4th QUARTER 2018 EARNINGS February 26, 2019

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 2019 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 and other risks more fully discussed in our filings with the Securities and Exchange Commission, including our Annual Reports on Form 10-K and 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, Discretionary Cash Flow, PV-10, Net Debt to LTM Adjusted EBITDA and other measures identified as non- GAAP. Management also uses EBITDAX, which reflects EBITDA plus exploration and abandonment expense. Reconciliations are available in the Appendix. 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, exploration expense, (gains) losses on derivative instruments excluding net settled derivative instruments, impairment of oil and natural gas properties, non-cash equity based compensation, other income, gains and losses from the sale of assets and other non-cash operating items. 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 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 Operating 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. We believe 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 the Company 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. The Company 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 cashflow effect may not be reflected 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 Year-end pre-tax PV-10 value is a non-GAAP financial measure as defined by the SEC. The Company 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. Net Debt to Last Twelve Months (“LTM)” Adjusted EBITDA is a non-GAAP measure. The Company defines Net Debt to LTM Adjusted EBITDA as the sum of total long-term debt less unrestricted cash and cash equivalents (as determined under U.S. GAAP), divided by the Company’s Adjusted EBITDA inclusive of annualized pro-forma results from its acquisitions completed over the last twelve month period. The Company presents this metric to help evaluate its capital structure, financial leverage, and forward-looking cash profile. The Company believes that Net Debt to LTM Adjusted EBITDA is widely used by industry professionals, research and credit analysts, and lending and rating agencies in the evaluation of total leverage.

FOUNDATIONAL SUCCESS IN 2018 SOLID EXECUTION OF PLAN 2018 2018 . Production at top of range GUIDANCE ACTUALS . Total production: 32.9 Mboepd Total production (MBoepd) 31.5 – 33.0 32.9 . Oil production of 25.9 MBopd Oil production 24.5 (76%) 25.9 (79%) . Operating Revenue: $587.6 MM Income statement expenses (per Boe) . Adjusted EBITDA (1): $432.5 MM . Operating margin (2): $40.16 / Boe LOE, including workovers $5.00 - $6.00 $5.76 . DCFPS (3): $1.96 Production taxes, including ad valorem 7% 6% (% of unhedged revenues) 2018 HIGHLIGHTS Adjusted G&A: cash component (4) $1.75 - $2.50 $2.35 . Expanded Delaware Basin position by over 30,000 net surface acres Adjusted G&A: non-cash component (5) $0.50 - $1.00 $0.55 . Increased total proved and proved developed reserves by 74% and 86%, Cash interest expense (6) $0.00 $0.00 respectively Net operated horizontal wells placed on 50 - 52 54 . Achieved industry leading operating production margins Capital expenditures ($MM, accrual basis) . Successfully shifted to large scale pad development across the asset base Total operational capital excluding $560 $583 while simultaneously managing drilling capitalized expenses (7) obligations Capitalized expenses $75 - $85 $84 . Initiated program of asset rationalization and optimization 1. Based on CPE calculated Adjusted EBITDA, a non-GAAP financial measure. Please see the Non-GAAP reconciliation disclosures in the Appendix. 2. Based on unhedged revenue less LOE and production taxes on a Boe basis. 3. Based on CPE calculated Discretionary Cash Flow per Diluted Share, a non-GAAP financial measure. Please see the Non-GAAP reconciliation disclosures in the Appendix. 4. Excludes stock-based compensation and corporate depreciation and amortization. Based on CPE calculated Adjusted G&A, a non-GAAP financial measure – please see reconciliation disclosures in the Appendix. 3 5. Excludes certain non-recurring expenses and non-cash valuation adjustments. Based on CPE calculated Adjusted G&A, a non-GAAP financial measure – please see reconciliation disclosures in the Appendix. 6. All cash interest expense anticipated to be capitalized. 7. Includes drilling, completions, facilities, seismic, land and other items. Excludes capitalized expenses.

