Filed by: PDC Energy, Inc.

(Commission File No.: 001-37419)

Pursuant to Rule 425 under the Securities Act of 1933, as amended

and deemed filed pursuant to 14a-12

under the Securities Exchange Act of 1934, as amended

Subject Company: SRC Energy Inc.

(Commission File No.: 001-35245)

Date: September 4, 2019

 


 

 

Barclays ceo energy conference September 2019

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Forward-Looking Statements 2 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 relates to a proposed business combination between PDC and SRC. In connection with the proposed transaction, PDC intends to file with the Securities and Exchange Commission (the “SEC”) a registration statement on Form S-4 that will include a joint proxy statement of PDC and SRC that also constitutes a prospectus of PDC. Each of PDC and SRC also plan 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. Any definitive joint proxy statement/prospectus of PDC and/or SRC (if and when available) will be mailed to shareholders of PDC and/or SRC, as applicable. 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 BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT 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://www.pdce.com 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 http://www.srcenergy.com 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 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 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. Cautionary Statement Regarding Forward-Looking Information This document contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than historical facts, that address activities that PDC or SRC assumes, plans, expects, believes, intends or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events, including this proposed transaction. These forward-looking statements involve certain risks and uncertainties that could cause the results to differ materially from those expected by the management of PDC or SRC. These include the expected timing and likelihood of completion of the proposed transaction, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed transaction that could reduce anticipated benefits or cause the parties to abandon the proposed transaction, the ability to successfully integrate the businesses, the occurrence of any event, change or other circumstances that could give rise to the termination of the merger agreement, the possibility that stockholders of PDC may not approve the issuance of new shares of common stock in the proposed transaction or that shareholders of SRC may not approve the merger agreement, the risk that the parties may not be able to satisfy the conditions to the proposed transaction in a timely manner or at all, risks related to disruption of management time from ongoing business operations due to the proposed transaction, the risk that any announcements relating to the proposed transaction could have adverse effects on the market price of PDC’s securities or SRC’s securities, the risk of any unexpected costs or expenses resulting from the proposed transaction, the risk of any litigation relating to the proposed transaction, the risk that the proposed transaction and its announcement could have an adverse effect on the ability of PDC and SRC to retain customers and retain and hire key personnel and maintain relationships with their suppliers and customers and on their operating results and businesses generally, the risk the pending proposed transaction could distract management of both entities and they will incur substantial costs, the risk that problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected, the risk that the combined company may be unable to achieve synergies or other anticipated benefits of the proposed transaction or that it may take longer than expected to achieve those synergies or benefits and other important factors that could cause actual results to differ materially from those projected. All such factors are difficult to predict and are beyond PDC’s or SRC’s control, including those detailed in PDC’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K that are available on its website at http://www.pdce.com and on the SEC’s website at http://www.sec.gov, and those detailed in SRC’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K that are available on SRC’s website at http://www.srcenergy.com and on the SEC’s website at http://www.sec.gov. All forward-looking statements are based on assumptions that PDC or SRC believe to be reasonable but that may not prove to be accurate. Any forward-looking statement speaks only as of the date on which such statement is made, and PDC and SRC undertake 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. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. 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. Sept. 2019

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PDC Energy – PDC + SRC = Top-Tier Mid-Cap E&P Company Expected to close 4Q19, subject to customary closing conditions & regulatory approvals; including approval by both PDC & SRC shareholders. Sept. 2019 3 (1) As of 8/28/19; (2) Niobrara & Codell only. (3) Net acreage of ~36,000 reflects recently divested ~6,500 net acres expected to expire in 2019 for ~$35 million. $2.0B 545 $3.2B Market Cap(1) Enterprise Value(1) YE18 Proved Reserves (MMBoe) Delaware Basin ~36,000 net acres(3) 120 MMBoe YE18 proved reserves 31,500 Boe/d (2Q19) Pro Forma Core Wattenberg ~182,000 net acres(2) 730 MMBoe YE18 proved reserves 166,000 Boe/d (2Q19) $3.2B 850 $5.1B Market Cap(1) Enterprise Value(1) YE18 Proved Reserves (MMBoe) PDC Standalone / PDC + SRC Pro Forma

