Filed by Denbury Resources Inc. (Commission File No. 001‐12935) Pursuant to Rule 425 of the Securities Act of 1933 and deemed filed pursuant to Rule 14a‐12 of the Securities Exchange Act of 1934 Subject Company: Penn Virginia Corporation (Commission File No. 001‐13283) Bank of America Merrill Lynch  2018 Global Energy  Conference November 15, 2018 NYSE:DNR

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 shareholders 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. Investorsandsecurityholderswillbeabletoobtainfreecopiesoftheregistration 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 Copies of documents filed with the SEC by Denbury will be made available free of charge on Denbury’s website at 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 madeavailablefreeofchargeonPennVirginia’, 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 or by accessing Denbury’s website at 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 or by accessing Penn Virginia’s website at 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. NYSE:DNR 2

Cautionary Statements (Cont.) Forward‐Looking Statements and Cautionary Statements: The following slides contain “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 reserves, 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 and on the SEC’s website at, 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 and on the SEC’s website at 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 forward‐looking statements regarding 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. NYSE:DNR 3

Uncommon Company, Extraordinary Potential » Industry Leading Oil Weighting Extreme Oil Gearing »Top Tier Operating Margin »Favorable Crude Quality & High Exposure to LLS Pricing » Vertically Integrated CO2 Supply and Infrastructure Operating Advantages »Cost Structure Largely Independent from Industry » Operating Outside Constrained Basins Significant Organic  »Newly Sanctioned EOR Project at CCA »Significant EOR Development Potential Growth Potential »Growing Portfolio of Short‐Cycle Opportunities »Strong Liquidity Rapidly De‐Levering »No Near‐Term Maturities » Reduced Debt/Improved Balance Sheet NYSE:DNR 4

Denbury –What We Are A Unique Energy Business Rocky  Mountain  • ~60% of production via CO2 enhanced oil recovery (EOR) Region • Vertically integrated CO2 supply and distribution • 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 Value Sustaining with Organic Growth Upside 260 MMBOE • Over 1 Billion BOE proved + EOR and exploitation potential YE17 Proved CO2 Reserves Intensely Focused on Execution and Results 6.4 Tcf • 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  Denbury Owned Fields Current Pipelines CO2 into our reservoirs CO2 Sources Planned Pipelines NYSE:DNR 5

Industry Leading Oil Weighting 100% 2Q18 % Liquids Production Oil Production 97% 90% 97% NGL Production 80% Peer Average (% Liquids) 70% Peer Average (% Oil) 60% 50% 40% 30% 20% 10% 0% DNR(1) Peer A Peer B Peer C Peer D Peer E Peer F(1) Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N Peer O(1) 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. NYSE:DNR 6

Top Tier Operating Margin 2Q18 Peer Operating Margins ($/BOE)  $40  $35 Peer Average  $30  $25  $20  $15  $10  $5  $‐ Peer APeer BDNRPeer CPeer DPeer EPeer FPeer GPeer HPeer IPeer JPeer KPeer LPeer MPeer NPeer OPeer PPeer QPeer RPeer SPeer TPeer U Operating Margin per BOE(1) 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 Lifting Cost per BOE(2) 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 Revenue per BOE(3) 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.  NYSE:DNR 7

Gulf Coast Region  Reserves Summary(1) (MMBOE) Proved + Tertiary Potential Tertiary Reserves Proved 127 Potential 306 Non‐Tertiary Reserves Proved 21 Total MMBOE(2) 454 Tertiary Potential by Field(3) 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 CO2 Floods Naturally‐Occurring CO2 Source Fields Owned by Others –CO2 EOR Candidates Webster 40 –75 Industrial CO2 Sources W. Yellow Creek 5 –10 Note: See “Slide Notes” on slide 39 in the appendix to this presentation for footnote explanations. NYSE:DNR 8

Rocky Mountain Region  Reserves Summary(1) (MMBOE) Proved + Tertiary Potential Tertiary Reserves Proved 26 Potential 534 Non‐Tertiary Reserves Proved 86 Total MMBOE(2) 646 Tertiary Potential by Field(3) Bell Creek 20 –40 Cedar Creek  400 –500 Anticline Area Denbury Operated Pipelines Gas Draw 10 Denbury Planned Pipelines Grieve 5 Pipelines Owned by Others CO2 Resources Owned or Contracted Hartzog Draw 30 –40 Denbury Owned Fields – Current CO2 Floods Denbury Owned Fields –Potential CO2 Floods Salt Creek 25 –35 Fields Owned by Others –CO2 EOR Candidates Note: See “Slide Notes” on slide 39 in the appendix to this presentation for footnote explanations. NYSE:DNR 9

