Filing of Certain Prospectuses and Communications in Connection With Business Combination Transactions (425)

Filed by Penn Virginia Corporation pursuant to

Rule 425 under the Securities Act of 1933

and deemed filed pursuant to Rule 14a-12

under the Securities Exchange Act of 1934

Subject Company: Lonestar Resources US Inc.

Commission File No. 001-37670

The following is a presentation used at Barclays’ CEO Energy-Power Conference held September 10, 2021.

Darrin Henke President and Chief Executive Officer September 10, 2021 CEO Energy-Power Conference CEO Energy-Power Conference

IMPORTANT DISCLOSURES Additional Information and Where To Find It In connection with the proposed merger (the “Proposed Merger”) between Penn Virginia Corporation (together with all predecessors and subsidiaries, “Penn Virginia,” “PVAC,” “we,” “us,” “our” or the “Company”) and Lonestar Resources US Inc. (“Lonestar” or “LONE”), Penn Virginia intends to file with the Securities and Exchange Commission (the “SEC”) a registration statement on Form S-4 (the “Registration Statement”) to register the shares of Penn Virginia’s common stock to be issued in connection with the Proposed Transaction. The Registration Statement will include a document that serves as a prospectus and proxy statement of Penn Virginia and a consent solicitation statement of Lonestar (the “proxy statement/consent solicitation statement/prospectus”), and each party will file other documents regarding the Proposed Transaction with the SEC. INVESTORS AND SECURITY HOLDERS OF PENN VIRGINIA AND LONESTAR ARE URGED TO CAREFULLY AND THOROUGHLY READ, WHEN THEY BECOME AVAILABLE, THE REGISTRATION STATEMENT, THE PROXY STATEMENT/CONSENT SOLICITATION STATEMENT/PROSPECTUS, AS EACH MAY BE AMENDED OR SUPPLEMENTED FROM TIME TO TIME, AND OTHER RELEVANT DOCUMENTS FILED BY PENN VIRGINIA AND LONESTAR WITH THE SEC BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT PENN VIRGINIA AND LONESTAR, THE PROPOSED TRANSACTION, THE RISKS RELATED THERETO AND RELATED MATTERS. After the Registration Statement has been declared effective, a definitive proxy statement/consent solicitation statement/prospectus will be mailed to shareholders of each of Penn Virginia and Lonestar. Investors will be able to obtain free copies of the Registration Statement and the proxy statement/consent solicitation statement/prospectus, as each may be amended from time to time, and other relevant documents filed by Penn Virginia and Lonestar with the SEC (when they become available) through the website maintained by the SEC at www.sec.gov. Copies of documents filed with the SEC by Penn Virginia, including the proxy statement/consent solicitation statement/prospectus (when available), will be available free of charge from Penn Virginia’s website at www.pennvirginia.com under the “Investors” tab. Copies of documents filed with the SEC by Lonestar will be available free of charge from Lonestar’s website at www.lonestarresources.com under the “Investor Relations” tab. Participants in the Solicitation Penn Virginia, Lonestar and certain of their respective directors, executive officers and other members of management and employees may be deemed to be participants in the solicitation of proxies from Penn Virginia’s shareholders and the solicitation of written consents from Lonestar’s shareholders, in each case with respect to the Proposed Transaction. Information about Penn Virginia’s directors and executive officers is available in Penn Virginia’s Annual Report on Form 10-K for the 2020 fiscal year filed with the SEC on March 9, 2021, and its definitive proxy statement for the 2021 annual meeting of shareholders filed with the SEC on April 7, 2021. Information about Lonestar’s directors and executive officers is available in Lonestar’s Annual Report on Form 10-K for the 2020 fiscal year, as amended, filed with the SEC on April 30, 2021. Other information regarding the participants in the solicitations and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the Registration Statement, the proxy statement/consent solicitation statement/prospectus and other relevant materials to be filed with the SEC regarding the Proposed Transaction when they become available. Stockholders, potential investors and other readers should read the proxy statement/consent solicitation statement/prospectus carefully when it becomes available before making any voting or investment decisions. No Offer or Solicitation This presentation is not intended to and shall not constitute an offer to sell or the solicitation of an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. 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. 2

