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IPAA – OGIS New york April 8, 2019

Forward-Looking Statements April 2019 2 This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this presentation are "forward-looking statements." Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed, and that cash flows from operations will exceed expected capital investments in crude oil and natural gas properties for 2019 and 2020; management of lease expiration issues and financial ratios relating to our revolving credit facility; midstream capacity and related curtailments; the Delaware midstream monetization process, which may not occur in the time frame expected or at all; number of wells spud and TIL’d; average percentage working interest of wells; well costs; and average lateral lengths. The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this presentation reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this presentation or accompanying materials, we may use the term “projection”, “outlook” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or the industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty. Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors, made in our Annual Report on Form 10-K and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this presentation. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this presentation or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement. This presentation contains certain non-GAAP financial measures. A reconciliation of each such measure to the most comparable GAAP measure is presented in the Appendix hereto. We use "adjusted cash flows from operations," "adjusted net income (loss)," "adjusted EBITDA“, and “adjusted EBITDAX” and "PV-10," non-GAAP financial measures, for internal reporting and providing guidance on future results. These measures are not measures of financial performance under GAAP. We strongly advise investors to review our financial statements and publicly filed reports in their entirety and not rely on any single financial measure. See the Appendix for a reconciliation of these measures to GAAP. Rate of return estimates do not reflect lease acquisition costs or corporate general and administrative expenses. Non-proved estimates of potentially recoverable hydrocarbons and EURs may not correspond to estimates of reserves as defined under SEC rules. Resource estimates and estimates of non-proved reserves include potentially recoverable quantities that are subject to substantially greater risk than proved reserves. ADDITIONAL INFORMATION On April 5, 2019, PDC filed a preliminary proxy statement and form of WHITE proxy card with the SEC in connection with its solicitation of proxies for its 2019 Annual Meeting of Stockholders (the “2019 Annual Meeting”). Prior to the 2019 Annual Meeting, PDC will file with the SEC and furnish to its shareholders a definitive proxy statement and WHITE proxy card. PDC SHAREHOLDERS ARE STRONGLY ENCOURAGED TO READ THE DEFINITIVE PROXY STATEMENT (AND ANY AMENDMENTS AND SUPPLEMENTS THERETO) AND ACCOMPANYING WHITE PROXY CARD WHEN THEY BECOME AVAILABLE AS THEY WILL CONTAIN IMPORTANT INFORMATION. Shareholders may obtain the proxy statement, any amendments or supplements to the proxy statement and other documents as and when filed by PDC with the SEC without charge from the SEC’s website at www.sec.gov or from PDC’s website at www.pdce.com. CERTAIN INFORMATION REGARDING PARTICIPANTS PDC, its directors and certain of its executive officers may be deemed to be participants in connection with the solicitation of proxies from PDC’s shareholders in connection with the matters to be considered at the 2019 Annual Meeting. Detailed information regarding participants and their direct and indirect interests, by security holdings and otherwise, is included in PDC’s preliminary proxy statement and will be included in its definitive proxy statement. . The proxy statement and other relevant documents filed by PDC can be found at the SEC’s website at www.sec.gov or PDC’s website at www.pdce.com.

PDC ENERGY – Company Overview April 2019 $2.8B 545 $4.0B Market Cap(1) Enterprise Value(1) YE18 Proved Reserves (MMBoe) Delaware Basin ~42,000 net acres(3) 120 MMBoe proved reserves Core Wattenberg ~96,000 net acres(2) 425 MMBoe proved reserves (1) As of 4/4/19; assumes 66 mm shares outstanding; (2) Niobrara & Codell only. (3) 2018 Year-End net acreage count of ~51,400. ~9,500 net acres (primarily in Western Culberson County) expired by end of 1Q19. Additional ~8,400 anticipated to expire or be monetized in remainder of 2019. Anticipated YE19 net acreage count of ~33,500. 3

