8-K

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 26, 2020

Callon Petroleum Company

(Exact name of registrant as specified in its charter)

DE	001-14039	64-0844345
(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 class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.01 par value	CPE	NYSE

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 26, 2020, Callon Petroleum Company issued the press release attached as Exhibit 99.1 providing information regarding the Company’s fourth quarter and full-year 2019 financial and operating results.

Item 7.01 Regulation FD

On February 27, 2020, the Company will host a conference call to discuss its fourth quarter and full-year 2019 financial and operating results. The Company’s accompanying slide presentation is attached to this Current Report on Form 8-K as Exhibit 99.2 (the “Earnings Presentation”) and incorporated herein by reference.

The information contained in the Earnings Presentation is summary information that is intended to be considered in the context of the Company’s Securities and Exchange Commission (“SEC”) filings and other public announcements that the Company may make, by press release or otherwise, from time to time. The Company undertakes no duty or obligation to publicly update or revise the information contained in this report, although it may do so from time to time as its management believes is warranted. Any such updating may be made through the filing of other reports or documents with the SEC, through press releases or through other public disclosure.

The information presented in Items 2.02 and 7.01 of this Current Report on Form 8-K and Exhibits 99.1 and 99.2 shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, unless the Company specifically states that the information is to be considered “filed” under the Exchange Act or specifically incorporates it by reference into a filing under the Securities Act of 1933, as amended, or the Exchange Act.

Item 9.01. Financial Statements and Exhibits

(d) Exhibits

Exhibit Number	Title of Document
99.1	Press release dated February 26, 2020
99.2	Earnings Presentation posted February 26, 2020

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 26, 2020	/s/ James P. Ulm, II
	James P. Ulm, II
	Senior Vice President and Chief Financial Officer

EX-99.1

Exhibit 99.1

Callon Petroleum Company Announces Fourth Quarter and Full Year 2019 Results and Provides Integrated 2020 Plan

HOUSTON, Texas (February 26, 2020) - Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three months and full-year ended December 31, 2019. All financial and operating results presented include Carrizo Oil & Gas, Inc. results from December 21 to December 31, 2019 unless otherwise noted.

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.

2019 Highlights

• Full-year 2019 production of 41.3 Mboe/d (77% oil), an increase of 26% over 2018 volumes

• Year-end proved reserves of 540.0 MMboe (64% oil), a year-over-year increase of 126%

• Realized income available to common stockholders of $55.6 million, or $0.24 per diluted share, and adjusted net income⁽ⁱ⁾ of $176.3 million or $0.76 per diluted share

• Generated an operating margin⁽ⁱ⁾ of $35.60 per Boe reflecting our high level of oil volumes and lease operating expense reductions

• Generated Adjusted EBITDA⁽ⁱ⁾ of $502.1 million

• Completed the acquisition of Carrizo Oil & Gas, creating an oil-weighted growth company with premier positions in the Permian Basin and Eagle Ford Shale

• Divested approximately $300 million in non-core assets as part of ongoing initiatives to enhance returns on capital employed and strengthen our financial position through absolute debt reduction

• Redeemed approximately $270 million in preferred securities, eliminating $25 million in annual future dividend payments

Fourth Quarter 2019 Highlights

• Fourth quarter 2019 production of 46.6 Mboe/d (75% oil), an increase of 14% over fourth quarter 2018 volumes and a sequential increase of 23%

• Realized loss available to common stockholders of $23.5 million, or ($0.09) per diluted share, and adjusted net income⁽ⁱ⁾ of $56.8 million or $0.23 per diluted share

• Generated $137.6 million of cash from operating activities, exceeding cash used in investing activities for operational capital additions of $105.8 million

• Sustained strong operating margins of $37.74 per Boe

• Built an inventory of drilled, uncompleted wells to support larger scale development in the Delaware Basin

Joe Gatto, President and Chief Executive Officer commented, “2019 was a transformational year and a significant step forward for Callon. We executed multiple strategic initiatives while delivering on our capital development plan with improved efficiency and lower costs. The acquisition of Carrizo has transformed Callon into a more robust entity with the capacity to execute a model of scaled development to drive lower free cash flow break-even costs and sustain growth in a low oil price environment. We generated free cash flow on both a stand-alone and pro forma basis in the fourth quarter, setting the stage for us to deliver free cash flow generation at $50/Bbl in 2020. Our transition to larger projects featuring multi-zone co-development across the the Permian asset base is reflected in our 2020 capital program. Given the capital synergies and overall efficiency we will capture from this development model, our 2020 capital program is more than $100 million below our pro forma 2019 capital spending levels.”

He continued, “I am very pleased by the progress that the organization has made in both integrating the combined activity plans ahead of schedule and driving our operational capital synergy targets higher than initially estimated. We now anticipate total year-one synergies from corporate cost and operational capital items to be over $80 million, excluding the impact of improved uptime from a program with less offsetting completion downtime. We remain steadfast in our long-term value focus in our life of field development philosophy, employing resource development concepts and a pace of activity that will keep us on a path to sustainable free cash flow growth from repeatable investments in our high quality asset base.”

Environmental, Social, and Governance (“ESG”) Updates

Callon today also announced the Company’s achievement of its best safety performance on record during 2019, reflecting the Company’s dedication to a culture of responsibility. Furthermore, the Company’s environmental sustainability initiatives resulted in a 40% year-over-year reduction in flaring intensity, as defined by the Texas Railroad Commission, and a two-fold increase in company-wide recycled water volumes during the fiscal year.

Callon continues to evolve its executive compensation program to align with shareholder priorities. The Company has included an absolute total shareholder return (“TSR”) modifier to the performance share program that links executive pay to the absolute returns realized by

(i) Non-GAAP measure. See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations

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the Company’s shareholders. Under the plan, payouts for the performance period will be reduced if annualized TSR is below the threshold of 5%, reflect a multiplier of 100% upon achieving an annualized TSR of 5% - 10%, and will include higher multipliers upon achieving an annualized TSR of greater than 10%. Additional detail will be available in the Company’s upcoming proxy.

Operations Update and Outlook

At December 31, 2019, Callon had 1,409 gross (1,242.3 net) horizontal wells producing fromestablished flow units in the Permian Basin and Eagle Ford Shale. Net daily production for the three months ended December 31, 2019 grew 14% to 46.6 Mboe/d (75% oil) as compared to the same period of 2018. Full year production for 2019 averaged 41.3 Mboe/d (77% oil) reflecting growth of 26% over 2018 volumes.

For the three months ended December 31, 2019, Callon drilled 11 gross (10.2 net) horizontal wells and placed a combined 14 gross (9.0 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 Wolfcamp A and Wolfcamp B in the Delaware Basin.

Legacy Carrizo activity in the fourth quarter was primarily focused on the building of an inventory of drilled uncompleted wells in the Eagle Ford Shale and Delaware Basin to provide the flexibility required for larger scale development in early 2020. During the quarter, legacy Carrizo drilled 28 gross (26.6 net) wells and placed 4 gross (3.2 net) wells on production near the beginning of the quarter.

Callon entered 2020 with an inventory of over 60 drilled uncompleted wells to support a new, integrated model of scaled development and deployed four completion crews to both the Delaware Basin and Eagle Ford Shale to turn several large projects to production in the first and second quarters. In mid-February, a 16-well project in the Eagle Ford and a five-well, co-development project in the Delaware were brought online as the new development model starts to progress for 2020. Additional large scale projects including two Eagle Ford projects totaling roughly 45 wells, multiple Delaware projects in both Eastern Reeves County and Ward County, and select Midland Basin projects will be completed and placed on production throughout the remainder of the first and second quarter. The Company is currently operating nine drilling rigs and four dedicated completion crews with plans to operate eight to nine drilling rigs and an average of three completion crews during this year.

2020 Capital Expenditures Budget

Callon has established an operational capital expenditure budget of $975 million for 2020 with approximately 70% of drilling, completion and equipment expenditures (“DC&E”) allocated to the Permian Basin. Development capital related to drilling, completion and equipping new wells is expected to compose approximately 85% to 90% of the spending with facilities and other items accounting for the remainder. The operational program in the Permian Basin will focus on co-development projects designed to optimize production and resource recovery from multiple zones. The Company also plans to continue large scale, multi-pad development in the Eagle Ford Shale, providing a balance of capital intensity and cycle times relative to the Delaware Basin program.

The 2020 plan implies a material improvement in capital efficiency relative to the 2019 pro forma spend of the combined companies and to the initial 2020 targeted operational capital spend of approximately $1.1 billion. Accelerated integration of the combined development programs, combined with the identification of additional sources of cost reductions and best practices as part of large scale development in the Delaware Basin, has resulted in a planned DC&E cost of under $1,000 per lateral foot in the Delaware Basin, surpassing initial synergy estimates.

Callon expects to drill approximately 165 gross operated wells and place 160 gross operated wells on production during 2020. Additional 2020 capital program highlights include:

• Initial 2020 full year production guidance (on a three-stream basis) is 115.0 to 120.0 MBoe/d with an oil cut of approximately 66%

• DC&E expenditures for the year are weighted approximately 60% to the first half of the year and 30% to the first quarter

• Average lateral lengths for the year are projected between ~7,900 feet and ~9,000 feet across all three asset areas

• Working interest will vary between 80% and 95% dependent upon project and asset area

• First quarter and second quarter completions activity will primarily be composed of Eagle Ford and Delaware wells

• First quarter production guidance is 95.0 to 100.0 MBoe/d with an oil cut of 66%

• Second quarter production growth is expected to be in excess of 15%

• Gross wells placed on production in the second quarter are expected to be the highest of any period during the year

• Projected oil volumes are more than 60% hedged for the entire year and more than 70% hedged for the first quarter

• The inventory of drilled uncompleted wells completed early in the year will be replenished throughout the year with an increased weighting to the Permian Basin providing ongoing flexibility within the larger development model in 2021 and is projected to be more than 60 wells by year-end 2020

The remainder of our full year 2020 outlook is provided later in this release under the section titled “2020 Guidance.”

(i) Non-GAAP measure. See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations

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Capital Expenditures

For the twelve months ended December 31, 2019, Callon incurred $515.1 million in operational capital expenditures on an accrual basis as compared to $583.4 million in 2018. For the three months ended December 31, 2019, the Company incurred $110.0 million in operational capital expenditures on an accrual basis, which represented a $6.4 milliondecrease from the third quarter. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis:

	Three Months Ended December 31, 2019
	Operational		Capitalized			Capitalized		Total Capital
	Capital (a)		Interest			G&A		Expenditures
	(In thousands)
Cash basis (b)		$105,846		$23,614			$7,655		$137,115
Timing adjustments (c)	4,175		(1,833		)	—		2,342
Non-cash items	—		—			1,125		1,125
Accrual (GAAP) basis		$110,021		$21,781			$8,780		$140,582

(a) Includes seismic, land, technology, and other items.

