0000928022false00009280222022-02-232022-02-23

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 23, 2022
https://cdn.kscope.io/7fa391f7202fc561b80207205d438c3d-cpe-20220223_g1.jpg
Callon Petroleum Company
(Exact name of registrant as specified in its charter)
DE001-1403964-0844345
(State or other jurisdiction of incorporation)(Commission File Number)(I.R.S. Employer Identification Number)

One Briarlake Plaza
2000 W. Sam Houston Parkway S., Suite 2000
Houston, TX 77042
(Address of principal executive offices, including zip code)

(281) 589-5200
(Registrant’s telephone number, including area code)
(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

    Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
    Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
    Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
    Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, $0.01 par valueCPENYSE

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (17 CFR §240.12b-2).
                                    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.                 



Item 2.02. Results of Operations and Financial Condition
The following information, including the press release attached as Exhibit 99.1, is being furnished pursuant to Item 2.02 “Results of Operations and Financial Condition,” not filed, for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This information shall not be deemed “filed” for purposes of Section 18 of the Exchange Act or incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.
On February 23, 2022, Callon Petroleum Company issued the press release attached as Exhibit 99.1 providing information regarding the Company’s fourth quarter and full-year 2021 financial and operating results, 2022 outlook, and current corporate strategy and initiatives.
Item 7.01 Regulation FD
The information set forth under Item 2.02 is incorporated herein by reference.
Item 9.01. Financial Statements and Exhibits

    (d) Exhibits
Exhibit NumberTitle of Document
99.1




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 hereunto duly authorized.
Callon Petroleum Company
(Registrant)
February 23, 2022/s/ Kevin Haggard
Kevin Haggard
Senior Vice President and Chief Financial Officer



Exhibit 99.1
Callon Petroleum Company Announces Fourth Quarter and Full Year 2021 Results and Provides 2022 Plan Focused on Free Cash Flow and Debt Reduction Initiatives

HOUSTON, Texas (February 23, 2022) - Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three months and full-year ended December 31, 2021.
Presentation slides accompanying this earnings release are available on the Company’s website at www.callon.com located on the “Presentations” page within the Investors section of the site.
2021 Highlights
Full-year 2021 production of 95.6 MBoe/d (64% oil)
Year-end proved reserves of 484.6 MMBoe (60% oil) with a standardized measure of future discounted cash flows of total proved reserves of $6.3 billion
PV-10 of total proved reserves of $7.1 billion; Proved developed reserves represent 57% of total reserve volumes with an associated PV-10 of $4.5 billion
Generated net cash provided by operating activities of $974.1 million and adjusted free cash flow of $274.2 million
Net income of $365.2 million, or $7.26 per diluted share, adjusted EBITDA of $998.8 million, and adjusted income of $437.4 million or $8.69 per diluted share
Achieved a full year operating margin of $42.05 per Boe, a 141% increase over last year
Announced approximately $210 million in non-core asset sales
Asset monetization proceeds, debt exchanges, and free cash flow contributed to a reduction in total debt of approximately $760 million, excluding cash consideration paid for acquisitions
Exited the year with a net debt / last twelve months EBITDA ratio of 2.3x pro forma for the Primexx acquisition and a net debt / fourth quarter annualized EBITDA of 2.0x
Fourth Quarter 2021 Highlights
Fourth quarter 2021 production of 112.4 MBoe/d (64% oil) with 16.8 net wells placed on production
Generated $366.3 million of net cash provided by operating activities and adjusted free cash flow of $123.6 million
Net income of $285.4 million, or $4.78 per diluted share, adjusted EBITDA of $339.2 million, and adjusted income of $159.2 million or $2.66 per diluted share
Achieved an operating margin of $48.71 per Boe, a 130% increase over last year
Closed the acquisition of 35,000 net acres and approximately 18,000 net barrels of oil equivalent per day in the Delaware Basin
Realized $153 million in proceeds through the divestiture of non-core Eagle Ford and Midland producing assets and water infrastructure assets
2022 Capital Plan Highlights
Operational capital budget of $725 million, with approximately 85% allocated to the Permian Basin
Annual production guidance of 101 - 105 MBoe/d (64% oil)
Transition to more efficient, larger scale development on recently acquired southern Delaware properties with an expanded drilled and uncompleted well inventory and execute on identified opportunities to reduce lifting costs by 30%
Maintenance capital spending program driving stable production profile relative to 2021 after adjusting for acquisitions and divestitures
Expected adjusted free cash flow generation of greater than $500 million and an estimated reinvestment rate1 of less than 60% at $75/Bbl oil (WTI benchmark)
Joe Gatto, President and Chief Executive Officer commented, “During the fourth quarter and throughout the year, our team has outperformed expectations and set new records, all the while dealing with pandemic-related workplace challenges and a dynamic industry environment. Our operations team once again delivered solid results with production for the fourth quarter and the full year coming in at the high end of guidance while delivering our program under budget for the year.
“In 2021, Callon successfully completed a large acquisition that was both accretive and deleveraging. We followed through on our monetization targets for the year, announcing approximately $210 million in gross proceeds from non-core asset sales. Financially, we set several new records, generating record net income of $365.2 million and annual adjusted EBITDA of $999 million which represents an increase of over 40% relative to last year. Our capital discipline and high margins enabled us to deliver $274 million in
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adjusted free cash flow, a new company record. These outstanding achievements allowed us to dramatically improve the balance sheet and reduce Callon’s leverage ratio by over 2x during the year. We look forward to raising the bar even further in 2022.