CALLON’S PERMIAN EVOLUTION 2014: INITIAL BUILDING PHASE 2019: TRANSITION TO FULL ASSET DEVELOPMENT ~ 19,000 net surface acres (1) ~ 85,000 net surface acres ~ 5,650 Boe/d of production (2014) Forecast production growth of ~25% 2 rigs running 4-6 rigs and 1-2 completion crews 27 net wells completed Estimated 47- 49 net wells PoP YE13: 15 MMBoe Proved Reserves YE18: 239 MMBoe Proved Reserves PROVED DEVELOPED GROWTH DRIVES VALUE (2) DEVELOPMENT CAPITAL ALIGNED WITH CASH FLOW (3) (4) 140 $2.5 150 45 ~ 65% RESERVE CAGR ADJ. EBITDA (3) > D&C Avg. 120 ~ 50% PD PV-10 CAGR ~ 80% PRODUCTION CAGR productiondaily $2.0 100 PV PD 100 30 $1.5 - 80 (Billion) 10 $MM ( 60 Mboepd $1.0 50 15 Reserves Reserves (MMBoe) 40 ) $0.5 20 0 $0.0 0 0 2014 2015 2016 2017 2018 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 PD PUD PD PV-10 Adjusted EBITDA D&C Capital Production 1. Excluding Northern Midland Basin exploration properties. 2. PD PV-10 is a non-GAAP financial measure: The 12-month average benchmark pricing used to estimate proved reserves in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (“SEC”) and pre-tax PV-10 value for crude oil and natural gas was $65.56 per Bbl of WTI crude oil and $3.10 per MMBtu of natural gas at Henry Hub before differential adjustments. After differential adjustments, the Company’s SEC pricing realizations for year-end 2018 were $58.40 per Bbl of oil and $3.64 per Mcf of natural gas. Please refer to the Non-GAAP Disclosure at the beginning of this release for information regarding pre-tax PV-10. 4 3. Based on CPE calculated Adjusted EBITDA and Adjusted Total Revenues, non-GAAP financial measures. Please see the Non-GAAP reconciliation disclosures in the Appendix. 4. D&C capital excludes facilities spend.

PRESERVATION OF INDUSTRY LEADING MARGINS MARGIN EXPANSION MARGIN PRESERVATION ACROSS COMMODITY CYCLES (1)(2) . Industry leading operating margins $75 150% . 125% Adj. EBITDA/Revenue Cash margin of $31.82/Boe represents Boe an 8% CAGR over the last two years $50 100% . Cash G&A of $2.03/Boe declined ~ 6% sequentially 75% . Adj. EBITDA(2) of $119.7MM $25 50% representing +1% sequential margin improvement as the unhedged realized 25% sales price declined 15% Q/Q Price$/ RealizedSales $0 0% . Acreage quality and operational 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 excellence Unhedged Realized Price ($/Boe) Cash Margin Adj. EBITDA/Revenue . 4Q’18 Adj. EBITDA/Revenue expanded CAPITAL EFFICIENT PRODUCTION GROWTH WITH SUPERIOR MARGINS (3) to 74% (2) CPE: SUPERIOR OPERATING MARGIN . In 2018, CPE achieved the highest $40 Bloomberg standardized Adj. $35 EBITDA(X)/Boe operating margin (3)(4) across publicly traded E&Ps $30 . Future cost improvements $25 . Reduced drilling days, increased local $20 sand usage, and more stages per day $15 . Adaptive completion designs . Increased water recycling $10 . Optimization of acquired properties Boe EBITDA(X) / AdjustedYTD 18 $5 . Preferred vendor concession $0 consolidation -40% -30% -20% -10% 0% 10% 20% 30% 40% 50% 60% 70% 80% Historical 3 Year Production CAGR 1. Cash margin is defined as operating revenue minus cash operating costs including Lease Operating Expenses, Production Taxes, and Cash G&A. 2. Based on CPE calculated Adjusted EBITDA, a non-GAAP financial measure. Please see the Non-GAAP reconciliation disclosures in the Appendix. 3. Based on standardized Bloomberg calculations for Adjusted EBITDA(X) for over 55 publicly traded E&Ps. Adjusted EBITDA(X) is a non-GAAP financial measure. Please see the Non-GAAP reconciliation disclosures in the 5 Appendix. 4. As of 2/25/19; 4Q18 consensus averages were utilized for companies yet to report financials.

BROAD “SCALE” INITIATIVES ACROSS THE BASIN SECURING LONG-TERM VALUE CREATION Field optimization and infrastructure WC A and LSBY investments are driving down operating costs co-development and increasing productivity Full section Successful integration of new core assets Strategic recycling and development on overlaying legacy Spur footprint with sourcing agreements 10-well spacing increased development pace Positive 10-well spacing pilot Advancing multi-interval development Mega-Pad success program to enhance long-term recovery and overall resource management WC A/B pairs and MSBY/LSBY tests CPE recycling facilities New strategic water management agreements combined with growing recycling program New Ellenburger SWD increase reliability, reduce capital needs, and mitigate environmental impact Disposal volumes to CBP Testing 2nd BS Testing of new intervals and enhanced WC A/WC B pairs completion concepts unlocking additional Multi-interval concepts value and organic inventory upside 6

