PennVirginiaCorp Investors Presentation May 2011

Investor PresentationMay 2011

NYSE: PVA

Eagle Ford Shale Drilling RigGonzales County, Texas

PENN VIRGINIACORPORATIONPENN VIRGINIACORPORATION

PENN VIRGINIACORPORATIONPENN VIRGINIACORPORATION 2

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 SecuritiesAct 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 arenot 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 replaceoil and gas reserves and sustain production; any impairments, write‐downs or write‐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; ourability 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 provedoil and gas reserves; drilling and operating risks; our ability to compete effectively against other independent and major oil and natural gas companies; uncertaintiesrelated 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 financialliquidity and to access adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure events; ourability to retain or attract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations; changes ingovernmental regulation or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general domestic andinternational 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 yearended 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 ExchangeCommission (SEC), including our Annual Report on Form 10‐K for the year ended December 31, 2010. Readers should not place undue reliance on forward‐lookingstatements, 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 makeany 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. Anyreserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves notnecessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure inPVA’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 economicallyproducible in future years from known oil and gas reservoirs under existing economic and operating conditions and government regulation prior to the expiration of thecontracts providing the right to operate, unless renewal of such contracts is reasonably certain. Probable reserves are those additional reserves that are less certain tobe 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 actuallyrecovered will equal or exceed the proved plus probable reserve estimates). Possible reserves are those additional reserves that are less certain to be recoverable thanprobable reserves (there should be at least a 10% probability that the total quantities actually recovered will equal or exceed the proved plus probable plus possiblereserve estimates). “3P” reserves refer to the sum of proved, probable and possible reserves. Estimated ultimate recovery (EUR) is the sum of reserves remaining as ofa given date and cumulative production as of that date.

Forward‐Looking Statements, Oil and Gas Reserves and Definitions


Maintain liquidity• Completed $300 million senior note offering• Considering sale of non‐core assets

Increase oil/NGL exposure• Targeting high rate of return projects in low gas price environment

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 Mid‐Continent

• Active exploration and development programs

3

Near‐Term and Long‐Term Catalysts for Generating Value

Strategic Road Map


Three 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– Seek predictable, profitable growth

Production and reserves have grown annually 16% and 23% respectively over the last five years

– Organic growth remains the preference, although periodic acquisitions 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

• Build on Strong Technical Staff– Continuously generate ideas – Focus on driving down unit costs, driving up

margins and increasing efficiencies• Maintain Strong Financial Position

– Maintain strong credit statistics and liquidity

ValueCreation

Fiscal Discipline

EngineeringExcellence

FocusedGeology

Strategy


Emerging Oil and Liquids‐Rich Plays, Plus “Option” in Significant Gas Plays

Core Operating Regions

Note: 2011 data based on latest guidance announced 5/4/11

2010 Proved Reserves: 942 Bcfe

2011E CAPEX: $320MM ‐ $370MM77% Oil & Liquids‐Rich Plays2011E Production: 50‐54 Bcfe

28‐30% Oil & Liquids

Oil / Liquids

Wet Gas

Dry Gas

2011E Production

5


Quality Assets are the Foundation for Growth in All Cycles

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

Track Record of Growth

• 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 greater growth in future periods


Experienced People Provide the Foundation of Value Creation

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

Track Record of Value Creation

$0.88

$1.15

$1.27

$1.09 $1.06

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

2006 2007 2008 2009 2010

Lease Operating Expenses$/Mcfe

2010E High‐Return Reserve Replacement1

$0

$2

$4

$6

$8

$10

$12

$14

‐10%

0%

10%

20%

30%

40%

50%

60%

Ex‐Leasehold PD F&D ($/Mcfe, left axis) Return on Drilling Dollars (right axis)

Median: $2.91/ Mcfe

Median: 13.7%

PVA

• Record of delivering growth at relatively low operating cost– Helps preserve margins, along with hedges, when commodity prices are low