“Our 2022 capital budget reflects both our continued commitment to capital discipline and a greater focus on Callon’s high rate of return Permian Basin assets. Inclusive of capitalized expenses, our capital budget implies a reinvestment rate1 of approximately 60% of adjusted discretionary cash flow at $75 per barrel WTI price and an adjusted free cash flow breakeven price of approximately $40 per barrel. We are in the process of implementing our operating model on the recently acquired Delaware assets and are actively taking measures to improve both production efficiency and operating cost structure. After completing our work to transition the acquired assets to larger project developments in the first quarter, we expect to generate oil production growth in excess of 10% over the course of the year.
“The industry continues to face inflationary cost pressures in items like steel tubulars and fuel, as well as overall labor and service costs. These inflationary pressures have increased estimated spot market well costs by over 15% based on recent data points. Given our scaled program of steady development activity and longer-term agreements with service providers, we expect to benefit from a wide range of efficiencies and limit the anticipated inflationary impact on our well costs to approximately 10%.
“Based on our planned operational activity and leading operating margins, we expect to generate over $500 million in adjusted free cash flow in 2022, based on $75 per barrel. This level of free cash flow puts us on a path to further reduce our absolute debt levels and achieve a leverage ratio of less than 1.5x by year end 2022,” concluded Mr. Gatto.
Environmental, Social, and Governance (“ESG”) Updates
Callon advanced its sustainability initiatives during 2021 with the Company achieving numerous milestones as detailed below:
Issued its second sustainability report, aligned with SASB and TCFD frameworks
Completed the second series of field electrification projects in the Eagle Ford and Delaware Basin
Improved its carbon footprint through flaring reduction initiatives
Reduced its spill occurrences and total fluid spill rate
Invested in employee development and wellness with the initiation of the Employee Development Program and Employee Wellness Program
Expanded community engagement through employee volunteering and financial support of education, social, and environmental initiatives
The Company remains committed to continued GHG emission reductions. As a result of these achievements, Callon made significant progress in environmental performance in 2021 and is announcing the adoption of more aggressive reduction goals:
End routine flaring by end of 2022, an acceleration of three years versus the previous goal
50% reduction in GHG intensity by 2024, targeting the high end of previous guidance and accelerating the achievement timeline by one year
Reduce all flaring to less than 1% by 2024
Reduce methane intensity to less than 0.2% by 2024
To advance these goals, Callon will be investing nearly $20 million in emission reduction projects this year as part of a broader multi-year emission reduction program. This capital allocation will help expand the field electrification and other system upgrades that will allow Callon to continue to reduce its greenhouse gas emissions and overall carbon footprint.
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Operations Update and Outlook
At December 31, 2021, Callon had 1,326 gross (1,187.1 net) horizontal wells producing from established flow units in the Permian and Eagle Ford. Net daily production for the three months ended December 31, 2021 grew 18% to 112.4 MBoe/d (64% oil) as compared to the same period of 2020. Full year production for 2021 averaged 95.6 MBoe/d (64% oil), a decrease of 6% over 2020 volumes.
For the three months ended December 31, 2021, Callon drilled 27 gross (24.9 net) horizontal wells and placed a combined 19 gross (16.8 net) horizontal wells on production. Wells placed on production during the quarter were completed in the Lower Spraberry and Wolfcamp A in the Midland Basin and the 3rd Bone Spring, Wolfcamp A and Wolfcamp C in the Delaware Basin.
Currently, the Company has seven active rigs with four in the Delaware Basin, one in the Eagle Ford, and two in the Midland Basin. Callon plans to release one of the Delaware rigs in late April. The Company is operating two completion crews with operations currently in the Delaware Basin.
2022 Capital Expenditures Budget
Callon has established an operational capital expenditure budget of $725 million for 2022 with approximately 83% of spending directed towards drilling, completion and equipment expenditures. The increase of approximately $216 million from 2021 levels reflects an increase in the number of drilled wells and the impact of cost inflation on items such as fuel, steel and labor. The Company’s 2022 development capital will be primarily focused on the Permian Basin, representing approximately 85% of the total budget.
The Permian development plan is characterized by large multi-bench project developments as the Company employs the life of field development philosophy. Permian development activity will predominantly feature co-development of the Wolfcamp A and B in the Delaware Basin and the Lower Spraberry and Wolfcamp A and B in the Midland Basin. The Eagle Ford program remains focused on the well-established target zone, the Lower Eagle Ford Shale, with the Company also planning to test the Austin Chalk in the second half of the year. In total, Callon expects to drill 125 to 130 gross wells and complete 113 to 118 gross wells.
The 2022 capital plan will leverage the structural savings and operational efficiencies that result from an integrated supply chain management focus and extensive experience operating in the Permian Basin and Eagle Ford. In particular, the Company believes that overlaying its development model on the newly acquired Delaware acreage will yield significant improvements in capital efficiency and operating cost structure. A repeatable program of moderated development activity, combined with service agreements to manage capital costs and strong operating cash margins, are expected to provide a foundation of durable free cash flow in 2022 and beyond.
The remainder of Callon’s full year 2022 outlook is provided later in this release under the section titled “2022 Guidance.”
Capital Expenditures
For the year ended December 31, 2021, Callon incurred $508.6 million in operational capital expenditures on an accrual basis as compared to $488.6 million in 2020. For the three months ended December 31, 2021, the Company incurred $159.8 million in operational capital expenditures on an accrual basis, which represented a $44.8 million increase from the third quarter of 2021. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis:
Three Months Ended December 31, 2021
OperationalCapitalizedCapitalizedTotal Capital
Capital (a)
InterestG&AExpenditures
(In thousands)
Cash basis (b)
$117,502 $22,398 $11,035 $150,935 
Timing adjustments (c)
46,357 193 — 46,550 
Non-cash items(4,073)3,001 2,588 1,516 
   Accrual basis$159,786 $25,592 $13,623 $199,001 
(a)Includes drilling, completions, facilities and equipment, but excludes land, seismic, and asset retirement costs.
(b)Cash basis is presented here to help users of financial information reconcile amounts from the cash flow statement to the balance sheet by accounting for timing related changes in working capital that align with our development pace and rig count.
(c)Includes timing adjustments related to cash disbursements in the current period for capital expenditures incurred in the prior period.
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Hedge Portfolio Summary
As of February 18, 2022, Callon had the following outstanding oil, natural gas and NGL derivative contracts:
For the Full YearFor the Full Year
Oil Contracts (WTI)20222023
Swap Contracts
Total volume (Bbls)5,891,000 905,000 
Weighted average price per Bbl$61.61 $71.20 
Collar Contracts
Total volume (Bbls)7,097,500 2,096,500 
Weighted average price per Bbl
Ceiling (short call)$67.70 $80.25 
Floor (long put)$56.15 $69.48 
Short Call Swaption Contracts a
Total volume (Bbls)— 1,825,000 
Weighted average price per Bbl$— $72.00 
Oil Contracts (Midland Basis Differential)
Swap Contracts
Total volume (Bbls)2,372,500 — 
Weighted average price per Bbl$0.50 $— 
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 $— 
(a)The 2023 short call swaption contracts have exercise expiration dates of December 30, 2022.