(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.

(d) Accrual basis capital as shown includes the impact of legacy Carrizo expenditures after December 20^th close date.

(i) Non-GAAP measure. See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations

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Operating and Financial Results

The following table presents summary information for the periods indicated:

	Three Months Ended,
	December 31, 2019			September 30, 2019			December 31, 2018
Net production
Oil (MBbls)	3,234			2,725			3,076
Natural gas (MMcf)	5,530			4,538			4,225
NGLs (MBbls)	135			—			—
Total barrels of oil equivalent (MBoe)	4,291			3,481			3,780
Total daily production (Boe/d)	46,641			37,837			41,087
Oil as % of total daily production	75		%	78		%	81		%
Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)		$56.61			$54.39			$48.89
Natural gas (per Mcf)		$1.98			$1.58			$2.72
NGLs (per Bbl)		$15.37			$—			$—
Total (per Boe)		$45.70			$44.64			$42.83
Average realized sales price (including impact of settled derivatives)
Oil (per Bbl)		$55.33			$54.01			$48.52
Natural gas (per Mcf)		$2.12			$2.03			$2.62
NGLs (per Bbl)		$15.37			$—			$—
Total (per Boe)		$44.92			$44.93			$42.41
Revenues (in thousands)
Oil		$183,071			$148,210			$150,398
Natural gas	10,949			7,168			11,497
NGLs	2,075			—			—
Total revenues		$196,095			$155,378			$161,895
Additional per Boe data
Sales price (a)		$45.70			$44.64			$42.83
Lease operating expense	5.90			5.65			6.47
Production taxes	2.06			3.41			2.51
Operating margin		$37.74			$35.58			$33.85
Depletion, depreciation and amortization		$14.30			$16.09			$15.74
Adjusted G&A (b)
Cash component (c)		$2.41			$2.52			$2.03
Non-cash component		$0.53			$0.44			$0.50

(a) Excludes the impact of settled derivatives.

(b) Excludes certain non-recurring expenses and non-cash valuation adjustments. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

(c) Excludes the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization.

Total Revenue.For the quarter ended December 31, 2019, Callon reported total revenue of $196.1 million and total revenue including the gain or loss from the settlement of derivative contracts (“Adjusted Total Revenue”⁽ⁱ⁾) of $192.7 million, reflecting the impact of a $3.4 million loss from the settlement of derivative contracts. Average daily production for the quarter was 46.6 Mboe/d compared to average daily production of 37.8 Mboe/d in the third quarter of 2019. Average realized prices, including and excluding the effects of hedging, are detailed above.

(i) Non-GAAP measure. See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations

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Hedging impacts. For the quarter ended December 31, 2019, Callon recognized the following hedging-related items:

	Three Months Ended December 31, 2019
	In Thousands			Per Unit
Oil derivatives
Net loss on settlements		($4,140	)		($1.28	)
Net loss on fair value adjustments	(34,375		)
Total loss on oil derivatives		($38,515	)
Natural gas derivatives
Net gain on settlements		$787			$0.14
Net gain on fair value adjustments	3,796
Total gain on natural gas derivatives		$4,583
Total oil & natural gas derivatives
Net loss on settlements		($3,353	)		($0.78	)
Net loss on fair value adjustments	(30,579		)
Total loss on oil & natural gas derivatives		($33,932	)

Lease Operating Expenses, including workover (“LOE”).LOE per Boe for the three months ended December 31, 2019 was $5.90 per Boe, compared to LOE of $5.65 per Boe in the third quarter of 2019. The slight increase is primarily from an increase in costs associated with recently acquired assets that reflect a higher historical operating cost.

Production Taxes, including ad valorem taxes. Production taxes were $2.06 per Boe for the three months ended December 31, 2019, representing approximately 5% of total revenue before the impact of derivative settlements.

Depreciation, Depletion and Amortization (“DD&A”).DD&A for the three months ended December 31, 2019 was $14.30 per Boe compared to $16.09 per Boe in the third quarter of 2019. The decrease was primarily attributed to the inclusion of the reserves acquired from Carrizo which lowered our depletion rate for the quarter.

General and Administrative (“G&A”).G&A was $13.6 million, or $3.18 per Boe, and G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, (“Adjusted G&A”⁽ⁱ⁾) was $12.6 million, or $2.94 per Boe, for the three months ended December 31, 2019 compared to $10.3 million, or $2.96 per Boe, for the third quarter of 2019. The cash component of Adjusted G&A was $10.3 million, or $2.41 per Boe, for the three months ended December 31, 2019 compared to $8.8 million, or $2.52 per Boe, for the third quarter of 2019.

For the three months ended December 31, 2019, G&A and Adjusted G&A, which excludes the amortization of equity-settled, share-based incentive awards and corporate depreciation and amortization, are calculated as follows (in thousands):

	Three Months Ended December 31, 2019
Total G&A expense		$13,626
Change in the fair value of liability share-based awards (non-cash)	(1,010		)
Adjusted G&A – total	12,616
Restricted stock share-based compensation (non-cash)	(1,855		)
Corporate depreciation & amortization (non-cash)	(439		)
Adjusted G&A – cash component		$10,322

Income tax expense. Callon provides for income taxes at a statutory rate of 21% adjusted for permanent differences expected to be realized. The Company recorded income tax expense of $5.9 million for the three months ended December 31, 2019, compared to income tax expense of $17.9 million for the three months ended September 30, 2019. The change in income tax expense is based upon activity during the respective periods.

Proved Reserves

DeGolyer and MacNaughton and Ryder Scott Company, L.P. prepared estimates of Callon and legacy Carrizo reserves, respectively, as of December 31, 2019.

As of December 31, 2019, Callon’s estimated net proved reserves grew 126% from prior year-end, totaling 540.0 MMboe and included 346.4 MMBbls of oil, 757.1 Bcf of natural gas and 67.5 MMBbls of NGLs with a standardized measure of discounted future net cash flows of $5.0 billion. Oil constituted approximately 64% of the Company’s total estimated equivalent net proved reserves and approximately 66% of total estimated equivalent proved developed reserves. The Company added 59.4 MMboe of new reserves in extensions and discoveries through development efforts in each operating area, where a total of 63 gross (55.7 net) wells were drilled.

(i) Non-GAAP measure. See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations

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The Company purchased reserves in place of 326.8 MMboeand reduced estimated net proved reserves through net revisions of previous estimates of 37.2 MMboe.

Callon’s net revisions of previous estimates were primarily related to technical revisions due to the observed impact of well spacing tests on producing wells and the resulting impact on reserve estimates as the Company advanced larger scale development concepts across multi-zone inventory. Other impacts to reserves included pricing effects and reclassifications of PUDs which were mainly driven by changes in future development plans resulting from the completion of the Carrizo acquisition which allowed the Company to reallocate capital across the combined companies’ portfolio in an effort to increase capital efficiency and resulting cash flow generation.

The changes in Callon’s proved reserves are as follows:

	Total (MBoe)
Reserves at December 31, 2018	238,508
Extensions and discoveries	59,424
Purchase of reserves in place	326,838
Revisions to previous estimates	(37,216	)
Production	(15,086	)
Sales of reserves in place	(32,456	)
Reserves at December 31, 2019	540,012

Callon replaced 212% of 2019 production as calculated by the sum of reserve extensions and discoveries, divided by annual production (“Organic reserve replacement ratio,”⁽ⁱ⁾). The Company’s finding and development costs from extensions and discoveries (“Drill-bit F&D costs per Boe,”⁽ⁱ⁾) were $15.55 per Boe calculated as accrual costs incurred for exploration, $309.0 million, and development, $189.3 million, divided by the reserves (in barrels of oil equivalent) added from extensions and discoveries, net of revisions excluding reclassifications.

2019 Full Year Actuals

	Full Year
	2019 Actual
Total production (Mboe/d) (a)	41.3
% oil	77%
Income statement expenses (per Boe)
LOE, including workovers	$6.09
Production taxes, including ad valorem (% unhedged revenue)	6%
Adjusted G&A: cash component (b)	$2.41
Adjusted G&A: non-cash component (c)	$0.52
Cash interest expense (d)	$0.00
Effective income tax rate	34.2%
Capital expenditures (in millions, accrual basis)
Total operational (e)	$515
Capitalized interest and G&A expenses	$115
Net operated horizontal wells placed on production	52

(a) Full year 2019 production reflects the 11 day impact of Carrizo volumes included after closing and represents Callon volumes on a 2-stream basis and Carrizo volumes on a 3-stream basis.

(b) Excludes the amortization of equity-settled, share-based incentive awards, corporate depreciation and amortization, and pending merger-related expenses. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

(c) Excludes certain non-recurring expenses and non-cash valuation adjustments. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

(d) All cash interest expense was capitalized.

(e) Includes facilities, equipment, seismic, land and other items. Excludes capitalized expenses.

(i) Non-GAAP measure. See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations

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2020 Guidance (three-stream basis)

	Full Year
	2020 Guidance
Total production (Mboe/d) (a)	115.0 - 120.0
Oil production	66%
NGL production	17%
Gas production	17%
Income statement expenses
LOE, including workovers (in millions)	$195.0 - $235.0
Gathering, processing, and transportation ($/Boe)	$1.55 - $1.95
Production taxes, including ad valorem (% of unhedged revenue)	6.5%
Adjusted G&A: cash component (b) (in millions)	$55.0 - $65.0
Adjusted G&A: non-cash component (c) (in millions)	$10.0 - $15.0
Cash interest expense(in millions)	$55.0 - $65.0
Effective income tax rate	23%
Capital expenditures (in millions, accrual basis)
Total operational capital (d)	$975.0
Capitalized interest	$115.0 - $125.0
Capitalized G&A	$45.0 - $50.0
Gross operated wells drilled / completed	~165 / ~160

(a) Total Company presented on a 3-stream basis.

(b) Excludes the amortization of equity-settled, share-based incentive awards and merger-related expenses. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

(c) Excludes certain non-recurring expenses and non-cash valuation adjustments. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

(d) Includes facilities, equipment, seismic, land and other items. Excludes capitalized expenses.

