Filed pursuant to Rule 425 under the Securities Act of 1933, as amended, and deemed filed under Rule 14a-12 under the Securities Exchange Act of 1934, as amended Filer: Penn Virginia Corporation Commission File No.: 001-13283 Subject Company: Penn Virginia Corporation Transformational Combination of & Investor Meetings November 13-15, 2018 N Y SE : DN R w w w .d e n b u r y . c o mFiled pursuant to Rule 425 under the Securities Act of 1933, as amended, and deemed filed under Rule 14a-12 under the Securities Exchange Act of 1934, as amended Filer: Penn Virginia Corporation Commission File No.: 001-13283 Subject Company: Penn Virginia Corporation Transformational Combination of & Investor Meetings November 13-15, 2018 N Y SE : DN R w w w .d e n b u r y . c o m

Cautionary Statements No Offer or Solicitation This presentation relates in part to a proposed business combination transaction (the “Transaction”) between Denbury Resources Inc. (“Denbury”) and Penn Virginia Corporation (“Penn Virginia”). This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the Transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended. Important Additional Information In connection with the Transaction, Denbury will file with the U.S. Securities and Exchange Commission (“SEC”) a registration statement on Form S-4, that will include a joint proxy statement of Denbury and Penn Virginia and a prospectus of Denbury. The Transaction will be submitted to Denbury’s stockholders and Penn Virginia’s stockholders for their consideration. Denbury and Penn Virginia may also file other documents with the SEC regarding the Transaction. The definitive joint proxy statement/prospectus will be sent to the stockholders of Denbury and shareholders of Penn Virginia. This document is not a substitute for the registration statement and joint proxy statement/prospectus that will be filed with the SEC or any other documents that Denbury or Penn Virginia may file with the SEC or send to stockholders of Denbury or Penn Virginia in connection with the Transaction. INVESTORS AND SECURITY HOLDERS OF DENBURY AND PENN VIRGINIA ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION WHEN IT BECOMES AVAILABLE AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS. Investors and security holders will be able to obtain free copies of the registration statement and the joint proxy statement/prospectus (when available) and all other documents filed or that will be filed with the SEC by Denbury or Penn Virginia through the website maintained by the SEC at http://www.sec.gov. Copies of documents filed with the SEC by Denbury will be made available free of charge on Denbury’s website at www.denbury.com or by directing a request to John Mayer, Director of Investor Relations, Denbury Resources Corporation, 5320 Legacy Drive, Plano, TX 75024, Tel. No. (972) 673-2383. Copies of documents filed with the SEC by Penn Virginia will be made available free of charge on Penn Virginia’s website at www.pennvirginia.com, under the heading “SEC Filings,” or by directing a request to Investor Relations, Penn Virginia Corporation, 16285 Park Ten Place, Suite 500, Houston, TX 77084, Tel. No. (713) 722-6540. Participants in the Solicitation Denbury, Penn Virginia and their respective directors and executive officers may be deemed to be participants in the solicitation of proxies in respect to the Transaction. Information regarding Denbury’s directors and executive officers is contained in the proxy statement for Denbury’s 2018 Annual Meeting of Stockholders filed with the SEC on April 12, 2018, and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC’s website at http://www.sec.gov or by accessing Denbury’s website at www.denbury.com. Information regarding Penn Virginia’s executive officers and directors is contained in the proxy statement for Penn Virginia’s 2018 Annual Meeting of Stockholders filed with the SEC on March 28, 2018, and its Current Report on Form 8-K filed on September 12, 2018. You can obtain a free copy of this document at the SEC’s website at www.sec.gov or by accessing Penn Virginia’s website at www.pennvirginia.com. Investors may obtain additional information regarding the interests of those persons and other persons who may be deemed participants in the Transaction by reading the joint proxy statement/prospectus regarding the Transaction when it becomes available. You may obtain free copies of this document as described above. N Y SE : DN R 2 w w w .d e n b u r y . c o mCautionary Statements No Offer or Solicitation This presentation relates in part to a proposed business combination transaction (the “Transaction”) between Denbury Resources Inc. (“Denbury”) and Penn Virginia Corporation (“Penn Virginia”). This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the Transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended. Important Additional Information In connection with the Transaction, Denbury will file with the U.S. Securities and Exchange Commission (“SEC”) a registration statement on Form S-4, that will include a joint proxy statement of Denbury and Penn Virginia and a prospectus of Denbury. The Transaction will be submitted to Denbury’s stockholders and Penn Virginia’s stockholders for their consideration. Denbury and Penn Virginia may also file other documents with the SEC regarding the Transaction. The definitive joint proxy statement/prospectus will be sent to the stockholders of Denbury and shareholders of Penn Virginia. This document is not a substitute for the registration statement and joint proxy statement/prospectus that will be filed with the SEC or any other documents that Denbury or Penn Virginia may file with the SEC or send to stockholders of Denbury or Penn Virginia in connection with the Transaction. INVESTORS AND SECURITY HOLDERS OF DENBURY AND PENN VIRGINIA ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION WHEN IT BECOMES AVAILABLE AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS. Investors and security holders will be able to obtain free copies of the registration statement and the joint proxy statement/prospectus (when available) and all other documents filed or that will be filed with the SEC by Denbury or Penn Virginia through the website maintained by the SEC at http://www.sec.gov. Copies of documents filed with the SEC by Denbury will be made available free of charge on Denbury’s website at www.denbury.com or by directing a request to John Mayer, Director of Investor Relations, Denbury Resources Corporation, 5320 Legacy Drive, Plano, TX 75024, Tel. No. (972) 673-2383. Copies of documents filed with the SEC by Penn Virginia will be made available free of charge on Penn Virginia’s website at www.pennvirginia.com, under the heading “SEC Filings,” or by directing a request to Investor Relations, Penn Virginia Corporation, 16285 Park Ten Place, Suite 500, Houston, TX 77084, Tel. No. (713) 722-6540. Participants in the Solicitation Denbury, Penn Virginia and their respective directors and executive officers may be deemed to be participants in the solicitation of proxies in respect to the Transaction. Information regarding Denbury’s directors and executive officers is contained in the proxy statement for Denbury’s 2018 Annual Meeting of Stockholders filed with the SEC on April 12, 2018, and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC’s website at http://www.sec.gov or by accessing Denbury’s website at www.denbury.com. Information regarding Penn Virginia’s executive officers and directors is contained in the proxy statement for Penn Virginia’s 2018 Annual Meeting of Stockholders filed with the SEC on March 28, 2018, and its Current Report on Form 8-K filed on September 12, 2018. You can obtain a free copy of this document at the SEC’s website at www.sec.gov or by accessing Penn Virginia’s website at www.pennvirginia.com. Investors may obtain additional information regarding the interests of those persons and other persons who may be deemed participants in the Transaction by reading the joint proxy statement/prospectus regarding the Transaction when it becomes available. You may obtain free copies of this document as described above. N Y SE : DN R 2 w w w .d e n b u r y . c o m

Cautionary Statements (Cont.) Forward-Looking Statements and Cautionary Statements: The following slides contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this communication that address activities, events or developments that Denbury or Penn Virginia expects, believes or anticipates will or may occur in the future are forward- looking statements. Words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “create,” “intend,” “could,” “may,” “foresee,” “plan,” “will,” “guidance,” “look,” “outlook,” “goal,” “future,” “assume,” “forecast,” “build,” “focus,” “work,” “continue” or the negative of such terms or other variations thereof and words and terms of similar substance used in connection with any discussion of future plans, actions, or events identify forward- looking statements. However, the absence of these words does not mean that the statements are not forward-looking. These forward-looking statements include, but are not limited to, statements regarding the advantages of the proposed Transaction, and conducting EOR in the Eagle Ford formations held by Penn Virginia, pro forma descriptions of the combined company and its operations, integration and transition plans, synergies, opportunities and anticipated future performance including Future years’ combined production levels, operating cash flow and development capital, the EOR potential in the Eagle Ford for recoverable reserve, EUR increases, EOR well capex and projected performance of EOR wells. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements included in this communication. These include the expected timing and likelihood of completion of the Transaction, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the Transaction that could reduce anticipated benefits or cause the parties to abandon the 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 Denbury may not approve the issuance of new shares of common stock in the Transaction or the amendment of Denbury’s charter or that shareholders of Penn Virginia may not approve the merger agreement, the risk that the parties may not be able to satisfy the conditions to the Transaction in a timely manner or at all, the risk that any announcements relating to the Transaction could have adverse effects on the market price of Denbury’s common stock or Penn Virginia’s common stock, the risk that the Transaction and its announcement could have an adverse effect on Denbury’s and Penn Virginia’s operating results and businesses generally, or cause them to 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 it may take longer than expected to achieve those synergies 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 Denbury’s or Penn Virginia’s control, including those detailed in Denbury’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 www.denbury.com and on the SEC’s website at http://www.sec.gov, and those detailed in Penn Virginia’s annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K that are available on Penn Virginia’s website at www.pennvirginia.com and on the SEC’s website at http://www.sec.gov. In addition, Denbury’s Form 10-Q for the period ended September 30, 2018 (filed with the SEC on November 9, 2018) contains risks and uncertainties related to Denbury, its operations and its financial condition. All forward-looking statements are based on assumptions that Denbury or Penn Virginia 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 Denbury and Penn Virginia 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 that speak only as of the date hereof. Statement Regarding Non-GAAP Financial Measures: This presentation also contains certain non-GAAP financial measures including adjusted cash flows from operations and adjusted EBITDAX. Any non-GAAP measure included herein is accompanied by a reconciliation to the most directly comparable U.S. GAAP measure along with a statement on why the Company believes the measure is beneficial to investors, which statements are included at the end of this presentation. Note to U.S. Investors: Current SEC rules regarding oil and gas reserves information allow oil and gas companies to disclose in filings with the SEC not only proved reserves, but also probable and possible reserves that meet the SEC’s definitions of such terms. We disclose only proved reserves in our filings with the SEC. Denbury’s proved reserves as of December 31, 2016 and December 31, 2017 were estimated by DeGolyer and MacNaughton, an independent petroleum engineering firm. In this presentation, we may make reference to probable and possible reserves, some of which have been estimated by our independent engineers and some of which have been estimated by Denbury’s internal staff of engineers. In this presentation, we also may refer to estimates of original oil in place, resource or reserves “potential,” barrels recoverable, “risked” and “unrisked” resource potential, estimated ultimate recovery (EUR) or other descriptions of volumes potentially recoverable, which in addition to reserves generally classifiable as probable and possible (2P and 3P reserves), include estimates of resources that do not rise to the standards for possible reserves, and which SEC guidelines strictly prohibit us from including in filings with the SEC. These estimates, as well as the estimates of probable and possible reserves, are by their nature more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. N Y SE : DN R 3 w w w .d e n b u r y . c o mCautionary Statements (Cont.) Forward-Looking Statements and Cautionary Statements: The following slides contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this communication that address activities, events or developments that Denbury or Penn Virginia expects, believes or anticipates will or may occur in the future are forward- looking statements. Words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “create,” “intend,” “could,” “may,” “foresee,” “plan,” “will,” “guidance,” “look,” “outlook,” “goal,” “future,” “assume,” “forecast,” “build,” “focus,” “work,” “continue” or the negative of such terms or other variations thereof and words and terms of similar substance used in connection with any discussion of future plans, actions, or events identify forward- looking statements. However, the absence of these words does not mean that the statements are not forward-looking. These forward-looking statements include, but are not limited to, statements regarding the advantages of the proposed Transaction, and conducting EOR in the Eagle Ford formations held by Penn Virginia, pro forma descriptions of the combined company and its operations, integration and transition plans, synergies, opportunities and anticipated future performance including Future years’ combined production levels, operating cash flow and development capital, the EOR potential in the Eagle Ford for recoverable reserve, EUR increases, EOR well capex and projected performance of EOR wells. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements included in this communication. These include the expected timing and likelihood of completion of the Transaction, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the Transaction that could reduce anticipated benefits or cause the parties to abandon the 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 Denbury may not approve the issuance of new shares of common stock in the Transaction or the amendment of Denbury’s charter or that shareholders of Penn Virginia may not approve the merger agreement, the risk that the parties may not be able to satisfy the conditions to the Transaction in a timely manner or at all, the risk that any announcements relating to the Transaction could have adverse effects on the market price of Denbury’s common stock or Penn Virginia’s common stock, the risk that the Transaction and its announcement could have an adverse effect on Denbury’s and Penn Virginia’s operating results and businesses generally, or cause them to 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 it may take longer than expected to achieve those synergies 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 Denbury’s or Penn Virginia’s control, including those detailed in Denbury’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 www.denbury.com and on the SEC’s website at http://www.sec.gov, and those detailed in Penn Virginia’s annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K that are available on Penn Virginia’s website at www.pennvirginia.com and on the SEC’s website at http://www.sec.gov. In addition, Denbury’s Form 10-Q for the period ended September 30, 2018 (filed with the SEC on November 9, 2018) contains risks and uncertainties related to Denbury, its operations and its financial condition. All forward-looking statements are based on assumptions that Denbury or Penn Virginia 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 Denbury and Penn Virginia 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 that speak only as of the date hereof. Statement Regarding Non-GAAP Financial Measures: This presentation also contains certain non-GAAP financial measures including adjusted cash flows from operations and adjusted EBITDAX. Any non-GAAP measure included herein is accompanied by a reconciliation to the most directly comparable U.S. GAAP measure along with a statement on why the Company believes the measure is beneficial to investors, which statements are included at the end of this presentation. Note to U.S. Investors: Current SEC rules regarding oil and gas reserves information allow oil and gas companies to disclose in filings with the SEC not only proved reserves, but also probable and possible reserves that meet the SEC’s definitions of such terms. We disclose only proved reserves in our filings with the SEC. Denbury’s proved reserves as of December 31, 2016 and December 31, 2017 were estimated by DeGolyer and MacNaughton, an independent petroleum engineering firm. In this presentation, we may make reference to probable and possible reserves, some of which have been estimated by our independent engineers and some of which have been estimated by Denbury’s internal staff of engineers. In this presentation, we also may refer to estimates of original oil in place, resource or reserves “potential,” barrels recoverable, “risked” and “unrisked” resource potential, estimated ultimate recovery (EUR) or other descriptions of volumes potentially recoverable, which in addition to reserves generally classifiable as probable and possible (2P and 3P reserves), include estimates of resources that do not rise to the standards for possible reserves, and which SEC guidelines strictly prohibit us from including in filings with the SEC. These estimates, as well as the estimates of probable and possible reserves, are by their nature more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. N Y SE : DN R 3 w w w .d e n b u r y . c o m

The Combination of Denbury & Penn Virginia Adds High Value Investment Diversity Rocky Mountain Region • Adds new core area in the oil window of the prolific Eagle Ford Shale play • Large development inventory – ~560 Gross Lower Eagle Ford locations Combined Pro Forma • Expands high-return, short-cycle investment opportunity set Highlights Enhances Growth While Delivering Free Cash Flow 3Q18 Production • Rapidly growing Eagle Ford production base 82 MBOE/d • Eagle Ford asset base expected to generate free cash flow in 2019 91% Oil • Increases Denbury’s already top-tier operating margin YE17 Proved O&G Reserves Leverages and Expands EOR Platform 343 MMBOE • Multiple ongoing nearby rich hydrocarbon gas EOR pilots and projects • Opportunity to apply Denbury’s leading EOR expertise to the Eagle Ford Gulf Coast Shale Region Plano HQ Increases Financial Strength Penn Virginia • Immediately accretive to cash flow and key per-share metrics Acreage • Path to < 2.5X debt / EBITDAX by year-end 2019 at recent strip prices • Free cash flow profile provides optionality for the utilization of capital • Increased size and scale and enhanced credit metrics should reduce long- Denbury Owned Fields Current Pipelines term cost of capital CO Sources Planned Pipelines 2 N Y SE : DN R 4 w w w .d e n b u r y . c o mThe Combination of Denbury & Penn Virginia Adds High Value Investment Diversity Rocky Mountain Region • Adds new core area in the oil window of the prolific Eagle Ford Shale play • Large development inventory – ~560 Gross Lower Eagle Ford locations Combined Pro Forma • Expands high-return, short-cycle investment opportunity set Highlights Enhances Growth While Delivering Free Cash Flow 3Q18 Production • Rapidly growing Eagle Ford production base 82 MBOE/d • Eagle Ford asset base expected to generate free cash flow in 2019 91% Oil • Increases Denbury’s already top-tier operating margin YE17 Proved O&G Reserves Leverages and Expands EOR Platform 343 MMBOE • Multiple ongoing nearby rich hydrocarbon gas EOR pilots and projects • Opportunity to apply Denbury’s leading EOR expertise to the Eagle Ford Gulf Coast Shale Region Plano HQ Increases Financial Strength Penn Virginia • Immediately accretive to cash flow and key per-share metrics Acreage • Path to < 2.5X debt / EBITDAX by year-end 2019 at recent strip prices • Free cash flow profile provides optionality for the utilization of capital • Increased size and scale and enhanced credit metrics should reduce long- Denbury Owned Fields Current Pipelines term cost of capital CO Sources Planned Pipelines 2 N Y SE : DN R 4 w w w .d e n b u r y . c o m

Why We Like the Eagle Ford § Expansive play with large oil window § Light Louisiana Sweet (LLS) premium oil pricing Oil § Well developed midstream infrastructure Condensate Denbury’s Gulf Dry Gas Coast Assets § Significant upside potential through: § Enhanced oil recovery Penn Virginia Assets § Upper Eagle Ford § Austin Chalk § Close proximity to Denbury’s Gulf Coast operations § Follow-on consolidation potential N Y SE : DN R 5 w w w .d e n b u r y . c o mWhy We Like the Eagle Ford § Expansive play with large oil window § Light Louisiana Sweet (LLS) premium oil pricing Oil § Well developed midstream infrastructure Condensate Denbury’s Gulf Dry Gas Coast Assets § Significant upside potential through: § Enhanced oil recovery Penn Virginia Assets § Upper Eagle Ford § Austin Chalk § Close proximity to Denbury’s Gulf Coast operations § Follow-on consolidation potential N Y SE : DN R 5 w w w .d e n b u r y . c o m

Why We like Penn Virginia § Large and contiguous acreage position in Eagle Ford oil window – 98,600 gross (84,700 net) acres Penn Virginia Fayette County Other Operator EOR Pilots § 90% Liquids / 77% oil production § Receives LLS premium pricing Gonzales County § Strong growth trajectory Lavaca County § Substantial lower Eagle Ford inventory estimated at 560 gross (461 net) locations § Top tier operating margin § Ongoing nearby EOR pilots Dewitt County § Knowledgeable and experienced operating team N Y SE : DN R 6 w w w .d e n b u r y . c o mWhy We like Penn Virginia § Large and contiguous acreage position in Eagle Ford oil window – 98,600 gross (84,700 net) acres Penn Virginia Fayette County Other Operator EOR Pilots § 90% Liquids / 77% oil production § Receives LLS premium pricing Gonzales County § Strong growth trajectory Lavaca County § Substantial lower Eagle Ford inventory estimated at 560 gross (461 net) locations § Top tier operating margin § Ongoing nearby EOR pilots Dewitt County § Knowledgeable and experienced operating team N Y SE : DN R 6 w w w .d e n b u r y . c o m

Transaction Overview Transaction Value: $1.7 Billion; 68% Stock and 32% Cash • $833 million equity; 12.4 shares of Denbury for each share of Penn Virginia (est. 191.8 million shares) • $400 million cash; $25.86 for each share of Penn Virginia • $483 million net debt assumed by Denbury • Denbury shareholders will own 71% of combined company Approvals and Timing • Subject to Denbury and Penn Virginia shareholder approvals as well as HSR approval • Closing expected in Q1 2019 Pro + = Forma (1) Enterprise Value (Billions) $4.5 $1.5 $6.0 (2) YE17 Proved Reserves (MMBOE) 260 83 343 3Q18 Production (MBOE/d) 59 23 82 3Q18 Liquids Production % 97% 90% 95% 3Q18 Annualized EBITDAX (Millions) $593 $340 $933 (1) FactSet data as of 10/26/18. (2) Pro forma for the acquisition of Eagle Ford assets located primarily in Gonzales and Lavaca Counties, Texas, from Hunt Oil Company on March 1, 2018 N Y SE : DN R 7 w w w .d e n b u r y . c o mTransaction Overview Transaction Value: $1.7 Billion; 68% Stock and 32% Cash • $833 million equity; 12.4 shares of Denbury for each share of Penn Virginia (est. 191.8 million shares) • $400 million cash; $25.86 for each share of Penn Virginia • $483 million net debt assumed by Denbury • Denbury shareholders will own 71% of combined company Approvals and Timing • Subject to Denbury and Penn Virginia shareholder approvals as well as HSR approval • Closing expected in Q1 2019 Pro + = Forma (1) Enterprise Value (Billions) $4.5 $1.5 $6.0 (2) YE17 Proved Reserves (MMBOE) 260 83 343 3Q18 Production (MBOE/d) 59 23 82 3Q18 Liquids Production % 97% 90% 95% 3Q18 Annualized EBITDAX (Millions) $593 $340 $933 (1) FactSet data as of 10/26/18. (2) Pro forma for the acquisition of Eagle Ford assets located primarily in Gonzales and Lavaca Counties, Texas, from Hunt Oil Company on March 1, 2018 N Y SE : DN R 7 w w w .d e n b u r y . c o m

Combination Maintains Industry-Leading Oil Weighting…. 2Q18 % Liquids Production Oil Production 100% 97% 94% NGL Production 90% 87% 90% 80% 74% 70% 60% 50% 40% 30% 20% 10% 0% (1) (1) (1) (1) DNR Pro CPG JAG PVAC WLL CRZO WPX HPR OXY OAS CDEV CPE EPE CRC AMR XOG LPI SN SRCI NFX PDCE SM MUR CLR Forma Source: Bloomberg and Company filings for period ended 6/30/2018. 1) NGL production is not reported separately for this entity. N Y SE : DN R 8 w w w .d e n b u r y . c o mCombination Maintains Industry-Leading Oil Weighting…. 2Q18 % Liquids Production Oil Production 100% 97% 94% NGL Production 90% 87% 90% 80% 74% 70% 60% 50% 40% 30% 20% 10% 0% (1) (1) (1) (1) DNR Pro CPG JAG PVAC WLL CRZO WPX HPR OXY OAS CDEV CPE EPE CRC AMR XOG LPI SN SRCI NFX PDCE SM MUR CLR Forma Source: Bloomberg and Company filings for period ended 6/30/2018. 1) NGL production is not reported separately for this entity. N Y SE : DN R 8 w w w .d e n b u r y . c o m