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For the Full YearFor the Full Year
Natural Gas Contracts (Henry Hub)20222023
Swap Contracts
Total volume (MMBtu)11,600,000 — 
Weighted average price per MMBtu$3.65 $— 
Collar Contracts
Total volume (MMBtu)9,100,000 1,800,000 
Weighted average price per MMBtu
Ceiling (short call)$4.14 $5.59 
Floor (long put)$3.29 $4.63 
Natural Gas Contracts (Waha Basis Differential)
Swap Contracts
Total volume (MMBtu)1,220,000 6,080,000 
Weighted average price per MMBtu($0.75)($0.75)
For the Full Year
NGL Contracts (OPIS Mont Belvieu Purity Ethane)2022
Swap Contracts
Total volume (Bbls)378,000 
Weighted average price per Bbl$15.70 
NGL Contracts (OPIS Mont Belvieu Non-TET Propane)
Swap Contracts
Total volume (Bbls)252,000 
Weighted average price per Bbl$48.43 
NGL Contracts (OPIS Mont Belvieu Non-TET Butane)
Swap Contracts
Total volume (Bbls)99,000 
Weighted average price per Bbl$54.39 
NGL Contracts (OPIS Mont Belvieu Non-TET Isobutane)
Swap Contracts
Total volume (Bbls)54,000 
Weighted average price per Bbl$54.29 
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Operating and Financial Results
The following table presents summary information for the periods indicated:
Three Months EndedYear Ended
 December 31, 2021September 30, 2021December 31, 2020December 31, 2021
Total production  
Oil (MBbls)
Permian 4,7273,4283,44514,475
Eagle Ford1,8392,4471,9807,749
Total oil6,5665,8755,42522,224
Natural gas (MMcf)
Permian9,1837,1537,47429,682
Eagle Ford2,0902,2422,2647,704
Total natural gas11,2739,3959,73837,386
NGLs (MBbls)
Permian1,5491,3151,3315,155
Eagle Ford3444173531,284
Total NGLs 1,8931,7321,6846,439
Total production (MBoe)
Permian7,8065,9366,02224,577
Eagle Ford2,5323,2372,71010,317
Total barrels of oil equivalent10,3389,1738,73234,894
Total daily production (Boe/d)
Permian84,84864,51765,45967,334
Eagle Ford27,51735,18629,45528,265
Total barrels of oil equivalent112,36599,70394,91495,599
Oil as % of total daily production64 %64 %62 %64 %
Average realized sales price
(excluding impact of derivative settlements)
Oil (per Bbl)
Permian$76.86$69.60$41.02$68.20
Eagle Ford77.8469.7641.1268.27
Total oil$77.13$69.67$41.06$68.22
Natural gas (per Mcf)
Permian$4.81$3.78$1.68$3.69
Eagle Ford6.004.222.654.13
Total natural gas$5.03$3.89$1.91$3.78
NGL (per Bbl)
Permian$37.50$34.41$15.00$30.60
Eagle Ford34.0030.8116.1628.12
Total NGL$36.86$33.54$15.24$30.11
Average realized sales price (per Boe)
Permian$59.64$52.37$28.87$51.05
Eagle Ford66.1059.6334.3657.86
Total average realized sales price$61.22$54.93$30.57$53.06
Average realized sales price
(including impact of derivative settlements)
Oil (per Bbl)$57.05$54.00$39.62$51.22
Natural gas (per Mcf)3.812.211.892.84
NGLs (per Bbl)34.5631.7115.2428.54
Total average realized sales price (per Boe)$46.72$42.84$29.66$40.93
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Three Months EndedYear Ended
December 31, 2021September 30, 2021December 31, 2020December 31, 2021
Revenues (in thousands)(a)
Oil
Permian$363,306$238,582$141,320$987,195
Eagle Ford143,139170,71181,413529,030
Total oil$506,445$409,293$222,733$1,516,225
Natural gas
Permian$44,133$27,065$12,560$109,640
Eagle Ford12,5419,4546,00131,853
Total natural gas$56,674$36,519$18,561$141,493
NGLs
Permian$58,085$45,249$19,964$157,757
Eagle Ford11,69712,8485,70436,104
Total NGLs$69,782$58,097$25,668$193,861
Total revenues
Permian$465,524$310,896$173,844$1,254,592
Eagle Ford167,377193,01393,118596,987
Total revenues$632,901$503,909$266,962$1,851,579
Additional per Boe data    
Sales price (b)
Permian$59.64$52.37$28.87$51.05
Eagle Ford66.1059.6334.3657.86
Total sales price$61.22$54.93$30.57$53.06
Lease operating expense
Permian$7.22$4.19$4.43$5.27
Eagle Ford6.775.516.777.13
Total lease operating expense$7.11$4.66$5.15$5.82
Production and ad valorem taxes
Permian$3.15$2.80$1.71$2.75
Eagle Ford3.602.892.293.16
Total production and ad valorem taxes$3.26$2.84$1.89$2.87
Gathering, transportation and processing
Permian$2.26$2.70$2.42$2.54
Eagle Ford1.761.492.251.80
Total gathering, transportation and processing$2.14$2.28$2.37$2.32
Operating margin
Permian$47.01$42.68$20.31$40.49
Eagle Ford53.9749.7423.0545.77
Total operating margin$48.71$45.16$21.16$42.05
Depletion, depreciation and amortization$10.89$9.80$11.00$10.22
General and administrative$1.27$1.04$1.22$1.45
Adjusted G&A
Cash component (c)
$1.18$1.13$0.86$1.08
Non-cash component$0.12$0.17$0.07$0.18

