Investor Presentation

Investor Presentation June 14-16, 2011 NYSE: PVA Eagle Ford Shale Drilling Rig Gonzales County, Texas

Forward-Looking Statements, Oil and Gas Reserves and Definitions Forward-Looking Statements Certain statements contained herein that are not descriptions of historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: the volatility of commodity prices for natural gas, natural gas liquids (NGLs) and oil; our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production; any impairments, write downs orwrite offs of our reserves or assets; the projected demand for and supply of natural gas, NGLs and oil; reductions in the borrowing base under our revolving credit facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and gas reserves; drilling and operating risks; our ability to compete effectively against other independent and major oil and natural gas companies; uncertainties related to expected benefits from acquisitions of oil and natural gas properties; environmental 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; our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain or attract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations; changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general domestic and international economic and political conditions; and the other risks, uncertainties and contingencies set forth in PVA s Annual Report on Form 10-K for the fiscal year ended December 31, 2010. Additional information concerning these and other factors can be found in our press releases and public periodic filings with the U.S. Securities and Exchange Commission (SEC), including our Annual Report on Form 10-K for the year ended December 31, 2010. Readers should not place undue reliance on forward looking statements, which reflect management s views only as of the date hereof. 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. Oil and Gas Reserves Effective January 1, 2010, the SEC permits oil and gas companies, in their filings with the SEC, to disclose not only proved reserves, but also probable reserves and possible reserves. As noted above, statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in PVA s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, available from PVA at Four Radnor Corporate Center, Suite 200, Radnor, PA 19087 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC s website at www.sec.gov. Definitions Proved reserves are those estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be economically producible in future years from known oil and gas reservoirs under existing economic and operating conditions and government regulation prior to the expiration of the contracts providing the right to operate, unless renewal of such contracts is reasonably certain. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves, but which are more likely than not to be recoverable (there should be at least a 50% probability that the quantities actually recovered will equal or exceed the proved plus probable reserve estimates). Possible reserves are those additional reserves that are less certain to be recoverable than probable reserves (there should be at least a 10% probability that the total quantities actually recovered will equal or exceed the proved plus probable plus possible reserve estimates). 3P reserves refer to the sum of proved, probable and possible reserves. Estimated ultimate recovery (EUR) is the sum of reserves remaining as of a given date and cumulative production as of that date. 2

Strategic Road Map Near-Term and Long-Term Strategies for Generating Value Maintain liquidity Completed $300 million senior note offering, netting over $50MM in cash Increase oil/ngl exposure Targeting high rate of return projects in low gas price environment Considering sale of non-core gas assets to fund growth in oilier plays Retain optionality of core gas assets Horizontal Cotton Valley, Haynesville Shale, Selma Chalk, etc. Explore and develop: Eagle Ford Shale - Continue to build acreage position; drill multi-year inventory Marcellus Shale - Continue to de-risk acreage and consider alternatives Mid-Continent - Upside associated with exploration program 3

Strategy Core Competencies for Value Growth Rate-of-Return Based Decisions Conservative commodity price outlook Diversified portfolio allows for efficient allocation of capital to projects and plays offering the best returns High-Quality Operating Assets Pursue predictable, profitable growth Production and reserves have annually grown 16% and 23%, respectively, over the last five years Organic growth enhanced by periodic acquisitions to replenish multi-year drilling inventory Prefer operatorship and reasonably long runway of prospects; not a land bank Divestitures of non-core assets narrows focus and provides supplemental liquidity Strong Technical Staff Continuously generate new ideas Focus on driving down unit costs, driving up margins and increasing efficiencies Strong Financial Position Maintain strong credit statistics and liquidity Engineering Excellence Fiscal Discipline Value Creation Focused Geology 4