FINANCIAL STRENGTH – Balance Sheet, Leverage and Liquidity Leverage and Liquidity YE18 leverage ratio improved to 1.4x from 1.9x at YE17 ~$30 million drawn on revolver (12/31/18) 4Q18 free cash flow of ~$25MM(1) Total liquidity of ~$1.3 billion Hedge Portfolio ~50% of 2019e oil production hedged at ~$55/Bbl(2) 8.6 MMBbls 2020 oil hedged at ~60/Bbl(2) ~25% of 2019e gas production hedged at ~$2.90/MMBtu(2) As of December 31, 2018 4 (1) 4Q18 adjusted cash flow from operations of $233.1 less 4Q18 O&G capital investments of $205.9; (2) Assumes weighted-average floor prices 5.75% Senior Notes April 2019

Long-Term Value Creation CORE STRATEGIC PRIORITIES – Built to Deliver Sustainable, Long-Term Value April 2019 5 PROVIDE TOP-TIER FINANCIAL & PERFORMANCE METRICS Maintain top-tier Balance Sheet strength and cash flow growth through extensive planning and scenario analysis BUILD A BEST-IN-CLASS ORGANIZATION Focus on the training and development of our future leaders while preserving our differentiating team-based culture MAINTAIN COMPETITIVE, HIGH-VALUE INVENTORY Create value through strategic acreage trades, focused innovation/exploration and opportunistic acquisitions PRIORITIZE HEALTH, SAFETY & THE ENVIRONMENT PDC’s top priority. Be a good neighbor in the communities in which we live and operate while minimizing our operational footprint DRIVE EFFICIENCY THROUGH TECHNOLOGY & INNOVATION Continuously pursue excellence in all we do by quickly adapting to successful technical innovation DELIVER SUSTAINABLE & PEER-COMPETITIVE RESULTS Emphasis on sustainable free cash flow with a more moderate growth profile while preserving operational flexibility

STRATEGIC PRIORITIES – Adapting to the Changing Landscape April 2019 Multi-Year Planning Focused to Achieve Specific Targets at $50 Oil & $3 Gas 6 (1) Free cash flow divided by capital investment PRIORITIES Sustainable FCF Year-over-year growth in FCF of >$50MM Consideration of opportunities to return capital to shareholders Financial & Operational Discipline Target both G&A and LOE per Boe of < $3/Boe Achieve CF Neutrality at $45/Bbl Return on Capital Emphasis on FCF Margin(1) Average portfolio rate-of-returns of >50% Solid Growth Debt-adjusted CFPS growth of >10% Production per share growth of >10% 1 2 3 4

PDC ENERGY – 2019 Plan Expected to Deliver Differentiating Results $50/Bbl WTI and $3/Mcf NYMEX Prices 2019 Guidance Overview Plan targets free cash flow generation at $50/bbl oil Capital investments ~$150MM lower than 2018 Every $5/bbl change in NYMEX oil price adjusts anticipated cash flows by ~$40MM Production growth of ~20% to 46 – 50 MMBoe Anticipate slight decline in volumes from 4Q18 to 1Q19 before steady growth through remainder of 2019 Oil & Gas Investments – ($770 - $830MM) Wattenberg – Plan to run 3 rigs and 1 completion crew Delaware – 2.5 rig pace planned with a part-time completion crew Delaware Basin Midstream – (~$40MM) Portion of investment expected to be recovered in net proceeds of ongoing monetization process April 2019 7 (1) Defined as cash flow from operating activities without regard to changes in operating assets and liabilities. (2) Does not include corporate capital of ~$20MM related to installation of Enterprise Resource Planning systems Oil & Gas Investment ($770 - $830MM) Adj. Cash Flow from Ops(1) ($840 - $890MM) Capital Investment(2) ($810 - $870MM) DE Midstream (~$40MM)