• Historically ranking among the best in drill‐bit reserve replacement and value associated with investment; 2010 was no exception


Play

Gross Undrilled Locations

Average Working Interest

Gross EUR (Bcfe/Well)1

Net Risked Reserve Potential (Bcfe)2

Henry HubGas Price

for 10% IRR3

Eagle Ford Shale 90‐115 83% 280 – 3801,4 ‐‐‐ N/A

Granite Wash – S. Clinton 81 28% 5.3 174 N/A

Marcellus Shale – Core 200‐250 90% 4.0 – 6.04 ‐‐‐ $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

8

PVA is Positioned in a Number of Compelling Plays in the U.S.

1 – Eagle Ford in MBOE2 – 3P reserves as of 12/31/10; no reserve potential reflected for Eagle Ford or Marcellus Shales and other prospects3 – Well economics; price per MMBtu Henry Hub; assumes oil price of $85.00 per barrel WTI and NGL price of $42.00 per barrel4 – There were no Eagle Ford and Marcellus Shale proved or unproved reserves at year‐end 2010

Resource Profile


Pre‐Tax Rates of ReturnGas Price Sensitivity

0

10

20

30

40

50

60

70

80

90

100

$2 $3 $4 $5 $6 $7 $8 $9 $10NYMEX Gas Price (Flat) ‐ $/MMBtu

Eagle Ford Shale (EUR = 371 MMBOE (8/8ths) / Capex = $7.000 MM)

Horizontal Cotton Valley (EUR = 5.0 Bcfe (8/8ths) / Capex = $5.770 MM)

Selma Chalk (EUR = 1.7 Bcfe (8/8ths) / Capex = $2.380 MM)

Haynesville Shale (EUR = 6.7 Bcfe (8/8ths) / Capex = $10.000 MM)

Marcellus Shale (EUR = 4.2 Bcfe (8/8ths) / Capex = $4.500 MM)

Granite Wash ‐ South Clinton (EUR = 5.3 Bcfe (8/8ths) / Capex = $6.250 MM)

9

PVA is Positioned in a Number of the Most Compelling Plays in the U.S.

Note: Well economics; assumes oil price of $85.00 per barrel WTI and NGL price of $42.00 per barrel

Rates of Return


2007 ‐ 2011 Capital Spending Increasingly Allocated to Oil & NGLs

Investing More in Oil & Liquids

Note: 2011 data based on latest guidance announced 5/4/11; see Appendix


2011 Capital Expenditures

Note: 2011 data based on latest guidance announced 5/4/11; see Appendix

Forecast uses $4.25/MMBtu and $90.00/Barrel

$320 ‐ $370MM of 2011 Capital Spending, 77% Targeting Oil & Liquids‐Rich Plays


Promising Early Results and Expanding Acreage Position in Emerging Oily Core Area


Eagle Ford Shale: Volatile Oil

Eagle Ford Shale• Positioning

– ~12,700 net acres in Gonzales Co., TX– Volatile oil window– Operator with 83% WI and 63% NRI– 90 to 115 gross drilling locations– Actively leasing

• Reserve Characteristics / Geology– Deeper with >100 feet thickness– First well IP’d at 1,250 BOE/d, excl. NGLs– 75% oil, 15% NGLs and 10% dry gas– Potential upside in Austin Chalk, Buda

• 2011 Activity– 3 rigs drilling; up to 29 (24.3 net) wells– Up to $187MM of CAPEX (48% of total)– 11% of 2011E production (20% of 4Q11E)


Located in the “Volatile Oil” Window Near Strong, Early Industry Results

Note ‐ Industry results based on peers’ investor presentations; IP wellhead rates (pre‐processing); production “windows” are PVA’s approximation

Eagle Ford Shale: Play Activity Map

GonzalesCounty

KarnesCounty Dewitt

County

LavacaCounty

FayetteCounty

WilsonCounty

PVA / MHR (1H11)Gardner 1H (1,250 BOEPD)