….While Delivering Top Tier Operating Margins…. 2Q18 Peer Operating Margins ($/BOE) $50 $45 $40 $35 $30 $25 $20 $15 $10 $5 $- Pro PVAC CPE JAG CRZO OAS DNR HPR WPX WLL CLR EPE MUR CDEV CRC AMR XOG OXY LPI PDCE NFX SM SRCI SN Forma (1) Operating Margin per BOE 45.57 44.18 44.14 40.95 40.79 40.76 39.04 38.12 35.05 34.26 32.60 32.56 32.56 32.30 31.90 31.26 30.63 29.41 28.47 27.94 27.88 27.20 26.92 22.44 (2) Lifting Cost per BOE 9.45 7.84 6.27 9.87 13.98 22.77 27.53 7.59 10.66 11.58 8.66 11.26 9.62 9.30 21.98 8.88 8.24 14.12 5.98 6.80 10.27 11.20 6.58 12.69 (3) Revenue per BOE 55.02 52.02 50.41 50.82 54.77 63.53 66.57 45.71 45.71 45.84 41.26 43.82 42.18 41.60 53.88 40.14 38.87 43.53 34.45 34.74 38.15 38.40 33.50 35.13 Highest revenue per BOE in the peer group Source: Company filings for the period ended 6/30/2018. 1) Operating margin calculated as revenues less lifting costs. 2) Lifting cost calculated as lease operating expenses, marketing/transportation expenses and production and ad valorem taxes. 3) Revenues exclude gain/loss on derivative settlements. N Y SE : DN R 9 w w w .d e n b u r y . c o m….While Delivering Top Tier Operating Margins…. 2Q18 Peer Operating Margins ($/BOE) $50 $45 $40 $35 $30 $25 $20 $15 $10 $5 $- Pro PVAC CPE JAG CRZO OAS DNR HPR WPX WLL CLR EPE MUR CDEV CRC AMR XOG OXY LPI PDCE NFX SM SRCI SN Forma (1) Operating Margin per BOE 45.57 44.18 44.14 40.95 40.79 40.76 39.04 38.12 35.05 34.26 32.60 32.56 32.56 32.30 31.90 31.26 30.63 29.41 28.47 27.94 27.88 27.20 26.92 22.44 (2) Lifting Cost per BOE 9.45 7.84 6.27 9.87 13.98 22.77 27.53 7.59 10.66 11.58 8.66 11.26 9.62 9.30 21.98 8.88 8.24 14.12 5.98 6.80 10.27 11.20 6.58 12.69 (3) Revenue per BOE 55.02 52.02 50.41 50.82 54.77 63.53 66.57 45.71 45.71 45.84 41.26 43.82 42.18 41.60 53.88 40.14 38.87 43.53 34.45 34.74 38.15 38.40 33.50 35.13 Highest revenue per BOE in the peer group Source: Company filings for the period ended 6/30/2018. 1) Operating margin calculated as revenues less lifting costs. 2) Lifting cost calculated as lease operating expenses, marketing/transportation expenses and production and ad valorem taxes. 3) Revenues exclude gain/loss on derivative settlements. N Y SE : DN R 9 w w w .d e n b u r y . c o m

….and Creating a Leading Mid-Cap Oil Producer 10 (1) Enterprise Value ($ Billion) 9.1 8 7.4 6 6.1 6.0 6.0 6.0 5.4 4 4.5 4.0 3.7 3.3 2.9 2 2.8 2.8 2.3 2.1 1.5 1.3 0 WPX CRC NFX OAS WLL Pro CDEV DNR PDCE AMR CRZO JAG CPE XOG SRCI LPI PVAC HPR Forma 200 2Q18 Production (MBOE/d) 187 150 134 126 125 100 103 84 79 74 67 50 62 58 57 48 35 29 26 26 22 0 NFX CRC WLL WPX PDCE Pro OAS XOG LPI DNR CDEV CRZO SRCI JAG CPE AMR HPR PVAC Forma 1) FactSet as of 10/26/18 for enterprise values Note: 2Q18 production sourced from company filings N Y SE : DN R 10 w w w .d e n b u r y . c o m….and Creating a Leading Mid-Cap Oil Producer 10 (1) Enterprise Value ($ Billion) 9.1 8 7.4 6 6.1 6.0 6.0 6.0 5.4 4 4.5 4.0 3.7 3.3 2.9 2 2.8 2.8 2.3 2.1 1.5 1.3 0 WPX CRC NFX OAS WLL Pro CDEV DNR PDCE AMR CRZO JAG CPE XOG SRCI LPI PVAC HPR Forma 200 2Q18 Production (MBOE/d) 187 150 134 126 125 100 103 84 79 74 67 50 62 58 57 48 35 29 26 26 22 0 NFX CRC WLL WPX PDCE Pro OAS XOG LPI DNR CDEV CRZO SRCI JAG CPE AMR HPR PVAC Forma 1) FactSet as of 10/26/18 for enterprise values Note: 2Q18 production sourced from company filings N Y SE : DN R 10 w w w .d e n b u r y . c o m

EOR Opportunity in the Eagle Ford Up to 140 MMBO EOR Potential on PVAC Acreage Significantly de-risked through more than 25 projects covering ~200 wells Gonzales County EOR focus with 12 projects • Successful peer projects immediately offsetting PVA acreage, focused on oil window EOR Projects • Projected EUR increases of 30% – 70+% over primary recovery • Potential 60 MMBO to 140 MMBO recoverable through EOR on PVAC acreage Currently estimated $1-1.5MM aggregated EOR capex per well EOR process proven to be commercial, optimization opportunities still abundant N Y SE : DN R 11 w w w .d e n b u r y . c o mEOR Opportunity in the Eagle Ford Up to 140 MMBO EOR Potential on PVAC Acreage Significantly de-risked through more than 25 projects covering ~200 wells Gonzales County EOR focus with 12 projects • Successful peer projects immediately offsetting PVA acreage, focused on oil window EOR Projects • Projected EUR increases of 30% – 70+% over primary recovery • Potential 60 MMBO to 140 MMBO recoverable through EOR on PVAC acreage Currently estimated $1-1.5MM aggregated EOR capex per well EOR process proven to be commercial, optimization opportunities still abundant N Y SE : DN R 11 w w w .d e n b u r y . c o m

Applying Leading EOR Capabilities to the Eagle Ford Gonzales County Pilot Primary and EOR Oil Production 14,000 EOR Production The EOR Process EOR Forecast 12,000 Primary Production Primary forecast • Rich hydrocarbon gas or CO is injected into a producing well and is 2 10,000 allowed to soak for a period before the well is returned to production 8,000 • While all projects to date have used rich hydrocarbon gas, 6,000 simulation work indicates that CO should provide greater recovery 2 4,000 • Planning to conduct both CO and rich hydrocarbon gas pilots 2 2,000 • For example, a 1-2 month injection period could be followed by several - 2012 2014 2016 2018 2020 2022 2024 2026 2028 weeks of soaking and then a 2-4 month producing period Gonzales County EOR Pilot • The cycle is repeated over multiple years until incremental recovery Primary and EOR Recovery 9,000 reaches an economic limit 8,000 7,000 3.3 MMBO Oil production in enhanced through several processes 6,000 66% incremental 5,000 • Injected gas provides lift energy to depleted wells 4,000 • The gas is miscible with oil, reducing viscosity and swelling the oil 3,000 2,000 • Gas will adsorb onto the shale that it contacts, expelling oil from the 1,000 shale - 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 N Y SE : DN R 12 w w w .d e n b u r y . c o m MBbls Gross Oil Rate (9 Wells), bopdApplying Leading EOR Capabilities to the Eagle Ford Gonzales County Pilot Primary and EOR Oil Production 14,000 EOR Production The EOR Process EOR Forecast 12,000 Primary Production Primary forecast • Rich hydrocarbon gas or CO is injected into a producing well and is 2 10,000 allowed to soak for a period before the well is returned to production 8,000 • While all projects to date have used rich hydrocarbon gas, 6,000 simulation work indicates that CO should provide greater recovery 2 4,000 • Planning to conduct both CO and rich hydrocarbon gas pilots 2 2,000 • For example, a 1-2 month injection period could be followed by several - 2012 2014 2016 2018 2020 2022 2024 2026 2028 weeks of soaking and then a 2-4 month producing period Gonzales County EOR Pilot • The cycle is repeated over multiple years until incremental recovery Primary and EOR Recovery 9,000 reaches an economic limit 8,000 7,000 3.3 MMBO Oil production in enhanced through several processes 6,000 66% incremental 5,000 • Injected gas provides lift energy to depleted wells 4,000 • The gas is miscible with oil, reducing viscosity and swelling the oil 3,000 2,000 • Gas will adsorb onto the shale that it contacts, expelling oil from the 1,000 shale - 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 N Y SE : DN R 12 w w w .d e n b u r y . c o m MBbls Gross Oil Rate (9 Wells), bopd

Eagle Ford is Ideally Suited for EOR Penn Virginia’s Drivers of EOR Niobrara Bakken Permian Eagle Ford üûûü Completion Complexity & 2,500 lb/ft fracs 1,200 lb/ft fracs 1,500 lb/ft fracs 2,000 lb/ft fracs Contact Area for Miscible Gas üûûû Geology Homogenous Fractured Sandstone Heterogenous üûûû Horizontal Gas Containment Low Permeability Medium High Permeability Medium/High Permeability Permeability Vertical Gas Containmentüûûû Play Maturityüûüû Industry EOR Developmentüûûû N Y SE : DN R 13 w w w .d e n b u r y . c o mEagle Ford is Ideally Suited for EOR Penn Virginia’s Drivers of EOR Niobrara Bakken Permian Eagle Ford üûûü Completion Complexity & 2,500 lb/ft fracs 1,200 lb/ft fracs 1,500 lb/ft fracs 2,000 lb/ft fracs Contact Area for Miscible Gas üûûû Geology Homogenous Fractured Sandstone Heterogenous üûûû Horizontal Gas Containment Low Permeability Medium High Permeability Medium/High Permeability Permeability Vertical Gas Containmentüûûû Play Maturityüûüû Industry EOR Developmentüûûû N Y SE : DN R 13 w w w .d e n b u r y . c o m

Historic Eagle Ford EOR Project Performance Eagle Ford EOR Projects Gonzales County Oil Window Normalized to EOR Start Date 11,000 10,000 Pre EOR EOR • 8 Gonzales County Projects with Long term 9,000 6000 BOPD Performance ~ 2.5X 8,000 • 6,000 BOPD incremental from EOR from 88 Incremental wells 7,000 • Average incremental production per well of Production 40 – 110 BOPD 6,000 Rate 5,000 4,000 3,000 2,000 1,000 0 -3 -1 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 Months from Start of EOR Project A Project B Project C Project D Project E Project F Project G Project H N Y SE : DN R 14 w w w .d e n b u r y . c o m BOPDHistoric Eagle Ford EOR Project Performance Eagle Ford EOR Projects Gonzales County Oil Window Normalized to EOR Start Date 11,000 10,000 Pre EOR EOR • 8 Gonzales County Projects with Long term 9,000 6000 BOPD Performance ~ 2.5X 8,000 • 6,000 BOPD incremental from EOR from 88 Incremental wells 7,000 • Average incremental production per well of Production 40 – 110 BOPD 6,000 Rate 5,000 4,000 3,000 2,000 1,000 0 -3 -1 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 Months from Start of EOR Project A Project B Project C Project D Project E Project F Project G Project H N Y SE : DN R 14 w w w .d e n b u r y . c o m BOPD

Penn Virginia Acreage EOR Timeline Estimate • Eagle Ford stands out amongst other oily unconventional plays as the best EOR candidate • Good containment of injected fluid • Miscible across wide range of the oil window • ~1,000 wells expected on Penn Virginia acreage over field life • De-risked by offset operators • Progressed from pilot stage to development stage • Significant opportunity to optimize process and accelerate development Phase 1 Phase 2 Phase 3 Laboratory testing, pilot Multiple infield pilots Initiate full scale planning and facility across oil window, development scoping including CO evaluation 2 4Q18- 3Q19 2H19- 2020 2021+ N Y SE : DN R 15 w w w .d e n b u r y . c o mPenn Virginia Acreage EOR Timeline Estimate • Eagle Ford stands out amongst other oily unconventional plays as the best EOR candidate • Good containment of injected fluid • Miscible across wide range of the oil window • ~1,000 wells expected on Penn Virginia acreage over field life • De-risked by offset operators • Progressed from pilot stage to development stage • Significant opportunity to optimize process and accelerate development Phase 1 Phase 2 Phase 3 Laboratory testing, pilot Multiple infield pilots Initiate full scale planning and facility across oil window, development scoping including CO evaluation 2 4Q18- 3Q19 2H19- 2020 2021+ N Y SE : DN R 15 w w w .d e n b u r y . c o m

Pro Forma Combined Capital Structure Financing Commitment Letter from JP Morgan Chase • $1.2 billion new senior secured bank credit facility nd • $0.4 billion senior secured 2 lien bridge loan Est. Pro Forma for (1) Transaction In millions, as of 9/30/18, unless otherwise noted Bank Credit Facility $─ $283 $483 Second Lien Notes / Term Loan 1,521 200 1,921 Pipeline Financings / Capital Lease Obligations 194─ 194 Senior Subordinated Notes 826─ 826 Total Debt $2,541 $483 $3,424 Liquidity and Credit Statistics Availability under credit facility $553 $654 3Q18 Annualized EBITDAX 593 $340 933 3Q18 Annualized EBITDAX (excluding hedge 839 401 1,240 settlements) (2) Net Debt /EBITDAX 4.2x 1.4x 3.6x (2) Net Debt /EBITDAX (excluding hedge settlements) 2.9x 1.2x 2.7x 1) Pro forma adjustments reflect $400 million cash outlay for the transaction, excluding fees and expenses. 2) Net debt balances are net of cash and cash equivalents of $67 million and $8 million for DNR and PVAC, respectively. N Y SE : DN R 16 w w w .d e n b u r y . c o mPro Forma Combined Capital Structure Financing Commitment Letter from JP Morgan Chase • $1.2 billion new senior secured bank credit facility nd • $0.4 billion senior secured 2 lien bridge loan Est. Pro Forma for (1) Transaction In millions, as of 9/30/18, unless otherwise noted Bank Credit Facility $─ $283 $483 Second Lien Notes / Term Loan 1,521 200 1,921 Pipeline Financings / Capital Lease Obligations 194─ 194 Senior Subordinated Notes 826─ 826 Total Debt $2,541 $483 $3,424 Liquidity and Credit Statistics Availability under credit facility $553 $654 3Q18 Annualized EBITDAX 593 $340 933 3Q18 Annualized EBITDAX (excluding hedge 839 401 1,240 settlements) (2) Net Debt /EBITDAX 4.2x 1.4x 3.6x (2) Net Debt /EBITDAX (excluding hedge settlements) 2.9x 1.2x 2.7x 1) Pro forma adjustments reflect $400 million cash outlay for the transaction, excluding fees and expenses. 2) Net debt balances are net of cash and cash equivalents of $67 million and $8 million for DNR and PVAC, respectively. N Y SE : DN R 16 w w w .d e n b u r y . c o m

Preliminary Combined Pro Forma Estimates Average Daily Production (BOE/d) 104,000 – 112,000 Estimates thru 2020 assuming $60 – $70 WTI oil price 92,000 – 100,000 82,600 – 83,600 • >10% annual production growth • 85% – 90% oil production mix Estimated 2018 Estimated 2019 Estimated 2020 (1) • Top-tier operating margins Operating Cash Flow (in billions) • Significant free cash flow generation $1.0 – $1.4 $0.9 – $1.2 • Targeting ~2.0x or lower Debt / EBITDAX by end of 2020 ~$0.7 • 2019 capital assumes ~$150 MM for CCA pipeline Estimated 2018 Estimated 2019 Estimated 2020 1) Cash flow before working capital, net of ~$85 million interest treated as debt in Denbury’s financial statements, and excluding (2) Development Capital transaction costs. (in billions) 2) Excludes capitalized interest and acquisitions/divestitures. Note: The preliminary combined pro forma estimates are estimates based on assumptions that Denbury deems $0.9 – $1.0 reasonable as of the date of this presentation. However, such assumptions are inherently uncertain and difficult or $0.7 – $0.8 ~$0.7 impossible to predict or estimate and many of them are beyond Denbury’s control. The preliminary combined pro forma estimates also reflect assumptions regarding the continuing nature of certain business decisions that, in reality, would be subject to change. Future results of Denbury or Penn Virginia may differ, possibly materially, from the preliminary combined pro forma estimates. Estimated 2018 Estimated 2019 Estimated 2020 N Y SE : DN R 17 w w w .d e n b u r y . c o mPreliminary Combined Pro Forma Estimates Average Daily Production (BOE/d) 104,000 – 112,000 Estimates thru 2020 assuming $60 – $70 WTI oil price 92,000 – 100,000 82,600 – 83,600 • >10% annual production growth • 85% – 90% oil production mix Estimated 2018 Estimated 2019 Estimated 2020 (1) • Top-tier operating margins Operating Cash Flow (in billions) • Significant free cash flow generation $1.0 – $1.4 $0.9 – $1.2 • Targeting ~2.0x or lower Debt / EBITDAX by end of 2020 ~$0.7 • 2019 capital assumes ~$150 MM for CCA pipeline Estimated 2018 Estimated 2019 Estimated 2020 1) Cash flow before working capital, net of ~$85 million interest treated as debt in Denbury’s financial statements, and excluding (2) Development Capital transaction costs. (in billions) 2) Excludes capitalized interest and acquisitions/divestitures. Note: The preliminary combined pro forma estimates are estimates based on assumptions that Denbury deems $0.9 – $1.0 reasonable as of the date of this presentation. However, such assumptions are inherently uncertain and difficult or $0.7 – $0.8 ~$0.7 impossible to predict or estimate and many of them are beyond Denbury’s control. The preliminary combined pro forma estimates also reflect assumptions regarding the continuing nature of certain business decisions that, in reality, would be subject to change. Future results of Denbury or Penn Virginia may differ, possibly materially, from the preliminary combined pro forma estimates. Estimated 2018 Estimated 2019 Estimated 2020 N Y SE : DN R 17 w w w .d e n b u r y . c o m

Combined 2019 & 2020 Hedge Positions 2019 2020 Detail as of November 7, 2018 1H 2H 1H 2H Volumes Hedged (Bbls/d) 3,500─── WTI NYMEX - (1) Denbury Swap Price $59.05─── Volumes Hedged (Bbls/d) 6,433 6,398 6,000 6,000 WTI NYMEX – (1) Penn Virginia Swap Price $54.47 $54.50 $54.09 $54.09 Volumes Hedged (Bbls/d) 4,000 4,000── Argus LLS - (1) Denbury Swap Price $71.40 $71.40── Volumes Hedged (Bbls/d) 5,000 5,000── Argus LLS – (1) Penn Virginia Swap Price $59.17 $59.17── Volumes Hedged (Bbls/d) 8,500 12,000 1,000 1,000 (1)(2) Sold Put Price/Floor Price/Ceiling Price $47/$55/$66.71 $47/$55/$66.23 $50.00/$60.00/$82.50 $50.00/$60.00/$82.50 WTI NYMEX - Denbury Volumes Hedged (Bbls/d) 10,000 10,000── (1)(2) Sold Put Price/Floor Price/Ceiling Price $50.40/$58.40/$72.69 $50.40/$58.40/$72.69── Volumes Hedged (Bbls/d) 3,000 3,000 1,000 1,000 (1)(2) Sold Put Price/Floor Price/Ceiling Price $54/$62/$78.50 $54/$62/$78.50 $55.00/$65.00/$86.80 $55.00/$65.00/$86.80 Argus LLS - Denbury Volumes Hedged (Bbls/d) 2,500 2,500── (1)(2) Sold Put Price/Floor Price/Ceiling Price $55.60/$64.40/$81.65 $55.60/$64.40/$81.65── Total Volumes Hedged 42,933 42,898 8,000 8,000 1) Averages are volume weighted. 2) If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the floor price and sold put price. N Y SE : DN R 18 w w w .d e n b u r y . c o m 3-Way Collars Fixed Price SwapsCombined 2019 & 2020 Hedge Positions 2019 2020 Detail as of November 7, 2018 1H 2H 1H 2H Volumes Hedged (Bbls/d) 3,500─── WTI NYMEX - (1) Denbury Swap Price $59.05─── Volumes Hedged (Bbls/d) 6,433 6,398 6,000 6,000 WTI NYMEX – (1) Penn Virginia Swap Price $54.47 $54.50 $54.09 $54.09 Volumes Hedged (Bbls/d) 4,000 4,000── Argus LLS - (1) Denbury Swap Price $71.40 $71.40── Volumes Hedged (Bbls/d) 5,000 5,000── Argus LLS – (1) Penn Virginia Swap Price $59.17 $59.17── Volumes Hedged (Bbls/d) 8,500 12,000 1,000 1,000 (1)(2) Sold Put Price/Floor Price/Ceiling Price $47/$55/$66.71 $47/$55/$66.23 $50.00/$60.00/$82.50 $50.00/$60.00/$82.50 WTI NYMEX - Denbury Volumes Hedged (Bbls/d) 10,000 10,000── (1)(2) Sold Put Price/Floor Price/Ceiling Price $50.40/$58.40/$72.69 $50.40/$58.40/$72.69── Volumes Hedged (Bbls/d) 3,000 3,000 1,000 1,000 (1)(2) Sold Put Price/Floor Price/Ceiling Price $54/$62/$78.50 $54/$62/$78.50 $55.00/$65.00/$86.80 $55.00/$65.00/$86.80 Argus LLS - Denbury Volumes Hedged (Bbls/d) 2,500 2,500── (1)(2) Sold Put Price/Floor Price/Ceiling Price $55.60/$64.40/$81.65 $55.60/$64.40/$81.65── Total Volumes Hedged 42,933 42,898 8,000 8,000 1) Averages are volume weighted. 2) If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the floor price and sold put price. N Y SE : DN R 18 w w w .d e n b u r y . c o m 3-Way Collars Fixed Price Swaps