Forward-Looking and Cautionary Statements Forward-Looking and Cautionary Statements This presentation contains certain "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. Statements that are not historical facts are forward-looking statements, and such statements include, words such as "anticipate," "guidance," "assumptions," "projects," "forward," "estimates,” "outlook,” "expects,” "continues,” "intends,” "plans,” "believes,” "future,” "potential,” "may,” "foresee,” "possible,” "should,” "would,” "could," “focus” and variations of such words or similar expressions, including the negative thereof, 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: risks related to the proposed acquisition of Lonestar, including the risk that acquisition will not be completed on the timeline or terms currently contemplated, that the benefits of the acquisition may not be fully realized or may take longer to realize than expected, and that management attention will be diverted to transaction-related issues; risks related to the recently completed transactions with Juniper, including the risk that the benefits of the transactions may not be fully realized or may take longer to realize than expected, and that management attention will be diverted to integration-related issues; risks related to potential and completed acquisitions, including related costs and our ability to realize their expected benefits; the decline in, sustained market uncertainty of, and volatility of commodity prices for crude oil, natural gas liquids, or NGLs, and natural gas; the impact of the COVID-19 pandemic, including reduced demand for oil and natural gas, economic slowdown, governmental actions, stay-at-home orders, interruptions to our operations or our customer's operations; risks related to and the impact of actual or anticipated other world health events; 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, including access to the capital markets, to fund our capital expenditures and meet working capital needs; our ability to access capital, including through lending arrangements and the capital markets, as and when desired; 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; our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production; changes to our drilling and development program our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; our ability to meet guidance, market expectations and internal projections, including type curves; 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, materials, supplies and services at reasonable costs; our ability to renew or replace expiring contracts on acceptable terms; our ability to obtain adequate pipeline transportation capacity or other transportation for our oil and gas production at reasonable cost and to sell our 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 gas reserves; use of new techniques in our development, including choke management and longer laterals; drilling, completion and operating risks, including adverse impacts associated with well spacing and a high concentration of activity; 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, 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; our ability to retain or attract senior management and key employees; our reliance on a limited number of customers and a particular region for substantially all of our revenues and production; compliance with and changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters; physical, electronic and cybersecurity breaches; uncertainties relating to general domestic and international economic and political conditions; the impact and costs associated with litigation or other legal matters; sustainability initiatives; and other risks set forth in our filings with the SEC, including our most recent Annual Report on Form 10-K and subsequent Quarterly Reports on Form 10-Q. 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. In addition, 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 the presentation. 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. Expected results of the completed period are preliminary and subject to change until published in our Quarterly Report on Form 10-Q filed with the SEC. Definitions – Special Note on PV-10 Calculations 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. Proved developed reserves are proved reserves that can be expected to be recovered: (a) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well; or (b) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is means not involving a well. 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. Proved developed producing and total proved reserves for PVAC presented herein are based on reserve reports from DeGolyer and MacNaughton (“D&M”) as of 7/1/2021 and 4/1/2021, respectively (the “D&M reports”). Proved reserves for LONE presented herein are based on a reserve report from W.D. Von Gonten & Co. (“WDVG”) as of 1/1/2021 (the “WDVG Report”). PV-10 of PVAC is based on such D&M reports as of 06/30/21 and updated for strip pricing as of 7/9/21. PV-10 of LONE is based on the WDVG Report as of 01/01/21 and adjusted by PVAC management for actual production, lease operating and transportation costs through 07/01/21 as well as the revised actual and anticipated development plans post-07/01/21, and using strip pricing as of 7/9/21. These “PV-10” metrics represent estimates for illustrative purposes and is a non-GAAP measures. Cautionary Statements The estimates and guidance presented in this presentation, including those regarding inventory of drilling locations and expected free cash flow, 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. 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, assumptions regarding well costs, the drilling program and economics and are subject to material change. The number of locations shown as being in the Company’s current estimated inventory or estimated combined inventory is not a guarantee of the number of wells that will actually be drilled and completed or the results or return that will be achieved. 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. Information presented about the two companies on a combined basis is not meant to be a representation of the combined business or performance of the companies following the closing of the Proposed Merger. Non‐GAAP Financial Measures This presentation contains references to certain non‐GAAP financial measures. 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. Penn Virginia’s or Lonestar’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. Penn Virginia or Lonestar 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 result. More Information Regarding LONE’s Non-GAAP Measures We have included certain of LONE’s non-GAAP measures in this presentation, but we have not sought to independently verify this financial information. No assurance can be given of this information’s accuracy or the accuracy and completeness of the reconciliations to the most directly comparable GAAP measures provided in LONE’s publicly available disclosures. Net Debt, excluding unamortized discount and debt issuance costs, is a non-GAAP financial measure that is defined as total principal amount of long-term debt less cash and cash equivalents. LONE’s principal amount of long-term debt used to calculate Net Debt excludes its non-recourse mortgage on its corporate office building and the PPP loan for which funds are fully reserved as restricted cash to cover the balance. LTM Leverage, a non-GAAP measure, is defined as Net Debt divided by Adjusted EBITDAX. The ratios are derived from the historical periods as reported in the respective Quarterly Reports on Forms 10-Q and Annual Report on Form 10-K for the relevant periods. With respect to LONE’s LTM Leverage at June 30, 2021, the ratio includes five months of the Predecessor period prior to emerging from bankruptcy and seven months of the successor period following the emergence (the predecessor and successor periods are defined as reported in Lonestar’s Form 10-K for the year ended December 31, 2020. We have not reconciled the components of LONE’s LTM Leverage, Net Debt and Adjusted EBITDAX, to the most comparable GAAP measure. This reconciliation would require unreasonable efforts as the amounts are currently based). For the second quarter 2021, LONE’s Net Debt and Adjusted EBITDAX were derived from actual 10-Q results. 3

Premier Oil Weighted Asset Strong PDP Base with Substantial Inventory Strong Balance Sheet / Liquidity PVAC Investment Thesis Focused on Cash-on-Cash Returns and Committed to Continuous Improvement High Margin / Improving Efficiency Advantaged Regulatory and Infrastructure Position Leadership in ESG