(i) Non-GAAP measure. See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations

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Hedge Portfolio Summary

The following table summarizes our open derivative positions as of December 31, 2019 for the periods indicated:

	For the Full Year of				For the Full Year of
Oil contracts (WTI)	2020				2021
Collar contracts with short puts (three-way collars)
Total volume (Bbls)	13,176,000				—
Weighted average price per Bbl
Ceiling (short call)		$65.28				$—
Floor (long put)		$55.38				$—
Floor (short put)		$45.08				$—
Short call contracts
Total volume (Bbls)	1,674,450			(a)	4,825,300		(a)
Weighted average price per Bbl		$75.98				$63.62
Swap contracts
Total volume (Bbls)	1,303,900				—
Weighted average price per Bbl		$55.19				$—
Swap contracts with short puts
Total volume (Bbls)	2,196,000				—
Weighted average price per Bbl
Swap		$56.06				$—
Floor (short put)		$42.50				$—
Oil contracts (Brent ICE)
Collar contracts with short puts (three-way collars)
Total volume (Bbls)	837,500				—
Weighted average price per Bbl
Ceiling (short call)		$70.00				$—
Floor (long put)		$58.24				$—
Floor (short put)		$50.00				$—
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	8,476,700				4,015,100
Weighted average price per Bbl		($1.47	)			$0.40
Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls)	1,439,205				—
Weighted average price per Bbl		$2.40				$—
Oil contracts (Argus Houston MEH swaps)
Swap contracts
Total volume (Bbls)	504,500				—
Weighted average price per Bbl		$58.22				$—
Natural gas contracts (Henry Hub)
Collar contracts (three-way collars)
Total volume (MMBtu)	3,660,000				—
Weighted average price per MMBtu
Ceiling (short call)		$2.75				$—
Floor (long put)		$2.50				$—
Floor (short put)		$2.00				$—
Swap contracts
Total volume (MMBtu)	3,660,000				—
Weighted average price per MMBtu		$2.48				$—
Short call contracts
Total volume (MMBtu)	12,078,000				7,300,000
Weighted average price per MMBtu		$3.50				$3.09
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	21,596,000				—
Weighted average price per MMBtu		($1.04	)			$—

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

(i) Non-GAAP measure. See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations

8

Adjusted Income and Adjusted EBITDA.The Company reported loss available to common stockholders of $23.5 million for the three months ended December 31, 2019 and Adjusted Income available to common stockholders of $56.8 million, or $0.23 per diluted share. The following tables reconcile the Company’s income (loss) available to common stockholders to Adjusted Income, and the Company’s net income (loss) to Adjusted EBITDA:

	Three Months Ended
	December 31, 2019			September 30, 2019			December 31, 2018
	(In thousands except per share data)
Income (loss) available to common stockholders		($23,543	)		$47,180			$154,370
(Gain) loss on derivatives contracts	30,694			(21,809		)	(103,918		)
Cash (paid) received for commodity derivative settlements, net	(3,353		)	1,011			(1,594		)
Change in the fair value of share-based awards	1,010			(925		)	(1,053		)
Merger and integration expense	68,420			5,943			—
Other operating expense	—			(175		)	—
Loss on extinguishment of debt	4,881			—			—
Tax effect on adjustments above	(21,347		)	3,351			22,379
Loss on redemption of preferred stock	—			8,304			—
Change in valuation allowance	—			—			(30,281		)
Adjusted Income		$56,762			$42,880			$39,903
Adjusted Income per fully diluted common share		$0.23			$0.19			$0.17

	Three Months Ended
	December 31, 2019			September 30, 2019			December 31, 2018
	(In thousands)
Net income (loss)		($23,543	)		$55,834			$156,194
(Gain) loss on derivatives contracts	30,694			(21,809		)	(103,918		)
Cash (paid) received for commodity derivative settlements, net	(3,353		)	1,011			(1,594		)
Non-cash stock-based compensation expense	3,390			644			770
Merger and integration expense	68,420			5,943			—
Other operating expense	145			(161		)	1,333
Income tax expense	5,857			17,902			5,647
Interest expense	689			739			735
Depreciation, depletion and amortization	63,198			57,235			60,549
Loss on extinguishment of debt	4,881			—			—
Other income	—			—			—
Adjusted EBITDA		$150,378			$117,338			$119,716

(i) Non-GAAP measure. See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations

9

Discretionary Cash Flow. Discretionary cash flow⁽ⁱ⁾ for the three months ended December 31, 2019 was $81.7 million and is reconciled to net cash provided by operating activities in the following table:

	Three Months Ended
	December 31, 2019			September 30, 2019			December 31, 2018
	(In thousands)
Net income (loss)		($23,543	)		$55,834			$156,194
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	63,198			57,235			60,549
Amortization of non-cash debt related items	689			739			734
Deferred income tax expense	5,857			17,902			5,647
(Gain) loss on derivative contracts	30,694			(21,809		)	(103,918		)
Cash received (paid) for commodity derivative settlements, net	(3,353		)	1,011			(1,594		)
Gain on sale of other property and equipment	(126		)	(13		)	(64		)
Non-cash loss on early extinguishment of debt	4,881			—			—
Non-cash expense related to equity share-based awards	1,899			1,569			1,823
Change in the fair value of liability share-based awards	1,518			(925		)	(1,053		)
Discretionary cash flow		$81,714			$111,543			$118,318
Changes in working capital	58,587			2,803			33,710
Payments to settle asset retirement obligations	(2,723		)	(654		)	(389		)
Net cash provided by operating activities		$137,578			$113,692			$151,639

Free Cash Flow. Free cash flow⁽ⁱ⁾ for the three months ended December 31, 2019 was $9.1 million. The following table reconciles the Company’s net cash provided by operating activities to Free Cash Flow:

	Three Months Ended
	December 31, 2019			September 30, 2019			December 31, 2018
	(In thousands)
Net cash provided by operating activities		$137,578			$113,692			$151,639
Less: Changes in working capital	(58,587		)	(2,803		)	(33,710		)
Plus: Payments to settle asset retirement obligations	2,723			654			389
Plus: Merger and integration expense	68,420			5,943			—
Plus: Other operating expense and non-recurring items	244			(148		)	1,398
Adjusted EBITDA		$150,378			$117,338			$119,716
Less: Operational capex (accrual)	110,021			116,413			141,177
Less: Capitalized interest	21,781			18,130			17,500
Less: Interest expense	689			739			735
Less: Capitalized G&A	8,780			8,239			8,192
Free Cash Flow		$9,107			($26,183	)		($47,888	)

(i) Non-GAAP measure. See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations

10

Adjusted Total Revenue. Adjusted total revenue⁽ⁱ⁾ for the three months ended December 31, 2019 was $192.7 million and is reconciled to total operating revenues in the following table:

	Three Months Ended
	December 31, 2019			September 30, 2019		December 31, 2018
	(In thousands)
Operating Revenues
Oil		$183,071			$148,210		$150,398
Natural gas	10,949			7,168		11,497
Natural gas liquids	2,075			—		—
Total operating revenues		$196,095			$155,378		$161,895
Impact of settled derivatives	(3,353		)	1,011		(1,594		)
Adjusted total revenue		$192,742			$156,389		$160,301

PV-10.PV-10⁽ⁱ⁾, as of December 31, 2019 is reconciled below to the standardized measure of discounted future net cash flows:

	As of December 31, 2019
	(In thousands)
Standardized measure of discounted future net cash flows		$4,951,026
Add: present value of future income taxes discounted at 10% per annum	418,555
Total Proved Reserves - PV-10	5,369,581
Total Proved Developed Reserves - PV-10	3,246,802
Total Proved Undeveloped Reserves - PV-10		$2,122,779

(i) Non-GAAP measure. See “Non-GAAP Financial Measures and Reconciliations” included within this release for related disclosures and calculations

11

Callon Petroleum Company

Consolidated Balance Sheets

(in thousands, except par values and share data)

	December 31,
	2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	13,341	$	16,051
Accounts receivable, net	209,463		131,720
Fair value of derivatives	26,056		65,114
Other current assets	19,814		9,740
Total current assets	268,674		222,625
Oil and natural gas properties, full cost accounting method:
Evaluated properties, net	4,682,994		2,314,345
Unevaluated properties	1,986,124		1,404,513
Total oil and natural gas properties, net	6,669,118		3,718,858
Operating lease right-of-use assets	63,908		—
Other property and equipment, net	35,253		21,901
Deferred tax asset	115,720		—
Deferred financing costs	22,233		6,087
Fair value of derivatives	9,216		—
Other assets, net	10,716		9,702
Total assets	$	7,194,838	$	3,979,173
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	511,622	$	285,849
Operating lease liabilities	42,858		—
Fair value of derivatives	71,197		10,480
Other current liabilities	26,570		18,587
Total current liabilities	652,247		314,916
Long-term debt	3,186,109		1,189,473
Operating lease liabilities	37,088		—
Asset retirement obligations	48,860		10,405
Deferred tax liability	—		9,564
Fair value of derivatives	32,695		7,440
Other long-term liabilities	14,531		2,167
Total liabilities	3,971,530		1,533,965
Commitments and contingencies
Stockholders’ equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 0 and 1,458,948 shares outstanding, respectively	—		15
Common stock, $0.01 par value, 525,000,000 and 300,000,000 shares authorized, respective; 396,600,022 and 227,582,575 shares outstanding, respectively	3,966		2,276
Capital in excess of par	3,198,076		2,477,278
Retained earnings (Accumulated deficit)	21,266		(34,361		)
Total stockholders’ equity	3,223,308		2,445,208
Total liabilities and stockholders’ equity	$	7,194,838	$	3,979,173

12

Callon Petroleum Company

Consolidated Statements of Operations

(in thousands, except per share data)

	Three Months Ended December 31,						For the Year Ended December 31,
	2019			2018			2019			2018
Operating Revenues:
Oil	$	183,071		$	150,398		$	633,107		$	530,898
Natural gas	10,949			11,497			36,390			56,726
Natural gas liquids	2,075			—			2,075			—
Total operating revenues	196,095			161,895			671,572			587,624
Operating Expenses:
Lease operating	25,316			24,475			91,827			69,180
Production taxes	8,841			9,490			42,651			35,755
Depreciation, depletion and amortization	61,367			59,750			240,642			182,783
General and administrative	13,626			8,514			45,331			35,293
Merger and integration expenses	68,420			—			74,363			—
Settled share-based awards	—			—			3,024			—
Other operating expense	145			1,333			1,076			5,083
Total operating expenses	177,715			103,562			498,914			328,094
Income From Operations	18,380			58,333			172,658			259,530
Other (Income) Expenses:
Interest expense, net of capitalized amounts	689			735			2,907			2,500
(Gain) loss on derivative contracts	30,694			(103,918		)	62,109			(48,544		)
Loss on extinguishment of debt	4,881			—			4,881			—
Other income	(198		)	(325		)	(468		)	(2,896		)
Total other (income) expense	36,066			(103,508		)	69,429			(48,940		)
Income (Loss) Before Income Taxes	(17,686		)	161,841			103,229			308,470
Income tax expense	5,857			5,647			35,301			8,110
Net Income (Loss)	(23,543		)	156,194			67,928			300,360
Preferred stock dividends	—			(1,824		)	(3,997		)	(7,295		)
Loss on redemption of preferred stock	—			—			(8,304		)	—
Income (Loss) Available to Common Stockholders	$	(23,543	)	$	154,370		$	55,627		$	293,065
Income (Loss) Available to Common Stockholders Per Common Share:
Basic	$	(0.09	)	$	0.68		$	0.24		$	1.35
Diluted	$	(0.09	)	$	0.68		$	0.24		$	1.35
Weighted Average Common Shares Outstanding:
Basic	248,232			227,580			233,140			216,941
Diluted	248,359			228,191			233,550			217,596