Core Operating Regions Emerging Oil and Liquids-Rich Plays Plus Option in Significant Gas Plays 2011E CAPEX: $320MM - $370MM 77% Oil & Liquids-Rich Plays 2011E Production: 50-54 Bcfe 28-30% Oil & Liquids; 35% by 4Q11 2011E Production Appalachia 16% Mississippi 14% Marcellus 2% Mid-Continent 32% East Texas 25% Eagle Ford 11% 2010 Proved Reserves: 942 Bcfe Oil / Liquids Wet Gas Mississippi 182 Bcfe Appalachia 120 Bcfe East Texas 448 Bcfe Note: 2011 data based on latest guidance announced 5/4/11 Dry Gas Mid-Continent 192 Bcfe 5

Track Record of Growth Quality Assets are the Foundation for Growth in All Cycles Solid growth over the past five years Increasing proportion of growth from oil and NGLs Trend should accelerate as a majority of future drilling activity is for oil and NGLs Retention of gas option, allowing for flexibility in future periods Pro Forma Proved Reserves 1 Pro Forma Production 1 Bcfe 1,250 1,000 750 500 330 437 644 885 911 942 Bcfe 60 50 40 30 20 25.0 32.1 39.9 45.2 46.9 52.0 250 10 0 2005 2006 2007 2008 2009 2010 0 2006 2007 2008 2009 2010 2011E Oil & NGLs Natural Gas Oil & NGLs Natural Gas 1 - Pro forma to exclude proved reserves and production from Gulf Coast assets divested in January 2010; 2011 data based on latest guidance announced 5/4/11 6

Track Record of Value Creation Experienced People Provide the Foundation of Value Creation Record of delivering growth at relatively low operating cost Along with hedges, helps preserve margins when commodity prices are low Historically ranking among the best in drill-bit reserve replacement and value associated with investment; 2010 was no exception $/Mcfe 1.40 1.20 1.00 $0.88 Lease Operating Expenses $1.27 $1.15 $1.09 $1.06 $14 $12 $10 2010E High-Return Reserve Replacement 1 60% 50% 40% 0.80 $8 30% 0.60 $6 20% 0.40 $4 Median: 13.7% Median: $2.91/ Mcfe 10% 0.20 $2 0% 0.00 2006 2007 2008 2009 2010 $0 PVA Ex-Leasehold PD F&D ($/Mcfe, left axis) -10% Return on Drilling Dollars (right axis) 1 - Source: JPMorgan PD F&D Survey (3/14/11); peers: APA, APC, AREX, ATPG, BEXP, BRY, CHK, CLR, COG, CRZO, CXO, DNR, DPTR, DVN, EOG, EP, EQT, GDP, HK, MMR, NBL, NFX, PETD, PQ, PXD, PXP, QEP, RRC, SD, SFY, SM, SWN, UPL, VQ, WLL, WMB, XEC 7

Resource Profile PVA is Positioned in a Number of Leading Oil & Gas Plays Play Gross Undrilled Locations Average Working Interest Gross EUR (Bcfe/Well) 1 Net Risked Reserve Potential (Bcfe) 2 Henry Hub Gas Price for 10% IRR 3 Eagle Ford Shale 90-115 83% 280 380 1,4 --- N/A Granite Wash S. Clinton 81 28% 4.1 174 $1.14 Marcellus Shale Core 200-250 90% 4.0 6.0 4 --- $3.48 Horizontal Cotton Valley 79 79% 5.0 267 $2.54 Haynesville Shale 183 74% 6.7 505 $3.50 Selma Chalk 183 97% 1.7 279 $3.84 1 Eagle Ford in MBOE 2 3P reserves as of 12/31/10; no reserve potential reflected for Eagle Ford or Marcellus Shales and other prospects 3 Well economics; price per MMBtu Henry Hub; assumes oil price of $85.00 per barrel WTI and NGL price of $42.00 per barrel 4 There were no Eagle Ford and Marcellus Shale proved or unproved reserves at year-end 2010 8