PVAC Company Overview NASDAQ: PVAC – Enterprise Value: $1,087 MM(1) 102,400 gross (90,400 net) acres(2) in Gonzales, Fayette, Lavaca and DeWitt counties; ~100% Operated; 91% HBP Approximately 500 identified drilling locations in inventory with significant identified upside potential 500 locations estimated to average 50%+ well level IRR at $60/bbl WTI(3) Two-thirds of locations estimated to average 65%+ well level IRR at $60/bbl WTI(3) 2Q21 sales: 20,117 bbl/d and 24,844 boe/d; 81% oil / 92% liquids Top quartile Adjusted EBITDAX(4)(5) margins Net Debt(4) to LTM adjusted EBITDAX(4) ~1.3x(6) Advantaged regulatory position No Federal acreage; Assets on private fee lands in Texas Located close to Gulf Coast Markets (MEH/LLS) Advantaged pricing and market access Houston (HQ) Condensate Oil Gas Eagle Ford Net debt as of 06/30/21, share price as of 09/03/21 and shares of common stock and common stock equivalents outstanding of 37,861,271 as of June 30, 2021 (as further described in the 2nd quarter 2021 Form 10-Q). As of 06/30/21. Estimated well level returns based on D&M type curves as of 01/01/21. Adjusted EBITDAX, as further adjusted for the Juniper Transaction ($3.5 MM), Net Debt and PV-10 are non-GAAP financial measures that are defined and reconciled in the appendix of this presentation. Source: FactSet. Companies include: APA, AR, BATL, BCEI, BRY, CDEV, CLR, CNX, COG, CPE, CRK, DVN, EOG, EQT, ESTE, FANG, LPI, MCF, MGY, MTDR, NOG, PDCE, PXD, RRC, SBOW, SM, SWN, WLL and XEC for 2020 and first quarter of 2021. Leverage ratio is calculated by dividing Net Debt as of 06/30/21 by LTM Adjusted EBITDAX as of 06/30/21 as adjusted for the Juniper transaction. Based on reserve report from D&M as of 06/30/21. Net Debt as of 06/30/21. Reserves Summary ($MM) $49.78/WTI $2.43/MMBtu SEC Pricing (7) $60/WTI $2.75/MMBtu Pricing (7) Proved Developed (“PD”) PV-10(4) $818 $1,055 PD PV-10 to Net Debt(4)(8) 2.4x 3.2x 5 Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG

2021 Year-to-date Accomplishments Validated Strength of PVAC Inventory 500 locations with two-thirds estimated to avg. 65%+ well level IRR at $60/bbl WTI using D&M third party reserve report type curves(1) 2020 and 2021 spud wells outperforming D&M type curve projections by more than 15% cumulatively(2) Additional 150 potential locations identified Fortified Balance Sheet and Liquidity with No Near-Term Maturities Issued $400 MM of Senior Notes due 2026 Increased borrowing base to $600 MM with aggregate commitments of $400 MM (3) Leverage of 1.3x(4) and targeting <1.0x in early 2022(5) Initiated Basin Consolidation Acquired Rocky Creek Resources assets Announced Lonestar acquisition ü Generated Free Cash Flow for Seven Consecutive Quarters(5) Estimated well level returns based on D&M type curves as of 01/01/21. Includes wells where D&M type curves existed. Effectiveness is subject to closing of the LONE acquisition and other conditions. As of 06/30/21, PVAC standalone. Free Cash Flow and Leverage are non-GAAP financial measures that are defined and reconciled in the appendix of this presentation. Step Change in Recent Well Performance 1Q21 - Exceeded high-end of production guidance and raised full-year 2021 production guidance 2Q21 - Exceeded high-end of production guidance ü ü ü ü Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG

Lonestar Acquisition Overview Leadership and Governance Existing Penn Virginia management team One LONE director will be appointed to PVAC Board of Directors Approvals and Timing Unanimously approved by PVAC and LONE Boards of Directors ~80% of LONE and ~60% of PVAC equity owners have executed voter support agreements Special meeting to approve transaction to be held on October 5, 2021, with closing expected soon after All-stock transaction at 0.51x exchange ratio; pro forma projected shares outstanding: 43.7 MM(1) PVAC shareholders retain approximately 87% ownership of pro forma company PVAC will assume LONE outstanding Net Debt of $236 million(2) as of 06/30/21 Issued $400 MM Senior Unsecured Notes in escrow to repay LONE debt and PVAC existing second lien term loan upon closing of LONE acquisition Consideration and Financing 1) Includes common share equivalent securities. 2) Excludes LONE’s non-recourse mortgage on its corporate office building. . 7 Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG

Strategic Fit and Additional Scale Contiguous position conducive to operational and G&A synergies expected to exceed $20MM per year Adds 13 Mboe/d resulting in 38 Mboe/d combined sales(1) Attractive Valuation and Significant Accretion Transaction value represents <$30,000 / boe/d current production and discount to PDP PV-10(2) Accretive to key metrics including Free Cash Flow Strong Balance Sheet <1.6x LTM Leverage and $194MM in liquidity at 06/30/21(3)(4) Continue to target 1.0x LTM Leverage in early 2022(4) Enhanced Inventory Adds ~250 estimated gross well locations resulting in ~750 combined gross locations Adjacent acreage allows for longer laterals Positioned for Further Consolidation Scale and strong balance sheet positions company for additional strategic acquisitions ü ü ü ü ü Highly Accretive Offset Operator Consolidation 1) Represents June 2021 sales with 6:1 gas equivalents. 2) At closing share price and strip pricing as of 07/09/21. 3) Assumes combined current borrowing bases of PVAC and LONE. 4) LTM leverage is a non-GAAP financial measure that is sourced from Lonestar and defined and explained on page 3. Complementary Assets Penn Virginia Acreage Recent Rocky Creek Acquisition Lonestar Resources Acreage Legend 8 Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG

Lonestar Assets Current Sales: 13 Mboe/d(1) (70% Liquids) PDP PV-10 Value at 7/01/21: $389 MM(2) Total Proved PV-10 Value at 7/01/21 : $700 MM(2) Net Acreage: ~53,000(3) Estimated Gross Drilling Locations: ~250 1) Represents June 2021 net sales with 6:1 gas equivalents. 2) See page 3 "Definitions - Special Note About PV-10" for information regarding the calculation of Lonestar's PV-10 as shown here. 3) As of June 30, 2021. 3 well (Hawkeye 33H, 34H, and 35H) Pad 11,080’ laterals TIL 2/21/2021 Avg IP-30 825 bbl/d and 369 Mcf/d PVAC Acreage LONE Acreage Legend Central Area Southern Area 2 well (Horned Frog W 1H and 2H) Pad 7500’ laterals TIL 4/23/2021 Avg Peak IP-30 629 bbl/d,197 bbl/d NGLs and 2.2 MMcf/d 2 well (Horned Frog Alderman A1H and B2H) Pad 12,000’ laterals TIL 6/17/2021 Avg Peak IP-30 820 bbl/d oil, 534 bbl/d NGLs and 5.7 MMcf/d Northern Area LONE Acreage Hawkwood Acreage Legend Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG

Net Acreage(1) Current Sales(2) Proved Reserves(3) Gross Inventory Shares Outstanding(4) PD PV-10 – 07/01/21(8) Net Debt @ 06/30/21(8) Estimated LTM Leverage(9) PVAC + LONE PVAC Standalone ~90,000 25 Mboe/d 137 MMboe ~500 37.9 MM $~1.1 B(5) $334 MM ~1.3x ~143,000 38 Mboe/d 219 MMboe ~750 43.7 MM $~1.5 B(6) $570 MM(7) <1.6x Complementary Scale and Strong Financial Metrics 1) As of June 30, 2021. 2) Represents June 2021 production with 6:1 gas equivalents. 3) Based on reserve report from D&M as of 04/01/21 for PVAC and reserve report from WDVG as of 01/01/21 for LONE. The combined reserves of PVAC and LONE at 12/31/20, based on the PVAC reserve report from D&M as of 12/31/20 and LONE reserve report from WDVG as of 01/01/21, would have been 206 MMboe. This number represents the sum of total reserves of the two companies as shown in their respective reports and does not represent reserves of the combined company following the closing of the Proposed Merger. The historical production and future development plans of the combined company will vary from those assumed in the applicable reserve reports. 4) Includes common share equivalent securities. 5) D&M PD reserve report as of 06/30/21 at strip pricing at 07/09/21. 6) See page 3 "Definitions - Special Note About PV-10" for information regarding the calculation of Lonestar's PV-10 as used here. 7) See description of Net Debt for LONE on page 3. 8) Net Debt for PVAC only and PV-10 are non-GAAP financial measures that are defined and reconciled in the appendix of this presentation. 9) As of June 30, 2021. Leverage ratio is calculated by dividing Net Debt as of 06/30/21 by LTM Adjusted EBITDAX as of 06/30/21. PVAC Adjusted EBITDAX as further adjusted for Juniper Transaction ($3.5 MM). Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG

Lavaca Gonzales Anticipated Synergies – Significant Value Creation Combined Acreage Footprint Provides Significant Operational Synergies PVAC Acreage Moulton Area Potential Locations LONE Operated Leases Surface Drilling Pads LONE Wells Drilled 1) Expected PV-10 based on PVAC’s internal management estimates with 07/09/2021 strip pricing. Complementary assets allow for significant synergies G&A/Corporate Operating Costs Capital Expenditures Marketing/Midstream Financing Costs Total expected to exceed $20 million per year Adjacent Moulton acreage adds over 45,000 net lateral feet Incremental PV-10 of $33 MM(1) on ~770 net acres Equivalent of >5 long lateral wells Longer laterals enhance capital efficiencies ESG Synergies More wells connected to pipelines reduces flaring Shared facilities reduces footprint Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG

Gonzales Lavaca Fayette De Witt Strong PDP Base Strong PDP Base with Substantial Inventory Concentrated position allows for operational efficiencies Proven productivity across acreage position Expected PDP decline of 34%(1) provides cash flow and flexibility Continually analyzing assets for cost reductions and efficiency improvements Premium sweet crude oil with blended yield of ~44 degree API gravity Strong PD PV-10(2)(3) to Net Debt(3)(4) ratio of 3.2x PVAC LONE EAGLE FORD PEERS ACREAGE Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG Note: Information provided represents Penn Virginia standalone. 1) Based on expectations from type curves as set forth in 2020 YE D&M Reserve Report. Decline is calculated from January 2021 to January 2022. 2) Based on reserve report from D&M as of 06/30/21. 3) Net Debt and PV-10 are non-GAAP measures reconciled in the appendix of this presentation. 4) Net Debt as of 06/30/21.