13

Callon Petroleum Company

Consolidated Statements of Cash Flows

(in thousands)

	Three Months Ended December 31,						For the Year Ended December 31,
	2019			2018			2019			2018
Cash flows from operating activities:
Net income (loss)		($23,543	)		$156,194			$67,928			$300,360
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	63,198			60,549			245,936			185,605
Amortization of non-cash debt related items	689			734			2,907			2,483
Deferred income tax (benefit) expense	5,857			5,647			35,301			8,110
(Gain) loss on derivative contracts	30,694			(103,918		)	62,109			(48,544		)
Cash paid for commodity derivative settlements, net	(3,353		)	(1,594		)	(3,789		)	(27,272		)
Gain on sale of other property and equipment	(126		)	(64		)	(90		)	(144		)
Non-cash loss on early extinguishment of debt	4,881			—			4,881			—
Non-cash expense related to equity share-based awards	1,899			1,823			9,767			6,289
Change in the fair value of liability share-based awards	1,518			(1,053		)	1,624			375
Payments to settle asset retirement obligations	(2,723		)	(389		)	(4,148		)	(1,469		)
Payments for cash-settled restricted stock unit awards	—			—			(1,425		)	(4,990		)
Changes in current assets and liabilities:
Accounts receivable	(52,671		)	37,033			(35,071		)	(17,351		)
Other current assets	1,006			(5,936		)	(4,166		)	(7,601		)
Current liabilities	99,476			9,510			86,438			74,311
Other long-term liabilities	—			(6,065		)	—			—
Other	10,776			(832		)	8,114			(2,508		)
Net cash provided by operating activities	137,578			151,639			476,316			467,654
Cash flows from investing activities:
Capital expenditures	(137,115		)	(155,821		)	(640,540		)	(611,173		)
Acquisitions	(1,478		)	(122,809		)	(42,266		)	(718,793		)
Additions to other assets	—			(3,100		)	—			(3,100		)
Proceeds from sales of assets	14,465			683			294,417			9,009
Net cash used in investing activities	(124,128		)	(281,047		)	(388,389		)	(1,324,057		)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	1,874,900			230,000			2,455,900			500,000
Payments on senior secured revolving credit facility	(314,500		)	(95,000		)	(895,500		)	(325,000		)
Repayment of Prior Credit Facility	(475,400		)	—			(475,400		)	—
Repayment of Carrizo's senior secured revolving credit facility	(853,549		)	—			(853,549		)	—
Repayment of Carrizo's preferred stock	(220,399		)	—			(220,399		)	—
Issuance of 6.375% senior unsecured notes due 2026	—			—			—			400,000
Issuance of common stock	—			(376		)	—			287,988
Payment of preferred stock dividends	—			(1,824		)	(3,997		)	(7,295		)
Payment of deferred financing costs	(22,449		)	530			(22,480		)	(9,430		)
Tax withholdings related to restricted stock units	(21		)	—			(2,195		)	(1,804		)
Redemption of preferred stock	—			—			(73,017		)	—
Net cash provided by (used in) financing activities	(11,418		)	133,330			(90,637		)	844,459
Net change in cash and cash equivalents	2,032			3,922			(2,710		)	(11,944		)
Balance, beginning of period	11,309			12,129			16,051			27,995
Balance, end of period		$13,341			$16,051			$13,341			$16,051

14

Non-GAAP Financial Measures and Reconciliations

This news release refers to non-GAAP financial measures such as “Drill-bit F&D costs per Boe,” “PD F&D costs per Boe,” “Operating margin per Boe,” “free cash flow,” “Organic reserve replacement ratio,” “PV-10,” “Discretionary Cash Flow,” “Adjusted G&A,” “Adjusted Income,” “Adjusted EBITDA” and “Adjusted Total Revenue.” 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.

• Callon believes that the non-GAAP measure of discretionary cash flow 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. Discretionary cash flow is defined by Callon as net cash provided by operating activities before changes in working capital and payments to settle asset retirement obligations and vested liability share-based awards. 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 in the period in which the operating activities occurred. 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 (as defined under GAAP), or as a measure of liquidity, or as an alternative to net income.

• Callon believes that the non-GAAP measure of free cash flow 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 after internally funding their capital development program and servicing their existing debt. Free cash flow is defined by Callon as Adjusted EBITDA (as defined below) less accrual-based capital expenditures and interest expense. 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 (as defined under GAAP), or as a measure of liquidity, or as an alternative to net income.

• Adjusted G&A is a supplemental non-GAAP financial measure that excludes certain non-recurring expenses and non-cash valuation adjustments related to incentive compensation plans, as well as non-cash corporate depreciation and amortization expense. 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. The table contained within this release details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A.

• Callon believes that the non-GAAP measure of Adjusted Income available to common shareholders (“Adjusted Income”) and Adjusted Income per fully diluted common share are useful to investors because they provide a meaningful measure of our profitability that does not take into account certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of certain non-recurring items and non-cash valuation adjustments, which are detailed in the reconciliation provided.

• Callon calculates adjusted earnings before interest, income taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, asset retirement obligation accretion expense, (gains) losses on derivative instruments excluding net settled derivative instruments, impairment of oil and natural gas properties, non-cash equity based compensation, 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. However, the Company believes that Adjusted EBITDA 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 may not be comparable to similarly titled measures of other companies.

• Callon believes that the non-GAAP measure of Adjusted Total Revenue 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.

• We believe Drill-Bit F&D costs per Boe and Organic reserve replacement ratio are non-GAAP metrics commonly used by companies in our industry, as well as analysts and investors, to measure and evaluate the cost of replenishing annual production and adding proved reserves. The Company’s definitions of Drill-Bit F&D costs per Boe and Organic reserve replacement ratio may differ significantly from definitions used by other companies to compute similar measures and as a result may not be comparable to similar measures provided by other companies. Consequently, we provided the detail of our calculation within the included tables.

• 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 (“Standardized Measure”). Pre-tax PV-10 is calculated using the Standardized Measure before deducting future income taxes, discounted at 10 percent. The 12-month average benchmark

15

pricing used to estimate proved reserves in accordance with the definitions and regulations of the SEC and pre-tax PV-10 value for crude oil and natural gas was $55.69 per Bbl of WTI crude oil and $2.58 per MMBtu of natural gas at Henry Hub before differential adjustments. After differential adjustments, the Company’s SEC pricing realizations for year-end 2019 were $53.90 per Bbl of oil and $1.55 per Mcf of natural gas.

Earnings Call Information

The Company will host a conference call on Thursday, February 27, 2020, to discuss fourth quarter 2019 financial and operating results.

Please join Callon Petroleum Company via the Internet for a webcast of the conference call:

Date/Time:	Thursday, February 27, 2020, 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.

Alternatively, you may join by telephone using the following numbers:

Domestic:	1-888-317-6003
Canada:	1-866-284-3684
International:	1-412-317-6061
Access code:	8524953

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

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 Statements

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 drilling activity and associated production and cash flow expectations; the Company’s 2020 production guidance and capital expenditure forecast; estimated reserve quantities and the present value thereof; 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; 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 activities; the ultimate timing, outcome and results of integrating the operations of Carrizo and Callon; the effects of the business combination of Carrizo and Callon, including the Company’s future financial condition, results of operations, strategy and plans; the ability of the combined company to realize anticipated synergies and other benefits in the timeframe expected or at all; 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.

Contact information

Mark Brewer

Director of Investor Relations

Callon Petroleum Company

ir@callon.com

1-281-589-5200

16

EX-99.2

Exhibit 99.2 4th QUARTER 2019 EARNINGS February 27th, 2020

IMPORTANT DISCLOSURES FORWARD LOOKING STATEMENTS This presentation 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 drilling activity and associated production and cash flow expectations; the Company’s production guidance and capital expenditure forecast; estimated reserve quantities and the present value thereof; anticipated returns and financial position; and the implementation of the Company's business plans and strategy, as well as statements including the words "believe," "expect," “may,” “will,” "forecast," “outlook,” "plans" 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, as of this date 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 of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except 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, ability to drill and complete wells, operational, regulatory and environment risks, cost and availability of equipment and labor, our ability to finance our activities, the ultimate timing, outcome and results of integrating the operations of Carrizo and Callon and the ability of the combined company to realized anticipated synergies and other benefits in the timeframe expected or at all, and other risks more fully discussed in our filings with the Securities and Exchange Commission, including our most recent Annual Report 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. SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES This presentation includes non-GAAP measures, such as Adjusted EBITDA, Adjusted Total Revenue, Adjusted G&A, PV-10, Net Debt to LQA Adjusted EBITDA, Free Cash Flow and other measures identified as non-GAAP. Reconciliations are available in the Appendix. Non-GAAP measures are not alternatives for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP, which are included in our SEC filings. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, asset retirement obligation accretion expense, (gains) losses on derivative instruments excluding net settled derivative instruments, impairment of oil and natural gas properties, non-cash equity based compensation, and other operating expenses. Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our presentation of Adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Adjusted Total Revenues is a supplemental non-GAAP financial measure. We define Adjusted Total Revenues as total revenues inclusive of the impact of commodity derivative settlements. We believe Adjusted Total Revenues 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. Adjusted General and Administrative expense (“Adjusted G&A”) is a supplemental non-GAAP financial measure that excludes certain non-recurring expenses and non-cash valuation adjustments related to incentive compensation plans, as well as non-cash corporate depreciation and amortization expense. We believe that the non-GAAP measure of Adjusted G&A is useful to investors because it provides readers with a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. Free Cash Flow is a non-GAAP measure. Free Cash Flow is defined by the Company as Adjusted EBITDA less operational capital, capitalized interest, net interest expense and capitalized G&A. We believe free cash flow 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. 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). PV-10 is a non-GAAP financial measure which excludes the present value of future income taxes discounted at 10% per annum, which is included in the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure. PV-10 is presented because management believes it provides greater comparability when evaluating oil and gas companies due to the many factors unique to each individual company that impact the amount and timing of future income taxes. In addition, the Company believes that PV-10 is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and gas companies. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company’s financial or operating performance presented in accordance with GAAP. Net Debt to Last Quarter Annualized (“LQA”) Adjusted EBITDA is a non-GAAP measure. The Company defines Net Debt to LQA Adjusted EBITDA as the sum of total long-term debt less unrestricted cash and cash equivalents (as determined under GAAP), divided by the Company’s current quarter annualized Adjusted EBITDA inclusive of pro-forma results from the acquisition completed in the current period. The Company presents these metrics to help evaluate its capital structure, financial leverage, and forward-looking cash profile. The Company believes that these metrics are widely used by industry professions, research and credit analysts, and lending and rating agencies in the evaluation of total leverage. 2