80 70 60 50 40 30 20 10 Rates of Return Balance Between Plays in Low Gas Price Environment Pre-Tax Rates of Return Gas Price Sensitivity 0 $3 $4 $5 $6 $7 NYMEX Gas Price (Flat) - $/MMBtu Eagle Ford Shale (EUR = 371 MMBOE (8/8ths) / Capex = $7.000 MM) Selma Chalk (EUR = 1.7 Bcfe (8/8ths) / Capex = $2.380 MM) Marcellus Shale (EUR = 4.2 Bcfe (8/8ths) / Capex = $4.500 MM) Horizontal Cotton Valley (EUR = 5.0 Bcfe (8/8ths) / Capex = $5.770 MM) Haynesville Shale (EUR = 6.7 Bcfe (8/8ths) / Capex = $10.000 MM) Granite Wash - South Clinton (EUR = 4.1 Bcfe (8/8ths) / Capex = $7.000 MM) Note: Well economics; assumes oil price of $85.00 per barrel WTI and NGL price of $42.00 per barrel 9

Investing More in Oil & Liquids 2007-2011 Capital Spending Increasingly Allocated to Oil & NGLs Oil and Gas Capital Expenditures $MM 700 $642 600 500 $520 $450 400 $345 300 200 100 $172 61% 77% 0 5% 10% 30% 2007 2008 2009 2010 2011E Oil & NGLs Natural Gas Note: 2011 data based on latest guidance announced 5/4/11; see Appendix 10

2011 Capital Expenditures $320 - $370MM of 2011 Capital Spending, 77% Targeting Oil & Liquids-Rich Plays Forecast uses $4.25/MMBtu and $90.00/Barrel 12% 7% 5% 18% 52% 83% 23% Leasehold Seismic and Other Drilling Eagle Ford Mid-Continent Marcellus Shale Other Note: 2011 data based on latest guidance announced 5/4/11; see Appendix 11

Eagle Ford Shale: Volatile Oil Promising Early Results and Expanding Acreage Position in Emerging Oily Core Area Eagle Ford Shale Positioning ~12,700 net acres in Gonzales Co., TX Operator with 83% WI and 63% NRI 92 to 122 gross drilling locations 6 wells currently producing 4,440 BOEPD (gross) Midstream on-line; fracturing services agreement extended Reserve Characteristics / Geology Volatile oil window: 75% oil, 15% NGLs, 10% gas First well IP d at 1,250 BOE/d; 78MBOE to date Next five wells IP d at 582-1,876 BOE/d 2011 Activity 997 BOE/d average IP rate 3 rigs drilling; up to 29 (24.3 net) wells Up to $187MM of CAPEX (52% of total) 11% of 2011E production (20% of 4Q11E) Note: 2011 data based on latest guidance announced 5/4/11 12

Eagle Ford Shale: Play Activity Map Located in the Volatile Oil Window Near Strong, Early Industry Results PVA s Gonzales County Eagle Ford Acreage and Potential is Well-Positioned Based on Overall Excellent Industry Results in Area Peers With Acreage Near PVA EOG MRO MHR FST Hunt Peers PVA Gonzales County PVA / MHR / EOG Gardner 1H (1,250 BOEPD) Southern Hunter 1H (1,335 BOEPD) Gonzo North 1H (1,039 BOEPD) Furrh 1H (>900 BOEPD) Hawn Holt Unit (582-1,876 BOEPD) Hill Unit 2H (1,347 BOEPD) PVA Acreage 12,700 Net Acres Fayette County MHR Gonzo Hunter 1H (605 BOEPD) EOG Brothers Unit (1,798-2,508 BOEPD) EOG Marshall Unit (703-1,658 BOEPD) Cusack Clampit (1,044-2,107 BOEPD) Hansen-Kullin 3H (1,791 BOEPD) Ullman 2H (925 BOEPD) HFS / Sweet (1,403-1,578 BOEPD) Lavaca County Wilson County EOG / Riley Expl. / EOG Edwards Unit (962 BOEPD) Maali 1H (968 BOEPD) Karnes County EOG Milton Unit (668-914 BOEPD) Harper Unit (695-1,070 BOEPD) Dulling (1,255-1,353 BOEPD) Dewitt County Note - Industry results based on peers investor presentations; IP wellhead rates (pre-processing); production windows are PVA s approximation 13

