FEBRUARY PRESENTATION FEBRUARY 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, 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 Income, Adjusted Income per diluted share, Adjusted G&A, PV-10 and other measures identified as non-GAAP. Management also uses EBITDAX, which reflects EBITDA plus exploration and abandonment 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, 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. Year-end pre-tax PV-10 value is a non-GAAP financial measure as defined by the SEC. 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 Company expects to include a full reconciliation of pre-tax PV-10 to the GAAP financial measure of Standardized Measure in its Earnings Press Release on Form 8-K for the fourth quarter 2018 financial and operating results, which it intends to file with the SEC on February 26, 2019.

EXECUTION REMAINS PRIORITY ONE THE EVOLUTION FROM CORE ASSETS TO A SUSTAINABLE OPERATING BUSINESS MODEL Core Permian Evolving to Full Field Sustainable Growth Footprint Established Development and FCF Generation 2014 - 2018 2019 2020 + . Increased Permian position from . Harvest asset value through . Sustainable double-digit organic ~19,000 to ~85,000 net acres in increasing pad development and growth funded with internally core areas cycle time reductions generated cash flow . Ramped activity from 2 to 5 rigs . Optimize margins and increase . Large pad development, and increased net lateral footage operational flexibility benefiting resource optimization drilled and long-term corporate level . Thoughtful capital allocation to returns . Built out robust infrastructure minimize outspend while growing network (>$200 mm invested) at a measured rate to augment . Leading cash margin preservation sustainable corporate return through cost management and . Increased credit facility from $250 model leveraging of existing million to $1.1 billion infrastructure . Balance longer term reinvestment . Expanded Callon skill sets with opportunities with near-term . Select asset rationalization significant investments in return profile opportunities to enhance returns employee base on capital . Selective activity to “block up” . Added cash flow per debt- acreage, extend laterals, and . Accelerate capital efficiency with adjusted share to compensation increase working and mineral balanced growth and maturing metrics interests decline profile 3

SOLID FOUNDATION OF PROVED RESERVE VALUE CONSERVATIVE AND CONSISTENT GROWTH TOP TIER RESERVE AND PRODUCTION GROWTH (2) . Total Proved PV-10 (1) value of $3.1 billion 300 35 . PD PV-10 (1) value of $2.2 billion Reserves CAGR: 66% . Oil accounts for > 75% of proved reserves 30 250 Production CAGR: 55% . PUD bookings consist of just over 200 locations . PD accounts for 54% of reserve volumes and 25 (1) Production DailyAverage 71% of PV-10 value 200 PD GROWTH DRIVING RESERVE VALUE ) $3.5 $100 20 MMBoe 150 $3.0 ( $80 (1) 15 $2.5 SEC SEC ( Reserves Mboepd $60 PV $2.0 100 - 10 Oil Oil 10 10 $1.5 ) $40 P rice $1.0 50 5 10 Value of Reserves 10 Value Reserves of ($B) - $20 PV $0.5 $0.0 $- 0 0 2015 2016 2017 2018 2014 2015 2016 2017 2018 PD PV-10 Value PUD PV-10 Value Reserves Oil Price PD PUD Production 1. 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 2. 4Q18 production based on current (2/7/19) “street” consensus.

2019 CAPITAL BUDGET GUIDANCE ANNUAL EXPENDITURE BUDGET ($MM) PRIMARY COMPONENTS . Budget based upon $50 oil / $2.75 natural gas with strip differentials from early January . Operational capital budget (D&C, facilities, & other) range between $500 - $525 million . Weighting is roughly 60% Delaware / 40% Midland inclusive of facilities capital . Operational capital deployment is projected to be relatively balanced between 1H19 and 2H19 . Potential “bolt-on” acquisitions to be funded with non-core divestitures 2019 ACTIVITY LEVELS $600 - $630 . Currently 6 rigs declining to 4 rigs at mid-year before entering 2020 with 5 rigs million . Currently 1 completion crew with intermittent addition of an additional crew for larger pad concepts . Estimated 47 to 49 net wells POP . Lower YoY net wells, but average net lateral length per net well increases by ~15% . Small DUC build for larger pad development . 1H19 Midland focus transitions to Delaware in 2H19 . (1) Sequential 1Q19 production decline followed by Drilling and Completions Facilities Other Capitalized G&A + Interest gradual increase to over 42.5 Mboepd in 4Q19 1. Assumes $50/Bbl WTI benchmark (flat). 5