Southern Hunter 1H (1,335 BOEPD)Gonzo North 1H (1,039 BOEPD)

Furrh 1H (>900 BOEPD)

PVA Acreage~12,700 Net Acres

EOG (2Q10)Brothers Unit (1,798‐2,508 BOEPD)

EOG (2Q10‐3Q10)Marshall Unit (703‐1,658 BOEPD)

Cusack Clampit (1,044‐2,107 BOEPD)

EOG (2Q09‐4Q10)Milton Unit (668‐914 BOEPD)Harper Unit (695‐1,070 BOEPD)Dulling (1,255‐1,353 BOEPD)

Riley Expl. (1Q10)Maali 1H (968 BOEPD)

• PVA’s Gonzales County Eagle Ford Acreage and Potential is Well‐Positioned Based on Overall Excellent Industry Results inArea

Peers WithAcreageNear PVAEOGHuntMHRFST

MHR (1Q11)Gonzo Hunter 1H

(605 BOEPD)

PeersPVA


Exploration Efforts Under Way in North Central Pennsylvania

Marcellus Shale: Economic Gas


Marcellus Shale• Positioning

– ~42,000 net core acres in PA and NY• 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– Currently seeking alternatives to monetize a

portion of acreage position

• 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)


Marcellus Shale: Play Activity Map

PotterCounty

TiogaCounty

McKeanCounty

CameronCounty

LycomingCounty

UPLButton 3H, 4H (7‐12 MMcfd)Kenton 4H (11.3 MMcfd)Mitchell 5H (7.7 MMcfd)SM

Potato Cr. 1H, 3H(4‐11 MMcfd)

PVA Acreage~35,000 Net Acres

• PVA’s Potter / Tioga Marcellus Position is Located in AreasWith Strong Well IPResults Reportedby Peers

ClintonCounty

XOM / PGE

XOM / PGE

NFGRRC

SM

NFG

Located in the North Central “Dry Gas” Part of the Play Near Encouraging Industry Results

Note ‐ Industry results and locations based on peers’ investor and other presentations; IP wellhead rates

15

Peer WellsPVA Wells


High‐Margin, Liquid‐Rich Production Growth Led by the Granite Wash

Mid‐Continent: Liquids Rich Play Types

Anadarko Basin


• Positioning– CHK development drilling JV

• ~9,700 net acres in Washita Co.• Operate about 1/3rd; ~35% WI• ~80 drilling locations in JV

– ~40,000 net acres in exploratory plays

• Reserve Characteristics / Geology– 5.3 Bcfe PUDs in JV; 48% liquids; high IRRs– Pursuing liquids‐rich play types

• Tonkawa, Cleveland, Granite Wash, other exploratory plays

• 2011 Activity– Up to 21 (9.7 net) Granite Wash wells– Non‐operated drilling through YE11– Up to $85MM of CAPEX (23% of total)


Low‐Cost, High‐Potential Natural Gas

Well economics; price per MMBtu Henry Hub; assumes oil price of $85.00 per barrel WTI and NGL price of $42.00 per barrel

• 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

East Texas & Mississippi: Gas Optionality

Cotton Valley / Haynesville Shale

Selma Chalk

Summary of Gas Option445 gross locations

1.1 Tcfe of 3P reserves

Wet Gas

Dry Gas


Cotton Valley Production Comparisons2010 Horizontal Completions vs. Typical Horizontal & Vertical Well

0

1,000

2,000

3,000

4,000

5,000

6,000

0 30 60 90 120 150 180 210 240 270 300

Days on Line

Post Processing Gas Equ

iv. R

ate (M

cfep

d)

Gibson 3H McClendon 6H Fogle 8HWilliams 12H Foreman 3H Brown 11HRosehaven 11H Typical Vertical Well Typical Horizontal Well