(a)Excludes sales of oil and gas purchased from third parties.
(b)Excludes the impact of settled derivatives.
(c)Excludes the change in fair value and amortization of share-based incentive awards and other non-recurring expenses.
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Revenue. For the quarter ended December 31, 2021, Callon reported total revenue of $632.9 million, which excluded revenue from sales of commodities purchased from a third-party of $59.3 million. Total revenue increased $129.0 million during the fourth quarter of 2021 as compared to the third quarter of 2021 primarily as a result of an 11% increase in the price of oil as well as a 13% increase in production. Revenues including the gain or loss from the settlement of derivative contracts (“Adjusted Total Revenue”1) were $483.0 million, reflecting the impact of a $149.9 million loss from the settlement of derivative contracts. Average daily production for the quarter was 112.4 MBoe/d compared to average daily production of 99.7 MBoe/d in the third quarter of 2021. Average realized prices, including and excluding the effects of hedging, are detailed above.
Commodity Derivatives. For the quarter ended December 31, 2021, the net (gain) loss on commodity derivative contracts includes the following (in thousands):
Three Months Ended
December 31, 2021
(Gain) loss on oil derivatives$35,364 
(Gain) loss on natural gas derivatives(14,918)
(Gain) loss on NGL derivatives(8,346)
(Gain) loss on commodity derivative contracts$12,100 
For the quarter ended December 31, 2021, the cash (paid) received for commodity derivative settlements includes the following (in thousands):
Three Months Ended
December 31, 2021
Cash (paid) received on oil derivatives($129,228)
Cash (paid) received on natural gas derivatives(21,709)
Cash (paid) received on NGL derivatives(5,782)
Cash (paid) received for commodity derivative settlements($156,719)
Lease Operating Expenses, including workover (“LOE”). LOE per Boe for the three months ended December 31, 2021 was $7.11 per Boe, compared to $4.66 per Boe in the third quarter of 2021. The increase in LOE per Boe is primarily attributable to the addition of the recently acquired Delaware production as well as overall cost inflation in materials and labor.
Production and Ad Valorem Taxes. Production and ad valorem taxes were $3.26 per Boe for the three months ended December 31, 2021, representing approximately 5.3% of revenue excluding revenue from sales of commodities purchased from a third-party and before the impact of derivative settlements.
Gathering, Transportation and Processing. Gathering, transportation and processing for the three months ended December 31, 2021 were $22.1 million, or $2.14 per Boe, as compared to $20.9 million, or $2.28 per Boe in the third quarter of 2021. The decrease in gathering, transportation and processing per Boe was primarily attributable to the addition of the recently acquired Delaware production which carried lower gathering, transportation and processing fees.
Depreciation, Depletion and Amortization (“DD&A”). DD&A for the three months ended December 31, 2021 was $10.89 per Boe compared to $9.80 per Boe in the third quarter of 2021. The increase in DD&A per Boe was primarily attributable to a larger percentage increase in production as compared to the depletion rate of our proved reserves from the third quarter of 2021 to the fourth quarter of 2021.
General and Administrative Expense (“G&A”). G&A for the three months ended December 31, 2021 and September 30, 2021 was $13.1 million and $9.5 million, respectively. G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, (“Adjusted G&A1” ) was $13.4 million for the three months ended December 31, 2021 compared to $12.0 million for the third quarter of 2021. The cash component of Adjusted G&A of $12.2 million for the fourth quarter of 2021 increased as compared to $10.4 million for the third quarter of 2021 primarily as a result of increased compensation costs during the fourth quarter.
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The following table reconciles total G&A to Adjusted G&A - cash component, and full cash G&A (in thousands):
Three Months EndedYear Ended
December 31, 2021September 30, 2021December 31, 2020December 31, 2021
Total G&A$13,116 $9,503 $10,614 $50,483 
Change in the fair value of liability share-based awards (non-cash)296 2,492 (2,500)(6,710)
Adjusted G&A – total13,412 11,995 8,114 43,773 
Equity settled, share-based compensation (non-cash) and other non-recurring expenses(1,230)(1,589)(580)(6,208)
Adjusted G&A – cash component$12,182 $10,406 $7,534 $37,565 
Capitalized cash G&A11,035 9,034 6,465 34,386 
Full cash G&A$23,217 $19,440 $13,999 $71,951 
Income Tax. Callon provides for income taxes at a federal statutory rate of 21% adjusted for permanent differences expected to be realized. The Company recorded income tax benefit of $0.8 million for the three months ended December 31, 2021, compared to $2.4 million income tax expense for the three months ended September 30, 2021. 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.
Adjusted EBITDA. Net income was $285.4 million and adjusted EBITDA was $339.2 million for the fourth quarter of 2021 as compared to net income of $171.9 million and adjusted EBITDA of $292.2 million for the third quarter of 2021. The increases in net income and adjusted EBITDA from the third quarter of 2021 were primarily due to incorporating the assets recently acquired in the southern Delaware as well as an increase in the price of oil partially offset by higher payments on derivative settlements.
Proved Reserves
DeGolyer and MacNaughton prepared the estimates of Callon’s proved reserves as of December 31, 2021. As of December 31, 2021, Callon’s estimated net proved reserves were 484.6 MMBoe and included 290.3 MMBbls of oil, 577.3 Bcf of natural gas, and 98.1 MMBbls of NGLs with a standardized measure of discounted future net cash flows of $6.3 billion using average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year of $65.44/Bbl for oil, $3.31/Mcf for natural gas, and $29.19/Bbl for NGLs.
Oil constituted approximately 60% of the Company’s estimated equivalent proved developed reserves as well as the Company’s estimated equivalent total proved reserves. The Company added 36.2 MMBoe of new reserves in extensions and discoveries through development efforts in 2021, with a total of 68 gross (61.3 net) wells drilled and 112 gross (103.8 net) wells completed.
The changes in Callon’s estimated net proved reserves are as follows:
Total
(MBoe)
Proved reserves at December 31, 2020475,879 
Extensions and discoveries36,180 
Revisions to previous estimates(14,181)
Purchase of reserves in place57,652 
Sales of reserves in place(36,015)
Production(34,894)
Proved reserves at December 31, 2021484,621 
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2021 Full Year Actuals
Full Year
2021 Actual
Total production (MBoe/d)95.6
Oil64%
NGL18%
Natural gas18%
Income statement expenses (in millions, except where noted)
LOE, including workovers$203.1
Gathering, transportation and processing$81.0
Production and ad valorem taxes (% of total oil, natural gas, and NGL revenues)5.4%
Adjusted G&A - cash component (a)
$37.6
Adjusted G&A - non-cash component (b)
$6.2
Cash interest expense, net$91.9
Capital expenditures (in millions, accrual basis)
Total operational capital (c)
$508.6
Capitalized interest and G&A$134.0
Gross operated wells drilled / completed68 / 112
(a)Excludes the change in fair value and amortization of share-based incentive awards and other non-recurring expenses.
(b)Amortization of equity-settled, share based incentive awards and other non-recurring expenses.
(c)Includes facilities, equipment, seismic, land and other items, excludes capitalized expenses.
2022 Guidance
Full Year
2022 Guidance
Total production (MBoe/d)101 - 105
Oil64%
NGL19%
Natural gas17%
Income statement expenses (in millions except where noted)
LOE, including workovers$275 - $295
Gathering, transportation and processing$75 - $85
Production and ad valorem taxes (% of total oil, natural gas, and NGL revenues)6.0%
Adjusted G&A: cash component (a)
$50 - $60
Adjusted G&A: non-cash component (b)
$5 - $15
Cash interest expense, net$55 - $60
Estimated effective income tax rate22%
Capital expenditures (in millions, accrual basis)
Total operational capital (c)
$725
Cash capitalized interest$110 - $115
Cash capitalized G&A$35 - $40
Gross operated wells drilled / completed125 - 130 / 113 - 118
(a)Excludes the change in fair value and amortization of share-based incentive awards and other non-recurring expenses.
(b)Amortization of equity-settled, share based incentive awards and other non-recurring expenses.
(c)Includes facilities, equipment, seismic, land and other items, excludes capitalized expenses.
For the first quarter, the Company expects to produce between 100 and 102 Boe/d (63% oil) with between 16 and 18 gross wells placed on production. In addition, Callon projects an operational capital spending level of between $175 and $185 million on an accrual basis.
10