Uncommon Company, Extraordinary Potential – Enhanced with Penn Virginia Combination ü » Industry Leading Oil Weighting » Favorable Crude Quality & High Exposure to LLS Pricing Extreme Oil Gearing ü » Top Tier Operating Margin & Significant Free Cash Flow » Blend of EOR, Conventional and Oil-rich Shale Assets » Broad EOR experience base and technical strength Operating Advantages » Vertically Integrated CO Supply and Infrastructure 2 ü » Operating Outside Constrained Basins » Meaningful Production Growth Significant Organic » Large Inventory of Short-Cycle Eagle Ford Locations Growth Potential ü » Significant EOR Development Potential » Strong Liquidity » Enhanced Credit Profile Rapidly De-Levering ü » No Near-Term Debt Maturities N Y SE : DN R 19 w w w .d e n b u r y . c o mUncommon Company, Extraordinary Potential – Enhanced with Penn Virginia Combination ü » Industry Leading Oil Weighting » Favorable Crude Quality & High Exposure to LLS Pricing Extreme Oil Gearing ü » Top Tier Operating Margin & Significant Free Cash Flow » Blend of EOR, Conventional and Oil-rich Shale Assets » Broad EOR experience base and technical strength Operating Advantages » Vertically Integrated CO Supply and Infrastructure 2 ü » Operating Outside Constrained Basins » Meaningful Production Growth Significant Organic » Large Inventory of Short-Cycle Eagle Ford Locations Growth Potential ü » Significant EOR Development Potential » Strong Liquidity » Enhanced Credit Profile Rapidly De-Levering ü » No Near-Term Debt Maturities N Y SE : DN R 19 w w w .d e n b u r y . c o m

Corporate Presentation November 2018 N Y SE : DN R w w w .d e n b u r y . c o mCorporate Presentation November 2018 N Y SE : DN R w w w .d e n b u r y . c o m

Cautionary Statements Forward-Looking Statements: The data and/or statements contained in this presentation that are not historical facts are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, financial forecasts, future hydrocarbon prices and their volatility, the sustainability of current oil prices, current or future liquidity sources or their adequacy to support our anticipated future activities, our ability to further reduce our debt levels, together with assumptions based on current and projected production levels, oil and gas prices and oilfield costs, current or future expectations or estimations of our cash flows or the impact of changes in commodity prices on cash flows, availability of capital, borrowing capacity, price and availability of advantageous commodity derivative contracts or the predicted cash flow benefits therefrom, forecasted capital expenditures, drilling activity or methods, including the timing and location thereof, the nature of any future asset purchase or sales or the timing or proceeds thereof, estimated timing of commencement of CO2 flooding of particular fields or areas, including CCA, or the availability of capital for CCA pipeline construction, or its ultimate cost or its date of completion, timing of CO2 injections and initial production responses in tertiary flooding projects, development activities, finding costs, anticipated future cost savings, capital budgets, interpretation or prediction of formation details, hydrocarbon reserve quantities and values, CO2 reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, levels of U.S. and worldwide tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, the impact of regulatory rulings or changes, anticipated outcomes of pending litigation, prospective legislation affecting the oil and gas industry, environmental regulations, mark-to-market values, competition, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide economic conditions and other variables surrounding operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil and natural gas; decisions as to production levels and/or pricing by OPEC or production levels by U.S. shale producers in future periods; levels of future capital expenditures; effects of our indebtedness; success of our risk management techniques; accuracy of our cost estimates; availability or terms of credit in the commercial banking or other debt markets; fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from well incidents, hurricanes, tropical storms, forest fires, or other natural occurrences; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial, trade and credit markets; general economic conditions; competition; government regulations, including changes in tax or environmental laws or regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this presentation, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements including, without limitation, the Company’s most recent Form 10-K. Statement Regarding Non-GAAP Financial Measures: This presentation also contains certain non-GAAP financial measures including adjusted cash flows from operations and adjusted EBITDAX. Any non-GAAP measure included herein is accompanied by a reconciliation to the most directly comparable U.S. GAAP measure along with a statement on why the Company believes the measure is beneficial to investors, which statements are included at the end of this presentation. Note to U.S. Investors: Current SEC rules regarding oil and gas reserves information allow oil and gas companies to disclose in filings with the SEC not only proved reserves, but also probable and possible reserves that meet the SEC’s definitions of such terms. We disclose only proved reserves in our filings with the SEC. Denbury’s proved reserves as of December 31, 2016 and December 31, 2017 were estimated by DeGolyer and MacNaughton, an independent petroleum engineering firm. In this presentation, we may make reference to probable and possible reserves, some of which have been estimated by our independent engineers and some of which have been estimated by Denbury’s internal staff of engineers. In this presentation, we also may refer to estimates of original oil in place, resource or reserves “potential,” barrels recoverable, “risked” and “unrisked” resource potential, estimated ultimate recovery (EUR) or other descriptions of volumes potentially recoverable, which in addition to reserves generally classifiable as probable and possible (2P and 3P reserves), include estimates of resources that do not rise to the standards for possible reserves, and which SEC guidelines strictly prohibit us from including in filings with the SEC. These estimates, as well as the estimates of probable and possible reserves, are by their nature more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. N Y SE : DN R 2 w w w .d e n b u r y . c o mCautionary Statements Forward-Looking Statements: The data and/or statements contained in this presentation that are not historical facts are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, financial forecasts, future hydrocarbon prices and their volatility, the sustainability of current oil prices, current or future liquidity sources or their adequacy to support our anticipated future activities, our ability to further reduce our debt levels, together with assumptions based on current and projected production levels, oil and gas prices and oilfield costs, current or future expectations or estimations of our cash flows or the impact of changes in commodity prices on cash flows, availability of capital, borrowing capacity, price and availability of advantageous commodity derivative contracts or the predicted cash flow benefits therefrom, forecasted capital expenditures, drilling activity or methods, including the timing and location thereof, the nature of any future asset purchase or sales or the timing or proceeds thereof, estimated timing of commencement of CO2 flooding of particular fields or areas, including CCA, or the availability of capital for CCA pipeline construction, or its ultimate cost or its date of completion, timing of CO2 injections and initial production responses in tertiary flooding projects, development activities, finding costs, anticipated future cost savings, capital budgets, interpretation or prediction of formation details, hydrocarbon reserve quantities and values, CO2 reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, levels of U.S. and worldwide tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, the impact of regulatory rulings or changes, anticipated outcomes of pending litigation, prospective legislation affecting the oil and gas industry, environmental regulations, mark-to-market values, competition, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide economic conditions and other variables surrounding operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil and natural gas; decisions as to production levels and/or pricing by OPEC or production levels by U.S. shale producers in future periods; levels of future capital expenditures; effects of our indebtedness; success of our risk management techniques; accuracy of our cost estimates; availability or terms of credit in the commercial banking or other debt markets; fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from well incidents, hurricanes, tropical storms, forest fires, or other natural occurrences; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial, trade and credit markets; general economic conditions; competition; government regulations, including changes in tax or environmental laws or regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this presentation, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements including, without limitation, the Company’s most recent Form 10-K. Statement Regarding Non-GAAP Financial Measures: This presentation also contains certain non-GAAP financial measures including adjusted cash flows from operations and adjusted EBITDAX. Any non-GAAP measure included herein is accompanied by a reconciliation to the most directly comparable U.S. GAAP measure along with a statement on why the Company believes the measure is beneficial to investors, which statements are included at the end of this presentation. Note to U.S. Investors: Current SEC rules regarding oil and gas reserves information allow oil and gas companies to disclose in filings with the SEC not only proved reserves, but also probable and possible reserves that meet the SEC’s definitions of such terms. We disclose only proved reserves in our filings with the SEC. Denbury’s proved reserves as of December 31, 2016 and December 31, 2017 were estimated by DeGolyer and MacNaughton, an independent petroleum engineering firm. In this presentation, we may make reference to probable and possible reserves, some of which have been estimated by our independent engineers and some of which have been estimated by Denbury’s internal staff of engineers. In this presentation, we also may refer to estimates of original oil in place, resource or reserves “potential,” barrels recoverable, “risked” and “unrisked” resource potential, estimated ultimate recovery (EUR) or other descriptions of volumes potentially recoverable, which in addition to reserves generally classifiable as probable and possible (2P and 3P reserves), include estimates of resources that do not rise to the standards for possible reserves, and which SEC guidelines strictly prohibit us from including in filings with the SEC. These estimates, as well as the estimates of probable and possible reserves, are by their nature more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. N Y SE : DN R 2 w w w .d e n b u r y . c o m

Cautionary Statements (Cont.) No Offer or Solicitation To the extent that this presentation relates to a proposed business combination transaction (the “Transaction”) between Denbury Resources Inc. (“Denbury”) and Penn Virginia Corporation (“Penn Virginia”), it does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, related to the Transaction or otherwise, nor shall it constitute any sale, issuance, exchange or transfer of any securities in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended, as referred to below. Important Additional Information In connection with the Transaction, Denbury will file with the U.S. Securities and Exchange Commission (“SEC”) a registration statement on Form S-4, that will include a joint proxy statement of Denbury and Penn Virginia and a prospectus of Denbury. The Transaction will be submitted to Denbury’s stockholders and Penn Virginia’s stockholders for their consideration. Denbury and Penn Virginia may also file other documents with the SEC regarding the Transaction. The definitive joint proxy statement/prospectus will be sent to the stockholders of Denbury and shareholders of Penn Virginia. This document is not a substitute for the registration statement and joint proxy statement/prospectus that will be filed with the SEC or any other documents that Denbury or Penn Virginia may file with the SEC or send to stockholders of Denbury or Penn Virginia in connection with the Transaction. INVESTORS AND SECURITY HOLDERS OF DENBURY AND PENN VIRGINIA ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION WHEN IT BECOMES AVAILABLE AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS. Investors and security holders will be able to obtain free copies of the registration statement and the joint proxy statement/prospectus (when available) and all other documents filed or that will be filed with the SEC by Denbury or Penn Virginia through the website maintained by the SEC at http://www.sec.gov. Copies of documents filed with the SEC by Denbury will be made available free of charge on Denbury’s website at www.denbury.com or by directing a request to John Mayer, Director of Investor Relations, Denbury Resources Corporation, 5320 Legacy Drive, Plano, TX 75024, Tel. No. (972) 673-2383. Copies of documents filed with the SEC by Penn Virginia will be made available free of charge on Penn Virginia’s website at www.pennvirginia.com, under the heading “SEC Filings,” or by directing a request to Investor Relations, Penn Virginia Corporation, 16285 Park Ten Place, Suite 500, Houston, TX 77084, Tel. No. (713) 722-6540. Participants in the Solicitation Denbury, Penn Virginia and their respective directors and executive officers may be deemed to be participants in the solicitation of proxies in respect to the Transaction. Information regarding Denbury’s directors and executive officers is contained in the proxy statement for Denbury’s 2018 Annual Meeting of Stockholders filed with the SEC on April 12, 2018, and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC’s website at http://www.sec.gov or by accessing Denbury’s website at www.denbury.com. Information regarding Penn Virginia’s executive officers and directors is contained in the proxy statement for Penn Virginia’s 2018 Annual Meeting of Stockholders filed with the SEC on March 28, 2018, and its Current Report on Form 8-K filed on September 12, 2018. You can obtain a free copy of this document at the SEC’s website at www.sec.gov or by accessing Penn Virginia’s website at www.pennvirginia.com. Investors may obtain additional information regarding the interests of those persons and other persons who may be deemed participants in the Transaction by reading the joint proxy statement/prospectus regarding the Transaction when it becomes available. You may obtain free copies of this document as described above. N Y SE : DN R 3 w w w .d e n b u r y . c o mCautionary Statements (Cont.) No Offer or Solicitation To the extent that this presentation relates to a proposed business combination transaction (the “Transaction”) between Denbury Resources Inc. (“Denbury”) and Penn Virginia Corporation (“Penn Virginia”), it does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, related to the Transaction or otherwise, nor shall it constitute any sale, issuance, exchange or transfer of any securities in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended, as referred to below. Important Additional Information In connection with the Transaction, Denbury will file with the U.S. Securities and Exchange Commission (“SEC”) a registration statement on Form S-4, that will include a joint proxy statement of Denbury and Penn Virginia and a prospectus of Denbury. The Transaction will be submitted to Denbury’s stockholders and Penn Virginia’s stockholders for their consideration. Denbury and Penn Virginia may also file other documents with the SEC regarding the Transaction. The definitive joint proxy statement/prospectus will be sent to the stockholders of Denbury and shareholders of Penn Virginia. This document is not a substitute for the registration statement and joint proxy statement/prospectus that will be filed with the SEC or any other documents that Denbury or Penn Virginia may file with the SEC or send to stockholders of Denbury or Penn Virginia in connection with the Transaction. INVESTORS AND SECURITY HOLDERS OF DENBURY AND PENN VIRGINIA ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION WHEN IT BECOMES AVAILABLE AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS. Investors and security holders will be able to obtain free copies of the registration statement and the joint proxy statement/prospectus (when available) and all other documents filed or that will be filed with the SEC by Denbury or Penn Virginia through the website maintained by the SEC at http://www.sec.gov. Copies of documents filed with the SEC by Denbury will be made available free of charge on Denbury’s website at www.denbury.com or by directing a request to John Mayer, Director of Investor Relations, Denbury Resources Corporation, 5320 Legacy Drive, Plano, TX 75024, Tel. No. (972) 673-2383. Copies of documents filed with the SEC by Penn Virginia will be made available free of charge on Penn Virginia’s website at www.pennvirginia.com, under the heading “SEC Filings,” or by directing a request to Investor Relations, Penn Virginia Corporation, 16285 Park Ten Place, Suite 500, Houston, TX 77084, Tel. No. (713) 722-6540. Participants in the Solicitation Denbury, Penn Virginia and their respective directors and executive officers may be deemed to be participants in the solicitation of proxies in respect to the Transaction. Information regarding Denbury’s directors and executive officers is contained in the proxy statement for Denbury’s 2018 Annual Meeting of Stockholders filed with the SEC on April 12, 2018, and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC’s website at http://www.sec.gov or by accessing Denbury’s website at www.denbury.com. Information regarding Penn Virginia’s executive officers and directors is contained in the proxy statement for Penn Virginia’s 2018 Annual Meeting of Stockholders filed with the SEC on March 28, 2018, and its Current Report on Form 8-K filed on September 12, 2018. You can obtain a free copy of this document at the SEC’s website at www.sec.gov or by accessing Penn Virginia’s website at www.pennvirginia.com. Investors may obtain additional information regarding the interests of those persons and other persons who may be deemed participants in the Transaction by reading the joint proxy statement/prospectus regarding the Transaction when it becomes available. You may obtain free copies of this document as described above. N Y SE : DN R 3 w w w .d e n b u r y . c o m

Uncommon Company, Extraordinary Potential » Industry Leading Oil Weighting » Top Tier Operating Margin Extreme Oil Gearing » Favorable Crude Quality & High Exposure to LLS Pricing » Vertically Integrated CO Supply and Infrastructure 2 » Cost Structure Largely Independent from Industry Operating Advantages » Operating Outside Constrained Basins » Newly Sanctioned EOR Project at CCA Significant Organic » Significant EOR Development Potential Growth Potential » Growing Portfolio of Short-Cycle Opportunities » Strong Liquidity » No Near-Term Maturities Rapidly De-Levering » Reduced Debt/Improved Balance Sheet N Y SE : DN R 4 w w w .d e n b u r y . c o mUncommon Company, Extraordinary Potential » Industry Leading Oil Weighting » Top Tier Operating Margin Extreme Oil Gearing » Favorable Crude Quality & High Exposure to LLS Pricing » Vertically Integrated CO Supply and Infrastructure 2 » Cost Structure Largely Independent from Industry Operating Advantages » Operating Outside Constrained Basins » Newly Sanctioned EOR Project at CCA Significant Organic » Significant EOR Development Potential Growth Potential » Growing Portfolio of Short-Cycle Opportunities » Strong Liquidity » No Near-Term Maturities Rapidly De-Levering » Reduced Debt/Improved Balance Sheet N Y SE : DN R 4 w w w .d e n b u r y . c o m

Denbury – What We Are A Unique Energy Business Rocky Mountain • ~60% of production via CO enhanced oil recovery (EOR) 2 Region • Vertically integrated CO supply and distribution 2 • Cost structure largely independent from industry 3Q18 Production Extraordinarily Geared to Crude Oil 59,181 BOE/d • 97% oil production, high exposure to LLS pricing YE17 Proved O&G Reserves 260 MMBOE Value Sustaining with Organic Growth Upside • Over 1 Billion BOE proved + EOR and exploitation potential YE17 Proved CO Reserves 2 6.4 Tcf Intensely Focused on Execution and Results • Highly economic project portfolio at $50 oil Plano HQ • Significant improvements in cost structure since 2014 Gulf Coast • Track record of spending within cash flow Region A Carbon Conscious Producer • Annually injecting over 3 million tons of industrial-sourced CO into our reservoirs 2 N Y SE : DN R 5 w w w .d e n b u r y . c o mDenbury – What We Are A Unique Energy Business Rocky Mountain • ~60% of production via CO enhanced oil recovery (EOR) 2 Region • Vertically integrated CO supply and distribution 2 • Cost structure largely independent from industry 3Q18 Production Extraordinarily Geared to Crude Oil 59,181 BOE/d • 97% oil production, high exposure to LLS pricing YE17 Proved O&G Reserves 260 MMBOE Value Sustaining with Organic Growth Upside • Over 1 Billion BOE proved + EOR and exploitation potential YE17 Proved CO Reserves 2 6.4 Tcf Intensely Focused on Execution and Results • Highly economic project portfolio at $50 oil Plano HQ • Significant improvements in cost structure since 2014 Gulf Coast • Track record of spending within cash flow Region A Carbon Conscious Producer • Annually injecting over 3 million tons of industrial-sourced CO into our reservoirs 2 N Y SE : DN R 5 w w w .d e n b u r y . c o m

Industry Leading Oil Weighting 100% 2Q18 % Liquids Production Oil Production 97% 97% NGL Production 90% 80% Peer Average (% Liquids) 70% Peer Average (% Oil) 60% 50% 40% 30% 20% 10% 0% (1) (1) (1) DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N Peer O Source: Bloomberg and Company filings for period ended 6/30/2018. Peers include CPG, CLR, CRC, CRZO, EPE, LPI, MUR, NFX, OAS, OXY, PDCE, SM, SN, WLL and WPX. 1) NGL production is not reported separately for this peer. N Y SE : DN R 6 w w w .d e n b u r y . c o mIndustry Leading Oil Weighting 100% 2Q18 % Liquids Production Oil Production 97% 97% NGL Production 90% 80% Peer Average (% Liquids) 70% Peer Average (% Oil) 60% 50% 40% 30% 20% 10% 0% (1) (1) (1) DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N Peer O Source: Bloomberg and Company filings for period ended 6/30/2018. Peers include CPG, CLR, CRC, CRZO, EPE, LPI, MUR, NFX, OAS, OXY, PDCE, SM, SN, WLL and WPX. 1) NGL production is not reported separately for this peer. N Y SE : DN R 6 w w w .d e n b u r y . c o m

Top Tier Operating Margin 2Q18 Peer Operating Margins ($/BOE) $40 $35 Peer Average $30 $25 $20 $15 $10 $5 $- Peer A Peer B DNR Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N Peer O Peer P Peer Q Peer R Peer S Peer T Peer U (1) Operating Margin per BOE 40.95 40.79 39.04 36.82 35.25 35.05 34.26 32.62 32.60 32.56 32.56 31.90 29.41 28.47 27.94 27.88 27.20 26.52 25.95 22.44 20.19 10.38 (2) Lifting Cost per BOE 9.87 13.98 27.53 13.95 10.06 10.66 11.58 10.50 8.66 11.26 9.62 21.98 14.12 5.98 6.80 10.27 11.20 11.43 8.94 12.69 11.62 9.44 (3) Revenue per BOE 50.82 54.77 66.57 50.77 45.31 45.71 45.84 43.12 41.26 43.82 42.18 53.88 43.53 34.45 34.74 38.15 38.40 37.95 34.89 35.13 31.81 19.82 Highest revenue per BOE in the peer group Source: Company filings for the period ended 6/30/2018. Peers include CLR, COP, CRC, CRZO, CXO, DVN, EPE, LPI, MRO, MUR, NBL, NFX, OAS, OXY, PDCE, PXD, RRC, SM, SN, WLL, and WPX. 1) Operating margin calculated as revenues less lifting costs. 2) Lifting cost calculated as lease operating expenses, marketing/transportation expenses and production and ad valorem taxes. 3) Revenues exclude gain/loss on derivative settlements. N Y SE : DN R 7 w w w .d e n b u r y . c o mTop Tier Operating Margin 2Q18 Peer Operating Margins ($/BOE) $40 $35 Peer Average $30 $25 $20 $15 $10 $5 $- Peer A Peer B DNR Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N Peer O Peer P Peer Q Peer R Peer S Peer T Peer U (1) Operating Margin per BOE 40.95 40.79 39.04 36.82 35.25 35.05 34.26 32.62 32.60 32.56 32.56 31.90 29.41 28.47 27.94 27.88 27.20 26.52 25.95 22.44 20.19 10.38 (2) Lifting Cost per BOE 9.87 13.98 27.53 13.95 10.06 10.66 11.58 10.50 8.66 11.26 9.62 21.98 14.12 5.98 6.80 10.27 11.20 11.43 8.94 12.69 11.62 9.44 (3) Revenue per BOE 50.82 54.77 66.57 50.77 45.31 45.71 45.84 43.12 41.26 43.82 42.18 53.88 43.53 34.45 34.74 38.15 38.40 37.95 34.89 35.13 31.81 19.82 Highest revenue per BOE in the peer group Source: Company filings for the period ended 6/30/2018. Peers include CLR, COP, CRC, CRZO, CXO, DVN, EPE, LPI, MRO, MUR, NBL, NFX, OAS, OXY, PDCE, PXD, RRC, SM, SN, WLL, and WPX. 1) Operating margin calculated as revenues less lifting costs. 2) Lifting cost calculated as lease operating expenses, marketing/transportation expenses and production and ad valorem taxes. 3) Revenues exclude gain/loss on derivative settlements. N Y SE : DN R 7 w w w .d e n b u r y . c o m