RETURNS-FOCUSED, MULTI-BASIN PORTFOLIO WITH SCALE KEY STATISTICS COMPLIMENTARY ASSET PORTFOLIO 4Q19 Total Production (MBoe/d) 46.6 / 105.8 4Q19 PF (1) Midland Basin: (1) 4Q19 Crude Oil Production (MBbls/d) 35.1 / 71.9 4Q19 PF Mid-cycle co-development of 4Q19 FCF ($MM) $9.1 / $58.2 4Q19 PF (1)(2) high return multi-zone inventory YE 2019 Proved Reserves (MMBoe) 540.0 YE 2019 PV-10 ($BN) $5.4 (3) Enterprise Value ($BN) $4.4 (4) 2020 Operational Capital Budget ($MM) $975 2020 Production Guidance (3-stream) 115 – 120 Mboepd 66% Oil 83% Liquids 2019 HIGHLIGHTS ▪ Acquired Carrizo Oil & Gas, more than doubling reserves, acreage, cash flow, and production Delaware Basin: Long-term growth driver shifting ▪ Completed over $300 million in non-core asset monetizations into development mode ▪ Achieved record production (top of guidance) with capital spending below the bottom of full year guidance range ▪ Maintained an industry-leading Adjusted EBITDA margin ($33.28 Eagle Ford Shale: per Boe for FY 2019) Highly efficient cash flow machine with repeatable, low-risk inventory ▪ Redeemed ~ $270 million in preferred shares, eliminating $25 million in annual future dividend payments ▪ Initiated full-field co-development across all asset areas, lowering (5) target development costs and improving capital efficiency ~ 200,000 Net Acres 1. Callon 4Q19 actual results include the final 11 days of Carrizo 4Q19 results. Callon presented on a two-stream basis and Carrizo on a three-stream basis for 4Q19 results and year end 2019 reserves. 2. Please see Appendix for reconciliation. Free cash flow (“FCF”) defined as Adjusted EBITDA minus the sum of operational capital, capitalized interest, capitalized G&A, and interest expense. Adjusted EBITDA is a non-GAAP financial measure; please refer to the Important Disclosures for a definition on Adjusted EBITDA as calculated by Callon and the Appendix for reconciliation. 3. Please refer to the Non-GAAP Disclosure at the beginning of this release for information regarding PV-10 and Appendix for reconciliation. 3 4. Based on volume weighted average price from 2/1/20 – 2/20//20. Defined as market cap plus 12/31/2019 net debt. Net debt is a Non-GAAP disclosure. Please see Appendix for Net Debt reconciliation. 5. Excludes approximately 57,000 net acres related to an exploration position in Texas and de minimus positions outside of Texas.

DELIVERING SHAREHOLDER VALUE (1) Improving Corporate Returns on Capital ▪ Targeting CROCI (2) of 18%, up from 13% in 2019 on stand-alone basis ▪ Focus on capital discipline, budget down over $100 million versus pro forma 2019 ▪ Scaled 2020 development program and balanced capital allocation reduces capital intensity ▪ Updated estimate of 2020 transaction synergies of over $80 million from cost reductions and capital efficiencies excluding improved uptime Generating Meaningful Free Cash Flow ▪ FCF positive in 4Q19, 2020 break-even costs already below $50/Bbl from pro forma development model ▪ Retaining margin leadership, 2019 pro forma Adj. EBITDA margin of 72% (FY19 $30.63 Adj. EBITDA per Boe) (3) ▪ Rationalization of corporate costs drives over $35 million in expected first year cash G&A savings (4) ▪ Moderated production growth and controlled flowback tempers declines and supports growing free cash flow Improving Financial Profile ▪ Redemption of preferred shares reduces dividend payments by $25 million and simplifies capital structure ▪ Multiple asset rationalization/monetization options progressing, targeting $300 to $400 million by YE20 ▪ Improved credit profile driving lower cost of capital Long Term Vision ▪ Optimize multi-zone, co-development with customized spacing for durability of returns and inventory ▪ Diversification of gathering and transport to manage risk and maximize returns ▪ Continued focus on SAFE and SUSTAINABLE operations 1. Pro forma represents combined Callon and Carrizo. 2. Cash Return on Invested Capital (“CROCI”) is defined as (GAAP cash flow from operations before changes in working capital + after tax interest expense) / (average total debt + average stockholders’ equity). 2019 estimated CROCI based on Callon standalone. 4 3. Adjusted EBITDA is a non-GAAP financial measure; please refer to the Important Disclosures for a definition on Adjusted EBITDA as calculated by Callon. 4. See page 21 for further information on G&A synergies.

HISTORY OF STRATEGIC EVOLUTION AND EXPANSION Three-year average: 73% (1) 100% 75% 50% 25% 0% CPE EBITDA Margin EBITDA CPE 120 CPE continues CPE acquires 140k expansion of CRZO Southern Delaware 120k 100 Basin CPE expands footprint with 100k 80 acquisitions in Permian NetAcreage Midland Basin and CPE expands Southern Delaware 80k CPE expands Basin 60 Permian Basin footprint by 150% Midland Basin with new acquisition footprint 60k Production (MBoe/d) Production in Midland Basin 40 40k 20 20k 0 0k Legacy CRZO Production Legacy Callon Production Callon Net Permian Acreage Annual EBITDA Margin 1. Calculated as unhedged adjusted EBITDA over revenue for standalone CPE. Unhedged adjusted EBITDA is calculated as unhedged revenue/boe less total LOE/boe, total production taxes (% revenue), and cash G&A/boe. Data from Bloomberg. 5

SELF-FUNDED, HIGH-MARGIN OIL GROWTH COMPANY ATTRACTIVE COMBINED ASSET BASE WITH FREE CASH FLOW TO DEVELOP DEEP PERMIAN INVENTORY Accelerated value realization from deep Permian inventory Reflective of recent upspacing 2,800 Eagle Ford Permian ▪ Scale improves operational flexibility 2,400 ▪ Long-term growth driver; strong runway of oil focused development 2,000 1,600 ▪ Leading Southern Delaware position allows for capital efficiencies, 1,200 infrastructure advantages, and enhanced data capture 800 Eagle Ford provides cash flow and repeatable, low cost oil production Wellsof Operated#Gross 400 ▪ Mature, low risk asset with lower capital intensity 0 2020 Completion Program Total Gross Operated ▪ Maintenance mode allows for reallocation of cash to Permian Locations INDUSTRY LEADING EBITDA MARGINS (1) ▪ Strong oil and gas pricing, solid infrastructure support robust margins $35 Balanced portfolio for flexible and efficient capital allocation CPE CRZO ▪ Shorter cycle, maturing asset areas support the Delaware growth vehicle $30 Boe ▪ Low cost of supply as scaled development continues to drive down $25 drilling and completion costs ▪ Enhances short and long term returns while generating corporate-level $20 free cash flow EBITDA/ Unhedged $15 $10 1. 3Q19 unhedged EBITDA/boe. Sourced from company filings of BCEI, CDEV, CLR, CXO, EOG, FANG, HPR, JAG, LPI, MGY, MTDR , OAS, PDCE, PE, PXD, SM, WLL, WPX, XEC, XOG. 6

2020 GAME PLAN KEY ELEMENTS ▪ Accelerate combination of individual activity plans into an integrated capital efficient development model with consistency and economies of scale ahead of plan ▪ Maximize free cash flow generation with reduced reinvestment rate relative to previous years ▪ Incorporate learnings from combined 2019 activity for completion design and selective up-spacing for multi-zone development / wells offsetting any existing parent wells ▪ Drive baseline corporate and capital efficiencies, resulting in improved returns on capital and a corporate break-even free cash flow price of below $50 / Bbl (WTI) ▪ Establish solid foundation of repeatable execution as development model matures for more balanced quarterly capital deployment into 2021 and sustained free cash flow profile with a reduced reinvestment rate ▪ Deliver on asset monetization goals from multiple options currently in process 4Q19 / 1Q20: “FIRING UP THE MACHINE” ▪ 4Q19 (pro forma estimated) free cash flow generation of $58.2 million ▪ Enter 2020 with substantial inventory of drilled, uncompleted wells (64) to overlay scaled development model ▪ Running nine rigs and four completion crews across portfolio starting early January 2020 ▪ Bring shorter cycle, large scale Eagle Ford projects online in mid / late 1Q20 ▪ Build queue of longer cycle Delaware Basin projects that will drive growth in 2Q / 3Q20 ▪ Substantial hedge protection in place for 1Q20 (70%+ of estimated oil volumes) and FY20 (60%+ of estimated volumes) 7

2020 OUTLOOK CAPITAL EFFICIENCY RATE OF CHANGE (1) 2020 GUIDANCE (2) Total production (MBoepd) 115 – 120 2020 Pro Forma Boepd Oil production 66% Add Per $1MM NGL production 17% Gas production 17% Income statement expenses 2019 Pro Forma Boepd Add Per $1MM LOE, including workovers (mm) $195 - $235 Gathering, Processing, and Transportation ($/Boe) $1.55 - $1.95 Production taxes, including ad valorem 6.5% 5 8 11 14 (% of unhedged revenues) SUPPLEMENTARY GUIDANCE POINTS Adjusted G&A: cash component (3) (mm) $55 - $65 ▪ 1Q20E total production of 95 – 100 Mboepd Adjusted G&A: non-cash component (4) (mm) $10 - $15 (65% oil) Cash interest expense (mm) $55 - $65 ▪ Expected sequential quarterly growth of 15% - 20% into 2Q20 Estimated effective income tax rate 23% ▪ Forecast FY20 unhedged oil price Capital expenditures ($MM, accrual basis) realizations of ~ 100% of WTI Total Operational Capital (5) $975 ▪ ~ 60% of operational capital budget planned for 1H20 Capitalized interest $115 - $125 ▪ Estimated corporate PDP production decline of ~ 35% from January 2020 to January 2021 Capitalized G&A (6) $45 - $50 Gross Operated Wells Drilled / Completed ~ 165 / ~ 160 1. Pro forma company with production and capital adjustments for 2018 Southern Delaware bolt-on and 2019 Southern Midland sale. 2. Guidance presented on a three-stream basis 3. Excludes stock-based compensation and corporate depreciation and amortization. 4. Excludes certain non-recurring expenses and non-cash valuation adjustments. 8 5. Includes drilling, completions, equipment, facilities, seismic, land and other items. Excludes capitalized expenses. 6. Capitalized G&A inclusive of non-cash items.