Adjusted Income and Adjusted EBITDA. The Company reported net income of $285.4 million for the three months ended December 31, 2021, or $4.78 per diluted share, and adjusted income of $159.2 million, or $2.66 per diluted share. The following tables reconcile the Company’s net income (loss) to adjusted income and adjusted EBITDA:
Three Months EndedYear Ended
December 31, 2021September 30, 2021December 31, 2020December 31, 2021
(In thousands except per share data)
Net income (loss)$285,351 $171,902 ($505,071)$365,151 
Loss on derivatives contracts10,145 107,169 125,739 522,300 
Loss on commodity derivative settlements, net(149,938)(110,960)(7,938)(423,306)
Non-cash expense (benefit) related to share-based awards939 (903)2,968 12,923 
Impairment of evaluated oil and gas properties— — 585,767 — 
Merger, integration and transaction11,271 3,018 2,120 14,289 
Other (income) expense1,072 4,305 5,328 7,655 
(Gain) loss on extinguishment of debt43,460 (2,420)(170,370)41,040 
Tax effect on adjustments above(a)
17,441 (44)(114,159)(36,729)
Change in valuation allowance(60,585)(34,190)118,388 (65,972)
Adjusted income$159,156 $137,877 $42,772 $437,351 
Adjusted income per diluted share$2.66 $2.93 $1.00 $8.69 
Basic WASO59,143 46,290 39,752 48,612 
Diluted WASO (GAAP)59,737 47,096 39,752 50,311 
Effective of potentially dilutive instruments— — 2,892 — 
Adjusted Diluted WASO59,737 47,096 42,644 50,311 
(a)Calculated using the federal statutory rate of 21%.

Three Months EndedYear Ended
December 31, 2021September 30, 2021December 31, 2020December 31, 2021
(In thousands)
Net income (loss)$285,351 $171,902 ($505,071)$365,151 
Loss on derivatives contracts10,145 107,169 125,739 522,300 
Loss on commodity derivative settlements, net(149,938)(110,960)(7,938)(423,306)
Non-cash expense (benefit) related to share-based awards939 (903)2,968 12,923 
Impairment of evaluated oil and gas properties— — 585,767 — 
Merger, integration and transaction11,271 3,018 2,120 14,289 
Other (income) expense1,072 4,305 5,328 7,655 
Income tax (benefit) expense(837)2,416 6,755 180 
Interest expense, net25,226 27,736 26,486 102,012 
Depreciation, depletion and amortization112,551 89,890 96,037 356,556 
(Gain) loss on extinguishment of debt43,460 (2,420)(170,370)41,040 
Adjusted EBITDA$339,240 $292,153 $167,821 $998,800 
11