Exceptional PVAC Well Results and Deep Inventory Type curve assumptions are estimates based on 2020 YE D&M Reserve Report and on management’s internal estimates as of 07/09/21. Capital expenditure assumptions include Drilling, Completion, Facilities, and Tie-in expenditures. Average Drilling and Completion capital of ~$5.75 MM per well plus $0.5 MM for Facilities and Tie-in expenditures for Total Capex of $6.25 MM. Estimated well level returns based on D&M type curves as of 01/01/21. Includes wells where D&M type curves existed. 2020 Outperformance and Future Inventory D&M Avg. Oil Type Curve for 2021 and 2022 TILs (bbl/d) D&M total inventory of ~500 locations (only Lower Eagle Ford) Two-thirds of locations estimated to average 65%+ well level IRR at $60/bbl WTI(3) 500 locations estimated to average 50%+ well level IRR at $60/bbl WTI(3) Substantial inventory upside (+150 locations ) from Upper Eagle Ford, Austin Chalk, down spacing results and non-operated wells 2020 and 2021 spud wells currently outperforming D&M projections by more than 15% on a cumulative basis(4) Relatively open undrilled lease geometries allow for long laterals and efficient multi-well pads Wells TIL YTD Actual Avg IP-30 Normalized for Lateral Length ~1,040 bbl/d * Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG Gonzales Lavaca Fayette De Witt TEXAS Black Oil Volatile Oil Condensate Wet Gas Dry Gas NAB Hunter/Nevels Addax 2-Well Pad Average IP-30 1,019 bbl/d Average CLL: 7,904 Reffenshack/Rhino 4-Well Pad Average IP-30 933 bbl/d Average CLL: 7,639’ Emerald 2-Well Pad Average IP-30 1,012 bbl/d Average CLL: 10,887’ PVAC LONE EF PEERS ACREAGE Matocha 1H: IP-30 1,248 bbl/d CLL: 8,580’ Aquamarine 4-Well Pad Average IP-30 770 bbl/d Average CLL: 4,885’ Blonde Unit 2H: IP-30 1,040 bbl/d CLL: 5,920’ Southern Bock (PSA) A1H: IP-30 1,676 bbl/d CLL:6,381’ B2H: IP-30 1,405 bbl/d CLL: 8,349’ Amethyst/Hippo 2-Well Pad Average IP-30 864 bbl/d Average CLL 6,647’ Munson Ranch 3-Well Pad Average IP-30 1,109 bbl/d Average CLL: 6,971’ Big 5 2-Well Pad Average IP-14 1,021 bbl/d Average CLL 8,502’

Gonzales Lavaca Fayette Northeast Acreage Provides Significant Inventory Based on PVAC current internal estimates. IRR calculated using 8,400 lateral length with flat $60 oil and $2.75 MMbtu. Ample running room for future drilling on high return oil-weighted inventory Acquired contiguous acreage allows for longer laterals and significant operating synergies ~100 inventory locations (Combined Company)(1) Average lateral length of ~8,400’ Estimated IRR >70%(2) 45 API gravity oil, 1,300 GOR Estimated total well costs of $7.3 MM Significant Future Inventory Adjacent Acreage, Attractive Well-level Economics, Substantial Inventory BIG FIVE B #2H BIG FIVE A #1H Matocha 1H: IP-30 1,248 bbl/d; 1.7 MMcf/d CLL: 8,580’ Drilled After 2018 Big Five Wells PVAC Acreage LONE Acreage Recently Acquired RCR Acreage Svatek 12 Mo. Cum. >155 Mbo CLL: 6,478’ Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG Big 5 2-Well Pad Average IP-14 1,021 bbl/d Average CLL 8,502’

Gonzales Gonzales EMERALD B #2H EMERALD A #1H Emerald 2-Well Pad Average IP-30 1,012 bbl/d Average CLL: 10,887’ LONE Acreage Drilled After 2018 EOG Wells Emerald Wells PVAC Acreage Southwest Acreage Provides Significant Opportunity Ample running room for future drilling on high return oil-weighted inventory Emerald wells tripled IP-30 of legacy wells 160 inventory locations (Combined Company)(1) Average lateral length of ~9,700’ Estimated IRR >70%(2) 35-40 API gravity oil, 600 GOR Estimated total well costs of $6.2 MM Significant Future Inventory Complementary Acreage, Attractive Well Level Economics, Substantial Inventory Based on PVAC internal estimates. IRR calculated using 9,700 lateral length with flat $60 oil and $2.75 MMbtu. Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG

Gonzales Lavaca Successful Infill and Downspacing 1) IRR calculated using flat $60 oil and $2.75 MMbtu. Successful Downspacing Around Early-Vintage Wells Provides Upside Potential Large number of legacy hybrid gel completions creates opportunity to access undrained reserves through infill and downspacing (< 500’ from offset well) Similar redevelopment is being deployed by MRO, DVN, and others, producing strong results Recent Munson Ranch and Reffenshack wells demonstrate strong performance around legacy wells Improved parent well production by 30+% Average new well estimated IRR >100+%(1) Previously Drilled Reffenshack Wells PVAC Acreage REFFENSHACK C #3H REFFENSHACK B #2H REFFENSHACK A #1H 315 FT. 360 FT. 409 FT. 494 FT. Previously Drilled Munson Ranch Wells PVAC Acreage MUNSON RANCH #14H MUNSON RANCH #15H MUNSON RANCH #13H 345 FT. 347 FT. 390 FT. 396 FT. 473 FT. 435 FT. 540 FT. 575 FT. Reffenshack 3-Well Pad Average IP-30 985 bbl/d Average CLL: 8,353’ Munson Ranch 3-Well Pad Average IP-30 1,109 bbl/d Average CLL: 6,971’ Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG

Continuously Improving Drilling Efficiencies Reserves based on D&M 2020 YE Reserve Report. Total Well Cost by Spud Date - $/Lateral Foot(1) Total Well Cost Include Drilling, Completion, Facilities and Tie-in Expenditures Total Well Cost per boe of Reserves Developed(1) Total Well Cost Include Drilling, Completion, Facilities and Tie-in Expenditures Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG

Committed to Strong Balance Sheet Net Debt Maturity Profile(1) $MM Capitalization(3) Nearest maturity occurs in 2024 1) Net Debt as of 06/30/21. 2) Net of cash as of 06/30/21. 3) Assumes the redemption of 225,490 shares of Series A Preferred Stock and 22,548,998 common units in a partnership subsidiary. As of 06/30/21, there were 15,312,273 shares of common stock outstanding. 4) As of 06/30/21. (2) No Near-Term Debt Maturities Net Revolver Outstanding 2nd Lien Term Loan Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG On August 10, 2021, Penn Virginia Issued $400 million of senior unsecured notes (“Notes”) with net proceeds anticipated to be used to refinance Lonestar’s long-term debt and Penn Virginia’s Second Lien Term Loan. Upon closing the Merger, Penn Virginia’s capitalization is expected to include the Notes and an upsized revolving credit facility to enhance liquidity.

Emissions Intensity by Eagle Ford Operator(1) Committed to Protecting the Environment Y Source: Enverus. 1) Emissions intensity includes combustion equipment, flaring, storage tanks, gas venting and other equipment. Reduce flaring by connecting wells to natural gas pipelines in advance of production Minimizing Flaring Lease operators inspect each well location daily as the first line of defense to detect and prevent leaks and emission events Optical gas imaging cameras scan production facilities for leaks and conduct voluntary surveys beyond regulatory requirements Leak Detection and Prevention Transport majority of crude oil production via pipeline, meaningfully reducing vehicle emissions Transport a portion of water via pipelines, further reducing vehicle emissions Transport via Pipeline Multi-well pads and longer laterals reduce environmental footprint Drilling & Completion Techniques and Well Design Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG

Substantial Infrastructure – Advantaged Pricing Location Close to Coast with Attractive Sales Points 2Q21 Sales: 81% Oil; 92% Liquids Receives MEH Pricing, Premium Over WTI and Midland Realized $52.70 per bbl in 2Q21(1) Blended Oil Yields ~44 Degree API Gravity 2Q21 Sales Mix Natural Gas NGLs Oil Note: Map data provided by and used with permission of Hart Energy Mapping and Data Services, LLC. 1) Realized oil price, including effects of derivatives, net is a non-GAAP 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 release. WTI MEH $0.35 Mid $-0.07 LLS $0.65 April '21 May '21 Jun '21 LLS vs. WTI vs. MEH and Midland Pricing Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG

Advantaged Regulatory Position Emissions Robust infrastructure and processing facilities reduce need for flaring Vast majority of production on pipeline, limiting emissions and spill occurrence Optical gas imaging cameras used to scan production facilities for leaks as part of leak detection and repair program Emission control equipment, such as vapor recovery towers (VRT), combustors, and low-pressure flares, that minimize natural gas flaring Infrastructure Direct access to Gulf Coast markets Minimizes dependency on interstate federal regulated infrastructure Limited infrastructure permitting risk State of Texas one of the friendliest to oil and gas industry Long track record of treating mineral rights as firm property rights Landowners are often mineral rights owners, incentivized to allow access and development Operating Environment Acreage No federal acreage exposure ~100% private landholder leases 91% held by production status Premier Oil Weighted Asset High Margin / Improving Efficiency Strong Balance Sheet / Liquidity Advantaged Regulatory and Infrastructure Position Strong PDP Base with Substantial Inventory Leadership in ESG

Further Consolidation Potential Numerous sub-scale operators in the Eagle Ford basin creates a robust set of potential opportunities Focused on increasing efficiencies with scale and enhancing inventory Penn Virginia is committed to maintaining disciplined approach to evaluating any potential transaction Private Public Pro Forma PVAC Production(1)(3) Top 50 Public and Private Operator Production in the Eagle Ford(1)(2) Source: Enverus. 1) Represents 20:1 gas equivalents. 2) Represents gross operated production between 01/01/21 and 03/31/21 of public and private operators in the Eagle Ford. 3) Represents gross production for June 2021. Operator Concentration by Basin Bubble Size represents average boe/d per Operator(1) Gross boe/d Q1 2021 MMboe from Active Operators

Appendix

3Q21 Guidance Focused on Cash-on-Cash Returns and Committed to Continuous Improvement Note: Guidance as of August 3, 2021. All guidance are estimates as of the date hereof and is subject to change without notice depending upon a number of factors, including commodity prices, industry conditions and other factors that are beyond the Company’s control. The Company undertakes no obligation to affirm or update its guidance. Free cash flow 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 in the appendix of this presentation. 3Q21 guidance assumes Penn Virginia standalone 4Q21 guidance dependent on timing of Lonestar acquisition closing Strong realized price for oil and natural gas production Maintain current 2-rig program while closely monitoring commodity prices and costs Will continue to monitor service cost environment with goal of ensuring capital program generates robust returns and free cash flow D&C Capex between $56 MM and $64 MM for 3Q21 Approximately $1 MM of land, facilities and other Consistently low per BOE operating costs Focus on returns and capital efficiency Continue Free Cash Flow(1) generation Realized Pricing Differentials 3Q21 Oil (WTI, per bbl) $(3.00) - $(2.00) Natural gas (HHub, per MMBtu) $(0.10) - $0.10 Direct Operating Expense 3Q21 Lease Operating Expense (per boe) $4.65 - $4.85 GPT Expense (per boe) $2.50 - $2.70 Ad Valorem and production taxes 6.3% - 6.8% Adj. Cash G&A expense (per boe) $2.90 - $3.20 Sales 3Q21 Oil Sales - bbl/d 20,000 – 20,600