2020 CAPITAL PROGRAM ACHIEVES EFFICIENCIES OF SCALE 2020 OPERATIONAL CAPEX BREAKDOWN (1) 8 - 9 Operated Rigs 3 Avg. Operated Completion Crews 165 / 160 Gross Wells Drilled / Completed (WI: 80 – 95%) 2020 TRAJECTORY COMMENTARY (2) Capital ▪ 2020 capital/production cadence similar to 2019 but better Budget: positioned for smoother profile in 2021 as new model matures $975 MM ▪ Operated capital expenditures for the year are expected to be weighted approximately 60% / 40% between the first / second half of the year ▪ Total production for the year is expected to be weighted roughly 45% / 55% between first / second half of the year ▪ 4Q20E rig / completion crew ratio declines > 30% to 4.0 (pro forma 4Q18 and 4Q19 ratios were ~ 6.0) with similar YE DUC counts ▪ DUCs completed early in the year will be replenished to over 60 at YE 2020 with increased Permian weighting Delaware Eagle Ford Midland Facilities Other providing continued flexibility into 2021 ▪ 2020 average pad size increases > 25% and average total project size more than doubles 1. Operational capital by asset area includes drilling, completions, and equipment. Other components includes non-operated activity, capitalized workovers, land, and technology. 2. DUC (drilled uncompleted) commentary based on gross wells. 9

DEVELOPMENT OPTIMIZATION MAXIMIZING RETURNS WHILE PRESERVING ECONOMIC INVENTORY DRIVES SUSTAINABLE FCF GENERATION OPTIMIZED PROGRAM DEVELOPMENT SIGNIFICANT ADVANTAGES ACHIEVED Communicate effectively Lower well costs ▪ Plan development to optimize ▪ Maximizing crew efficiency, leveraging production between zones that infrastructure, and bundling costs communicate reduces overall capex Shorter cycle times ▪ Project compression allows for faster Give it some space cash recovery and better crew utilization ▪ Customize spacing where needed to Less offset completion impact account for prior development ▪ Improved ratio of new wells to impacted production PLUS lower downtime for shut-ins and faster returns to production Mind the gap + Parents, - children ▪ Reduce time between development ▪ Improved development timing through vintages to minimize effects of pressure project scale and field efficiency lowers depletion and voidage the number of potential child wells, boosting average future well productivity Parent wells Child wells 10

DELAWARE SYNERGY VALUE CAPTURE EXCEEDS TARGET (1)(2) IDENTIFIED STRUCTURAL SAVINGS AVERAGE WELL SYNERGY BREAKDOWN (DC&E/1,000’ LATERAL) Scaled development model $1,300 > $45 MM (3) 2020 D&C Synergy Update ▪ Consistent crews and equipment ~ $25 - $30 MM Original 2020 D&C Synergy Guidance ▪ Shared services and reduced surface costs $1,250 ▪ Decreased mobilization times $1,200 Best practices / design improvement $1,250 $150 ▪ Proppant and loading modifications $1,150 ▪ Local sand usage $105 / 1,000’ ▪ Process optimization from knowledge sharing $1,100 STRUCTURAL SAVINGS: $105,000 / 1,000’ $1,100 $60 $1,050 2020 Synergy Breakdown DC&E/1,000’ $45 $1,000 5% DC&E Reduction $60 1,000’Lateral($000) Targeted / DC&E Target $950 Additional Large Scale $35 Savings $995 $900 Additional Best Practices $10 Savings $850 Initial 2019 Realized 2019 5% Targeted Additional Current Delaware Service Cost Adjusted Delaware Identified Delaware DC&E Deflation and Delaware DC&E Structural DC&E AFE 2019 DC&E Synergies Savings Efficiencies 1. All data based on pro forma Company and targeted lateral length. 2. 2019 Delaware DC&E adjusted for service cost deflation. 3. See Appendix slide: “Long Term Focus on Capital Allocation Strategy” for further modeling detail. 11

CONTINUED CAPITAL EFFICIENCY EXECUTION (1)(2) DELAWARE DC&E ($000) / 1,000’ Scaled development drives lower costs $1,450 ▪ Simultaneous operations improves completion cycle $1,100 $995 time efficiency and performance consistency ▪ Reduced mobilization/demobilization time ▪ Executing multi-pad development 2018 2019 2020 ▪ Consolidation of vendor services MIDLAND DC&E ($000) / 1,000’ Design improvements increase well recoveries $1,150 ▪ DC&E/1,000’ declines while improving overall fluid $800 $700 efficiency ▪ Increase WildHorse activity in 2020 ▪ Acreage capture promotes lateral extension 2018 2019 2020 EAGLE FORD DC&E ($000) / 1,000’ $675 Completion cost savings and upspacing enhance $550 $505 efficiency ▪ Local sand availability improves pricing ▪ Gains in stages/day as average project size increases 2018 2019 2020 ▪ Customized spacing parameters for all locations 1. All data based on pro forma company and targeted lateral length. 2. Drilling and completions includes equipment costs related to flowlines and testers. 12

DURABLE FREE CASH FLOW THROUGH CYCLES (1)(2)(3) 2020 FREE CASH FLOW SENSITIVITIES PF 4Q19 FREE CASH $58 MM (3) $250 20% FLOW 2020 WTI < $50 BREAKEVEN $200 15% 2020 REVENUE < 10% EXPOSURE TO GAS $150 (4) FCF FCF Yield 2020 NET CONTINGENT PAYMENTS 10% No potential outflows after 2020 $MM (potential inflows) $35 $100 $30 $25 5% $20 $50 $MM $15 $10 $5 $0 0% $0 $50 Oil $55 Oil $60 Oil $50 Oil $55 Oil $60 Oil Free Cash Flow Free Cash Flow Yield 1. Assumes $2.50/mmbtu Henry Hub (~ 35% HH realized) and $19.25/Bbl NGLs (~ 80% NGL realized). 2. Free cash flow yield based on CPE volume weighted average price from 2/1/20 – 2/20/20. 3. Free cash flow (“FCF”) defined as Adjusted EBITDA minus the sum of operational capital, capitalized interest, capitalized G&A, and interest expense. Adjusted EBITDA is a non-GAAP financial measure; please refer to 13 the Important Disclosures for a definition on Adjusted EBITDA as calculated by Callon. 4. Assumes accrual basis accounting for contingent payments in 2020.

DIFFERENTIATED ASSETS AND OPPORTUNITY QUALITY BUSINESS MODEL (1) Operating Margin CPE Pro Forma ▪ Industry-leading operating margin and return on capital differentiate asset quality and outperform premium Top 5 Equity Performers Average multiple peers Bottom 5 Equity Performers Average ▪ Efficient capital allocation of high-margin assets not reflected in current EV/EBITDA multiple of 3.3x (represented in bubble size of below quadrant) ▪ Positive momentum further spurred by absolute debt reduction from organically generated free cash flow and Oil Weighting Returns on Capital targeted asset monetizations 2020 EV/EBITDA MULTIPLES POISED FOR HIGH MARGIN, CAPITAL EFFICIENT RE-RATING (2) Low Margin High Margin 11 More Capital Efficient More Capital Efficient 8 CPE 5 2 Bubble Size Based on Operational CapitalOperational EV/EBITDA Multiple -1 Low Margin High Margin Less Capital Efficient Less Capital Efficient 2020 Bopd Pro Forma Addition Per $1MM $1MM PerForma AdditionPro2020Bopd -4 $10 $15 $20 $25 $30 $35 2019 Operating Margin (Adj. EBITDAX $/Boe) 1. Universe includes: APA, AR, BRY, CDEV, CHK, CLR, COG, CPE, CXO, DVN, EOG, EQT, FANG, HES, HPR, LPI, MRO, MTDR, MUR, NBL, OAS, OVV, OXY, PDCE, PE, PXD, QEP, RRC, SM, SWN, WLL, WPX, XEC. Top and bottom five performers based on 2/1/20-2/20/20 VWAP vs. 1/31/19-2/20/19 VWAP performance. Operating margin (defined as 2019 Adj. EBITDA(X) /Boe) and oil weighting sourced from Bloomberg. Returns (2020E ROACE) sourced from BMO Research. CPE reflects pro forma adjustments for all metrics. As of 2/21/20. 14 2. Bubble size based on 2020EV/EBITDA(X) multiples. Peers Include: APA, CDEV, CXO, EOG, FANG, LPI, MRO, MTDR, NBL, OAS, OVV, PDCE, PE, QEP, SM, and XEC. DVN and WPX excluded due to pro forma reconciliations. Source: Bloomberg 2/21/20.

PROTECTING CASH FLOW AND IMPROVING DIVERSIFICATION ▪ Focused on total realized price including both benchmark and Robust hedges minimize the impact to oil revenue which is basis; aligning hedges to complement pricing points > than 90% of projected total revenue ▪ Over 70% of 1Q20 oil hedged above $55/Bbl (1) WTI ▪ Waha basis hedge protection for ~ 65% of Permian dry gas volumes (1) ▪ Nymex floors for Henry Hub at just under $2.50/mmbtu ▪ Magellan East Houston basis hedges (~$2.60) covering nearly 13,000 Bbls/d for 2Q20 to 4Q20 ▪ 25,000 gross barrels of oil per day covered by FT as of 2Q20 Oil Revenue Natural Gas and NGL Revenue 2020 oil volumes (1) are ~ 60% oriented to Gulf markets with 2020 oil volumes (1) are currently > 60% hedged at a weighted protection via fixed price swaps and basis hedges average floor of more than $55 WTI International Magellan East Houston WTI (Midland) Total Barrels Unhedged Total Barrels Hedged 1. Percentages based on the midpoint of guidance. 15

FINANCIAL STRENGTH ENHANCED CREDIT AND SIMPLIFIED CAP STRUCTURE 4Q19 CAPITALIZATION TABLE ▪ No near-term maturities and elected availability of ~ $700 4Q19 million Cash $13 ▪ PDP reserves PV-10 in excess of total debt Credit Facility $1,285 ▪ Upgraded by Moody’s in June 2019 and S&P in January 2020 Senior Notes 1,900 Total Debt $3,185 ▪ Continue to opportunistically add 2020 and 2021 commodity hedge positions to protect FCF generation Stockholders’ Equity 3,223 Total Capitalization $6,408 ▪ Redeemed 10% and 8.75% preferred stock securities Total Liquidity (1) $710 ▪ Targeting < 2.0x via FCF and non-core asset sales Net Debt to LQA EBITDA (2) 2.6x LONG DATED MATURITIES $650MM 6.25% $250MM 8.25% Sr Notes Due Sr Notes Due $600MM 6.125% $400MM 6.375% Sr Notes Due Sr Notes Due 2019 2020 2021 2022 2023 2024 2025 2026 December 20 RBL Maturity RBL Effective Date 1. Based on elected commitment amount of $2.0 billion on current borrowing base of $2.5 billion. All figures are as of 12/31/2019, 2. Net Debt to LQA Adjusted EBITDA is calculated as the sum of total long-term debt less unrestricted cash and cash equivalents, divided by the full quarter annualized pro forma Adjusted EBITDA. 16