Marcellus Shale: Economic Gas Exploration Efforts Under Way in North Central Pennsylvania Marcellus Shale Positioning ~42,000 net core acres Potter / Tioga Cos. ~35,000 net acres SW PA / NY ~7,000 net acres ~13,000 net non-core acres Operator with ~87% WI and 76% NRI 200 to 250 gross drilling locations Reserve Characteristics / Geology Moderate depth and thickness Expected to be dry gas 2011 Activity 1 rig drilling; up to 11 (10.0 net) wells Up to $64MM of CAPEX (18% of total) 2% of 2011E production (3% of 4Q11E) Note: 2011 data based on latest guidance announced 5/4/11 14

Marcellus Shale: Play Activity Map Located in the North Central Dry Gas Part of the Play Near Encouraging Industry Results PVA s Potter / Tioga Marcellus Position is Located in Areas With Strong Well IP Results Reported by Peers McKean County RRC SM Potato Cr. 1H, 3H (4-11 MMcfd) XOM / PGE Potter County XOM / PGE PVA Acreage ~35,000 Net Acres NFG-DCNR Block 001 (4.5 MMcfd) Geneseo (~3 MMcfd) UPL Button 3H, 4H (7-12 MMcfd) Kenton 1H,4H (7.2-11.3 MMcfd) Mitchell 5H (7.7 MMcfd) Thomas 1H (4.9 MMcfd) Pierson 8H (10.0 MMcfd) NFG Tioga County Cameron County Peer Wells PVA Wells Clinton County Lycoming County Note - Industry results and locations based on peers investor and other presentations; IP wellhead rates 15

Mid-Continent: Liquids Rich Play Types High-Margin, Liquid-Rich Reserves and Production Anadarko Basin Positioning CHK development drilling JV ~9,700 net acres in Washita Co. Operate about 1/3 rd ; ~35% WI ~80 drilling locations in JV ~40,000 net acres in exploratory plays Reserve Characteristics / Geology Granite Wash: 48% liquids; attractive IRRs Pursuing liquids-rich play types 2011 Activity Tonkawa, Cleveland, Granite Wash, other exploratory plays Up to 21 (9.7 net) Granite Wash wells Non-operated drilling through YE11 Up to $85MM of CAPEX (23% of total) Note: 2011 data based on latest guidance announced 5/4/11 16

East Texas & Mississippi: Gas Optionality Low-Cost, High-Potential Natural Gas Cotton Valley / Haynesville Shale Selma Chalk Wet Gas Dry Gas Summary of Gas Option 445 gross locations 1.1 Tcfe of 3P reserves ETX - Horizontal Cotton Valley 5.0 Bcfe PUDs; 35% liquids $2.54 PV10 breakeven gas price 79 gross drilling locations 267 Bcfe of 3P reserves at YE10 ETX - Haynesville Shale 6.7 Bcfe PUDs; dry gas $3.50 PV10 breakeven gas price 183 gross drilling locations 505 Bcfe of 3P reserves at YE10 Mississippi - Selma Chalk 1.7 Bcfe PUDs; dry gas $3.84 PV10 breakeven gas price 183 gross drilling locations 279 Bcfe of 3P reserves at YE10 Well economics; price per MMBtu Henry Hub; assumes oil price of $85.00 per barrel WTI and NGL price of $42.00 per barrel 17