Gulf Coast Region (1) Reserves Summary (MMBOE) Proved + Tertiary Potential Tertiary Reserves Proved 127 Potential 306 Non-Tertiary Reserves Proved 21 (2) Total MMBOE 454 (3) Tertiary Potential by Field Mature Area 25 – 30 Citronelle 25 Conroe 130 Delhi 30 Hastings 30 – 70 Heidelberg 25 Manvel 8 – 12 Oyster Bayou 15 Tinsley 25 Denbury Operated Pipelines Denbury Owned Fields – Current CO Floods 2 Thompson 20 – 40 Denbury Planned Pipelines Denbury Owned Fields – Potential CO Floods 2 Naturally-Occurring CO Source Fields Owned by Others – CO EOR Candidates Webster 40 – 75 2 2 Industrial CO Sources 2 W. Yellow Creek 5 – 10 Note: See “Slide Notes” on slide 23 in the appendix to this presentation for footnote explanations. N Y SE : DN R 8 w w w .d e n b u r y . c o mGulf Coast Region (1) Reserves Summary (MMBOE) Proved + Tertiary Potential Tertiary Reserves Proved 127 Potential 306 Non-Tertiary Reserves Proved 21 (2) Total MMBOE 454 (3) Tertiary Potential by Field Mature Area 25 – 30 Citronelle 25 Conroe 130 Delhi 30 Hastings 30 – 70 Heidelberg 25 Manvel 8 – 12 Oyster Bayou 15 Tinsley 25 Denbury Operated Pipelines Denbury Owned Fields – Current CO Floods 2 Thompson 20 – 40 Denbury Planned Pipelines Denbury Owned Fields – Potential CO Floods 2 Naturally-Occurring CO Source Fields Owned by Others – CO EOR Candidates Webster 40 – 75 2 2 Industrial CO Sources 2 W. Yellow Creek 5 – 10 Note: See “Slide Notes” on slide 23 in the appendix to this presentation for footnote explanations. N Y SE : DN R 8 w w w .d e n b u r y . c o m

Rocky Mountain Region (1) Reserves Summary (MMBOE) Proved + Tertiary Potential Tertiary Reserves Proved 26 Potential 534 Non-Tertiary Reserves Proved 86 (2) Total MMBOE 646 (3) Tertiary Potential by Field Bell Creek 20 – 40 Cedar Creek 400 – 500 Anticline Area Gas Draw 10 Denbury Operated Pipelines Denbury Planned Pipelines Grieve 5 Pipelines Owned by Others CO Resources Owned or Contracted 2 Hartzog Draw 30 – 40 Denbury Owned Fields – Current CO Floods 2 Denbury Owned Fields – Potential CO Floods 2 Salt Creek 25 – 35 Fields Owned by Others – CO EOR Candidates 2 Note: See “Slide Notes” on slide 23 in the appendix to this presentation for footnote explanations. N Y SE : DN R 9 w w w .d e n b u r y . c o mRocky Mountain Region (1) Reserves Summary (MMBOE) Proved + Tertiary Potential Tertiary Reserves Proved 26 Potential 534 Non-Tertiary Reserves Proved 86 (2) Total MMBOE 646 (3) Tertiary Potential by Field Bell Creek 20 – 40 Cedar Creek 400 – 500 Anticline Area Gas Draw 10 Denbury Operated Pipelines Denbury Planned Pipelines Grieve 5 Pipelines Owned by Others CO Resources Owned or Contracted 2 Hartzog Draw 30 – 40 Denbury Owned Fields – Current CO Floods 2 Denbury Owned Fields – Potential CO Floods 2 Salt Creek 25 – 35 Fields Owned by Others – CO EOR Candidates 2 Note: See “Slide Notes” on slide 23 in the appendix to this presentation for footnote explanations. N Y SE : DN R 9 w w w .d e n b u r y . c o m

2018 Watch List 1H18 2H18 Development Oyster Bayou Facility Expansion ✔ Bell Creek Phase 5 Response ✔ West Yellow Creek Response ✔ CCA EOR Investment Decision ✔ Grieve Field Startup ✔ Delhi Tuscaloosa Infill ✔ Exploitation Cedar Creek Anticline (Mission Canyon) ✔✔✔ Tinsley (Perry) ✔ Tinsley (Cotton Valley) Hartzog Draw Deep Financial Houston Surface Acreage Sales Extend Bank Line & Maintain Liquidity ✔ A Foundation of Strong Execution Safety & Environment Value Culture Project Delivery Capital Discipline Reservoir Management N Y SE : DN R 10 w w w .d e n b u r y . c o m2018 Watch List 1H18 2H18 Development Oyster Bayou Facility Expansion ✔ Bell Creek Phase 5 Response ✔ West Yellow Creek Response ✔ CCA EOR Investment Decision ✔ Grieve Field Startup ✔ Delhi Tuscaloosa Infill ✔ Exploitation Cedar Creek Anticline (Mission Canyon) ✔✔✔ Tinsley (Perry) ✔ Tinsley (Cotton Valley) Hartzog Draw Deep Financial Houston Surface Acreage Sales Extend Bank Line & Maintain Liquidity ✔ A Foundation of Strong Execution Safety & Environment Value Culture Project Delivery Capital Discipline Reservoir Management N Y SE : DN R 10 w w w .d e n b u r y . c o m

2018E Capital Plan & Production Guidance (1) 2018 Development Capital Budget 2018 Production Guidance (BOE/d) In Millions 60,100 - 60,600 $45 ~ $300 - $325 Million 60,298 $20 ~ $155 ~ $241 MM ~$300-325 MM Tertiary (2) 2 CapEx CapEx $95 ~ Non-Tertiary CO Sources & Other 2 (2) Other Capitalized Items 2017 2018 FY2016 2018 2017 1) Excludes ~$30 million of capitalized interest. 2) Includes capitalized internal acquisition, exploration and development costs and pre- production tertiary startup costs. N Y SE : DN R 11 w w w .d e n b u r y . c o m2018E Capital Plan & Production Guidance (1) 2018 Development Capital Budget 2018 Production Guidance (BOE/d) In Millions 60,100 - 60,600 $45 ~ $300 - $325 Million 60,298 $20 ~ $155 ~ $241 MM ~$300-325 MM Tertiary (2) 2 CapEx CapEx $95 ~ Non-Tertiary CO Sources & Other 2 (2) Other Capitalized Items 2017 2018 FY2016 2018 2017 1) Excludes ~$30 million of capitalized interest. 2) Includes capitalized internal acquisition, exploration and development costs and pre- production tertiary startup costs. N Y SE : DN R 11 w w w .d e n b u r y . c o m

Sanctioning CO EOR Development at CCA 2 Cedar Creek Anticline Overview EOR Formation Details Red River Initial Formations Targeted Interlake Stony Mountain 1930’s (Discovery) Field Discovery Timeframe (Oil) 1950’s (Development) Formation Type Carbonate Depth 7,000 – 9,000 ft Original Reservoir Pressure 3,600 – 4,140 psi CO Flood Type Miscible 2 API Gravity 29-38 Average Perm 5 md Average Porosity 11.4% OOIP ~5 Billion Barrels Note: The information included in slides 12 through 16, Oil Recovered to Date ~700 Million Barrels other than historical facts, are forward-looking statements based on current estimates. See slide 2, “Cautionary Est. Tertiary Recovery Factor 8 – 15% Statements” for risks and uncertainties related to this forward-looking information. N Y SE : DN R 12 w w w .d e n b u r y . c o mSanctioning CO EOR Development at CCA 2 Cedar Creek Anticline Overview EOR Formation Details Red River Initial Formations Targeted Interlake Stony Mountain 1930’s (Discovery) Field Discovery Timeframe (Oil) 1950’s (Development) Formation Type Carbonate Depth 7,000 – 9,000 ft Original Reservoir Pressure 3,600 – 4,140 psi CO Flood Type Miscible 2 API Gravity 29-38 Average Perm 5 md Average Porosity 11.4% OOIP ~5 Billion Barrels Note: The information included in slides 12 through 16, Oil Recovered to Date ~700 Million Barrels other than historical facts, are forward-looking statements based on current estimates. See slide 2, “Cautionary Est. Tertiary Recovery Factor 8 – 15% Statements” for risks and uncertainties related to this forward-looking information. N Y SE : DN R 12 w w w .d e n b u r y . c o m

EOR Potential >400 MMBBL at Cedar Creek Anticline Planned Development Summary • Phase 1 – Red River formation development at East Lookout Butte and Cedar Hills South ~175,000 net acres Est. 5 Billion Bbls OOIP • Targets ~30 MMBbls of recoverable oil; first tertiary production expected late 2021/early 2022 • Excluding CO pipeline, ~$100 MM development capital to initial tertiary 2 production; ~$400 MM total capital over 15-year period • Requires $150 MM CO pipeline that will service all future CCA EOR development Phase 2 EOR Target 2 ~100 MMBbls oil • Pipeline cost represents <$0.50/Bbl across total CCA EOR potential • Expect to internally fund development using available cash flow, will also evaluate external capital sources for pipeline • Phase 2 - Cabin Creek development in Interlake, Stony Mountain and Red River formations Phase 1 EOR Target ~30 MMBbls oil • Targets ~100 MMBbls of recoverable oil • Development estimated to begin in 2022; fully funded from Phase 1 cash flow • Estimated total capital of $500 – $600 MM over multiple decades • Future Phases – Remainder of CCA • > 300 MMBbl EOR potential in multiple formations ~110 mi. CO Pipeline 2 from Bell Creek Note: See “Note” on slide 12 related to the forward-looking information included on this slide. N Y SE : DN R 13 w w w .d e n b u r y . c o mEOR Potential >400 MMBBL at Cedar Creek Anticline Planned Development Summary • Phase 1 – Red River formation development at East Lookout Butte and Cedar Hills South ~175,000 net acres Est. 5 Billion Bbls OOIP • Targets ~30 MMBbls of recoverable oil; first tertiary production expected late 2021/early 2022 • Excluding CO pipeline, ~$100 MM development capital to initial tertiary 2 production; ~$400 MM total capital over 15-year period • Requires $150 MM CO pipeline that will service all future CCA EOR development Phase 2 EOR Target 2 ~100 MMBbls oil • Pipeline cost represents <$0.50/Bbl across total CCA EOR potential • Expect to internally fund development using available cash flow, will also evaluate external capital sources for pipeline • Phase 2 - Cabin Creek development in Interlake, Stony Mountain and Red River formations Phase 1 EOR Target ~30 MMBbls oil • Targets ~100 MMBbls of recoverable oil • Development estimated to begin in 2022; fully funded from Phase 1 cash flow • Estimated total capital of $500 – $600 MM over multiple decades • Future Phases – Remainder of CCA • > 300 MMBbl EOR potential in multiple formations ~110 mi. CO Pipeline 2 from Bell Creek Note: See “Note” on slide 12 related to the forward-looking information included on this slide. N Y SE : DN R 13 w w w .d e n b u r y . c o m

CCA – Decades of Sustainable Production and Free Cash Flow Est. Incremental EOR Production CCA Project Highlights • Phase 1 and 2 estimated incremental tertiary production ~7,500 - 12,500 net Bbls/d for Phase 1 of 7,500 – 12,500 Bbls/d • Potential to significantly increase production over Future EOR Potential time subject to CO availability and other factors 2 Planned Phase 2 • Phase 1 investment, including full CO pipeline, attractive 2 Phase 1 at $50 oil 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 • Initial pipeline investment benefits all incremental development Est. Cumulative Net Cash Flow @ $60 oil • Phase 1 payout expected within 2 years after first $ in millions production; future phases funded from project cashflow ~$3 Billion 2,000 ~$3 billion @ $60, ~$4 billion @ $70 • Potential to generate ~$3 billion of cumulative free cash 1,500 flow from Phases 1 and 2 at $60 oil 1,000 500 • Expect tertiary LOE to average $10-$15/Bbl - (500) 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 Note: See “Note” on slide 12 related to the forward-looking information included on this slide. N Y SE : DN R 14 w w w .d e n b u r y . c o mCCA – Decades of Sustainable Production and Free Cash Flow Est. Incremental EOR Production CCA Project Highlights • Phase 1 and 2 estimated incremental tertiary production ~7,500 - 12,500 net Bbls/d for Phase 1 of 7,500 – 12,500 Bbls/d • Potential to significantly increase production over Future EOR Potential time subject to CO availability and other factors 2 Planned Phase 2 • Phase 1 investment, including full CO pipeline, attractive 2 Phase 1 at $50 oil 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 • Initial pipeline investment benefits all incremental development Est. Cumulative Net Cash Flow @ $60 oil • Phase 1 payout expected within 2 years after first $ in millions production; future phases funded from project cashflow ~$3 Billion 2,000 ~$3 billion @ $60, ~$4 billion @ $70 • Potential to generate ~$3 billion of cumulative free cash 1,500 flow from Phases 1 and 2 at $60 oil 1,000 500 • Expect tertiary LOE to average $10-$15/Bbl - (500) 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 Note: See “Note” on slide 12 related to the forward-looking information included on this slide. N Y SE : DN R 14 w w w .d e n b u r y . c o m

Exploitation – A New Dimension for Growth Size of circles = Cost to test Costs per test range from $0.5MM – $8MM - Testing in 2018 Large Short-Cycle Opportunity Set 20 30 18 • Numerous exploitation targets across 28 Denbury’s 600,000 acre asset base 16 • Potential 65 MMBOE risked; 135 MMBOE 14 unrisked 12 • Adding new opportunities as team works extensive proprietary 3D seismic data set 10 Mission Canyon-Pennel • Spending ~$30MM – $40MM in 2018 to 8 accelerate program 6 • Testing > 40 MMBOE ultimate risked resource 4 potential in 2018 2 • Successful first 3 Mission Canyon wells at CCA, de-risking multi-well follow-on program 0 Lower Higher Increasing Probability of Success Note: See “Note” on slide 12 related to the forward-looking information included on this slide. N Y SE : DN R 15 w w w .d e n b u r y . c o m (1) Potential EUR, MMBOEExploitation – A New Dimension for Growth Size of circles = Cost to test Costs per test range from $0.5MM – $8MM - Testing in 2018 Large Short-Cycle Opportunity Set 20 30 18 • Numerous exploitation targets across 28 Denbury’s 600,000 acre asset base 16 • Potential 65 MMBOE risked; 135 MMBOE 14 unrisked 12 • Adding new opportunities as team works extensive proprietary 3D seismic data set 10 Mission Canyon-Pennel • Spending ~$30MM – $40MM in 2018 to 8 accelerate program 6 • Testing > 40 MMBOE ultimate risked resource 4 potential in 2018 2 • Successful first 3 Mission Canyon wells at CCA, de-risking multi-well follow-on program 0 Lower Higher Increasing Probability of Success Note: See “Note” on slide 12 related to the forward-looking information included on this slide. N Y SE : DN R 15 w w w .d e n b u r y . c o m (1) Potential EUR, MMBOE

Mission Canyon Mission Canyon Exploitation nd • Added 2 rig in late 3Q Cedar Creek Anticline • Successful test at Cabin Creek with 24 hour rate >1000 BOPD • Potential to add up to 5 additional Cabin Creek locations Well 6 (Oct 18) • Began delineation of Pennel-Coral Creek accumulation • Tested southern extent at Coral Creek Wells 2/3 (Apr 18) • Encountered increased fracturing relative to Pennel 1 well resulting in anomalous water rates; currently preparing to 1 well run diagnostic logs Well 1 (Dec 17) • Current activities: Wells 4/5 (Oct 18) • Completing down-dip Pennel well Planned wells 4Q18 • Preparing to rig down from Cedar Creek initial test well and 1 well Previously drilled wells begin completion Areas with Mission Canyon 1 well development potential • Plan to test Little Beaver Mission Canyon accumulation and Cabin Creek Charles B prospects in late 2018 Note: See “Note” on slide 12 related to the forward-looking information included on this slide. N Y SE : DN R 16 w w w .d e n b u r y . c o mMission Canyon Mission Canyon Exploitation nd • Added 2 rig in late 3Q Cedar Creek Anticline • Successful test at Cabin Creek with 24 hour rate >1000 BOPD • Potential to add up to 5 additional Cabin Creek locations Well 6 (Oct 18) • Began delineation of Pennel-Coral Creek accumulation • Tested southern extent at Coral Creek Wells 2/3 (Apr 18) • Encountered increased fracturing relative to Pennel 1 well resulting in anomalous water rates; currently preparing to 1 well run diagnostic logs Well 1 (Dec 17) • Current activities: Wells 4/5 (Oct 18) • Completing down-dip Pennel well Planned wells 4Q18 • Preparing to rig down from Cedar Creek initial test well and 1 well Previously drilled wells begin completion Areas with Mission Canyon 1 well development potential • Plan to test Little Beaver Mission Canyon accumulation and Cabin Creek Charles B prospects in late 2018 Note: See “Note” on slide 12 related to the forward-looking information included on this slide. N Y SE : DN R 16 w w w .d e n b u r y . c o m

Tinsley Perry Sand Well 2 Overview Recovery Factor North Fault • Proven light tight oil accumulation with low historical Block vertical well recovery; below current producing horizon Well 1 (2Q18) • Successful first well with strong pressure support and high deliverability • Based on first well results, expecting development wells to IP30 at >200 bopd average with shallow decline West Fault Block • Estimated >20% IRR at $50 flat oil price; >40% at current strip pricing East Fault • Second well currently drilling Block • Drill and complete cost estimated at $3 – $4 million per well • 6,000 prospective acres in North and West Fault Blocks; Mississippi Up to 18 potential horizontal locations identified to date • Upside CO EOR potential after primary production 2 Planned well 4Q18 Previously drilled wells N Y SE : DN R 17 w w w .d e n b u r y . c o mTinsley Perry Sand Well 2 Overview Recovery Factor North Fault • Proven light tight oil accumulation with low historical Block vertical well recovery; below current producing horizon Well 1 (2Q18) • Successful first well with strong pressure support and high deliverability • Based on first well results, expecting development wells to IP30 at >200 bopd average with shallow decline West Fault Block • Estimated >20% IRR at $50 flat oil price; >40% at current strip pricing East Fault • Second well currently drilling Block • Drill and complete cost estimated at $3 – $4 million per well • 6,000 prospective acres in North and West Fault Blocks; Mississippi Up to 18 potential horizontal locations identified to date • Upside CO EOR potential after primary production 2 Planned well 4Q18 Previously drilled wells N Y SE : DN R 17 w w w .d e n b u r y . c o m

Nebraska South Dakota Powder River Basin Stacked Pay In Hartzog Draw Unit Hartzog Draw Exploitation North Dakota Shannon: • 20,700 gross / 12,900 net acres in Campbell & 449 BOED IP Rate, 94% Oil Johnson Counties, WY Montana Wyoming Parkman: • Significant nearby successes from Turner, 1,166 BOED IP Rate, 96% Niobrara, Shannon, Parkman, and Mowry Oil formations HDU • Recent acreage transactions valued at between $4,000 – $12,000 per acre x x x x • Acreage held by Hartzog Draw Unit production Turner/Frontier 1,393 BOED IP • Production & transport infrastructure in place Rate, 91% Oil x • Planning to begin drilling activities to test deeper horizons in 4Q18 Niobrara: Mowry: 1,617 BOED IP 1,336 BOED IP Rate, 81% Oil Rate, 83% Oil N Y SE : DN R 18 w w w .d e n b u r y . c o mNebraska South Dakota Powder River Basin Stacked Pay In Hartzog Draw Unit Hartzog Draw Exploitation North Dakota Shannon: • 20,700 gross / 12,900 net acres in Campbell & 449 BOED IP Rate, 94% Oil Johnson Counties, WY Montana Wyoming Parkman: • Significant nearby successes from Turner, 1,166 BOED IP Rate, 96% Niobrara, Shannon, Parkman, and Mowry Oil formations HDU • Recent acreage transactions valued at between $4,000 – $12,000 per acre x x x x • Acreage held by Hartzog Draw Unit production Turner/Frontier 1,393 BOED IP • Production & transport infrastructure in place Rate, 91% Oil x • Planning to begin drilling activities to test deeper horizons in 4Q18 Niobrara: Mowry: 1,617 BOED IP 1,336 BOED IP Rate, 81% Oil Rate, 83% Oil N Y SE : DN R 18 w w w .d e n b u r y . c o m

Recent Debt Transactions Further Improve Leverage Profile Net Debt Principal Reduction Since 12/31/14 9/30/18 Debt Maturity Profile RECENT TRANSACTIONS (In millions) (In millions) $553 million of bank line Over $1 Billion Net Debt Reduction » Amended and Extended Bank Credit availability at 9/30/18 after LOCs Facility to Dec. 2021 $3,548 » Issued $450 million of New 7½% Sr. nd Secured 2 Lien Notes; Proceeds $395 Used to Fully Repay Credit Facility $324 $2,475 $2,514 $204 $194 ACCOMPLISHMENTS $415 $315 $202 » Extended Credit Facility Maturity to Dec. 2021 and Streamlined Bank $1,521 Group $2,852 $1,071 » Extended Overall Debt Maturity $615 Profile $456 $450 $308 » Maintained Same Access to $826 $826 Liquidity, $615 Million Undrawn $(23) $- $(67) Credit Facility 2018 2019 2020 2021 2022 2023 2024 12/31/14 6/30/18 9/30/18 nd Sr. Subordinated Notes Sr. Secured 2 Lien Notes Sr. Secured Bank Credit Facility Cash & Cash Equivalents Pipeline / Capital Lease Debt N Y SE : DN R 19 w w w .d e n b u r y . c o mRecent Debt Transactions Further Improve Leverage Profile Net Debt Principal Reduction Since 12/31/14 9/30/18 Debt Maturity Profile RECENT TRANSACTIONS (In millions) (In millions) $553 million of bank line Over $1 Billion Net Debt Reduction » Amended and Extended Bank Credit availability at 9/30/18 after LOCs Facility to Dec. 2021 $3,548 » Issued $450 million of New 7½% Sr. nd Secured 2 Lien Notes; Proceeds $395 Used to Fully Repay Credit Facility $324 $2,475 $2,514 $204 $194 ACCOMPLISHMENTS $415 $315 $202 » Extended Credit Facility Maturity to Dec. 2021 and Streamlined Bank $1,521 Group $2,852 $1,071 » Extended Overall Debt Maturity $615 Profile $456 $450 $308 » Maintained Same Access to $826 $826 Liquidity, $615 Million Undrawn $(23) $- $(67) Credit Facility 2018 2019 2020 2021 2022 2023 2024 12/31/14 6/30/18 9/30/18 nd Sr. Subordinated Notes Sr. Secured 2 Lien Notes Sr. Secured Bank Credit Facility Cash & Cash Equivalents Pipeline / Capital Lease Debt N Y SE : DN R 19 w w w .d e n b u r y . c o m

