amount equal to the reduction in par value of common stock to additional paid-in capital in the current period.
Note 12 - Leases
The Company determines if declared by our Boardan arrangement is a lease at inception of Directors, outthe 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 funds legally availablethe 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 payment of dividends, cumulative cash dividends at alease term. The Company’s operating leases typically do not provide an implicit interest rate, of 10.0% per annumtherefore, the Company utilizes its incremental borrowing rate to calculate the present value of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrearslease 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 last dayfinancing lease liability and the amortization of each March, June, Septemberthe 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 December when,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.
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The tables below, which present the components of lease costs and supplemental balance sheet information are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment.
The table below presents the components of the Company’s lease costs for the periods indicated:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In thousands)(In thousands)
Components of Lease Costs
Finance lease costs$252 $0 $1,380 $0 
Amortization of right-of-use assets (1)
233 0 1,253 0 
Interest on lease liabilities (2)
19 0 127 0 
Operating lease costs (3)
9,347 7,964 39,251 27,122 
Impairment of Operating lease ROU assets (4)
0 0 3,575 0 
Short-term lease costs (5)
19 293 1,736 3,640 
Variable lease costs (6)
116 0 190 0 
Total lease costs$9,734 $8,257 $46,132 $30,762 

(1)    Included as a component of “Depreciation, depletion and if declared by our Boardamortization” in the consolidated statements of Directors. Preferred Stock dividends were $1,824 and $1,824 foroperations.
(2)    Included as a component of “Interest expense, net of capitalized amounts” in the consolidated statements of operations.
(3)    For the three months ended September 30, 20172020 and 2016, respectively,2019, approximately $6.1 million and $5,471 and $5,471 for$7.6 million were costs associated with drilling rigs. For the nine months ended September 30, 20172020 and 2016, respectively.2019, approximately $29.7 million and $21.5 million were costs associated with drilling rigs. and were capitalized to “Evaluated properties” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations.

(4)    As a result of the downturn in economic conditions in conjunction with our ongoing effort to consolidate various office locations due to the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment. Upon evaluation, the Company recorded impairments of certain of its Operating lease ROU assets for the three and nine months ended September 30, 2020 of 0 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 Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018,table below presents supplemental balance sheet information for the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date.

Following a change of control in which the Company or the acquirer no longer have a class of common securities listed on a national exchange, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon such change of control, the holdersCompany’s leases as of the Preferred Stock haveperiods indicated:
September 30, 2020December 31, 2019
(In thousands)
Leases
Operating leases:
Operating lease ROU assets$29,519 $63,908 
Current operating lease liabilities$19,458 $42,858 
Long-term operating lease liabilities28,906 37,088 
Total operating lease liabilities$48,364 $79,946 
Financing leases:
Other property and equipment$1,285 $2,197 
Accumulated depreciation(395)(82)
Other property and equipment, net$890 $2,115 
Current financing lease liabilities$321 $1,334 
Long-term financing lease liabilities543 807 
Total financing lease liabilities$864 $2,141 
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The table below presents the option to convertweighted average remaining lease terms and weighted average discounts rates for the Preferred Stock into a number of sharesCompany’s leases for the period indicated:
As of September 30, 2020
Weighted Average Remaining Lease Term (In years)
Operating leases5.6
Financing leases3.1
Weighted Average Discount Rate
Operating leases5.5 %
Financing leases6.8 %
The table below presents the maturity of the Company’s common stock based on the value of the common stock on the date of the change of controllease liabilities as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on September 30, 2017, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $11.24 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 4.4 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above.

On February 4, 2016, the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of September 30, 2017, the Company had 1,458,948 shares of its Preferred Stock issued2020:
Operating LeasesFinancing Leases
(In thousands)
Remainder of 2020$8,375 $120 
202114,777 314 
20225,438 250 
20235,011 233 
20244,935 39 
Thereafter18,098 0 
   Total lease payments56,634 956 
Less imputed interest(8,270)(92)
   Total$48,364 $864 

Note 13 - Accounts Receivable, Net
September 30, 2020December 31, 2019
(In thousands)
Oil and natural gas receivables$81,364 $165,275 
Joint interest receivables15,700 39,114 
Other receivables17,240 6,610 
   Total114,304 210,999 
Allowance for doubtful accounts(1,768)(1,536)
   Total accounts receivable, net$112,536 $209,463 

Note 14 - Accounts Payable and outstanding.Accrued Liabilities

September 30, 2020December 31, 2019
(In thousands)
Accounts payable$104,665 $217,578 
Revenues payable148,387 145,816 
Accrued capital expenditures27,875 61,950 
Accrued interest49,370 36,295 
Accrued severance (1)
2,682 28,803 
   Total accounts payable and accrued liabilities$332,979 $490,442 
Commonstock 

On December 19, 2016, the Company completed an underwritten public offering of 40,000,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634,934. Proceeds from the offering were used to substantially fund the Ameredev Transaction, described in Note 2.

On September 6, 2016, the Company completed an underwritten public offering of 29,900,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $421,864. Proceeds from the offering were used to substantially fund the Plymouth Transaction, described in Note 2. 


Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Table of Contents

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

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Note 15 - Supplemental Cash Flow
Nine Months Ended September 30,
20202019
Supplemental cash flow information:
Interest paid, net of capitalized amounts$62,414 $0 
Income taxes paid0 0 
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases$35,919 $1,667 
Investing cash flows from operating leases16,956 25,455 
Non-cash investing and financing activities:
Change in accrued capital expenditures($72,782)($15,032)
Change in asset retirement costs1,208 (393)
ROU assets obtained in exchange for lease liabilities:
Operating leases$10,475 $2,588 

Note 16 - Subsequent Events
Hedging
Subsequent to September 30, 2020, the Company entered into the following derivative contracts:
For the Full Year
Oil contracts (WTI)of 2021
   Collar contracts
   Total volume (Bbls)4,769,525 
   Weighted average price per Bbl
   Ceiling (short call)$48.22 
   Floor (long put)$38.44 
For the Full Year
Natural gas contracts (Waha basis differential)of 2021
   Swap contracts
      Total volume (MMBtu)3,650,000 
      Weighted average price per MMBtu($0.25)
Additionally, subsequent to September 30, 2020, the Company terminated 1,908,675 Bbls of Argus WTI-Houston fixed price oil swaps at a weighted average price of $39.78 per Bbl, certain of which were terminated contemporaneously with entering into the WTI collars above. The Company also terminated 424,150 Bbls of ICE Brent fixed price oil swaps at a weighted average price of $40.00 per Bbl, resulting in neither cash receipts or payments.
Non-operated sale
On November 2, 2020, the Company closed the sale of substantially all of its non-operated assets. See “Note 3 - Acquisitions and Divestitures” for additional details.
Senior Note Exchange
On May 26, 2016,November 2, 2020, the Company entered into an Exchange Agreement (the “Exchange Agreement”) with certain holders (the “Holders”) of the Company’s 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”), and 6.375% Senior Notes due 2026 (the “6.375% Senior Notes”, and together with the 6.25% Senior Notes, 6.125% Senior Notes, and 8.25% Senior Notes, the “Senior Unsecured Notes”). Pursuant to the Exchange Agreement, the Company has agreed to exchange $286.0 million of aggregate principal amount of Senior Unsecured Notes held by the Holders for $158.5 million aggregate principal amount of newly issued 9,333,3339.00% Second Lien Senior Secured Notes due 2025 (the “New Notes”) at exchange ratios of $650, $575, $480 and $460 per $1,000 principal amount of 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes, and 6.375% Senior Notes, respectively, tendered (the “Exchange Ratios”).
Pursuant to the Exchange Agreement, the Company has also agreed to issue to the Holders approximately 1.16 million warrants exercisable for shares of common stock, to partially fund the Big Star Transaction, described in Note 2, atwith a term of 5 years and an assumed offeringexercise price of $11.74$5.60 per share, whichexercisable only on a net share settlement basis. The Holders and their affiliates may elect to include in the exchange up to an additional $104.0 million of Senior Unsecured Notes for New Notes at the Exchange Ratios set forth above. In the event the aggregate principal amount of Senior Unsecured Notes exchanged for New Notes at closing is the last reported sale price of our common stock on the New York Stock Exchange on that date.

On April 25, 2016,greater than $286.0 million, the Company completed an underwritten public offeringwill increase proportionally the number of 25,300,000 shareswarrants to be issued to the Holders up to a warrant eligibility cap of its common stock for total net proceeds (after$375.3 million. The maximum number of warrants issuable to the underwriter’s discounts and commissions and estimated offering expenses) ofHolders is approximately $205,869. Proceeds from the offering were used to fund the Big Star Transaction, described in Note 2, and other working interest acquisitions.1.76 million.

On March 9, 2016, the Company completed an underwritten public offering of 15,250,000 shares of its common stock for total net proceeds (after the underwriting discounts and estimated offering costs) of approximately $94,948. Proceeds from the offering were used to pay down the balance on the Company’s Credit Facility and for general corporate purposes.

Note 10 - Other

Operating leases

As of September 30, 2017 the Company had contracts for four horizontal drilling rigs (the “Cactus 1 Rig”, “Cactus 2 Rig”, “Cactus 3 Rig”, and “Independence Rig”). The contract terms, as amended in July 2017, of the Cactus 1 Rig and Cactus 2 Rig will end in January 2020 and February 2021, respectively. The contract terms, as amended in July 2017, of the Cactus 3 Rig that commenced drilling in mid-January 2017, will end in July 2018. Effective April 2017, the Company entered into a contract for the Independence Rig, which commenced drilling in July 2017. The contract terms of the Independence Rig will end in July 2019. The rig lease agreements include early termination provisions that obligate the Company to pay reduced minimum rentals for the remaining term of the agreement. These payments would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee.
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Callon Petroleum Company
Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per share and per unit data)
Table of Contents

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 productioncapital 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 recently completedrecent 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 volatilityeffects of excess supply of oil and natural gas prices;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;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 endangered species;hydraulic fracturing and water disposal wells;
•any increase in severance or similar taxes;
litigation relating to hydraulic fracturing, the climate and over-the-counter derivatives;
•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 on Form 10-K for the year ended December 31, 2016 (the  “2016 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto.

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Should one or more of thethese risks or uncertainties described hereinabove or in our 20162019 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. We specifically disclaim all responsibilityAdditional risks or uncertainties that are not currently known to publicly updateus, that we currently deem to be immaterial, or that could apply to any information contained in acompany 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 its entiretytime, engineering interpretation of the data, and therefore disclaim any resulting liability for potentially related damages.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.

AllExcept 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.

Callon Petroleum CompanyManagement’s Discussion and Analysis of Financial Condition and Results
Table of Contents33



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 20162019 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 reportQuarterly Report on Form 10-Q.