FINANCIAL GUIDANCE – 2019 Full-Year Guidance 8 2019 Guidance Production: 46 – 50 MMBoe Capital Investments: $810 – $870 Price Realizations (% NYMEX) (ex. TGP) Oil: 90 – 95% Gas: 50 – 55% NGL: 30 – 35% $3.00- $3.40 $0.80 - $1.00 $2.85 - $3.15 41- 45% 21-23% 33-37% April 2019 $- $1.00 $2.00 $3.00 $4.00 2016 2017 2018 2019e LOE/Boe $- $2.00 $4.00 $6.00 2016 2017 2018 2019e G&A/Boe $- $0.50 $1.00 $1.50 2016 2017 2018 2019e TGP/Boe 2019e Commodity Mix Oil Natural Gas NGLs

2019-2020 OUTLOOK – Prioritizing Free Cash Flow & Debt-Adj. Per Share Growth 9 (1) Does not include corporate capital. Delaware midstream capital investment of $77MM, ~$40MM and $0 in 2018, 2019 & 2020, respectively; (2) Midpoint of cash flow deficit/free cash flow divided by midpoint of total capital investment. (2018 FCF Margin = -$176MM/$985MM = -18%); (3) Uses 2018 average share price of $51.48 2018 2019e 2020e Capital Investment (MM)(1) $985 $810 - $870 $825 - $925 (Outspend)/FCF (MM) ($176) ~$25 $100 - $200 Free Cash Flow Margin(2) (18%) ~3% ~15% Prod. Growth/Debt-Adj. Share(3) ~20% ~20% ~15-20% NYMEX Pricing (Oil/Gas) $64.77/$3.09 $50/$3 $50/$3 Rig Count (WB/DE) 3/3 3/2.5 3/2 April 2019 2019 Highlights Commitment to capital discipline Capital investments reduced ~$150MM from 2018 Anticipate generating FCF of ~$25MM at $50 WTI Improving balance sheet with steady production growth Anticipate YE19 leverage ratio of ~1.3x at $50 WTI Solid production growth per debt-adjusted share of ~20% 2020 Considerations Increase DUC count throughout 2019 Ability to manage completions in 2020 Additional Delaware basin completions due to potential for operational efficiencies Consider return of capital to shareholders at sustainable levels when consistent quarterly FCF generation achieved 10-15% 0.0x 0.5x 1.0x 1.5x 2.0x 0 10 20 30 40 50 60 70 80 2018 2019e 2020e Leverage Ratio MMBoe Production and Leverage Ratio Outlook Production Leverage Ratio

Asset overview

97,080 Boe/d 16% Q/Q Growth 40 Spuds 40 TILs CORE WATTENBERG – Prolific Asset in Development Mode April 2019 (1) Niobrara and Codell only. 96,000 425 ~Net Acres(1) YE18 Proved Reserves (MMBoe) 4Q18 Results Kersey Area Plains Area Prairie Area 11

CORE WATTENBERG – Safely Developing Rural Acreage in Weld County April 2019 Kersey Greeley Evans Gilcrest Eaton Fort Collins PDC Acreage City Boundary I-25 Interstate State Highway PDC has operated in the Wattenberg Field of the DJ Basin for almost 20 years Field office of ~250 employees located in Evans Consolidated acreage position minimizes surface usage Extensive history of positive working relationships with surrounding communities, regulators and elected officials Support multiple community organizations through year-round charitable giving and volunteerism ~100% of PDC net acreage in rural Weld County County voted 75% No on Proposition 112 in November 2018 ~5% of gross acreage located within municipal boundaries Anticipate ~100% can be reached through long-lateral development from outside municipal boundary Kersey Area Plains Area Prairie Area WELD COUNTY LARIMER COUNTY 12