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PDC + SRC – The Right Combination at the Right Time COMBINATION OVERVIEW Creates a premier E&P company with size, scale and financial strength to deliver value in the new E&P paradigm Forms a champion of Colorado energy Consolidated, contiguous position in Core Wattenberg Resilient asset base in two of the premier U.S. onshore plays Multi-basin platform in the DJ and Delaware Basins Leading free cash flow yield supports upsized share repurchase Project ~$800 million of combined FCF from 2H19 through 2021 Industry-leading operational and financial metrics Clear and achievable G&A synergies Accretive to key financial metrics Free cash flow per share, CROCI, NAV Maintains strong balance sheet All-Stock transaction with significant shareholder overlap Sept. 2019 Expected to close 4Q19, subject to customary closing conditions & regulatory approvals; including approval by both PDC & SRC shareholders. (1) Source: FactSet and Company filings; SRC Enterprise Value based on 0.158x exchange ratio; PDC share count of ~63.7 million shares outstanding Pro forma Enterprise Value ($bn)(1) $3.2 $1.9 $5.1 Wattenberg Net Acres ~96,000 ~86,000 ~182,000 Delaware Net Acres ~36,000 - ~36,000 2Q19 Production (Mboe/d) 136.5 60.8 197.3 TTM Leverage Ratio 1.4x 1.3x 1.3x Weld County PDC Acreage SRC Acreage 4 Core Wattenberg

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PDC + SRC – Transaction Overview All stock transaction valued at $1.7bn, including the assumption of $685mm of SRC net debt SRC shareholders will receive a fixed exchange ratio of 0.158 PDC common shares for each share of SRC common stock they own Exchange ratio implies a price of $3.99 per SRC share based on PDC’s closing price of $25.25 on August 23, 2019, which implies a: Premium of 6.8% compared to the 30-day average exchange ratio of .148x PDC Management team will lead combined company Combined company Board will consist of nine directors SRC will receive two Board seats in the pro forma company Expected to close 4Q19 Subject to customary closing conditions and regulatory approvals, including the approval by both PDC and SRC shareholders Sept. 2019 Expected to close 4Q19, subject to customary closing conditions & regulatory approvals; including approval by both PDC & SRC shareholders. Clear Roadmap to Completion Pro forma Leadership and Governance Low Premium and All-Stock Consideration 5

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PDC + SRC – Combined Company Strengthens Strategic Priorities Sept. 2019 Expected to close 4Q19, subject to customary closing conditions & regulatory approvals; including approval by both PDC & SRC shareholders. (1) FCF Margin defined as free cash flow divided by mid-point of capital investment range; (2) Assumes completion of share repurchase program. PRIORITIES Sustainable FCF Financial & Operational Discipline Return on Capital Solid Growth 1 2 3 4 Transaction positions PDC for long-term success 2H19 – 2021 estimated FCF generation of ~$800mm Commitment to return capital to shareholders through expanded $525mm stock buyback program Project industry-leading cost structure with anticipated G&A/Boe of ~$2.00 & LOE/Boe of ~$2.80 in 2020e Expect ~$40mm of 2020 G&A synergies; additional $10mm in 2021 Accretive to FCF Margin(1) – anticipate ~20% in 2020 Accretive to CROCI – anticipate greater than 15% in 2020 Pro forma Company generates multi-year debt-adjusted CFPS growth rate greater than 10% Production per share growth of greater than 10%(2) 6

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PDC + SRC – A Colorado Champion with a Culture of Responsible Development Clear leader in Colorado oil & gas industry headquartered in Denver Combined company expected to be the 2nd largest producer in DJ Basin ~182,000 combined Wattenberg acres (~100% in Weld County) Continuous focus on health, safety and the environment Consistent, transparent communication and engagement with our communities Company-wide focus on volunteerism and charitable giving Sept. 2019 Expected to close 4Q19, subject to customary closing conditions & regulatory approvals; including approval by both PDC & SRC shareholders. (1) Source: Company filings 2Q19 DJ Basin Daily Production (MBoe/d)(1) Significant amount of contiguous acreage in rural Weld County expected to lead to greater value creation 7 301 166 145 105 83 61 31 24 OXY PDC + SRC NBL PDC XOG SRC HPR BCEI