PVAC 3Q21 4Q21 1Q22 2Q22 3Q22 4Q22 1Q23 2Q23 3Q23 4Q23 1Q24 Hedges WTI Swaps (bbl/d) 1,902 815 – – – – – – – – – WTI Average Fixed Price ($/bbl) $59.95 $45.54 – – – – – – – – – WTI Collars (bbl/d) 14,130 13,043 7,083 6,181 4,484 4,484 2,917 2,885 – – – WTI Average Purchased Put ($/bbl) $44.27 $47.75 $44.71 $45.33 $40.00 $40.00 $40.00 $40.00 – – – WTI Average Sold Call ($/bbl) $59.21 $59.19 $58.05 $57.23 $52.47 $52.47 $50.00 $50.00 – – – WTI Purchased Puts (bbl/d) 1,630 1,630 – – – – – – – – – WTI Average Purchased Put ($/bbl) $55.00 $55.00 – – – – – – – – – WTI CMA Roll Swaps (bbl/d) 17,935 17,935 6,667 6,593 – – – – – – – WTI CMA Roll Average Fixed Price ($/bbl) $0.17 $0.17 $0.63 $0.63 HH Collars (MMbtu/d) 9,783 9,783 – 13,187 13,043 13,043 – 11,538 11,413 11,413 11,538 HH Average Purchased Put ($/MMbtu) $2.61 $2.61 – $2.50 $2.50 $2.50 – $2.50 $2.50 $2.50 $2.50 HH Average Sold Call ($/MMbtu) $3.12 $3.12 – $3.22 $3.22 $3.22 – $2.68 $2.68 $2.68 $3.65 HH Sold Puts (MMbtu/d) 6,522 6,522 – – – – – – – – – HH Average Sold Put Strike ($/MMbtu) $2.00 $2.00 – – – – – – – – – Ethane Swaps (gal/d) 35,870 – – 28,022 27,717 27,717 – 98,901 – – – Ethane Average Fixed Price ($/gal) $0.23 – – $0.25 $0.25 $0.25 – $0.23 – – – LONE Hedges WTI Swaps (bbl/d) 5,650 5,400 3,250 3,000 3,000 3,000 1,500 1,400 1,350 1,200 – WTI Average Fixed Price ($/bbl) $46.62 $46.03 $47.63 $46.99 $46.69 $46.76 $53.15 $52.83 $52.62 $52.36 – HH Swaps (MMbtu/d) 16,400 10,700 10,000 5,000 5,000 5,000 – – – – – HH Average Fixed Price ($/MMbtu) $2.93 $3.05 $2.88 $2.70 $2.70 $2.70 – – – – – Commodity Hedge Summary – Quarterly(1) As of 07/16/21.

PVAC Commodity Hedge Summary – Quarterly(1) As of 07/16/21. PVAC Strike Map 3Q21 4Q21 1Q22 2Q22 3Q22 4Q22 1Q23 2Q23 3Q23 4Q23 1Q24 WTI Call $50.00 4,348 3,261 2,917 2,885 2,853 2,853 2,917 2,885 – – – $50.50 1,630 1,630 – – – – – – – – – $55.00 – 3,261 – – – – – – – – – $56.80 – – 1,667 1,648 1,630 1,630 – – – – – $59.10 – – 833 – – – – – – – – $60.10 1,630 – – – – – – – – – – $65.00 3,261 – – – – – – – – – – $69.00 1,630 1,630 – – – – – – – – – $70.04 1,630 – – – – – – – – – – $70.30 – – – 1,648 – – – – – – – $72.00 – 1,630 – – – – – – – – – $72.05 – 1,630 – – – – – – – – – $72.85 – – 1,667 – – – – – – – – WTI Put $35.00 – – – – – – – – – – – $36.00 – – – – – – – – – – – $40.00 7,609 6,522 5,417 4,533 4,484 4,484 2,917 2,885 – – – $42.00 1,630 1,630 – – – – – – – – – $50.00 3,261 1,630 – – – – – – – – – $55.00 3,261 3,261 – – – – – – – – – $60.00 – – 1,667 1,648 – – – – – – – $65.00 – 3,261 – – – – – – – – – WTI Swap $45.54 815 815 – – – – – – – – – $70.75 1,087 – – – – – – – – – – HHUB Call $2.682 – – – – – – – 11,538 11,413 11,413 – $2.850 1,087 1,630 – – – – – – – – – $2.851 1,087 1,630 – – – – – – – – – $3.220 – – – 13,187 13,043 13,043 – – – – – $3.250 4,348 6,522 – – – – – – – – – $3.650 – – – – – – – – – – 11,538 HHUB Put $2.000 (4,348) (6,522) – – – – – – – – – $2.500 2,174 3,261 – 13,187 13,043 13,043 – 11,538 11,413 11,413 11,538 $2.660 2,174 3,261 – – – – – – – – – $2.662 2,174 3,261 – – – – – – – – –

