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 June 30, 20172021
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
(281)589-5200
Registrant’s Telephone Number, Including Area Code
Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report
(Registrant’s Telephone Number, Including Area Code)

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


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 201,836,17246,290,613 shares of common stock outstanding as of November 1, 2017.July 30, 2021.




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
1927
3039
3141
Part II. Other Information
3241
3241
3241
3241
3241
3241
3342


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, butanesbutane 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.
•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 and share data)amounts)
(Unaudited)
 June 30, 2021December 31, 2020
ASSETS 
Current assets:  
Cash and cash equivalents$3,800 $20,236 
Accounts receivable, net200,246 133,109 
Fair value of derivatives14,941 921 
Other current assets24,876 24,103 
Total current assets243,863 178,369 
Oil and natural gas properties, full cost accounting method:  
  Evaluated properties, net2,517,783 2,355,710 
Unevaluated properties1,697,832 1,733,250 
Total oil and natural gas properties, net4,215,615 4,088,960 
Other property and equipment, net32,805 31,640 
Deferred financing costs20,670 23,643 
Other assets, net33,444 40,256 
Total assets$4,546,397 $4,362,868 
LIABILITIES AND STOCKHOLDERS’ EQUITY  
Current liabilities:  
Accounts payable and accrued liabilities$419,434 $341,519 
Fair value of derivatives331,702 97,060 
Other current liabilities62,668 58,529 
Total current liabilities813,804 497,108 
Long-term debt2,865,154 2,969,264 
Asset retirement obligations57,546 57,209 
Fair value of derivatives8,204 88,046 
Other long-term liabilities44,401 40,239 
Total liabilities3,789,109 3,651,866 
Commitments and contingencies00
Stockholders’ equity:  
Common stock, $0.01 par value, 78,750,000 and 52,500,000 shares authorized; 46,288,813 and 39,758,817 shares outstanding, respectively463 398 
Capital in excess of par value3,361,282 3,222,959 
Accumulated deficit(2,604,457)(2,512,355)
Total stockholders’ equity757,288 711,002 
Total liabilities and stockholders’ equity$4,546,397 $4,362,868 
 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 June 30,Six Months Ended
June 30,
 2021202020212020
Operating Revenues:  
Oil$333,442 $130,513 $600,487 $396,280 
Natural gas24,080 12,242 48,300 18,271 
Natural gas liquids36,625 14,479 65,982 32,602 
Sales of purchased oil and gas46,252 0 85,511 0 
Total operating revenues440,399 157,234 800,280 447,153 
Operating Expenses:    
Lease operating46,460 50,838 86,913 103,221 
Production and ad valorem taxes21,958 10,361 40,397 30,041 
Gathering, transportation and processing20,031 20,037 38,012 34,415 
Cost of purchased oil and gas49,249 0 90,166 0 
Depreciation, depletion and amortization83,128 138,930 154,115 270,393 
General and administrative11,065 10,024 27,864 18,349 
Impairment of evaluated oil and gas properties0 1,276,518 0 1,276,518 
Merger and integration0 8,067 0 23,897 
Other operating2,437 4,135 3,366 4,135 
Total operating expenses234,328 1,518,910 440,833 1,760,969 
Income (Loss) From Operations206,071 (1,361,676)359,447 (1,313,816)
Other (Income) Expenses:    
Interest expense, net of capitalized amounts24,634 22,682 49,050 43,160 
(Gain) loss on derivative contracts190,463 126,965 404,986 (125,004)
Other (income) expense3,147 2,157 (1,088)895 
Total other (income) expense218,244 151,804 452,948 (80,949)
Loss Before Income Taxes(12,173)(1,513,480)(93,501)(1,232,867)
Income tax benefit (expense)478 (51,251)1,399 (115,299)
Net Loss($11,695)($1,564,731)($92,102)($1,348,166)
Net Loss Per Common Share (1):
    
Basic($0.25)($39.41)($2.07)($33.97)
Diluted($0.25)($39.41)($2.07)($33.97)
Weighted Average Common Shares Outstanding (1):
   
Basic46,267 39,707 44,439 39,687 
Diluted46,267 39,707 44,439 39,687 
 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; inIn thousands)
໿(Unaudited)
CommonCapital inTotal
StockExcessAccumulatedStockholders’
Shares$of ParDeficitEquity
Balance at December 31, 202039,759 $398 $3,222,959 ($2,512,355)$711,002 
Net loss— — — (80,407)(80,407)
Restricted stock13 — 2,609 — 2,609 
Warrant exercises6,385 64 134,754 — 134,818 
Balance at March 31, 202146,157 $462 $3,360,322 ($2,592,762)$768,022 
Net loss— — — (11,695)(11,695)
Restricted stock132 1 960 — 961 
Balance at June 30, 202146,289 $463 $3,361,282 ($2,604,457)$757,288 
Retained
CommonCapital inEarningsTotal
StockExcess(AccumulatedStockholders’
Shares (1)
$of ParDeficit)Equity
Balance at December 31, 201939,659 $3,966 $3,198,076 $21,266 $3,223,308 
Net income— — — 216,565 216,565 
   Restricted stock14 1 3,141 — 3,142 
   Other— — (112)— (112)
Balance at March 31, 202039,673 $3,967 $3,201,105 $237,831 $3,442,903 
Net loss— — — (1,564,731)(1,564,731)
   Restricted stock66 7 3,205 — 3,212 
Balance at June 30, 202039,739 $3,974 $3,204,310 ($1,326,900)$1,881,384 
 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

(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


INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTSCallon Petroleum Company
Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)
 Six Months Ended June 30,
Cash flows from operating activities:20212020
Net loss($92,102)($1,348,166)
Adjustments to reconcile net loss to net cash provided by operating activities:  
Depreciation, depletion and amortization154,115 270,393 
Impairment of evaluated oil and gas properties0 1,276,518 
Amortization of non-cash debt related items, net4,508 1,145 
Deferred income tax expense0 115,299 
(Gain) loss on derivative contracts404,986 (125,004)
Cash received (paid) for commodity derivative settlements, net(127,571)101,301 
Non-cash expense (benefit) related to share-based awards12,887 (211)
Other, net4,511 3,656 
Changes in current assets and liabilities:
Accounts receivable(67,357)113,040 
Other current assets(7,423)(4,348)
Accounts payable and accrued liabilities26,714 (114,127)
Net cash provided by operating activities313,268 289,496 
Cash flows from investing activities:  
Capital expenditures(251,003)(418,688)
Acquisition of oil and gas properties(2,215)(11,881)
Proceeds from sale of assets31,611 10,079 
Cash paid for settlements of contingent consideration arrangements, net0 (40,000)
Other, net4,220 6,834 
Net cash used in investing activities(217,387)(453,656)
Cash flows from financing activities:  
Borrowings on Credit Facility736,500 4,775,500 
Payments on Credit Facility(846,500)(4,610,500)
Payment of deferred financing and debt exchange costs0 (6,011)
Tax withholdings related to restricted stock units(2,280)(388)
Other, net(37)(282)
Net cash provided by (used in) financing activities(112,317)158,319 
Net change in cash and cash equivalents(16,436)(5,841)
Balance, beginning of period20,236 13,341 
Balance, end of period$3,800 $7,500 


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.Acquisitions and Divestitures11.Stockholders’ Equity
4.Property and Equipment, Net12.Accounts Receivable, Net
5.13.Accounts Payable and Accrued Liabilities
6.14.Supplemental Cash Flow
7.15.Subsequent Events
8.

Note 1 - Description of Business and Basis of Presentation

Description of business

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 acquisition, development, explorationMidland and exploitationDelaware Basins, both of unconventional onshore, oil and natural gas reserveswhich are part of the larger Permian Basin in West Texas, as well as the Eagle Ford in South Texas. The Company’s primary operations in the Permian Basin. The Company’s operations to date have been predominantly focused on thereflect 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.
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.

Presentation
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. and Mississippi Marketing, Inc.

balances. These interim consolidated financial statements shouldhave been prepared pursuant to the rules and regulations of the SEC and therefore do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP. In the opinion of management, these financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim financial position, results of operations and cash flows. However, the results of operations for the periods presented are not necessarily indicative of the results of operations that may be readexpected for the full year. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications did not have a material impact on prior period financial statements.
Significant Accounting Policies
The Company’s significant accounting policies are described in conjunction with“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, 2016.2020 (“2020 Annual Report”) and are supplemented by the notes included in this Quarterly Report on Form 10-Q. The balance sheet at December 31, 2016 has been derived from the audited financial statements at that date. Operating results for the periods presented are not necessarily indicative of the results that mayand related notes included in this report should be expected for the year ended December 31, 2017.

In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairlyread in conjunction with 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.

2020 Annual Report.
Recently issued accounting policiesAdopted Accounting Standards

Income Taxes.In May 2014,December 2019, the FASB issuedreleased ASU No. 2014-09, Revenue from Contracts with Customers (“2019-12 (“ASU 2014-09”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 standard requires an entityASU also adds guidance to recognize revenuereduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of 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 entitled 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, theconsolidated group. The amended 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)
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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 periodsfiscal years beginning after December 15, 2016, including interim periods therein.2020, with early adoption permitted. The Company adopted this ASU 2019-12 on January 1, 2017 and it2021. The adoption of ASU 2019-12 did not have a material impact to the Company’s consolidated financial statements or disclosures.
Recently Issued Accounting Pronouncements
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on itsFinancial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial statements. reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. As of June 30, 2021, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to “Note 6 – Borrowings”
9

for discussion of the use of the adjusted LIBO rate in connection with borrowings under the Company’s senior secured revolving credit facility.
In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06”). ASU 2020-06 was issued to reduce the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The guidance is to be applied using either a modified retrospective or a fully retrospective method. ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. As of June 30, 2021, the Company has not elected to early adopt and is evaluating the impact on the Company’s accompanying consolidated financial statements and related disclosures.
Subsequent Events
The Company has elected to no longer estimate forfeitures.evaluates subsequent events through the date the financial statements are issued. See “Note 15 - Subsequent Events” for further discussion.

Note 2 - Acquisitions Revenue Recognition

Revenue from contracts with customers
Acquisitions were accounted for underThe Company recognizes oil, natural gas, and NGL production revenue at the acquisition method of accounting, which involves determining the fair valuepoint in time when control of the assets acquiredproduct transfers to the purchaser, which differs depending on the applicable contractual terms. Transfer of control also drives the presentation of gathering, transportation and liabilities assumedprocessing in the consolidated statements of operations. See “Note 3 - Revenue Recognition” of the Notes to Consolidated Financial Statements in the 2020 Annual Report for more information regarding the types of contracts under which oil, natural gas, and NGL production revenue is generated.
Accounts receivable from revenues from contracts with customers
Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at June 30, 2021 and December 31, 2020 of $148.7 million and $100.3 million, respectively, and are presented in “Accounts receivable, net” in the income approach.consolidated balance sheets.