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PDC Strategic rationale

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PDC Pro Forma – Premier E&P with Increased Size, Scale & Financial Strength Increased size and scale within DJ Basin strengthens relationships with midstream and service providers Continued emphasis on financial discipline highlighted by low leverage and ample liquidity Increased scale and conservative financial profile expected to benefit credit profile and lower corporate cost of capital Sept. 2019 Expected to close 4Q19, subject to customary closing conditions & regulatory approvals; including approval by both PDC & SRC shareholders. (1) Source: FactSet, equity research and company filings. Note: CPE presented pro forma for its acquisition of CRZO, excluding synergies. Peers include: CDEV, CPE, JAG, MTDR, OAS, PE, QEP, SM, WPX, XEC, XOG Significant increase in size and scale 2020e EBITDAX (rounded to nearest $100mm)(1) Strong balance sheet with ample liquidity YE 2020e Net Debt / 2020e EBITDAX(1) 9 Peer Median = 2.1x 3.0x 2.4x 2.3x 2.2x 2.1x 2.1x 1.8x 1.3x 1.1x 1.1x 1.0x ~ 1.0x Peer F Peer E Peer H Peer I Peer D Peer G Peer J Peer K Peer A Peer C Peer B PDC PF $1,700 $1,700 $1,600 $1,600 $1,400 $1,100 $1,000 $900 $800 $700 $700 $600 Peer A Peer B PDC PF Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K

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Strong, Sustainable Free Cash Flow PDC Pro Forma – Leading FCF Generation with Commitment to Shareholder Returns Anticipate generating ~$800 million of FCF between 2H19 and year-end 2021 at $55/Bbl & $2.70/Mcf 2020e FCF Yield of ~11% (pro forma Market Cap of ~$2.6bn) Share repurchase program increased to $525 million with target completion date of year-end 2021 Represents 15-20% of implied pro forma Market Cap $125mm of program executed year-to-date Remaining $400mm represents ~50% of projected FCF generated between 2H19 and YE21 Sept. 2019 Expected to close 4Q19, subject to customary closing conditions & regulatory approvals; including approval by both PDC & SRC shareholders. (1) Source: FactSet, equity research and company filings. Note: CPE presented pro forma for its acquisition of CRZO, excluding synergies. Peers include: CDEV, CPE, JAG, MTDR, OAS, PE, QEP, SM, WPX, XEC, XOG (2) PDC pro forma assumes $55/Bbl and $2.70/Mcf NYMEX; S&P E&P index includes: APA, COG, COP, CXO, DVN, EOG, FANG, HES, MRO, NBL, PXD & XEC; PDC comparable peers are same is shown in FCF bar chart. 2020e FCF yield vs. S&P 500 and S&P E&P Index(2) 2020e FCF ($mm)(1) 10 Peer Median = $24mm $297 ~$275 $204 $171 $142 $61 $24 ($63) ($64) ($67) ($161) ($190) Peer B PDC PF Peer C Peer A Peer G Peer D Peer F Peer H Peer K Peer E Peer I Peer J ~11% 7% 6% 2% PDC pro forma S&P E&P index median S&P 500 median PDC peer companies

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PDC Pro Forma – Highly-Efficient, Peer-Leading Cost Structure Project NPV of G&A synergies of ~$300 million through optimization and elimination of corporate redundancies Estimate immediate synergies of $40 million in 2020 leading to G&A of ~$2.00/Boe Anticipate an incremental $10 million of synergies in 2021 (post-integration) Anticipate peer-leading 2020 cost structure – combined G&A + LOE total of less than $5.00/Boe Approximately 40% lower than peer median combined G&A + LOE of $7.99/Boe Sept. 2019 Expected to close 4Q19, subject to customary closing conditions & regulatory approvals; including approval by both PDC & SRC shareholders. (1) Source: FactSet, equity research and company filings. Note: CPE presented pro forma for its acquisition of CRZO, excluding synergies. G&A reflects cash and non-cash expenses and is adjusted to included capitalized G&A where applicable, based on 2018 actual capitalized G&A as a % of total G&A. Peers include: CDEV, CPE, JAG, MTDR, OAS, PE, QEP, SM, WPX, XEC, XOG Peer-leading operating margins Peer-leading operating margins Peer-Leading Cash + Non-Cash G&A Structure Best-in-Class Lifting Costs Enhance Margins 2020e G&A ($ / Boe)(1) 2020e LOE ($ / Boe)(1) 11 Peer Median = $5.02 Peer Median = $2.97 $7.38 $6.25 $6.18 $5.85 $5.49 $5.02 $4.50 $3.94 $3.61 $3.49 $3.00 ~$2.80 Peer F Peer G Peer D Peer C Peer E Peer I Peer J Peer K Peer A Peer B Peer H PDC PF $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