Significantly Improving Leverage Metrics TTM Leverage Ratio 3Q18 Annualized Leverage Ratio Trailing 12 months Trailing 12 months 3Q18 3Q18 in millions (incl. hedges) (excl. hedges) (incl. hedges) (excl. hedges) (1) Adjusted EBITDAX $601 $760 $148 $210 3Q18 Annualized 593 839 (2) 9/30/18 Net Debt Principal 2,475 2,475 2,475 2,475 (1) Debt/Adjusted EBITDAX 4.1x 3.3x 4.2x 2.9x 1) A non-GAAP measure. See press release attached as Exhibit 99.1 to the Form 8-K filed November 8, 2018 for additional information, as well as slide 35 indicating why the Company believes this non-GAAP measure is useful for investors. 2) Total debt principal balance as of September 30, 2018 is net of cash & cash equivalents. N Y SE : DN R 20 w w w .d e n b u r y . c o mSignificantly Improving Leverage Metrics TTM Leverage Ratio 3Q18 Annualized Leverage Ratio Trailing 12 months Trailing 12 months 3Q18 3Q18 in millions (incl. hedges) (excl. hedges) (incl. hedges) (excl. hedges) (1) Adjusted EBITDAX $601 $760 $148 $210 3Q18 Annualized 593 839 (2) 9/30/18 Net Debt Principal 2,475 2,475 2,475 2,475 (1) Debt/Adjusted EBITDAX 4.1x 3.3x 4.2x 2.9x 1) A non-GAAP measure. See press release attached as Exhibit 99.1 to the Form 8-K filed November 8, 2018 for additional information, as well as slide 35 indicating why the Company believes this non-GAAP measure is useful for investors. 2) Total debt principal balance as of September 30, 2018 is net of cash & cash equivalents. N Y SE : DN R 20 w w w .d e n b u r y . c o m

Hedge Positions – as of November 7, 2018 2018 2019 2020 Detail as of November 7, 2018 2H 1H 2H 1H 2H Volumes Hedged (Bbls/d) 15,500──── (1) Swap Price $50.13──── WTI NYMEX Volumes Hedged (Bbls/d) 5,000 3,500─── (1) Swap Price $56.54 $59.05─── Volumes Hedged (Bbls/d) 5,000 4,000 4,000── Argus (1) LLS Swap Price $60.18 $71.40 $71.40── Volumes Hedged (Bbls/d) 15,000 8,500 12,000── (1)(2) Sold Put Price/Floor Price/Ceiling Price $36.50/$46.50/$53.88 $47/$55/$66.71 $47/$55/$66.23── WTI NYMEX Volumes Hedged (Bbls/d)─ 10,000 10,000 1,000 1,000 (1)(2) Sold Put Price/Floor Price/Ceiling Price─ $50.40/$58.40/$72.69 $50.40/$58.40/$72.69 $50/$60/$82.50 $50/$60/$82.50 Volumes Hedged (Bbls/d)─ 3,000 3,000 (1)(2) Sold Put Price/Floor Price/Ceiling Price─ $54/$62/$78.50 $54/$62/$78.50 Argus LLS Volumes Hedged (Bbls/d)─ 2,500 2,500 1,000 1,000 (1)(2) Sold Put Price/Floor Price/Ceiling Price─ $55.60/$64.40/$81.65 $55.60/$64.40/$81.65 $55/$65/$86.80 $55/$65/$86.80 Total Volumes Hedged 40,500 31,500 31,500 2,000 2,000 1) Averages are volume weighted. 2) If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the floor price and sold put price. N Y SE : DN R 21 w w w .d e n b u r y . c o m 3-Way Collars Fixed Price SwapsHedge Positions – as of November 7, 2018 2018 2019 2020 Detail as of November 7, 2018 2H 1H 2H 1H 2H Volumes Hedged (Bbls/d) 15,500──── (1) Swap Price $50.13──── WTI NYMEX Volumes Hedged (Bbls/d) 5,000 3,500─── (1) Swap Price $56.54 $59.05─── Volumes Hedged (Bbls/d) 5,000 4,000 4,000── Argus (1) LLS Swap Price $60.18 $71.40 $71.40── Volumes Hedged (Bbls/d) 15,000 8,500 12,000── (1)(2) Sold Put Price/Floor Price/Ceiling Price $36.50/$46.50/$53.88 $47/$55/$66.71 $47/$55/$66.23── WTI NYMEX Volumes Hedged (Bbls/d)─ 10,000 10,000 1,000 1,000 (1)(2) Sold Put Price/Floor Price/Ceiling Price─ $50.40/$58.40/$72.69 $50.40/$58.40/$72.69 $50/$60/$82.50 $50/$60/$82.50 Volumes Hedged (Bbls/d)─ 3,000 3,000 (1)(2) Sold Put Price/Floor Price/Ceiling Price─ $54/$62/$78.50 $54/$62/$78.50 Argus LLS Volumes Hedged (Bbls/d)─ 2,500 2,500 1,000 1,000 (1)(2) Sold Put Price/Floor Price/Ceiling Price─ $55.60/$64.40/$81.65 $55.60/$64.40/$81.65 $55/$65/$86.80 $55/$65/$86.80 Total Volumes Hedged 40,500 31,500 31,500 2,000 2,000 1) Averages are volume weighted. 2) If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the floor price and sold put price. N Y SE : DN R 21 w w w .d e n b u r y . c o m 3-Way Collars Fixed Price Swaps

Appendix N Y SE : DN R 22 w w w .d e n b u r y . c o mAppendix N Y SE : DN R 22 w w w .d e n b u r y . c o m

Slide Notes Slide 8 – Gulf Coast Region Slide 9 – Rocky Mountain Region 1) Proved tertiary and non-tertiary oil and natural gas reserves based upon 1) Proved tertiary and non-tertiary oil and natural gas reserves based upon year-end 12/31/17 SEC pricing. Potential includes probable and possible year-end 12/31/17 SEC pricing. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/16 (with the tertiary reserves estimated by the Company as of 12/31/16 (with the exception of West Yellow Creek, estimated as of 3/31/17), using the mid- exception of Salt Creek, estimated as of 6/30/17), using the mid-point of point of ranges, based upon a variety of recovery factors and long-term oil ranges, based upon a variety of recovery factors and long-term oil price price assumptions, which also may include estimates of resources that do assumptions, which also may include estimates of resources that do not rise not rise to the standards of possible reserves. See slide 2, “Cautionary to the standards of possible reserves. See slide 2, “Cautionary Statements” for additional information. Statements” for additional information. 2) Total reserves in the table represent total proved plus potential tertiary 2) Total reserves in the table represent total proved plus potential tertiary reserves, using the mid-point of ranges, plus proved non-tertiary reserves, reserves, using the mid-point of ranges, plus proved non-tertiary reserves, but excluding additional potential related to non-tertiary exploitation but excluding additional potential related to non-tertiary exploitation opportunities. opportunities. 3) Field reserves shown are estimated proved plus potential tertiary reserves. 3) Field reserves shown are estimated proved plus potential tertiary reserves. N Y SE : DN R 23 w w w .d e n b u r y . c o mSlide Notes Slide 8 – Gulf Coast Region Slide 9 – Rocky Mountain Region 1) Proved tertiary and non-tertiary oil and natural gas reserves based upon 1) Proved tertiary and non-tertiary oil and natural gas reserves based upon year-end 12/31/17 SEC pricing. Potential includes probable and possible year-end 12/31/17 SEC pricing. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/16 (with the tertiary reserves estimated by the Company as of 12/31/16 (with the exception of West Yellow Creek, estimated as of 3/31/17), using the mid- exception of Salt Creek, estimated as of 6/30/17), using the mid-point of point of ranges, based upon a variety of recovery factors and long-term oil ranges, based upon a variety of recovery factors and long-term oil price price assumptions, which also may include estimates of resources that do assumptions, which also may include estimates of resources that do not rise not rise to the standards of possible reserves. See slide 2, “Cautionary to the standards of possible reserves. See slide 2, “Cautionary Statements” for additional information. Statements” for additional information. 2) Total reserves in the table represent total proved plus potential tertiary 2) Total reserves in the table represent total proved plus potential tertiary reserves, using the mid-point of ranges, plus proved non-tertiary reserves, reserves, using the mid-point of ranges, plus proved non-tertiary reserves, but excluding additional potential related to non-tertiary exploitation but excluding additional potential related to non-tertiary exploitation opportunities. opportunities. 3) Field reserves shown are estimated proved plus potential tertiary reserves. 3) Field reserves shown are estimated proved plus potential tertiary reserves. N Y SE : DN R 23 w w w .d e n b u r y . c o m

CO EOR Process 2 CO Injection Well 2 Production Well CO EOR can produce about as much oil as 2 CO Pipeline 2 (1) primary or secondary recovery Primary ~20% Secondary ~ 18% (Waterfloods) CO EOR 2 ~ 17% Oil Formation (Tertiary) CO moves through formation mixing with oil, expanding 2 1) Based on OOIP at Denbury’s Little Creek Field and moving it toward producing wells N Y SE : DN R 24 w w w .d e n b u r y . c o m Recovery of Original Oil in Place (“OOIP”)CO EOR Process 2 CO Injection Well 2 Production Well CO EOR can produce about as much oil as 2 CO Pipeline 2 (1) primary or secondary recovery Primary ~20% Secondary ~ 18% (Waterfloods) CO EOR 2 ~ 17% Oil Formation (Tertiary) CO moves through formation mixing with oil, expanding 2 1) Based on OOIP at Denbury’s Little Creek Field and moving it toward producing wells N Y SE : DN R 24 w w w .d e n b u r y . c o m Recovery of Original Oil in Place (“OOIP”)

CO EOR is a Proven Process 2 (1) CO EOR Oil Production by Region 2 Significant CO EOR Operators by Region 300 2 Gulf Coast/Other Gulf Coast Region Mid-Continent 250 » Denbury Resources » Hilcorp Rocky Mountains Permian Basin Region Permian Basin 200 » Occidental » Kinder Morgan 150 Rocky Mountain Region » Denbury Resources » FDL 100 » Devon » Chevron 50 Canada » Whitecap » Apache 0 Significant CO Supply by Region 2 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 Gulf Coast Region » Jackson Dome, MS (Denbury Resources) DGC » Air Products (Denbury Resources) » Nutrien (Denbury Resources) Lost Cabin » Petra Nova (Hilcorp) LaBarge Permian Basin Region » Bravo Dome, NM (Kinder Morgan, Occidental) Sheep Mountain McElmo Dome » McElmo Dome, CO (ExxonMobil, Kinder Morgan) Bravo Dome » Sheep Mountain, CO (ExxonMobil, Occidental) Rocky Mountain Region Jackson Dome » LaBarge, WY (ExxonMobil, Denbury Resources) Nutrien Air Products » Lost Cabin, WY (ConocoPhillips) Naturally Occurring CO Source Petra Nova 2 Canada Industrial-Sourced CO 2 » Dakota Gasification (Whitecap, Apache) 1) Source: Advanced Resources International N Y SE : DN R 25 w w w .d e n b u r y . c o m MBbls/dCO EOR is a Proven Process 2 (1) CO EOR Oil Production by Region 2 Significant CO EOR Operators by Region 300 2 Gulf Coast/Other Gulf Coast Region Mid-Continent 250 » Denbury Resources » Hilcorp Rocky Mountains Permian Basin Region Permian Basin 200 » Occidental » Kinder Morgan 150 Rocky Mountain Region » Denbury Resources » FDL 100 » Devon » Chevron 50 Canada » Whitecap » Apache 0 Significant CO Supply by Region 2 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 Gulf Coast Region » Jackson Dome, MS (Denbury Resources) DGC » Air Products (Denbury Resources) » Nutrien (Denbury Resources) Lost Cabin » Petra Nova (Hilcorp) LaBarge Permian Basin Region » Bravo Dome, NM (Kinder Morgan, Occidental) Sheep Mountain McElmo Dome » McElmo Dome, CO (ExxonMobil, Kinder Morgan) Bravo Dome » Sheep Mountain, CO (ExxonMobil, Occidental) Rocky Mountain Region Jackson Dome » LaBarge, WY (ExxonMobil, Denbury Resources) Nutrien Air Products » Lost Cabin, WY (ConocoPhillips) Naturally Occurring CO Source Petra Nova 2 Canada Industrial-Sourced CO 2 » Dakota Gasification (Whitecap, Apache) 1) Source: Advanced Resources International N Y SE : DN R 25 w w w .d e n b u r y . c o m MBbls/d

Significant Running Room with CO EOR 2 (1)(2) Up to 83 Billion Barrels of Technically Recoverable Oil – U.S Lower 48 2.8 to 6.6 MT ND Billion Barrels (2) Rocky Mountain Region 33-83 Billion of Technically WY (1,2) Recoverable Oil (amounts in billions of barrels) Permian 9-21 East & Central Texas 6-15 Mid-Continent 6-13 Denbury’s fields represent (3) California 3-7 ~10% of total potential South East Gulf Coast 3-7 Rockies 2-6 MS Other 0-5 Existing Denbury CO Pipelines 2 Planned Denbury CO Pipeline 2 Michigan/Illinois 2-4 CO Pipeline owned by Others TX 2 LA Williston 1-3 Denbury owned oil fields CO Source Owned or Contracted 2 Appalachia 1-2 3.7 to 9.1 1) Source: 2013 DOE NETL Next Gen EOR. Billion Barrels 2) Total estimated recoveries on a gross basis utilizing CO EOR. 2 3) Using approximate mid-points of ranges, based on a variety of recovery factors. (2) Gulf Coast Region N Y SE : DN R 26 w w w .d e n b u r y . c o mSignificant Running Room with CO EOR 2 (1)(2) Up to 83 Billion Barrels of Technically Recoverable Oil – U.S Lower 48 2.8 to 6.6 MT ND Billion Barrels (2) Rocky Mountain Region 33-83 Billion of Technically WY (1,2) Recoverable Oil (amounts in billions of barrels) Permian 9-21 East & Central Texas 6-15 Mid-Continent 6-13 Denbury’s fields represent (3) California 3-7 ~10% of total potential South East Gulf Coast 3-7 Rockies 2-6 MS Other 0-5 Existing Denbury CO Pipelines 2 Planned Denbury CO Pipeline 2 Michigan/Illinois 2-4 CO Pipeline owned by Others TX 2 LA Williston 1-3 Denbury owned oil fields CO Source Owned or Contracted 2 Appalachia 1-2 3.7 to 9.1 1) Source: 2013 DOE NETL Next Gen EOR. Billion Barrels 2) Total estimated recoveries on a gross basis utilizing CO EOR. 2 3) Using approximate mid-points of ranges, based on a variety of recovery factors. (2) Gulf Coast Region N Y SE : DN R 26 w w w .d e n b u r y . c o m

Abundant CO Supply & No Significant Capital Required for Several Years 2 Gulf Coast CO Supply Rocky Mountain CO Supply 2 2 LaBarge Area Jackson Dome (1) o Estimated field size: 750 square miles o Proved CO reserves as of 12/31/17: ~5.2 Tcf 2 o Estimated recoverable CO : 100 Tcf 2 o Additional probable CO reserves as of 12/31/17: ~1.0 Tcf 2 Shute Creek – ExxonMobil Operated Industrial-Sourced CO 2 o Proved reserves as of 12/31/17: ~1.2 Tcf Current Sources o Denbury has a 1/3 overriding royalty interest and could receive up to ~115 MMcf/d of CO by 2021 at o Air Products (hydrogen plant): ~45 MMcf/d 2 current plant capacity o Nutrien (ammonia products): ~20 MMcf/d Lost Cabin – ConocoPhillips Operated Future Potential Sources (2) o Denbury could receive up to ~36 MMcf/d of CO at o Lake Charles Methanol (methanol plant) 2 current plant capacity 1) Reported on a gross (8/8th’s) basis. 2) Planned but not currently under construction. Estimated CO capture date could be as early as 2021, with estimated potential CO volumes >200 MMcf/d. 2 2 N Y SE : DN R 27 w w w .d e n b u r y . c o mAbundant CO Supply & No Significant Capital Required for Several Years 2 Gulf Coast CO Supply Rocky Mountain CO Supply 2 2 LaBarge Area Jackson Dome (1) o Estimated field size: 750 square miles o Proved CO reserves as of 12/31/17: ~5.2 Tcf 2 o Estimated recoverable CO : 100 Tcf 2 o Additional probable CO reserves as of 12/31/17: ~1.0 Tcf 2 Shute Creek – ExxonMobil Operated Industrial-Sourced CO 2 o Proved reserves as of 12/31/17: ~1.2 Tcf Current Sources o Denbury has a 1/3 overriding royalty interest and could receive up to ~115 MMcf/d of CO by 2021 at o Air Products (hydrogen plant): ~45 MMcf/d 2 current plant capacity o Nutrien (ammonia products): ~20 MMcf/d Lost Cabin – ConocoPhillips Operated Future Potential Sources (2) o Denbury could receive up to ~36 MMcf/d of CO at o Lake Charles Methanol (methanol plant) 2 current plant capacity 1) Reported on a gross (8/8th’s) basis. 2) Planned but not currently under construction. Estimated CO capture date could be as early as 2021, with estimated potential CO volumes >200 MMcf/d. 2 2 N Y SE : DN R 27 w w w .d e n b u r y . c o m

2018E CapEx Within Budgeted Cash Flow @ $55 Oil In millions, unless otherwise noted Est. Cash Flow Range 2018E Budgeted Sources & Uses @ $55/Bbl (1) $400 (Including Hedges) (1) In millions 2018E (2) Capital Budget Adjusted cash flow from operations $430 – $480 $350 Interest payments treated as debt reduction (90) Adjusted total, net $340 – $390 $300 Development capital $300 – $325 Capitalized interest 30 $250 Total capital costs $330 – $355 Net excess cash flow $10 – $35 $200 (1) Development Capital Budget ($300MM – $325MM) 1) Estimated ranges based on assumed $55/Bbl NYMEX oil prices, forecasts and Capitalized Interest ($30MM) assumptions as of February 9, 2018. 2) Cash flow from operations before working capital changes (a non-GAAP measure). (2) Adjusted Cash Flow , less interest payments treated as debt See press release attached as Exhibit 99.1 to the Form 8-K filed November 8, 2018 for additional information, as well as slide 34 indicating why the Company believes this non-GAAP measure is useful for investors. Excluding hedges, each $5 change in oil price impacts cash flow by ~$100 million N Y SE : DN R 28 w w w .d e n b u r y . c o m2018E CapEx Within Budgeted Cash Flow @ $55 Oil In millions, unless otherwise noted Est. Cash Flow Range 2018E Budgeted Sources & Uses @ $55/Bbl (1) $400 (Including Hedges) (1) In millions 2018E (2) Capital Budget Adjusted cash flow from operations $430 – $480 $350 Interest payments treated as debt reduction (90) Adjusted total, net $340 – $390 $300 Development capital $300 – $325 Capitalized interest 30 $250 Total capital costs $330 – $355 Net excess cash flow $10 – $35 $200 (1) Development Capital Budget ($300MM – $325MM) 1) Estimated ranges based on assumed $55/Bbl NYMEX oil prices, forecasts and Capitalized Interest ($30MM) assumptions as of February 9, 2018. 2) Cash flow from operations before working capital changes (a non-GAAP measure). (2) Adjusted Cash Flow , less interest payments treated as debt See press release attached as Exhibit 99.1 to the Form 8-K filed November 8, 2018 for additional information, as well as slide 34 indicating why the Company believes this non-GAAP measure is useful for investors. Excluding hedges, each $5 change in oil price impacts cash flow by ~$100 million N Y SE : DN R 28 w w w .d e n b u r y . c o m