We are an independent oil and natural gas company establishedincorporated 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, development, exploration and exploitationdevelopment of unconventional, onshore, oil and natural gas reserveshigh-quality assets in the Permian Basin. Theleading 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 is located in West Texas, and southeastern New Mexico and is comprised of three primary sub-basins:as well as the Midland Basin,Eagle Ford Shale, which we entered into through the Delaware Basin, and the Central Basin Platform. We have historically been focused on the Midland Basin and recently entered the Delaware Basin through an acquisition completedCarrizo Acquisition in February 2017. 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.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. Our production was approximately 78%
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 22%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 forin the nine months ended September 30, 2017. On September 30, 2017, our net acreage positionUnited 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 was approximately 58,336 net acres. See Note 2Basin.
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 Footnotesrisk 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 Financial Statementswork site, being prepared to quarantine any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected), and, while at the work site, imposing safety protocols in accordance with the guidelines released by the Center for additional information about the Company’s acquisitions.


Operational Highlights

AllDisease Control. In addition, a large portion of our producing propertiesnon-operational employees are located innow working remotely, and we have established COVID-19 specific safety protocols for those working from the Permian Basin. Asoffice. 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 acquisitionoperations in order to preserve capital. We expect to fund the remainder of our 2020 capital expenditures with cash flows from operations and, horizontal development efforts,if necessary, borrowings under our senior secured revolving credit facility. As substantially all of our revenues are generated by the production and sale of hydrocarbons, if it became necessary to curtail or shut-in a significant portion of our production, grew 36%it could adversely affect our business, financial condition, results of operations, liquidity, and 53% forability to finance planned capital expenditures.
We have resumed production from wells that were curtailed as a result of field level economic decisions in the threesecond quarter, and nine months ended September 30, 2017, respectively,we do not forecast additional shut-ins at this time. We have various firm transportation agreements on pipelines in both the Permian Basin as well as the Eagle Ford Shale to help manage delivery risk of our production and provide us with the ability to deliver to various regional markets where we have the potential to receive more favorable pricing as compared to selling to purchasers at the same periods of 2016. Production increased to 2,074 MBOEwellhead. See “—Contractual Obligations” below for further details.
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Overview
Third Quarter 2020 Highlights
•Total production for the three months ended September 30, 20172020 was 102,029 Boe/d, an increase of 170% from 1,527 MBOEthe three months ended September 30, 2019, primarily due to production from the Carrizo Acquisition and new wells placed on production during 2020, partially offset by normal production decline.
•Operated drilling and completion activity for the three months ended September 30, 20162020 along with our drilled but uncompleted and increased to 5,934 MBOEproducing wells as of September 30, 2020 are summarized in the table below.    
Three Months Ended September 30, 2020As of September 30, 2020
DrilledCompletedDrilled But UncompletedProducing
RegionGrossNetGrossNetGrossNetGrossNet
Permian Basin— — 6 5.5 30 27.4 842 731.7 
Eagle Ford Shale— — 6 5.9 29 29.0 637 574.2 
Total— — 12 11.4 59 56.4 1,479 1,305.9 
▪Operational capital expenditures, inclusive of leasehold and seismic, for the nine months endedthird quarter of 2020 were $38.4 million, of which approximately 70% were in the Permian Basin with the remaining balance in the Eagle Ford. In response to the decline in commodity prices for oil and natural gas, we reduced activity relative to our original plan, including the suspension of all completion activity in April and transition to one active drilling rig in mid-May. We resumed activity during the third quarter and expect to operate three drilling rigs and one completion crew during the fourth quarter. Near-term operational activity will consist of drilling and completion activity in all three core asset areas in the fourth quarter while maintaining our drilled but uncompleted inventory. As a result, we currently forecast total operational capital expenditures to be approximately $500.0 to $510.0 million for the full year 2020. See “—Liquidity and Capital Resources—2020 Capital Plan and Outlook” for additional details.
•On August 7, 2020 and following approval by our shareholders at the June 8, 2020 annual meeting of shareholders of an amendment to our Certificate of Incorporation to effect a reverse stock split, our Board of Directors approved a reverse stock split of our common stock at a ratio of 1-for-10 and a reduction in the number of authorized shares of our common stock. Our common stock began trading on a split-adjusted basis on August 10, 2020 upon opening of the markets. See “Note 11 - Stockholders’ Equity” for additional information.
•On September 25, 2020, we entered into a Purchase and Sale Agreement to sell substantially all of our non-operated assets. We received $29.6 million on November 2, 2020 at closing, subject to post-closing adjustments, which was used to repay borrowings outstanding under our senior secured revolving credit facility. See “Note 3 - Acquisitions and Divestitures” for further discussion.
•On September 30, 2017 from 3,884 MBOE2020, we entered into the ORRI Transaction where we sold an undivided 2.0% (on an 8/8ths basis) overriding royalty interest, proportionately reduced to our net revenue interest, in and to our operated leases, excluding certain interests as defined in the Purchase and Sale Agreement, for the nine months endednet proceeds of approximately $135.8 million, net of transaction costs. See “Note 3 - Acquisitions and Divestitures” for further discussion.
•On September 30, 2016.2020, we issued $300.0 million in aggregate principal amount of Second Lien Notes and 7.3 million Warrants for proceeds, net of issuance costs, of approximately $288.6 million. See “Note 6 - Borrowings” and “Note 7 - Derivative Instruments and Hedging Activities” for further discussion.

•On September 30, 2020, we entered into the second amendment to our credit agreement governing the revolving credit facility which, among other things, reaffirmed the $1.7 billion borrowing base as a result of the fall 2020 scheduled redetermination. Also on September 30, 2020, we entered into the third amendment to our credit agreement governing the revolving credit facility which, among other things, (a) established a new borrowing base of $1.6 billion and reduced the elected commitments to $1.6 billion in connection with the issuance of the Second Lien Notes and Warrants and ORRI Transaction; (b) permitted the issuance of the $300.0 million of Second Lien Notes as contemplated by the Purchase Agreement without triggering a reduction in the borrowing base; (c) extended through the end of 2021 the time period during which Exchange Notes may be issued without triggering a reduction in the borrowing base; and (d) if the Second Lien Notes are outstanding at such time, caused the maturity of the revolving credit facility to spring forward to a date which is 182 days prior to the maturity of any of the 6.25% Senior Notes or the 6.125% Senior Notes, in each case, to the extent a principal amount of more than $100.0 million with respect to each such issuance is outstanding as of such date. See “Note 6 - Borrowings” for further discussion.
For•We recorded a loss available to common stockholders for the three months ended September 30, 2017, we drilled 13 gross (10.3 net) horizontal wells and completed 15 gross (13.2 net) horizontal wells. For2020 of $680.4 million, or $17.12 per diluted share, as compared to income available to common stockholders for the ninethree months ended September 30, 2017 we drilled 36 gross (28.9 net) horizontal wells and completed 34 gross (27.7 net) horizontal wells. As
35

2019 of September 30, 2017, we had 9 gross (6.4 net) horizontal wells awaiting completion.

As$47.2 million, or $2.07 per diluted share. The change from income available to common stockholders to loss available to common stockholders between the respective periods was driven primarily by the recording of September 30, 2017, we had 535 gross (418.1 net) working interest oil wells, three gross (0.1 net) royalty interest oil wells and no natural gas wells. A well is categorized as an oil well or a natural gas well based upon the ratioimpairment of oil to natural gas reserves on a BOE basis. However, most of our wells produce bothevaluated oil and natural gas.

Liquidity and Capital Resources

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities, and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties in addition to refinancing of debt instruments. We continue to evaluate other sources$685.0 million during the third quarter of capital to complement our cash flows from operations2020 as we pursue our long-term growth plans. Aswell as a loss on derivative contracts of September 30, 2017, there was no balance outstanding onapproximately $27.0 million during the Credit Facility, which has a borrowing basethird quarter of $650 million with a current elected commitment of $500 million. For the nine months ended September 30, 2017, cash and cash equivalents decreased $264.3 million to $61.6 million2020 compared to $325.9a gain on derivative contracts of approximately $21.8 million at September 30, 2016.  

Liquidity and cash flow
  Nine Months Ended September 30,
(in millions) 2017 2016
Net cash provided by operating activities $149.7
 $84.8
Net cash used in investing activities (935.6) (434.5)
Net cash provided by financing activities 194.5
 674.4
   Net change in cash and cash equivalents $(591.4) $324.7
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Operating activities. Forduring the nine months ended September 30, 2017, net cash provided by operating activities was $149.7 million compared to net cash provided by operating activitiesthird quarter of $84.8 million for the same period in 2016. The change was predominantly attributable to the following:

An increase in revenue;
A decrease on settlements of derivative contracts;
An increase in certain operating expenses related to acquired properties;  
An increase in payments in cash-settled restricted stock unit (“RSU”) awards; and
A change related to the timing of working capital payments and receipts.

Production, realized prices, and operating expenses are discussed below in 2019. See “—Results of Operations. See Notes 4, 5 and 6 in the Footnotes to the Financial StatementsOperations” below for additional information on our debt and a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation. further details.

Investing activities. For the nine months ended September 30, 2017, net cash used in investing activities was $935.6 million compared to $434.5 million for the same period in 2016. The change was predominantly attributable to the following:

A  $141.7 million increase in operational expenditures due to the transition from a two-rig to a three-rig program in January 2017 and from a three-rig to a four-rig program in July 2017; and
A $333.6 million increase attributable to acquisition activity. See Note 2 in the Footnotes to the Financial Statements for additional information on the Company’s acquisitions.

Our investing activities, on a cash basis, include the following for the periods indicated (in millions):
  Nine Months Ended September 30,
  2017 2016 $ Change
Operational expenditures $232.2
 $90.5
 $141.7
Seismic, leasehold and other 11.4
 10.0
 1.4
Capitalized general and administrative costs 11.9
 9.0
 2.9
Capitalized interest 11.7
 13.2
 (1.4)
   Total capital expenditures(a)
 267.2
 122.7
 144.5
       
Acquisitions 714.5
 302.1
 412.4
Acquisition deposits (46.1) 32.7
 (78.8)
Proceeds from the sale of mineral interest and equipment —
 (22.9) 22.9
   Total investing activities $935.6
 $434.5
 $501.1

(a)On an accrual (GAAP) basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the nine months ended September 30, 2017 were $277.0 million. Inclusive of capitalized general and administrative and interest costs, total capital expenditures for the nine months ended September 30, 2017 were $326.5 million.

General and administrative expenses and capitalized interest are discussed below in Results of Operations. See Note 2 in the Footnotes to the Financial Statements for additional information on acquisitions.

