3RD 2019 QUARTER EARNINGS CALL November 2019

Forward-Looking Statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act"), Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 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 report 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, the pending acquisition of SRC Energy, Inc. ("SRC") and the effects thereof; the expected timing of the acquisition of SRC; 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; cash flows from operations relative to future capital investments; our stock repurchase program, which may be modified or discontinued at any time; potential additional payments from the sale of our midstream assets; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; impacts of certain accounting and tax changes; timing and adequacy of infrastructure projects of our midstream providers and the related impact on our midstream capacity and related curtailments; fractionation capacity; impacts of Colorado political matters and expected timing of rulemakings; ability to meet our volume commitments to midstream providers; ability to obtain permits from the Colorado Oil and Gas Conservation Commission in a timely manner; ongoing compliance with our consent decree and expected timing of certain litigation; and reclassification of the Denver Metro/North Front Range NAA ozone classification to serious. The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report 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 report or accompanying materials, we may use the term “projection” 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 our 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 the heading "Risk Factors," made in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, our Annual Report on Form 10-K for the year ended December 31, 2018 filed with the U.S. Securities and Exchange Commission ("SEC") on February 28, 2019, and our other filings with the SEC for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the 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. Additional Information and Where to Find it This document does not constitute an offer to buy or sell or the solicitation of an offer to buy or sell any securities or a solicitation of any vote or approval. This communication references a proposed business combination between PDC and SRC Energy Inc. (“SRC”). In connection with the proposed transaction, PDC has filed with the Securities and Exchange Commission (the “SEC”) a registration statement on Form S-4, as amended, that includes a preliminary joint proxy statement of PDC and SRC that also constitutes a preliminary prospectus of PDC. The information in the preliminary joint proxy statement/prospectus is not complete and may be changed. Each of PDC and SRC also plans to file other relevant documents with the SEC regarding the proposed transaction. No offering of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the U.S. Securities Act of 1933, as amended. Each of SRC and PDC will send the definitive joint proxy statement/prospectus, when available, to its respective security holders seeking their approval of the proposed transaction. INVESTORS AND SECURITY HOLDERS OF PDC AND SRC ARE URGED TO READ THE REGISTRATION STATEMENT, JOINT PROXY STATEMENT/PROSPECTUS AND OTHER DOCUMENTS THAT MAY BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY IF AND WHEN THEY BECOME AVAILABLE, INCLUDING ANY AMENDMENTS OR SUPPLEMENTS TO THOSE MATERIALS, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT PDC, SRC AND THE PROPOSED TRANSACTION. Investors and security holders will be able to obtain free copies of these documents (if and when available) and other documents containing important information about PDC and SRC, once such documents are filed with the SEC through the website maintained by the SEC at http://www.sec.gov. Copies of the documents filed with the SEC by PDC will be available free of charge on PDC’s website at http://investor.pdce.com/sec-filings or by contacting PDC’s Senior Director of Investor Relations by email at michael.edwards@pdce.com, or by phone at 303-860-5820. Copies of the documents filed with the SEC by SRC will be available free of charge on SRC’s website at https://ir.srcenergy.com/investor-relations or by contacting SRC’s Investor Relations Manager by email at jrichardson@srcenergy.com, or by phone at 720-616-4308. Certain Information Concerning Participants PDC, SRC and certain of their respective directors and executive officers may be deemed to be participants in the solicitation of proxies in respect of the proposed SRC transaction. Information about the directors and executive officers of PDC is set forth in PDC’s proxy statement for its 2019 annual meeting of stockholders, which was filed with the SEC on April 17, 2019. Information about the directors and executive officers of SRC is set forth in its proxy statement for its 2019 annual meeting of shareholders, which was filed with the SEC on March 28, 2019. These documents can be obtained free of charge from the sources indicated above. Other information regarding the participants in the proxy solicitations and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the joint proxy statement/prospectus and other relevant materials to be filed with the SEC when such materials become available. Investors should read the definitive joint proxy statement/prospectus carefully when it becomes available before making any voting or investment decisions. You may obtain free copies of these documents from PDC or SRC using the contact information indicated above. November 2019 2