Production by Area Average Daily Production (BOE/d) Field 2016 1Q17 2Q17 3Q17 4Q17 2017 1Q18 2Q18 3Q18 Delhi 4,155 4,991 4,965 4,619 4,906 4,869 4,169 4,391 4,383 Hastings 4,829 4,288 4,400 4,867 5,747 4,830 5,704 5,716 5,486 Heidelberg 5,128 4,730 4,996 4,927 4,751 4,851 4,445 4,330 4,376 Oyster Bayou 5,083 5,075 5,217 4,870 4,868 5,007 5,056 4,961 4,578 Tinsley 7,192 6,666 6,311 6,506 6,241 6,430 6,053 5,755 5,294 Bell Creek 3,121 3,209 3,060 3,406 3,571 3,313 4,050 4,010 3,970 Salt Creek — — 23 2,228 2,172 1,115 2,002 2,049 2,274 Other Tertiary 11 14 10 19 7 13 57 142 246 (1) Mature area 8,241 7,502 7,171 6,893 6,763 7,078 6,726 6,725 6,612 Total tertiary production 37,760 36,475 36,153 38,335 39,026 37,506 38,262 38,079 37,219 Gulf Coast non-tertiary 6,271 6,158 6,454 5,394 5,810 5,952 5,692 6,236 5,992 Cedar Creek Anticline 16,322 15,067 15,124 14,535 14,302 14,754 14,437 15,742 14,208 Other Rockies non-tertiary 1,844 1,626 1,475 1,514 1,533 1,537 1,485 1,490 1,409 Total non-tertiary production 24,437 22,851 23,053 21,443 21,645 22,243 21,614 23,468 21,609 Total continuing production 62,197 59,326 59,206 59,778 60,671 59,749 59,876 61,547 58,828 (2) Property divestitures 1,806 607 568 550 473 549 462 447 353 Total production 64,003 59,933 59,774 60,328 61,144 60,298 60,338 61,994 59,181 1) Mature area includes Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, and Soso fields. 2) Includes non-tertiary production in the Rocky Mountain region related to the sale of assets in the Williston Basin of North Dakota and Montana (“Williston Assets”), which closed in the third quarter of 2016, and tertiary and non- tertiary production from Lockhart Crossing Field, which closed in third quarter of 2018. N Y SE : DN R 29 w w w .d e n b u r y . c o mProduction by Area Average Daily Production (BOE/d) Field 2016 1Q17 2Q17 3Q17 4Q17 2017 1Q18 2Q18 3Q18 Delhi 4,155 4,991 4,965 4,619 4,906 4,869 4,169 4,391 4,383 Hastings 4,829 4,288 4,400 4,867 5,747 4,830 5,704 5,716 5,486 Heidelberg 5,128 4,730 4,996 4,927 4,751 4,851 4,445 4,330 4,376 Oyster Bayou 5,083 5,075 5,217 4,870 4,868 5,007 5,056 4,961 4,578 Tinsley 7,192 6,666 6,311 6,506 6,241 6,430 6,053 5,755 5,294 Bell Creek 3,121 3,209 3,060 3,406 3,571 3,313 4,050 4,010 3,970 Salt Creek — — 23 2,228 2,172 1,115 2,002 2,049 2,274 Other Tertiary 11 14 10 19 7 13 57 142 246 (1) Mature area 8,241 7,502 7,171 6,893 6,763 7,078 6,726 6,725 6,612 Total tertiary production 37,760 36,475 36,153 38,335 39,026 37,506 38,262 38,079 37,219 Gulf Coast non-tertiary 6,271 6,158 6,454 5,394 5,810 5,952 5,692 6,236 5,992 Cedar Creek Anticline 16,322 15,067 15,124 14,535 14,302 14,754 14,437 15,742 14,208 Other Rockies non-tertiary 1,844 1,626 1,475 1,514 1,533 1,537 1,485 1,490 1,409 Total non-tertiary production 24,437 22,851 23,053 21,443 21,645 22,243 21,614 23,468 21,609 Total continuing production 62,197 59,326 59,206 59,778 60,671 59,749 59,876 61,547 58,828 (2) Property divestitures 1,806 607 568 550 473 549 462 447 353 Total production 64,003 59,933 59,774 60,328 61,144 60,298 60,338 61,994 59,181 1) Mature area includes Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, and Soso fields. 2) Includes non-tertiary production in the Rocky Mountain region related to the sale of assets in the Williston Basin of North Dakota and Montana (“Williston Assets”), which closed in the third quarter of 2016, and tertiary and non- tertiary production from Lockhart Crossing Field, which closed in third quarter of 2018. N Y SE : DN R 29 w w w .d e n b u r y . c o m

NYMEX Oil Differential Summary Another quarter of company-wide positive differential to NYMEX Crude Oil Differentials $ per barrel 2016 1Q17 2Q17 3Q17 4Q17 2017 1Q18 2Q18 3Q18 Tertiary Oil Fields Gulf Coast Region $(1.35) $(1.58) $(1.01) $(0.10) $2.84 $0.06 $1.87 $0.85 $3.01 Rocky Mountain Region (2.16) (1.74) (1.75) (0.83) (1.09) (0.96) 0.22 (1.10) (0.86) Gulf Coast Non-Tertiary (1.89) (0.42) 0.59 0.90 4.18 1.26 3.26 2.73 4.42 Cedar Creek Anticline (3.77) (2.08) (1.93) (0.96) (0.57) (1.43) (0.11) (0.67) (0.31) Other Rockies Non-Tertiary (8.63) (3.41) (3.20) (2.08) (1.65) (2.72) (1.30) (1.96) (1.92) Denbury Totals $(2.29) $(1.64) $(1.16) $(0.34) $1.70 $(0.32) $1.29 $0.39 $1.84 During 3Q18, ~60% of our crude oil was based on, or partially tied to, the LLS index price N Y SE : DN R 30 w w w .d e n b u r y . c o mNYMEX Oil Differential Summary Another quarter of company-wide positive differential to NYMEX Crude Oil Differentials $ per barrel 2016 1Q17 2Q17 3Q17 4Q17 2017 1Q18 2Q18 3Q18 Tertiary Oil Fields Gulf Coast Region $(1.35) $(1.58) $(1.01) $(0.10) $2.84 $0.06 $1.87 $0.85 $3.01 Rocky Mountain Region (2.16) (1.74) (1.75) (0.83) (1.09) (0.96) 0.22 (1.10) (0.86) Gulf Coast Non-Tertiary (1.89) (0.42) 0.59 0.90 4.18 1.26 3.26 2.73 4.42 Cedar Creek Anticline (3.77) (2.08) (1.93) (0.96) (0.57) (1.43) (0.11) (0.67) (0.31) Other Rockies Non-Tertiary (8.63) (3.41) (3.20) (2.08) (1.65) (2.72) (1.30) (1.96) (1.92) Denbury Totals $(2.29) $(1.64) $(1.16) $(0.34) $1.70 $(0.32) $1.29 $0.39 $1.84 During 3Q18, ~60% of our crude oil was based on, or partially tied to, the LLS index price N Y SE : DN R 30 w w w .d e n b u r y . c o m

Analysis of Total Operating Costs Total Operating Costs $ per BOE 2016 1Q17 2Q17 3Q17 4Q17 2017 1Q18 2Q18 3Q18 CO Costs $2.16 $2.86 $2.36 $3.22 $3.02 $2.86 $3.09 $2.92 $2.63 2 Power & Fuel 5.29 5.93 6.04 6.18 5.72 5.97 6.68 6.19 6.31 1) Normalized LOE excludes special or Labor & Overhead 5.41 6.34 6.41 6.24 6.24 6.32 6.38 6.47 6.99 unusual items and Thompson Field repair costs (see footnotes 2 and 3 below). Repairs & Maintenance 0.84 0.95 0.83 0.76 0.84 0.84 0.80 0.91 1.09 2) Special or unusual items consist of Chemicals 1.02 1.15 1.05 1.01 0.95 1.04 1.00 1.05 1.17 cleanup and repair costs associated with Hurricane Harvey ($3MM) in 3Q17, and Workovers 1.87 2.65 2.68 2.26 2.20 2.44 2.84 2.21 3.20 an adjustment for pricing related to one of our industrial CO sources ($7MM) in Other 0.97 1.23 1.09 1.07 0.88 1.06 1.01 1.59 1.11 2 4Q17. (1) Total Normalized LOE $17.56 $21.11 $20.46 $20.74 $19.85 $20.53 $21.80 $21.34 $22.50 3) Represents repair costs to return (2) Special or Unusual Items — — — 0.48 (1.21) (0.18) — — — Thompson Field to production following weather-related flooding in 2Q16. Thompson Field Repair 0.15 — — — — — — — — (3) Costs 4) Excludes derivative settlements. Total LOE $17.71 $21.11 $20.46 $21.22 $18.64 $20.35 $21.80 $21.34 $22.50 Oil Pricing NYMEX Oil Price $43.41 $51.95 $48.32 $48.12 $55.47 $50.96 $62.96 $67.85 $69.60 (4) Realized Oil Price $41.12 $50.31 $47.16 $47.78 $57.17 $50.64 $64.25 $68.24 $71.44 N Y SE : DN R 31 w w w .d e n b u r y . c o mAnalysis of Total Operating Costs Total Operating Costs $ per BOE 2016 1Q17 2Q17 3Q17 4Q17 2017 1Q18 2Q18 3Q18 CO Costs $2.16 $2.86 $2.36 $3.22 $3.02 $2.86 $3.09 $2.92 $2.63 2 Power & Fuel 5.29 5.93 6.04 6.18 5.72 5.97 6.68 6.19 6.31 1) Normalized LOE excludes special or Labor & Overhead 5.41 6.34 6.41 6.24 6.24 6.32 6.38 6.47 6.99 unusual items and Thompson Field repair costs (see footnotes 2 and 3 below). Repairs & Maintenance 0.84 0.95 0.83 0.76 0.84 0.84 0.80 0.91 1.09 2) Special or unusual items consist of Chemicals 1.02 1.15 1.05 1.01 0.95 1.04 1.00 1.05 1.17 cleanup and repair costs associated with Hurricane Harvey ($3MM) in 3Q17, and Workovers 1.87 2.65 2.68 2.26 2.20 2.44 2.84 2.21 3.20 an adjustment for pricing related to one of our industrial CO sources ($7MM) in Other 0.97 1.23 1.09 1.07 0.88 1.06 1.01 1.59 1.11 2 4Q17. (1) Total Normalized LOE $17.56 $21.11 $20.46 $20.74 $19.85 $20.53 $21.80 $21.34 $22.50 3) Represents repair costs to return (2) Special or Unusual Items — — — 0.48 (1.21) (0.18) — — — Thompson Field to production following weather-related flooding in 2Q16. Thompson Field Repair 0.15 — — — — — — — — (3) Costs 4) Excludes derivative settlements. Total LOE $17.71 $21.11 $20.46 $21.22 $18.64 $20.35 $21.80 $21.34 $22.50 Oil Pricing NYMEX Oil Price $43.41 $51.95 $48.32 $48.12 $55.47 $50.96 $62.96 $67.85 $69.60 (4) Realized Oil Price $41.12 $50.31 $47.16 $47.78 $57.17 $50.64 $64.25 $68.24 $71.44 N Y SE : DN R 31 w w w .d e n b u r y . c o m

CO Cost & NYMEX Oil Price 2 $0.50 $110 $100 $0.45 $90 $0.40 $80 $0.35 $70 $0.30 $60 $0.25 $50 $0.20 $40 $0.15 $30 $0.10 $20 $0.05 $10 $0.00 $0 (2) (2) (2) 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 Industrial-Sourced CO % Industrial-Sourced CO2 % 16% 16% 15% 15% 18% 22% 22% 23% 23% 25% 22% 22% 26% 24% 25% 28% 29% 34% 29% 2 Tax 0.028 0.031 0.039 0.030 0.025 0.038 0.045 0.040 0.047 0.053 0.052 0.048 0.045 0.040 0.041 0.042 0.043 0.046 0.047 OPEX Purchases Tax NYMEX Crude Oil Price Purchases 0.243 0.300 0.285 0.207 0.171 0.183 0.169 0.161 0.163 0.233 0.215 0.184 0.222 0.200 0.207 0.073 0.185 0.216 0.190 1) Excludes DD&A on CO wells and facilities; includes Gulf Coast & Rocky Mountain industrial-source CO costs. 2 2 OPEX 0.111 0.120 0.113 0.113 0.120 0.148 0.131 0.185 0.124 0.144 0.138 0.160 0.142 0.140 0.209 0.166 0.167 0.183 0.171 2) CO costs include workovers carried out at Jackson Dome in 3Q17 and 4Q15 of $3 million ($0.08 per Mcf) and $3 million ($0.05 per Mcf), respectively, and a downward adjustment in 4Q17 for pricing 2 NYMEX Crude Oil 98.60 103.0 97.31 73.04 48.83 57.99 46.70 42.15 33.73 45.56 45.02 49.25 51.95 48.32 48.12 55.48 62.96 67.85 69.60 related to one of our industrial CO sources of $7 million ($0.12 per Mcf) 2 N Y SE : DN R 32 w w w .d e n b u r y . c o m (1) CO Costs / Mcf 2 NYMEX Crude Oil Price / BblCO Cost & NYMEX Oil Price 2 $0.50 $110 $100 $0.45 $90 $0.40 $80 $0.35 $70 $0.30 $60 $0.25 $50 $0.20 $40 $0.15 $30 $0.10 $20 $0.05 $10 $0.00 $0 (2) (2) (2) 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 Industrial-Sourced CO % Industrial-Sourced CO2 % 16% 16% 15% 15% 18% 22% 22% 23% 23% 25% 22% 22% 26% 24% 25% 28% 29% 34% 29% 2 Tax 0.028 0.031 0.039 0.030 0.025 0.038 0.045 0.040 0.047 0.053 0.052 0.048 0.045 0.040 0.041 0.042 0.043 0.046 0.047 OPEX Purchases Tax NYMEX Crude Oil Price Purchases 0.243 0.300 0.285 0.207 0.171 0.183 0.169 0.161 0.163 0.233 0.215 0.184 0.222 0.200 0.207 0.073 0.185 0.216 0.190 1) Excludes DD&A on CO wells and facilities; includes Gulf Coast & Rocky Mountain industrial-source CO costs. 2 2 OPEX 0.111 0.120 0.113 0.113 0.120 0.148 0.131 0.185 0.124 0.144 0.138 0.160 0.142 0.140 0.209 0.166 0.167 0.183 0.171 2) CO costs include workovers carried out at Jackson Dome in 3Q17 and 4Q15 of $3 million ($0.08 per Mcf) and $3 million ($0.05 per Mcf), respectively, and a downward adjustment in 4Q17 for pricing 2 NYMEX Crude Oil 98.60 103.0 97.31 73.04 48.83 57.99 46.70 42.15 33.73 45.56 45.02 49.25 51.95 48.32 48.12 55.48 62.96 67.85 69.60 related to one of our industrial CO sources of $7 million ($0.12 per Mcf) 2 N Y SE : DN R 32 w w w .d e n b u r y . c o m (1) CO Costs / Mcf 2 NYMEX Crude Oil Price / Bbl

Houston Area Land Sales Conroe Webster o ~3,400 surface acres consisting of 7 parcels for o ~800 surface acres consisting of 11 commercial commercial and residential development parcels o Multiple parcels along I-45 frontage road Pasadena Conroe 45 Sam Houston Tollway 45 Surface 1314 Acreage Pearland Surface Acreage 242 League City The Woodlands N Y SE : DN R 33 w w w .d e n b u r y . c o mHouston Area Land Sales Conroe Webster o ~3,400 surface acres consisting of 7 parcels for o ~800 surface acres consisting of 11 commercial commercial and residential development parcels o Multiple parcels along I-45 frontage road Pasadena Conroe 45 Sam Houston Tollway 45 Surface 1314 Acreage Pearland Surface Acreage 242 League City The Woodlands N Y SE : DN R 33 w w w .d e n b u r y . c o m

Non-GAAP Measures Reconciliation of net income (GAAP measure) to adjusted cash flows from operations (non-GAAP measure) to cash flows from operations (GAAP measure) 2017 2018 In millions Q1 Q2 Q3 Q4 FY Q1 Q2 Q3 Net income (GAAP measure) $22 $14 $0 $127 $163 $40 $30 $78 Adjustments to reconcile to adjusted cash flows from operations 52 53 208 52 53 51 51 51 Depletion, depreciation, and amortization (15) (132) (96) 15 10 18 35 16 Deferred income taxes 3 3 15 3 3 4 Stock-based compensation 4 5 25 78 30 15 41 (17) (52) (22) Noncash fair value adjustments on commodity derivatives 3 5 9 – (3) 1 2 1 Other $68 $134 $329 $125 $134 $135 $62 $65 Adjusted cash flows from operations (non-GAAP measure) (2) (10) (62) (33) 20 13 (38) (12) Net change in assets and liabilities relating to operations $66 $124 $267 $92 $154 $148 $24 $53 Cash flows from operations (GAAP measure) Adjusted cash flows from operations is a non-GAAP measure that represents cash flows provided by operations before changes in assets and liabilities, as summarized from the Company’s Consolidated Statements of Cash Flows. Adjusted cash flows from operations measures the cash flows earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. Management believes that it is important to consider this additional measure, along with cash flows from operations, as it believes the non-GAAP measure can often be a better way to discuss changes in operating trends in its business caused by changes in production, prices, operating costs and related factors, without regard to whether the earned or incurred item was collected or paid during that period. N Y SE : DN R 34 w w w .d e n b u r y . c o mNon-GAAP Measures Reconciliation of net income (GAAP measure) to adjusted cash flows from operations (non-GAAP measure) to cash flows from operations (GAAP measure) 2017 2018 In millions Q1 Q2 Q3 Q4 FY Q1 Q2 Q3 Net income (GAAP measure) $22 $14 $0 $127 $163 $40 $30 $78 Adjustments to reconcile to adjusted cash flows from operations 52 53 208 52 53 51 51 51 Depletion, depreciation, and amortization (15) (132) (96) 15 10 18 35 16 Deferred income taxes 3 3 15 3 3 4 Stock-based compensation 4 5 25 78 30 15 41 (17) (52) (22) Noncash fair value adjustments on commodity derivatives 3 5 9 – (3) 1 2 1 Other $68 $134 $329 $125 $134 $135 $62 $65 Adjusted cash flows from operations (non-GAAP measure) (2) (10) (62) (33) 20 13 (38) (12) Net change in assets and liabilities relating to operations $66 $124 $267 $92 $154 $148 $24 $53 Cash flows from operations (GAAP measure) Adjusted cash flows from operations is a non-GAAP measure that represents cash flows provided by operations before changes in assets and liabilities, as summarized from the Company’s Consolidated Statements of Cash Flows. Adjusted cash flows from operations measures the cash flows earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. Management believes that it is important to consider this additional measure, along with cash flows from operations, as it believes the non-GAAP measure can often be a better way to discuss changes in operating trends in its business caused by changes in production, prices, operating costs and related factors, without regard to whether the earned or incurred item was collected or paid during that period. N Y SE : DN R 34 w w w .d e n b u r y . c o m

Non-GAAP Measures (Cont.) Reconciliation of net income (GAAP measure) to adjusted EBITDAX (non-GAAP measure) 2017 2018 In millions Q3 Q4 FY Q1 Q2 Q3 TTM Net income (GAAP measure) $0 $127 $163 $40 $30 $78 $275 Adjustments to reconcile to Adjusted EBITDAX 25 23 99 75 Interest expense 17 16 19 (14) (134) (117) (95) Income tax expense (benefit) 14 9 16 52 53 207 209 Depletion, depreciation and amortization 52 53 51 Noncash fair value adjustments on commodity 25 78 29 117 15 41 (17) derivatives Stock-based compensation 3 3 15 3 3 4 13 (1) Noncash, non-recurring and other 11 7 25 1 1 (3) 6 $102 $157 $421 $600 Adjusted EBITDAX (non-GAAP measure) $142 $153 $148 1) Excludes proforma adjustments related to qualified acquisitions or dispositions under the Company’s senior secured bank credit facility. Adjusted EBITDAX is a non-GAAP financial measure which management uses and is calculated based upon (but not identical to) a financial covenant related to “Consolidated EBITDAX” in the Company’s senior secured bank credit facility, which excludes certain items that are included in net income, the most directly comparable GAAP financial measure. Items excluded include interest, income taxes, depletion, depreciation and amortization, and items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or are non-recurring. Management believes Adjusted EBITDAX may be helpful to investors in order to assess the Company’s operating performance as compared to that of other companies in its industry, without regard to financing methods, capital structure or historical costs basis. It is also commonly used by third parties to assess leverage and the Company’s ability to incur and service debt and fund capital expenditures. Adjusted EBITDAX should not be considered in isolation, as a substitute for, or more meaningful than, net income, cash flow from operations, or any other measure reported in accordance with GAAP. Adjusted EBITDAX may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDAX, EBITDAX or EBITDA in the same manner. N Y SE : DN R 35 w w w .d e n b u r y . c o mNon-GAAP Measures (Cont.) Reconciliation of net income (GAAP measure) to adjusted EBITDAX (non-GAAP measure) 2017 2018 In millions Q3 Q4 FY Q1 Q2 Q3 TTM Net income (GAAP measure) $0 $127 $163 $40 $30 $78 $275 Adjustments to reconcile to Adjusted EBITDAX 25 23 99 75 Interest expense 17 16 19 (14) (134) (117) (95) Income tax expense (benefit) 14 9 16 52 53 207 209 Depletion, depreciation and amortization 52 53 51 Noncash fair value adjustments on commodity 25 78 29 117 15 41 (17) derivatives Stock-based compensation 3 3 15 3 3 4 13 (1) Noncash, non-recurring and other 11 7 25 1 1 (3) 6 $102 $157 $421 $600 Adjusted EBITDAX (non-GAAP measure) $142 $153 $148 1) Excludes proforma adjustments related to qualified acquisitions or dispositions under the Company’s senior secured bank credit facility. Adjusted EBITDAX is a non-GAAP financial measure which management uses and is calculated based upon (but not identical to) a financial covenant related to “Consolidated EBITDAX” in the Company’s senior secured bank credit facility, which excludes certain items that are included in net income, the most directly comparable GAAP financial measure. Items excluded include interest, income taxes, depletion, depreciation and amortization, and items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or are non-recurring. Management believes Adjusted EBITDAX may be helpful to investors in order to assess the Company’s operating performance as compared to that of other companies in its industry, without regard to financing methods, capital structure or historical costs basis. It is also commonly used by third parties to assess leverage and the Company’s ability to incur and service debt and fund capital expenditures. Adjusted EBITDAX should not be considered in isolation, as a substitute for, or more meaningful than, net income, cash flow from operations, or any other measure reported in accordance with GAAP. Adjusted EBITDAX may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDAX, EBITDAX or EBITDA in the same manner. N Y SE : DN R 35 w w w .d e n b u r y . c o m

Transformational Combination of Denbury & Penn Virginia Investor Meetings Investor Presentation – November 13-15, 2018 – Nasdaq Ticker: PVAC November 2016Transformational Combination of Denbury & Penn Virginia Investor Meetings Investor Presentation – November 13-15, 2018 – Nasdaq Ticker: PVAC November 2016