Transaction price allocated to remaining performance obligations
2017acquisitionsFor the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Prior period performance obligations
On February 13, 2017,The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.
Note 3 - Acquisitions and Divestitures
Non-Core Asset Divestitures
During the second quarter of 2021, the Company completed the acquisitionits divestitures of 29,175 gross (16,688 net) acrescertain non-core assets in the Delaware Basin for aggregate net cash proceeds of $30.7 million, subject to post-closing adjustments. The divestitures were primarily locatedcomprised of natural gas producing properties in Wardthe Western Delaware Basin as well as a small undeveloped acreage position. The net proceeds were recognized as a reduction of evaluated oil and Pecos Counties, Texas from American Resource Development, LLC, forgas properties with no gain or loss recognized.
10

Note 4 - Property and Equipment, Net
As of June 30, 2021 and December 31, 2020, total cash considerationproperty and equipment, net consisted of $646,559, excluding customary purchase price adjustments (the “Ameredev Transaction”). the following:
June 30, 2021December 31, 2020
Oil and natural gas properties, full cost accounting method(In thousands)
Evaluated properties$8,206,124 $7,894,513 
Accumulated depreciation, depletion, amortization and impairments(5,688,341)(5,538,803)
Evaluated properties, net2,517,783 2,355,710 
Unevaluated properties
Unevaluated leasehold and seismic costs1,462,154 1,532,304 
Capitalized interest235,678 200,946 
Total unevaluated properties1,697,832 1,733,250 
Total oil and natural gas properties, net$4,215,615 $4,088,960 
Other property and equipment$62,258 $60,287 
Accumulated depreciation(29,453)(28,647)
Other property and equipment, net$32,805 $31,640 
The Company fundedcapitalized internal costs of employee compensation and benefits, including share-based compensation, directly associated with acquisition, exploration and development activities totaling $12.1 million and $8.9 million for the cash purchase price withthree months ended June 30, 2021 and 2020, respectively, and $23.3 million and $16.4 million for the net proceeds of an equity offering (see Note 9 for additional information regarding the equity offering). six months ended June 30, 2021 and 2020, respectively.
The Company obtainedcapitalized interest costs to unproved properties totaling $23.9 million and $20.9 million for the three months ended June 30, 2021 and 2020, respectively, and $47.9 million and $44.9 million for the six months ended June 30, 2021 and 2020, respectively.
Impairment of Evaluated Oil and Gas Properties
For the three and six months ended June 30, 2021, the capitalized costs of oil and gas properties did not exceed the cost center ceiling. As a result, the Company did 0t recognize an 82% average working interestimpairment in the carrying value of evaluated oil and gas properties acquiredfor the three and six months ended June 30, 2021.
Primarily due to declines in the Ameredev Transaction. In December 2016,average realized prices for sales of oil on the first calendar day of each month during the trailing 12-month period (“12-Month Average Realized Price”) prior to June 30, 2020, the capitalized costs of oil and gas properties exceeded the cost center ceiling resulting in connection withan impairment in the executioncarrying value of evaluated oil and gas properties for the three and six months ended June 30, 2020.
Details of the purchase and sale agreement12-Month Average Realized Price of crude oil for the Ameredev Transaction, the Company paid a depositthree and six months ended June 30, 2021 and 2020 are summarized 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:below:
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Impairment of evaluated oil and gas properties (in thousands)$0$1,276,518$0$1,276,518
Beginning of period 12-Month Average Realized Price ($/Bbl)$37.51$54.63$37.44$53.90
End of period 12-Month Average Realized Price ($/Bbl)$48.06$45.87$48.06$45.87
Percent increase (decrease) in 12-Month Average Realized Price28 %(16 %)28 %(15 %)
Note 5 - EarningsPer Share
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 9,333,333 shares of common stock (at an assumed offering price of $11.74Basic earnings (loss) per share which is computed by dividing net income (loss) by the last reported sale priceweighted average number 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)
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Unaudited pro forma financial statements

The following unaudited summary pro forma financial informationshares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted shares and unexercised warrants outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is for illustrative purposes onlyanti-dilutive. For the three and does not purport to represent whatsix months ended June 30, 2021 and 2020, the Company’s resultsCompany reported a net loss. As a result, the calculation 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:diluted weighted average common shares outstanding excluded all potentially dilutive common shares outstanding.
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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 management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest.

The properties associated with the Ameredev Transaction, Plymouth Transaction and Big Star Transaction have been commingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties.

Note 3 - EarningsPer Share

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

Three Months Ended June 30,Six Months Ended June 30,
 2021202020212020
(In thousands, except per share amounts)
Net Loss($11,695)($1,564,731)($92,102)($1,348,166)
Basic weighted average common shares outstanding (1)
46,267 39,707 44,439 39,687 
Dilutive impact of restricted stock (1)
0 0 0 0 
Dilutive impact of warrants (1)
0 0 0 0 
Diluted weighted average common shares outstanding (1)
46,267 39,707 44,439 39,687 
    
Net Loss Per Common Share (1)
Basic($0.25)($39.41)($2.07)($33.97)
Diluted($0.25)($39.41)($2.07)($33.97)
    
Restricted stock (1)(2)
140 432 882 424 
Warrants (1)(2)
1,066 481 3,433 481 
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)    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)    Shares excluded from the diluted earnings per share calculation as their effect would be anti-dilutive.
Note 46 - Borrowings

The Company’s borrowings consisted of the following at:໿following:
June 30, 2021December 31, 2020
(In thousands)
Senior Secured Revolving Credit Facility due 2024$875,000 $985,000 
9.00% Second Lien Senior Secured Notes due 2025516,659 516,659 
6.25% Senior Notes due 2023542,720 542,720 
6.125% Senior Notes due 2024460,241 460,241 
8.25% Senior Notes due 2025187,238 187,238 
6.375% Senior Notes due 2026320,783 320,783 
Total principal outstanding2,902,641 3,012,641 
Unamortized discount on Second Lien Notes(36,241)(41,820)
Unamortized premium on 6.25% Senior Notes2,454 2,917 
Unamortized premium on 6.125% Senior Notes2,805 3,236 
Unamortized premium on 8.25% Senior Notes2,859 3,240 
Unamortized deferred financing costs for Second Lien Notes(3,399)(3,931)
Unamortized deferred financing costs for Senior Notes(5,965)(7,019)
Total carrying value of borrowings (1)
$2,865,154 $2,969,264 
 September 30, 2017 December 31, 2016
Principal components:   
Senior secured revolving credit facility$—
 $—
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 $20.7 million and $23.6 million as of June 30, 2021 and December 31, 2020, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets.
Senior secured revolving credit facility
The Company has a senior secured revolving credit facility with a syndicate of lenders (the “Credit Facility”)

On May 31, 2017, the Company entered into the Sixth Amended that, as of June 30, 2021, had a borrowing base and Restated Credit Agreement toelected commitment amount of $1.6 billion, with borrowings outstanding of $875.0 million at a weighted-average interest rate of 2.61%, and letters of credit outstanding of $24.0 million. The credit agreement governing the Credit Facility provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”) are outstanding at such time (and which were retired in full on July 21, 2021), (ii) July 2, 2024 if the 6.125% Senior Notes due 2024 (the “6.125% Senior Notes”) are outstanding at such time, and (iii) if the 9.00% Second Lien Senior Secured Notes due 2025 (the “Second Lien Notes”) are outstanding at such time, the date which is 182 days prior to the maturity of any of the 6.25% Senior Notes or the 6.125% Senior Notes, in each case, to the extent a principal amount of more than $100.0 million with 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 Facility is secured by first preferred mortgages covering the Company’s major producing properties. Concurrent with the execution
12

The capitalized terms which are not defined in this description of the Sixth Amended and Restated Credit Agreement,Facility shall have the meaning given to such terms in the credit agreement.
On May 3, 2021, the Company entered into the fourth amendment to its credit agreement governing the Credit Facility’sFacility. The amendment, among other things, (a) reaffirmed the borrowing base increased to $650,000, butand the Company elected an aggregate commitment amount of $500,000. As$1.6 billion as a result of September 30, 2017, the Company continued to maintainspring 2021 scheduled redetermination; and (b) permits the prepayment, repurchase or redemption of Junior Debt (as defined in the credit agreement governing the Credit Facility’s borrowingFacility), which includes the Senior Unsecured Notes (as defined below) and the Second Lien Notes, in an aggregate amount not to exceed $100.0 million, commencing April 1, 2021, if certain liquidity and free cash flow thresholds are met.
Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base at $500,000.

As of September 30, 2017, there was no balance outstanding onrate for a base rate loan plus a margin between 1.00% to 2.00%, where the Credit Facility. For the quarter ended September 30, 2017, the Credit Facility had a weighted-average interestbase 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 of capitalized amounts” in the borrowing base.

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

On October 3, 2016, the Company issued $400,000 aggregate principal amountconsolidated statements 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 aggregate principal amount of its 6.125% Senior 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 proceeds of the offering, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $206,139. The Company used the proceeds, in part, to fund an acquisition completed on June 5, 2017 (discussed further in Note 2) and for general corporate purposes.

The Company may redeem the 6.125% Senior Notes in accordance with the following terms: (1) prior to October 1, 2019, 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% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to October 1, 2019, a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to 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 the date of the redemption, (i) of 104.594% of principal if the redemption occurs on or after October 1, 2019, but before October 1, 2020, and (ii) of 103.063% of principal if the redemption occurs on or after October 1, 2020, but before October 1, 2021, 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.

Following a change of control, each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the 6.125% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.

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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operations.
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: (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 SeptemberJune 30, 2017.2021.

The credit agreement and the indentures governing the Company’s 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes due 2025, and 6.375% Senior Notes due 2026 (together the “Senior Unsecured Notes”) also place restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
The credit agreement and indentures are subject to customary events of default. If an event of default occurs and is continuing, the holders or lenders may elect to accelerate amounts due (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).
Note 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 June 30, 2021, the Company has outstanding commodity derivative instruments with 15 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.
13

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.

Contingent consideration arrangements
Ranger Divestiture. In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Divestiture”). The Company’s Ranger Divestiture provided for potential contingent consideration to be received by the Company if commodity prices exceed specified thresholds. See “Note 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 PresentationRemaining Contingent Receipt - Aggregate Limit
Remaining Potential Settlement2021Greater than $60/Bbl, less than $65/Bbl$9,000Equal to or greater than $65/Bbl$20,833(2)(2)$20,833 
(1)    The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group.
(2)    Cash received for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the divestiture date fair value with any excess classified as cash flows from operating activities. If either of the commodity price thresholds is reached in 2021, $8.5 million of the contingent receipt will be presented in cash flows from financing activities with the remainder presented in cash flows from operating activities in the first quarter of 2022.
As a result of the acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”) in late 2019 (the “Carrizo Acquisition”), the Company assumed all contingent consideration arrangements previously entered into by Carrizo. Only one of the contingent consideration arrangements remains and is summarized below:
Contingent ExL Consideration
Year
Threshold (1)
Period
Cash Flow
Occurs		Statement of
Cash Flows Presentation		Contingent
Payment -
Annual		Remaining Contingent
Payments -
Aggregate Limit
(In thousands)
Remaining Potential Settlement2021$50.00 (2)(2)($25,000)($25,000)
(1)    The price used to determine whether the specified threshold for the year has been met is the average daily settlement price of the front month NYMEX WTI futures contract as published by the CME Group.
(2)    Cash paid for settlements of contingent consideration arrangements are classified as cash flows from investing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. If the commodity price threshold is reached in 2021, $19.2 million of the contingent payment will be presented in cash flows from investing activities with the remainder presented in cash flows from operating activities in the first quarter of 2022.
Warrants
On September 30, 2020, the Company issued $300.0 million in aggregate principal amount of its Second Lien Notes and warrants for 7.3 million shares of the Company’s common stock exercisable only on a net share settlement basis (the “September 2020 Warrants”). The Company determined that the September 2020 Warrants were required to be accounted for as a derivative instrument. The Company recorded the September 2020 Warrants as a liability on its consolidated balance sheet measured at fair value as a component of “Fair value of derivatives” with gains and losses as a result of changes in the fair value of the September 2020 Warrants recorded as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 8 - Fair Value Measurements” for additional details.
14

In February 2021, holders of the September 2020 Warrants provided notice and exercised all of their outstanding warrants. As a result of this exercise, the Company issued 5.6 million shares of its common stock in exchange for all of the outstanding September 2020 Warrants. The exercise of the September 2020 Warrants resulted in settlement of the associated derivative liability, which was $134.8 million at the time of exercise, and the fair value of the September 2020 Warrants at exercise, less the par value of the shares of common stock issued in the exercise, was reclassified to “Capital in excess of par value” in the consolidated balance sheets.
Derivatives not designated as hedging instruments

The Company records its derivative 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 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 June 30, 2021
Presented without As Presented with
Effects of NettingEffects of NettingEffects of Netting
(In thousands)
Assets
Commodity derivative instruments$79,820 ($79,564)$256 
Contingent consideration arrangements14,685 0 14,685 
Fair value of derivatives - current$94,505 ($79,564)$14,941 
Commodity derivative instruments$5,850 ($5,850)$0 
Contingent consideration arrangements0 0 0 
Other assets, net$5,850 ($5,850)$0 
Liabilities   
Commodity derivative instruments (1)
($387,162)$79,564 ($307,598)
Contingent consideration arrangements(24,104)0 (24,104)
Fair value of derivatives - current($411,266)$79,564 ($331,702)
Commodity derivative instruments($14,054)$5,850 ($8,204)
Contingent consideration arrangements0 0 0 
Fair value of derivatives - non-current($14,054)$5,850 ($8,204)
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Table of Contents