OPTIMIZING THE FOOTPRINT ACTIVELY IMPROVING OUR NET ACRE VALUE . Infill acreage additions . Acquired 3,158 net acres within/contiguous to Spur footprint in 2H18 . 100% HBP; ~77% NRI . Enhance scaled program development . Leasehold activity . Trades: ~ 4,325 net acres HOWARD . Leasing and additions: ~ 3,100 net acres MIDLAND . Mineral rights . Acquired over 1,600 net mineral acres across core development areas . Highly accretive with near-term planned development . Increasing asset rationalization WARD . Non-core asset sales and continued trade activity expected through 2019 . 3,540 net acres divested in 2018 REAGAN Callon Acreage Infill Acreage and WI additions Acreage Trade Activity and Mineral Purchases 7

RECENT OPERATIONAL HIGHLIGHTS 4Q18 HIGHLIGHTS DELAWARE DRILLING DAYS SIGNIFICANTLY IMPROVED . Quarterly production: 41.1 Mboed (81% oil) . 55% growth YoY . Production achieved while gas plant volumes remained offline . Delaware: completed first WCA well utilizing 100% in-basin CYCLE TIMES IMPROVED sand resulting in cost savings of $45,000 per 1,000’ MEASURABLY AND CONSISTENTLY . WildHorse multi-well WC A pad with 10 well per section spacing performing above expectations . Monarch: multi-interval, co-development pilots delineating stacked pay potential COMPLETION STAGES PER DAY CONTINUE TO INCREASE SUBSTANTIAL EFFICIENCY GAIN FROM SINGLE WELL TO PAD TRANSITION (feet) Depth Measured Less Days = Less $ Reduced Rig Days 0 10 20 30 40 50 Days 2017 2018 2017 2018 Single well average Multi-well average Vintage 1 Vintage 2 Vintage 3 8

CONSISTENTLY IMPROVING WELL PERFORMANCE DELAWARE WELLS PoP AVG. CUM OIL PRODUCTION (1) MIDLAND WELLS PoP AVG. CUM OIL PRODUCTION (1) 160 250 ~ 25% ~ 15% 4Q18 AVERAGE WELL 4Q18 AVERAGE WELL OUTPERFORMANCE VS. 2018 OUTPERFORMANCE VS. 2018 AVERAGE WELL AFTER 3 140 AVERAGE WELL AFTER 3 MONTHS MONTHS 200 120 100 150 80 100 60 40 50 Average Well Cum Oil Production (MBo) Normalized to 10,000' to Normalized (MBo) Production Oil Cum WellAverage Average Well Cum Oil Production (MBo) Normalized to 10,000' to Normalized (MBo) Production Oil Cum WellAverage 20 0 0 1 24 47 70 93 116 139 162 185 208 231 254 277 300 1 175 Days on production Days on production 2016 2017 2018 4Q18 2017 2018 3Q18 4Q18 1. 2018 inclusive of production data from all wells PoP. 9

CO-DEVELOPMENT EXCEEDING PRIOR VINTAGES CAPITAL DEPLOYMENT FOR ASSET OPTIMIZATION MULTI-INTERVAL: MIDLAND CO-DEVELOP MSB/ULSB/LLSB 140 . Average well performance per pad exceeding risked expectations as increase co-development 120 Multi-Interval Mega-Pads Ramping Up . 100 with Infill LSBY Targets Middle Spraberry interval de-risking as part of recent Outperforming Prior Pads Mega-Pad test 80 . New interval testing with larger pads (ex: Middle 60 nd Spraberry and 2 Bone Shale) Normalized 10,000' 40 . Repeatable multi-interval A/B program in Monarch 20 Average Average CumWell Production Oil (Mbo) . D&C cost savings for multi-well development driving 0 1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161 171 efficient capital allocation 2015 Kendra Amanda 29LL 30UL 2019 Kendra Amanda 28LL 31UL 32LL 28MS 2016 Kendra Kristen 23UL, 24LL, 25UL 2019 Kendra Kristen 26LL 27UL 2017 Kendra PSA 209UL, 208LL, 210LL MULTI-WELL: DELAWARE WCA TESTS MULTI-INTERVAL: MIDLAND CO-DEVELOP WCA/WCB 200 60 180 4Q18/1Q19 Multi-Well Projects 3 Well Pad (1 WCA and 2 WCB) Matching or Exceeding Best 160 Demonstrating Consistent WCA/WCB Wells to Date 50 140 Performance 30 day cum oil per well 120 ~52,000 Bo 40 100 30 80 Normalized Normalized 7,500' 60 20 (Normalized (Normalized 5,000') 40 30 day cum oil per well ~36,000 Bo 20 10 Average Average CumWell Production Oil (Mbo) 0 Average Pad CumProduction Oil MBo 1 8 15 22 29 36 43 50 57 64 71 78 85 0 1 9 17 25 33 41 49 57 65 73 81 89 97 2Q18 Rendezvous A1 LA A2 UA 4Q18 Teewinot A1 LA A2 LA 2018 Casselman 40 14H 21AH 2019 Casselman 40 19H 20H 26AH 1Q19 Wally World A1 LA A2 LA 10