Forward Looking and Cautionary Statements Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. We use words such as guidance, projects, estimates, “expects, continues, intends, “plans,” believes, forecasts, future, “potential,” and variations of such words or similar expressions in this presentation to identify forward-looking statements. Because such statements include assumptions, risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: the impact of our pending merger with Denbury Resources Inc. and our ability to complete the transaction as expected and realize its anticipated benefits; risks risks related to acquisitions, including the Company’s ability to realize their expected benefits; our ability to realize the expected benefits of our cost management strategy, including slickwater, saltwater disposal and gas lift; our ability to satisfy our short-term and long-term liquidity needs, including our ability to generate sufficient cash flows from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs; negative events or publicity adversely affecting our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties; plans, objectives, expectations and intentions contained in this presentation that are not historical; our ability to execute our business plan in volatile and depressed commodity price environments; any decline in and volatility of commodity prices for oil, NGLs, and natural gas; our anticipated production and development results; our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; any impairments, write-downs or write-offs of our reserves or assets; the projected demand for and supply of oil, NGLs and natural gas; our ability to contract for drilling rigs, frac crews, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from that estimated in our proved oil and natural gas reserves; drilling and operating risks; concentration of assets; our ability to compete effectively against other oil and gas companies; leasehold terms expiring before production can be established and our ability to replace expired leases; environmental obligations, results of new drilling activities, locations and methods, costs and liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements with other parties and counterparty risk related to the ability of these parties to meet their future obligations; the occurrence of unusual weather or operating conditions, including force majeure events and hurricanes; our ability to retain or attract senior management and key employees; especially with respect to environmental, health and safety matters; physical, electronic and cybersecurity risks and breaches; litigation that impacts us, our assets or our midstream service providers; uncertainties relating to general domestic and international economic and political conditions; and other risks set forth in our filings with the SEC, including our Annual Report on Form 10‐ K for the fiscal year ended December 31, 2017 and Quarterly Reports on Form 10-Q, which are available on our website at www.pennvirginia.com under Investors – SEC Filings. Additional information concerning these and other factors can be found in our press releases and public filings with the SEC. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management's views only as of the date hereof. The statements in this presentation speak only as of the date of this presentation and have not been updated for any information or events subsequent to that date. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable law. Oil and Gas Reserves Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Investors are urged to consider closely the disclosure in Penn Virginia’s public filings with the SEC, including its Annual Report on Form 10‐ K for the fiscal year ended December 31, 2017 and subsequent Quarterly Reports on Form 10-Q, which are available on its website at www.pennvirginia.com under Investors – SEC Filings. You can also obtain these reports from the SEC’s website at www.sec.gov. Definitions Proved reserves are those quantities of oil and gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate. Estimated ultimate recovery (EUR) is the sum of reserves remaining as of a given date and cumulative production as of that date. EUR is a measure that by its nature is more speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly is less certain. Cautionary Statements The estimates and guidance presented in this presentation are based on assumptions of capital expenditure levels, prices for oil, natural gas and NGLs, current indications of supply and demand for oil, well results and operating costs. IP 24-hour and IP 30-day production rate results might not be indicative of production over longer periods in the life of the well. The guidance, estimates and type curves provided or used in this presentation do not constitute any form of guarantee or assurance that the matters indicated will be achieved. Statements regarding inventory are based on current information, drilling program and economics or subject to material change. Past results are not necessarily indicative of future results, which may differ materially. The number of locations in the Company’s current estimated inventory or that will use enhanced oil recovery (EOR) is not a guarantee of the number of wells that will actually be drilled and completed or economic. While we believe these estimates and the assumptions on which they are based are reasonable, they are inherently uncertain and are subject to, among other things, significant business, economic, operational and regulatory risks and uncertainties and are subject to material revision. Actual results may differ materially from estimates and guidance. Reconciliation of Non‐ GAAP Financial Measures This presentation contains references to certain non‐ GAAP financial measures. Reconciliations between GAAP and non‐ GAAP financial measures are available in the appendix to this presentation. The non-GAAP financial measures presented may not provide information that is directly comparable to that provided by other companies, as other companies may calculate such financial results differently. The Company's non-GAAP financial measures are not measurements of financial performance under GAAP and should not be considered as alternatives to amounts presented in accordance with GAAP. The Company views these non-GAAP financial measures as supplemental and they are not intended to be a substitute for, or superior to, the information provided by GAAP financial results. 1Forward Looking and Cautionary Statements Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. We use words such as guidance, projects, estimates, “expects, continues, intends, “plans,” believes, forecasts, future, “potential,” and variations of such words or similar expressions in this presentation to identify forward-looking statements. Because such statements include assumptions, risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: the impact of our pending merger with Denbury Resources Inc. and our ability to complete the transaction as expected and realize its anticipated benefits; risks risks related to acquisitions, including the Company’s ability to realize their expected benefits; our ability to realize the expected benefits of our cost management strategy, including slickwater, saltwater disposal and gas lift; our ability to satisfy our short-term and long-term liquidity needs, including our ability to generate sufficient cash flows from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs; negative events or publicity adversely affecting our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties; plans, objectives, expectations and intentions contained in this presentation that are not historical; our ability to execute our business plan in volatile and depressed commodity price environments; any decline in and volatility of commodity prices for oil, NGLs, and natural gas; our anticipated production and development results; our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; any impairments, write-downs or write-offs of our reserves or assets; the projected demand for and supply of oil, NGLs and natural gas; our ability to contract for drilling rigs, frac crews, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from that estimated in our proved oil and natural gas reserves; drilling and operating risks; concentration of assets; our ability to compete effectively against other oil and gas companies; leasehold terms expiring before production can be established and our ability to replace expired leases; environmental obligations, results of new drilling activities, locations and methods, costs and liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements with other parties and counterparty risk related to the ability of these parties to meet their future obligations; the occurrence of unusual weather or operating conditions, including force majeure events and hurricanes; our ability to retain or attract senior management and key employees; especially with respect to environmental, health and safety matters; physical, electronic and cybersecurity risks and breaches; litigation that impacts us, our assets or our midstream service providers; uncertainties relating to general domestic and international economic and political conditions; and other risks set forth in our filings with the SEC, including our Annual Report on Form 10‐ K for the fiscal year ended December 31, 2017 and Quarterly Reports on Form 10-Q, which are available on our website at www.pennvirginia.com under Investors – SEC Filings. Additional information concerning these and other factors can be found in our press releases and public filings with the SEC. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management's views only as of the date hereof. The statements in this presentation speak only as of the date of this presentation and have not been updated for any information or events subsequent to that date. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable law. Oil and Gas Reserves Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Investors are urged to consider closely the disclosure in Penn Virginia’s public filings with the SEC, including its Annual Report on Form 10‐ K for the fiscal year ended December 31, 2017 and subsequent Quarterly Reports on Form 10-Q, which are available on its website at www.pennvirginia.com under Investors – SEC Filings. You can also obtain these reports from the SEC’s website at www.sec.gov. Definitions Proved reserves are those quantities of oil and gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate. Estimated ultimate recovery (EUR) is the sum of reserves remaining as of a given date and cumulative production as of that date. EUR is a measure that by its nature is more speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly is less certain. Cautionary Statements The estimates and guidance presented in this presentation are based on assumptions of capital expenditure levels, prices for oil, natural gas and NGLs, current indications of supply and demand for oil, well results and operating costs. IP 24-hour and IP 30-day production rate results might not be indicative of production over longer periods in the life of the well. The guidance, estimates and type curves provided or used in this presentation do not constitute any form of guarantee or assurance that the matters indicated will be achieved. Statements regarding inventory are based on current information, drilling program and economics or subject to material change. Past results are not necessarily indicative of future results, which may differ materially. The number of locations in the Company’s current estimated inventory or that will use enhanced oil recovery (EOR) is not a guarantee of the number of wells that will actually be drilled and completed or economic. While we believe these estimates and the assumptions on which they are based are reasonable, they are inherently uncertain and are subject to, among other things, significant business, economic, operational and regulatory risks and uncertainties and are subject to material revision. Actual results may differ materially from estimates and guidance. Reconciliation of Non‐ GAAP Financial Measures This presentation contains references to certain non‐ GAAP financial measures. Reconciliations between GAAP and non‐ GAAP financial measures are available in the appendix to this presentation. The non-GAAP financial measures presented may not provide information that is directly comparable to that provided by other companies, as other companies may calculate such financial results differently. The Company's non-GAAP financial measures are not measurements of financial performance under GAAP and should not be considered as alternatives to amounts presented in accordance with GAAP. The Company views these non-GAAP financial measures as supplemental and they are not intended to be a substitute for, or superior to, the information provided by GAAP financial results. 1

Penn Virginia Overview Pure Play Eagle Ford Shale Operator (1) § 98,500 gross / 84,700 net acres in Gonzales, Lavaca and Dewitt Counties; 99% Operated; 92% HBP § Substantial Lower Eagle Ford inventory estimated at 560 gross (2) locations (461 net) § Production is 77% oil / 90% liquids, sells in LLS market and generates robust adjusted EBITDAX margins § Active 3-rig program § Targeting Y-o-Y production growth (3) of ~120% for 2018 with current development program; 50-60% for 2019 1) As of November 8, 2018. 2) As of August 3, 2018. 3) Mid-point of production guidance, pro forma for Oklahoma asset sale. Guidance as of November 8, 2018 and the Company is not confirming guidance. 2Penn Virginia Overview Pure Play Eagle Ford Shale Operator (1) § 98,500 gross / 84,700 net acres in Gonzales, Lavaca and Dewitt Counties; 99% Operated; 92% HBP § Substantial Lower Eagle Ford inventory estimated at 560 gross (2) locations (461 net) § Production is 77% oil / 90% liquids, sells in LLS market and generates robust adjusted EBITDAX margins § Active 3-rig program § Targeting Y-o-Y production growth (3) of ~120% for 2018 with current development program; 50-60% for 2019 1) As of November 8, 2018. 2) As of August 3, 2018. 3) Mid-point of production guidance, pro forma for Oklahoma asset sale. Guidance as of November 8, 2018 and the Company is not confirming guidance. 2

Strong Operational and Financial Performance Third Quarter 2018 Highlights § Continued Operational Excellence in 3Q’18 § Drilled and turned to sales 10 gross (9.7 net) wells in the Eagle Ford § 2.1 MMBOE (77% oil), or 22,912 BOEPD § 9% increase in oil production over Q2’18 § Continue to be low cost operator - LOE of $4.70 per BOE Eagle Ford (1) Net Acreage: 84,700 (92% HBP) (2) Drilling Locations: Est. 560 gross/461 net § Impressive Financial Performance (3) Proved Reserves: 83 MMBOE (4) § Adjusted EBITDAX of $85.1 MM, up ~12% from Q2’18 § Selling 100% of oil into LLS market; realized $2.24 per barrel premium over WTI Houston Office (4) § Adjusted direct operating expenses per BOE of $12.84 (4) § Realized cash operating margin per BOE of $47.31 § On Track to Meet 2018 Goals and Setting Foundation for 2019 (5) § Anticipate ~120% production growth over 2017 (6) § Expect to grow production ~29% in Q4’18 over Q3’18 (7) § Estimate a LTM leverage ratio (debt to adjusted EBITDAX ) of ~1.5x by year-end (8) § Expect 2019 production growth of 50% - 60%, drilling within cash flow 1) As of November 8, 2018. 2) As of August 3, 2018. 3) As of December 31, 2017, pro forma for Hunt acquisition. 4) Non-GAAP financial measures reconciled in the appendix of this presentation. 5) Mid-point of production guidance, pro forma for Oklahoma asset sale. Guidance as of November 8, 2018 and the Company is not confirming guidance. 3 6) Calculated using actual production for 3Q’18 to mid-point of 4Q’18 guidance. Guidance as of November 8, 2018 and the Company is not confirming guidance. 7) Pro forma for acquisitions. 8) Based on $65 WTIStrong Operational and Financial Performance Third Quarter 2018 Highlights § Continued Operational Excellence in 3Q’18 § Drilled and turned to sales 10 gross (9.7 net) wells in the Eagle Ford § 2.1 MMBOE (77% oil), or 22,912 BOEPD § 9% increase in oil production over Q2’18 § Continue to be low cost operator - LOE of $4.70 per BOE Eagle Ford (1) Net Acreage: 84,700 (92% HBP) (2) Drilling Locations: Est. 560 gross/461 net § Impressive Financial Performance (3) Proved Reserves: 83 MMBOE (4) § Adjusted EBITDAX of $85.1 MM, up ~12% from Q2’18 § Selling 100% of oil into LLS market; realized $2.24 per barrel premium over WTI Houston Office (4) § Adjusted direct operating expenses per BOE of $12.84 (4) § Realized cash operating margin per BOE of $47.31 § On Track to Meet 2018 Goals and Setting Foundation for 2019 (5) § Anticipate ~120% production growth over 2017 (6) § Expect to grow production ~29% in Q4’18 over Q3’18 (7) § Estimate a LTM leverage ratio (debt to adjusted EBITDAX ) of ~1.5x by year-end (8) § Expect 2019 production growth of 50% - 60%, drilling within cash flow 1) As of November 8, 2018. 2) As of August 3, 2018. 3) As of December 31, 2017, pro forma for Hunt acquisition. 4) Non-GAAP financial measures reconciled in the appendix of this presentation. 5) Mid-point of production guidance, pro forma for Oklahoma asset sale. Guidance as of November 8, 2018 and the Company is not confirming guidance. 3 6) Calculated using actual production for 3Q’18 to mid-point of 4Q’18 guidance. Guidance as of November 8, 2018 and the Company is not confirming guidance. 7) Pro forma for acquisitions. 8) Based on $65 WTI

Key Slickwater Completions & Well Results 22 Choke (1) PVA Axis Unit PVA Rigby Unit 3 Well IP-24: 6,341 BOE/D 3 Well IP-24: 5,183 BOE/D IP-30: TBD GEN 4 IP-30: 3,928 BOE/D GEN 4 PVA Hawg Hunter Unit PVA Kudu Unit 3 Well IP-24: 11,532 BOE/D 4 Well IP-24: 5,889 BOE/D IP-30: 5,575 BOE/D IP-30: 3,343 BOE/D GEN 3 GEN 4 PVA Bertha Unit PVA Sable Unit 3 Well IP-24: 5,705 BOE/D 3 Well IP-24: 6,540 BOE/D IP-30: 2,918 BOE/D IP-30: 2,806 BOE/D GEN 4 GEN 2 PVA Schacherl-Effenberger PVA Lott Unit 2 Well IP-24: 3,075 BOE/D 3 Well IP-24: 4,286 BOE/D IP-30: 2,117 BOE/D IP-30: 2,958 BOE/D GEN 4 GEN 4 22 Choke (1) PVA Pilsner Unit PVA Schacherl-Vana 1 Well IP-24: 1,469 BOE/D 2 Well IP-24: 3,027 BOE/D GEN 4 IP-30: TBD IP-30: TBD GEN 4 (2) PVA Southern Hunter Amber TEAL Molnoskey Unit 2 Well IP-24: 5,092 BOE/D 2H : IP-24: 2,171 BOE/D (W-2 form) IP-30: 4,028 BOE/D GEN 4 PVA Raab Fojtik (SA) PVA Amber-Porter (SA) 2 Well Pad: Drilling 2 Well 24-IP: 3,979 BOE/D GEN 4 IP-30: TBD PVA D.Raab-Netardus 2 Well Pad: Drilling PVA Cinco J Ranch LTD Unit 3 Well IP-24: 5,798 BOE/D PVA Mc Creary-Technik Unit IP-30: 3,547 BOE/D 3 Well IP-24: 5,426 BOE/D GEN 3 IP-30: 3,843 BOE/D GEN 4 PVA L & J Lee Unit 3 Well IP-24: 3,877 BOE/D PVA Heatwave (SA) GEN 3 IP-30: 2,299 BOE/D 2 Well Pad: WOC GEN 4 PVA Lager PVA Sharktooth 1 Well IP-24: 2,511 BOE/D 2 Well IP-24: 3,366 BOE/D IP-30: 1,846 BOE/D GEN 4 IP-30: 2,423 BOE/D GEN 4 PVA Geo Hunter Unit RCR Shiner Unit (1) Preliminary Rates; additional 2 Well IP-24: 5,478 BOE/D 1H : Flowing Back choke changes likely before IP-24 IP-30: 3,786 BOE/D GEN 4 finalized (2) RCR Kloesel Unit (2) Data from Texas Railroad PVA Carol-Robin Unit 1H : IP 1,303 BOE/D (G-5 form) Commission 2 Well Pad: on Flowback GEN 4 (2) RCR Five Star Unit PVA Marcia-Shelly (SA) 1H : IP 1,479 BOE/D (G-5 form) 2 Well Pad: Drilling PVA Medina Unit 3 Well IP-24: 5,209 BOE/D IP-30: 3,827 BOE/D GEN 4/GEN 5 Offset Operator 4 EOR ProjectKey Slickwater Completions & Well Results 22 Choke (1) PVA Axis Unit PVA Rigby Unit 3 Well IP-24: 6,341 BOE/D 3 Well IP-24: 5,183 BOE/D IP-30: TBD GEN 4 IP-30: 3,928 BOE/D GEN 4 PVA Hawg Hunter Unit PVA Kudu Unit 3 Well IP-24: 11,532 BOE/D 4 Well IP-24: 5,889 BOE/D IP-30: 5,575 BOE/D IP-30: 3,343 BOE/D GEN 3 GEN 4 PVA Bertha Unit PVA Sable Unit 3 Well IP-24: 5,705 BOE/D 3 Well IP-24: 6,540 BOE/D IP-30: 2,918 BOE/D IP-30: 2,806 BOE/D GEN 4 GEN 2 PVA Schacherl-Effenberger PVA Lott Unit 2 Well IP-24: 3,075 BOE/D 3 Well IP-24: 4,286 BOE/D IP-30: 2,117 BOE/D IP-30: 2,958 BOE/D GEN 4 GEN 4 22 Choke (1) PVA Pilsner Unit PVA Schacherl-Vana 1 Well IP-24: 1,469 BOE/D 2 Well IP-24: 3,027 BOE/D GEN 4 IP-30: TBD IP-30: TBD GEN 4 (2) PVA Southern Hunter Amber TEAL Molnoskey Unit 2 Well IP-24: 5,092 BOE/D 2H : IP-24: 2,171 BOE/D (W-2 form) IP-30: 4,028 BOE/D GEN 4 PVA Raab Fojtik (SA) PVA Amber-Porter (SA) 2 Well Pad: Drilling 2 Well 24-IP: 3,979 BOE/D GEN 4 IP-30: TBD PVA D.Raab-Netardus 2 Well Pad: Drilling PVA Cinco J Ranch LTD Unit 3 Well IP-24: 5,798 BOE/D PVA Mc Creary-Technik Unit IP-30: 3,547 BOE/D 3 Well IP-24: 5,426 BOE/D GEN 3 IP-30: 3,843 BOE/D GEN 4 PVA L & J Lee Unit 3 Well IP-24: 3,877 BOE/D PVA Heatwave (SA) GEN 3 IP-30: 2,299 BOE/D 2 Well Pad: WOC GEN 4 PVA Lager PVA Sharktooth 1 Well IP-24: 2,511 BOE/D 2 Well IP-24: 3,366 BOE/D IP-30: 1,846 BOE/D GEN 4 IP-30: 2,423 BOE/D GEN 4 PVA Geo Hunter Unit RCR Shiner Unit (1) Preliminary Rates; additional 2 Well IP-24: 5,478 BOE/D 1H : Flowing Back choke changes likely before IP-24 IP-30: 3,786 BOE/D GEN 4 finalized (2) RCR Kloesel Unit (2) Data from Texas Railroad PVA Carol-Robin Unit 1H : IP 1,303 BOE/D (G-5 form) Commission 2 Well Pad: on Flowback GEN 4 (2) RCR Five Star Unit PVA Marcia-Shelly (SA) 1H : IP 1,479 BOE/D (G-5 form) 2 Well Pad: Drilling PVA Medina Unit 3 Well IP-24: 5,209 BOE/D IP-30: 3,827 BOE/D GEN 4/GEN 5 Offset Operator 4 EOR Project

Large Inventory of Locations With Attractive Returns Eagle Ford Economics by Area Capital Efficiency of XRLs Provides Superior ROR + + [67]% (1) UPdate Note: Based on management’s internal estimates as of June 30, 2018; economics based on $60 WTI, $3 natural gas and Gen 4 completion. Drilling locations as of August 3, 2018. 5Large Inventory of Locations With Attractive Returns Eagle Ford Economics by Area Capital Efficiency of XRLs Provides Superior ROR + + [67]% (1) UPdate Note: Based on management’s internal estimates as of June 30, 2018; economics based on $60 WTI, $3 natural gas and Gen 4 completion. Drilling locations as of August 3, 2018. 5

Selling into LLS Market LLS – Commanding Significant Premium Over WTI and Midland Prices • Q3’18 Production: 90% Liquids; ~77% Oil • Receives LLS Pricing, Premium Over WTI and Midland • Realized $71.67 per barrel in 3Q’18 • Blended Oil Yields ~43 Degree API Gravity Q3’18 Production Mix Q3’18 – LLS vs. WTI and Midland Pricing Oil NGLs Natural Gas LLS 10% WTI 13% Mid 77% 6Selling into LLS Market LLS – Commanding Significant Premium Over WTI and Midland Prices • Q3’18 Production: 90% Liquids; ~77% Oil • Receives LLS Pricing, Premium Over WTI and Midland • Realized $71.67 per barrel in 3Q’18 • Blended Oil Yields ~43 Degree API Gravity Q3’18 Production Mix Q3’18 – LLS vs. WTI and Midland Pricing Oil NGLs Natural Gas LLS 10% WTI 13% Mid 77% 6

Crude Oil Delivery Optionality • Geographic Location Provides PVAC’s Production Access to LLS Markets and Pricing Flatonia • Three Delivery Points Enterprise Products Line • Kinder Morgan Pipeline • Houston Ship Channel • Phillips 66 Refinery - Sweeny • Enterprise Products Line (Eagle Ford Crude Oil System) • Trucked from wellhead or CDP to multiple markets • ~84% of PVAC Oil Production on Pipe Kinder Morgan Line to Houston Ship Channel or Phillips 66 Refinery Ample Takeaway Capacity 7Crude Oil Delivery Optionality • Geographic Location Provides PVAC’s Production Access to LLS Markets and Pricing Flatonia • Three Delivery Points Enterprise Products Line • Kinder Morgan Pipeline • Houston Ship Channel • Phillips 66 Refinery - Sweeny • Enterprise Products Line (Eagle Ford Crude Oil System) • Trucked from wellhead or CDP to multiple markets • ~84% of PVAC Oil Production on Pipe Kinder Morgan Line to Houston Ship Channel or Phillips 66 Refinery Ample Takeaway Capacity 7

