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 fromestablished 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 theLower 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
	Operational	Capitalized	Capitalized	Total Capital
	Capital (a)	Interest	G&A	Expenditures
	(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 Year	For the Full Year
Oil Contracts (WTI)	2022	2023
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 Year	For the Full Year
Natural Gas Contracts (Henry Hub)	2022	2023
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 Ended						Year Ended
	December 31, 2021		September 30, 2021		December 31, 2020		December 31, 2021
Total production
Oil (MBbls)
Permian	4,727		3,428		3,445		14,475
Eagle Ford	1,839		2,447		1,980		7,749
Total oil	6,566		5,875		5,425		22,224
Natural gas (MMcf)
Permian	9,183		7,153		7,474		29,682
Eagle Ford	2,090		2,242		2,264		7,704
Total natural gas	11,273		9,395		9,738		37,386
NGLs (MBbls)
Permian	1,549		1,315		1,331		5,155
Eagle Ford	344		417		353		1,284
Total NGLs	1,893		1,732		1,684		6,439
Total production (MBoe)
Permian	7,806		5,936		6,022		24,577
Eagle Ford	2,532		3,237		2,710		10,317
Total barrels of oil equivalent	10,338		9,173		8,732		34,894
Total daily production (Boe/d)
Permian	84,848		64,517		65,459		67,334
Eagle Ford	27,517		35,186		29,455		28,265
Total barrels of oil equivalent	112,365		99,703		94,914		95,599
Oil as % of total daily production	64	%	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 Ford	77.84		69.76		41.12		68.27
Total oil	$77.13		$69.67		$41.06		$68.22
Natural gas (per Mcf)
Permian	$4.81		$3.78		$1.68		$3.69
Eagle Ford	6.00		4.22		2.65		4.13
Total natural gas	$5.03		$3.89		$1.91		$3.78
NGL (per Bbl)
Permian	$37.50		$34.41		$15.00		$30.60
Eagle Ford	34.00		30.81		16.16		28.12
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 Ford	66.10		59.63		34.36		57.86
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)	3.81		2.21		1.89		2.84
NGLs (per Bbl)	34.56		31.71		15.24		28.54
Total average realized sales price (per Boe)	$46.72		$42.84		$29.66		$40.93

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	Three Months Ended			Year Ended
	December 31, 2021	September 30, 2021	December 31, 2020	December 31, 2021
Revenues (in thousands)(a)
Oil
Permian	$363,306	$238,582	$141,320	$987,195
Eagle Ford	143,139	170,711	81,413	529,030
Total oil	$506,445	$409,293	$222,733	$1,516,225
Natural gas
Permian	$44,133	$27,065	$12,560	$109,640
Eagle Ford	12,541	9,454	6,001	31,853
Total natural gas	$56,674	$36,519	$18,561	$141,493
NGLs
Permian	$58,085	$45,249	$19,964	$157,757
Eagle Ford	11,697	12,848	5,704	36,104
Total NGLs	$69,782	$58,097	$25,668	$193,861
Total revenues
Permian	$465,524	$310,896	$173,844	$1,254,592
Eagle Ford	167,377	193,013	93,118	596,987
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 Ford	66.10	59.63	34.36	57.86
Total sales price	$61.22	$54.93	$30.57	$53.06
Lease operating expense
Permian	$7.22	$4.19	$4.43	$5.27
Eagle Ford	6.77	5.51	6.77	7.13
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 Ford	3.60	2.89	2.29	3.16
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 Ford	1.76	1.49	2.25	1.80
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 Ford	53.97	49.74	23.05	45.77
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 Ended			Year Ended
	December 31, 2021	September 30, 2021	December 31, 2020	December 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 – total	13,412	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&A	11,035	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, 2020	475,879
Extensions and discoveries	36,180
Revisions to previous estimates	(14,181)
Purchase of reserves in place	57,652
Sales of reserves in place	(36,015)
Production	(34,894)
Proved reserves at December 31, 2021	484,621

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2021 Full Year Actuals

	Full Year
	2021 Actual
Total production (MBoe/d)	95.6
Oil	64%
NGL	18%
Natural gas	18%
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 / completed	68 / 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
Oil	64%
NGL	19%
Natural gas	17%
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 rate	22%
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 / completed	125 - 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.

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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 Ended			Year Ended
	December 31, 2021	September 30, 2021	December 31, 2020	December 31, 2021
	(In thousands except per share data)
Net income (loss)	$285,351	$171,902	($505,071)	$365,151
Loss on derivatives contracts	10,145	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 awards	939	(903)	2,968	12,923
Impairment of evaluated oil and gas properties	—	—	585,767	—
Merger, integration and transaction	11,271	3,018	2,120	14,289
Other (income) expense	1,072	4,305	5,328	7,655
(Gain) loss on extinguishment of debt	43,460	(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 WASO	59,143	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 WASO	59,737	47,096	42,644	50,311

(a)Calculated using the federal statutory rate of 21%.