Core Wattenberg – 2019 Plan Significantly Enhances Efficiencies Capital investment of ~$500 MM Three rigs and one completion crew SRL/MRL/XRL well costs of $3/$4/$5 MM with average spud to spud drill times of 5/7/9 days Continued focus on capital efficiency Long laterals Increased working interests Reduced surface locations Planned third-party midstream expansions to unlock tremendous value Relatively flat production expected in 1Q19 from 4Q18 before steady growth through year-end Plant 11 assumed to begin gradually coming online in June 2019(1) Associated bypass expected to begin in August 2019 April 2019 13 (1) Source: DCP press release dated 2/11/19; (2) Reflects impact of 2018 strategic acreage trade 139 TILs 110-125 TILs TILs by Lateral Length 139 TILs ~1,500 Locations ~6,300’ Avg. Lateral 79% WI ~920 Locations(2) ~8,250’ Avg. Lateral 85% WI ~85 DUCs ~120 DUCs 2018 SRL MRL XRL 2019 0 2,000 4,000 6,000 8,000 YE17 2018 TILs YE18 Net WI Lateral Feet (thousands)

Kersey Area Prairie Area Plains Area CORE WATTENBERG – Production Unbundling with Midstream Expansions DCP Midstream – 1.05 Bcf/d Plant 10 (Mewbourne 3): In-service August 1, 2018 Plant 11 (O’Connor 2): 200 MMcf/d (expected start-up in June 2019) 100 MMcf/d bypass (expected start-up in August 2019) Plant 12 (Big Horn): Up to 1 Bcf/d (including bypass) First-phase start-up expected in 2020 (~300 MMcf/d) Aka Energy Processing capacity of ~40 MMcf/d Additional capacity via offloads to WES system Other DJ Basin Anticipated Expansions Rimrock, Discovery, Western Gas, Outrigger expected to benefit entire basin (~1 Bcf/d additional capacity) April 2019 14 (1) Source: DCP Midstream press release dated 2/11/19 Plant 10 Grand Parkway Plant 11 Additional compression 2018-19 Processing Plant Expansions DCP - Compression Processing Plant Aka -

DELAWARE BASIN – Primary Focus in Two Oil-Rich Areas April 2019 (1) 2018 Year-End net acreage count of ~51,400. ~9,500 net acres (primarily in Western Culberson County) to expire by end of 1Q19. Additional ~8,400 anticipated to expire or be monetized in remainder of 2019. Anticipated YE19 net acreage count of ~33,500. 42,000 120 ~Net Acres(1) YE18 Proved Reserves (MMBoe) 30,840 Boe/d 19% Q/Q Growth 9 Spuds 4 TILs 4Q18 Results 15

DELAWARE BASIN – Focused on Continued Execution Anticipate a 2.5 rig pace and part-time completion crew in 2019 Successful marketing and midstream efforts ensure flow assurance at competitive prices ~90% of 2019 oil volumes expected to receive Brent-based pricing Natural gas flow assurance Midstream monetization process continuing to progress with expected execution in 1H19 2019 capital investments associated with midstream infrastructure of ~$40MM (part expected to be recovered through divestiture) April 2019 16 5,700 7,000 10,000 13,000 16,000 21,000 25,000 26,000 31,000 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 Dec. '16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Boe/d Delaware Production (Boe/d)

Delaware Basin – Steady Progress Towards Development Mode Capital investment of ~$350 MM Includes ~$40 MM of planned midstream investment (portion of which expected to be refunded if divested) Project ~20% increase in lateral feet TIL’d compared to 2018 Expect decreased average well costs due to modified completion design Increased stage spacing Additional benefits possible through pad drilling efficiencies, faster drill times, service cost reductions Anticipate 2.5 rig pace and part-time completion crew ~2/3 of 2019 TILs focused in Block 4 All 2019 TILs expected to be MRL or XRL Inventory of ~365 identified locations with average lateral length of ~7,900’(1) April 2019 17 (1) Gross operated inventory primarily targeting the WCA and WCB zones within our oilier Eastern and North Central areas. Some locations are within untested target zones that may be subject to a higher degree of uncertainty or may depend on additional delineation testing. (2) XRL spud to rig release ~2,000 lbs/ft ~200’ stage spacing ~34 Days(2) 26 TILs 20-25 TILs TILs by Lateral Length $12.5 - $15.0 $11.5 - $13.0 ~2,400 lbs/ft ~160’ stage spacing ~36 Days(2) 2018 SRL MRL XRL 2019 $0 $4 $8 $12 $16 2018 2019e millions Costs per Well – MRL/XRL