2019 OPERATIONAL PROGRAM 2019 DEVELOPMENT PROGRAM LARGE DELAWARE PROJECTS SET UP STRONG ENTRY INTO 2020 . 2019 current efficiency objectives 160 . ~ 25% production growth on reduced 140 capex (YoY) (M) 120 . 15% decline in D&C/1,000’ (YoY) PoP 100 . Operating cost reductions with larger Feet 80 scale development 60 . Lateral 2019 future valuation creation 40 objectives Net 20 . Increase capital allocation in the 0 Delaware to maximize resource capture 1Q19 2Q19 3Q19 4Q19 . Mitigate parent-child impact in Midland Midland Delaware co-development program (2) . Apply appropriate risking parameters CONSISTENT PROFILE OF GROWTH FOR THE FORESEEABLE FUTURE throughout planning process 50 . Foundation of maturing PDP 45 40 . 2019 PDP decline rate upper 30% (1) 35 . Projected 2020 decline rate lower by ~5% 30 . Transition to 2020 25 Mboepd . FCF generation and 15%+ growth at 20 $52.50/Bbl WTI ($62.50 Brent) and 15 $2.75/mmbtu 10 . Maintain operational capex below 2018 5 levels - . Determine cash return priorities 2014 2015 2016 2017 2018 2019 2020 1) On a percentage basis. Based upon January 2019 production rate to projected January 2020 rate. 2) Production range estimate for 2019 represents incremental growth including the top end of current guidance for estimated daily production rates. 2020 figures assume 15% growth from the range provided for 2019. 11

INFLECTION POINT OF DEVELOPMENT PROGRAM LARGER PAD DEVELOPMENT DRIVING CAPITAL EFFICIENCY . Increased opportunity for longer laterals as a result of blocking up acreage and executing quality trades . Improvements to operational efficiency drive cost reductions on a lateral foot basis . Consistently lower development costs across the portfolio without assumed service cost deflation 22% NET LATERAL FOOTAGE PER 13% OPERATIONAL CAPITAL 6% NET LATERAL FEET $1 MM OF OPERATIONAL CAPEX $600 400 800 $500 300 600 PoP $400 200 400 $MM / $1MM of Operational Capex Operational of $1MM / PoP Net Lateral Feet Lateral Net $300 100 200 Net Lateral Feet Lateral Net $200 0 0 2018 2019 2018 2019 2018 2019 12

2019 OUTLOOK ALIGNING CASH FLOW PROGRAM SUMMARY SUBSTANTIAL INCREASE IN AVERAGE PROJECT SIZE 30 . Increased pad sizes while preserving cash cycle times 2 FRAC CREWS 25 . Reductions in HBP wells drive enhanced operational 20 flexibility 15 10 . “Bang for our D&C buck” improved by operational cost POP WellsGross 5 savings from scaled development 0 1-Well 2-Well 3-Well 4-Well 5-Well 6-Well 7-Well 2018 2019 FLEXIBILITY: REDUCED HBP AND FACILITIES SPEND HARVESTING VALUE: ADJ. EBITDA > D&C CAPITAL(1)(2) 80% HBP OBLIGATIONS: 30% 600% 2018: ~ 50% 2019: ~ 25% 70% 25% Facilities % of Operational Capital 500% 60% 20% 400% 50% 40% 15% 300% 30% % HBP Wells PoP WellsHBP % 10% 200% 20% 5% 100% 10% 0% 0% 0% 1H17 2H17 1H18 2H18 FY19E 2016 2017 2018 2019E 2020E % HBP Wells PoP Facilities / Operational Capital Adj. EBITDA(X) D&C Capital 1. Based on $50/Bbl oil and $2.75/Mcf commodity price assumption. 2. Based on CPE calculated Adjusted EBITDA, a non-GAAP financial measure. Please see the Non-GAAP reconciliation disclosures in the Appendix. 13