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 NYSE:DNR 10

2018E Capital Plan & Production Guidance 2018 Development Capital Budget (1) 2018 Production Guidance (BOE/d) In Millions $300 ‐ $325 Million  ~$45 60,100 ‐ 60,600 60,298  ~$20 ~ $155 Tertiary $241 MM  (2) ~$300‐325 MM  2 $95 CapEx CapEx Non‐Tertiary ~ CO2  Sources & Other Other Capitalized Items(2) FY20162017 20172018 2018 1) Excludes ~$30 million of capitalized interest. 2) Includes capitalized internal acquisition, exploration and development costs and pre‐ production tertiary startup costs. NYSE:DNR 11

Sanctioning CO2 EOR Development at CCA 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 CO2 Flood Type  Miscible API Gravity  29‐38 Average Perm 5 md Average Porosity  11.4% OOIP  ~5 Billion Barrels Oil Recovered to Date ~700 Million Barrels Note: The information included in slides 12 through 16,  other than historical facts, are forward‐looking statements  based on current estimates.  See slide 3, “Cautionary  Est. Tertiary Recovery Factor 8 – 15% Statements” for risks and uncertainties related to this  forward‐looking information. NYSE:DNR 12

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 • Targets ~30 MMBbls of recoverable oil; first tertiary production expected late  Est. 5 Billion Bbls OOIP 2021/early 2022 • Excluding CO2 pipeline, ~$100 MM development capital to initial tertiary  production; ~$400 MM total capital over 15‐year period • Requires $150 MM CO2 pipeline that will service all future CCA EOR development Phase 2 EOR Target • Pipeline cost represents <$0.50/Bbl across total CCA EOR potential ~100 MMBbls oil • 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 • Targets ~100 MMBbls of recoverable oil ~30 MMBbls 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. CO2 Pipeline from Bell Creek Note: See “Note” on slide 12 related to the forward‐looking information included on this slide. NYSE:DNR 13

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 CO2 availability and other factors  • Planned Phase 2 Phase 1 investment, including full CO2 pipeline, attractive  Phase 1 at $50 oil 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 • Initial pipeline investment benefits all incremental  development • Phase 1 payout expected within 2 years after first  Est. Cumulative Net Cash Flow @ $60 oil production; future phases funded from project cashflow $ in millions ~$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 • Expect tertiary LOE to average $10‐$15/Bbl  500  ‐  (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. NYSE:DNR 14

Exploitation –A New Dimension for Growth Size of circles = Cost to test Costs per test range from $0.5MM – $8MM Large Short‐Cycle Opportunity Set ‐ Testing in 2018 3020 • Numerous exploitation targets across  2818 Denbury’s 600,000 acre asset base 16 • Potential 65 MMBOE risked; 135 MMBOE  14 unrisked 12 • Adding new opportunities as team works  (1) extensive proprietary 3D seismic data set 10 Mission Canyon‐Pennel MMBOE   • Spending ~$30MM – $40MM in 2018 to  8 EUR, accelerate program    6 • Testing > 40 MMBOE ultimate risked resource  Potential potential in 2018 4 • Successful first 3 Mission Canyon wells at CCA,  2 de‐risking multi‐well follow‐on program 0 Note: See “Note” on slide 12 related to the forward‐looking information included on this slide. Lower Increasing Probability of Success  Higher NYSE:DNR 15

Mission Canyon Mission Canyon Exploitation • Added 2nd rig in late 3Q • Successful test at Cabin Creek with 24 hour rate >1000 BOPD Cedar Creek Anticline • 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. NYSE:DNR 16

Tinsley Perry Sand Well 2  Overview Recovery Factor • Proven light tight oil accumulation with low historical  North Fault  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 • Second well currently drilling East Fault  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 CO2 EOR potential after primary production Planned well 4Q18 Previously drilled wells NYSE:DNR 17

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 South Parkman:   • Dakota 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  Nebraska $4,000 – $12,000 per acre x x x • Acreage held by Hartzog Draw Unit production x Turner/Frontier  • Production & transport infrastructure in place 1,393 BOED IP  x Rate, 91% Oil • Planning to begin drilling activities to test  deeper horizons in 4Q18 Mowry:  Niobrara:  1,336 BOED IP  1,617 BOED IP  Rate, 83% Oil Rate, 81% Oil NYSE:DNR 18