Reconciliation of Non-U.S. GAAP Financial Measures We use "adjusted cash flows from operations”, “free cash flow”, "adjusted net income (loss)" and "adjusted EBITDAX," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, in providing public guidance on possible future results. In addition, we believe these are measures of our fundamental business and can be useful to us, investors, lenders and other parties in the evaluation of our performance relative to our peers and in assessing acquisition opportunities and capital expenditure projects. These supplemental measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. In the future, we may disclose different non-U.S. GAAP financial measures in order to help us and our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. Adjusted cash flows from operations and free cash flow. We believe adjusted cash flows from operations can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe free cash flow provides additional information that may be useful in an analysis of our ability to generate cash to fund exploration and development activities and to return capital to stockholders. Adjusted net income (loss). We believe that adjusted net income (loss) provides additional transparency into operating trends, such as production, realized sales prices, operating costs and net settlements on commodity derivative contracts, because it disregards changes in our net income (loss) from mark-to-market adjustments resulting from net changes in the fair value of our unsettled commodity derivative contracts, and these changes are not directly reflective of our operating performance. Adjusted EBITDAX. We believe that adjusted EBITDAX provides additional transparency into operating trends because it reflects the financial performance of our assets without regard to financing methods, capital structure, accounting methods or historical cost basis. In addition, because adjusted EBITDAX excludes certain non-cash expenses, we believe it is a not a measure of income, but rather a measure of our liquidity and ability to generate sufficient cash for exploration, development, acquisitions and to service our debt obligations. Beginning in the third quarter of 2019, we are now including a reconciling item for the gain or loss on the sale of properties and equipment when calculating adjusted EBITDAX, thereby no longer including such gains or losses in our reported adjusted EBITDAX. We believe this methodology for calculating adjusted EBITDAX is more consistent with the majority of our peers and will prevent potential confusion that could result from us including an adjustment for impairments, but not including an adjustment for gains or losses on the sale of properties and equipment. As a result, we also now exclude the gain or loss on the sale of properties and equipment as a reconciling item from cash flows from operating activities to adjusted EBITDAX. All prior periods have been conformed for comparability of this information. November 2019 3

BART BROOKMAN President & CEO

3rd PDC Energy – Strong Financial Results Headline Quarter • ~$234 million of net cash from operating activities with ~$202 million of adjusted cash flows(1) -~$164 million oil & gas capital investments • ~$40 million of FCF(2) generated in 3Q • Production of 12.7 MMBoe (26% increase year-over-year) • $155 million returned to shareholders via repurchase of 4.7 million shares year-to-date • 3rd quarter D&C well costs below budget in both basins • $1.6 billion borrowing base reaffirmed in October (maintained commitment level of $1.3 billion) - $2.1 billion contingent upon closing of SRC Acquisition – with commitment level up to $1.9 billion (1) Non-U.S. GAAP metric, see appendix for reconciliation; (2) FCF = Free cash flow defined as cash flow from operating activities, adjusted for changes in working capital less oil & gas capital investment; non-U.S. GAAP metric, see appendix for reconciliation; (3) Expected closing in early 1Q20 November 2019 5 Top 2020 Priorities •Commitment to generate meaningful free cash flow and return capital to shareholders •Successful integration of SRC assets(3)

2020 Priority – Target FCF of $275 Million at $55 Oil & $2.70 Gas Pro Forma Contingent Upon Successful Closing of SRC Acquisition • • • Expect FY19 capital at or near bottom of $810 - $840 million range Project 2H19 FCF of > $150 million(1) Reducing costs – well costs, LOE/Boe and G&A/Boe decreasing throughout 2019 Returned $155 million to shareholders via stock repurchase program Flexibility to reduce capital spend and production growth profile to ensure ~13 MMBbls of oil hedged at weighted-avg. floor of ~$58/Bbl $5/bbl change in oil price = ~$100 million change to cash flow $0.25/Mcf change in gas price = ~$15 million change to cash flow 5% change in NGLs (as % of NYMEX) = ~$30 million change to cash flow (1) meaningful 2020 FCF • • • • Expect to enter 2020 with ~220 Wattenberg DUCs and short-term rig contracts Expect 5-10% improvement to D&C costs compared to initial 2020 Outlook • • • • (1) The Company is unable to present a reconciliation of forward-looking free cash flow because components of the calculation, including fluctuations in working capital accounts, are inherently unpredictable. Moreover, estimating the most directly comparable GAAP measure with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. The Company believes that forward-looking estimates of free cash flow are important to investors because they assist in the analysis of the Company’s ability to generate cash from its operations in excess of capital investments in crude oil and natural gas properties. November 2019 6 Pro Forma Commodity Price Protection Flexible Capital Program 2019 PDC Track Record of Execution