Delaware Basin – 2019 Plan Focused on Oily Areas of Block 4 2019 Program Focus on multi-well pads, longer-laterals and spacing design Continue to refine Area boundaries and type curves Anticipate first Bone Spring TIL in 2Q19 Tinman Project – Seven well pad in Area 3 designed to test several spacing assumptions: Parent/child (WCA) Vertical spacing in WCB & between zones (WCA/WCB) Horizontal spacing in WCB Anticipate similar performance as Grizzly Pad Grizzly Pad performance Artificial lift has stabilized production profile Key findings to-date: Upper WCA wells showing strongest performance Lower WCA wells producing in-line with average WCB Overall project underperformance believed to be associated with localized rock and fluid properties not spacing Continue to Test Optimal Spacing Design April 2019 18 Block 4 Wolfcamp A AREA 1 >6,000 GOR AREA 3 <3,000 GOR AREA 2 3,000 – 6,000 GOR 2019 2020 Area 1 - - Area 2 25% 60% Area 3 40% 15% North Central 35% 25% Anticipated TIL Breakdown Grizzly Pad

PDC ENERGY – Delivering Strong Value in 2019 at $50 Oil April 2019 $50/Bbl WTI and $3/Mcf NYMEX Prices $810- $870 46-50 41- 45% ~$25 2019e % Oil 2019e Production (MMBoe) 2019e Free Cash Flow (MM) 2019e Capital Investment (MM) Returns Results Responsibility Strong Returns on Core Wattenberg and Delaware basins projects generate solid debt-adjusted per share growth in 2019 Prolific Results help generate free cash flow of ~$25 million at $50/Bbl WTI oil in 2019 Corporate Responsibility focused on sustainable operations with safe and responsible development of our assets 19

Investor Relations Mike Edwards, Senior Director Investor Relations michael.edwards@pdce.com Kyle Sourk, Manager Investor Relations kyle.sourk@pdce.com Corporate Headquarters PDC Energy, Inc. 1775 Sherman Street Suite 3000 Denver, Colorado 80203 303-860-5800 Website www.pdce.com

appendix

EXECUTIVE COMP. – New Metrics Demonstrate Commitment to Capital Efficiency April 2019 50% Qualitative & 50% Quantitative 22 Capital Efficiency One-year measurement of F&D (capital invested divided by EURs of TILs) 5 Production Measurement of operational success Moderate growth with focus on FCF 4 LOE and G&A/Boe Ensures focus on cost structure and profitability 3 Debt-Adj. Cash Flow per Share Ability to create cash flow in a capital efficient manner without change to capital structure 2 Free Cash Flow Margin Percentage measurement of free cash flow divided by capital investments 1 2019 METRICS New Metrics Rationale for New Metrics FCF Margin Measures ability to deliver organic FCF in range of oil prices Mgmt. has ultimate control to manage capital investment Debt-Adj. CFPS Multi-year analysis indicates strong correlation to share price performance

Strong Improvements in Quarterly Production and LOE/Boe Strong Wattenberg performance due to steady third-party processing throughput Kersey line pressures still elevated though showed modest improvement by year-end Late 3rd quarter and early 4th quarter Delaware TILs drive strong sequential production growth Declining LOE per Boe coincides with unbundled Wattenberg production Full-year Wattenberg LOE of less than $3/Boe Steady Delaware basin execution deliver competitive lifting costs of ~$4.15/Boe in 2018 April 2019 23 73,900 88,100 92,500 94,100 99,000 103,000 110,000 128,000 50,000 100,000 150,000 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Production ( Boe/d) $2.98 $2.50 $2.98 $2.83 $3.33 $3.44 $3.27 $3.06 $2.00 $3.00 $4.00 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 LOE ($/Boe)