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PDC Pro Forma – Delivering FCF, Shareholder Returns & Reasonable Growth Sept. 2019 Expected to close 4Q19, subject to customary closing conditions & regulatory approvals; including approval by both PDC & SRC shareholders. Long-term strategy focused on growing and generating sustainable FCF with consistent returns to shareholders Expect to generate ~$800mm of FCF between 2H19 and YE21 Plan to return ~50% of FCF to shareholders through remaining $400mm stock buyback program Remaining FCF expected to be allocated for debt repayment, future shareholder friendly initiatives and/or accretive growth opportunities 2020 Outlook Planned 2020 capital investments between $1.2 and $1.4bn 3 Wattenberg rigs and 2 Delaware rigs 2 full-time Wattenberg completion crews Exit 2020 with ~125 Wattenberg DUCs Anticipate FCF of ~$275mm Expected production of 200,000 to 220,000 Boe/d Does not include potential flush production associated with lower line pressures resulting from DCP system expansion Long-Term Development Plan Continued investment in both Wattenberg and Delaware Target 5-10% long-term production growth rate with significant FCF generation as top priority Continue to utilize DUC management in Wattenberg Wattenberg development plan aligns with upcoming DCP expansions Projected long-term oil mix of 40-42% 12 Significant FCF Generating Ability – ($55/Bbl & $2.70/Mcf NYMEX) ~$275 ~$325 $185 - $215

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PDC Pro Forma – Delivering Strong Value Expected to close 4Q19, subject to customary closing conditions & regulatory approvals; including approval by both PDC & SRC shareholders. Sept. 2019 (1) Does not include unconditional payment of $82 million due June 2020 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 $800 million at $55/Bbl WTI oil through 2021 Corporate Responsibility focused on sustainable operations with safe and responsible development of our assets ~$800MM $525MM ~$4.80 2H2019 – 2021 Free Cash Flow (Assuming $55/$2.70 NYMEX) Combined 2020 G&A plus LOE per Boe (Pro forma SRC Combination) Stock Repurchase Program ($125MM Executed Year-to-Date; YE 2021 Target Completion) 13

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Delaware overview

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Delaware Basin – Primary Focus in Two Oil-Rich Areas Sept. 2019 15 (1) Net acreage of ~36,000 reflects recently divested ~6,500 net acres expected to expire in 2019 for ~$35 million. 36,000 120 ~Net Acres(1) YE18 Proved Reserves (MMBoe) ~31,500 Boe/d 27% Y/Y Growth 10 Spuds 8 TILs $3.76 LOE/Boe 2Q19 Results N. Central Block 4 Pecos Reeves County Loving County

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Delaware Basin – Steady Progress Towards Development Mode Capital investment of ~$350 MM Drilling & Completion capital investments of ~$300 million ~$30 million of midstream investment in 1H ~$20 million for leasing and non-ops Reduced rig count from 3 to 2 in June Plan to run 2 rigs through 2020 Idled completion crew in early July ~5 TILs in 3Q19 with 0 expected in 4Q19 Anticipate modest sequential production growth in 3Q19 and modest declines in 4Q19 Inventory of ~365 identified locations with average lateral length of ~7,900’(1) Sept. 2019 (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) 16 2018 SRL MRL XRL 2019 $0 $4 $8 $12 $16 2018 2019e millions Costs per Well – MRL/XRL

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Delaware Basin – Systematic Drilling Improvements 2019 activity has been largely focused in North Central area Typically more difficult drilling in Block 4 due to total depth and geologic properties North Central averages 10-20% fewer drill days per well 100% of planned 2020 activity is in Block 4 Argentine S5 – 3rd Bone Spring 30-day peak IP of ~175 Boe/1,000’ (68% oil) Sept. 2019 17 ~33% Improvement MRL XRL ~33% Improvement $600 $715 $535 $485 $405 $0 $300 $600 $900 2Q18 3Q18 4Q18 1Q19 2Q19 Average Drilling Cost ($ per Lateral Ft.) 34 33 30 27 23 0 10 20 30 40 2Q18 3Q18 4Q18 1Q19 2Q19 Average Drill Days (Spud to Rig Release) 0 10 20 30 40 50 2018 2019 2018 2019 Average Drilling Days by Area (Spud to Rig Release) Block 4 N. Central