Strong Financial Position Financial Flexibility to Execute Growth Plan Over the past few years, we have prudently managed our balance sheet Liquidity has remained strong over the past few years PVA remains well-positioned to fund its 2011 capital spending plan Conservative Leverage Strong Liquidity 4.0x 3.0x 2.0x 35.9% 30.0% 1.7x 35.6% 1.8x 31.6% 2.3x 28.2% 2.2x 34.7% 3.0x 40% 30% 20% $MM 600 500 400 300 $361 $458 $540 $310 1.0x 1.2x 10% 200 100 $185 $147 0.0x 2006 2007 2008 2009 2010 1 Pro Forma 1Q11 Net Debt/EBITDAX Net Debt/Capitalization 0% 0 2006 2007 2008 2009 2010 Pro Forma 1 1Q11 Borrowing Base Availability Cash 1 - Pro forma for 4/5/11 offering of $300MM of senior notes; pro forma liquidity at 3/31/11 of $310MM is comprised of pro forma cash of approximately $100MM and availability under our revolving credit facility, subject to covenant compliance, of approximately $210MM (approximately $398MM pro forma borrowing base) 18

MMBtu per Day (000s) Weighted Avg. Floors and Swaps ($/MMBtu) Natural Gas Hedges Protecting our Capital Budget and Well Economics 57% of our natural gas price exposure is hedged for the remainder of 2011 80 Natural Gas Hedges 1 Swaps and Collars $8 70 Weighted Average Floor / Swap Price by Quarter $7 60 50 40 $5.65 $5.67 $5.70 $4.25 $4.96 $4.96 $4.25 $4.25 $4.25 $5.31 $5.31 $5.10 $5.00 $5.00 $5.00 $5.00 Budget Price by Quarter $6 $5 $4 30 $3 20 $2 10 $1 0 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 $0 1 As of 5/4/11; crude oil hedges include 425 BOPD @ $80 x $102 for 1H11, 860 BOPD @ $97 x $107 for 2H11 and 500 BOPD @ $100 x $120 for CY12 19

Value Proposition PVA Appears Significantly Undervalued on a Sum-of-the-Parts NAV per Share YE 2010 SEC Pricing Net Asset Value @ Flat NYMEX Pricing of: $4.38 1 $5.00 2 $6.00 2 Proved Developed Reserves 3 $786.2 $918.6 $1,093.9 Proved Undeveloped Reserves 3 92.0 191.5 310.4 Probable and Possible Reserves 3 95.8 311.3 607.1 3P Reserves 3 $973.9 $1,421.4 $2,011.4 Eagle Ford Shale 4 95.3 95.3 95.3 Marcellus Shale 5 168.0 168.0 168.0 Mid-Continent Exploratory 6 50.0 50.0 50.0 Asset Value $1,287.2 $1,734.7 $2,324.6 Less: Long-Term Debt (net of cash; pro forma 3/31/11) 7 (497.1) (497.1) (497.1) Net Asset Value (NAV) $790.1 $1,237.6 $1,827.6 Shares Outstanding (4/29/11) 45.7 45.7 45.7 NAV per Share $17.30 $27.10 $40.02 Recent Stock Price (6/10/11 close) $15.28 $15.28 $15.28 Upside to NAV per Share 13% 77% 162% Asset Value Per Proved Reserve ($/Mcfe; 941.8 Bcfe) $ 1.37 $ 1.84 $ 2.47 2H11 2012 2013 2014 NYMEX Gas Futures Strip Prices @ 6/10/11 close $4.88 $5.12 $5.35 $5.55 NYMEX Oil Futures Strip Prices @ 6/10/11 close $100.10 $102.48 $101.96 $100.96 1 - SEC pricing of $4.38 per MMBtu (natural gas) and $79.43 per barrel (crude oil) 2 - Natural gas price varies between $5 and $6 per MMBtu, while assuming an $85 per barrel WTI price and $42 per barrel NGL price 3 - Third-party 3P reserve report as of 12/31/10; pretax PV-10% values 4 - Approximately 12,700 net Eagle Ford acres, using midpoint of recent transactions value range of between $5K and $10K per net acre 5 - Approximately 42,000 net Marcellus acres, using midpoint of PVA s estimated value range of between $3K and $5K per net acre 6 - Approximately 40,000 net exploratory acres, using midpoint of PVA s estimated value range of between $500 and $2,000 per net acre 7 - Pro forma for 4/5/11 offering of $300MM of senior notes 20