2019 CAPITAL PROGRAM: SUSTAINABLE VALUE CREATION MANAGE CASH CONVERSION OF QUALITY INVENTORY HIGHIGHTING CAPITAL EFFICIENCY (YoY vs 2018) (1) . Capital expenditures actively managed across the 30% organization to optimize both well-level and corporate- level targets 20% . Development planning and well selection 10% . Prioritize multi-well pad development vs single-well pads . Establish DSUs which allow longer laterals and higher 0% NRI to efficiently access more acreage . Target multi-interval development for long-term returns -10% . Leverage utilization of existing facilities . Active supplier negotiations and D&C cost saving -20% Production Net Lateral Feet PoP Operational Capital initiatives . Completions contract in place for 2019 OPTIMIZE GROSS CAPITAL PER OPERATED LATERAL FT . Increase use of local sand . Integrate supply chain to reduce costs Midland Delaware . Increase water recycling and non-potable water sourcing . Reduce drilling days 2018 Gross D&C/1,000’ $1.1MM $1.4MM . Application of technology for long-term continuous improvement and NPV accretion 2019E Gross D&C/1,000’ $0.9MM $1.2MM . Completion and well spacing optimization . Enhanced subsurface knowledge and reservoir 2018 Avg Net Lateral 6,500’ 7,400’ characterization 2019E Avg Net Lateral 7,700’ 8,400’ 1. 2018 reference points based on current (2/7/19) “street” consensus. 2019 reference points based on midpoint of guidance. 6

DELAWARE: SUSTAINABLE INVESTMENT AND RETURN OPTIMAL DEVELOPMENT GOALS NET WELLS PoP BUILD INTO YE19 NET WELLS BY ZONE . Transition from single-well, HBP- driven activity to multi-pad concepts . Define well spacing assumptions early in single-interval and multi- interval inventory development . Benefit from existing infrastructure . Selectively test new intervals 2BS UWCA LWCA WCB 1Q19E 2Q19E 3Q19E 4Q19E SPUR OPERATING AREA . Larger pad concepts with multi-interval development of upper WCA, lower WCA, and WCB objectives . 2nd Bone Shale upside evaluation . Offset development of existing lower WCA well development . Continue co-development of the upper and lower WCA in mega-pad concept . Expand water recycling to eventually eliminate potable water sourcing . Field optimization projects underway to enhance 2019 Program operational reliability and safety Legacy Acreage Acquired Acreage 7

MIDLAND: BALANCED MULTI-INTERVAL DEVELOPMENT OPTIMAL DEVELOPMENT GOALS NET WELLS PoP FOCUSED IN 2Q/3Q NET WELLS BY ZONE . Leverage operational flexibility embedded in program given infrastructure investments and inventory depth . Advance multi-interval development concepts across areas . Increase average pad size for scalability and mitigation of timing effects MSBY LSBY WCA WCB 1Q19E 2Q19E 3Q19E 4Q19E MONARCH OPERATING AREA WILDHORSE OPERATING AREA . Co-development of . Focus on combined WCA/WCB WCA/LSBY pads . Continued program . Selective integration of development of upper/lower WCB in larger scale co- LSBY development pads . Test MSBY upside interval . Increase average net pad for future large pad drilling size . Increase water recycling . Leverage SWD network to efforts to reduce potable third-parties for further cost water sourcing reductions 2019 Program 2019 Program C CPE Acreage C CPE Acreage 8

DEVELOPMENT CAPITAL ALIGNED WITH CASH FLOW $150 45 Adjusted EBITDAX (1) exceeded D&C Capital for the last 3 years Avg $100 30 ( ProductionDaily $MM Mboepd ) $50 15 $0 0 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 (2) Adjusted EBITDAX (1) D&C Capital Facilities Capital Production 1. 1Q16-3Q18 based on CPE calculated Adjusted EBITDA(X), a non-GAAP financial measure. Please see the Appendix for additional reconciliation. 2. 4Q18 EBITDA, D&C capital, and production are based on Bloomberg consensus estimates as of 2/7/19. 9

QUALITY INVENTORY SCALABLE FOR LARGER PADS MIDLAND DELAWARE Net Acres ~ 39,500 ~ 45,200 DELAWARE WILDHORSE MONARCH RANGER Producing Flow Units 7 4 MSBY Gross Delineated Locations 940 1,210 LSBY Operated 820 580 Non-Operated 120 630 Upper Wtd. Avg. Lateral Length 8,100’ 8,600’ Lower Operated 7,800’ 8,900’ 2BS Non-Operated 9,600’ 8,400’ Delineated Lateral Feet ~ 18 Million WCA (Gross Operated) Upper 32 MM GROSS LATERAL FEET OF POTENTIAL RESOURCE 35 Lower 30 25 WCB 20 Upper 15 10 Lower Gross Lateral GrossLateral Feet (MM) 5 WCC 0 Delineated Testing WCC Delineated Spur Wildhorse Ranger Monarch 10