FINANCIAL POSITIONING (1) HIGHLIGHTS CAPITALIZATION ($MM) . Progressing toward free cash flow generation from field 4Q18 level to corporate-level with 4Q19 target at $50/Bbl (2) Cash $16 . Focused on reducing leverage to meet long-term Credit Facility $200 targets, < 2.0x Net Debt (3) / Adjusted EBITDA(X) Senior Notes due 2024 600 . Strong liquidity position that is supported by a Revolving Senior Notes due 2026 400 Credit Facility that has an elected commitment amount of $850MM under a $1.1Bn borrowing base Total Debt $1,200 . Flexible capital structure given no near-term debt Stockholders’ Equity 2,445 maturities Total Capitalization $3,645 Total Liquidity (1) $648 Net Debt to FY2018 Adjusted EBITDA (3)(4) 2.4x DEBT MATURITY SUMMARY ($MM) $1,200 $1,000 $1.1BN Borrowing $600MM No Near-term Base Senior Notes $800 $400MM Maturities Senior Notes $600 $850MM Elected $400 Commitment $200 $0 2018 2019 2020 2021 2022 2023 2024 2025 2026 1. Based on current elected commitment amount. All figures are as of 12/31/18 and reflect certain items, such as letters of credit, not specifically shown in the capitalization table. 2. WTI benchmark pricing. Assumes Henry Hub benchmark pricing of $2.75/mmbtu. 3. Net debt is a non-GAAP financial measure. Please refer to the Appendix for reconciliation. 14 4. Net Debt to LTM Adjusted EBITDA is a non-GAAP measure and is calculated as the sum of total long-term debt less unrestricted cash and cash equivalents, divided by the Company’s Adjusted EBITDA inclusive of annualized pro-forma results from its acquisitions completed over the last twelve month period.

MARKETING AND RISK MANAGEMENT (1) PROTECTING CASH FLOW 2019 WTI INSTRUMENT OVERVIEW CURRENT 2020E PRICING POINTS . Total realized price focus covering both benchmark and basis . Midland oil basis differentials have narrowed as expected, with Mid-Cush trading at a premium to WTI recently . Will strategically align the hedge portfolio to match additional pricing points . Beginning to layer into 2020 positions 3 Way Collars Put Options Put Spreads Midland WTI Gulf Coast Brent/Waterborne ENHANCING RETURNS WTI HEDGE VOLUME WITH WEIGHTED AVERAGE CEILING AND FLOOR PRICE (2) . New marketing agreements will 1.7 $70 Average WTI AverageWTI Price increase exposure to MEH, Brent, and ) $68 waterborne pricing starting 4Q19 MMbo 1.6 $66 . 4Q19 Gray Oak: 15 Mb/d gross FT $64 matched with a combination of MEH and Brent contracts 1.6 $62 Ceiling/Floor ($/ $60 . Incremental 10 Mb/d gross sales at waterborne pricing starting 1/1/20 1.5 $58 Bbl . $56 ) Evaluating additional physical ( Volumes Hedge WTINYMEX 1.4 $54 marketing and FT contracts to diversify 1Q19 2Q19 3Q19 4Q19 price exposure Ceiling Floor WTI Hedge Volumes 1. Hedge contracts as of 2/22/19. 2. Ceiling prices reflected are only applicable to 3-way collars. Puts and put spreads are uncapped with upside potential for rising prices. 15

2019 OUTLOOK GUIDANCE TAKEAWAYS FY’19 . Program designed to maximize efficiency in GUIDANCE continued shift to large pad development Total production (MBoepd) 39.5 – 41.5 . Emergence of large pad Delaware impact in 2H19 drives strong transition in 1Q20 Oil production 77% - 78% . Appropriately risking for start-up of multi- interval and co-development projects Income statement expenses (per BOE) LOE, including workovers $5.50 - $6.50 LONGER LATERALS WITH LESS CAPITAL Production taxes, including ad valorem 7% 350 (% of unhedged revenues) (1) 300 Adjusted G&A: cash component $2.00 - $2.50 Adjusted G&A: non-cash component (2) $0.50 - $1.00 250 Cash interest expense (3) $0.00 200 Statutory income tax rate 22% 150 Capital expenditures ($MM, accrual basis) 100 Total operational capital (4) $500 - $525 50 Total capitalized expenses (including interest) (3) $100 - $105 0 1H18 2H18 1H19 2H19 Net operated horizontal wells placed on production 47 - 49 Operational Capital ($MM) Net Lateral Feet (M) 1. Excludes stock-based compensation and corporate depreciation and amortization. Based on CPE calculated Adjusted G&A, a non-GAAP financial measure – please see reconciliation disclosures in the Appendix. 2. Excludes certain non-recurring expenses and non-cash valuation adjustments. Based on CPE calculated Adjusted G&A, a non-GAAP financial measure – please see reconciliation disclosures in the Appendix. 3. All cash interest expense anticipated to be capitalized at estimated weighted average of 6%. 16 4. Includes drilling, completions, facilities, seismic, land and other items. Excludes capitalized expenses.