Financing activities. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Credit Facility, term debt and equity offerings. For the nine months ended September 30, 2017, net cash provided by financing activities was $194.5 million compared to $674.4 million for the same period of 2016. The change was predominantly attributable to the following:

A $201.7 million increase in borrowings on fixed-rate debt, resulting from the issuance of $200 million of 6.125% senior unsecured notes due 2024, including a premium issue price of 104.125% and net of payments of deferred financing costs
We had no issuance of common stock during the nine months ended September 30, 2017, a change of $722.7 million compared to the same period of 2016. 

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Net cash provided by financing activities includes the following for the periods indicated (in millions):
Nine Months Ended September 30, 2017
2017 2016 $ Change
Net borrowings on senior secured revolving credit facility$—
 $(40.0) $40.0
Issuance of 6.125% senior unsecured notes due 2024200.0
 —
 200.0
Premium on the issuance of 6.125% senior unsecured notes due 20248.3
 —
 8.3
Issuance of common stock—
 722.7
 (722.7)
Payment of preferred stock dividends(5.5) (5.5) —
Payment of deferred financing costs(7.2) (0.6) (6.6)
Tax withholdings related to restricted stock units(1.1) (2.2) 1.1
Net cash provided by financing activities$194.5
 $674.4
 $(479.9)

See Notes 4 and 9 in the Footnotes to the Financial Statements for additional information on our debt and equity offerings.

Capital Plan and Year to Date 2017 Summary

Our operational capital budget for 2017 was established at $350 million on an accrual, or GAAP, basis, inclusive of a transition from a three-rig program that commenced in January 2017 to a four-rig program in July 2017 that includes horizontal development activity at our recent Delaware Basin acquisition (see Note 2 in the Footnotes to the Financial Statements for information on this acquisition).

In addition to the operational capital budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $40 to $45 million for capitalized general and administrative expenses and capitalized interest expenses, both on an accrual, or GAAP, basis.

Operational capital expenditures on an accrual basis were $277.0 million for the nine months ended September 30, 2017. In addition to the operational capital expenditures, $14.0 million of capitalized general and administrative and $24.1 million of capitalized interest expenses were accrued in the nine months ended September 30, 2017. Based on current activity levels and service cost expectations, for full-year 2017 we estimate operational capital expenditures of approximately $375 million, net of the monetization of certain infrastructure assets, including natural gas gathering lines and saltwater disposal facilities.

Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of oil and natural gas. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, including commodity hedging strategy, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly.

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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 September 30,Nine Months Ended September 30,
 20202019Change% Change20202019Change% Change
Total production (1)
    
Oil (MBbls)5,8752,7253,150 116 %18,1188,4319,687 115 %
Natural gas (MMcf)10,2614,5385,723 126 %31,06414,18816,876 119 %
NGLs (MBbls)1,802—1,802 100 %5,166—5,166 100 %
Total barrels of oil equivalent (MBoe)9,3873,4815,906 170 %28,46110,79617,665 164 %
Total daily production (Boe/d)102,02937,83764,192 170 %103,87339,54664,327 163 %
Oil as % of total daily production63 %78 %    64 %78 %
Average realized sales price (excluding impact of settled derivatives)
      
Oil (per Bbl)$39.43$54.39($14.96)(28 %)$34.66$53.38($18.72)(35 %)
Natural gas (per Mcf)1.471.58(0.11)(7 %)1.071.79(0.72)(40 %)
NGLs (per Bbl)12.78—12.78 100 %10.77—10.77 100 %
Total (per Boe)$28.73$44.64($15.91)(36 %)$25.19$44.04($18.85)(43 %)
Revenues (in thousands)        
Oil$231,654$148,210$83,444 56 %$627,934$450,036$177,898 40 %
Natural gas15,0347,1687,866 110 %33,30525,4417,864 31 %
NGLs23,025—23,025 100 %55,627—55,627 100 %
Total$269,713$155,378$114,335 74 %$716,866$475,477$241,389 51 %
Benchmark prices (2)
WTI (per Bbl)$40.94$56.34($15.40)(27 %)$38.30$57.04($18.74)(33 %)
Henry Hub (per Mcf)2.132.38(0.25)(11 %)1.922.62(0.70)(27 %)
  Three Months Ended September 30,
  2017 2016 Change % Change
Net production:        
Oil (MBbls) 1,591
 1,153
 438
 38 %
Natural gas (MMcf) 2,900
 2,244
 656
 29 %
   Total (MBOE) 2,074
 1,527
 547
 36 %
Average daily production (BOE/d) 22,543
 16,598
 5,945
 36 %
   % oil (BOE basis) 77% 76%      
Average realized sales price:           
   Oil (Bbl) (excluding impact of cash settled derivatives) $46.10
 $42.58
 $3.52
 8 %
   Oil (Bbl) (including impact of cash settled derivatives) 45.24
 46.27
 (1.03) (2)%
   Natural gas (Mcf) (excluding impact of cash settled derivatives) $3.88
 $3.04
 $0.84
 28 %
   Natural gas (Mcf) (including impact of cash settled derivatives) 3.94
 2.97
 0.97
 33 %
   Total (BOE) (excluding impact of cash settled derivatives) $40.80
 $36.63
 $4.17
 11 %
   Total (BOE) (including impact of cash settled derivatives) 40.21
 39.30
 0.91
 2 %
Oil and natural gas revenues (in thousands):            
   Oil revenue $73,349
 $49,095
 $24,254
 49 %
   Natural gas revenue 11,265
 6,832
 4,433
 65 %
      Total $84,614
 $55,927
 $28,687
 51 %
Additional per BOE data:           
   Sales price (excluding impact of cash settled derivatives) $40.80
 $36.63
 $4.17
 11 %
      Lease operating expense (excluding gathering and treating expense) 5.08
 6.16
 (1.08) (18)%
      Gathering and treating expense 0.52
 0.36
 0.16
 44 %
      Production taxes 2.62
 2.28
 0.34
 15 %
   Operating margin $32.58
 $27.83
 $4.75
 17 %


  Nine Months Ended September 30,
  2017 2016 Change % Change
Net production:        
Oil (MBbls) 4,621
 2,993
 1,628
 54 %
Natural gas (MMcf) 7,878
 5,345
 2,533
 47 %
   Total (MBOE) 5,934
 3,884
 2,050
 53 %
Average daily production (BOE/d) 21,736
 14,175
 7,561
 53 %
   % oil (BOE basis) 78% 77%      
Average realized sales price:           
   Oil (Bbl) (excluding impact of cash settled derivatives) $47.23
 $39.12
 $8.11
 21 %
   Oil (Bbl) (including impact of cash settled derivatives) 46.32
 44.29
 2.03
 5 %
   Natural gas (Mcf) (excluding impact of cash settled derivatives) $3.81
 $2.75
 $1.06
 39 %
   Natural gas (Mcf) (including impact of cash settled derivatives) 3.84
 2.81
 1.03
 37 %
   Total (BOE) (excluding impact of cash settled derivatives) $41.84
 $33.93
 $7.91
 23 %
   Total (BOE) (including impact of cash settled derivatives) 41.17
 38.00
 3.17
 8 %
Oil and natural gas revenues (in thousands):            
   Oil revenue $218,242
 $117,093
 $101,149
 86 %
   Natural gas revenue 30,019
 14,677
 15,342
 105 %
      Total $248,261
 $131,770
 $116,491
 88 %
Additional per BOE data:           
   Sales price (excluding impact of cash settled derivatives) $41.84
 $33.93
 $7.91
 23 %
      Lease operating expense (excluding gathering and treating expense) 5.72
 5.96
 (0.24) (4)%
      Gathering and treating expense 0.47
 0.28
 0.19
 68 %
      Production taxes 2.72
 2.10
 0.62
 30 %
   Operating margin $32.93
 $25.59
 $7.34
 29 %

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(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.
36


Revenues

The following table reconcilesis intended to reconcile the change in oil, natural gas, NGLs, and total revenue for the respective periodsperiod presented by reflecting the effect of changes in volume and in the underlying commodity prices.prices:
Three Months Ended September 30Nine Months Ended September 30
OilNatural GasNGLsTotalOilNatural GasNGLsTotal
(In thousands)
Revenues for the periods ended in 2019$148,210 $7,168 $— $155,378 $450,036 $25,441 $— $475,477 
   Volume increase (decrease)171,325 9,040 23,025 203,390 517,080 30,261 55,627 602,968 
   Price increase (decrease)(87,881)(1,174)— (89,055)(339,182)(22,397)— (361,579)
   Net increase (decrease)83,444 7,866 23,025 114,335 177,898 7,864 55,627 241,389 
Revenues for the periods ended in 2020 (1)
$231,654 $15,034 $23,025 $269,713 $627,934 $33,305 $55,627 $716,866 
(in thousands) Oil Natural Gas Total
Revenues for the three months ended September 30, 2016 $49,095
 $6,832
 $55,927
Volume increase 18,650
 1,994
 20,644
Price increase 5,604
 2,439
 8,043
Net increase 24,254
 4,433
 28,687
Revenues for the three months ended September 30, 2017 $73,349
 $11,265
 $84,614
       
(in thousands) Oil Natural Gas Total
Revenues for the nine months ended September 30, 2016 $117,093
 $14,677
 $131,770
Volume increase 63,687
 6,966
 70,653
Price increase 37,462
 8,376
 45,838
Net increase 101,149
 15,342
 116,491
Revenues for the nine months ended September 30, 2017 $218,242
 $30,019
 $248,261


Commodity(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.

CommodityPrices
The prices for oil, and natural gas, can beand NGLs remain extremely volatile primarily due to the underlying supply and sometimes experience large fluctuationsdemand concerns as a result of relatively small changes in supply, weather conditions, economic conditions andCOVID-19 as well as the actions taken by the Organization of Petroleum Exporting CountriesOPEC and other countries and government actions.as described above. Prices of oil, and 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 our Credit Facility;the revolving credit facility; and
•the value of our oil and natural gas properties.