INCREMENTAL CAPITAL EFFICIENCY MULTI-WELL PROJECT DEVELOPMENT ACCELERATES INCREASING NET LATERAL LENGTH PER WELL 25 9,000 20 6,000 15 10 Gross Wells POP WellsGross 3,000 5 Average Net Lateral Length Completed Per Net WellNet CompletedPer LengthNetLateral Average 0 0 1-Well 2-Well 3-Well 4-Well 5-Well 6-Well 7-Well MONARCH SPUR WILDHORSE 2018 2019 2018 2019 2019 Average Project Size 2019 Average Net Lateral Increases 75% Feet Increases + 15% 11

COST LEADERSHIP IN SOUTHERN DELAWARE DRILLING SCALE AND EFFICIENCY GAINS LEADER IN SOUTHERN DELAWARE WELL COSTS (1) 100 60% Increase YoY 700 28% Increase YoY $1.8 90 600 $1.7 80 $1.6 500 70 $1.5 60 400 $1.4 Peer Average 50 $1.3 300 40 $1.2 30 200 Lateral ($MM) $1.1 $1.0 Drilling Drilling Footage, 1,000' 20 100 GrossD&C Cost Per 1,000’ 10 $0.9 Average Average Footage Drilled Per Day 0 0 $0.8 CPE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 4Q17 4Q18 4Q17 4Q18 INCREMENTAL COST SAVINGS TARGETED FROM AVERAGE 2018 WCA AFE (10,000’ LATERAL) $13 . Completions Contract . Local Sand Usage $12 . Water Recycling . Flowback Optimization . Pad Development . . Drilling Efficiencies Other Initiatives . Equipment rentals $MM . Other Initiatives $11 $10 2018 2019E Target 1. Based on JPM estimates. Peers include CRZO, CDEV, CXO, HK, JAG, OAS, PE, PDCE. 12

INFRASTRUCTURE ALLOWS OPERATIONAL FLEXIBILITY OPERATIONAL FLEXIBILITY FROM PRIOR INVESTMENTS 2019: FACILITIES CAPEX DECLINES BY 50% YoY . Leveraging existing facilities in 2019 development schedule 40% . Over 80% of wells drilled in 2019 utilize existing facilities 35% 30% . 4 new production facilities and 12 production facility upgrade projects across the assets 25% . Significant increase of recycling capabilities with addition of 20% incremental 30K BPD capacity 15% . Sustainable investments in the Delaware account for more 10% than 2/3rds of 2019 facilities spend 5% . Monetization opportunities available if accretive to long-term 0% corporate-level return profile without reducing operational 2017 2018 2019E reliability % of D&C SCALABILITY UPSIDE FROM CONTIGUOUS ACREAGE DELAWARE WATER RECYCLING GROWTH (1) 7 . 100%+ increase . Sustainable savings 6 . Alignment with ESG initiatives 5 Water of 4 3 Barrels Barrels of 2 1 Millions Millions 0 Density Heat Map 2018 2019* 1. 2019 Delaware recycling volumes based on projected targets for announced capital program. 13

RISK MANAGEMENT (1) STRATEGY WTI INSTRUMENT BREAKOUT . Portfolio approach with focus on total 100% 15% 15% 14% 14% 14% realized price 80% 15% 15% 14% 14% 14% . Protect WTI downside at ~$59 and Instrument allow for upside price participation in a 60% volatile market 40% 70% 70% 72% 72% 72% . Lock in WTI protection to support cash % of Hedges by by Hedges of % flow with FY19E ~ 55% hedged (2) 20% . Monitor market dynamics between 0% WTI, MEH and Brent in anticipation of 1Q19 2Q19 3Q19 4Q19 2019 volumes being sold outside the basin 3-way Collars Put Options Put Spreads expected by late 2019 . 4Q19+ Gray Oak: ~ 15 Mb/d gross FT WTI HEDGE VOLUME WITH WEIGHTED AVERAGE CEILING AND FLOOR PRICE . 2019 Mid-Cush basis swaps: ~ 19 Mb/d 1.7 $70 hedged at an average swap price of ) $68 AverageWTI Price Ceiling/Floor ($4.34) MMbo ( 1.6 $66 . 2020 Mid-Cush basis swaps: ~13 Mb/d hedged at an average swap price of $64 ($1.29) Volumes 1.6 $62 . Mitigate WaHa price volatility through $60 basis swaps with ~ 55% of FY19E gas volumes exposed to basis swap 1.5 $58 protection (2) $56 NYMEX WTI Hedge Hedge WTINYMEX . Evaluate a variety of physical and 1.4 $54 1Q19 2Q19 3Q19 4Q19 financial risk mitigation alternatives Ceiling Floor WTI Hedge Volumes 1. Hedge contracts as of 2/7/19. 2. Percentages based on the mid-point of 2019 guidance. 14