 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,(1)    Includes approximately $8.3 million of deferred premiums, which the Company recordedwill pay as the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts:
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Oil derivatives       
Net gain (loss) on settlements$(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)

applicable contracts settle.
15

As of December 31, 2020
Presented without As Presented with
Effects of NettingEffects of NettingEffects of Netting
(In thousands)
Assets
Commodity derivative instruments$21,156 ($20,235)$921 
Contingent consideration arrangements0 0 0 
Fair value of derivatives - current$21,156 ($20,235)$921 
Commodity derivative instruments$0 $0 $0 
Contingent consideration arrangements1,816 0 1,816 
Other assets, net$1,816 $0 $1,816 
Liabilities   
Commodity derivative instruments (1)
($117,295)$20,235 ($97,060)
Contingent consideration arrangements0 0 0 
Fair value of derivatives - current($117,295)$20,235 ($97,060)
Commodity derivative instruments$0 $0 $0 
Contingent consideration arrangements(8,618)0 (8,618)
September 2020 Warrants liability(79,428)0 (79,428)
Fair value of derivatives - non-current($88,046)$0 ($88,046)
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)    Includes approximately $11.2 million of deferred premiums, which the Company will pay as the applicable contracts settle.
The components of “(Gain) loss on derivative contracts” are as follows for the respective periods:
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
(In thousands)
(Gain) loss on oil derivatives$177,033 $122,369 $326,594 ($134,954)
(Gain) loss on natural gas derivatives12,816 4,695 15,513 11,524 
(Gain) loss on NGL derivatives3,734 (4)4,872 (4)
(Gain) loss on contingent consideration arrangements(3,120)(95)2,617 (1,570)
(Gain) loss on September 2020 Warrants liability0 0 55,390 0 
(Gain) loss on derivative contracts$190,463 $126,965 $404,986 ($125,004)
The components of “Cash received (paid) for commodity derivative settlements, net” and “Cash paid for settlements of contingent consideration arrangements, net” are as follows for the respective periods:
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
(In thousands)
Cash flows from operating activities    
Cash received (paid) on oil derivatives($82,413)$100,470 ($122,360)$98,693 
Cash received (paid) on natural gas derivatives(1,906)(1,782)(3,275)2,608 
Cash received (paid) on NGL derivatives(1,090)0 (1,936)0 
Cash received (paid) for commodity derivative settlements, net($85,409)$98,688 ($127,571)$101,301 
Cash flows from investing activities    
Cash paid for settlements of contingent consideration arrangements, net$0 $0 $0 ($40,000)
16

Derivative positions

Listed in the tables below are the outstanding oil, and natural gas and NGL derivative contracts as of SeptemberJune 30, 2017:  2021:
 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)

For the RemainderFor the Full YearFor the Full Year
Oil contracts (WTI)of 2021of 2022of 2023
   Swap contracts
   Total volume (Bbls)1,104,000 1,372,500 0 
   Weighted average price per Bbl$42.10 $60.00 $0 
   Collar contracts
   Total volume (Bbls)5,522,775 3,725,000 0 
   Weighted average price per Bbl
   Ceiling (short call)$49.16 $64.84 $0 
   Floor (long put)$40.71 $52.66 $0 
   Short call contracts
   Total volume (Bbls)2,432,480 (1)0 0 

   Weighted average price per Bbl$63.62 $0 $0 
Short call swaption contracts
   Total volume (Bbls)0 1,825,000 (2)1,825,000 (2)
   Weighted average price per Bbl$0 $52.18 $72.00 
Oil contracts (Brent ICE)  
   Swap contracts
   Total volume (Bbls)0 (3)0 0 
   Weighted average price per Bbl$0 $0 $0 
Collar contracts
Total volume (Bbls)368,000 0 0 
Weighted average price per Bbl
Ceiling (short call)$50.00 $0 $0 
Floor (long put)$45.00 $0 $0 
Oil contracts (Midland basis differential)
   Swap contracts
   Total volume (Bbls)1,504,400 0 0 
   Weighted average price per Bbl$0.25 $0 $0 
Oil contracts (Argus Houston MEH)
   Collar contracts
   Total volume (Bbls)0 452,500 0 
   Weighted average price per Bbl
Ceiling (short call)$0 $63.15 $0 
Floor (long put)$0 $51.25 $0 
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 and three-way collars.
(2)    The 2022 and 2023 short call swaption contracts have exercise expiration dates of December 31, 2021 and December 30, 2022, respectively.
(3)    In February 2021, the Company entered into certain offsetting ICE Brent swaps to reduce its exposure to rising oil prices. Those offsetting swaps resulted in a locked-in loss of approximately $2.9 million, of which $1.6 million will be settled in the third quarter of 2021 with the remaining $1.3 million to be settled in the fourth quarter of 2021.
17

 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 2021of 2022
   Swap contracts
      Total volume (MMBtu)7,301,000 2,140,000 
      Weighted average price per MMBtu$2.61 $2.65 
Collar contracts
      Total volume (MMBtu)3,680,000 3,600,000 
      Weighted average price per MMBtu
         Ceiling (short call)$2.80 $3.75 
         Floor (long put)$2.50 $2.83 
   Short call contracts
      Total volume (MMBtu)3,680,000 (1)0 
      Weighted average price per MMBtu$3.09 $0 
Natural gas contracts (Waha basis differential)
   Swap contracts
      Total volume (MMBtu)8,280,000 5,475,000 
      Weighted average price per MMBtu($0.42)($0.21)

Subsequent event(1)    Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.

For the RemainderFor the Full Year
NGL contracts (OPIS Mont Belvieu Purity Ethane)of 2021of 2022
   Swap contracts
      Total volume (Bbls)920,000 0 
      Weighted average price per Bbl$7.62 $0 
The following derivative contracts were executed subsequent to September 30, 2017:໿
 For the Remainder of For the Full Year of
Oil contracts (Midland basis differential)2017 2018
Swap contracts   
Volume (MBbls)—
 546
Weighted average price per Bbl$—
 $(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 approximates fair value becauseas the borrowings bear interest at variable rates were variable and are reflective of market rates. The following table presents the principal amounts of the Company’s Second Lien Notes and Senior Unsecured Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “Note 6 - Borrowings” for further discussion.
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.

June 30, 2021December 31, 2020
Principal AmountFair ValuePrincipal AmountFair Value
(In thousands)
Second Lien Notes$516,659 $561,867 $516,659 $470,160 
6.25% Senior Notes542,720 542,720 542,720 344,627 
6.125% Senior Notes460,241 444,133 460,241 260,036 
8.25% Senior Notes187,238 184,429 187,238 100,172 
6.375% Senior Notes320,783 303,140 320,783 161,995 
Total$2,027,641 $2,036,289 $2,027,641 $1,336,990 
18
Callon Petroleum Company
Notes to the Consolidated Financial Statements

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

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.sheets. The following methods and assumptions were used to estimate fair value:

Commodity derivative instruments. The fair value of commodity derivative instruments is derived using 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.
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:basis as of June 30, 2021 and December 31, 2020:
June 30, 2021
Level 1Level 2Level 3
(In thousands)
Assets   
Commodity derivative instruments$0 $256 $0 
Contingent consideration arrangements0 14,685 0 
Liabilities   
Commodity derivative instruments (1)
0 (315,802)0 
Contingent consideration arrangements0 (24,104)0 
Total net assets (liabilities)$0 ($324,965)$0 
   
December 31, 2020
Level 1Level 2Level 3
(In thousands)
Assets   
Commodity derivative instruments$0 $921 $0 
Contingent consideration arrangements0 1,816 0 
Liabilities   
Commodity derivative instruments (2)
0 (97,060)0 
Contingent consideration arrangements0 (8,618)0 
September 2020 Warrants0 0 (79,428)
Total net assets (liabilities)$0 ($102,941)($79,428)
(1)    Includes approximately $8.3 million of deferred premiums which the Company will pay as the applicable contracts settle.
(2)    Includes approximately $11.2 million of deferred premiums which the Company will pay as the applicable contracts settle.
September 2020 Warrants. The fair value of the September 2020 Warrants was calculated using a Black Scholes-Merton option pricing model. As historical volatility is a significant input into the model, the September 2020 Warrants were designated as Level 3 within the valuation hierarchy.
In February 2021, holders of the September 2020 Warrants provided notice and exercised all of their outstanding warrants. The exercise of the September 2020 Warrants resulted in settlement of the associated derivative liability of $134.8 million. See “Note 7 - Derivative Instruments and Hedging Activities” for additional details.
19

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)

Assets andliabilitiesmeasured atfairvalue onThe following table presents anonrecurringbasis

Acquisitions. The Company determines reconciliation of the change in the fair value of the assets acquiredliability related to the September 2020 Warrants, which was designated as Level 3 within the valuation hierarchy, for the six months ended June 30, 2021.
Six Months Ended June 30, 2021
(In thousands)
Beginning of period$79,428 
(Gain) loss on changes in fair value (1)
55,390 
Transfers into (out of) Level 3(134,818)
End of period$0 
(1)    Included in “(Gain) loss on derivative contracts” in the consolidated statements of operations.
Assets and liabilities assumedmeasured at fair value on a nonrecurring basis
Asset retirement obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using the income approacha discounted cash flow model based on expected discounted future cash flows from estimated reserve quantities,inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs to produceof plugging and develop reserves, andabandoning oil and natural gas forward prices. Thewells, removing production equipment and facilities, restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped and probable reserves are reduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 2 and Level 3 inputs.inflation rates.

Note 79 - Income Taxes

The Company typically provides for income taxes at athe statutory rate of 35% adjusted for permanent21%. Reported income tax benefit (expense) differs from the amount of income tax benefit (expense) that would result from applying domestic federal statutory tax rates to pretax income (loss). These differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls, changes in valuation allowances, and state income taxes. As a result
For the three months ended June 30, 2021, and 2020, the Company’s effective income tax rates were 4% and 3%, respectively. The primary differences between the effective tax rates for the three months ended June 30, 2021 and 2020 and the statutory rate resulted from the valuation allowance recorded against the Company’s net deferred tax assets beginning in the second quarter of 2020 and the write-downeffect of state income taxes.
For the six months ended June 30, 2021 and 2020, the Company’s effective income tax rates were 1% and 9%, respectively. The primary differences between the effective tax rates for the six months ended June 30, 2021 and 2020 and the statutory rate resulted from the valuation allowance recorded against the Company’s net deferred tax assets beginning in the second quarter of 2020 and the effect of state income taxes.
Deferred Tax Asset Valuation Allowance
Management monitors company-specific, oil and natural gas properties inindustry and worldwide economic factors and assesses the latter part of 2015 and likelihood that
the first half of 2016, the Company incurred a cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability ofCompany’s net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at June 30, 2021, driven primarily by the impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through future earnings, the Company assessedfourth quarter of 2020. This limits the ability to realize itsconsider other subjective evidence such as the Company’s potential for future growth. Since the second 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 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 asset 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 as of September 30, 2017. 

The Company recently adopted a new accounting standard that simplified the accounting for stock-based compensation.will not be realized. As a result, the Company has recorded a cumulative-effect adjustment to retained earningsvaluation allowance, reducing the net deferred tax assets as of January 1, 2017 for all windfall tax benefits that were not previously recognized becauseJune 30, 2021 to 0.
The Company will continue to evaluate whether 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, and therefore,is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net effectdeferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more future potential transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes taxable income. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit.
Note 10 - Share-Based Compensation
All share and per share numbers included in this footnote have been adjusted for the reverse stock split. See “Note 11 - Stockholders’ Equity” for discussion of this new accounting standard was zero. See Note 1the reverse stock split and reduction in authorized shares.
20

RSU Equity Awards
The following table summarizes activity for additional information about this new accounting standard.restricted stock units that may be settled in common stock (“RSU Equity Awards”) for the three and six months ended June 30, 2021 and 2020:

Three Months Ended June 30,
20212020
RSU Equity Awards
(in thousands)		Weighted Average Grant Date
Fair Value		RSU Equity Awards
(in thousands)		Weighted Average Grant Date
Fair Value
Unvested, beginning of the period1,210 $36.02 485 $69.50 
Granted (1)
66 $38.86 324 $12.62 
Vested (2)
(184)$35.68 (90)$100.57 
Forfeited(57)$42.83 0 $0 
Unvested, end of the period1,035 $35.88 719 $39.99 
Six Months Ended June 30,
20212020
RSU Equity Awards
(in thousands)		Weighted Average Grant Date
Fair Value		RSU Equity Awards
(in thousands)		Weighted Average Grant Date
Fair Value
Unvested, beginning of the period677 $34.57 269 $102.48 
Granted (1)
636 $38.46 556 $21.20 
Vested (2)
(205)$39.23 (106)$100.23 
Forfeited(73)$36.83 0 $0 
Unvested, end of the period1,035 $35.88 719 $39.99 
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)Includes 0 target performance-based RSU Equity Awards granted during both the three and six months ended June 30, 2021 and 25.8 thousand and 111.2 thousand during the three and six months ended June 30, 2020, respectively.
(2)The fair value of shares vested was $7.4 million and $0.6 million during the three months ended June 30, 2021 and 2020, respectively, and $7.8 million and $1.3 million for the six months ended June 30, 2021 and 2020, respectively.
Note 8 - Asset Retirement ObligationsGrant activity for the six months ended June 30,2021 and 2020 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards.