APPENDIX

OIL HEDGE PORTFOLIO (1) 1Q19 2Q19 3Q19 4Q19 1H19 2H19 2019 1Q20 2Q20 3Q20 4Q20 1H20 2H20 2020 NYMEX WTI (Bbl, $/Bbl) Three-w ay Collars Total Volumes 1,080,000 1,092,000 1,196,000 1,196,000 2,172,000 2,392,000 4,564,000 - - - - - - - Total Daily Volumes 12,000 12,000 13,000 13,000 12,000 13,000 12,504 - - - - - - - Avg. Short Call Price $67.78 $67.78 $67.46 $67.46 $67.78 $67.46 $67.62 - - - - - - - Avg. Long Put Price $56.67 $56.67 $56.54 $56.54 $56.67 $56.54 $56.60 - - - - - - - Avg. Short Put Price $43.54 $43.54 $43.65 $43.65 $43.54 $43.65 $43.60 - - - - - - - Avg. Premium Price ($0.10) ($0.10) ($0.09) ($0.09) ($0.10) ($0.09) ($0.09) - - - - - - - Tw o-w ay Collars Total Volumes - - - - - - - 182,000 182,000 184,000 184,000 364,000 368,000 732,000 Total Daily Volumes - - - - - - - 2,000 2,000 2,000 2,000 2,000 2,000 2,000 Avg. Short Call - - - - - - - $64.63 $64.63 $64.63 $64.63 $64.63 $64.63 $64.63 Avg. Put - - - - - - - $55.00 $55.00 $55.00 $55.00 $55.00 $55.00 $55.00 Avg. Premium Price - - - - - - - $2.00 $2.00 $2.00 $2.00 $2.00 $2.00 $2.00 Put Options Total Volumes 225,000 227,500 230,000 230,000 452,500 460,000 912,500 - - - - - - - Total Daily Volumes 2,500 2,500 2,500 2,500 2,500 2,500 2,500 - - - - - - - Avg. Long Put Price $65.00 $65.00 $65.00 $65.00 $65.00 $65.00 $65.00 - - - - - - - Avg. Premium Price $6.44 $6.44 $6.44 $6.44 $6.44 $6.44 $6.44 - - - - - - - Put Spreads Total Volumes 225,000 227,500 230,000 230,000 452,500 460,000 912,500 - - - - - - - Total Daily Volumes 2,500 2,500 2,500 2,500 2,500 2,500 2,500 - - - - - - - Avg. Long Put Price $65.00 $65.00 $65.00 $65.00 $65.00 $65.00 $65.00 - - - - - - - Avg. Short Put Price $42.50 $42.50 $42.50 $42.50 $42.50 $42.50 $42.50 - - - - - - - Avg. Premium Price $4.39 $4.39 $4.39 $4.39 $4.39 $4.39 $4.39 - - - - - - - Total Volume Hedged (Bbl) 1,530,000 1,547,000 1,656,000 1,656,000 3,077,000 3,312,000 6,389,000 182,000 182,000 184,000 184,000 364,000 368,000 732,000 Average Ceiling Price ($/Bbl) $67.78 $67.78 $67.46 $67.46 $67.78 $67.46 $67.62 $64.63 $64.63 $64.63 $64.63 $64.63 $64.63 $64.63 Average Floor Price ($/Bbl) $59.12 $59.12 $58.89 $58.89 $59.12 $58.89 $59.00 $55.00 $55.00 $55.00 $55.00 $55.00 $55.00 $55.00 MIDLAND-CUSHING DIFFERENTIAL (Bbls/$/Bbl) Sw aps Total Volumes 1,634,000 1,683,500 1,748,000 1,670,500 3,317,500 3,418,500 6,736,000 1,092,000 1,092,000 1,196,000 1,196,000 2,184,000 2,392,000 4,576,000 Total Daily Volumes 18,156 18,500 19,000 18,158 18,329 18,579 18,455 12,000 12,000 13,000 13,000 12,000 13,000 12,503 Avg. Sw ap Price ($5.59) ($5.51) ($3.13) ($3.22) ($5.55) ($3.18) ($4.34) ($1.73) ($1.73) ($0.89) ($0.89) ($1.73) ($0.89) ($1.29) 1. Hedge contracts as of 2/22/19. 18