Period over Period Variances
The change in absolute value for the three and nine months ended September 30, 2020 as compared to September 30, 2019 can be primarily attributed to the Carrizo Acquisition which closed in December 2019. The Carrizo Acquisition had a material impact to our reported results of operations. In order to provide a more meaningful basis for comparison, we focused our discussion on per unit metrics and only expanded on changes in absolute value where appropriate.
Oil revenue 
For the three months ended September 30, 2020, oil revenues of $231.7 million increased $83.4 million, or 56%, compared to revenues of $148.2 million for the same period of 2019. The increase was primarily attributable to a 116% increase in production as a result of the Carrizo Acquisition and our development efforts. The increase in production was partially offset by the 28% decline in the average realized sales price which fell to $39.43 per Bbl from $54.39 per Bbl.
For the nine months ended September 30, 2020, oil revenues of $627.9 million increased $177.9 million, or 40%, compared to revenues of $450.0 million for the same period of 2019. The increase was primarily attributable to the 115% increase in production as a result of the Carrizo Acquisition and our development efforts. The increase was partially offset by a 35% decline in the average realized sales price which fell to $34.66 per Bbl from $53.38 per Bbl.
Natural gas revenue
For the three months ended September 30, 2020, natural gas revenues of $15.0 million increased $7.9 million, or 110%, compared to $7.2 million for the same period of 2019. The increase was primarily attributable to the 126% increase in production as a result of the Carrizo Acquisition and our development efforts. The increase was partially offset by a 7% decline in the average realized sale price which fell to $1.47 per Mcf from $1.58 per Mcf.
For the nine months ended September 30, 2020, natural gas revenues of $33.3 million increased $7.9 million, or 31%, compared to $25.4 million for the same period in 2019. The increase was primarily attributable to the 119% increase in production as a result of the Carrizo Acquisition and our development efforts. The increase was partially offset by a 40% decline in the average realize sales price, which fell to $1.07 per Mcf from $1.79 per Mcf.
37

NGL revenue
For the three and nine months ended September 30, 2017, the average NYMEX price for a barrel of oil was $48.202020, NGL revenues were $23.0 million and $49.36$55.6 million, or $12.78 and $10.77 per Bbl, compared to $44.94 and $41.47 per Bbl for the same periods of 2016, respectively. The NYMEX price for a barrel of oil for the three and nine months ended September 30, 2017 ranged from a low of $44.23 per Bbl to a high of $47.29 per Bbl and a low of $42.53 per Bbl to a high of $54.45 Bbl, respectively.

For the three and nine months ended September 30, 2017, the average NYMEX price for natural gas was $3.00 and $3.17 per MMBtu compared to $2.81 and $2.29 per MMBtu for the same periods of 2016. The NYMEX price for natural gas for the three and nine months ended September 30, 2017 ranged from a low of $2.77 per MMBtu to a high of $3.15 per MMBtu and a low of $2.56 per MMBtu to a high of $3.42 MMBtu, respectively.

໿
Oil revenue 

For the quarter ended September 30, 2017, oilno revenues of $73.3 million increased $24.2 million, or 49%, compared to revenues of $49.1 million for the same period of 2016.2019. The increase in oil revenue was primarily attributabledue to a 38% increase in production and an 8% increase in the average realized sales price,modification of certain of our natural gas processing agreements, which roseallowed us to $46.10 per Bbl intake title to NGLs resulting from the third quarterprocessing of 2017 from $42.58 per Bbl in the third quarter of 2016. The increase in production was attributable to 633 MBbls from wells placed on production asour natural gas. As a result, of our horizontal drilling programsales and 241 MBbls from producing wells added from our acquired properties. Offsetting these increases were normalreserve volumes, prices, and expected declines from our existing wells.  

For the nine months ended September 30, 2017, oil revenues of $218.2 million increased $101.1 million, or 86%, compared to revenues of $117.1 million for the same period of 2016. The increase in oil revenue was primarily attributable to a 54% increase in production and a 21% increase in the average realized sales price, which rose to $47.23 per Bbl for the nine months ended September 30, 2017 from $39.12 per Bbl for the same period of 2016. The increase in production was comprised of 1,612 MBbls attributable to wells placed on production as a result of our horizontal drilling program and 669 MBbls attributable to producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells.

See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.
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Natural gas revenue (including NGLs)

Natural gas revenues of $11.3 million increased $4.4 million, or 66%, during the three months ended September 30, 2017, compared to $6.8 million for the same period of 2016. The increase primarily relates to a 29% increase in natural gas volumes and a 28% increase in the average realized sales price, which rose to $3.88 per Mcf from $3.04 per Mcf, reflecting both natural gasNGLs and natural gas liquids prices. The increase in production was comprised of 735 MMcf attributableare presented separately for periods subsequent to wells placed on production as a result ofJanuary 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 horizontal drilling programsales and 287 MMcf attributable to producing wells added from our acquired properties. Offsetting these increases were normal expected declines from our existing wells.

Natural gasreserves volumes, prices, and revenues of $30.0 million increased $15.3 million, or 105%, during the nine months ended September 30, 2017, compared to $14.7 million for the same period of 2016. The increase primarily relates to a 47% increase inNGLs with natural gas volumes and a 39% increase in the average realized sales price, which rose to $3.81 per Mcf from $2.75 per Mcf, reflecting both natural gas and natural gas liquids prices. The increase in production was comprised of 1,785 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 806 MMcf attributable to producing wells added from our acquired properties. Offsetting these increases were normal expected declines from our existing wells.

See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.

gas.
Operating Expenses
Three Months Ended September 30,
PerPerTotal ChangeBoe Change
2020Boe2019Boe$%$%
(In thousands, except per Boe and % amounts)
Lease operating expenses$45,870 $4.89 $19,668 $5.65 $26,202 133 %($0.76)(13 %)
Production and ad valorem taxes16,110 1.72 11,866 3.41 4,244 36 %(1.69)(50 %)
Gathering, transportation and processing22,200 2.36 — — 22,200 100 %2.36 100 %
Depreciation, depletion and amortization114,201 12.17 56,130 16.12 58,071 103 %(3.95)(25 %)
General and administrative8,224 0.88 9,388 2.70 (1,164)(12 %)(1.82)(67 %)
Impairment of evaluated oil and gas properties684,956 72.97 — — 684,956 100 %72.97 100 %
Merger and integration2,465 0.26 5,943 1.71 (3,478)(59 %)(1.45)(85 %)
(in thousands, except per unit amounts) Three Months Ended September 30,
    Per   Per Total Change BOE Change
  2017 BOE 2016 BOE $ % $ %
Lease operating expenses $11,624
 $5.60
 $9,961
 $6.52
 $1,663
 17 % $(0.92) (14)%
Production taxes 5,444
 2.62
 3,478
 2.28
 1,966
 57 % 0.34
 15 %
Depreciation, depletion and amortization 28,525
 13.75
 17,303
 11.33
 11,222
 65 % 2.42
 21 %
General and administrative 7,259
 3.50
 7,891
 5.17
 (632) (8)% (1.67) (32)%
Accretion expense 131
 0.06
 187
 0.12
 (56) (30)% (0.06) (50)%
Acquisition expense 205
 nm
 456
 nm
 (251) nm
 nm
 nm
                 
(in thousands, except per unit amounts) Nine Months Ended September 30,
    Per   Per Total Change BOE Change
  2017 BOE 2016 BOE $ % $ %
Lease operating expenses $36,708
 $6.19
 $24,229
 $6.24
 $12,479
 52 % $(0.05) (1)%
Production taxes 16,168
 2.72
 8,153
 2.10
 8,015
 98 % 0.62
 30 %
Depreciation, depletion and amortization 79,172
 13.34
 49,318
 12.70
 29,854
 61 % 0.64
 5 %
General and administrative 18,894
 3.18
 19,755
 5.09
 (861) (4)% (1.91) (38)%
Settled share-based awards 6,351
 nm
 —
 nm
 6,351
 nm
 nm
 nm
Accretion expense 523
 0.09
 762
 0.20
 (239) (31)% (0.11) (55)%
Write-down of oil and natural gas properties —
 nm
 95,788
 nm
 (95,788) nm
 nm
 nm
Acquisition expense 3,027
 nm
 2,410
 nm
 617
 nm
 nm
 nm

nm = not meaningful
Nine Months Ended September 30,
PerPerTotal ChangeBoe Change
2020Boe2019Boe$%$%
(In thousands, except per Boe and % amounts)
Lease operating expenses$149,091 $5.24 $66,511 $6.16 $82,580 124 %($0.92)(15 %)
Production and ad valorem taxes46,151 1.62 33,810 3.13 12,341 37 %(1.51)(48 %)
Gathering, transportation and processing56,615 1.99 — — 56,615 100 %1.99 100 %
Depreciation, depletion and amortization384,594 13.51 179,275 16.61 205,319 115 %(3.10)(19 %)
General and administrative26,573 0.93 34,729 3.22 (8,156)(23 %)(2.29)(71 %)
Impairment of evaluated oil and gas properties1,961,474 68.92 — — 1,961,474 100 %68.92 100 %
Merger and integration26,362 0.93 5,943 0.55 20,419 344 %0.38 69 %

Lease operating expenses (“LOE”).expenses. These are daily costs incurred to extract oil, and natural gas together with the daily costs incurred toand NGLs and maintain our producing properties. Such costs also include maintenance, repairs, gas treating fees, salt water disposal, insurance and workover expenses related to our oil and natural gas properties. 

ForLease operating expenses for the three months ended September 30, 2017, LOE2020 increased by 17% to $11.6$45.9 million compared to $10.0$19.7 million for the same period of 2016. Contributing to the increase was $2.3 million related to oil and natural gas properties acquired during 2016 and the first half of 2017 (see Note 2 in the Footnotes to the Financial Statements). For the three months ended September 30, 2017, LOE per BOE decreased to $5.60 per BOE compared to $6.52 per BOE for the same period of 2016, which was primarily attributable to higher production volumes offset by an increase in cost as previously discussed.2019. The increase in productionlease operating expense was primarily attributablerelated to an increased numbera 170% increase in production over the comparative periods, which carries a variable component for each unit of producing wellsproduction.
Lease operating expense on a per unit basis decreased to $4.89 for the third quarter of 2020, which represents a decrease of $0.76 per Boe from our horizontal drilling program and acquisitions as discussed above. the third quarter of 2019. The lower per unit metric reflects the distribution of fixed costs spread over higher production volumes.

ForLease operating expenses for the nine months ended September 30, 2017, LOE2020 increased by 52% to $36.7$149.1 million compared to $24.2$66.5 million for the same period of 2016. Contributing to the2019. The increase in LOE was $10.1 millionprimarily related to oil and natural gas properties acquired during 2016 and the first half of 2017 (see Note 2 in the Footnotes to the Financial Statements). Excluding LOE related to these acquired properties, LOE increased
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by $2.4 million, or 10%, compared to the same period of 2016, which was primarily due to ana 164% increase in cost driven by higher production volumes from our legacy assets. Forover the comparative periods, which carries a variable component for each unit of production.
Lease operating expenses on a per unit basis decreased to $5.24 for the nine months ended September 30, 2017, LOE2020, which represents a decrease of $0.92 per BOE decreased to $6.19Boe from the comparable period in 2019. The lower per BOE compared to $6.24 per BOE forunit metric reflects the same perioddistribution of 2016, which was primarily attributable tofixed costs spread over higher production volumes offset by an increase in cost as previously discussed. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above. volumes.