NaN performance-based RSU Equity Awards were granted during the six months ended June 30,2021. For the performance-based RSU Equity Awards granted in the first half of 2020, 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. These awards include an absolute TSR modifier, which was added as a second factor in the calculation, which could increase the number of awards that vest or reduce the number of awards that vest 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 $0.5 million and $3.4 million for the three and six months ended June 30, 2020, respectively. The following table summarizes the assumptions used to calculate the grant date fair value of the performance-based RSU Equity Awards granted during the three and six months ended June 30, 2020:
Performance-based AwardsJune 29, 2020January 31, 2020
Expected term (in years)2.52.9
Expected volatility113.2 %54.8 %
Risk-free interest rate0.2 %1.3 %
Dividend yield0 %0 %
As of June 30, 2021, unrecognized compensation costs related to unvested RSU Equity Awards were $29.5 million and will be recognized over a weighted average period of 2.3 years.
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Cash-Settled RSU Awards
The table below summarizes the activity for the Company’s asset retirement obligations:
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

Certain of the Company’s operating agreements requirerestricted stock units that assetsmay be restricted for abandonment obligations. Amounts recordedsettled in 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 several of the Company’s oil and natural gas properties.

Note 9 - Equity Transactions

10% Series A Cumulative Preferred Stockcash (“Preferred Stock”Cash-Settled RSU Awards”)

Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March,three and six months ended June September30, 2021 and December when, as2020:
Three Months Ended June 30,
20212020
Cash-Settled RSU Awards
(in thousands)		Weighted Average Grant Date
Fair Value		Cash-Settled RSU Awards
(in thousands)		Weighted Average Grant Date
Fair Value
Unvested, beginning of the period194 $47.15 171 $78.54 
Granted (1)
3 $36.71 39 $20.33 
Vested0 $0 (1)$166.60 
Did not vest at end of performance period0 $0 (1)$166.60 
Forfeited(23)$54.57 0 $0 
Unvested, end of the period174 $45.93 208 $67.20 
Six Months Ended June 30,
20212020
Cash-Settled RSU Awards
(in thousands)		Weighted Average Grant Date
Fair Value		Cash-Settled RSU Awards
(in thousands)		Weighted Average Grant Date
Fair Value
Unvested, beginning of the period196 $47.56 86 $124.22 
Granted (1)
3 $36.71 125 $29.76 
Vested(1)$110.48 (2)$126.51 
Did not vest at end of performance period(1)$110.48 (1)$166.60 
Forfeited(23)$54.57 0 $0 
Unvested, end of the period174 $45.93 208 $67.20 
(1)Includes 3.2 thousand and if declared by our Board of Directors. Preferred Stock dividends were $1,824 and $1,82412.7 thousand units for the three months ended SeptemberJune 30, 20172021 and 2016,2020, respectively, and $5,4713.2 thousand and $5,47113.7 thousand units for the ninesix months ended SeptemberJune 30, 20172021 and 2016, respectively.2020, respectively, associated with deferrals of certain non-employee director compensation pursuant to the terms of the Amended and Restated Deferred Compensation Plan for Outside Directors.

No Cash-Settled RSU Awards were granted to employees during the six months ended June 30,2021. Grant activity in the first quarter of 2020 primarily consisted of Cash-Settled RSU Awards to executives as part of the annual grant of long-term equity incentive awards. These awards cliff vest after an approximate three-year performance period.
The PreferredCompany’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 during the six months ended June 30, 2020 are the same as the performance-based RSU Equity Awards presented above.
The following table summarizes the Company’s liability for Cash-Settled RSU Awards and the classification in the consolidated balance sheets for the periods indicated:
June 30, 2021December 31, 2020
(In thousands)
Other current liabilities$996 $182 
Other long-term liabilities7,789 1,336 
Total Cash-Settled RSU Awards$8,785 $1,518 
As of June 30, 2021, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $5.9 million and will be recognized over a weighted average period of 1.5 years.
Cash-Settled SARs
As a result of the Carrizo Acquisition, cash-settled stock appreciation rights (“Cash SARs”) previously granted by Carrizo that were outstanding at closing were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Carrizo Acquisition. The liabilities for Cash SARs as of June 30, 2021 and December 31, 2020 were $10.2 million and $1.7 million, respectively, all of which were classified as “Other current
22

liabilities” in the consolidated balance sheets in the respective periods. Changes in the fair value of the Cash SARs are included in “General and administrative” in the consolidated statements of operations.
Share-Based Compensation Expense (Benefit), Net
Share-based compensation expense associated with the RSU Equity Awards, Cash-Settled RSU Awards, Cash SARs, net of amounts capitalized, is included in “General and administrative” in the consolidated statements of operations. The following table presents share-based compensation expense (benefit), net for each respective period:
Three Months Ended June 30,Six Months Ended
June 30,
2021202020212020
(In thousands)
RSU Equity Awards$3,242 $3,212 $5,850 $7,160 
Cash-Settled RSU Awards3,007 596 7,449 (1,400)
Cash SARs3,676 1,115 8,542 (3,641)
9,925 4,923 21,841 2,119 
Less: amounts capitalized to oil and gas properties(4,646)(2,162)(8,954)(2,330)
Total share-based compensation expense (benefit), net$5,279 $2,761 $12,887 ($211)
See “Note 10 - Share-Based Compensation” of the Notes to Consolidated Financial Statements in the 2020 Annual Report for details of the Company’s equity-based incentive plans. 
Note 11 - Stockholders’ Equity
Increase in Authorized Common Shares
The Company filed an amendment to its certificate of incorporation, which became effective on May 14, 2021, to increase the number of authorized shares of common stock from 52,500,000 to 78,750,000, as approved by the Company’s shareholders at the 2021 Annual Meeting of Shareholders on May 14, 2021.
Warrant Exercises
During the six months ended June 30,2021, certain holders of the September 2020 Warrants and warrants issued in conjunction with the exchange of Senior Unsecured Notes on November 2, 2020 (the “November 2020 Warrants”) provided notice and exercised all of their outstanding warrants. As a result of the exercises, the Company issued a total of 6.4 million shares of its common stock in exchange for 8.4 million outstanding warrants determined on a net share settlement basis. See “Note 7 - Derivative Instruments and Hedging Activities” and “Note 8 - Fair Value Measurements” for additional details regarding the September 2020 Warrants. As of June 30, 2021, 0.6 million November 2020 Warrants remain outstanding.
Reverse Stock has no stated maturitySplit
On August 7, 2020, the Board of Directors effected a reverse stock split of the Company’s outstanding shares of common stock at a ratio of 1-for-10 and reduced the total number of authorized shares of the Company’s common stock from 525,000,000 to 52,500,000 shares 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 Company’s common stock began trading on a split-adjusted basis on August 10, 2020 upon opening of the markets. All share and per share amounts, except par value per share, in the consolidated financial statements and notes thereto for periods prior to August 2020 were retroactively adjusted to give effect to this reverse stock split.
Note 12 - Accounts Receivable, Net
June 30, 2021December 31, 2020
(In thousands)
Oil and natural gas receivables$148,663 $100,257 
Joint interest receivables12,869 11,530 
Other receivables41,585 24,191 
   Total203,117 135,978 
Allowance for credit losses(2,871)(2,869)
   Total accounts receivable, net$200,246 $133,109 
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Note 13 - Accounts Payable and Accrued Liabilities
June 30, 2021December 31, 2020
(In thousands)
Accounts payable$92,549 $101,231 
Revenues payable224,812 162,762 
Accrued capital expenditures57,355 32,493 
Accrued interest44,718 45,033 
   Total accounts payable and accrued liabilities$419,434 $341,519 
Note 14 - Supplemental Cash Flow
Six Months Ended June 30,
20212020
(In thousands)
Supplemental cash flow information:
Interest paid, net of capitalized amounts$44,734 $31,649 
Income taxes paid0 0 
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases$14,576 $26,110 
Investing cash flows from operating leases8,402 11,278 
Non-cash investing and financing activities:
Change in accrued capital expenditures$47,247 ($6,186)
Change in asset retirement costs2,567 207 
ROU assets obtained in exchange for lease liabilities:
Operating leases$9,710 $2,666 
Note 15 - Subsequent Events
Senior Unsecured Notes
On June 21, 2021, the Company entered into a Purchase Agreement pursuant to which it agreed to issue and sell $650.0 million in aggregate principal amount of 8.00% senior unsecured notes due 2028 (the “8.00% Senior Notes”) in a private placement, which closed on July 6, 2021 for proceeds of approximately $638.1 million, net of underwriting discounts and commissions and offering costs. The 8.00% Senior Notes mature on August 1, 2028 and interest is payable on the Notes semi-annually each February 1 and August 1, commencing on February 1, 2022.
At any time prior to August 1, 2024, the Company may, from time to time, redeem up to 35% of the aggregate principal amount of the 8.00% Senior Notes in an amount of cash not subjectgreater than the net cash proceeds from certain equity offerings at the redemption price of 108.00% of the principal amount, plus accrued and unpaid interest, if any, to, any sinking fund or other mandatory redemption. On orbut excluding, the date of redemption, if at least 65% of the aggregate principal amount of the 8.00% Senior Notes remains outstanding after May 30, 2018,such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to August 1, 2024, the Company may, at its option, on any one or more occasions, redeem all or a portion of the Preferred Stock, in whole or in part, by paying $50.00 per share,8.00% Senior Notes at 100.00% of the principal amount plus anyan applicable make-whole premium and accrued and unpaid dividends to the redemption date.

Following a change of control in whichinterest. On or after August 1, 2024, the Company may redeem all or a portion of the acquirer no longer have a class8.00% Senior Notes at redemption prices decreasing annually from 104.00% to 100.00% 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,principal amount redeemed plus accrued and unpaid dividends (whether or not declared), tointerest. Upon the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon suchoccurrence of certain kinds of change of control, the holderseach holder of the Preferred8.00% Senior Notes may require the Company to repurchase all or a portion of the 8.00% Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such Notes, plus accrued and unpaid interest.
Also on June 21, 2021, the Company delivered a redemption notice with respect to all $542.7 million of its outstanding 6.25% Senior Notes, which became redeemable on July 21, 2021. The Company used a portion of the net proceeds from the 8.00% Senior Notes to redeem all of its outstanding 6.25% Senior Notes and the remaining proceeds to partially repay amounts outstanding under its Credit Facility.
Primexx Acquisition
On August 3, 2021, the Company entered into purchase and sale agreements with Primexx Resource Development, LLC and BPP Acquisition, LLC (collectively, the “Primexx PSAs”) to purchase, effective as of July 1, 2021, certain producing oil and gas properties and undeveloped acreage in the Delaware Basin for total consideration of $440.0 million in cash and 9.19 million shares of Company common stock, subject to customary purchase price adjustments, with closing expected to occur early in the fourth quarter of 2021, subject to completion of various customary conditions (the “Primexx Acquisition”). Upon signing the Primexx PSAs, the Company paid approximately $60.1 million as a deposit into third-party escrow accounts.
24

Second Lien Note Exchange
Also on August 3, 2021, the Company entered into an agreement with Chambers Investments, LLC, a private investment vehicle managed by Kimmeridge Energy, to exchange $197.0 million of its outstanding Second Lien Notes for a notional amount of approximately $223.1 million of Company common stock. The value of equity to be delivered is based on the construct of the optional redemption language in the indenture for the Second Lien Notes. The price of the Company common stock used to calculate the shares issued is based on the 10-day volume-weighted average price as of August 2, 2021. This exchange is contingent upon the closing of the Primexx Acquisition described above as well as a shareholder vote as required under New York Stock have the optionExchange rules because Kimmeridge is a deemed related party due to convert the Preferred Stock into a numberits ownership of sharesover 5% of the Company’s common stock based on the value of the common stock on the date of the change of control 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 issued and outstanding.