2020 Priority – Successful Integration of SRC • • • Commitment to achieve $40 million of G&A synergies in 2020(1) Focused on integrating top-talent from both organizations Assessing and integrating culture Creating committee focused on integration and additional corporate synergies & cost efficiencies Integration Team assembled and planning transition tasks Focused on development plan optimization - pro forma combined budget process underway Regulatory approval process progressing and bank financing approvals completed Focus on optimizing field operations near term Nearing go-live date of PDC’s new ERP system Integration of SRC financial systems into new ERP after go-live by elimination of system redundancies • • • • • • • (1) Excludes transaction related costs that may be pushed to 2020 due to anticipated timing of closing November 2019 7 TECHNOLOGY a a a PROCESS PEOPLE

SCOTT MEYERS Chief Financial Officer

Financial Results – Summary U.S. GAAP $400 Net Cash from Operating Activities DE Midstream Related $300 September 30, September 30, $200 $100 $0 3Q18 4Q18 1Q19 2Q19 3Q19 20.0 Production by Basin Wattenberg Delaware 15.0 10.0 * = Not Meaningful 5.0 0.0 3Q18 4Q18 1Q19 2Q19 3Q19 November 2019 9 MMBoe millions Measure (millions except per share and price per Boe data) Three Months EndedNine Months Ended 2019 2018 %2019 2018 % Production (MMBoe)12.7 10.1 26%36.4 28.4 28% Realized Price per Boe (excluding derivatives)$24.18 $36.88 (34%)$26.61 $35.35 (25%) Total crude oil, natural gas and NGLs sales$307.4 $372.4 (17%)$967.5 $1,003.6 (4%) Net income (loss)$15.9 ($3.4) *($35.7) ($176.8) 80% General & Administrative Expense$41.1 $48.2 (15%)$123.5 $121.2 2% General & Administrative Expense per Boe$3.23 $4.78 (32%)$3.40 $4.27 (20%) Earnings per diluted share$0.25 ($0.05) *($0.55) ($2.68) 79% Net cash from operating activities$233.5 $197.0 19%$675.7 $577.8 17%

Financial Results – Summary Non-U.S. GAAP See Appendix for Reconciliation Adjusted EBITDAX(1) Avg. NYMEX Oil $300 $80 $250 $70 September 30, September 30, $200 $60 $150 $50 $100 $40 $50 $30 $0 $20 3Q18 4Q18 1Q19 2Q19 3Q19 Adj. Cash Flow from Operations $300 $80 Avg. NYMEX Oil * = Not Meaningful $250 $70 $200 $60 $150 $50 $100 $40 $50 $30 $0 $20 3Q18 4Q18 1Q19 2Q19 3Q19 (1) Beginning in 3Q19, the Company modified its adjusted EBITDAX reconciliation to exclude (Gain) loss on sale of properties and equipment. See appendix for quarterly reconciliations. November 2019 10 millions millions NYMEX Oil ($/Bbl) NYMEX Oil ($/Bbl) Measure (millions except per share and price per Boe data) Three Months EndedNine Months Ended 2019 2018 %2019 2018 % Adjusted net income (loss)($24.5) $31.8 *$16.1 ($49.6) * Adjusted earnings per diluted share($0.39) $0.48 *$0.25 ($0.75) * Adjusted cash flows from operations$202.4 $201.1 1%$601.9 $575.3 5% Adjusted EBITDAX(1)$214.7 $215.3 (0%)$646.4 $621.1 4% Adjusted EBITDAX per diluted share$3.43 $3.25 5%$9.96 $9.37 6%