	Three Months Ended			Year Ended
	December 31, 2021	September 30, 2021	December 31, 2020	December 31, 2021
	(In thousands)
Net income (loss)	$285,351	$171,902	($505,071)	$365,151
Loss on derivatives contracts	10,145	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 awards	939	(903)	2,968	12,923
Impairment of evaluated oil and gas properties	—	—	585,767	—
Merger, integration and transaction	11,271	3,018	2,120	14,289
Other (income) expense	1,072	4,305	5,328	7,655
Income tax (benefit) expense	(837)	2,416	6,755	180
Interest expense, net	25,226	27,736	26,486	102,012
Depreciation, depletion and amortization	112,551	89,890	96,037	356,556
(Gain) loss on extinguishment of debt	43,460	(2,420)	(170,370)	41,040
Adjusted EBITDA	$339,240	$292,153	$167,821	$998,800

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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, 2021	September 30, 2021	June 30, 2021	March 31, 2021	December 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 settlements	6,781	(153)	(14,719)	(20,117)	(5,055)
Cash interest expense, net	22,268	25,078	22,383	22,159	24,167
Merger, integration and transaction	11,271	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 interest	22,591	23,590	21,740	21,817	23,015
Less: Interest expense, net of capitalized amounts	22,268	25,078	22,383	22,159	26,486
Less: Capitalized cash G&A	11,035	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, 2021	September 30, 2021	December 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 amortization	112,551	89,890	96,037
Impairment of evaluated oil and gas properties	—	—	585,767
Amortization of non-cash debt related items, net	2,958	2,658	2,319
Deferred income tax expense	—	—	3,308
Loss on derivative contracts	10,145	107,169	125,739
Cash paid for commodity derivative settlements, net	(156,719)	(110,807)	(2,884)
(Gain) loss on extinguishment of debt	43,460	(2,420)	(170,370)
Non-cash expense (benefit) related to share-based awards	939	(903)	2,968
Merger, integration and transaction	11,271	3,018	2,120
Other, net	31	6,495	1,347
Adjusted discretionary cash flow	$309,987	$267,002	$141,280
Changes in working capital	67,594	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, 2021	September 30, 2021	December 31, 2020
	(In thousands)
Operating Revenues
Oil	$506,445	$409,293	$222,733
Natural gas	56,674	36,519	18,561
Natural gas liquids	69,782	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, 2020	March 31, 2021	June 30, 2021	September 30, 2021	December 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 equivalents	20,236	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,
	2021	2020
ASSETS
Current assets:
Cash and cash equivalents	$9,882	$20,236
Accounts receivable, net	232,436	133,109
Fair value of derivatives	22,381	921
Other current assets	30,745	24,103
Total current assets	295,444	178,369
Oil and natural gas properties, full cost accounting method:
Evaluated properties, net	3,352,821	2,355,710
Unevaluated properties	1,812,827	1,733,250
Total oil and natural gas properties, net	5,165,648	4,088,960
Other property and equipment, net	28,128	31,640
Deferred financing costs	18,125	23,643
Other assets, net	40,158	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 derivatives	185,977	97,060
Other current liabilities	116,523	58,529
Total current liabilities	872,491	497,108
Long-term debt	2,694,115	2,969,264
Asset retirement obligations	54,458	57,209
Fair value of derivatives	11,409	88,046
Other long-term liabilities	49,262	40,239
Total liabilities	3,681,735	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 value	4,012,358	3,222,959
Accumulated deficit	(2,147,204)	(2,512,355)
Total stockholders’ equity	1,865,768	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,
	2021	2020	2021	2020
Operating Revenues:
Oil	$506,445	$222,733	$1,516,225	$850,667
Natural gas	56,674	18,561	141,493	51,866
Natural gas liquids	69,782	25,668	193,861	81,295
Sales of purchased oil and gas	59,287	29,006	193,451	49,319
Total operating revenues	692,188	295,968	2,045,030	1,033,147
Operating Expenses:
Lease operating	73,522	45,010	203,141	194,101
Production and ad valorem taxes	33,693	16,487	100,160	62,638
Gathering, transportation and processing	22,083	20,694	80,970	77,309
Cost of purchased oil and gas	61,530	30,484	201,088	51,766
Depreciation, depletion and amortization	112,551	96,037	356,556	480,631
General and administrative	13,116	10,614	50,483	37,187
Impairment of evaluated oil and gas properties	—	585,767	—	2,547,241
Merger, integration and transaction	11,271	2,120	14,289	28,482
Other operating	—	2,084	3,366	10,644
Total operating expenses	327,766	809,297	1,010,053	3,489,999
Income (Loss) From Operations	364,422	(513,329)	1,034,977	(2,456,852)
Other (Income) Expenses:
Interest expense, net of capitalized amounts	25,226	26,486	102,012	94,329
Loss on derivative contracts	10,145	125,739	522,300	27,773
(Gain) loss on extinguishment of debt	43,460	(170,370)	41,040	(170,370)
Other (income) expense	1,077	3,132	4,294	2,983
Total other (income) expense	79,908	(15,013)	669,646	(45,285)
Income (Loss) Before Income Taxes	284,514	(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:
Basic	59,143	39,752	48,612	39,718
Diluted	59,737	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,
	2021	2020	2021	2020
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 amortization	112,551	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, net	2,958	2,319	10,124	3,901
Deferred income tax expense	—	3,308	—	118,607
Loss on derivative contracts	10,145	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 debt	43,460	(170,370)	41,040	(170,370)
Non-cash expense related to share-based awards	939	2,968	12,923	2,663
Other, net	31	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)	6	(10,399)	(6,550)
Accounts payable and accrued liabilities	72,467	15,752	146,910	(92,227)
Net cash provided by operating activities	366,310	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 assets	152,686	29,152	188,101	178,970
Cash paid for settlements of contingent consideration arrangements, net	—	—	—	(40,000)
Other, net	3,512	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 Facility	904,000	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 activities	61,106	(44,626)	(108,097)	(22,997)
Net change in cash and cash equivalents	6,183	9,736	(10,354)	6,895
Balance, beginning of period	3,699	10,500	20,236	13,341
Balance, end of period	$9,882	$20,236	$9,882	$20,236

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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.

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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.

19