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. 


25
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Table of Contents

On May 26, 2016, the Company issued 9,333,333 shares of common stock to partially fund the Big Star Transaction, described in Note 2, 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.

On April 25, 2016, the Company completed an underwritten public offering of 25,300,000 shares of its common stock for total net proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately $205,869. Proceeds from the offering were used to fund the Big Star Transaction, described in Note 2, and other working interest acquisitions.

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.

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, as amended (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:
•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:
general economic conditions including the availability of credit and access to existing lines of credit;
the volatility of oil and natural gas prices;
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;
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;
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;
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;
weather conditions; 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 and other risks include, but are not limited to, the risks described in Part I, Item 1A of our 2020 Annual Report on Form 10-K for the year ended December 31, 2016 (the  “2016 Annual Report on Form 10-K”), and in all quarterly reports on Form 10-Q filed subsequently thereto. These factors include:

•volatility of oil, natural gas and NGL prices or a prolonged period of low oil, natural gas or NGLs prices;
•general economic conditions including the availability of credit and access to existing lines of credit;
•changes in the supply of and demand for oil and natural gas, including as a result of the COVID-19 pandemic and various governmental actions taken to mitigate its impact or actions by, or disputes among, members of OPEC 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;
•the uncertainty of estimates of oil and natural gas reserves;
•impairments;
•the impact of competition;
•the availability and cost of seismic, drilling and other equipment, waste and water disposal infrastructure, and personnel;
•operating hazards inherent in the exploration for and production of oil and natural gas;
•difficulties encountered during the exploration for and production of oil and natural gas;
•the potential impact of future drilling on production from existing wells;
•difficulties encountered in delivering oil and natural gas to commercial markets;
•the uncertainty of our ability to attract capital and obtain financing on favorable terms;
•compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases;
•the impact of government regulation, including regulation of hydraulic fracturing and water disposal wells;
•any increase in severance or similar taxes;
•the financial impact of accounting regulations and critical accounting policies;
•the comparative cost of alternative fuels;
•credit risk relating to the risk of loss as a result of non-performance by our counterparties;
•cyberattacks on the Company or on systems and infrastructure used by the oil and natural gas industry; and
•weather conditions.
Should one or more of thethese risks or uncertainties described herein or in our 2016 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.

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

General

The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and our 20162020 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 establishedwith roots that go back over 70 years to our 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, 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 completedEagle Ford in February 2017. South Texas.
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, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales.shales, and the Eagle Ford. 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
Recent Developments and Overview
Senior Unsecured Notes
On June 21, 2021, we entered into a Purchase Agreement pursuant to which we agreed to issue and sell $650.0 million in aggregate principal amount of 8.00% Senior Notes in a private placement, which closed on July 6, 2021 for proceeds of approximately 78%$638.1 million, net of underwriting discounts and commissions and offering costs. Also on June 21, 2021, we delivered a redemption notice with respect to all $542.7 million of our outstanding 6.25% Senior Notes, which became redeemable on July 21, 2021. We used a portion of the net proceeds from the 8.00% Senior Notes to redeem all of our outstanding 6.25% Senior Notes and the remaining proceeds to partially repay amounts outstanding under our Credit Facility. See “Note 15 - Subsequent Events” for further discussion.
Primexx Acquisition and Second Lien Note Exchange
On August 3, 2021, we entered into the Primexx PSAs to purchase, effective as of July 1, 2021, certain producing oil and 22% natural gas for the nine months ended September 30, 2017. On September 30, 2017, our netproperties and undeveloped acreage position in the PermianDelaware Basin was approximately 58,336 net acres. See Note 2for total consideration of $440.0 million in the Footnotes to the Financial Statements for additional information about the Company’s acquisitions.


Operational Highlights

Allcash and 9.19 million shares of our producing properties are located in the Permian Basin. Ascommon stock, subject to customary purchase price adjustments. Also on August 3, 2021, we entered into an agreement with Chambers Investments, LLC, a resultprivate investment vehicle managed by Kimmeridge Energy, to exchange $197.0 million of our acquisition and horizontal development efforts,outstanding Second Lien Notes for a notional amount of approximately $223.1 million of our production grew 36% and 53%common stock, contingent upon the closing of the Primexx Acquisition described above as well as a required shareholder vote. See “Note 15 - Subsequent Events” for the three and nine months ended September 30, 2017, respectively, compared to the same periods of 2016. Production increased to 2,074 MBOEfurther discussion.
Second Quarter 2021 Highlights
•Total production for the three months ended SeptemberJune 30, 2017 2021 was 89.0 MBoe/d, an increase of 10% from 1,527 MBOEthe three months ended March 31, 2021, primarily due to new wells placed on production during the second quarter of 2021 as well as lower production in the first quarter of 2021 as a result of the shut-in of our operated production during the severe winter storms in February 2021. Total production for the six months ended June 30, 2021 was 85.0 MBoe/d, a decrease of 19% from the six months ended June 30, 2020, primarily due to normal production decline partially offset by new wells placed on production during 2021.
•Operated drilling and completion activity for the three months ended SeptemberJune 30, 20162021 along with our drilled but uncompleted and increased to 5,934 MBOEproducing wells as of June 30, 2021 are summarized in the table below.
Three Months Ended June 30, 2021As of June 30, 2021
DrilledCompletedDrilled But UncompletedProducing
RegionGrossNetGrossNetGrossNetGrossNet
Permian8 6.5 22 20.2 15 11.9 847 738.1 
Eagle Ford— — 29 29.0 6 6.0 689 621.1 
Total8 6.5 51 49.2 21 17.9 1,536 1,359.2 
27

•Operational capital expenditures, exclusive of leasehold and seismic, for the nine months ended September 30, 2017 from 3,884 MBOEsecond quarter of 2021 were $138.3 million, of which approximately 63% were in the Permian with the remaining balance in the Eagle Ford. See “—Liquidity and Capital Resources—2021 Capital Budget and Funding Strategy” for additional details.
•Completed divestitures of certain non-core assets in the nine months ended September 30, 2016.Delaware Basin for aggregate net cash proceeds of $30.7 million, subject to post-closing adjustments. See “Note 3 - Acquisitions and Divestitures” for further discussion.

•Entered into the fourth amendment to our credit agreement governing the Credit Facility which, among other things reaffirmed the borrowing base and the elected commitment amount of $1.6 billion as a result of the spring 2021 scheduled redetermination. See “Note 6 - Borrowings” for further discussion.
For•Reduced borrowings outstanding under our Credit Facility by $75.0 million compared to the first quarter of 2021, reflecting our continued emphasis on deleveraging our balance sheet.
•We recorded net loss for the three months ended SeptemberJune 30, 2017, we drilled 13 gross (10.3 net) horizontal wells2021 and completed 15 gross (13.2 net) horizontal wells. For2020 of $11.7 million, or $0.25 per diluted share, and $1.6 billion, or $39.41 per diluted share, respectively. The variance between the nine months ended September 30, 2017 we drilled 36 gross (28.9 net) horizontal wells and completed 34 gross (27.7 net) horizontal wells. Asrespective periods was driven primarily by the impairment of September 30, 2017, we had 9 gross (6.4 net) horizontal wells awaiting completion.

Asevaluated properties 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$1.3 billion during the second quarter of 2020 as well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE basis. However, most of our wells produce both 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 of capital to complement our cash flows from operations as we pursue our long-term growth plans. As of September 30, 2017, there was no balance outstanding on the Credit Facility, which has a borrowing base 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 million compared to $325.9 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
Callon Petroleum CompanyManagement’s Discussion and Analysis of Financial Condition and Results
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Operating activities. For the nine months ended September 30, 2017, net cash provided by operating activities was $149.7 million compared to net cash provided by operating activities 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 settlementsoperating revenues in the second quarter of derivative contracts;
An2021 driven by an approximate 206% 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,total average realized prices, and operating expenses are discussed below in Results of Operations. See Notes 4, 5 and 6 in the Footnotes to the Financial Statements 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. 

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 issuesales 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 periodsecond quarter of 2016. 
2020 as well as a decrease in depreciation, depletion and amortization primarily driven by the recording of impairments of evaluated oil and gas properties during 2020, partially offset by an increase in the loss on derivative contracts to approximately $190.5 million during the second quarter of 2021 compared to approximately $127.0 million during the second quarter of 2020. See “—Results of Operations” below for further details.


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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.

Callon Petroleum CompanyManagement’s Discussion and Analysis of Financial Condition and Results
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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 EndedSix Months Ended June 30,
 June 30, 2021March 31, 2021$ Change% Change20212020$ Change% Change
Total production    
Oil (MBbls)
Permian3,2323,088144 5 %6,3207,227(907)(13 %)
Eagle Ford1,8701,593277 17 %3,4635,016(1,553)(31 %)
Total oil (MBbls)5,1024,681421 9 %9,78312,243(2,460)(20 %)
Natural gas (MMcf)
Permian7,1386,208930 15 %13,34616,745(3,399)(20 %)
Eagle Ford1,7451,627118 7 %3,3724,057(685)(17 %)
Total natural gas (MMcf)8,8837,8351,048 13 %16,71820,802(4,084)(20 %)
NGLs (MBbls)
Permian1,2161,075141 13 %2,2912,636(345)(13 %)
Eagle Ford29922475 33 %523728(205)(28 %)
Total NGLs (MBbls)1,5151,299216 17 %2,8143,364(550)(16 %)
Total Production (MBoe)
Permian5,6375,198439 8 %10,83512,654(1,819)(14 %)
Eagle Ford2,4602,088372 18 %4,5486,420(1,872)(29 %)
Total barrels of oil equivalent (MBoe)8,0977,286811 11 %15,38319,074(3,691)(19 %)
Total daily production (Boe/d)88,98180,9578,024 10 %84,991104,802(19,811)(19 %)
Oil as % of total daily production63 %64 %    64 %64 %
Benchmark prices (1)
WTI (per Bbl)$66.06$57.80$8.26 14 %$61.95$36.97$24.98 68 %
Henry Hub (per Mcf)2.972.720.25 9 %2.851.811.04 57 %
Average realized sales price (excluding impact of settled derivatives)
    
Oil (per Bbl)
Permian$65.08$56.66$8.42 15 %$60.97$34.38$26.59 77 %
Eagle Ford65.8357.808.03 14 %62.1429.4732.67 111 %
Total oil (per Bbl)65.3657.058.31 15 %61.3832.3729.01 90 %
Natural gas (per Mcf)
Permian2.683.11(0.43)(14 %)2.880.662.22 336 %
Eagle Ford2.823.03(0.21)(7 %)2.921.801.12 62 %
Total natural gas (per Mcf)2.713.09(0.38)(12 %)2.890.882.01 228 %
NGL (per Bbl)
Permian24.7122.682.03 9 %23.769.9313.83 139 %
Eagle Ford22.0022.24(0.24)(1 %)22.108.8113.29 151 %
Total NGLs (per Bbl)24.1722.601.57 7 %23.459.6913.76 142 %
29