ENVIRONMENTAL, SOCIAL, AND GOVERNANCE (1) LONG TERM INCENTIVE PLAN (“LTIP”) COMPENSATION ALIGNED WITH STAKEHOLDERS ▪ 70% of executive compensation weighted to LTIP ▪ Performance shares = 60% of LTIP weighting ▪ Added an ABSOLUTE TSR modifier to 2020 performance share awards to further align executive compensation with stakeholders (Minimum absolute annualized TSR of 5% required for 100% multiplier) ▪ ~ 60% produced water sourced for Total Recycled Water Volumes (MM Bbls) Delaware completions in 2019 9 ▪ > 40% reduction in gas flaring in 2019 ENVIRONMENTAL (based on flaring intensity Mcf/Bbl as 6 defined by the TX RRC) (2) 3 ▪ > 2x increase in average project size in 0 2020 minimizes surface impact 2017 2018 2019 ▪ 50% reduction in TRIR (2019 best year on Record TRIR Safety Performance (3) record for safety performance) 1.50 ▪ Named “Top Workplace” by Houston 1.00 SOCIAL Chronicle 3 years in a row 0.50 ▪ Employee matching program for 0.00 charitable giving 2017 2018 2019 ▪ Two female Directors % Independent Directors ▪ Less than 5 year tenure for over half the 95% Directors GOVERNANCE 90% ▪ 80% quantitative metrics for 2020 STIP (including returns and synergy-related 85% metrics) 2017 2018 2019 1. Data based on standalone Callon 2019 performance for Environmental and Social sections with the exception of 2020 project size increase. Governance and compensation commentary based on 2020 pro forma company. 2. TX RRC (Texas Railroad Commission) defines flare intensity as gross daily flare volumes divided by gross daily oil production. Callon flare intensity of 8% in 2019 is below the 10% benchmark set by the Texas Railroad Commission. 17 3. Defined as incidents per 200,000 man hours, inclusive of contractor performance.

SCALE TO COMPETE IN THE CURRENT ENVIRONMENT (1) 2016 2019 PF 2020E OUR FOCUS: (2) • Consistent Execution Total Net Acres ~ 40,000 ~ 200,000 • Efficient Development Proved Reserves 54 540 (mmboe) (mmboe) • Improving Returns (3) • FCF Generation Oil Production 4 73 78 7% (mbopd) (mbopd) (mbopd) • Debt Reduction Adj. EBITDA $1.22 $2.97 ~ $3.20 8% • Asset Rationalization Per Share (4) • Sustainability Operational $117 $1,067 $975 9% Capital (mm) (mm) (mm) CROCI (5) 10% 13% 18% 5% 1. Figures below represent net acreage positions and proved reserves as of December 31, 2015 and 2019 (adjusted for Southern Midland sale). 2. Excludes approximately 57,000 net acres related to an exploration position in Texas and de minimus positions outside of Texas. 3. Pro forma Ranger sale. 18 4. Standalone data in 2016 please see Appendix for reconciliation. Pro forma Company data in 2019 and 2020 based on share count from 11/20/19 proxy filing. 2020 EBITDA sourced from Bloomberg consensus estimates. 5. Cash Return on Invested Capital (“CROCI”) is defined as (GAAP cash flow from operations before changes in working capital + after tax interest expense) / (average total debt + average stockholders’ equity). 2019 estimated CROCI based on Callon standalone.

APPENDIX

LONG-TERM FOCUS ON CAPITAL ALLOCATION STRATEGY DELAWARE (1) MIDLAND (1) EAGLE FORD (1) 2019 (2) 2020 2019 2020 2019 2020 DC&E / 1,000’ $1,100 $995 DC&E / 1,000’ $800 $700 DC&E / 1,000’ $550 $505 % Drilling 45% 45% % Drilling 45% 45% % Drilling 35% 40% % Completions 50% 50% % Completions 50% 45% % Completions 60% 55% % Equipment 5% 5% % Equipment 5% 10% % Equipment 5% 5% Average Lateral 9,000’ 8,900’ Average Lateral 8,300’ 8,400’ Average Lateral 7,700’ 7,900’ Length POP’d Length POP’d Length POP’d Gross Drilled / 62 / 47 ~ 65 / 50 Gross Drilled / 27 / 34 ~ 40 / 30 Gross Drilled / 74 / 77 ~ 60 / 80 Completion Count Completion Count Completion Count % Working Interest 75 - 95% 80 - 90% % Working Interest 80 - 85% 80 - 90% % Working Interest 90 - 95% 90 - 95% % Operational Capex ~ 40% ~ 45% % Operational Capex ~ 15% ~ 20% % Operational Capex ~ 30% ~ 25% CAPITAL ALLOCATION REFLECTS CO-DEVELOPMENT STRATEGY (3) NON - DC&E CAPITAL DECLINES (4) Callon Delaware Pro Forma Southern Delaware Operator Average 25% 20% 15% ~ 50% ~ 70% WCA WCA 10% Operational Operational Capital 5% % Non Non % DC&E Capital ofTotal 0% Above WCA WCA Below WCA 2018 2019 2020 1. All data based on operated wells for pro forma company. Assumes targeted lateral length. 2. 2019 Delaware DC&E adjusted for service cost deflation. 3. Source: IHS based on wells placed on production from 2014-2019. Callon Delaware includes CPE and CRZO. Southern Delaware Average includes CDEV, CXO, FANG, EOG, XOM, NBL, OAS, PE/JAG, and WPX. 20 4. 2018 data based on standalone Callon,

ACHIEVING G&A SYNERGIES EARLY TIME COMPLETE SUBSTANTIALLY COMPLETE IN PROGRESS Executive Leadership Reductions in Non-Payroll Related Reductions Duplicative Groups Corporate Overlap • Office consolidation • Software licensing • Public company costs • Outside advisors • Systems redundancy • Duplicate service providers $150 150 $100 2020 Capitalized G&A: $40 to $45 million >$35 MM $50 2020 Cash G&A: In Cash G&A ($MM) G&A CashIn “Year One” - $55 to $65 million All Savings $0 2019 Total Leadership Duplicate Non-Payroll 2020 Total G&A(1) Reductions Groups G&A G&A(1) 1. Total G&A is the combined total of cash G&A costs plus capitalized G&A costs. 21

4Q19 CONTRIBUTION DETAIL CPE 4Q19 Stand-alone (1) CRZO 4Q19 11 Days (2) 4Q19 Reported CRZO 4Q19 Stand-alone (1) TOTAL PRODUCTION (Mboe) 3,582 707 4,289 6,151 OIL PERCENTAGE 78% 60% 75% 62% NGL PERCENTAGE N/A 20% 3% 18% GAS PERCENTAGE 22% 20% 22% 20% OIL PRICE (% WTI) 99% 104% 99% 98% NGL PRICE (% WTI) N/A 27% 27% 26% GAS PRICE (% HH) 85% 64% 82% 74% LOE ($/Boe) $5.53 $5.83 $5.58 $5.73 GP&T ($/Boe) (3) $1.95 $1.93 CASH G&A ($/Boe) $2.46 $1.37 $2.28 $1.85 PRODUCTION TAX (%) 4% 5% 5% 5% OPERATIONAL CAPITAL ($MM) $96 $14 $110 $84 CAPITALIZED INTEREST ($MM) $20 $2 $22 N/A CAPITALIZED G&A ($MM) $9 $0.0 $9 $7 1. Pricing excludes impact of realized derivative settlements. 2. Only represents Carrizo’s 11-day contribution to 4Q19 reported results. Does not represent full 4Q19 for Carrizo. Capitalized interest for Carrizo contribution represents accrued interest on Carrizo Senior Notes during those 11 days. 22 3. Historical CPE is under two-stream basis with GP&T treated as a revenue deduct.

THREE-STREAM CONVERSION PRO FORMA CPE FY19 CRZO FY19 PF FY19 PF FY19 TWO STREAM THREE STREAM COMBINED THREE STREAM TOTAL PRODUCTION (Mboepd) 39.4 66.1 105.5 108.6 OIL PERCENTAGE 78% 65% 70% 68% NGL PERCENTAGE N/A 17% 10% 16% GAS PERCENTAGE 22% 18% 20% 16% OIL PRICE (% WTI) 95% 100% 98% NGL PRICE (% WTI) N/A 26% 26% GAS PRICE (% HH) 73% 59% 65% LOE ($/Boe) $6.00 $5.75 $5.85 $5.69 GP&T ($/Boe) (3) $1.66 CASH G&A ($/Boe) $2.42 $2.09 $2.21 $2.15 PRODUCTION TAX (%) 6% 6% 6% 6% OPERATIONAL CAPITAL ($MM) $501 $566 $1,067 CAPITALIZED INTEREST ($MM) $78 $26 $104 CAPITALIZED G&A ($MM) $36 $18 $55 1. Pricing excludes impact of realized derivative settlements. 2. Only represents Carrizo’s 11-day contribution to 4Q19 reported results. Does not represent full 4Q19 for Carrizo. Capitalized interest for Carrizo contribution represents accrued interest on Carrizo Senior Notes during those 11-days. 23 3. Historical CPE is under two-stream basis with GP&T treated as a revenue deduct.