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PDC + SRC – The Right Combination at the Right Time Sept. 2019 Expected to close 4Q19, subject to customary closing conditions & regulatory approvals; including approval by both PDC & SRC shareholders. Creates a premier E&P company with enhanced size and scale Best in class Wattenberg operator with contiguous, core acreage Commitment to return capital to shareholders and protect balance sheet Strong Delaware position benefiting from continued efficiency-gains Leading free cash flow generation Colorado energy champion Focus on highly efficient, peer-leading cost structure 18

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appendix

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PDC ENERGY – Corporate Social Responsibility Sept. 2019 20 COMMUNITY OUTREACH EMPLOYEES MATTER SAFE OPERATIONS

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PDC Energy – Strong Balance Sheet with Low Leverage and Ample Liquidity Leverage and Liquidity TTM leverage ratio of 1.4x Total liquidity of ~$1.3 billion Borrowing base increased to $1.6 billion Maintained commitment level of $1.3 billion ~$30 million drawn on revolver (6/30/19) 2Q19 outspend of ~$70 million Anticipate generating $160 - $190 million FCF in 2H19 Stock Repurchase Program ~3.7 million shares repurchased YTD ($125 million) 3.1 million shares repurchased in 2Q ($105 million) Hedge Portfolio ~60% of 2H19e oil production hedged at ~$55/Bbl(1) 9.8 MMBbls 2020 oil hedged at ~$60/Bbl(1) ~15% of 2H19e gas production hedged at ~$2.90/MMBtu(1) ($0.68) CIG basis swaps on ~20% of 2H19e gas production As of June 30, 2019 Sept. 2019 21 (1) Assumes weighted-average floor prices 5.75% Senior Notes

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PDC Energy – Implementing Key Steps to Deliver Shareholder Value Creation Focused on Timely Execution and Commitment to Capital Discipline OPERATIONS – Delivering on capital discipline Decreased full-year capital investment range to $810 – $840 million(1), a decrease of $15 million at the mid-point from prior guidance Reducing Wattenberg rig count from 3 to 2 in September & reduced Delaware rig count from 3 to 2 in June Increased full-year production range to 48 – 50 MMBoe FINANCIAL – Improving position with each passing quarter Implemented payroll and non-payroll G&A cost reduction program – Anticipate 2H19 run-rate of $2.60 - $2.80 per Boe and 2020 Outlook of $2.50 - $2.75 per Boe Anticipate generating approximately $300 million of FCF between 2H19 and year-end 2020 Successfully executed more than 60% of stock buyback program (utilized $125 million to repurchase ~3.7 million shares YTD) BUSINESS DEVELOPMENT – Proactively generating significant value ~$264 million received from Delaware midstream divestitures (additional $82 million due in June 2020) ~$35 million received for divestiture of ~6,500 net Delaware acres (previously disclosed to expire in 3Q19) Agreed to settlement terms for final two Partnerships (anticipated completion prior to year-end 2019) Sept. 2019 22 (1) Excludes corporate capital

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PDC Energy – Updated 2019 Plan Indicates Strong 2nd Half Performance $55/Bbl WTI and $2.70/Mcf NYMEX Prices 2019 Updated Guidance Overview Full-year plan generates $0 – 30MM FCF at $55/bbl oil Anticipate generating $160 - $190MM FCF in 2H19 Full-year capital investments – ($810 - $840MM) Reduced mid-point of full-year range by $15MM Anticipate 3Q capex below 2Q driven by reduced DE rig count and fewer DE completions Full-year production growth of ~20% to 48 – 50 MMBoe Anticipate modest 3Q19 Wattenberg production growth compared to 2Q19 Expect modest sequential growth in Delaware (3Q19 v 2Q19) Anticipate continued operating cost improvements throughout 2H19 Expect LOE/Boe < $3 in 3Q19 & 4Q19 Sequential G&A/Boe improvements expected in 3Q19 Anticipate G&A of $2.60 - $2.80/Boe in 2H19 Sept. 2019 23 (1) Does not include corporate capital of ~$20MM primarily related to installation of Enterprise Resource Planning systems Oil & Gas Investment ($780 - $810MM) Adj. Cash Flow from Ops ($825 - $875MM) Capital Investment(1) ($810 - $840MM) DE Midstream (~$30MM)