  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
 $4.75
 17 %
Three Months EndedSix Months Ended June 30,
June 30, 2021March 31, 2021$ Change% Change20212020$ Change% Change
Total average realized sales price (per Boe)
Permian46.0442.063.98 9 %44.1322.5721.56 96 %
Eagle Ford54.7248.855.87 12 %52.0225.1626.86 107 %
Total (per Boe)$48.68$44.01$4.67 11 %$46.46$23.44$23.02 98 %
Average realized sales price (including impact of settled derivatives)
Oil (per Bbl)$46.82$44.33$2.49 6 %$45.63$41.02$4.61 11 %
Natural gas (per Mcf)2.252.88(0.63)(22 %)2.541.041.50 144 %
NGLs (per Bbl)23.2121.771.44 7 %22.549.6912.85 133 %
Total (per Boe)$36.31$35.46$0.85 2 %$35.91$29.18$6.73 23 %
Revenues (in thousands)        
Oil
Permian$210,340$174,967$35,373 20 %$385,307$248,444$136,863 55 %
Eagle Ford123,10292,07831,024 34 %215,180147,83667,344 46 %
Total oil333,442267,04566,397 25 %600,487396,280204,207 52 %
Natural gas
Permian19,15219,290(138)(1 %)38,44210,98427,458 250 %
Eagle Ford4,9284,930(2)— %9,8587,2872,571 35 %
Total natural gas24,08024,220(140)(1 %)48,30018,27130,029 164 %
NGLs
Permian30,04724,3765,671 23 %54,42326,18828,235 108 %
Eagle Ford6,5784,9811,597 32 %11,5596,4145,145 80 %
Total NGLs36,62529,3577,268 25 %65,98232,60233,380 102 %
Total Revenues
Permian259,539218,63340,906 19 %478,172285,616192,556 67 %
Eagle Ford134,608101,98932,619 32 %236,597161,53775,060 46 %
Total revenues$394,147$320,622$73,525 23 %$714,769$447,153$267,616 60 %
Additional per Boe data
Lease operating
Permian$4.60$4.31$0.29 7 %$4.46$5.00($0.54)(11 %)
Eagle Ford8.348.65(0.31)(4 %)8.496.222.27 36 %
Total lease operating$5.74$5.55$0.19 3 %$5.65$5.41$0.24 4 %
Production and ad valorem taxes
Permian$2.53$2.32$0.21 9 %$2.43$1.55$0.88 57 %
Eagle Ford3.123.070.05 2 %3.101.621.48 91 %
Total production and ad valorem taxes$2.71$2.53$0.18 7 %$2.63$1.57$1.06 68 %
Gathering, transportation and processing
Permian$2.75$2.54$0.21 8 %$2.65$2.09$0.56 27 %
Eagle Ford1.842.29(0.45)(20 %)2.051.230.82 67 %
Total gathering, transportation and processing$2.47$2.47$— — %$2.47$1.80$0.67 37 %

  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)    Reflects calendar average daily spot market prices.

30


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
OilNatural GasNGLsTotal
(In thousands)
Revenues for the period ended in March 31, 2021 (1)
$267,045$24,220$29,357$320,622 
Volume increase (decrease)24,0183,2404,88132,139 
Price increase (decrease)42,379(3,380)2,38741,386 
Net increase (decrease)66,397(140)7,26873,525 
Revenues for the period ended in June 30, 2021 (1)
$333,442$24,080$36,625$394,147 
Percent of total revenues85 %6 %9 %
(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

Commodityprices

The prices for oil and natural gas can be volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by the Organization of Petroleum Exporting Countries and other countries and government actions. Prices(1)    Excludes sales of oil and natural gas will affect the following aspects of our business:purchased from third parties.

Six Months Ended June 30,
OilNatural GasNGLsTotal
(In thousands)
Revenues for the period ended in 2020$396,280$18,271$32,602$447,153 
Volume increase (decrease)(79,625)(3,587)(5,330)(88,542)
Price increase (decrease)283,83233,61638,710356,158 
Net increase (decrease)204,20730,02933,380267,616 
Revenues for the period ended in 2021 (1)
$600,487$48,300$65,982$714,769 
Percent of total revenues84 %7 %9 %
our revenues, cash flows and earnings;
the amount(1)    Excludes sales of oil and natural gas that we are economically able to produce;purchased from third parties.
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; and
the value of our oil and natural gas properties.

For the three and nine months ended September 30, 2017, the average NYMEX price for a barrel of oil was $48.20 and $49.36 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 oilRevenues for the three and nine months ended SeptemberJune 30, 2017 ranged from a low2021 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, oil revenues of $73.3$394.1 million increased $24.2$73.5 million, or 49%23%, compared to revenues of $49.1$320.6 million for the same period of 2016.three months ended March 31, 2021. The increase in oil revenue was primarily attributable to a 38% increase in production and an 8%11% increase in the average realized sales price which rose to $46.10$48.68 per Bbl in the third quarter of 2017 from $42.58$44.01 per Bbl in the third quarter of 2016. Theas well as a 10% increase in production was attributable to 633 MBbls from wells placed on production as a result of our horizontal drilling program and 241 MBbls from producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells.  discussed above.

ForRevenues for the ninesix months ended SeptemberJune 30, 2017, oil revenues2021 of $218.2$714.8 million increased $101.1$267.6 million, or 86%60%, compared to revenues of $117.1$447.2 million for the same period of 2016.2020. The increase in oil revenue was primarily attributable to a 54% increase in production and a 21%98% increase in the average realized sales price which rose to $47.23$46.46 per Bbl for the nine months ended September 30, 2017 from $39.12$23.44 per Bbl for the same period of 2016.Bbl. 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 gas and natural gas liquids prices. The increasewas partially offset by a 19% decrease in production was comprised of 735 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 287 MMcf attributable to producing wells added from our acquired properties. Offsetting these increases were normal expected declines from our existing wells.discussed above.

31
Natural gas 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 in 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.

Operating Expenses
Three Months Ended
June 30, 2021PerMarch 31, 2021PerTotal ChangeBoe Change
BoeBoe$%$%
(In thousands, except per Boe and % amounts)
Lease operating$46,460 $5.74 $40,453 $5.55 $6,007 15 %$0.19 3 %
Production and ad valorem taxes21,958 2.71 18,439 2.53 3,519 19 %0.18 7 %
Gathering, transportation and processing20,031 2.47 17,981 2.47 2,050 11 %— — %
Depreciation, depletion and amortization83,128 10.27 70,987 9.74 12,141 17 %0.53 5 %
General and administrative11,065 1.37 16,799 2.31 (5,734)(34 %)(0.94)(41 %)
Impairment of evaluated oil and gas properties— — — — — — %— — %
Merger and integration— — — — — — %— — %
(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 % $(0.05) (1)%
Production taxes 16,168
 2.72
 8,153
 2.10
 8,015
 98 % 0.62
 30 %
Depreciation, depletion and amortization 79,172
 13.34
 49,318
 12.70
 29,854
 61 % 0.64
 5 %
General and administrative 18,894
 3.18
 19,755
 5.09
 (861) (4)% (1.91) (38)%
Settled share-based awards 6,351
 nm
 —
 nm
 6,351
 nm
 nm
 nm
Accretion expense 523
 0.09
 762
 0.20
 (239) (31)% (0.11) (55)%
Write-down of oil and natural gas properties —
 nm
 95,788
 nm
 (95,788) nm
 nm
 nm
Acquisition expense 3,027
 nm
 2,410
 nm
 617
 nm
 nm
 nm
Six Months Ended June 30,
PerPerTotal ChangeBoe Change
2021Boe2020Boe$%$%
(In thousands, except per Boe and % amounts)
Lease operating$86,913 $5.65 $103,221 $5.41 ($16,308)(16 %)$0.24 4 %
Production and ad valorem taxes40,397 2.63 30,041 1.57 10,356 34 %1.06 68 %
Gathering, transportation and processing38,012 2.47 34,415 1.80 3,597 10 %0.67 37 %
Depreciation, depletion and amortization154,115 10.02 270,393 14.18 (116,278)(43 %)(4.16)(29 %)
General and administrative27,864 1.81 18,349 0.96 9,515 52 %0.85 89 %
Impairment of evaluated oil and gas properties— — 1,276,518 66.92 (1,276,518)(100 %)(66.92)(100 %)
Merger and integration— — 23,897 1.25 (23,897)(100 %)(1.25)(100 %)
nm = not meaningful

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 SeptemberJune 30, 2017, LOE2021 increased by 17% to $11.6$46.5 million compared to $10.0$40.5 million for the three months ended March 31, 2021, primarily due to production volumes increasing 11%. Lease operating expense per Boe for the three months ended June 30, 2021 increased to $5.74 compared to $5.55 for the three months ended March 31, 2021, primarily due to increased electrical costs.
Lease operating expenses for the six months ended June 30, 2021 decreased to $86.9 million compared to $103.2 million for the same period of 2016. Contributing2020, primarily due to production volumes decreasing 19%. Lease operating expense per Boe for 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 threesix months ended SeptemberJune 30, 2017, LOE per BOE decreased2021 increased to $5.60 per BOE$5.65 compared to $6.52 per BOE$5.41 for the same period of 2016, which was primarily attributable to 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. 

For the nine months ended September 30, 2017, LOE increased by 52% to $36.7 million compared to $24.2 million for the same period of 2016. Contributing to the increase was $10.1 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). 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 was2020, primarily due to an increase in cost driven by higherthe distribution of fixed costs spread over lower production volumes, from our legacy assets. For the nine months ended September 30, 2017, LOE per BOE decreased to $6.19 per BOE compared to $6.24 per BOE for the same period of 2016, which was primarily attributable to higher production volumespartially offset by an increasea reduction in cost as previously discussed. The increase incertain operating expenses including repairs and maintenance and production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above. chemicals.

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. Severance 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, weWe benefit from tax credits and exemptions in our various taxing jurisdictions.jurisdictions where available and applicable. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties.

ProductionFor the three months ended June 30, 2021, production and ad valorem taxes increased 19% to $22.0 million compared to $18.4 million for the three months ended SeptemberMarch 31, 2021, which is primarily related to a 23% increase in total revenues which increased production taxes. Production and ad valorem taxes as a percentage of total revenues decreased to 5.6% for the second quarter of 2021 as compared to 5.8% of total revenues for the three months ended March 31, 2021, primarily due to total revenues increasing at a higher rate than the increase in ad valorem taxes.
For the six months ended June 30, 20172021, production and ad valorem taxes increased by 57%34% to $5.4$40.4 million compared to $3.5$30.0 million for the same period of 2016. The increase was2020, which is primarily duerelated to ana 60% increase in severance taxes,total revenues which was attributable toincreased production taxes. The impact of the increase in revenue. Also contributing to the increaseproduction taxes was an increasepartially offset by a decrease in ad valorem taxes which was attributabledue to an increase in the valuation of our oil and gas properties by taxing jurisdictionslower expected property tax valuations for 2021 as a result of an increased number of producing wells from our horizontal drilling program, acquisitions as discussed above, and an increase inlower commodity prices year over year. Onduring 2020 compared to higher property tax valuations for 2020 as a per BOE basis, productionresult of higher commodity prices during 2019. Production and ad valorem taxes as a percentage of total revenues decreased to 5.7% for the six months ended June 30, 2021, as compared to 6.7% of total revenues for the same period of 2020, primarily due to lower expected property tax valuations for 2021 as a result of lower commodity prices during 2020.
32

Gathering, transportation and processing expenses. For the three months ended June 30, 2021, gathering, transportation and processing expenses increased 11% to $20.0 million compared to $18.0 million for the three months ended September 30, 2017 increased by 15% comparedMarch 31, 2021, which is primarily related to the same period of 2016.11% increase in production volumes between the two periods.

Production taxes forFor the ninesix months ended SeptemberJune 30, 20172021, gathering, transportation and processing expenses increased by 98%10% to $16.2$38.0 million compared to $8.2$34.4 million for the same period of 2016. The increase2020, which was primarily duerelated to an increase in severance taxes,new oil transportation agreements which was attributablewere executed subsequent 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 jurisdictions as a result of an increased number of producing wells from our horizontal drilling program, acquisitions as discussed above, and an increase in commodity prices year over year. On a per BOE basis, production taxes for the three months ended September 30, 2017 increasedMarch 31, 2020, partially offset by 30% compared toa 19% decrease in production volumes between the same period of 2016.two periods.