OIL HEDGE PORTFOLIO (1) 1Q20 2Q20 3Q20 4Q20 FY 2020 FY 2021 WTI NYMEX (Bbls, $/Bbl) Swaps Total Volumes 819,000 919,100 933,800 828,000 3,499,900 - Total Daily Volumes 9,000 10,100 10,150 9,000 9,563 - Avg. Sw ap $55.72 $55.82 $55.66 $55.72 $55.73 - Three-way Collars Total Volumes 3,276,000 3,276,000 3,312,000 3,312,000 13,176,000 - Total Daily Volumes 36,000 36,000 36,000 36,000 36,000 - Avg. Short Call Price $65.28 $65.28 $65.28 $65.28 $65.28 - Avg. Long Put Price $55.38 $55.38 $55.38 $55.38 $55.38 - Avg. Short Put Price $45.08 $45.08 $45.08 $45.08 $45.08 - Avg. Premium Price $0.08 $0.08 $0.08 $0.08 $0.08 - Total WTI Hedged (Bbl) 4,095,000 4,195,100 4,245,800 4,140,000 16,675,900 - Average WTI Ceiling Price ($/Bbl) $63.37 $63.20 $63.16 $63.37 $63.27 - Average WTI Floor Price ($/Bbl) $55.45 $55.48 $55.45 $55.45 $55.46 - ICE BRENT (Bbls, $/Bbl) Three-way Collars Total Volumes 150,000 227,500 230,000 230,000 837,500 - Total Daily Volumes 1,648 2,500 2,500 2,500 2,288 - Avg. Short Call Price $70.00 $70.00 $70.00 $70.00 $70.00 - Avg. Long Put Price $58.24 $58.24 $58.24 $58.24 $58.24 - Avg. Short Put Price $50.00 $50.00 $50.00 $50.00 $50.00 - MAGELLAN EAST HOUSTON FIXED PRICE (Bbls/$/Bbl) Swaps Total Volumes - 136,500 184,000 184,000 504,500 - Total Daily Volumes - 1,500 2,000 2,000 1,378 - Avg. Sw ap Price - $59.61 $58.23 $57.19 $58.22 - MAGELLAN EAST HOUSTON DIFFERENTIAL (Bbls/$/Bbl) Swaps Total Volumes 347,000 1,201,201 1,360,802 975,202 3,884,205 - Total Daily Volumes 3,813 13,200 14,791 10,600 10,613 - Avg. Sw ap Price $2.55 $2.62 $2.59 $2.56 $2.59 - MIDLAND-CUSHING DIFFERENTIAL (Bbls/$/Bbl) Swaps Total Volumes 1,901,900 1,965,600 2,217,200 2,392,000 8,476,700 4,015,100 Total Daily Volumes 20,900 21,600 24,100 26,000 23,160 11,000 Avg. Sw ap Price ($2.27) ($1.84) ($1.13) ($0.84) ($1.47) $0.40 1. Callon hedge portfolio as of 02/17/2020. In addition to the above hedge positions, Callon holds short the following positions: 6,000 bpd Cal20 $42.50-strike WTI puts, 4,575 bpd Cal20 WTI calls (avg. strike $75.98), and 13,220 bpd Cal21 WTI calls (avg. strike $63.62). 24

GAS HEDGE PORTFOLIO (1) 1Q20 2Q20 3Q20 4Q20 FY 2020 FY 2021 NYMEX HENRY HUB (MMBtu, $/MMBtu) Swaps Total Volumes 910,000 910,000 920,000 920,000 3,660,000 - Total Daily Volumes 10,000 10,000 10,000 10,000 10,000 - Avg. Sw ap Price $2.48 $2.48 $2.48 $2.48 $2.48 - Three-way Collars Total Volumes 910,000 910,000 920,000 920,000 3,660,000 - Total Daily Volumes 10,000 10,000 10,000 10,000 10,000 - Avg. Short Call Price $2.75 $2.75 $2.75 $2.75 $2.75 - Avg. Long Put Price $2.50 $2.50 $2.50 $2.50 $2.50 - Avg. Short Put Price $2.00 $2.00 $2.00 $2.00 $2.00 Total NYMEX Volume Hedged (MMBtu) 1,820,000 1,820,000 1,840,000 1,840,000 7,320,000 - Average NYMEX Ceiling Price ($/MMBtu) $2.61 $2.61 $2.61 $2.61 $2.61 - Average NYMEX Floor Price ($/MMBtu) $2.49 $2.49 $2.49 $2.49 $2.49 - WAHA DIFFERENTIAL (MMBtu, $/MMBtu) Swaps Total Volumes 5,824,000 4,732,000 5,244,000 5,796,000 21,596,000 - Total Daily Volumes 64,000 52,000 57,000 63,000 59,005 - Avg. Sw ap Price ($0.99) ($1.48) ($0.98) ($0.77) ($1.04) - 1. Callon hedge portfolio as of 02/17/2020. In addition to the above hedge positions, Callon holds short the following positions: 33,000 mmbtu/d Cal20 $3.50-strike calls, 20,000 mmbtu/d Cal21 calls (avg. strike $3.09). 25

QUARTERLY CASH FLOW STATEMENT (1) ($000s) 4Q'18 1Q'19 2Q'19 3Q'19 4Q'19 (2) Cash flows from operating activities: Net income (loss) 156,194 (19,543) 55,180 55,834 (23,543) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization 60,549 60,913 64,590 57,235 63,198 Amortization of non-cash debt related items 734 738 741 739 689 Deferred income tax (benefit) expense 5,647 (5,149) 16,691 17,902 5,857 (Gain) loss on derivative contracts (103,918) 67,260 (14,036) (21,809) 30,694 Cash paid for commodity derivative settlements, net (1,594) (290) (1,157) 1,011 (3,353) (Gain) loss on sale of other property and equipment (64) 28 21 (13) (126) Non-cash loss on early extinguishment of debt - - - - 4,881 Non-cash expense related to equity share-based awards 1,823 4,545 1,754 1,569 1,899 Change in the fair value of liability share-based awards (1,053) 1,881 (850) (925) 1,518 Payments to settle asset retirement obligations (389) (664) (107) (654) (2,723) Payments for cash-settled restricted stock unit awards - (1,296) (129) - - Changes in current assets and liabilities: Accounts receivable 37,033 (5,390) 44,071 (21,081) (52,671) Other current assets (5,936) (2,294) (3,807) 929 1,006 Current liabilities 9,510 (26,003) (10,251) 23,216 99,476 Other (6,897) (177) (2,224) (261) 10,776 Net cash provided by operating activities 151,639 74,559 150,487 113,692 137,578 Cash flows from investing activities: Capital expenditures (155,821) (193,211) (166,219) (143,995) (137,115) Acquisitions (122,809) (27,947) (11,423) (1,418) (1,478) Proceeds from sales of assets 683 13,879 260,417 5,656 14,465 Additions to other assets (3,100) - - - - Net cash used in investing activities (281,047) (207,279) 82,775 (139,757) (124,128) Cash flows from financing activities: Borrowings on senior secured revolving credit facility 230,000 220,000 140,000 221,000 1,874,900 Payments on senior secured revolving credit facility (95,000) (90,000) (365,000) (126,000) (314,500) Repayment of Prior Credit Facility - - - - (475,400) Repayment of Carrizo's senior secured revolving credit facility - - - - (853,549) Repayment of Carrizo's preferred stock - - - - (220,399) Issuance of common stock (376) - - - - Payment of preferred stock dividends (1,824) (1,824) (1,823) (350) - Payment of deferred financing costs 530 - (31) - (22,449) Tax withholdings related to restricted stock units - (1,025) (833) (316) (21) Redemption of preferred stock - - - (73,012) - Other financing activities - - (5) - - Net cash provided by (used in) financing activities 133,330 127,151 (227,692) 21,322 (11,418) Net change in cash and cash equivalents 3,922 (5,569) 5,570 (4,743) 2,032 Balance, beginning of period 12,129 16,051 10,482 16,052 11,309 Balance, end of period 16,051 10,482 16,052 11,309 13,341 1. See “Important Disclosures” slide for additional information related to Supplemental Non-GAAP Financial Measures. 2. Includes Carrizo results from December 21 to December 31, 2019. 26

NON-GAAP FREE CASH FLOW RECONCILIATION (1) ($000s) 4Q19 (2) Net cash provided by operating activities 137,578 Less: Changes in working capital (58,587) Plus: Payments to settle asset retirement obligations 2,723 Plus: Merger and integration expense 68,420 Plus: Other operating expense and non-recurring items 244 Adjusted EBITDA $150,378 Less: Operational capex (accrual) $110,021 Less: Capitalized Interest $21,781 Less: Interest Expense, net $689 Less: Capitalized G&A $8,780 Free Cash Flow $9,107 1. See “Important Disclosures” slide for additional information related to Supplemental Non-GAAP Financial Measures 2. Includes Carrizo results from December 21 to December 31, 2019. 27

NON-GAAP ADJUSTED EBITDA RECONCILIATION (1) ($000s) FY 2019 (2) Net income 67,928 (Gain) loss on derivatives, net 62,109 Cash paid for commodity derivative settlements, net (3,789) Non-cash stock-based compensation expense 11,364 Merger-related expenses 74,363 Other operating expense 1,076 Income tax (benefit) expense 35,301 Interest expense 2,907 Depreciation, depletion and amortization 244,991 Accretion expense 945 Loss on extinguishment of debt 4,881 Adjusted EBITDA $ 502,076 Adj. EBITDA per BOE $33.28 Total Production MBOE 15,086 1. See “Important Disclosures” slide for additional information related to Supplemental Non-GAAP Financial Measures 2. Includes Carrizo results from December 21 to December 31, 2019. 28

NON-GAAP PV-10 RECONCILIATION (1) As of December 31, 2019 2018 2017 (in millions) Standardized measure of discounted future net cash flows $4,951 $2,941 $1,557 Add: present value of future income taxes discounted at 10% per annum 419 208 20 PV-10 5,370 3,149 1,577 1. See “Important Disclosures” slide for additional information related to Supplemental Non-GAAP Financial Measures 29

NON-GAAP NET DEBT RECONCILIATION (1) As of December 31, 2019 (in millions) Long-term debt $3,186 Gross debt 3,186 Less Cash and cash equivalents 13 Net Debt $3,173 1. See “Important Disclosures” slide for additional information related to Supplemental Non-GAAP Financial Measures 30

NON-GAAP ADJUSTED EBITDA RECONCILIATION (1) ($000s) FY 2016 Net Income ($91,813) (Gain) loss on derivative contracts, net of settlements 38,135 Non-cash stock-based compensation expense 9,721 Withdrawn proxy contest expenses 224 Acquisition expense 3,673 Income tax expense (14) Interest expense 11,871 Loss on early extinguishment of debt 12,883 Depreciation, depletion and amortization 73,072 Impairment 95,788 Accretion expense 958 Adjusted EBITDA $154,498 Adjusted EBITDA per share $1.22 Shares Outstanding 126,258 1. See “Important Disclosures” slide for additional information related to Supplemental Non-GAAP Financial Measures. 31

XML

Cover Page	Feb. 26, 2020
Cover page.
Document Type	8-K
Document Period End Date	Feb. 26, 2020
Entity Registrant Name	Callon Petroleum Co
Entity Incorporation, State or Country Code	DE
Entity File Number	001-14039
Entity Tax Identification Number	64-0844345
Entity Address, Address Line One	2000 W. Sam Houston Parkway S.,
Entity Address, Address Line Two	Suite 2000
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77042
City Area Code	281
Local Phone Number	589-5200
Written Communications	false
Soliciting Material	false
Pre-commencement Tender Offer	false
Pre-commencement Issuer Tender Offer	false
Title of 12(b) Security	Common Stock, $0.01 par value
Trading Symbol	CPE
Security Exchange Name	NYSE
Entity Emerging Growth Company	false
Entity Central Index Key	0000928022
Amendment Flag	false