Recent Debt Transactions Further Improve Leverage Profile Net Debt Principal Reduction Since 12/31/14 9/30/18 Debt Maturity Profile (In millions) RECENT TRANSACTIONS (In millions) Over $1 Billion Net Debt Reduction » Amended and Extended Bank Credit  $553 million of bank line Facility to Dec. 2021 availability at 9/30/18 after LOCs $3,548 » Issued $450 million of New 7½% Sr.  $395 Secured 2nd Lien Notes; Proceeds  Used to Fully Repay Credit Facility $324  $2,514 $2,475 $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 $826  $826  » Maintained Same Access to  $(23) $‐ $(67) Liquidity, $615 Million Undrawn  Credit Facility 12/31/14 6/30/18 9/30/18 2018 2019 2020 2021 2022 2023 2024 Sr. Secured Bank Credit Facility Cash & Cash Equivalents Pipeline / Capital Lease Debt Sr. Subordinated Notes Sr. Secured 2nd Lien Notes NYSE:DNR 19

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) Adjusted EBITDAX(1) $601 $760 $148 $210 3Q18 Annualized 593 839 9/30/18 Net Debt Principal(2) 2,475 2,475 2,475 2,475 Debt/Adjusted EBITDAX(1) 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 40 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. NYSE:DNR 20

Transformational Combination of & NYSE:DNR 21

The Combination of Denbury & Penn Virginia Adds High Value Investment Diversity Rocky Mountain  • Adds new core area in the oil window of the prolific Eagle Ford Shale play Region • Large development inventory – ~560 Gross Lower Eagle Ford locations • Expands high‐return, short‐cycle investment opportunity set Combined Pro Forma  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 Leverages and Expands EOR Platform YE17 Proved O&G Reserves 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  • Immediately accretive to cash flow and key per‐share metrics Virginia 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‐ term cost of capital Denbury Owned Fields Current Pipelines CO2 Sources Planned Pipelines NYSE:DNR 22

Why We Like the Eagle Ford . Expansive play with large oil window . Light Louisiana Sweet (LLS) premium oil pricing Oil Condensate . Well developed midstream infrastructure Denbury’s Gulf  Dry Gas Coast Assets . Significant upside potential through: Penn Virginia Assets . Enhanced oil recovery . Upper Eagle Ford . Austin Chalk . Close proximity to Denbury’s Gulf Coast  operations  . Follow‐on consolidation potential NYSE:DNR 23

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 Gonzales County . Receives LLS premium pricing . 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 NYSE:DNR 24

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 Enterprise Value (Billions)(1) $4.5 $1.5 $6.0 YE17 Proved Reserves (MMBOE) 260 83(2) 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 NYSE:DNR 25

Combination Maintains Industry‐Leading Oil Weighting…. 100% 97% 2Q18 % Liquids Production Oil Production 94% NGL Production 90% 90% 87% 80% 70% 74% 60% 50% 40% 30% 20% 10% 0% DNR(1) Pro CPG JAG PVAC WLL CRZO WPX HPR OXY OAS(1) CDEV CPE(1) EPE CRC AMR XOG LPI SN SRCI NFX PDCE SM MUR CLR(1) Forma Source: Bloomberg and Company filings for period ended 6/30/2018. 1) NGL production is not reported separately for this entity. NYSE:DNR 26

….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 Operating Margin per BOE (1) 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 Lifting Cost per BOE (2) 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 Revenue per BOE (3) 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.  NYSE:DNR 27

….and Creating a Leading Mid‐Cap Oil Producer 10 Enterprise Value(1) ($ Billion) 8 9.1 7.4 6 6.1 6.0 6.0 6.0 5.4 4 4.5 4.0 3.7 3.3 2 2.9 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 200 187  2Q18 Production (MBOE/d) 150 134  126  125  100 103  84  79  50 74  67  62  58  57  48  35  29  26  26  0 22  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 NYSE:DNR 28

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 NYSE:DNR 29

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 • Rich hydrocarbon gas or CO is injected into a producing well and is  Primary forecast bopd 2    10,000 allowed to soak for a period before the well is returned to production Wells),  8,000   (9 •   While all projects to date have used rich hydrocarbon gas,   6,000 Rate   Oil simulation work indicates that CO2 should provide greater recovery    4,000 • Planning to conduct both CO and rich hydrocarbon gas pilots Gross 2  2,000 • For example, a 1‐2 month injection period could be followed by several   ‐ weeks of soaking and then a 2‐4 month producing period 2012 2014 2016 2018 2020 2022 2024 2026 2028 Gonzales County EOR Pilot • The cycle is repeated over multiple years until incremental recovery  Primary and EOR Recovery reaches an economic limit  9,000  8,000  7,000 Oil production is enhanced through several processes 3.3 MMBO  6,000 66% incremental • Injected gas provides lift energy to depleted wells  5,000 MBbls  4,000 • The gas is miscible with oil, reducing viscosity and swelling the oil  3,000 • Gas will adsorb onto the shale that it contacts, expelling oil from the   2,000 shale  1,000  ‐ 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 NYSE:DNR 30