Production taxes. Production taxes include severance and ad valorem taxes. In general, production taxes are directly related to commodity price changes; however, severance taxes are based upon current year commodity prices whereas ad valorem taxes are based upon prior year commodity prices. SeveranceProduction 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. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. In the counties where our production
38

is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties. 

We benefit from tax credits and exemptions in our various taxing jurisdictions where available.
Production and ad valorem taxes for the three months ended September 30, 20172020 increased by 57%36% to $5.4$16.1 million compared to $3.5$11.9 million for the same period of 2016. The2019, which is primarily related to a 74% increase wasin total revenues. Production and ad valorem taxes as a percentage of total revenues decreased to 6.0% for the third quarter of 2020 as compared to 7.6% of revenues for the same period of 2019 primarily due to an increase in severance taxes,the contribution of the Carrizo Acquisition assets which was attributable to the increase in revenue. Also contributing to the increase was an increase in ad valorem taxes, which was attributable to an increase in the valuation of our oil and gas properties by taxing jurisdictionscarried lower effective production tax rates as a result of an increased numberthe impacts of producing wells from our horizontal drilling program, acquisitions as discussed above,natural gas and an increase in commodity prices year over year. On a per BOE basis, production taxes for the three months ended September 30, 2017 increased by 15% compared to the same period of 2016.

NGL marketing deductions and exemptions.
Production and ad valorem taxes for the nine months ended September 30, 20172020 increased by 98%37% to $16.2$46.2 million compared to $8.2$33.8 million for the same period of 2016. The2019, which is primarily related to a 51% increase wasin total revenues. Production and ad valorem taxes as a percentage of total revenues decreased to 6.4% for the nine months ended September 30, 2020 as compared to 7.1% of revenues for the same period of 2019 primarily due to an increase in severance taxes,the contribution of the Carrizo Acquisition assets which was attributable to the increase in revenue. Also contributing to the increase was an increase in ad valorem taxes, which was attributable to an increase in the valuation of our oil and gas properties by taxing jurisdictionscarried lower effective production tax rates as a result of an increased numberthe impacts of producing wells from our horizontal drilling program, acquisitions as discussed above,natural gas and an increase in commodity prices year over year. On a per BOE basis, production taxesNGL marketing deductions and exemptions.
Gathering, transportation and processing expenses. Gathering, transportation and processing costs for the three and nine months ended September 30, 2017 increased by 30% compared to2020 were $22.2 million and $56.6 million, respectively. No expense was recognized for gathering, transportation and processing costs during the same period of 2016.2019. The change is due to the assumption of the processing agreements assumed in the Carrizo acquisition and certain contract modifications effective January 1, 2020. As such, the Company now records contractual fees associated with gathering, processing, treating and compression, as well as any transportation fees incurred to deliver the product to the purchaser, as gathering, transportation and processing expense. These fees were historically recorded as a reduction of revenue depending on when control transferred to the purchaser.

Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically expenseamortize those costs on a units-of-production basisan equivalent unit-of-production method based on proved oilproduction and natural gasestimated proved reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unevaluated properties, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteentwenty years. The following table sets forth the components of our depreciation, depletion and amortization for the periods indicated:

Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In thousands, except per Boe amounts)
AmountPer BoeAmountPer BoeAmountPer BoeAmountPer Boe
DD&A of evaluated oil and gas properties$111,699 $11.90 $56,000 $16.09 $377,353 $13.26 $178,673 $16.55 
Depreciation of other property and equipment836 0.09 2 — 2,908 0.10 17 0.01 
Amortization of other assets837 0.09 — — 1,832 0.06 — — 
Accretion of asset retirement obligations829 0.09 128 0.03 2,501 0.09 585 0.05 
DD&A$114,201 $12.17 $56,130 $16.12 $384,594 $13.51 $179,275 $16.61 
For the three and nine months ended September 30, 2017,2020, DD&A increased 65% to $28.5expense was $114.2 million and $384.6 million compared to $17.3$56.1 million and $179.3 million for the same periodperiods of 2016.2019. 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 is primarily attributable to a 36% increase in production and a 21% increase in our per BOE DD&A rate. Forof evaluated oil and gas properties for the three and nine months ended September 30, 2017,2020, resulted from production increases of 170% and 164%, respectively, which were partially offset by lower DD&A onrates between the periods. Those factors accounted for a $70.3 million increase and $14.6 million offsetting decrease, respectively, during the third quarter of 2020. Similarly, the increased production and decreased per unit basis increased to $13.75 per BOE compared to $11.33 per BOErate accounted for the same period of 2016. Thea $234.2 million increase is attributable to greater increases in our depreciable base and assumed future development costs to undeveloped proved reserves relative to the increase in our estimated proved reserve base. The increases in our depreciable base, assumed future development costs and estimated proved reserve base area result of additions made through our horizontal drilling efforts and acquisitions.

For$35.5 million offsetting decrease, respectively, for the nine months ended September 30, 2017,2020 as compared to 2019.
The decrease in DD&A increased 61% to $79.2 million compared to $49.3 million for the same period of 2016. The increase is primarily attributable to a 53% increase in production and a 5% increase in our per BOE DD&A rate. For the nine months ended September 30, 2017, DD&Arates on a per unit basis increased to $13.34 per BOE compared to $12.70 per BOE for the same period of 2016. The increase is attributable to our increased estimated proved reserves relative to our depreciable base and assumed future development costs related to undeveloped proved reserves asacross both periods was primarily a result of additions made throughthe Carrizo Acquisition which contributed to a significant increase in our horizontal drilling efforts and acquisitions, offset byproved reserves at a lower relative cost per Boe than our historical DD&A rate as well as the write downimpairment of evaluated oil and natural gas properties inthat was recognized during the first halfsecond quarter of 2016.2020.

General and administrative, net of amounts capitalized (“G&A”). These are costs incurred for overhead, including payroll and benefits for our corporate staff, severance and early retirement expenses, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, depreciation of corporate level assets, public company costs, vesting of equity and liability awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other professional services, and legal compliance.

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G&A for the three months ended September 30, 2017 decreased to $7.32020 was $8.2 million compared to $7.9$9.4 million for the samecomparative period in 2019 due to cost saving initiatives, which were partially offset by increased headcount of 2016. G&A expenses for the periods indicated include the following (in millions):
  Three Months Ended September 30,
  2017 2016 $ Change % Change
Recurring expenses        
   G&A $5.3
 $3.8
 $1.5
 39 %
   Share-based compensation 1.2
 0.8
 0.4
 50 %
   Fair value adjustments of cash-settled RSU awards 0.7
 3.4
 (2.7) (79)%
Total G&A expenses $7.2
 $8.0
 $(0.8) (10)%

combined companies. Additionally, G&A for the nine months ended September 30, 20172020 decreased to $18.9$8.2 million compared to $19.8 million for2019 primarily due to cost saving initiatives and a decrease in the same period of 2016. G&A expenses for the periods indicated include the following (in millions):
  Nine Months Ended September 30,
  2017 2016 $ Change % Change
Recurring expenses        
   G&A $15.4
 $11.6
 $3.8
 33 %
   Share-based compensation 3.1
 1.9
 1.2
 63 %
   Fair value adjustments of cash-settled RSU awards (0.1) 6.0
 (6.1) (102)%
Non-recurring expenses        
   Early retirement expenses 0.4
 —
 0.4
 100 %
   Early retirement expenses related to share-based compensation 0.1
 —
 0.1
 100 %
   Expense related to a threatened proxy contest —
 0.2
 (0.2) (100)%
Total G&A expenses $18.9
 $19.7
 $(0.8) (4)%

Settled share-based awards. In June 2017, the Company settled the outstanding share-based award agreements of its former Chief Executive Officer, resulting in $6.4 million recorded on the Consolidated Statements of Operations as Settled share-based awards.

Accretion expense. The Company is required to record the estimated fair value of liabilities for obligations associated with the retirementCash-Settled RSU Awards and Cash SARs.
Impairment of tangible long-lived assetsevaluated oil and the associated ARO costs. Interest is accreted on the present valuegas properties. We recognized impairments of the AROevaluated oil and reported as accretion expense within operating expenses in the consolidated statementsgas properties of operations.

Accretion expense related to our ARO decreased 30%$685.0 million and 31%$2.0 billion for the three and nine months ended September 30, 2017, compared2020, respectively, due primarily to declines in the same period12-Month Average
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Realized Price of 2016. Accretion expense generally correlatescrude oil. There was no impairment of evaluated oil and gas properties for the three or nine months ended September 30, 2019. See “Note 4 - Property and Equipment, Net” for further discussion.
Merger and integration expense. For the three and nine months ended September 30, 2020, the Company incurred expenses associated with the Company’s ARO, which was $5.0Carrizo Acquisition of $2.5 million at September 30, 2017and $26.4 million, respectively, as compared to $5.5$5.9 million atfor both the three and nine months ended September 30, 2016.2019. See Note 8 in the Footnotes to the Financial Statements“Note 3 - Acquisitions and Divestitures” for additional information regarding the Company’s ARO.

Acquisition expense. Acquisition expense for all periods was related to costsmerger with respect to our acquisition efforts in the Permian Basin. See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.

Write-down of oil and natural gas properties. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling.

For the comparative three months ended September 30, 2017 and 2016, the Company did not recognize write-downs of oil and natural gas properties. For the nine months ended September 30, 2017, the Company did not recognize a write-down of oil and natural gas properties compared to a write-down of $95.8 million for the nine months ended September 30, 2016, as a result of the ceiling test limitation. At September 30, 2017, the average prices used in determining the estimated future net cash flows from proved reserves were $49.81 per barrel of oil and $3.00 per Mcf of natural gas. If commodity prices were to decline, we could incur additional ceiling test write-downs in the future.