Why PVA? A Track Record of Growth and Value Generation Diversified portfolio of high-quality assets Management team with a track record Allocating capital to build oil and liquids production High rate of return play types Option on natural gas assets Strong balance sheet Value proposition 21

Appendix Granite Wash Pump Jack Washita County, Oklahoma

2011 Guidance Table As of May 4, 2011 Full-Year 2011 Guidance Production: Natural gas (Bcf) 36.2-37.8 Crude oil (MBbls) 1,300-1,500 NGLs (MBbls) 1,000-1,200 Equivalent production (Bcfe) 50.0-54.0 Equivalent daily production (MMcfe per day) 137.0-147.9 Operating expenses: Lease operating ($ per Mcfe) $ 0.75-0.80 Gathering, processing and transportation costs ($ per Mcfe) $ 0.32-0.33 Production and ad valorem taxes (percent of oil and gas revenues) 7.0% - 7.5% General and administrative: Recurring general and administrative $ 44.5-45.5 Share-based compensation $ 6.0-8.0 Restructuring $ 0.1 0.1 Total reported G&A $ 50.6 53.6 Exploration: Dry hole costs $ 18.5-19.5 Unproved property amortization $ 40.0-42.0 Other $ 11.5-13.5 Total reported Exploration $ 70.0-75.0 Depreciation, depletion and amortization ($ per Mcfe) $ 3.00-3.25 Capital expenditures: Development drilling $ 225.0-255.0 Exploratory drilling $ 35.0-50.0 Pipeline, gathering, facilities $ 7.0-8.0 Seismic $ 8.0-10.0 Lease acquisitions, field projects and other $ 45.0-47.0 Total oil and gas capital expenditures $ 320.0-370.0 Dollars in millions, except per unit data; based on latest guidance announced 5/4/11 23

Non-GAAP Reconciliations EBITDAX Year ended December 31, LTM 3 Mos. Ended 2006 2007 2008 2009 2010 1Q11 Mar-10 Mar-11 dollars in millions Net income (loss) from continuing operations $ 44.2 $ 26.5 $ 93.6 $ (130.9) $ (65.3) $ (102.4) $ 10.8 $ (26.3) Add: Income tax expense (benefit) 50.0 30.5 55.6 (85.9) (42.9) (63.8) 6.8 (14.2) Add: Interest expense 6.0 20.1 24.6 44.2 53.7 53.5 13.7 13.5 Add: Depreciation, depletion and amortization 56.7 88.0 135.7 154.4 134.7 139.5 30.0 34.8 Add: Exploration 34.3 28.6 42.4 57.8 49.6 73.2 6.0 29.5 Add: Impairments 8.5 2.6 20.0 106.4 46.0 46.0 - - Add: Share-based compensation expense 1.1 1.6 6.0 9.1 7.8 6.6 3.0 1.8 Add/Less: Derivatives (income) expense included in net income (30.7) 2.0 (29.7) (31.6) (41.9) (13.4) (29.9) (1.3) Add/Less: Cash receipts (payments) to settle derivatives 10.5 14.1 (7.6) 58.1 32.8 31.1 8.4 6.7 Add/Less: Net loss (gain) on sale of assets - (12.6) (33.2) (2.0) (1.2) (1.9) 0.3 (0.5) Adjusted EBITDAX $ 180.6 $ 201.5 $ 307.4 $ 179.7 $ 173.3 $ 168.3 $ 49.1 $ 44.1 24

Penn Virginia Corporation 4 Radnor Corporate Center, Suite 200 Radnor, PA 19087 610-687-8900 www.pennvirginia.com Marcellus Shale Drilling Rig Potter County, Pennsylvania