Adjusted Free Cash Flow. The following table reconciles the Company’s net cash provided by operating activities to adjusted EBITDA and adjusted free cash flow:
Three Months Ended
December 31, 2021September 30, 2021June 30, 2021March 31, 2021December 31, 2020
(In thousands)
Net cash provided by operating activities$366,310 $294,565 $175,603 $137,665 $134,578 
Changes in working capital and other(67,390)(30,355)13,520 30,913 12,011 
Changes in accrued hedge settlements6,781 (153)(14,719)(20,117)(5,055)
Cash interest expense, net22,268 25,078 22,383 22,159 24,167 
Merger, integration and transaction11,271 3,018 — — 2,120 
Adjusted EBITDA$339,240 $292,153 $196,787 $170,620 $167,821 
Less: Operational capital expenditures (accrual)159,786 114,964 138,321 95,545 87,488 
Less: Capitalized interest22,591 23,590 21,740 21,817 23,015 
Less: Interest expense, net of capitalized amounts22,268 25,078 22,383 22,159 26,486 
Less: Capitalized cash G&A11,035 9,034 7,404 6,913 6,465 
Adjusted free cash flow (a)
$123,560 $119,487 $6,939 $24,186 $24,367 
(a) Effective January 1, 2021, non-cash interest expense amounts consisting primarily of amortization of debt issuance costs, premiums, and discounts associated with our long-term debt are excluded from our calculation of adjusted free cash flow.
Adjusted Discretionary Cash Flow. The following table reconciles the Company’s net cash provided by operating activities to adjusted discretionary cash flow:
Three Months Ended
December 31, 2021September 30, 2021December 31, 2020
(In thousands)
Cash flows from operating activities:
Net income (loss)$285,351 $171,902 ($505,071)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization112,551 89,890 96,037 
Impairment of evaluated oil and gas properties
— — 585,767 
Amortization of non-cash debt related items, net2,958 2,658 2,319 
Deferred income tax expense— — 3,308 
Loss on derivative contracts10,145 107,169 125,739 
Cash paid for commodity derivative settlements, net(156,719)(110,807)(2,884)
(Gain) loss on extinguishment of debt43,460 (2,420)(170,370)
Non-cash expense (benefit) related to share-based awards939 (903)2,968 
Merger, integration and transaction11,271 3,018 2,120 
Other, net31 6,495 1,347 
Adjusted discretionary cash flow$309,987 $267,002 $141,280 
Changes in working capital67,594 30,581 (4,582)
Merger, integration and transaction(11,271)(3,018)(2,120)
Net cash provided by operating activities$366,310 $294,565 $134,578 
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Adjusted Total Revenue. Adjusted total revenue is reconciled to total operating revenues, which excludes revenue from sales of commodities purchased from a third-party, in the following table:
Three Months Ended
December 31, 2021September 30, 2021December 31, 2020
(In thousands)
Operating Revenues
Oil$506,445 $409,293 $222,733 
Natural gas56,674 36,519 18,561 
Natural gas liquids69,782 58,097 25,668 
Total operating revenues$632,901 $503,909 $266,962 
Impact of settled derivatives(149,938)(110,960)(7,938)
Adjusted total revenue$482,963 $392,949 $259,024 
Net Debt. The following table reconciles the Company’s total debt to net debt:
December 31, 2020March 31, 2021June 30, 2021September 30, 2021December 31, 2021
(In thousands)
Total debt$2,969,264 $2,937,239 $2,865,154 $2,809,610 $2,694,115 
Unamortized premiums, discount, and deferred
loan costs, net
43,377 40,402 37,487 48,311 28,806 
Adjusted total debt$3,012,641 $2,977,641 $2,902,641 $2,857,921 $2,722,921 
Less: Cash and cash equivalents20,236 24,350 3,800 3,699 9,882 
Net debt$2,992,405 $2,953,291 $2,898,841 $2,854,222 $2,713,039 
PV-10. PV-10 as of December 31, 2021 is reconciled below to the standardized measure of discounted future net cash flows:
As of December 31, 2021
(In millions)
Standardized measure of discounted future net cash flows$6,250.8 
Add: present value of future income taxes discounted at 10% per annum$800.5 
Total proved reserves - PV-10$7,051.3 
Total proved developed reserves - PV-10$4,502.6 
Total proved undeveloped reserves - PV-10$2,548.7 

13


Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except par and share amounts)

December 31,
20212020
ASSETS
Current assets:
   Cash and cash equivalents$9,882 $20,236 
   Accounts receivable, net232,436 133,109 
   Fair value of derivatives22,381 921 
   Other current assets30,745 24,103 
      Total current assets295,444 178,369 
Oil and natural gas properties, full cost accounting method:
   Evaluated properties, net3,352,821 2,355,710 
   Unevaluated properties1,812,827 1,733,250 
      Total oil and natural gas properties, net5,165,648 4,088,960 
Other property and equipment, net28,128 31,640 
Deferred financing costs18,125 23,643 
Other assets, net40,158 40,256 
   Total assets$5,547,503 $4,362,868 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
   Accounts payable and accrued liabilities$569,991 $341,519 
   Fair value of derivatives185,977 97,060 
   Other current liabilities116,523 58,529 
      Total current liabilities872,491 497,108 
Long-term debt2,694,115 2,969,264 
Asset retirement obligations54,458 57,209 
Fair value of derivatives11,409 88,046 
Other long-term liabilities49,262 40,239 
   Total liabilities3,681,735 3,651,866 
Commitments and contingencies
Stockholders’ equity:
   Common stock, $0.01 par value, 78,750,000 and 52,500,000 shares authorized;
   61,370,684 and 39,758,817 shares outstanding, respectively
614 398 
   Capital in excess of par value4,012,358 3,222,959 
   Accumulated deficit(2,147,204)(2,512,355)
      Total stockholders’ equity1,865,768 711,002 
Total liabilities and stockholders’ equity$5,547,503 $4,362,868 


14


Callon Petroleum Company
Consolidated Statements of Operations
(in thousands, except per share amounts)

 Three Months Ended December 31,For the Year Ended December 31,
 2021202020212020
Operating Revenues:  
Oil$506,445 $222,733 $1,516,225 $850,667 
Natural gas56,674 18,561 141,493 51,866 
Natural gas liquids69,782 25,668 193,861 81,295 
Sales of purchased oil and gas59,287 29,006 193,451 49,319 
Total operating revenues692,188 295,968 2,045,030 1,033,147 
Operating Expenses:  
Lease operating73,522 45,010 203,141 194,101 
Production and ad valorem taxes33,693 16,487 100,160 62,638 
Gathering, transportation and processing22,083 20,694 80,970 77,309 
Cost of purchased oil and gas61,530 30,484 201,088 51,766 
Depreciation, depletion and amortization112,551 96,037 356,556 480,631 
General and administrative13,116 10,614 50,483 37,187 
Impairment of evaluated oil and gas properties— 585,767 — 2,547,241 
Merger, integration and transaction11,271 2,120 14,289 28,482 
Other operating— 2,084 3,366 10,644 
Total operating expenses327,766 809,297 1,010,053 3,489,999 
Income (Loss) From Operations364,422 (513,329)1,034,977 (2,456,852)
Other (Income) Expenses:  
Interest expense, net of capitalized amounts25,226 26,486 102,012 94,329 
Loss on derivative contracts10,145 125,739 522,300 27,773 
(Gain) loss on extinguishment of debt43,460 (170,370)41,040 (170,370)
Other (income) expense1,077 3,132 4,294 2,983 
Total other (income) expense79,908 (15,013)669,646 (45,285)
Income (Loss) Before Income Taxes284,514 (498,316)365,331 (2,411,567)
Income tax benefit (expense)837 (6,755)(180)(122,054)
Net Income (Loss)$285,351 ($505,071)$365,151 ($2,533,621)
Net Income (Loss) Per Common Share:    
Basic$4.82 ($12.71)$7.51 ($63.79)
Diluted$4.78 ($12.71)$7.26 ($63.79)
Weighted Average Common Shares Outstanding:    
Basic59,143 39,752 48,612 39,718 
Diluted59,737 39,752 50,311 39,718 