PDC ENERGY – Exiting 2018 with Strong Momentum April 2019 ~130 40.2 1.4x 42% 2018 Crude Oil 2018 Production (MMBoe) Dec. ‘18 Exit Rate (Mboe/d) YE18 Leverage Ratio Returns Results Responsibility Strong Results drive 4Q18 growth of 17% compared to 3Q18 with a December exit rate of ~130,000 Boe/d Solid Returns generate free cash flow in 4Q18 and set stage for sustainable future free cash flow generation Corporate Responsibility focused on sustainable operations with safe and responsible development of our assets 24

20% increase in proved reserves 329% all-sources reserve replacement(1) 66% increase in before-tax SEC PV-10(2) to ~$5.3 billion Stress-tested reserves at $50/bbl WTI flat Lost ~2% of proved reserves 2017 (MMBoe) 2018 (MMBoe) Liquids (2018) Wattenberg 350.8 425.4 57% Delaware 97.9 119.5 68% Utica 4.2 - - Total 452.9 544.9 59% +132.2 (40.2) B-Tax PV-10 (MM) $3,212 B-Tax PV-10 (MM) $5,321 (3) 544.9 452.9 PDC ENERGY – Solid Growth in 2018 SEC Proved Reserves April 2019 25 (1) All-sources reserve replacement defined as sum of the year-over-year net additions in proved reserves from extensions, revisions, dispositions and acquisitions, divided by 2018 estimated production; (2) 2018 SEC NYMEX pricing: $65.56/Bbl and $3.10/MMBtu gas; (3) Net Additions is extensions, revisions, dispositions and acquisitions. 200 300 400 500 600 Year-End 2017 Net Additions 2018 Production Year-End 2018 Proved Reserves Summary (MMBoe) Wattenberg Delaware Utica

PDC ENERGY – Corporate Social Responsibility April 2019 COMMUNITY OUTREACH EMPLOYEES MATTER SAFE OPERATIONS 26

Hedge Position Hedges in Place as of 12/31/18 27 (1) Corresponding CIG Basis swaps in place averaging ($.78) April 2019 CRUDE OIL 2019 2020 Volumes (MMBbls) Collar 2.6 3.6 Swap 8.4 5.0 Total Crude Oil Hedged 11.0 8.6 Crude Oil Price ($/Bbl) Floor $56.54 $55.00 Ceilings $68.13 $71.68 NYMEX Swap $53.86 $62.07 Weighted Average Price (floor) $54.50 $59.11 NATURAL GAS 2019 Volumes (BBtu) Collar - Swap 26,008 Total Natural Gas Hedged 26,008 Natural Gas Price ($/Mmbtu) Floor - $ Ceilings - $ NYMEX Swap (1) $2.91 Weighted Average Price (floor) $2.91

Reconciliation of Non-U.S. GAAP Financial Measures April 2019 28 Adjusted Net Income (Loss) Three Months Ended December 31, Twelve Months Ended December 31, 2018 2017 2018 2017 Adjusted net income (loss): Net income (loss) $ 178.9 $ 77.6 $ 2.0 $ (127.5 ) (Gain) loss on commodity derivative instruments (403.0 ) 90.4 (145.2 ) 3.9 Net settlements on commodity derivative instruments (25.0 ) (8.9 ) (115.5 ) 13.3 Tax effect of above adjustments 102.4 (28.2 ) 62.4 (4.1 ) Adjusted net income (loss) $ (146.7 ) $ 130.9 $ (196.3 ) $ (114.4 ) Weighted - average diluted shares outstanding 66.2 66.1 66.3 65.8 Adjusted diluted earnings per share $ (2.22 ) $ 1.98 $ (2.96 ) $ (1.74 ) Adjusted Cash Flows from Operations Three Months Ended December 31, Twelve Months Ended December 31, 2018 2017 2018 2017 Adjusted cash flows from operations: Net cash from operating activities $ 311.5 $ 177.2 $ 889.3 $ 597.8 Changes in assets and liabilities (78.4 ) (2.6 ) (80.9 ) (15.7 ) Adjusted cash flows from operations $ 233.1 $ 174.6 $ 808.4 $ 582.1 Year-end 2018 Year-end 2017 PV-10 5,321 $ 3,212 $ Present value of estimated future income tax discounted at 10% (873) (332) Standardized measure of discounted future net cash flows 4,448 $ 2,880 $ Reconciliation of PV-10