Reconciliation of GAAP "Net Income" to Non-GAAP "Adjusted EBITDAX" Reconciliation of GAAP "Net income (loss)" to Non-GAAP "Adjusted EBITDAX" Adjusted EBITDAX represents net income (loss) before loss on extinguishment of debt, interest expense, income taxes, impairments of oil and gas properties, depreciation, depletion and amortization expense and share-based compensation expense, further adjusted to include the net commodity realized settlements of derivatives and 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, divestiture and strategic transaction costs, organizational restructuring, including severance and other items, executive retirement costs, other, reorganization items and restructuring expenses. We believe this presentation is commonly used by investors and professional research analysts for the valuation, comparison, rating, 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.

Reconciliation of GAAP "Realized prices" to Non-GAAP "Realized prices, including effects of derivatives, net" Reconciliation of GAAP "Realized prices" to Non-GAAP "Realized prices, including effects of derivatives, net" We present our realized prices for crude oil and natural gas, as adjusted for the effects of derivatives, net as we believe these measures are useful to management and stakeholders in determining the effectiveness of our price-risk management program that is designed to reduce the volatility associated with our operations. Realized prices for crude oil and natural gas, as adjusted for the effects of derivatives, net, are supplemental financial measures that are not prepared in accordance with generally accepted accounting principles (“GAAP”). The following table presents the calculation of our non-GAAP realized prices for crude oil and natural gas, as adjusted for the effects of derivatives, net and reconciles to realized prices for crude oil and natural gas determined in accordance with GAAP:

Definition of Net Debt Net Debt Net debt, excluding unamortized discount and debt issuance costs is a non-GAAP financial measure that is defined as total principal amount of long-term debt less cash and cash equivalents. Net debt, as adjusted, calculated on a pro forma basis as of December 31, 2020 and June 30, 2020 to adjust for related impacts of the Juniper Transaction (refer to footnote 1 below). The most comparable financial measure to net debt, excluding unamortized discount and debt issuance costs under GAAP is principal amount of long-term debt. Net debt is used by management as a measure of our financial leverage. Net debt, excluding unamortized discount and debt issuance costs should not be used by investors or others as the sole basis in formulating investment decisions as it does not represent the Company’s actual GAAP indebtedness.

Non-GAAP Reconciliation – "PV-10" Reconciliation of GAAP "Standardized Measure of Discounted Future Net Cash Flows" to Non-GAAP "PV-10" Non-GAAP PV-10 value is the estimated future net cash flows from estimated proved developed reserves discounted at an annual rate of 10 percent before giving effect to income taxes. The standardized measure of discounted future net cash flows is the after-tax estimated future cash flows from estimated proved reserves discounted at an annual rate of 10 percent, determined in accordance with generally accepted accounting principles (GAAP). We use non-GAAP PV-10 value as one measure of the value of our estimated proved reserves and to compare relative values of proved reserves amount exploration and production companies without regard to income taxes. We believe that securities analysts and rating agencies use PV-10 value in similar ways. Our management believes PV-10 value is a useful measure for comparison of proved reserve values among companies because, unlike standardized measure, it excludes future income taxes that often depend principally on the characteristics of the owner of the reserves rather than on the nature, location and quality of the reserves themselves. Note: Sec pricing: $49.78 and $2.43/MMBtu. June 30, 2021 SEC Pricing Flat $60 Pricing (in millions) Standardized measure of future discounted cash flows of PD $ 809 $ 1,043 Present value of future income taxes discounted at 10% 9 12 PV-10 of PD reserves $ 818 $ 1,055

Reconciliation of PV-10 and Adjusted PV-10 (Non-GAAP) – Proved Developed Reserves (“PD”) June 30, 2021 (in millions) Standardized measure of future discounted cash flows of PD 809 Add: Present value of future income taxes attributable to PD reserves discounted at 10% 9 PV-10 of proved developed reserves $ 818 Add: Adjustment using flat pricing of $60/BBL WTI, $2.75/MMbtu and NGLs as 23% of WTI PD reserves. Differentials of ($3.78) off WTI and ($0.05) off natural gas. 237 Adjusted PV-10 of PD adjusted for pricing and differentials $ 1,055 Reconciliation of PV-10 and Adjusted PV-10 (Non-GAAP) – PD Reserves Non-GAAP PV-10 value is the estimated future net cash flows from estimated proved reserves discounted at an annual rate of 10 percent before giving effect to income taxes. The standardized measure of discounted future net cash flows is the after-tax estimated future cash flows from estimated proved reserves discounted at an annual rate of 10 percent, determined in accordance with generally accepted accounting principles (GAAP). We use non-GAAP PV-10 value as one measure of the value of our estimated proved reserves and to compare relative values of proved reserves amount exploration and production companies without regard to income taxes. We believe that securities analysts and rating agencies use PV-10 value in similar ways. Our management believes PV-10 value is a useful measure for comparison of proved reserve values among companies because, unlike standardized measure, it excludes future income taxes that often depend principally on the characteristics of the owner of the reserves rather than on the nature, location and quality of the reserves themselves. Note: Sec pricing: $49.78 and $2.43/MMBtu.

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