15


Callon Petroleum Company
Consolidated Statements of Cash Flows
(in thousands)

 Three Months Ended
December 31,
For the Year Ended
December 31,
 2021202020212020
Cash flows from operating activities:    
Net income (loss)$285,351 ($505,071)$365,151 ($2,533,621)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:   
  Depreciation, depletion and amortization112,551 96,037 356,556 480,631 
  Impairment of evaluated oil and gas properties— 585,767 — 2,547,241 
  Amortization of non-cash debt related items, net2,958 2,319 10,124 3,901 
  Deferred income tax expense— 3,308 — 118,607 
  Loss on derivative contracts10,145 125,739 522,300 27,773 
  Cash received (paid) for commodity derivative settlements, net(156,719)(2,884)(395,097)98,870 
  (Gain) loss on extinguishment of debt43,460 (170,370)41,040 (170,370)
  Non-cash expense related to share-based awards939 2,968 12,923 2,663 
  Other, net31 1,347 11,037 7,087 
  Changes in current assets and liabilities:   
    Accounts receivable(3,175)(20,340)(86,402)75,770 
    Other current assets(1,698)(10,399)(6,550)
    Accounts payable and accrued liabilities72,467 15,752 146,910 (92,227)
    Net cash provided by operating activities366,310 134,578 974,143 559,775 
Cash flows from investing activities:  
Capital expenditures(150,935)(109,408)(578,487)(664,231)
Acquisition of oil and gas properties(426,496)— (493,732)(12,923)
Proceeds from sales of assets152,686 29,152 188,101 178,970 
Cash paid for settlements of contingent consideration arrangements, net— — — (40,000)
Other, net3,512 40 7,718 8,301 
    Net cash used in investing activities(421,233)(80,216)(876,400)(529,883)
Cash flows from financing activities:  
Borrowings on Credit Facility904,000 265,500 2,140,500 5,353,000 
Payments on Credit Facility(842,000)(305,500)(2,340,500)(5,653,000)
Issuance of 8.00% Senior Notes due 2028— — 650,000 — 
Redemption of 6.25% Senior Notes— — (542,755)— 
Issuance of 9.00% Second Lien Senior Secured Notes due 2025— — — 300,000 
Discount on the issuance of 9.00% Second Lien Senior Secured Notes due 2025— — — (35,270)
Issuance of September 2020 Warrants— — — 23,909 
Payment of deferred financing costs and debt exchange costs(504)(4,499)(12,672)(10,811)
Tax withholdings related to restricted stock units— (14)(2,280)(509)
Other, net(390)(113)(390)(316)
    Net cash provided by (used in) financing activities61,106 (44,626)(108,097)(22,997)
Net change in cash and cash equivalents6,183 9,736 (10,354)6,895 
  Balance, beginning of period3,699 10,500 20,236 13,341 
  Balance, end of period$9,882 $20,236 $9,882 $20,236 

16


Non-GAAP Financial Measures
This news release refers to non-GAAP financial measures such as “adjusted free cash flow,” “adjusted discretionary cash flow,” “adjusted G&A,” “full cash G&A,” “adjusted income,” “adjusted income per diluted share,” “adjusted EBITDA,” “adjusted total revenue,” and “PV-10.” These measures, detailed below, are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our filings with the U.S. Securities and Exchange Commission (the “SEC”) and posted on our website.
Adjusted free cash flow is a supplemental non-GAAP measure that is defined by the Company as adjusted EBITDA less operational capital, cash capitalized interest, net cash interest expense and capitalized cash G&A (which excludes capitalized expense related to share-based awards). We believe adjusted free cash flow provides useful information to investors because it is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company’s ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Adjusted free cash flow is not a measure of a company’s financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities, or as a measure of liquidity, or as an alternative to net income (loss).
Adjusted discretionary cash flow is a supplemental non-GAAP measure that Callon believes provides useful information to investors because it is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company’s ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Adjusted discretionary cash flow is defined by Callon as net cash provided by operating activities before changes in working capital and merger, integration and transaction expenses. Callon has included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements, which the Company may not control and the cash flow effect may not be reflected the period in which the operating activities occurred. Adjusted discretionary cash flow is not a measure of a company’s financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities, or as a measure of liquidity, or as an alternative to net income (loss).
Adjusted G&A is a supplemental non-GAAP financial measure that excludes certain non-cash incentive share-based compensation valuation adjustments and non-recurring expenses. Callon believes that the non-GAAP measure of adjusted G&A is useful to investors because it provides a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period.
Full cash G&A is a supplemental non-GAAP financial measure that Callon defines as adjusted G&A – cash component plus capitalized G&A excluding capitalized expense related to share-based awards. Callon believes that the non-GAAP measure of full cash G&A is useful to investors because it provides a meaningful measure of our total recurring cash G&A costs, whether expensed or capitalized, and provides for greater comparability on a period-over-period basis.
Adjusted income and adjusted income per diluted share are supplemental non-GAAP measures that Callon believes are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of these items and non-cash valuation adjustments, which are detailed in the reconciliation provided. Adjusted income and adjusted income per diluted share are not measures of financial performance under GAAP. Accordingly, neither should be considered as a substitute for net income (loss), operating income (loss), or other income data prepared in accordance with GAAP. However, the Company believes that adjusted income and adjusted income per diluted share provide additional information with respect to our performance. Because adjusted income and adjusted income per diluted share exclude some, but not all, items that affect net income (loss) and may vary among companies, the adjusted income and adjusted income per diluted share presented above may not be comparable to similarly titled measures of other companies.
Adjusted diluted weighted average common shares outstanding (“Adjusted Diluted WASO”) is a non-GAAP financial measure which includes the effect of potentially dilutive instruments that, under certain circumstances described below, are excluded from diluted weighted average common shares outstanding (“Diluted WASO”), the most directly comparable GAAP financial measure. When a net loss exists, all potentially dilutive instruments are anti-dilutive to the net loss per common share and therefore excluded from the computation of Diluted WASO. The effect of potentially dilutive instruments are included in the computation of Adjusted Diluted WASO for purposes of computing adjusted income per diluted share.
Callon calculates adjusted EBITDA as net income (loss) before interest expense, income tax expense (benefit), depreciation, depletion and amortization, (gains) losses on derivative instruments excluding net settled derivative instruments, impairment of evaluated oil and gas properties, non-cash share-based compensation expense, merger, integration and transaction expense, (gain) loss on extinguishment of debt, and other operating expenses. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), cash flow provided by operating activities or other income or cash flow data prepared in accordance with GAAP.
17


