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