Financial Results – Production Cost Summary Production Costs per Boe $8 15 September 30, 13 $6 11 $4 9 $2 7 $0 5 3Q18 4Q18 1Q19 2Q19 3Q19 Production LOE TGP Production Tax LOE per Boe by Basin $6 $4 $2 $0 3Q18 4Q18 Wattenberg 1Q19 Delaware 2Q19 3Q19 Total Company November 2019 11 $/Boe Production Costs (per Boe) Production (MMBoe) Measure (millions except per share and price per Boe data) Three Months Ended September 30, Nine Months Ended 2019 2018 % 2019 2018 % Production (MMBoe) 12.7 10.1 26% 36.4 28.4 28% Operating Costs (millions) Lease operating expenses $36.5 $33.0 10% $106.0 $94.9 12% Production taxes $13.0 $24.0 (46%) $57.8 $66.8 (13%) Transportation, processing and gathering $11.0 $9.2 19% $34.6 $25.5 36% Total $60.5 $66.2 (9%) $198.4 $187.2 6% Operating Costs per Boe Lease operating expenses$2.87$3.27(12%)$2.92$3.34(13%) Production taxes$1.03$2.37(57%)$1.59$2.35(32%) Transportation, processing and gathering$0.87$0.91(4%)$0.95$0.906% Total per Boe$4.77$6.55(27%)$5.46$6.59(17%) Lease Operating Expenses by Basin ($/Boe) Wattenberg$2.51$3.01(17%)$2.53$3.11(19%) Delaware$3.94$4.09(4%)$4.21$4.132%

Financial Results – Continued Focus on G&A Improvements • Expect to meet updated 2019 G&A guidance of $3.00 - $3.20/Boe -Includes all 1H19 expenses related to shareholder activism, Delaware midstream divestitures and PDC RIF-related severance -Excludes SRC merger-related expenses in 2H19 Project peer-leading 2020 G&A of ~$2.00/Boe • - Includes ~$40mm of G&A synergies related to SRC merger (excludes SRC transaction costs) $3.53 $3.45 $3.23 1Q19 2Q19 3Q19 $4.31 $3.98 $3.43 $3.02 $2.99 $2.97 $2.87 $2.85 $2.78 $2.46 $2.14 ~$2.00 Peer I Peer F Peer H Peer G Peer C Peer J Peer K Peer D Peer A Peer E Peer B PDC PF (1) Source: FactSet, equity research and company filings. Note: CPE presented pro forma for its acquisition of CRZO, excluding synergies. G&A reflects cash and non-cash expenses and is adjusted to included capitalized G&A where applicable, based on 2018 actual capitalized G&A as a % of total G&A. Peers include: CDEV, CPE, JAG, MTDR, OAS, PE, QEP, SM, WPX, XEC, XOG November 2019 12 2020e G&A ($ / Boe)(1) Peer-Leading Cash + Non-Cash G&A Structure $3.28 - SRC Merger $3.10 $2.81 ~$0.42/Boe - Partnerships ~$0.25/Boe - DE Midstream - Activism ~$0.35/Boe - Activism - Partnerships - Severance - Insurance Credit Steady Improvements to Quarterly G&A/Boe 2019 G&A Breakdown ($/Boe)

Financial Overview – Leverage, Liquidity & Hedge Position Overview As of September 30, 2019 (millions) (1) Anticipate 2019 FCF of $0 - $30 million; (2) Assumes weighted-average floor prices (PDC only) November 2019 13 Debt Maturity Schedule $1,500 Revolver – Commitment Level $1,250 $1,000 $750 Notes $500 $250 $0 20192020202120222023202420252026 5.75% Senior 6.125% Senior 1.125% Convertible Notes Notes $97mm Leverage and Liquidity •TTM leverage ratio of 1.5x •Total liquidity of ~$1.2 billion -PDC borrowing base reaffirmed at $1.6 bn (October 2019) -Pro forma borrowing base approved to increase to $2.1 bn (subject to SRC acquisition closing) •~$97 million drawn on revolver -3Q19 FCF ~$40 million -Anticipate generating $110 - $150 million FCF in 4Q19(1) Stock Repurchase Program •~4.7 million shares repurchased YTD ($155 million) -~1.2 million shares repurchased in 3Q ($40 million) Hedge Portfolio •9.8 MMBbls 2020 oil hedged at ~$60/Bbl(2)