However, the Company believes that adjusted EBITDA provides useful information to investors because it provides additional information with respect to our performance or ability to meet our future debt service, capital expenditures and working capital requirements. Because adjusted EBITDA excludes some, but not all, items that affect net income (loss) and may vary among companies, the adjusted EBITDA presented above may not be comparable to similarly titled measures of other companies.
Callon believes that the non-GAAP measure of adjusted total revenue (which is revenue including the gain or loss from the settlement of derivative contracts) is useful to investors because it provides readers with a revenue value more comparable to other companies who engage in price risk management activities through the use of commodity derivative instruments and reflects the results of derivative settlements with expected cash flow impacts within total revenues. See the reconciliation provided above for further details.
Callon believes that operating margin is a comparable metric against other companies in the industry and is an indicator of an oil and natural gas company’s operating profitability per unit of production. Operating margin is a supplemental non-GAAP measure that is defined by the Company as oil, natural gas, and NGL revenues sales price less lease operating expense; production and ad valorem taxes; and gathering, transportation and processing fees divided by total production for the period.
Net debt is a supplemental non-GAAP measure that is defined by the Company as total debt excluding unamortized premiums, discount, and deferred loan costs, less cash and cash equivalents. Net debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company’s outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company’s leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with Adjusted EBITDA in order to provide investors with another means of evaluating the Company’s ability to service its existing debt obligations as well as any future increase in the amount of such obligations.
Callon believes that the presentation of pre-tax PV-10 value is relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves prior to taking into account future corporate income taxes and the Company’s current tax structure. The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves as compared with other companies. The GAAP financial measure most directly comparable to pre-tax PV-10 is the standardized measure of discounted future net cash flows. Pre-tax PV-10 is calculated using the standardized measure of discounted future net cash flows before deducting future income taxes, discounted at 10 percent.
Callon is unable to reconcile the projected adjusted free cash flow (non-GAAP) metric included in this release to projected net cash provided by operating activities (GAAP) because components of the calculation are inherently unpredictable, such as changes to current assets and liabilities, the timing of capital expenditures, movements in oil and gas pricing, unknown future events, and estimating future certain GAAP measures. The inability to project certain components of the calculation would significantly affect the accuracy of the reconciliation. Additionally, Callon does not provide guidance on the items used to reconcile forecasted Adjusted G&A and forecasted G&A due to the uncertainty regarding timing and estimates of certain items. Therefore, Callon cannot reconcile forecasted Adjusted G&A to forecasted G&A without unreasonable effort.

18


Earnings Call Information
The Company will host a conference call on Thursday, February 24, 2022, to discuss fourth quarter 2021 financial and operating results, reserves, inventory, 2022 outlook, and current corporate strategy and initiatives.
Please join Callon Petroleum Company via the Internet for a webcast of the conference call:
Date/Time:Thursday, February 24, 2022, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time)
Webcast:Select “News and Events” under the “Investors” section of the Company’s website: www.callon.com.
An archive of the conference call webcast will also be available at www.callon.com under the “Investors” section of the website.
About Callon Petroleum Company
Callon Petroleum Company is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas.
Cautionary Statement Regarding Forward Looking Information
This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include all statements regarding wells anticipated to be drilled and placed on production; future levels of development activity and associated production, capital expenditures and cash flow expectations; the Company’s production and expenditure guidance; estimated reserve quantities and the present value thereof; future debt levels and leverage; and the implementation of the Company’s business plans and strategy, as well as statements including the words “believe,” “expect,” “plans,” “may,” “will,” “should,” “could,” and words of similar meaning. These statements reflect the Company’s current views with respect to future events and financial performance based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. Any forward-looking statement speaks only as of the date on 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 as required by applicable law. Some of the factors which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil and natural gas prices; 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 with respect to production levels or other matters related to the price of oil; our ability to drill and complete wells, operational, regulatory and environment risks; the cost and availability of equipment and labor; our ability to finance our development activities at expected costs or at expected times or at all; our inability to realize the benefits of recent transactions; currently unknown risks and liabilities relating to the newly acquired assets and operations; adverse actions by third parties involved with the transactions; risks that are not yet known or material to us; and other risks more fully discussed in our filings with the SEC, including our most recent Annual Reports on Form 10-K and subsequent Quarterly Reports on Form 10-Q, available on our website or the SEC’s website at www.sec.gov. Any forward-looking statement speaks only as of the date on 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 as required by applicable law.

Contact Information

Kevin Smith
Director of Investor Relations
Callon Petroleum Company
ir@callon.com
(281) 589-5200


1) Callon defines “reinvestment rate” as capital expenditures divided by cash flow from operating activities.
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