The table below presents the cumulative results of the full cost ceiling test along with various pricing scenarios to demonstrate the sensitivity of our full cost ceiling to changes in 12-month average oil and natural gas prices. This sensitivity analysis is as of September 30, 2017, and accordingly, does not consider drilling results, production, changes in oil and natural gas prices, and changes in future
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development and operating costs subsequent to September 30, 2017 that may require revisions to our proved reserve estimates and resulting estimated future net cash flows used in the full cost ceiling test.
  12-Month Average Prices   Excess (Deficit) of
Full Cost Ceiling Over Net Capitalized Costs
Pricing Scenarios Oil ($/Bbl) Natural gas ($/Mcf) (in thousands)
September 30, 2017 Actual $49.81
 $3.00
 $235,000
Combined price sensitivity      
Oil and natural gas +10% $54.79
 $3.30
 $496,690
Oil and natural gas -10% $44.83
 $2.70
 (26,166)
Oil price sensitivity      
Oil +10% $54.79
 $3.00
 $472,126
Oil -10% $44.83
 3.00
 (1,603)
Natural gas sensitivity      
Natural gas +10% $49.81
 $3.30
 $259,825
Natural gas -10% 49.81
 $2.70
 210,698


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Carrizo.
Other Income and Expenses and Preferred Stock Dividends
Three Months Ended September 30,Nine Months Ended September 30,
20202019$ Change% Change20202019$ Change% Change
(In thousands, except % amounts)
Interest expense$45,358 $18,869 $26,489 140 %$133,427 $58,929 $74,498 126 %
Capitalized interest(20,675)(18,130)(2,545)14 %(65,584)(56,711)(8,873)16 %
Interest expense, net of capitalized amounts24,683 739 23,944 3,240 %67,843 2,218 65,625 2,959 %
(Gain) loss on derivative contracts$27,038 ($21,809)$48,847 (224 %)($97,966)$31,415 ($129,381)(412 %)
(in thousands) Three Months Ended September 30,
  2017 2016 $ Change % Change
Interest expense, net of capitalized amounts $444
 $831
 $(387) (47)%
(Gain) loss on derivative contracts 14,162
 (5,135) 19,297
 (376)%
Other income (498) (122) (376) 308 %
   Total $14,108
 $(4,426)    
         
Income tax (benefit) expense $237
 $(62) $299
 (482)%
Preferred stock dividends (1,824) (1,824) —
 — %
         
(in thousands) Nine Months Ended September 30,
  2017 2016 $ Change % Change
Interest expense, net of capitalized amounts $1,698
 $10,502
 $(8,804) (84)%
(Gain) loss on derivative contracts (11,636) 11,281
 (22,917) (203)%
Other income (1,270) (299) (971) 325 %
   Total $(11,208) $21,484
    
         
Income tax (benefit) expense $1,026
 $(62) $1,088
 (1,755)%
Preferred stock dividends (5,471) (5,471) —
 — %

໿Interest expense, net of capitalized amounts.amounts. We finance a portion of our capital expenditures, acquisitions and working capital requirements capital expenditures and acquisitions with borrowings under our Credit Facilityrevolving credit facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees, and annual agency fees, and interest from our financing leases in interest expense.

Interest expense, net of capitalized amounts, incurred during the three months ended September 30, 2017 decreased $0.42020 increased $23.9 million to $24.7 million compared to $0.7 million for the same period of 2016. The decrease is primarily attributable to a $2.4 million increase in capitalized2019. Additionally, interest compared to the 2016 period, resulting from a higher average unevaluated property balance for the three months ended September 30, 2017 as compared to the same period of 2016. The increase in unevaluated property was primarily due to acquired properties. Offsetting the decrease was a $2.0 million increase in interest expense on our Credit Facility and term debt.

Interest expense, net of capitalized amounts, incurred during the nine months ended September 30, 2017 decreased $8.82020 increased $65.6 million to $67.8 million compared to $2.2 million for the same period of 2016. The decrease is primarily attributable to a $10.9 million increase in capitalized interest compared to the 2016 period, resulting from a higher average unevaluated property balance for the nine months ended September 30, 2017 as compared to the same period of 2016.2019. The increase in unevaluated property wasis primarily due to acquired properties. Offsettingdebt that was assumed as a result of the decrease was a $2.1 million increase in interest expense on our Credit Facility and term debt.Carrizo Acquisition.
See Notes 2 and 4 in the Footnotes to the Financial Statements for additional information on our acquisitions and debt.

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

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For the three months ended September 30, 2017, the net loss on derivative contracts was $14.2 million compared to a $5.1 million net gain for the same period of 2016. The net gain (loss)(gain) loss on derivative instruments for the periods indicated includes the following (in millions):following:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In thousands)
(Gain) loss on oil derivatives$16,606 ($24,722)($118,348)$34,798 
(Gain) loss on natural gas derivatives7,296 (1,323)18,819 (4,306)
(Gain) loss on NGL derivatives2,421 — 2,418 — 
(Gain) loss on contingent consideration arrangements715 4,236 (855)923 
(Gain) loss on derivative contracts$27,038 ($21,809)($97,966)$31,415 
Three Months Ended September 30,
2017 2016
Oil derivatives   
Net gain (loss) on settlements$(1.4) $4.2
Net gain (loss) on fair value adjustments(12.8) 0.7
Total gain (loss) on oil derivatives$(14.2) $4.9
Natural gas derivatives   
Net gain on settlements$0.1
 $(0.2)
Net gain (loss) on fair value adjustments(0.1) 0.4
Total gain (loss) on natural gas derivatives$—
 $0.2
   
Total gain (loss) on oil & natural gas derivatives$(14.2) $5.1
See “Note 7 - Derivative Instruments and Hedging Activities” and “Note 8 - Fair Value Measurements” of the Notes to our Consolidated Financial Statements for additional information.

Sales and cost of purchased oil and gas. For the three and nine months ended September 30, 2017, the net gain on derivative contracts was $11.62020, we recorded sales of purchased oil and gas of $20.3 million comparedand $21.5 million, respectively, and cost of purchased oil and gas of $21.3 million and $22.5 million, respectively, related to a $11.3 million net loss forcommodities purchased from third parties and sold to our customers. No sales or cost of purchased oil and gas occurred during the same periodperiods of 2016. The net gain (loss) on derivative instruments for the periods indicated includes the following (in millions):2019.
 Nine Months Ended September 30,
 2017 2016
Oil derivatives   
Net gain (loss) on settlements$(4.2) $15.5
Net gain (loss) on fair value adjustments14.6
 (26.9)
Total gain (loss) on oil derivatives$10.4
 $(11.4)
Natural gas derivatives   
Net gain on settlements$0.2
 $0.4
Net gain (loss) on fair value adjustments1.0
 (0.2)
Total gain on natural gas derivatives$1.2
 $0.2
   
Total gain (loss) on oil & natural gas derivatives$11.6
 $(11.2)
໿

See Notes 5 and 6 in the Footnotes to the Financial Statements for additional information on the Company’s derivative contracts and disclosures related to derivative instruments.

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.

The Company hadAs a result of the valuation allowance that we recorded against our net deferred tax assets, we did not have any income tax expense for the three months ended September 30, 2020, compared to $17.9 million for the same period of 2019. Additionally, we recorded income tax expense of $0.2$115.3 million for the nine months ended September 30, 2020, compared to $29.4 million for the same period of 2019. The increase in expense is due to the recording of a valuation allowance during the nine months ended September 30, 2020.
Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that
40

our net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at September 30, 2020, driven primarily by impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the three months ended September 30, 2020, which limits the ability to consider other subjective evidence such as our potential for future growth. Beginning in the second quarter of 2020 and continuing through the third quarter of 2020, based on the evaluation of the evidence available, we concluded that it is more likely than not that the net deferred tax assets will not be realized. As a result, we recorded a valuation allowance of $520.8 million, reducing the net deferred tax assets as of September 30, 2020 to zero. See “Note 9 - Income Taxes” for further discussion.
Preferred stock dividends. On July 18, 2019, we redeemed all outstanding shares of Preferred Stock, after which, the Preferred Stock was no longer deemed outstanding and dividends ceased to accrue. As such, we did not make any Preferred Stock dividend payments during the three and nine months ended September 30, 2020. Preferred Stock dividends of $0.4 million and $1.0$4.0 million were paid during the three and nine months ended September 30, 2019.
Liquidity and Capital Resources
Our primary uses of capital have historically been for the acquisition, development, and exploration of oil and natural gas properties. Our capital program could vary depending upon factors, including, but not limited to, continued depressed commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of oil and gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition of leases with drilling commitments and other factors. In addition, depending upon our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may, from time to time, seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or through privately negotiated transactions or otherwise. The amounts involved in any such transactions, individually or in aggregate, may be material.
Historically, our primary sources of capital have been cash flows from operations, borrowings under our revolving credit facility, proceeds from the issuance of debt securities and public equity offerings, and non-core asset dispositions. We regularly consider which resources, including debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and liquidity requirements.
Overview of Cash Flow Activities. For the nine months ended September 30, 2020, cash and cash equivalents decreased $2.8 million to $10.5 million compared to $13.3 million at December 31, 2019.
Nine Months Ended September 30,
20202019
(In thousands)
Net cash provided by operating activities$425,197 $338,738 
Net cash used in investing activities(449,667)(264,261)
Net cash provided by (used in) financing activities21,629 (79,219)
   Net change in cash and cash equivalents($2,841)($4,742)
Operating activities. For the nine months ended September 30, 2020, net cash provided by operating activities was $425.2 million compared to net cash provided by operating activities of $338.7 million for the same period in 2019. The change in operating activities was predominantly attributable to the following:
•An increase in revenue due to a 164% increase in production volumes predominantly as a result of the Carrizo Acquisition, which was partially offset by a decrease in realized pricing,
•An increase in the cash received from commodity derivative settlements, and
•An offsetting increase in operating expenses as a result of higher production volumes.
Production, realized prices, and operating expenses are discussed in Results of Operations. See “Note 7 - Derivative Instruments and Hedging Activities” and “Note 8 - Fair Value Measurements” for a reconciliation of the components of our derivative contracts and disclosures related to derivative instruments including their composition and valuation. 
41

Investing activities. For the nine months ended September 30, 2020, net cash used in investing activities was $449.7 million compared to $264.3 million for the same period in 2019.
Net cash used in investing activities for the following periods included:
Nine Months Ended September 30,
20202019$ Change
(In thousands)
Capital expenditures$567,746 $503,425 $64,321 
Acquisitions— 40,788 (40,788)
Proceeds from the sale of assets(149,818)(279,952)130,134 
Cash paid for settlements of contingent consideration arrangements, net40,000 — 40,000 
Other, net(8,261)— (8,261)
   Total investing activities$449,667 $264,261 $185,406 
Cash used in investing activities increased by approximately $185.4 million for the nine months ended September 30, 2020 compared to the same period in 2019 due primarily to lower proceeds from the sale of assets during the nine months ended September 30, 2020. In 2019, we sold certain non-core assets in the southern Midland Basin (the “Ranger Asset Divestiture”) for net cash proceeds of $244.9 million. See Note 3- “Acquisitions and Divestitures” for further discussion of this divestiture.
Financing activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our credit facility, term debt and equity offerings. For the nine months ended September 30, 2020, net cash provided by financing activities was $21.6 million compared to net cash used in financing activities of $79.2 million for the same period of 2019.
Net cash provided by (used in) financing activities for the following periods included:
Nine Months Ended September 30,
20202019$ Change
(In thousands)
Net borrowings on senior secured revolving credit facility($260,000)$— ($260,000)
Issuance of Second Lien Notes, net of discount264,730 — 264,730 
Issuance of warrants23,909 — 23,909 
Payment of deferred financing costs(6,312)(31)(6,281)
Payment of preferred stock dividends(1)
— (3,997)3,997 
Tax withholdings related to restricted stock units and other(698)(2,174)1,476 
Redemption of preferred stock— (73,017)73,017 
Net cash provided by (used in) financing activities$21,629 ($79,219)$100,848 