SCOTT REASONER Chief Operating Officer

3rd Operations – Quarter Highlighted by Reduced Well Costs 138,000 Production (Boe/d) 13% Oil Production Increase (3Q19 v 3Q18) Delaware Basin ~36,000 net acres(2) ~34,500 Boe/d (42% oil) 4 spuds & 4 TILs $41 MM capital investment Core Wattenberg ~96,000 net acres(1) ~103,500 Boe/d (37% oil) 26 spuds & 43 TILs $123 MM capital investment • • • • • • • • $1,150 DE Well Costs ($/Lateral ft.) (1) Niobrara & Codell only; Does not reflect pending SRC Energy acquisition (2) Anticipate YE19 net acreage of ~33,000. November 2019 15

Operations – Strong Sequential Production Growth Contributes to Reduced LOE Successfully achieving target LOE of less than $3/Boe • Sequential production growth and reduced non-operated activity deliver LOE of $2.87/Boe • Optimized field/contract labor in Wattenberg offsets night time monitoring and keeps field-wide LOE at $2.51/Boe LOE ($/Boe) $3.50 138,000 136,500 $3.27 $3.00 $2.50 $2.00 3Q18 4Q18 1Q19 2Q19 3Q19 (1) Expected production decline consistent with previous guidance November 2019 16 $3.06$3.14 $2.87 $2.76 Reiterate FY19 production range of 48-50 MMBoe •Sequential Delaware production growth of 11% in 3Q -Expect production decline in 4Q due to lack of TILs(1) •DJ volumes negatively impacted in 3Q by third-party midstream constraints and residue & NGL takeaway near capacity -Anticipate modest DJ growth in 4Q to offset Delaware declines Production (Boe/d) 150,000 100,000 50,000 3Q184Q181Q192Q193Q19 128,000125,000 110,000

Delaware Basin – Capturing Efficiencies Throughout 2019 • 20+% improvement in 2019 drill times compared to 2018 • 3Q19 drilling cost per lateral foot is 31% better than 3Q18 • 4-well Buckskin pad (3Q19 TIL): - - - Avg. peak 30-day IP of 225 Boe/1,000’ 47% oil Avg. D&C costs of $1,150/lateral ft. $650 $605 $590 $565 2017 2018 North Central 2019 2017 2018 Block 4 2019 November 2019 17 $480 $405 Consistent Improvement in Drilling Costs per Lateral Foot Across Entire Position Year-Over-Year Drilling Cost Improvements ($/lateral ft.)

Delaware Basin – Peer-Leading Cost Structure with Upside in 2020 • 2020 focus on pad drilling in Block 4 -Currently project 25-30 spuds and TILs • Line of sight on 10-15% year-over-year improvement in D&C costs in 2020 - Equates to anticipated $1 - $1.5 million per well savings compared to initial 2020 assumptions $1,610 $1,471 $1,425 $1,390 $1,350 $1,283 $1,242 $1,211 $1,191 $1,150 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 PDCE Peer 7 Peer 8 PDCE 3Q (1) Source: RSEG, 10/3/19, company disclosures. Peers include: JAG, CDEV, MTDR, ROSE, CRZO, HKRS, WPX, XEC November 2019 18 Top-Tier 2019 Drilling & Completion costs per lateral foot 2019 D&C Costs ($/lateral ft.)(1)