GAS HEDGE PORTFOLIO (1) 1Q19 2Q19 3Q19 4Q19 1H19 2H19 2019 1Q20 2Q20 3Q20 4Q20 1H20 2H20 2020 NYMEX Henry Hub (MMBtu, $/MMBtu) Swaps Total Volumes - 455,000 1,242,000 155,000 455,000 1,397,000 1,852,000 - - - - - - - Total Daily Volumes - 5,000 13,500 1,685 2,514 7,592 5,074 - - - - - - - Avg. Sw ap Price - $2.87 $2.89 $2.87 $2.87 $2.89 $2.88 - - - - - - - Two-way Collars Total Volumes 2,525,000 1,501,500 598,000 598,000 4,026,500 1,196,000 5,222,500 - - - - - - - Total Daily Volumes 28,056 16,500 6,500 6,500 22,246 6,500 14,308 - - - - - - - Avg. Short Call Price $3.63 $3.82 $3.50 $3.50 $3.70 $3.50 $3.65 - - - - - - - Avg. Put Price $2.97 $3.06 $3.13 $3.13 $3.00 $3.13 $3.03 - - - - - - - Total Volume Hedged (MMBtu) 2,525,000 1,956,500 1,840,000 753,000 4,481,500 2,593,000 7,074,500 - - - - - - - Average Ceiling Price ($/MMBtu) $3.63 $3.60 $3.09 $3.37 $3.62 $3.17 $3.45 - - - - - - - Average Floor Price ($/MMBtu) $2.97 $3.02 $2.97 $3.07 $2.99 $3.00 $2.99 - - - - - - - WAHA DIFFERENTIAL (MMBtu, $/MMBtu) Swaps Total Volumes 2,300,000 1,729,000 2,116,000 2,116,000 4,029,000 4,232,000 8,261,000 1,183,000 1,183,000 1,196,000 1,196,000 2,366,000 2,392,000 4,758,000 Total Daily Volumes 25,556 19,000 23,000 23,000 22,260 23,000 22,633 13,000 13,000 13,000 13,000 13,000 13,000 13,000 Avg. Sw ap Price ($1.24) ($1.22) ($1.18) ($1.18) ($1.24) ($1.18) ($1.21) ($1.12) ($1.12) ($1.12) ($1.12) ($1.12) ($1.12) ($1.12) 1. Hedge contracts as of 2/22/19. 19

QUARTERLY CASH FLOW STATEMENT 4Q17 1Q18 2Q18 3Q18 4Q18 Cash flows from operating activities: Net income (loss) $ 22,824 $ 55,761 $ 50,474 $ 37,931 $ 156,194 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 37,222 36,066 39,387 48,977 60,301 Accretion expense 154 218 206 202 248 Amortization of non-cash debt related items 455 453 588 708 734 Deferred income tax (benefit) expense 247 495 481 1,487 5,647 (Gain) loss on derivatives, net of settlements 26,037 (3,978) 8,572 25,100 (105,512) (Gain) loss on sale of other property and equipment — — 22 (102) (64) Non-cash expense related to equity share-based awards 1,240 1,131 1,627 1,708 1,823 Change in the fair value of liability share-based awards 865 1,012 (463) 879 (1,053) Payments to settle asset retirement obligations (216) (366) (207) (507) (389) Payments for cash-settled restricted stock unit awards — (3,089) (1,901) — — Changes in current assets and liabilities: Accounts receivable (32,347) (8,067) 10,447 (56,764) 37,033 Other current assets 444 61 (5,611) 3,885 (5,936) Current liabilities 23,413 12,938 4,123 47,741 9,510 Other long-term liabilities — 87 200 5,500 (6,065) Other assets, net (152) (507) (181) (709) (832) Net cash provided by operating activities 80,186 92,215 107,764 116,036 151,639 Cash flows from investing activities: Capital expenditures (152,621) (111,330) (187,040) (156,982) (155,821) Acquisitions (3,952) (38,923) (6,469) (550,592) (122,809) Acquisition deposit (900) 900 (28,500) 27,600 — Proceeds from sales of assets 20,525 — 3,077 5,249 683 Additions to other assets — — — — (3,100) Net cash used in investing activities (136,948) (149,353) (218,932) (674,725) (281,047) Cash flows from financing activities: Borrowings on senior secured revolving credit facility 25,000 80,000 85,000 105,000 230,000 Payments on senior secured revolving credit facility — (30,000) (160,000) (40,000) (95,000) Issuance of 6.375% senior unsecured notes due 2026 — — 400,000 — — Payment of deferred financing costs (28) — (8,664) (1,296) 530 Issuance of common stock — — 288,357 7 (376) Payment of preferred stock dividends (1,824) (1,824) (1,824) (1,823) (1,824) Tax withholdings related to restricted stock units — (560) (1,028) (216) — Net cash provided by financing activities 23,148 47,616 601,841 61,672 133,330 Net change in cash and cash equivalents (33,614) (9,522) 490,673 (497,017) 3,922 Balance, beginning of period 61,609 27,995 18,473 509,146 12,129 Balance, end of period $ 27,995 $ 18,473 $ 509,146 $ 12,129 $ 16,051 20