(1)    On July 18, 2019, we redeemed all outstanding shares of the Preferred Stock, after which, the Preferred Stock were no longer deemed outstanding and dividends on the Preferred Stock ceased to accrue.
See “Note 6 - Borrowings”, “Note 7 - Derivative Instruments and Hedging Activities” and “Note 10 - Share-based Compensation” for additional information on our debt, derivative instruments and equity transactions.
We have a senior secured revolving credit facility with a syndicate of lenders that, as of September 30, 2020, had a borrowing base of $1.6 billion, with an elected commitment amount of $1.6 billion, borrowings outstanding of $1.03 billion at a weighted average interest rate of 2.93%, and $24.2 million in letters of credit outstanding. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The revolving credit facility is secured by first preferred mortgages covering our major producing properties.
On May 7, 2020, we entered into the first amendment to our credit agreement governing the revolving credit facility and on September 30, 2020, we entered into the second and third amendments to our credit agreement governing the revolving credit facility. See “Note 6 - Borrowings” for further discussion of these amendments. On September 30, 2020, we issued $300.0 million in aggregate principal amount of Second Lien Notes and 7.3 million Warrants for proceeds, net of issuance costs, of approximately $288.6 million, which we used to repay borrowings outstanding under our senior secured revolving credit facility.
On November 2, 2020, we entered into a privately negotiated agreement with certain holders of our Senior Unsecured Notes to exchange $286.0 million of principal of our Senior Unsecured Notes for $158.5 million aggregate principal of newly issued 9.00% Second Lien Secured Notes due 2025 at a weighted average exchange ratio of approximately $555 per $1,000 of principal exchanged. See “Note 16 - Subsequent Events” for further discussion.
Even with the downturn in commodity prices as well as a drop in demand as a result of COVID-19, we expect to have sufficient liquidity to pay interest on our revolving credit facility, Second Lien Notes, and our Senior Unsecured Notes as well as to fund our
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development program. Upon a redetermination, if any borrowings in excess of the revised borrowing base were outstanding, we could be forced to immediately repay a portion of the borrowings outstanding under the credit agreement. Additionally, if the current commodity price environment were to persist for an extended period, our ability to remain in compliance with our restrictive financial covenants could be challenged. If we are unable to remain in compliance with our restrictive financial covenants, we could be subject to lender elections for default resolution.
Hedging. As of October 29, 2020, the Company had the following outstanding oil, natural gas and NGL derivative contracts:
For the RemainderFor the Full Year
Oil contracts (WTI)of 2020of 2021
   Swap contracts
   Total volume (Bbls)2,496,880 1,377,000 
   Weighted average price per Bbl$42.10 $42.00 
   Collar contracts
   Total volume (Bbls)1,501,440 9,423,275 
   Weighted average price per Bbl
   Ceiling (short call)$45.00 $46.78 
   Floor (long put)$35.00 $39.21 
   Short put contracts
      Total volume (Bbls)552,000 — 
      Weighted average price per Bbl$42.50 $— 
   Long call contracts
    Total volume (Bbls)460,000 — 
    Weighted average price per Bbl$67.50 $— 
   Short call contracts
   Total volume (Bbls)460,000 (1)4,825,300 (1)
   Weighted average price per Bbl$55.00 $63.62 
Oil contracts (Brent ICE)  
   Swap contracts
   Total volume (Bbls)— 848,300 
   Weighted average price per Bbl$— $37.36 
Collar contracts
Total volume (Bbls)— 730,000 
Weighted average price per Bbl
Ceiling (short call)$— $50.00 
Floor (long put)$— $45.00 
Oil contracts (Midland basis differential)
   Swap contracts
   Total volume (Bbls)1,380,000 3,022,900 
   Weighted average price per Bbl($1.89)$0.26 
Oil contracts (Argus Houston MEH basis differential)
   Swap contracts
   Total volume (Bbls)1,435,202 — 
   Weighted average price per Bbl$0.03 $— 
Oil contracts (Argus Houston MEH swaps)
   Swap contracts
   Total volume (Bbls)— 1,060,375 
   Weighted average price per Bbl$— $38.94 

(1)    Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps.
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For the RemainderFor the Full Year
Natural gas contracts (Henry Hub)of 2020of 2021
   Swap contracts
      Total volume (MMBtu)1,633,000 11,123,000 
      Weighted average price per MMBtu$2.05 $2.60 
   Collar contracts (three-way collars)
      Total volume (MMBtu)1,525,000 1,350,000 
      Weighted average price per MMBtu
         Ceiling (short call)$2.72 $2.70 
         Floor (long put)$2.45 $2.42 
         Floor (short put)$2.00 $2.00 
Collar contracts (two-way collars)
      Total volume (MMBtu)1,525,000 9,550,000 
      Weighted average price per MMBtu
         Ceiling (short call)$3.25 $3.04 
         Floor (long put)$2.67 $2.59 
   Short call contracts
      Total volume (MMBtu)2,013,000 7,300,000 
      Weighted average price per MMBtu$3.50 $3.09 
Natural gas contracts (Waha basis differential)
   Swap contracts
      Total volume (MMBtu)4,421,000 16,425,000 
      Weighted average price per MMBtu($0.91)($0.42)

For the RemainderFor the Full Year
NGL contracts (OPIS Mont Belvieu Purity Ethane)of 2020of 2021
   Swap contracts
      Total volume (Bbls)— 1,825,000 
      Weighted average price per Bbl$— $7.62 

2020 Capital Plan and Outlook
Our original operational capital budget for 2020 was established at $975.0 million, which included running an average of eight to nine drilling rigs and an average of three completion crews. In response to the decline in commodity prices for oil and natural gas, we reduced activity relative to our original plan, including the suspension of all completion activity in April and transition to one active drilling rig in mid-May. We resumed activity during the third quarter and expect to operate three drilling rigs and one completion crew during the fourth quarter. Near-term operational activity will consist of drilling and completion activity in all three core asset areas in the fourth quarter while maintaining our drilled but uncompleted inventory. As a result, we currently forecast total operational capital expenditures to be approximately $500.0 to $510.0 million for the full year 2020.
Our revenues, earnings, liquidity, and ability to deliver returns to our shareholders are substantially dependent on the prices we receive for, and our ability to develop our proved reserves. We monitor current and expected market conditions including the commodity price environment and our liquidity needs, and we may adjust our capital investment plan accordingly. Additionally, we may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to divest such assets on terms that are acceptable to us.
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Contractual Obligations
The following table includes our current contractual obligations and purchase commitments as of September 30, 2020:
Payments due by Period
October - December 20202021202220232024 and ThereafterTotal
(In thousands)
6.25% Senior Notes (1)
$— $— $— $650,000 $— $650,000 
6.125% Senior Notes (1)
— — — — 600,000 600,000 
8.25% Senior Notes (1)
— — — — 250,000 250,000 
6.375% Senior Notes (1)
— — — — 400,000 400,000 
Second Lien Notes (1)
300,000 300,000 
Senior secured revolving credit facility (2)
— — — — 1,025,000 1,025,000 
Interest expense and other fees related to debt commitments (3)
46,885 183,286 183,286 162,974 226,798 803,229 
Delivery commitments (4)
3,469 13,437 10,980 11,553 51,715 91,154 
Operating leases3,639 10,460 5,438 5,011 23,033 47,581 
Asset retirement obligations (5)
2,857 23 380 197 48,942 52,399 
Produced water disposal commitments (6)
7,687 21,355 18,321 10,775 12,983 71,121 
Drilling rig leases (7)
4,736 4,317 — — — 9,053 
Other commitments290 884 524 392 39 2,129 
Total contractual obligations$69,563 $233,762 $218,929 $840,902 $2,938,510 $4,301,666 