18

Recent Success With this Oil and Liquids‐Rich Horizontal Play

East Texas Horizontal Cotton Valley


• 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

19

Strong Financial Position

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)

Financial Flexibility to Execute Growth Plan

1

1.2x

1.7x 1.8x

2.3x 2.2x

3.0x

35.9%

30.0%

35.6%

31.6%

28.2%

34.7%

0%

10%

20%

30%

40%

0.0x

1.0x

2.0x

3.0x

4.0x

2006 2007 2008 2009 2010 Pro Forma1Q11

Conservative Leverage

Net Debt/EBITDAX Net Debt/Capitalization

1


Natural Gas Hedges

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

Protecting our Capital Budget and Well Economics

Natural Gas Hedges1Swaps and Collars

$5.65 $5.67 $5.70$5.31 $5.31

$5.10

$4.25

$5.00 $5.00 $5.00 $5.00

$4.96 $4.96

$4.25$4.25$4.25

0

10

20

30

40

50

60

70

80

1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12

MMBtu pe

r Day

(000s)

$0

$1

$2

$3

$4

$5

$6

$7

$8

Weighted Avg. Floors and Sw

aps ($/MMBtu)

Weighted Average Floor /Swap Price by Quarter

Budget Price by Quarter


Value PropositionPVA Appears Significantly Undervalued on a “Sum‐of‐the‐Parts” NAV per Share

21

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 price3 ‐ Third‐party 3P reserve report as of 12/31/10; pretax PV‐10% values4 ‐ Approximately 12,700 net Eagle Ford acres, using midpoint of recent transactions’ value range of between $5K and $10K per net acre5 ‐ Approximately 42,000 net Marcellus acres, using midpoint of PVA’s estimated value range of between $3K and $5K per net acre6 ‐ Approximately 40,000 net exploratory acres, using midpoint of PVA’s estimated value range of between $500 and $2,000 per net acre7 ‐ Pro forma for 4/5/11 offering of $300MM of senior notes

YE 2010SEC Pricing

$4.38 1 $5.00 2 $6.00 2

Proved Developed Reserves3 $786.2 $918.6 $1,093.9

Proved Undeveloped Reserves3 92.0 191.5 310.4

Probable and Possible Reserves3 95.8 311.3 607.1

3P Reserves3 $973.9 $1,421.4 $2,011.4

Eagle Ford Shale4 95.3 95.3 95.3

Marcellus Shale5 168.0 168.0 168.0

Mid‐Continent Exploratory6 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 (2/18/11) 45.7 45.7 45.7

NAV per Share $17.30 $27.10 $40.02

Recent Stock Price (5/10/11 close) $14.74 $14.74 $14.74Upside to NAV per Share 17% 84% 171%

Asset Value Per Proved Reserve ($/Mcfe; 941.8 Bcfe) 1.37$ 1.84$ 2.47$

2H11 2012 2013 2014 NYMEX Gas Futures Strip Prices @ 5/10/11 close $4.49 $4.89 $5.27 $5.61NYMEX Oil Futures Strip Prices @ 5/10/11 close $104.59 $104.28 $101.17 $98.91

Net Asset Value @ Flat NYMEX Pricing of:


• 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

22

Why PVA?A Track Record of Growth and Value Generation


Appendix

Granite Wash Pump JackWashita County, Oklahoma


2011 Guidance TableAs of May 4, 2011

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

2011 GuidanceFull‐Year

Dollars in millions, except per unit data


Non‐GAAP Reconciliations

2006 2007 2008 2009 2010 Mar‐10 Mar‐11EBITDAX

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

dollars in millions

Year ended December 31, 3 Mos. EndedLTM1Q11


Penn Virginia Corporation4 Radnor Corporate Center, Suite 200Radnor, PA 19087610‐687‐8900www.pennvirginia.com

Marcellus Shale Drilling RigPotter County, Pennsylvania