NON-GAAP RECONCILIATION (1) Adjusted EBITDA Reconciliation 4Q17 1Q18 2Q18 3Q18 4Q18 Net income $ 22,824 $ 55,761 $ 50,474 $ 37,931 $ 156,194 Adjustments: Net (gain) loss on derivatives, net of settlements 26,037 (3,978) 8,572 25,100 (105,512) Non-cash stock-based compensation expense 2,101 2,143 1,164 2,587 770 Acquisition expense (112) 548 1,767 1,435 1,333 Income tax expense 248 495 481 1,487 5,647 Interest expense 461 460 594 711 735 Depreciation, depletion and amortization 37,222 36,066 39,387 48,977 60,301 Accretion expense 154 218 206 202 248 Adjusted EBITDA $ 88,935 $ 91,713 $ 102,645 $ 118,430 $ 119,716 Net Debt to LTM Adjusted EBITDA 2018 Senior secured revolving credit facility $ 200,000 6.125% senior unsecured notes due 2024 600,000 6.375% senior unsecured notes due 2026 400,000 Total principal outstanding 1,200,000 LESS: Unrestricted cash (16,100) Net Debt 1,183,900 Adjusted EBITDA 432,504 Acquisitions - pro forma adjustments 54,325 LTM Adjusted EBITDA $ 486,829 LTM Net debt to Adjusted EBITDA 2.4 Adjusted G&A Reconciliation 4Q17 1Q18 2Q18 3Q18 4Q18 Total G&A expense $ 8,173 $ 8,769 $ 8,289 $ 9,721 $ 8,514 Less: Change in the fair value of liability share-based awards (non-cash) (844) (991) 484 (921) 1,069 Adjusted G&A – total 7,329 7,778 8,773 8,800 9,583 Less: Restricted stock share-based compensation (non-cash) (1,202) (1,105) (1,587) (1,730) (1,802) Less: Corporate depreciation & amortization (non-cash) (125) (124) (109) (102) (94) Adjusted G&A – cash component $ 6,002 $ 6,549 $ 7,077 $ 6,968 $ 7,687 1. See “Important Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures. 21

NON-GAAP RECONCILIATION (1) Adjusted Total Revenue Reconciliation 4Q17 1Q18 2Q18 3Q18 4Q18 Oil revenue $ 104,132 $ 115,286 $ 122,613 $ 142,601 $ 150,398 Natural gas revenue 14,081 12,154 14,462 18,613 11,497 Total revenue 118,213 127,440 137,075 161,214 161,895 Impact of cash-settled derivatives (4,501) (8,459) (7,980) (9,239) (1,594) Adjusted Total Revenue $ 113,712 $ 118,981 $ 129,095 $ 151,975 $ 160,301 Total Production (Mboe) 2,439 2,391 2,635 3,212 3,780 Adjusted Total Revenue per Boe $ 46.62 $ 49.76 $ 48.99 $ 47.31 $ 42.41 Discretionary Cash Flow Reconciliation 4Q17 1Q18 2Q18 3Q18 4Q18 Net cash provided by operating activities $ 80,186 $ 92,215 $ 107,764 $ 116,036 $ 151,639 Changes in working capital 8,642 (4,512) (8,978) 347 (33,710) Payments to settle asset retirement obligations 216 366 207 507 389 Payments for cash-settled restricted stock unit awards — 3,089 1,901 — — Discretionary cash flow $ 89,044 $ 91,158 $ 100,894 $ 116,890 $ 118,318 PV-10 Reconciliation 2014 2015 2016 2017 2018 Standardized measure of discounted future net cash flows $ 579,542 $ 570,890 $ 809,832 $ 1,556,682 $ 2,941,293 Add: 10 percent annual discount, net of income taxes 586,596 589,918 1,009,787 1,822,842 3,716,571 Add: future undiscounted income taxes 164,490 — 1,602 166,985 782,470 Undiscounted future net cash flows 1,330,628 1,160,808 1,821,221 3,546,509 7,440,334 Less: 10 percent annual discount without tax effect (700,948) (589,902) (1,011,389) (1,969,754) (4,291,127) Total Proved Reserves - Pre-tax PV-10 629,680 570,906 809,832 1,576,755 3,149,207 Total Proved Developed Reserves - Pre-tax PV-10 469,485 378,752 501,098 1,030,329 2,222,049 Total Proved Undeveloped Reserves - Pre-tax PV-10 $ 160,195 $ 192,154 $ 308,734 $ 546,426 $ 927,158 1. See “Important Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures. 22