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 production and estimated proved oil and natural gas 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 EndedSix Months Ended June 30,
June 30, 2021March 31, 202120212020
AmountPer BoeAmountPer BoeAmountPer BoeAmountPer Boe
(In thousands, except per Boe)
DD&A of evaluated oil and gas properties$80,833 $9.98 $68,705 $9.43 $149,538 $9.72 $265,654 $13.93 
Depreciation of other property and equipment489 0.06 516 0.07 1,005 0.07 2,072 0.11 
Amortization of other assets883 0.11 839 0.11 1,722 0.11 995 0.05 
Accretion of asset retirement obligations923 0.12 927 0.13 1,850 0.12 1,672 0.09 
DD&A$83,128 $10.27 $70,987 $9.74 $154,115 $10.02 $270,393 $14.18 
For the three months ended SeptemberJune 30, 2017,2021, DD&A increased 65% to $28.5$83.1 million from $71.0 million for the three months ended March 31, 2021. The increase in DD&A was primarily attributable to a production increase of 11%, higher capital expenditures during the second quarter of 2021 as compared to $17.3the first quarter of 2021 and increases in future development cost assumptions.
For the six months ended June 30, 2021, DD&A decreased to $154.1 million from $270.4 million for the same period of 2016.in 2020. The increase isdecrease in DD&A was primarily attributable to a 36% increase in production and a 21% increase in our per BOE DD&A rate. For the three months ended September 30, 2017, DD&A on a per unit basis increased to $13.75 per BOE compared to $11.33 per BOE for the same perioddecrease of 2016. The increase is attributable to greater increases in our depreciable base19% 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 the nine months ended September 30, 2017, 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&A 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 as a result of additions made through our horizontal drilling efforts and acquisitions, offset by the write downimpairments of evaluated oil and natural gas properties in the first half of 2016.that were recognized during 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 SeptemberJune 30, 20172021 decreased to $7.3$11.1 million compared to $7.9$16.8 million for the three months ended March 31, 2021, primarily due to lower compensation costs and a decrease in share-based compensation expense, net as the fair value of Cash-Settled RSU Awards and Cash SARs did not increase in the second quarter of 2021 at the same rate as in the first quarter of 2021.
G&A for the six months ended June 30, 2021 increased to $27.9 million compared to $18.3 million for the same period in 2020 primarily due to an increase in the fair value of 2016. G&A expensesCash-Settled RSU Awards and Cash SARs, partially offset by lower compensation costs.
Impairment of evaluated oil and gas properties. We did not recognize an impairment of evaluated oil and gas properties 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)%

G&A for the ninethree or six months ended SeptemberJune 30, 2017 decreased2021 or three months ended March 31, 2021. An impairment of evaluated oil and gas properties of $1.3 billion was recognized for six months ended June 30, 2020, which was due primarily to $18.9 milliondeclines in the 12-Month Average Realized Price of crude oil. See “Note 4 - Property and Equipment, Net” for further discussion.
Merger and integration expense. For the three and six months ended June 30, 2021 as well as the three months ended March 31, 2021, we incurred no merger and integration expenses compared to $19.8$23.9 million for 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. Insix months ended 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 retirement of tangible long-lived assets and the associated ARO costs. Interest is accreted on the present value of the ARO and reported as accretion expense within operating expenses in the consolidated statements of operations.

Accretion expense30, 2020, which were related to our ARO decreased 30% and 31% for the three and nine months ended September 30, 2017, compared to the same period of 2016. Accretion expense generally correlates with the Company’s ARO, which was $5.0 million at September 30, 2017 as compared to $5.5 million at September 30, 2016. See Note 8 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO.

Acquisition expense. Acquisition expense for all periods was related to costs 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 Acquisition.
Other Income and Expenses and Preferred Stock Dividends
(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. We finance a portion of our capital expenditures, acquisitions and working capital requirements capital expenditures and acquisitions with borrowings under our 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),
33

commitment fees and annual agency fees, and interest from our financing leases in interest expense. The following table sets forth the components of our interest expense, net of capitalized amounts for the periods indicated:

Three Months EndedSix Months Ended June 30,
June 30, 2021March 31, 2021$ Change20212020$ Change
(In thousands)
Interest expense on Credit Facility$7,970 $7,817 $153 $15,787 $24,320 ($8,533)
Interest expense on Second Lien Notes11,625 11,625 — 23,250 — 23,250 
Interest expense on Senior Unsecured Notes24,502 24,502 — 49,004 61,750 (12,746)
Amortization of debt issuance costs, premiums and discounts4,438 4,478 (40)8,916 1,892 7,024 
Other interest expense26 32 (6)58 107 (49)
Capitalized interest(23,927)(24,038)111 (47,965)(44,909)(3,056)
Interest expense, net of capitalized amounts$24,634 $24,416 $218 $49,050 $43,160 $5,890 
Interest expense, net of capitalized amounts, incurred during the three months ended SeptemberJune 30, 2017 decreased $0.42021 remained consistent at $24.6 million compared to the same period of 2016. The decrease is primarily attributable to a $2.4$24.4 million increase in capitalized 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.

March 31, 2021.
Interest expense, net of capitalized amounts, incurred during the ninesix months ended SeptemberJune 30, 2017 decreased $8.82021 increased $5.9 million to $49.1 million compared to $43.2 million for the same period of 2016.2020. The decreaseincrease is primarily attributable to a $10.9 million increase in capitalized interest compareddue to the 2016 period, resulting fromissuance of the Second Lien Notes in the third quarter of 2020 as well as amortization of the discount associated with those Second Lien Notes, offset by the reduction in Senior Unsecured Notes outstanding as a higher average unevaluated property balance forresult of the nine months ended September 30, 2017 as compared toexchange which occurred during the fourth quarter of 2020 and lower borrowings on the Credit Facility during the same period of 2016. The increase in unevaluated property was primarily due to acquired properties. Offsetting the decrease was a $2.1 million increase in interest expense on our Credit Facility and term debt.2020.
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(Gain) loss on derivative contracts 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.

Callon Petroleum CompanyManagement’s Discussion and Analysis of Financial Condition and Results
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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 $5.1 million net gain for the same period of 2016. The net gain (loss)(gain) loss on derivative instruments for the periods indicated includes the following (in millions):following:
Three Months Ended September 30,
2017 2016
Oil derivatives   
Net gain (loss) on settlements$(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

For the nine months ended September 30, 2017, the net gain on derivative contracts was $11.6 million compared to a $11.3 million net loss for the same period of 2016. The net gain (loss) on derivative instruments for the periods indicated includes the following (in millions):
 Nine Months Ended September 30,
 2017 2016
Oil derivatives   
Net gain (loss) on settlements$(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)
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Three Months EndedSix Months Ended June 30,
June 30, 2021March 31, 202120212020
(In thousands)
(Gain) loss on oil derivatives$177,033 $149,561 $326,594 ($134,954)
(Gain) loss on natural gas derivatives12,816 2,697 15,513 11,524 
(Gain) loss on NGL derivatives3,734 1,138 4,872 (4)
(Gain) loss on contingent consideration arrangements(3,120)5,737 2,617 (1,570)
(Gain) loss on September 2020 Warrants liability— 55,390 55,390 — 
(Gain) loss on derivative contracts$190,463 $214,523 $404,986 ($125,004)
See Notes 5“Note 7 - Derivative Instruments and 6 in the Footnotes to the Financial StatementsHedging Activities” and “Note 8 - Fair Value Measurements” for additional information on the Company’s derivative contracts and disclosures related to derivative instruments.information.

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

We recorded income tax benefit of $0.5 million and $0.9 million for the three months ended June 30, 2021 and March 31, 2021, respectively. Since the second quarter of 2020, we have concluded that it is more likely than not that the net deferred tax assets will not be realized and have recorded a full valuation allowance against our deferred tax assets. As long as we continue to conclude that the valuation allowance is necessary, we will not have significant deferred tax expense or benefit.
The Company hadWe recorded income tax benefit of $1.4 million for the six months ended June 30, 2021 compared to income tax expense of $0.2$115.3 million for the same period of 2020. The income tax expense for the six month period in 2020 is due to the recording of the valuation allowance during the three months ended June 30, 2020, which still remained as of June 30, 2021. See “Note 9 - Income Taxes” for further discussion.
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Liquidity and $1.0Capital Resources
2021 Capital Budget and Funding Strategy. Our primary uses of capital are for the exploration and development of our oil and natural gas properties. Our 2021 capital budget has been established at up to $430.0 million, with approximately 80% directed towards drilling, completion, and equipment expenditures. Approximately 70% of our 2021 capital budget is allocated towards development in the Permian with the remaining 30% towards development in the Eagle Ford. As part of our 2021 operated horizontal drilling program, we expect to drill approximately 55 to 65 gross operated wells and complete approximately 90 to 100 gross operated wells. Our 2021 capital budget and the number of wells we expect to drill and complete discussed above does not contemplate incremental activity that may occur subsequent to the planned closing of the Primexx Acquisition.
During the three months ended June 30, 2021, we drilled 8 gross (6.5 net) wells, all in the Permian, and completed 51 gross (49.2 net) wells, with 29.0 net wells completed in Eagle Ford and 20.2 net wells completed in the Permian. We expect to operate an average of three to four drilling rigs and approximately one completion crew during the second half of 2021.
The following table is a summary of our capital expenditures(1) for the three and ninesix months ended SeptemberJune 30, 2017, compared to income tax benefit of $0.1 million and $0.1 million for the same periods of 2016, respectively. The change in income tax expense is primarily related to deferred state income tax expense. The Company had a valuation allowance of $109.8 million as of September 30, 2017. See Note 7 in the Footnotes to the Financial Statements for additional information.2021:

Preferred Stock dividends. Preferred Stock dividends of $1.8 million and $5.5 million 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.

Three Months EndedSix Months Ended
March 31, 2021June 30, 2021June 30, 2021
(In millions)
Operational capital$95.6 $138.3 $233.9 
Capitalized interest24.0 23.9 47.9 
Capitalized G&A11.2 12.1 23.3 
Total$130.8 $174.3 $305.1 
Callon Petroleum Company
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(1)    Capital expenditures, presented on an accrual basis, includes drilling, completions, facilities, and equipment, but excludes land, seismic, and asset retirement costs.
We continually evaluate our capital expenditure needs and compare them to our capital resources. Because we are the operator of a high percentage of our properties, we can control the amount and timing of our capital expenditures. We can choose to defer or accelerate a portion of our planned capital expenditures depending on various factors, including, but not limited to, 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. We plan to execute a more moderated capital expenditure program through reduced reinvestment rates and balanced capital deployment for a more consistent cash flow generation and will be focused to further enhance our multi-zone, scale development program while leveraging our drilled, but uncompleted backlog to drive capital efficiency.
Historically, our primary sources of capital have been cash flows from operations, borrowings under our 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. 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.
We may continue to consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth or enter into joint venture agreements, provided we are able to divest such assets or enter into joint venture agreements on terms that are acceptable to us.
Overview of Cash Flow Activities. For the six months ended June 30, 2021, cash and cash equivalents decreased $16.4 million to $3.8 million compared to $20.2 million at December 31, 2020.
Six Months Ended June 30,
20212020
(In thousands)
Net cash provided by operating activities$313,268 $289,496 
Net cash used in investing activities(217,387)(453,656)
Net cash provided by (used in) financing activities(112,317)158,319 
   Net change in cash and cash equivalents($16,436)($5,841)
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Operating activities. For the six months ended June 30, 2021, net cash provided by operating activities was $313.3 million compared to $289.5 million for the same period in 2020. The change in net cash provided by operating activities was predominantly attributable to the following:
•An increase in revenue primarily driven by a 90% increase in realized oil price, partially offset by a 19% decrease in production volumes,
•Changes in working capital as accounts receivable has increased from December 31, 2020 as a result of the increase in the price of oil,
•An offsetting decrease in the cash received from commodity derivative settlements, and
•An offsetting decrease in operating expenses as a result of lower production volumes as well as our continued improvement of managing our field operating costs.
Production, realized prices, and operating expenses are discussed in Results of Operations. See “Note 7 - Derivative Instruments and Hedging Activities” and “Note 8 - Fair Value Measurements” for a reconciliation of the components of our derivative contracts and disclosures related to derivative instruments including their composition and valuation. 
Investing activities. For the six months ended June 30, 2021, net cash used in investing activities was $217.4 million compared to $453.7 million for the same period in 2020. The decrease in net cash used in investing activities was primarily attributed to the following:
•A decrease in operational capex during the six months ended June 30, 2021 compared to the same period in 2020,
•A decrease in cash paid for the settlement of contingent consideration agreements as net cash payments of $40.0 million were paid in January 2020 related to contingent considerations acquired in the Carrizo Acquisition, and
•An offsetting increase in cash received from the sale of assets due to the divestitures of certain non-core assets in the Delaware Basin.
Financing activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under the Credit Facility, term debt and equity offerings. For the six months ended June 30, 2021, net cash used in financing activities was $112.3 million compared to net cash provided by financing activities of $158.3 million for the same period of 2020. This change was primarily attributable to repayment of approximately $110.0 million on the Credit Facility during the six months ended June 30, 2021, which reflects our continued commitment and focus on deleveraging.
See “Note 6 - Borrowings” for additional information on our debt transactions.
Contractual Obligations. Our contractual obligations primarily consist of long-term debt, operating leases, asset retirement obligations, produced water disposal commitments, and gathering, processing and transportation service commitments. Since December 31, 2020, there have been no material changes to our contractual obligations other than the changes to the borrowings under our Credit Facility as discussed further in “Note 6 - Borrowings”. Also, see “Note 15 - Subsequent Events” for a discussion of the issuance of our 8.00% Senior Notes and the redemption of all of our 6.25% Senior Notes, which occurred subsequent to June 30, 2021.
Credit Facility. As of June 30, 2021, our Credit Facility had a borrowing base of $1.6 billion, with an elected commitment amount of $1.6 billion, borrowings outstanding of $875.0 million at a weighted average interest rate of 2.61%, and $24.0 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 Credit Facility is secured by first preferred mortgages covering our major producing properties. 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.
Our Credit Facility contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. Under the Credit Facility, we 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. We were in compliance with these covenants at June 30, 2021. If we are unable to remain in compliance with our restrictive financial covenants, we could be subject to lender elections for default resolution. However, we expect to have sufficient liquidity to pay interest on our Credit Facility (as well as on the Second Lien Notes and our Senior Unsecured Notes and to fund our development program).
The Credit Facility also places restrictions on us and certain of our subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of our common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
See “Note 6 – Borrowings” for additional information related to the Credit Facility.
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Hedging. As of August 2, 2021, the Company had the following outstanding oil, natural gas and NGL derivative contracts:
For the RemainderFor the Full YearFor the Full Year
Oil contracts (WTI)
of 2021 (1)
of 2022 (1)
of 2023
   Swap contracts
   Total volume (Bbls)1,104,000 3,015,000 — 
   Weighted average price per Bbl$42.10 $63.55 $— 
   Collar contracts
   Total volume (Bbls)5,522,775 7,097,500 — 
   Weighted average price per Bbl
   Ceiling (short call)$49.16 $67.70 $— 
   Floor (long put)$40.71 $56.15 $— 
Long put contracts
Total volume (Bbls)414,000 — — 
Weighted average price per Bbl$62.50 $— $— 
   Short call contracts
   Total volume (Bbls)2,432,480 (2)— — 