Reconciliation of Non-U.S. GAAP Financial Measures April 2019 29 Adjusted EBITDAX Three Months Ended December 31, Twelve Months Ended December 31, 2018 2017 2018 2017 Net income (loss) to adjusted EBITDAX: Net income (loss) $ 178.9 $ 77.6 $ 2.0 $ (127.5 ) (Gain) loss on commodity derivative instruments (403.0 ) 90.4 (145.2 ) 3.9 Net settlements on commodity derivative instruments (25.0 ) (8.9 ) (115.5 ) 13.3 Non - cash stock - based compensation 5.4 4.8 21.8 19.4 Interest expense, net 18.1 19.6 70.3 76.4 Income tax expense (benefit) 59.1 (140.4 ) 5.4 (211.9 ) Impairment of properties and equipment 264.2 3.4 458.4 285.9 Impairment of goodwill — — — 75.1 Exploration, geologic and geophysical expense 1.6 3.4 6.2 47.3 Depreciation, depletion and amortization 149.8 108.5 559.8 469.1 Accretion of asset retirement obligations 1.3 1.4 5.1 6.4 Loss on extinguishment of debt — 24.7 — 24.7 Adjusted EBITDAX $ 250.4 $ 184.5 $ 868.3 $ 682.1 Cash from operating activities to adjusted EBITDAX: Net cash from operating activities $ 311.5 $ 177.2 $ 889.3 $ 597.8 Interest expense, net 18.1 19.6 70.3 76.4 Amortization of debt discount and issuance costs (3.3 ) (3.3 ) (12.8 ) (12.9 ) Gain (loss) on sale of properties and equipment 2.8 — (0.4 ) 0.7 Exploration, geologic and geophysical expense 1.6 3.4 6.2 47.3 Exploratory dry hole costs (0.1 ) (0.1 ) (0.1 ) (41.3 ) Other (1.8 ) (9.7 ) (3.3 ) 29.8 Changes in assets and liabilities (78.4 ) (2.6 ) (80.9 ) (15.7 ) Adjusted EBITDAX $ 250.4 $ 184.5 $ 868.3 $ 682.1

Commonly Used Definitions April 2019 30 Bbl – Barrel Boe – Barrel of oil equivalent Btu – British thermal unit CAGR – Compound Annual Growth Rate CFPS – Cash flow per share CWC – Completed well cost D&C – Drilling and Completions EBITDAX – Earnings before interest, taxes, depreciation, amortization and exploration EUR – Estimated Ultimate Recovery FCF – Free Cash Flow (cash flows from operations less capital investments) FCF Margin – Free cash flow divided by capital investments Gross Margin – Oil, gas and NGL sales less LOE, TGP and prod. tax, as a % of oil, gas and NGL sales Leverage Ratio – as defined in our revolving credit facility agreement; similar to Debt to EBITDAX LOE – Lease operating expenses MM – Million MMcf – Million cubic feet RoR – Rate of Return SRL/MRL/XRL – Standard-, Mid- and Extended-reach lateral SWD – Salt-water disposal TGP – Transportation, gathering and processing TIL – Turn-in-line