(1)Includes the outstanding principal amount only.
(2)The revolving credit facility has a maturity date of December 20, 2024, subject to springing maturity dates as discussed above. See “Note 6 – Borrowings” for additional information.
(3)Includes estimated cash payments on the 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes, 6.375% Senior Notes, Second Lien Notes, the revolving credit facility and commitment fees calculated based on the unused portion of lender commitments as of September 30, 2020, at the applicable commitment fee rate.  
(4)Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil and natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas.
(5)Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment.
(6)Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water.
(7)Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on September 30, 2020. The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our consolidated financial statements as incurred.
Critical Accounting Policies
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: use of estimates, oil and gas properties, oil and gas reserve estimates, derivative instruments, contingent consideration arrangements, income taxes, and commitments and contingencies. These policies and estimates are described in “Note 2 - Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our 2019 Annual Report. See “Note 7 - Derivative Instruments and Hedging Activities” and “Note 8 - Fair Value Measurements” for details of the contingent consideration arrangements. We evaluate subsequent events through the date the financial statements are issued.
Impairment of Evaluated Oil and Gas Properties
Capitalized costs, less accumulated amortization and related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (A) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures
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to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (B) the costs of unevaluated properties not being amortized, and (C) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. If the net capitalized costs exceed the cost center ceiling, the excess is recognized as an impairment of evaluated oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices in the future increase the cost center ceiling applicable to the subsequent period.
The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period (“12-Month Average Realized Price”). Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of derivative instruments because we elected not to meet the criteria to qualify our derivative instruments for hedge accounting treatment.
Due primarily to declines in the average realized prices for sales of oil and gas on the first calendar day of each month during the trailing 12-month period prior to September 30, 2020, the capitalized costs of oil and gas properties exceeded the cost center ceiling resulting in an impairment in the carrying value of evaluated oil and gas properties for the three and nine months ended September 30, 2017, compared2020 as summarized in the table below:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Impairment of evaluated oil and gas properties (in thousands)$684,956$—$1,961,474$—
Beginning of period 12-Month Average Realized Price ($/Bbl)$45.87$53.00$53.90$58.40
End of period 12-Month Average Realized Price ($/Bbl)$41.71$52.44$41.71$52.44
Percent decrease in 12-Month Average Realized Price(9 %)(1 %)(23 %)(10 %)
The decrease in the 12-Month Average Realized Price as of September 30, 2020 reduced our proved oil and gas reserve volumes by approximately 9.6 MMBoe, or less than 2% of our December 31, 2019 proved oil and gas reserves volumes. This reduction was primarily attributable to income tax benefitproved developed reserves of $0.1 millionproducing wells and $0.1 millionproved undeveloped reserves with shorter economic lives. Volumes associated with locations of proved undeveloped reserves that were no longer economic and removed from proved reserves as a result of the decrease in the 12-Month Average Realized Price as of September 30, 2020 were less than 0.5% of our December 31, 2019 proved oil and gas reserves. There were no impairments of evaluated oil and gas properties for the same periodsthree months ended March 31, 2020 or for the corresponding prior year periods.
Based on the first calendar day of 2016, respectively. each month oil and gas prices available for the 10 months ended October 1, 2020 and an estimate for the eleventh and twelfth months based on a quoted forward price, we anticipate recording an additional impairment in the carrying value of evaluated oil and gas properties in the fourth quarter of 2020 in the range of $500.0 million to $750.0 million. We currently estimate that the forecasted decrease in the 12-Month Average Realized Price as of December 31, 2020 will result in a reduction of our proved oil and gas reserve volumes of less than 2% of our December 31, 2019 proved oil and gas reserves volumes. This estimated reduction is primarily attributable to proved developed reserves of producing wells and proved undeveloped reserves with shorter economic lives. We estimate that volumes associated with locations of proved undeveloped reserves that would no longer be economic and would be removed from proved reserves would be less than 0.5% of our December 31, 2019 proved oil and gas reserves based on these estimated prices. Further impairments in subsequent quarters may occur if the trailing 12-month commodity prices continue to be lower than the comparable trailing 12-month commodity prices applicable to the first three quarters of 2020. Based on the current outlook for future commodity prices, we do not believe that those prices, if realized, would have a significant adverse impact on our proved oil and gas reserves volumes.
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The changetable below presents various pricing scenarios to demonstrate the sensitivity of our September 30, 2020 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-month average realized prices. The sensitivity analysis is as of September 30, 2020 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to September 30, 2020 that may require revisions to estimates of proved reserves.
12-Month Average
Realized Prices		Excess (deficit) of cost center ceiling over net book value, less related deferred income taxesIncrease (decrease) of cost center ceiling over net book value, less related deferred income taxes
Full Cost Pool ScenariosCrude Oil
($/Bbl)		Natural Gas
($/Mcf)		(In millions)(In millions)
September 30, 2020 Actual$41.71$1.08$—
Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%$46.04$1.28$715$715
Crude Oil and Natural Gas -10%$37.37$0.88($721)($721)
Crude Oil Price Sensitivity
Crude Oil +10%$46.04$1.08$674$674
Crude Oil -10%$37.37$1.08($672)($672)
Natural Gas Price Sensitivity
Natural Gas +10%$41.71$1.28$49$49
Natural Gas -10%$41.71$0.88($49)($49)
Income taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards.
Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that
our net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at September 30, 2020, driven primarily by impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the three months ended September 30, 2020, which limits the ability to consider other subjective evidence such as our potential for future growth. Beginning in the second quarter of 2020 and continuing through the third quarter of 2020, based on the evaluation of the evidence available, we concluded that it is primarily related tomore likely than not that the net deferred state income tax expense. The Company hadassets will not be realized. As a result, we recorded a valuation allowance of $109.8$520.8 million, reducing the net deferred tax assets as of September 30, 2017.2020 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 7 in the Footnotes to the Financial Statements“Note 9 - Income Taxes” for additional information.discussion.

Recently Adopted and Recently Issued Accounting Pronouncements
Preferred Stock dividends. Preferred Stock dividendsSee “Note 1 - Description of $1.8 millionBusiness and $5.5 millionBasis of Presentation” for the three and nine months ended September 30, 2017 were consistent with dividends for the same periods of 2016, respectively. Dividends reflect a 10% dividend rate. See Note 9 in the Footnotes to the Financial Statements for additional information.discussion.

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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 addressmitigate these risks through a program of risk management including the use of commodity derivative instruments.

Commodity price risk

The Company’sOur revenues are derived from the sale of its oil, and natural gas and NGL production. The prices for oil, and natural gas and NGLs remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions,government actions, economic
47

conditions, and government actions.weather conditions. From time to time, the Company enterswe enter into derivative financial instruments to manage oil, and natural gas and NGL price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes which we hedge through use of our derivative instruments varies from period to period; however, generallyperiod. Generally our objective is to hedge approximately 40%  to  60% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Oursenior secured revolving credit facility. Given the current commodity price environment, we have increased our hedge coverage for 2020 and 2021, however, our hedge policies and objectives may change significantly with movements in commodities prices or futures prices, in addition to modificationprices.
As of our capital spending plans related to operational activities and acquisitions.

The Company’s hedging portfolio, linked to NYMEX benchmark pricing, covers approximately 1,130 MBbls and 1,348 MMBtu of our expected oil and natural gas production, respectively,September 30, 2020, for the remainder of 2017. We2020, the Company had 3,998,320 Bbls of fixed price oil hedges across NYMEX WTI, ICE Brent and Argus WTI-Houston benchmarks. The Company also have commodity hedging contracts linked to Midlandhad 1,380,000 Bbls of WTI Midland-Cushing oil basis differentials relative to Cushing covering approximately 552 MBblshedges and 1,435,202 Bbls of our expectedWTI Houston-Cushing oil productionbasis hedges. Additionally, for the remainder of 2017.2020, the Company had 4,683,000 MMBtus of fixed price NYMEX natural gas hedges and 4,421,000 MMBtus of Waha natural gas basis hedges. See Note 5 in the Footnotes to the Financial Statements“Note 7 - Derivative Instruments and Hedging Activities” for a description of the Company’s outstanding derivative contracts atas of September 30, 2017, and derivative contracts established subsequent to that date.

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 counter-partycounterparty 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 (or call) options at a price lower than the floor price (or higher than the ceiling 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 put and call options,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. Though we had no balance outstanding on our Credit Facility atsenior secured revolving credit facility. As of September 30, 2017, based on a notional amount of $10 million2020, the Company had $1.03 billion outstanding under the senior secured revolving credit facility anwith a weighted average interest rate of 2.93%. An increase or decrease of 1%1.00% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $0.1 million.$10.3 million, based on the balance outstanding at September 30, 2020. See Note 4 to the Consolidated Financial Statements“Note 6 - Borrowings” for more information on the Company’s interest rates on its Credit Facility.

our senior secured revolving credit facility.
Counterparty and customer credit risk

The Company’s principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts.

The Company markets its oil, and natural gas and NGL production to energy marketing companies. We are subject to credit risk due to the concentration of our oil, and natural gas and NGL receivables with several significant customers. We do not require any of our customers to post
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collateral, and theThe inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. At September 30, 20172020 our total receivables from the sale of our oil and natural gas production were approximately $51.3 million.$81.4 million.

Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At September 30, 20172020 our joint interest receivables were approximately $30.0 million.

$15.7 million.
Our oil, and natural gas and NGL commodity derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. MostAll of the counterparties on our commodity derivative instruments currently in place are lenders under our Credit Facility.senior secured revolving credit facility. We are likely to enter into additional commodity derivative instruments with these or other lenders under our Credit Facility,senior secured revolving credit facility, representing institutions with investment grade ratings. We have existing International Swap Dealers Association MasterISDA Agreements (“ISDA Agreements”) with our commodity derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with
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rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a commodity derivative, whereby the party not in default may offset all commodity derivative liabilities owed to the defaulting party against all commodity derivative asset receivables from the defaulting party. At September 30, 2020, we had a net commodity derivative liability position of $32.6 million. 

Item 4. Controls and Procedures

Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2017.2020.

Changes in internal control over financial reporting. There were no changes to ourin internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscalthe third quarter of 2020 that have materially affected, or are reasonablereasonably likely to materially affect, ourthe Company’s 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. We do notWhile 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

ThereExcept 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 with respect to the risk factors disclosedset forth under the heading “Item 1A. Risk Factors” included in our 20162019 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.
None.

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 NumberDescriptionFormExhibitFiling Date
3.1
Certificate of Incorporation of the Company, as amended through May 12, 2016
10-Q3.111/03/2016
3.2
Certificate of Amendment to the Certificate of Incorporation of Callon, effective December 20, 2019
8-K3.111/20/2019
3.3
Certificate of Amendment to the Certificate of Incorporation of Callon, effective August 7, 2020
8-K3.18/07/2020
3.4
Amended and Restated Bylaws of the Company
10-K3.22/27/2019
4.18-K4.110/01/2020
4.28-K4.210/01/2020
4.38-K4.310/01/2020
10.18-K10.110/01/2020
10.28-K10.210/01/2020
10.38-K10.310/01/2020
10.4(a)(c)
10.5(a)(c)
Form of Callon Petroleum Company Officer Cash Incentive Award Agreement, adopted on September 30, 2020 under the 2020 Omnibus Incentive Plan
31.1(a)
Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)
31.2(a)
Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)
32.1(b)
Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b)
101.INS(a)XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH(a)Inline XBRL Taxonomy Extension Schema Document
101.CAL(a)Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF(a)Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB(a)Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE(a)Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104(a)Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
Exhibit NumberDescription
3.Articles of Incorporation and By-Laws
3.1
Certificate of Incorporation of the Company, as amended through May 12, 2016 (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q, filed on November 3, 2016)
3.2
Certificate of Designation of Rights and Preferences of 10% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.5 of the Company’s Form 8-A, filed on May 23, 2013)
3.3Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Registration Statement on Form S-4, filed on August 4, 1994, Reg. No. 33-82408)
4.Instruments defining the rights of security holders, including indentures
4.1Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company’s Registration Statement on Form S-4, filed on August 4, 1994, Reg. No. 33-82408)
4.2
Certificate for the Company’s 10% Cumulative Preferred Stock (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-A, filed on May 23, 2013)
4.3
Indenture of 6.125% Senior Notes Due 2024, dated as of October 3, 2016, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed on October 4, 2016)
4.4
Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated May 24, 2017, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed on May 24, 2017)
31.Section 13a-14 Certifications
31.1(a)
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2(a)
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.Section 1350 Certifications
32.1(b)
Section 1350 Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.(c)Interactive Data Files
(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.
(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)Pursuant to Rule 406T of Regulation S-T, these interactive data files are being furnished herewith and are not deemed filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability.
(c)Indicates management compensatory plan, contract, or arrangement.

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Callon Petroleum Company
Table of Contents


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


SignatureTitleDate
SignatureTitleDate
/s/ Joseph C. Gatto, Jr.President andNovember 6, 20173, 2020
Joseph C. Gatto, Jr.Chief Executive Officer


/s/ Correne S. LoefflerJames P. Ulm, IITreasurerSenior Vice President andNovember 6, 20173, 2020
Correne S. LoefflerJames P. Ulm, IIInterim Chief Financial Officer



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