Wattenberg – Improving Run-Times and Upcoming Expansion Offer Upside • High line pressures reduce oil productivity on new and legacy wells Fought elevated line pressures through most of 3Q -Delayed Plant 11 start-up (August) and unplanned plant downtime (September) Recent improvements in line pressures support higher oil mix • • PDC Volumes vs Kersey Line Pressure 350 350 100 100 PDC Gross Volume Kersey Line Pressure (1) Source: DCP Midstream 2Q Earnings call (8/7/19); (2) Anticipates limitations to total capacity utilization until Cheyenne Connector is in-service in 1H20 November 2019 19 PDC Gross Gas on DCP (MMcf/d) Kersey Line Pressure (psi) Plant 11 St art-Up DCP Projected Processing & Bypass Expansion Timeline(1) Aka Energy processes/offloads 75-80 MMcf/d of PDC volumes Upcoming DJ Basin Takeaway Expansions •Front Range NGL line Expansion (FREX) (Line Fill has Begun) -4Q19 – 40,000 Bbls/d to Mt. Belvieu -1Q20 – 60,000 Bbls/d to Mt. Belvieu •White Cliffs crude-to-NGL line conversion (Line Fill has Begun) -4Q19 – 90,000 Bbls/d to DCP’s Southern Hills to Mt. Belvieu •Cheyenne Connector residue pipeline (Construction Underway) -1H20 – 600 MMcf/d to Cheyenne Hub Throughput (MMcf/d) Details 1,100 Current capacity (1H19) 200 Plant 11 – Start-up in August 2019(2) 100 Plant 11 associated bypass – anticipated 4Q19(2) 225 DCP/WES agreement – Latham II – anticipated in-service mid-2020 50 DCP current temporary offloads ~1,700 Mid-Year 2020 - Anticipate PDC pro forma utilize ~40-50% of system

Wattenberg – Committed to Working Alongside COGCC and CDPHE CDPHE Study • 2013-2016 air sampling data used to model & predict potential health impacts within 2,000’ of an oil & gas well “The study shows short-term exposures…during worst-case weather and emission conditions may cause negative short-term health effects. Based on the limitations of the modeling study, additional assessment is needed to evaluate real world circumstances.” What Does it Mean for PDC? • COGCC, CDPHE, and industry will work together to: -Gather site specific and relevant air monitoring data -Update best management practices (BMPs) to be implemented on permits within 2,000’ of a building COGCC will provide greater scrutiny on permits within 2,000’ of a building prior to approving -This level of scrutiny is currently applied to permits within 1,500’ of a building • November 2019 20 PDC Development Plan •Anticipate exiting 2019 with ~150 DUCs •Current approved permits cover entire 2020 drilling program and 2021 TIL activity •PDC has received permits within 1,500’ of building units (under more scrutiny & former BMPs)

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

Financial Guidance – 2019 Full-Year Guidance 2019 Guidance LOE/Boe $4.00 • • • Production: 48 – 50 MMBoe Capital Investments: $810 – $840 million FCF: $0 – $30 million $2.85 - $3.00 $3.00 2019e Commodity Mix $2.00 Price Realizations (% NYMEX) (ex. TGP) Oil: Gas: NGL: 90-95% 40-45% 20-25% $1.00 ~22% $-2016 2017 2018 2019e 0% TGP/Boe G&A/Boe ~38% $1.50 $6.00 Oil Natural Gas NGLs $0.90 - $1.00 $1.00 $4.00 $3.00-$3.20 $0.50 $2.00 $-$- 2016 2017 2018 2019e 2016 2017 2018 2019e November 2019 23

Reconciliation of Non-U.S. GAAP Financial Measures Adjusted Cash Flows from Operations and Free Cash Flow (Deficit) Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Adjusted cash flows from operations and free cash flow (deficit): Net cash from operating activities Changes in assets and liabilities Adjusted cash flows from operations Capital expenditures for development of crude oil and natural gas properties Change in accounts payable related to capital expenditures Free cash flow (deficit) $ 233.5 (31.1) $ 197.0 4.1 $ 675.7 (73.8) $ 577.8 (2.5) 202.4 (237.8) 201.1 (252.9) 601.9 (780.6) 575.3 (685.5) 74.2 (19.1) 57.7 (91.4) $ 38.8 $ (70.9) $ (121.0) $ (201.6) Adjusted Net Income (Loss) Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Adjusted net income (loss): Net income (loss) (Gain) loss on commodity derivative instruments Net settlements on commodity derivative instruments Tax effect of above adjustments Adjusted net income (loss) $ 15.9 (54.9) 1.8 12.7 $ (3.4) 94.4 (48.1) (11.1) $ (35.7) 87.9 (19.8) (16.3) $ (176.8) 257.8 (90.5) (40.1) $ (24.5) $ 31.8 $ 16.1 $ (49.6) Earnings per share, diluted (Gain) loss on commodity derivative instruments Net settlements on commodity derivative instruments Tax effect of above adjustments Adjusted earnings per share, diluted $ 0.25 (0.87) 0.03 0.20 $ (0.05) 1.43 (0.73) (0.17) $ (0.55) 1.35 (0.30) (0.25) $ (2.68) 3.91 (1.37) (0.61) $ (0.39) $ 0.48 $ 0.25 $ (0.75) November 2019 24