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PDC Energy – Updated 2019 Full-Year Guidance Sept. 2019 24 2019 Guidance Production: 48 – 50 MMBoe Capital Investments: $810 – $840 million Price Realizations (% NYMEX) (ex. TGP) Oil: 90-95% Gas: 40-45% NGL: 20-25% $3.00- $3.20 $0.90 - $1.00 $2.85 - $3.00 ~40% ~22% ~38% $- $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

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Core Wattenberg – Prolific Asset in Development Mode Sept. 2019 25 (1) Niobrara and Codell only. ~105,000 Boe/d 34% Y/Y Growth 43 Spuds 27 TILs $2.46 LOE/Boe 96,000 425 ~Net Acres(1) YE18 Proved Reserves (MMBoe) 2Q19 Results Kersey Area Plains Area Prairie Area

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Core Wattenberg – 2019 Plan Significantly Enhances Efficiencies Capital investment of ~$475 MM Plan to reduce rig count from 3 to 2 in September 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 Modest production growth expected in 3Q and 4Q 2H19 performance largely dependent on DCP Plant 11 at ~50% capacity + associated bypass expected to through year-end 2019(1) Sept. 2019 (1) Source: DCP 2Q earnings call 8/7/19; (2) Reflects impact of 2018 strategic acreage trade. 139 TILs 110-120 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 26 2018 SRL MRL XRL 2019 0 2,000 4,000 6,000 8,000 YE17 2018 TILs YE18 Net WI Lateral Feet (thousands)

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PDC Pro Forma – 3rd Party Midstream Expansions Improve Operating Outlook DCP Projected Processing & Bypass Expansion Timeline(1) Aka Energy currently processes/offloads an incremental 75-80 MMcf/d of PDC volumes Upcoming DJ Basin Takeaway Expansions Front Range NGL line Expansion (FREX) 4Q19 – 100,000 Bbls/d to Mt. Belvieu White Cliffs crude-to-NGL line conversion 4Q19 – 90,000 Bbls/d to DCP’s Southern Hills to Mt. Belvieu Cheyenne Connector residue natural gas pipeline Late 1Q20 – 600 MMcf/d to Cheyenne Hub (pending FERC approval) Sept. 2019 (1) Source: DCP Midstream 2Q Earnings call (8/7/19); (2) Anticipates potential minor limitations to total capacity utilization until Cheyenne Connector is in-service Plant 10 Grand Parkway Plant 11 27 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 in summer 2020 50 DCP current temporary offloads ~1,700 Mid-Year 2020 - Anticipate PDC pro forma utilize ~40-50% of total system PDC Acreage SRC Acreage Additional compression 2018-19 Processing Plant Expansions DCP - Compression Processing Plant Aka - Latham II WES -

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CORE STRATEGIC PRIORITIES – Built to Deliver Sustainable, Long-Term Value Sept. 2019 28 Long-Term Value Creation 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

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EXECUTIVE COMP. – New Metrics Demonstrate Commitment to Capital Efficiency Sept. 2019 50% Qualitative & 50% Quantitative 29 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

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PDC Pro Forma – Value-Enhancing Transaction Across the Board Sept. 2019 Creates a premier E&P company with enhanced size and scale Combination creates a new E&P sector leader built for long-term success with materially enhanced financial and operating scale Best in class Wattenberg operator with contiguous, core acreage Second largest DJ Basin producer with a consolidated acreage position in Weld County to enable reduced surface usage through increased opportunities for long-lateral development Leading free cash flow generation Industry-leading capital efficiency drives best-in-class combination of FCF generation and FCF growth Commitment to return capital to shareholders and protect balance sheet Expect to return ~50% of $800mm FCF generated through 2021 to shareholders through share repurchase plan with flexibility for incremental return programs Strong Delaware position benefiting from continued efficiency-gains ~36,000 net acreage position in Delaware delivers production growth, upside and basin diversification Focus on highly efficient, peer-leading cost structure Project 2020 G&A synergies of ~$40mm resulting in expected 2020 G&A of ~$2.00/Boe; Anticipate an incremental $10 million of G&A synergies post-integration (2021) with an ongoing focus on cost structure Colorado energy champion Positioned to work alongside key stakeholders through ongoing community and government outreach, shared midstream providers and service companies 30