   Weighted average price per Bbl$63.62 $— $— 
Short call swaption contracts
   Total volume (Bbls)— 1,825,000 (3)1,825,000 (3)
   Weighted average price per Bbl$— $52.18 $72.00 
Oil contracts (Brent ICE)  
   Swap contracts
   Total volume (Bbls)— (4)— — 
   Weighted average price per Bbl$— $— $— 
Collar contracts
Total volume (Bbls)368,000 — — 
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)1,504,400 — — 
   Weighted average price per Bbl$0.25 $— $— 
Oil contracts (Argus Houston MEH)
   Collar contracts
   Total volume (Bbls)— 452,500 — 
   Weighted average price per Bbl
Ceiling (short call)$— $63.15 $— 
Floor (long put)$— $51.25 $— 
(1)    We have approximately $9.4 million of deferred premiums, of which $6.5 million are associated with contracts that will settle in 2021 and $2.9 million for contracts that will settle in 2022.
(2)    Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.
(3)    The 2022 and 2023 short call swaption contracts have exercise expiration dates of December 31, 2021 and December 30, 2022, respectively.
(4)    In February 2021, we entered into certain offsetting ICE Brent swaps to reduce our exposure to rising oil prices. Those offsetting swaps resulted in a locked-in loss of approximately $2.9 million, of which $1.6 million will be settled in the third quarter of 2021 with the remaining $1.3 million to be settled in the fourth quarter of 2021.
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For the RemainderFor the Full Year
Natural gas contracts (Henry Hub)of 2021of 2022
   Swap contracts
      Total volume (MMBtu)7,301,000 7,320,000 
      Weighted average price per MMBtu$2.61 $3.08 
Collar contracts
      Total volume (MMBtu)3,680,000 5,740,000 
      Weighted average price per MMBtu
         Ceiling (short call)$2.80 $3.64 
         Floor (long put)$2.50 $2.83 
   Short call contracts
      Total volume (MMBtu)3,680,000 (1)— 
      Weighted average price per MMBtu$3.09 $— 
Natural gas contracts (Waha basis differential)
   Swap contracts
      Total volume (MMBtu)8,280,000 5,475,000 
      Weighted average price per MMBtu($0.42)($0.21)
(1)    Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.
For the RemainderFor the Full Year
NGL contracts (OPIS Mont Belvieu Purity Ethane)of 2021of 2022
   Swap contracts
      Total volume (Bbls)920,000 — 
      Weighted average price per Bbl$7.62 $— 
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 2020 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.
The table below presents various pricing scenarios to demonstrate the sensitivity of our June 30, 2021 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-month average realized prices. The sensitivity analysis is as of June 30, 2021 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to June 30, 2021 that may require revisions to estimates of proved reserves. See also “Part I, Item 1A. Risk Factors—If oil
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and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties” in our 2020 Annual Report.
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)
June 30, 2021 Actual$48.06$1.55$1,044
Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%$53.04$1.79$1,684$640
Crude Oil and Natural Gas -10%$43.08$1.31$406($638)
Crude Oil Price Sensitivity
Crude Oil +10%$53.04$1.55$1,637$593
Crude Oil -10%$43.08$1.55$453($591)
Natural Gas Price Sensitivity
Natural Gas +10%$48.06$1.79$1,091$47
Natural Gas -10%$48.06$1.31$997($47)
Income taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards.
Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that
our net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at June 30, 2021, driven primarily by impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the fourth quarter of 2020, which limits the ability to consider other subjective evidence such as our potential for future growth. Since the second 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, reducing the net deferred tax assets as of June 30, 2021 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 our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude us from utilizing the tax attributes if we recognize taxable income. As long as we continue to conclude that the valuation allowance against our net deferred tax assets is necessary, we will have no significant deferred income tax expense or benefit. See “Note 9 - Income Taxes” for additional discussion.
Recently Adopted and Recently Issued Accounting Pronouncements
See “Note 1 - Description of Business and Basis of Presentation” for discussion.
Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We 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 itsour 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 conditions, and government actions. weather conditions. 
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The following table sets forth oil, natural gas and NGL revenues for the three months ended June 30, 2021 as well as the impact on the oil, natural gas and NGL revenues assuming a 10% increase or decrease in our average realized sales prices for oil, natural gas and NGLs, excluding the impact of commodity derivative settlements:
Three Months Ended June 30, 2021
OilNatural GasNGLsTotal
(In thousands)
Revenues$333,442$24,080$36,625$394,147
Impact of a 10% fluctuation in average realized prices$33,344$2,408$3,663$39,415
Six Months Ended June 30, 2021
OilNatural GasNGLsTotal
(In thousands)
Revenues$600,487$48,300$65,982$714,769
Impact of a 10% fluctuation in average realized prices$60,049$4,830$6,598$71,477
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 forecastforecasted production for the next 12 to 24 months, subject to the covenants under our Credit Facility. 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,June 30, 2021, for the remainder of 2017.2021, we had 6,994,775 Bbls of fixed price oil hedges across NYMEX WTI, ICE Brent and Argus WTI-Houston benchmarks. We also have commodity hedging contracts linked to Midlandhad 1,504,400 Bbls of WTI Midland-Cushing oil basis differentials relative to Cushing covering approximately 552 MBbls of our expected oil productionhedges. Additionally, for the remainder of 2017.2021, we had 10,981,000 MMBtus of fixed price NYMEX natural gas hedges and 8,280,000 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’sour outstanding derivative contracts at Septemberas of June 30, 2017, and derivative contracts established subsequent to that date.2021.

The CompanyWe may utilize fixed price swaps, which reduce the Company’sour exposure to decreases in commodity prices, and limitbut limits the benefit the Companywe 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 CompanyWe also 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,us, and if the price rises above the ceiling, the counterparty receives the difference from the Company.us. Additionally, the Companywe 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’sour net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis.

The CompanyWe may purchase put and call options, which reduce the Company’sour 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.us.

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

Interest rate risk

The Company isWe are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. ThoughAs of June 30, 2021, we had no balance outstanding on our Credit Facility at September 30, 2017, based on a notional amount of $10$875.0 million outstanding under the facility, anCredit Facility with a weighted average interest rate of 2.61%. An increase or decrease of 1%1.00% in the interest rate would have a corresponding increase or decrease in our annual net incomeinterest expense of approximately $0.1 million.$8.8 million, based on the balance outstanding as of June 30, 2021. See Note 4 to the Consolidated Financial Statements“Note 6 - Borrowings” for more information on the Company’s interest rates on itsour Credit Facility.

Counterparty and customer credit risk

The Company’sOur 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 itsWe market our oil, and natural gas and NGL production to energy marketing companies. Wecompanies and 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
Callon Petroleum Company
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collateral, and theThe inability of our significant customers
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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 SeptemberJune 30, 20172021, our total receivables from the sale of our oil, and natural gas and NGL production were approximately $51.3 million.$148.7 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. We generally have the right to withhold future revenue distributions to recover past due receivables from joint interest owners. The allowance for credit losses related to our joint interest receivables is immaterial. At SeptemberJune 30, 20172021, our joint interest receivables were approximately $30.0 million.$12.9 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 onof our commodity derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional commodity derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing 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 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 June 30, 2021, we had a net commodity derivative liability position of $315.5 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 management, with the participation of the Chief Executive Officer and Chief Financial Officer, performed an evaluation of the effectiveness 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 SeptemberJune 30, 2017.2021.

Changes in internal control over financial reporting. There were no changes toin our 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 second quarter of 2021 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 not currently a defendant in variousparty to, nor is our property currently subject to, any material legal proceedings other than ordinary routine litigation incidental to the business, and claims, which arise in the ordinary course of our business. We dowe are not believe the ultimate resolutionaware of any such actions will have a material effect on our financial position or results of operations.proceedings contemplated by governmental authorities.

Item 1A. Risk Factors

There have been no material changes with respect to the risk factors disclosedset forth under the heading “Part I, Item 1A. Risk Factors” included in our 20162020 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
Certificate of Amendment to the Certificate of Incorporation of Callon, effective May 14, 2021
8-K3.15/14/2021
3.5
Amended and Restated Bylaws of the Company
10-K3.22/27/2019
4.1
Indenture, dated as of July 6, 2021, by and among the Company, Callon Petroleum Operating Company, Callon (Eagle Ford) LLC, Callon (Niobrara) LLC, Callon (Permian) LLC, Callon (Permian) Minerals LLC, Callon (Utica) LLC, Callon Marcellus Holding, Inc. and U.S. Bank National Association, as trustee.
8-K4.17/7/2021
10.1(c)8-K10.14/16/2021
10.2(c)8-K10.24/16/2021
10.3(c)8-K10.34/16/2021
10.4(c)8-K10.44/16/2021
10.5(c)8-K10.54/16/2021
10.610-Q10.65/6/2021
10.7
Purchase Agreement, dated as of June 21, 2021, among Callon Petroleum Company, the Guarantors and BofA Securities, Inc., as representative of the several initial purchasers.
8-K10.16/22/2021
31.1(a)
Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)
31.2(a)
Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)
32.1(b)
Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b)
101.INS(a)XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH(a)Inline XBRL Taxonomy Extension Schema Document
101.CAL(a)Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF(a)Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB(a)Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE(a)Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104(a)Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
(a)Filed herewith.
(b)Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act, except to the extent that the registrant specifically incorporates it by reference.
(c)Indicates management compensatory plan, contract, or arrangement.

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.
(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.
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SIGNATURES


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


Callon Petroleum Company

SignatureTitleDate
SignatureTitleDate
/s/ Joseph C. Gatto, Jr.President andNovember 6, 2017August 4, 2021
Joseph C. Gatto, Jr.Chief Executive Officer

/s/ Correne S. LoefflerKevin HaggardTreasurerSenior Vice President andNovember 6, 2017August 4, 2021
Correne S. LoefflerKevin HaggardInterim Chief Financial Officer



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