OUTLOOK RESPONSIBILITY: EXECUTION AND SAFETY OPTIMIZE HIGH-QUALITY PERMIAN INVENTORY DRIVE CORPORATE LEVEL RETURNS WITH PEER LEADING CASH MARGINS EFFICIENT CAPITAL CONVERSION WITHIN CASH FLOWS GENERATES DOUBLE DIGIT PRODUCTION GROWTH DELINEATE AND RATIONALIZE RESOURCE BASE INTEGRATE SUSTAINABLE INVESTMENTS TO DRIVE FUTURE COST SAVINGS AND LONG-TERM EFFICIENCY GAINS 15

APPENDIX

OIL AND GAS 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) - - - - - - - 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 $4.39 - - - - - - - Total Volume Hedged (Bbl) 1,530,000 1,547,000 1,656,000 1,656,000 3,077,000 3,312,000 6,389,000 - - - - - - - Average Ceiling Price ($/Bbl) $67.78 $67.78 $67.46 $67.46 $67.78 $67.46 $67.62 - - - - - - - Average Floor Price ($/Bbl) $59.12 $59.12 $58.89 $58.89 $59.12 $58.89 $59.00 - - - - - - - MIDLAND-CUSHING DIFFERENTIAL (Bbls/$/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) NYMEX Henry Hub (MMBtu, $/MMBtu) Sw aps 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 - - - - - - - Tw o-w ay 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) Sw aps Total Volumes 2,610,000 2,639,000 3,036,000 3,036,000 5,249,000 6,072,000 11,321,000 1,183,000 1,183,000 1,196,000 1,196,000 2,366,000 2,392,000 4,758,000 Total Daily Volumes 29,000 29,000 33,000 33,000 29,000 33,000 31,016 13,000 13,000 13,000 13,000 13,000 13,000 13,000 Avg. Sw ap Price ($1.25) ($1.25) ($1.22) ($1.22) ($1.25) ($1.22) ($1.23) ($1.12) ($1.12) ($1.12) ($1.12) ($1.12) ($1.12) ($1.12) 1. Hedge contracts as of 2/7/19. 17

NON-GAAP RECONCILIATION (1) 3Q17 4Q17 1Q18 2Q18 3Q18 Adjusted Income Reconciliation Income available to common stockholders $ 15,257 $ 21,001 $ 53,937 $ 48,650 $ 36,108 Adjustments: Net (gain) loss on derivatives, net of settlements 12,947 26,037 (3,978) 8,572 25,100 Change in the fair value of share-based awards 732 865 1,012 (463) 879 Tax effect on adjustments above (4,788) (9,416) 622 (1,703) (5,456) Change in valuation allowance (6,064) (8,285) (11,753) (10,562) (8,323) Adjusted Income $ 18,084 $ 30,202 $ 39,840 $ 44,494 $ 48,308 Adjusted Income per fully diluted common share $ 0.09 $ 0.15 $ 0.20 $ 0.21 $ 0.21 Adjusted EBITDA Reconciliation Net income $ 17,081 $ 22,824 $ 55,761 $ 50,474 $ 37,931 Adjustments: Net (gain) loss on derivatives, net of settlements 12,947 26,037 (3,978) 8,572 25,100 Non-cash stock-based compensation expense 1,952 2,101 2,143 1,164 2,587 Acquisition expense 205 (112) 548 1,767 1,435 Income tax expense 237 248 495 481 1,487 Interest expense 444 461 460 594 711 Depreciation, depletion and amortization 29,132 37,222 36,066 39,387 48,977 Accretion expense 131 154 218 206 202 Adjusted EBITDA $ 62,129 $ 88,935 $ 91,713 $ 102,645 $ 118,430 1. See “Important Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures. 18