Eagle Ford is Ideally Suited for EOR Penn Virginia’s  Drivers of EOR Niobrara Bakken Permian Eagle Ford Completion Complexity &      Contact Area for Miscible Gas 2,500 lb/ft fracs 1,200 lb/ft fracs 1,500 lb/ft fracs 2,000 lb/ft fracs     Geology Homogenous Fractured Sandstone Heterogenous     Horizontal Gas Containment Low Permeability Medium  High Permeability Medium/High  Permeability Permeability Vertical Gas Containment  Play Maturity  Industry EOR Development  NYSE:DNR 31

Historic Eagle Ford EOR Project Performance 6000 BOPD • 8  Gonzales County Projects with Long term  Performance ~ 2.5X  • 6,000 BOPD incremental from EOR from 88  Incremental wells Production • Average incremental production per well of  40 – 110 BOPD Rate NYSE:DNR 32

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 CO2 evaluation 4Q18‐ 3Q19 2H19‐ 2020 2021+ NYSE:DNR 33

Pro Forma Combined Capital Structure Financing Commitment Letter from JP Morgan Chase • $1.2 billion new senior secured bank credit facility • $0.4 billion senior secured 2nd lien bridge loan Est. Pro Forma for  (1) In millions, as of 9/30/18, unless otherwise noted Transaction 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. NYSE:DNR 34

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 • Top‐tier operating margins Operating Cash Flow(1) (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) transaction costs. Development Capital 2) Excludes capitalized interest and acquisitions/divestitures. (in billions) 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 impossible to predict or estimate and many of them are beyond Denbury’s control. The preliminary combined pro  ~$0.7 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 NYSE:DNR 35

Combined 2019 & 2020 Hedge Positions 2019 2020 Detail as of November 7, 2018 1H 2H 1H 2H WTI NYMEX ‐ Volumes Hedged (Bbls/d) 3,500 ─── Denbury Swap Price(1) $59.05 ─── WTI NYMEX – Volumes Hedged (Bbls/d) 6,433 6,398 6,000 6,000 Swaps (1)   Penn Virginia Swap Price $54.47 $54.50 $54.09 $54.09 Price   Argus LLS ‐ Volumes Hedged (Bbls/d) 4,000 4,000 ── Denbury Swap Price(1) $71.40 $71.40 ── Fixed Argus LLS – Volumes Hedged (Bbls/d) 5,000 5,000 ── Penn Virginia Swap Price(1) $59.17 $59.17 ── Volumes Hedged (Bbls/d) 8,500 12,000 1,000 1,000 (1)(2) WTI NYMEX ‐ 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 Denbury Volumes Hedged (Bbls/d) 10,000 10,000 ── Sold Put Price/Floor Price/Ceiling Price(1)(2) $50.40/$58.40/$72.69 $50.40/$58.40/$72.69 ── Collars   Volumes Hedged (Bbls/d) 3,000 3,000 1,000 1,000 Way ‐ 3 (1)(2) Argus LLS ‐ 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 Denbury Volumes Hedged (Bbls/d) 2,500 2,500 ── Sold Put Price/Floor Price/Ceiling Price(1)(2) $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. NYSE:DNR 36

Uncommon Company, Extraordinary Potential  – Enhanced with Penn Virginia Combination » Industry Leading Oil Weighting Extreme Oil Gearing »Favorable Crude Quality & High Exposure to LLS Pricing  »Top Tier Operating Margin & Significant Free Cash Flow »Blend of EOR, Conventional and Oil‐rich Shale Assets Operating Advantages »Broad EOR experience base and technical strength » Vertically Integrated CO2 Supply and Infrastructure  » Operating Outside Constrained Basins Significant Organic  » Meaningful Production Growth »Large Inventory of Short‐Cycle Eagle Ford Locations   Growth Potential »Significant EOR Development Potential »Strong Liquidity Rapidly De‐Levering » Enhanced Credit Profile  »No Near‐Term Debt Maturities NYSE:DNR 37

Appendix NYSE:DNR 38

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 3, “Cautionary  to the standards of possible reserves. See slide 3, “Cautionary Statements”  Statements” for additional information. 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. NYSE:DNR 39

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 Interest expense 25 23 99 17 16 19 75 Income tax expense (benefit) (14) (134) (117) 14 9 16 (95) Depletion, depreciation and amortization 52 53 207 52 53 51 209 Noncash fair value adjustments on commodity  25 78 29 15 41 (17) 117 derivatives Stock‐based compensation 331533413 Noncash, non‐recurring and other(1) 11 7 25 11(3)6 Adjusted EBITDAX (non‐GAAP measure) $102 $157 $421 $142 $153 $148 $600 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. NYSE:DNR 40