2 nd QUARTER 2018 EARNINGS AUGUST 6, 2018 Important Disclosures - PowerPoint PPT Presentation

2 nd QUARTER 2018 EARNINGS AUGUST 6, 2018

Important Disclosures Forward-Looking Statements This presentation contains projections and other 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. Words such as “estimate,” “project,” “will,” “may,” “anticipate,” “plan,” “intend,” “believe,” “expect,” “outlook,” “guidance,” “target,” “objective,” “forecast” or similar expressions that convey the prospective nature of events or outcomes generally indicate forward-looking statements. These projec tions and statements reflect the Company’s current views with respect to future events, investment plans and financial performance as of this date. 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. For a summary of events that may affect the accuracy of these projections and forward- looking statements, see “Risk Factors” in our Form 10 -K for the year ended December 31, 2017 filed with the Securities and Exchange Commission (the “SEC”) and other filings with the SEC. Unless legally required, Callon does not undertake any obligation to update forward looking statements as a result of new information, future events or otherwise SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES This presentation includes non-GAAP measures, such as Adjusted EBITDA, Adjusted Income, Adjusted Income per diluted share, Adjusted G&A and other measures identified as non- GAAP. Management also uses EBITDAX, which reflects EBITDA plus exploration and abandonments expense. 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, exploration expense, (gains) losses on derivative instruments excluding net cash receipts (payments) on settled derivative instruments and premiums paid for put options that settled during the period, impairment of oil and natural gas properties, non-cash equity based compensation, asset retirement obligation accretion expense, other income, gains and losses from the sale of assets and other non-cash operating items. Adjusted EBITDA is not a measure of net income as determined by United States general ly accepted accounting principles (‘‘GAAP’’). 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 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 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 i n 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. We believe that the non- GAAP measure of Adjusted income available to common shareholders (“Adjusted Income”) and Adjusted Income per diluted share are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of certain non-recurring items and non-cash valuation adjustments, which are detailed in the reconciliation provided below. Prior to being tax-effected and excluded, the amounts reflected in the determination of Adjusted income and Adjusted income per diluted share below were computed in accordance with GAAP. 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. 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. The Appendix table details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A. For a reconciliation of non-GAAP measures to their most directly comparable GAAP measure, please see schedules included in the Appendix.

Callon Petroleum 2Q18 RESULTS CURRENT RIG ACTIVITY 2Q18 production of 29.0 Mboe/d  Oil mix of 76%  YoY growth of 30% / sequential growth of 9% Operating margin of $44.17 per Boe (~85%) LOE per Boe $4.99 (1) Adjusted EBITDA of $102.6 MM QUARTERLY HIGHLIGHTS  Announced acquisition of significant bolt-on acreage in Delaware Basin with meaningful near-term value contribution  8% sequential reduction in LOE  Operational efficiencies driving more wells PoP during Q2 with operational capex lower than estimated  1 st Mega-pad online with wells performing favorably against offset three-well pads  Multiple new Wolfcamp wells online at Spur, including first WC C test well  Recent Fairway wells outperforming type curves early time  Executed Firm Transportation agreement to 85,000+ PRO FORMA NET ACRES move 15,000 barrels per day to Gulf Coast 1. LOE figures are calculated on a two-stream basis. 3

CPE Industry Leading Margins Continue to Improve MARGIN EXPANSION COST IMPROVEMENTS DRIVING OPERATING RETURNS Cash margin growth illustrates $60 35% operational efficiencies $50 Cash Costs/Revenue  Per unit cash operating costs (1) declined 10% 30% $40 sequentially $/Boe  Overall cash operating costs as a percent of $30 25% unhedged revenue declined to 20% in 2Q’18 $20 from 33% in 4Q’16 20% $10 Industry leading operating margins $0 15%  2Q’18 Adj. EBITDA(X)/ Boe expanded to 4Q'16 1Q'17 2Q'17 3Q'17 4Q'17 1Q'18 2Q'18 $38.95/Boe (2) , representing 17% margin CAGR over the last 2 years Unhedged Realized Price Cash Margin Cash Costs/Revenue  CPE continues to exhibit one of the highest CAPITAL EFFICIENT PRODUCTION GROWTH WITH SUPERIOR MARGINS (3) cash operating margins across 60+ E&Ps $40 CPE Integration of XEC assets will $35 further margin expansion trajectory 1Q'18 EBITDA(X) Adjusted/ Boe  Immediate low cost cash flow stream from $30 producing wells $25  Improved scalability enhances optionality for $20 multi-well pad development  Accelerates timing of FCF $15 $10 $5 $0 -40% -30% -20% -10% 0% 10% 20% 30% 40% 50% 60% 70% 80% Historical 3 Year Production CAGR 1. Cash operating costs include Lease Operating Expenses, Production Taxes, and Cash G&A. 2. Based on CPE calculated Adjusted EBITDA(X). 4 3. Based on standardized Bloomberg calculations for Adjusted EBITDA(X).

Operational Execution DEVELOPMENT ON TARGET 1H18 OPERATIONAL CAPITAL ($MM) 1H18 NET WELLS PoP (1) 14 net wells placed on production during Q2, bringing 50 $600 1H18 total to 23 45 8 net wells PoP in June, $525 combined with Monarch area mega-pad in July, provide 40 strong momentum into Q3 $450 Capital expenditures tracking 35 on budget with additional 2H18 benefits expected from: $375 30  Increased local sand usage 54% of 52% of  Ramp-up of recycling efforts 2018 Midpoint 2018 Midpoint $300 25  Supply chain initiatives  Reduced infrastructure spending in Q3 and Q4 20 $225 To date in the reporting cycle, oil-levered E&P 2Q capital 15 expenditures have been 12% $150 above consensus estimates on 10 average (2) $75 5 $0 0 2018 2018 1Q 2Q 1Q 2Q Guidance Guidance 1. Placed on production during the quarter. 2. Based on Bloomberg consensus estimates vs. reported capital expenditures from property additions. 5

Production Growth Drivers HIGHLIGHTS INCREASED PAD DEVELOPMENT (1) Weather 50% PoP in last Evolution to larger pad 60,000 impact 5 days of July 32.0 concepts Net Production (Boepd) 50,000 30.0 Net Lateral Feet PoP  Mitigate offset frac impacts 40,000 28.0  Multi-zone development where lack 30,000 26.0 of natural barriers  Simultaneous operation of two 20,000 24.0 drilling rigs followed by two 10,000 22.0 completion crews preserves short cycle times 0 20.0 January February March April May June July  ~160,000 net lateral feet PoP in 1H18 (~60K in June alone) Daily Production Lateral Feet PoP Delaware Basin underpins RAPIDLY EMERGING DELAWARE PRODUCTION CONTRIBUTION robust production growth 100% outlook  Prolific well results with 80% improvements over initial vintages  Reduced cycle times and move to 60% multi-well pad development breed cost savings 40%  Infrastructure build-out removes impediments to growth 20%  Pending acquisition impact bolsters future production profile 0% January February March April May June July Delaware Midland 1. Placed on production during the quarter. 6