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Operations – Strong Sequential Production Growth Contributes to Reduced LOE Consistent level of Delaware TILs leads to sequential production increase of 25+% Anticipate more modest growth in 3Q as full-year TIL activity was completed in July Wattenberg volumes benefit from accelerated completion/TIL pace DCP beginning to take incremental volumes on Plant 11 Successfully achieved target LOE of less than $3 per Boe Strong sequential production growth in both basins and reduced midstream expense help drive lower rate Project LOE per Boe of less than $3 in 2H19 Optimized field/contract labor to align with modified development pace Sept. 2019 31 20% Improvement 30+% Increase 103,000 110,000 128,000 125,000 136,500 50,000 100,000 150,000 2Q18 3Q18 4Q18 1Q19 2Q19 Production ( Boe/d) $3.44 $3.27 $3.06 $3.14 $2.76 $2.00 $2.50 $3.00 $3.50 $4.00 2Q18 3Q18 4Q18 1Q19 2Q19 LOE ($/Boe)

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Financial Results – Detailed G&A Breakdown Reduced 2019 G&A guidance to $3.00 - $3.20 per Boe Includes cash and non-cash G&A Revised guidance includes all expenses related to: Shareholder activism Settlement of final Partnerships net of insurance credit Delaware midstream divestitures Reduction-in-force (severance) Reduced corporate headcount by ~15% in 2Q19 Anticipate 2H19 G&A of $2.60 - $2.80 per Boe Project 2020 G&A of $2.50 - $2.75 per Boe Sept. 2019 32 $3.53 $3.45 ~$0.25/Boe - DE Midstream - Activism ~$0.35/Boe - Activism - Partnerships Severance Insurance Credit $3.28 $3.10 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 1Q19 2Q19 $ 4.25 $ 3.49 $2.60 - $2.80 $3.00 - $3.20 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 2018 1H19 2H19e 2019e Cash + Non - Cash G&A per Boe

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EVENT IMPACT PDC ACTION Drilling Efficiencies Improvement in Delaware drill times Lower well costs Increased number of wells spuds Reallocate completion dollars to drilling – swap Tinman pad (7 MRLs) for Buckskin pad (4 XRLs) Maintain budgeted number of completions by extending frac holiday in 2H19 Reduce Wattenberg rig count from 3 to 2 Implement DUC management program to increase capital efficiency Decrease anticipated FY19 capital investments and implement corporate cost saving initiatives Completion Efficiencies Currently completing 10+% more stages per day than budgeted in Wattenberg Pull forward Wattenberg production and capital investments earlier in the year High DJ Line Pressures Challenging midstream environment in 1H19 and less than expected benefit from Plant 11 Gassier Wattenberg production mix Decrease to projected oil revenues Slower than expected production ramp in 2H Gas & NGL Price Erosion Widened 2019 differentials at Waha, CIG, Mt. Belvieu and Conway Decrease to projected gas & NGL revenues PDC Energy – Demonstrating Commitment to Capital Discipline Sept. 2019 Full-Year 2019 Capital Investment Range Decreased to $810 million - $840 million(1) 33 (1) Excludes Corporate Capital Reduced DE rig count Fewer DE completions Zero DE midstream $ Reduced WB rig count WB frac holiday extended $282 million $277 million 1Q19 2Q19 3Q19e 4Q19e Quarterly Capital Investment Breakdown Wattenberg Delaware DE Midstream