Reconciliation of Non-U.S. GAAP Financial Measures Adjusted EBITDAX Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Net income (loss) to adjusted EBITDAX: Net income (loss) (Gain) loss on commodity derivative instruments Net settlements on commodity derivative instruments Non-cash stock-based compensation Interest expense, net Income tax expense (benefit) Impairment of properties and equipment Exploration, geologic and geophysical expense Depreciation, depletion and amortization Accretion of asset retirement obligations Loss on sale of properties and equipment Adjusted EBITDAX $ 15.9 (54.9) 1.8 5.9 17.8 10.7 0.2 0.2 171.8 1.4 $ (3.4) 94.4 (48.1) 5.6 17.4 (3.9) 1.5 1.0 147.5 1.2 $ (35.7) 87.9 (19.8) 18.1 53.7 (4.2) 37.0 3.5 491.8 4.5 $ (176.8) 257.8 (90.5) 16.4 52.2 (53.8) 194.2 4.6 410.0 3.8 43.9 2.1 9.6 3.2 $ 214.7 $ 215.3 $ 646.4 $ 621.1 Cash from operating activities to adjusted EBITDAX: Net cash from operating activities Interest expense, net Amortization of debt discount and issuance costs Exploration, geologic and geophysical expense Other Changes in assets and liabilities Adjusted EBITDAX $ 233.5 17.8 (3.4) 0.2 (2.3) $ 197.0 17.4 (3.1) 1.0 (1.1) $ 675.7 53.7 (10.1) 3.5 (2.6) $ 577.8 52.2 (9.5) 4.6 (1.5) (31.1) 4.1 (73.8) (2.5) $ 214.7 $ 215.3 $ 646.4 $ 621.1 November 2019 25

Reconciliation of Non-U.S. GAAP Metrics Beginning in 3Q19, the Company modified its adjusted EBITDAX reconciliation to exclude (Gain) loss on sale of properties and equipment Net income (loss) to adjusted EBITDAX (in millions): 3Q18 4Q18 1Q19 2Q19 3Q19 Net income (loss) (Gain) loss on commodity derivative instruments Net settlements on commodity derivative instruments Non-cash stock-based compensation Interest expense, net Income tax expense (benefit) Impairment of properties and equipment Exploration, geologic and geophysical expense Depreciation, depletion and amortization Accretion of asset retirement obligations (Gain) loss on sale of properties and equipment Adjusted EBITDAX $ (3.4) 94.4 (48.1) 5.6 17.4 (3.9) 1.5 1.0 147.5 1.2 $ 178.9 (403.0) (25.0) 5.4 18.1 59.1 264.2 1.6 149.8 1.3 $ (120.2) 190.1 (8.5) 4.7 17.0 (37.4) 7.9 2.6 151.4 1.6 $ 68.5 (47.3) (13.2) 7.6 18.9 22.6 29.0 0.6 168.5 1.6 $ 15.9 (54.9) 1.8 5.9 17.8 10.7 0.2 0.2 171.8 1.4 2.1 (2.8) (0.4) (33.9) 43.9 $ 215.3 $ 247.6 $ 208.8 $ 222.9 $ 214.7 November 2019 26

Commonly Used Definitions Bbl – Barrel Boe – Barrel of oil equivalent EBITDAX November 2019 27 AMI – Area of Mutual InterestGross 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 Btu – British thermal unitLOE – Lease operating expenses CAGR – Compound Annual Growth RateMM – Million CFPS – Cash flow per shareMMcf – Million cubic feet CWC – Completed well costRoR – Rate of Return D&C – Drilling and CompletionsSRL/MRL/XRL – Standard-, Mid-and Extended-reach lateral EBITDAX – Earnings before interest, taxes, depreciation, amortization and exploration SWD – Salt-water disposal EUR – Estimated Ultimate RecoveryTGP – Transportation, gathering and processing FCF – Free Cash Flow (cash flows from operations less capital investments)TIL – Turn-in-line FCF Margin – Free cash flow divided by capital investments