Production Growth (1) Targeting 120+% Year-Over-Year Production Growth (pro forma for Oklahoma sale) Lower Adjusted Increasing Increasing Realized Lowers Direct Operating Production Cash Operating Margin Expenses per Leverage Metric 120+% Y-O-Y per BOE BOE (2) Peer Leading 2018 Production Growth 28,500 – 30,500 BOEPD 22,912 BOEPD 22,200 BOEPD 16,145 BOEPD 12,340 BOEPD 4Q17A 1Q18A 2Q18A 3Q18A 4Q18E 2019 Production Growth Expected to be 50-60% Note: Guidance as of November 8, 2018 and the Company is not confirming guidance. 1) Assumes mid-point of production guidance, pro forma for Oklahoma sale. 2) Peers include: CRZO, ESTE, LONE, SN, SNDE and WRD. 8Production Growth (1) Targeting 120+% Year-Over-Year Production Growth (pro forma for Oklahoma sale) Lower Adjusted Increasing Increasing Realized Lowers Direct Operating Production Cash Operating Margin Expenses per Leverage Metric 120+% Y-O-Y per BOE BOE (2) Peer Leading 2018 Production Growth 28,500 – 30,500 BOEPD 22,912 BOEPD 22,200 BOEPD 16,145 BOEPD 12,340 BOEPD 4Q17A 1Q18A 2Q18A 3Q18A 4Q18E 2019 Production Growth Expected to be 50-60% Note: Guidance as of November 8, 2018 and the Company is not confirming guidance. 1) Assumes mid-point of production guidance, pro forma for Oklahoma sale. 2) Peers include: CRZO, ESTE, LONE, SN, SNDE and WRD. 8

(1) Declining Adjusted Direct Operating Expenses per BOE Lower Adjusted Increasing Increasing Realized Direct Operating Lowers Cash Operating Production Expenses per Leverage Metric 120+% Y-O-Y Margin per BOE BOE • LOE per BOE declined by ~18% from 2017 (2) • Adjusted Cash G&A per BOE declined by ~31% from 2017 $14.41 $13.25 $13.05 $12.84 $11.63 2017A 4Q17A 1Q18A 2Q18A 3Q18A Adjusted Direct Operating Expenses per BOE Expected to Decrease Significantly by Year-End 1) Adjusted Direct Operating Expenses per BOE is comprised of the sum of (Lease Operating Expense + GPT Expense + Adjusted Cash G&A Expense(2) + Production and Ad Valorem Taxes)/Total Production. 2) Adjusted Direct Operating Expenses per BOE and Adjusted Cash G&A per BOE are non-GAAP financial measures. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial measures appear at the end of this presentation. 9(1) Declining Adjusted Direct Operating Expenses per BOE Lower Adjusted Increasing Increasing Realized Direct Operating Lowers Cash Operating Production Expenses per Leverage Metric 120+% Y-O-Y Margin per BOE BOE • LOE per BOE declined by ~18% from 2017 (2) • Adjusted Cash G&A per BOE declined by ~31% from 2017 $14.41 $13.25 $13.05 $12.84 $11.63 2017A 4Q17A 1Q18A 2Q18A 3Q18A Adjusted Direct Operating Expenses per BOE Expected to Decrease Significantly by Year-End 1) Adjusted Direct Operating Expenses per BOE is comprised of the sum of (Lease Operating Expense + GPT Expense + Adjusted Cash G&A Expense(2) + Production and Ad Valorem Taxes)/Total Production. 2) Adjusted Direct Operating Expenses per BOE and Adjusted Cash G&A per BOE are non-GAAP financial measures. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial measures appear at the end of this presentation. 9

(1) Strong Realized Cash Operating Margin per BOE Lower Adjusted Increasing Increasing Realized Direct Operating Lowers Production Cash Operating Margin Expenses per Leverage Metric 120+% Y-O-Y per BOE BOE LLS Pricing and Low Cost Structure Yield Strong Cash Operating Margins $47.31 $43.39 $39.94 $34.44 $27.79 2017A 4Q17A 1Q18A 2Q18A 3Q18A 1) Realized Cash Operating Margin per BOE is a non-GAAP financial measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial measures appear at the end of this presentation. 10(1) Strong Realized Cash Operating Margin per BOE Lower Adjusted Increasing Increasing Realized Direct Operating Lowers Production Cash Operating Margin Expenses per Leverage Metric 120+% Y-O-Y per BOE BOE LLS Pricing and Low Cost Structure Yield Strong Cash Operating Margins $47.31 $43.39 $39.94 $34.44 $27.79 2017A 4Q17A 1Q18A 2Q18A 3Q18A 1) Realized Cash Operating Margin per BOE is a non-GAAP financial measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial measures appear at the end of this presentation. 10

Balance Sheet Improvement LTM Net Debt to Adjusted EBITDAX Lower Adjusted Lowers Increasing Increasing Realized Cash Direct Operating Leverage Production Operating Margin per BOE Expenses per Metric 120+% Y-O-Y BOE • Expect to Spend Within Cash Flow in 2019 (1) (1) 2.6x 2.6x • Targeting Leverage Ratio of ~1.5x (Debt / (2) 2.4x LTM Adj. EBITDAX) (2) 2.2x (2) 1.9x (2) ~1.5x PF YE17A 1Q18A 2Q18A 3Q18A YE18E Strong Cash Flow Growth Rapidly Improves Balance Sheet 1) Pro forma for Devon and Hunt Acquisition (2017 year-end debt / Adjusted EBITDAX was 2.3x). 2) Pro forma for acquisitions. 11Balance Sheet Improvement LTM Net Debt to Adjusted EBITDAX Lower Adjusted Lowers Increasing Increasing Realized Cash Direct Operating Leverage Production Operating Margin per BOE Expenses per Metric 120+% Y-O-Y BOE • Expect to Spend Within Cash Flow in 2019 (1) (1) 2.6x 2.6x • Targeting Leverage Ratio of ~1.5x (Debt / (2) 2.4x LTM Adj. EBITDAX) (2) 2.2x (2) 1.9x (2) ~1.5x PF YE17A 1Q18A 2Q18A 3Q18A YE18E Strong Cash Flow Growth Rapidly Improves Balance Sheet 1) Pro forma for Devon and Hunt Acquisition (2017 year-end debt / Adjusted EBITDAX was 2.3x). 2) Pro forma for acquisitions. 11

AppendixAppendix

(1) Updated Hedge Portfolio Mitigating Commodity Price Volatility Through Proactive Hedging Program 12,000 $57.05 10,000 8,000 $54.48 $65.27 $54.09 6,000 $59.17 4,000 2,000 - 0 Q3-Q4 2018 2019 2020 WTI WTI LLS LLS Volumes Average Price Volumes Average Price (Bbls / Day) ($ / Bbl) (Bbls / Day) ($ / Barrel) Q3-Q4 2018 10,455 $57.05 6,000 $65.27 2019 6,415 $54.48 5,000 $59.17 2020 6,000 $54.09 - - 1) As of 08/08/2018. 13 Oil Barrels Per Day(1) Updated Hedge Portfolio Mitigating Commodity Price Volatility Through Proactive Hedging Program 12,000 $57.05 10,000 8,000 $54.48 $65.27 $54.09 6,000 $59.17 4,000 2,000 - 0 Q3-Q4 2018 2019 2020 WTI WTI LLS LLS Volumes Average Price Volumes Average Price (Bbls / Day) ($ / Bbl) (Bbls / Day) ($ / Barrel) Q3-Q4 2018 10,455 $57.05 6,000 $65.27 2019 6,415 $54.48 5,000 $59.17 2020 6,000 $54.09 - - 1) As of 08/08/2018. 13 Oil Barrels Per Day

Non-GAAP Reconciliation – Adjusted EBITDAX - Unaudited Reconciliation of GAAP Net income (loss) to Non-GAAP Adjusted EBITDAX Adjusted EBITDAX represents net income (loss) before interest expense, income tax expense, depreciation, depletion and amortization expense and share- based compensation expense, further adjusted to exclude the effects of gains and losses on sales of assets, non-cash changes in the fair value of derivatives, and special items including acquisition and divestiture transaction costs, executive retirement costs and restructuring expenses. We believe this presentation is commonly used by investors and professional research analysts for the valuation, comparison, rating, and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income (loss). Adjusted EBITDAX as defined by Penn Virginia may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) and other measures prepared in accordance with GAAP, such as operating income or cash flows from operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Penn Virginia's results as reported under GAAP. Three Months Ended Nine Months Ended September 30, June 30, September 30, September 30, September 30, 2018 2018 2017 2018 2017 (in thousands, except per unit amounts) Net income (loss) $ 16,276 $ (2,521) $ (5,947) $ 24,050 $ 43,463 Adjustments to reconcile to Adjusted EBITDAX: Interest expense, net 7,322 6,150 1,202 18,073 3,014 Income tax (benefit) expense (10) - - 153 - Depreciation, depletion and amortization 35, 016 31,273 10,659 88, 370 31,545 Share-based compensation expense (equity-classified) 1,021 875 1,013 3,472 2,707 (Gain) loss on sales of assets, net (2) (4) (9) (81) 60 Adjustments for derivatives: Net losses (gains) 40, 689 52, 241 12,275 111,725 (15,802) Cash settlements, net (15,214) (12,401) 788 (35,191) (1,670) Adjustment for special items: Acquisition, divestiture and strategic transaction costs 44 56 1,505 531 1,505 Executive retirement costs - - - 250 - Other, net (80) - - (80) - Restructuring expenses - - - - (20) Adjusted EBITDAX $ 85,062 $ 75,669 $ 21,486 $ 211,272 $ 64,802 Adjusted EBITDAX per BOE $ 40.35 $ 37.46 $ 24.85 $ 37.85 $ 24.51 14Non-GAAP Reconciliation – Adjusted EBITDAX - Unaudited Reconciliation of GAAP Net income (loss) to Non-GAAP Adjusted EBITDAX Adjusted EBITDAX represents net income (loss) before interest expense, income tax expense, depreciation, depletion and amortization expense and share- based compensation expense, further adjusted to exclude the effects of gains and losses on sales of assets, non-cash changes in the fair value of derivatives, and special items including acquisition and divestiture transaction costs, executive retirement costs and restructuring expenses. We believe this presentation is commonly used by investors and professional research analysts for the valuation, comparison, rating, and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income (loss). Adjusted EBITDAX as defined by Penn Virginia may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) and other measures prepared in accordance with GAAP, such as operating income or cash flows from operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Penn Virginia's results as reported under GAAP. Three Months Ended Nine Months Ended September 30, June 30, September 30, September 30, September 30, 2018 2018 2017 2018 2017 (in thousands, except per unit amounts) Net income (loss) $ 16,276 $ (2,521) $ (5,947) $ 24,050 $ 43,463 Adjustments to reconcile to Adjusted EBITDAX: Interest expense, net 7,322 6,150 1,202 18,073 3,014 Income tax (benefit) expense (10) - - 153 - Depreciation, depletion and amortization 35, 016 31,273 10,659 88, 370 31,545 Share-based compensation expense (equity-classified) 1,021 875 1,013 3,472 2,707 (Gain) loss on sales of assets, net (2) (4) (9) (81) 60 Adjustments for derivatives: Net losses (gains) 40, 689 52, 241 12,275 111,725 (15,802) Cash settlements, net (15,214) (12,401) 788 (35,191) (1,670) Adjustment for special items: Acquisition, divestiture and strategic transaction costs 44 56 1,505 531 1,505 Executive retirement costs - - - 250 - Other, net (80) - - (80) - Restructuring expenses - - - - (20) Adjusted EBITDAX $ 85,062 $ 75,669 $ 21,486 $ 211,272 $ 64,802 Adjusted EBITDAX per BOE $ 40.35 $ 37.46 $ 24.85 $ 37.85 $ 24.51 14

Non-GAAP Reconciliation – Adjusted Cash G&A - Unaudited Reconciliation of GAAP General administrative expenses to Non-GAAP Adjusted cash general and administrative expenses Adjusted cash general and administrative expense ( Adjusted cash G&A ) is a supplemental non-GAAP financial measure that excludes certain non- recurring expenses and non-cash share-based compensation expense. We believe that the non-GAAP measure of Adjusted cash G&A is useful to investors because it provides readers with a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. Three Twelve Three Months Ended Nine Months Ended Months Ended Months Ended September 30, June 30, September 30, September 30, September 30, December 31, December 31, 2018 2018 2017 2018 2017 2017 2017 (in thousands, except per unit amounts) General and administrative expenses - direct $ 5, 134 $ 4,447 $ 5,919 $ 14,476 $ 12,034 $ 2,360 $ 14,453 Share-based compensation - equity-classified awards 1,021 875 1,013 3,472 2,707 1,102 3,809 GAAP General and administrative expenses 6,155 5,322 6,932 17,948 14,741 3,462 18,262 Less: Share-based compensation - equity-classified awards (1,021) (875) (1,013) (3,472) (2,707) (1,102) (3,809) Significant special charges: Acquisition, divestiture and strategic transaction costs (44) (56) (1,505) (531) (1,505) 165 (1,340) Executive retirement costs - - - (250) - - - Restructuring expenses - - - - 20 - 20 Adjusted cash-based general and administrative expenses $ 5,090 $ 4,391 $ 4,414 $ 13,695 $ 10,549 $ 2,525 $ 13,133 GAAP General and administrative expenses per BOE $ 2.92 $ 2.63 $ 8.02 $ 3.22 $ 5.58 $ 3.05 $ 4.83 Adjusted cash-based general and administrative expenses per BOE $ 2.41 $ 2.17 $ 5.11 $ 2.45 $ 3.99 $ 2.22 $ 3.48 15Non-GAAP Reconciliation – Adjusted Cash G&A - Unaudited Reconciliation of GAAP General administrative expenses to Non-GAAP Adjusted cash general and administrative expenses Adjusted cash general and administrative expense ( Adjusted cash G&A ) is a supplemental non-GAAP financial measure that excludes certain non- recurring expenses and non-cash share-based compensation expense. We believe that the non-GAAP measure of Adjusted cash G&A is useful to investors because it provides readers with a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. Three Twelve Three Months Ended Nine Months Ended Months Ended Months Ended September 30, June 30, September 30, September 30, September 30, December 31, December 31, 2018 2018 2017 2018 2017 2017 2017 (in thousands, except per unit amounts) General and administrative expenses - direct $ 5, 134 $ 4,447 $ 5,919 $ 14,476 $ 12,034 $ 2,360 $ 14,453 Share-based compensation - equity-classified awards 1,021 875 1,013 3,472 2,707 1,102 3,809 GAAP General and administrative expenses 6,155 5,322 6,932 17,948 14,741 3,462 18,262 Less: Share-based compensation - equity-classified awards (1,021) (875) (1,013) (3,472) (2,707) (1,102) (3,809) Significant special charges: Acquisition, divestiture and strategic transaction costs (44) (56) (1,505) (531) (1,505) 165 (1,340) Executive retirement costs - - - (250) - - - Restructuring expenses - - - - 20 - 20 Adjusted cash-based general and administrative expenses $ 5,090 $ 4,391 $ 4,414 $ 13,695 $ 10,549 $ 2,525 $ 13,133 GAAP General and administrative expenses per BOE $ 2.92 $ 2.63 $ 8.02 $ 3.22 $ 5.58 $ 3.05 $ 4.83 Adjusted cash-based general and administrative expenses per BOE $ 2.41 $ 2.17 $ 5.11 $ 2.45 $ 3.99 $ 2.22 $ 3.48 15

Non-GAAP Reconciliation – Adjusted Direct Operating Expenses - Unaudited Reconciliation of GAAP Operating expenses to Non-GAAP Adjusted direct operating expenses Adjusted direct operating expenses and adjusted direct operating expenses per BOE are a supplemental non-GAAP financial measure that excludes certain non-recurring expenses and non-cash expenses. We believe that the non-GAAP measure of Adjusted direct operating expense per BOE is useful to investors because it provides readers with a meaningful measure of our cost profile and provides for greater comparability period-over-period. Three Twelve Three Months Ended Nine Months Ended Months Ended Months Ended September 30, June 30, September 30, September 30, September 30, December 31, December 31, 2018 2018 2017 2018 2017 2017 2017 (in thousands, except per unit amounts) Operating expenses $ 63,149 $ 55,694 $ 26,912 $ 162,142 $ 75,097 $ 33,085 $ 108,243 Less: Share-based compensation - equity-classified awards ( 1,021) (875) ( 1,013) ( 3,472) (2,707) (1,102) (3,809) Depreciation, depletion and amortization (35,016) (31,273) (10,659) (88,370) (31,545) (17,104) (48,649) Significant special charges: Acquisition, divestiture and strategic transaction costs (44) (56) ( 1,505) (531) (1,505) 165 (1,340) Executive retirement costs - - - (250) - - - Restructuring expenses - - - - 20 - 20 Non-GAAP Adjusted direct operating expenses $ 27,068 $ 23,490 $ 13,735 $ 69,519 $ 39,360 $ 15,044 $ 54,465 Non-GAAP Adjusted direct operating expenses per BOE $ 12.84 $ 11.63 $ 15.89 $ 12.46 $ 14.89 $ 13.25 $ 14.41 16Non-GAAP Reconciliation – Adjusted Direct Operating Expenses - Unaudited Reconciliation of GAAP Operating expenses to Non-GAAP Adjusted direct operating expenses Adjusted direct operating expenses and adjusted direct operating expenses per BOE are a supplemental non-GAAP financial measure that excludes certain non-recurring expenses and non-cash expenses. We believe that the non-GAAP measure of Adjusted direct operating expense per BOE is useful to investors because it provides readers with a meaningful measure of our cost profile and provides for greater comparability period-over-period. Three Twelve Three Months Ended Nine Months Ended Months Ended Months Ended September 30, June 30, September 30, September 30, September 30, December 31, December 31, 2018 2018 2017 2018 2017 2017 2017 (in thousands, except per unit amounts) Operating expenses $ 63,149 $ 55,694 $ 26,912 $ 162,142 $ 75,097 $ 33,085 $ 108,243 Less: Share-based compensation - equity-classified awards ( 1,021) (875) ( 1,013) ( 3,472) (2,707) (1,102) (3,809) Depreciation, depletion and amortization (35,016) (31,273) (10,659) (88,370) (31,545) (17,104) (48,649) Significant special charges: Acquisition, divestiture and strategic transaction costs (44) (56) ( 1,505) (531) (1,505) 165 (1,340) Executive retirement costs - - - (250) - - - Restructuring expenses - - - - 20 - 20 Non-GAAP Adjusted direct operating expenses $ 27,068 $ 23,490 $ 13,735 $ 69,519 $ 39,360 $ 15,044 $ 54,465 Non-GAAP Adjusted direct operating expenses per BOE $ 12.84 $ 11.63 $ 15.89 $ 12.46 $ 14.89 $ 13.25 $ 14.41 16

Non-GAAP Reconciliation – Realized Cash Operating Margin Unaudited Reconciliation of GAAP Income (loss) before income taxes to Non-GAAP Realized cash operating margin Realized cash operating margin and realized cash operating margin per BOE are a supplemental non-GAAP financial measure that excludes certain non- recurring expenses, certain non-operating items and non-cash expenses. We believe that the non-GAAP measure of realized cash operating margin per BOE is useful to investors because it provides readers with a meaningful measure of our operating profitability and provides for greater comparability period-over-period. Three Twelve Three Months Ended Nine Months Ended Months Ended Months Ended September 30, June 30, September 30, September 30, September 30, December 31, December 31, 2018 2018 2017 2018 2017 2017 2017 (in thousands, except per unit amounts) Income (loss) before income taxes $ 16,266 $ (2,521) $ (5,947) $ 24,203 $ 43,463 $ (15,744) $ 27,719 Plus: Interest expense, net 7,322 6,150 1,202 18, 073 3,014 3, 378 6,392 Derivatives 40, 689 52,241 12, 275 111,725 (15,802) 33,621 17,819 Other, net (241) 16 17 (167) (45) (13) (119) Share-based compensation - equity classified awards 1,021 875 1,013 3,472 2,707 1, 102 3, 809 Acquisition, divestiture and strategic transaction costs 44 56 1,505 531 1,505 ( 165) 1,340 Executive retirement costs - - - 250 - - - Restructuring expenses - - - - (20) - (20) Depreciation, depletion and amortization 35, 016 31, 273 10, 659 88, 370 31, 545 17,104 48,649 Less: (Gain) loss on sales of assets, net (2) (4) (9) (81) 60 (24) 36 Other revenues, net (380) (415) (117) (937) (462) (159) (621) Non-GAAP Realized cash operating margin $ 99,735 $ 87,671 $ 20,598 $ 245,439 $ 65,965 $ 39,100 $ 105,004 Non-GAAP Realized cash operating margin per BOE $ 47.31 $ 43.40 $ 23.83 $ 43.98 $ 24.95 $ 34.44 $ 27.79 17Non-GAAP Reconciliation – Realized Cash Operating Margin Unaudited Reconciliation of GAAP Income (loss) before income taxes to Non-GAAP Realized cash operating margin Realized cash operating margin and realized cash operating margin per BOE are a supplemental non-GAAP financial measure that excludes certain non- recurring expenses, certain non-operating items and non-cash expenses. We believe that the non-GAAP measure of realized cash operating margin per BOE is useful to investors because it provides readers with a meaningful measure of our operating profitability and provides for greater comparability period-over-period. Three Twelve Three Months Ended Nine Months Ended Months Ended Months Ended September 30, June 30, September 30, September 30, September 30, December 31, December 31, 2018 2018 2017 2018 2017 2017 2017 (in thousands, except per unit amounts) Income (loss) before income taxes $ 16,266 $ (2,521) $ (5,947) $ 24,203 $ 43,463 $ (15,744) $ 27,719 Plus: Interest expense, net 7,322 6,150 1,202 18, 073 3,014 3, 378 6,392 Derivatives 40, 689 52,241 12, 275 111,725 (15,802) 33,621 17,819 Other, net (241) 16 17 (167) (45) (13) (119) Share-based compensation - equity classified awards 1,021 875 1,013 3,472 2,707 1, 102 3, 809 Acquisition, divestiture and strategic transaction costs 44 56 1,505 531 1,505 ( 165) 1,340 Executive retirement costs - - - 250 - - - Restructuring expenses - - - - (20) - (20) Depreciation, depletion and amortization 35, 016 31, 273 10, 659 88, 370 31, 545 17,104 48,649 Less: (Gain) loss on sales of assets, net (2) (4) (9) (81) 60 (24) 36 Other revenues, net (380) (415) (117) (937) (462) (159) (621) Non-GAAP Realized cash operating margin $ 99,735 $ 87,671 $ 20,598 $ 245,439 $ 65,965 $ 39,100 $ 105,004 Non-GAAP Realized cash operating margin per BOE $ 47.31 $ 43.40 $ 23.83 $ 43.98 $ 24.95 $ 34.44 $ 27.79 17