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Financial Overview – Updated Guidance Indicates Strong 2nd Half of 2019 Metric Previous Guidance Updated Guidance 1H19 Actual 2H19 Estimates (based on midpoints of production & capital) Production (MMBoe) 46 - 50 48 - 50 23.6 24.4 - 26.4 % Oil 41 - 45% ~40% ~40% ~40% Capital Investments (millions) $810 - $870 $810 - $840 $560 $250 - $280 Operating Costs ($/Boe) LOE $2.85 - $3.15 $2.85 - $3.00 $2.94 $2.75 - $3.00 G&A $3.00 - $3.40 $3.00 - $3.20 $3.49 $2.60 - $2.80 TGP $0.80 - $1.00 $0.90 - $1.00 $1.00 $0.85 - $1.00 Price Realizations (% NYMEX)(excl. TGP) Oil 90 - 95% 90 - 95% 93% 90-95% Gas 50 - 55% 40 - 45% 53% 35-40% NGL 30 - 35% 20 -25% 24% 20-25% Adj. CF from Ops. (millions) $880 - $930 $825 - $875 $400 $420 - $450 Free Cash Flow (millions) ~$65 $0 - $30 ($160) $160 - $190 Sept. 2019 2H19 Outlook Reflects $55/$2.70 NYMEX 34 5-10% growth compared to 1H DJ – modest growth in 3Q & 4Q; includes most recent update from DCP Del. – modest growth in 3Q & declines in 4Q Full-year G&A includes expenses related to activism, partnerships & DE midstream Full-year G&A includes cash & non-cash Similar LOE & TGP rates post midstream sale 2H19 commodity price assumptions (NYMEX): WTI - $55/Bbl Gas - $2.70/Mcf Changes to gas/NGL realizations negatively impact Adj. CF by ~$90 million in 2019 (partially off-set by PDC cost-saving initiatives) Ample FCF for stock repurchase program Project YE19 leverage ratio of 1.3x

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Reconciliation of Non-U.S. GAAP Financial Measures Sept. 2019 35 Adjusted Net Income (Loss) Three Months Ended June 30, Six Months End ed June 30, 2019 2018 2019 2018 Adjusted net income (loss): Net income (loss) $ 68.5 $ (160.3 ) $ (51.6 ) $ (173.4 ) (Gain) loss on commodity derivative instruments (47.3 ) 116.1 142.7 163.4 Net settlements on commodity deriva tive instruments (13.2 ) (16.4 ) (21.6 ) (42.4 ) Tax effect of above adjustments 14.5 (23.9 ) (29.0 ) (29.0 ) Adjusted net income (loss) $ 22.5 $ (84.5 ) $ 40.5 $ (81.4 ) Weighted - average diluted shares outstanding 65.9 66.1 66.0 6 6.0 Adjusted diluted earnings per share $ 0.34 $ (1.28 ) $ 0.61 $ (1.23 ) Adjusted Cash Flows from Operations Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 Adjusted cash flows from operations: Net cash from operating activities $ 2 60.4 $ 175.7 $ 442. 2 $ 380.9 Changes in assets and liabilities (53.4) 23.6 (42.7) (6.6 ) Adjusted cash flows from operations $ 207.0 $ 199.3 $ 399. 5 $ 374.3

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Reconciliation of Non-U.S. GAAP Financial Measures Sept. 2019 36 Adjusted EBITDAX Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 Net income (loss) to adjusted EBITDAX: Net income (loss) $ 68.5 $ (160.3 ) $ (51.6 ) $ (173.4 ) (Gain) loss on commodity derivative instruments (47.3 ) 116.1 142.7 163.4 Net settlements on commodity derivative instruments (13.2 ) (16.4 ) (21.6 ) (42.4 ) Non - cash stock - based compensation 7.6 5 .5 12.3 10.8 Interest expense, net 18.9 17.3 35.9 34.7 Income tax expense (benefit) 22.6 (45.3 ) (14.8 ) (49.9 ) Impairment of properties and equipment 29.0 159.5 36.9 192.7 Exploration, geologic and geophysical expense 0.6 0.9 3.3 3.5 Depreciation, depletion and amortization 168.5 135.6 319.9 262.4 Accretion of asset retirement obligations 1.6 1.4 3.1 2.6 Adjusted EBITDAX $ 256.8 $ 214.3 $ 466.1 $ 404.4 Cash from operating activiti es to adjusted EBITDAX: Net cash from operating activities $ 260.4 $ 175.7 $ 442.2 $ 380.9 Interest expense, net 18.9 17.3 35.9 34.7 Amortization of debt discount and issuance costs (3.4 ) (3.1 ) (6.7 ) (6.4 ) Gain (loss) on sale of properties and equipment 33.9 0.4 34.3 (1.1 ) Exploration, geologic and geophysical expense 0.6 0.9 3.3 3.5 Other (0.2 ) (0.5 ) (0. 2 ) (0.6 ) Changes in assets and liabilities (53.4 ) 23.6 (42.7 ) (6.6 ) Adjusted EBITDAX $ 256.8 $ 214.3 $ 466.1 $ 404.4

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