2011 Investor Presentation

1. The GHS Conference 2011
Investor Presentation
July 18, 2011
NYSE: PVA
Eagle Ford Shale Drilling Rig
Gonzales County, Texas

2. 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 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; 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

3. Strategic Road Map
Near‐Term and Long‐Term Strategies for Maximizing Value
 Increasing oil/NGL exposure
• Targeting higher rate of return projects in low gas price environment
 Retain optionality of core gas assets
• Horizontal Cotton Valley, Haynesville Shale, Selma Chalk, etc.
 Maintain liquidity
• Recently completed $300 million senior note offering, netting over $50MM in cash, as well
as a tender offer for convertible notes
• Considering sale of non‐core gas assets to fund growth in oilier plays
 Explore and develop:
• Eagle Ford Shale
 Excellent early results
 Continue to build acreage position; drill multi‐year inventory
• Mid‐Continent / Marcellus Shale
 Continued participation in non‐operated Granite Wash
 Expand testing to eastern portion of Marcellus Shale acreage
3

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
2010 Proved Reserves: 942 Bcfe
Oil / Liquids
Wet Gas
Dry Gas
4
Note: 2011 data based on latest guidance announced 5/4/11

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 as gas prices improve
1 ‐ Pro forma to exclude proved reserves and production from Gulf Coast assets divested in January 2010;
5
2011 data based on latest guidance announced 5/4/11

6. Track Record of Value Creation
Low Costs and High Returns in Challenging Times
• Record of delivering growth at relatively low operating cost
– Along with hedges, helps preserve margins when commodity prices are low
• Historical statistics place PVA among the “best in class” ‐ 2010 was no exception
– Ranked 3rd in drill‐bit F&D and 6th in return on drilling dollars out of 38 leading E&P firms1
Lease Operating Expenses 2010 High‐Return Reserve Replacement1
$/Mcfe
1.40
$1.27 $14 60%
1.20 $1.15
$1.09 $1.06 $12 50%
1.00
$0.88 $10 40%
0.80
$8 30%
0.60
$6 20%
0.40 Median: 13.7%
$4 10%
Median: $2.91/ Mcfe
0.20 $2 0%
0.00 $0 ‐10%
2006 2007 2008 2009 2010 PVA
Ex‐Leasehold PD F&D ($/Mcfe, left axis) 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, 6
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
Net
Risked Henry Hub
Gross Average Reserve Gas Price
Undrilled Working Gross EUR Potential for
Play Locations Interest (Bcfe/Well)1 (Bcfe)2 10% IRR3
Eagle Ford Shale 98‐128 83% 3711 ‐‐‐4 N/A
Granite Wash 81 28% 6871 174 $1.14
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
Marcellus Shale 200‐250 90% 4.0 – 6.0 ‐‐‐4 $3.48
1 – Eagle Ford and Granite Wash EURs in MBOE
2 – 3P reserves as of 12/31/10
3 – Well economics assume $5.00 gas price per MMBtu Henry Hub, oil price of $85.00 per barrel WTI and NGL price of $42.00 per barrel 7
4 – No Eagle Ford Shale or Marcellus Shale proved or unproved reserves were included in the reserve report at year‐end 2010

8. Rates of Return
Balance Between Plays in Low Gas Price Environment
Pre‐Tax Rates of Return
Gas Price Sensitivity
80
70
60
50
40
30
20
10
0
$3 $4 $5 $6 $7
NYMEX Gas Price (Flat) ‐ $/MMBtu
Eagle Ford Shale Horizontal Cotton Valley
(EUR = 371 MBOE (8/8ths) / Capex = $7.000 MM) (EUR = 5.0 Bcfe (8/8ths) / Capex = $5.770 MM)
Selma Chalk Haynesville Shale
(EUR = 1.7 Bcfe (8/8ths) / Capex = $2.380 MM) (EUR = 6.7 Bcfe (8/8ths) / Capex = $10.000 MM)
Marcellus Shale Granite Wash ‐ South Clinton
(EUR = 4.2 Bcfe (8/8ths) / Capex = $4.500 MM) (EUR = 687 MBOE (8/8ths) / Capex = $7.000 MM)
8
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
9
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
10
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
• Positioning
Eagle Ford Shale – ~14,000 net acres in Gonzales Co., TX
– Operator with 83% WI and 63% NRI
– 98 to 128 gross drilling locations
– Processing agreement in place; fracturing
services agreement extended
– 9 wells currently producing approximately 5,000
BOEPD (gross), including NGLs
• Reserve Characteristics / Geology
– Volatile oil window: 75% oil, 15% NGLs, 10% gas
– First well IP’d at 1,250 BOE/d
– Next five wells IP’d at 582‐1,876 BOE/d
– 997 BOE/d average IP rate
• 2011 Activity
– 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)
11
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 Peers With Peers PVA / MHR / EOG
Fayette
County
Ford Acreage and Potential Acreage PVA
Gardner 1H (1,250 BOEPD)
Southern Hunter 1H (1,335 BOEPD)
Gonzo North 1H (1,039 BOEPD)
Near PVA
is Well‐Positioned Based Furrh 1H (>900 BOEPD)
Hawn Holt Unit (582‐1,876 BOEPD)
EOG Hill Unit 2H (1,347 BOEPD)
on Overall Excellent MRO MHR
Gonzo Hunter 1H
Industry Results in MHR Gonzales
PVA Acreage
~14,000 Net Acres (605 BOEPD)
FST County
Area Hunt
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)
Lavaca
Ullman 2H (925 BOEPD) County
HFS / Sweet (1,403‐1,578 BOEPD)
EOG / Riley Expl.
Wilson Edwards Unit (962 BOEPD)
County Maali 1H (968 BOEPD)
Karnes EOG
Milton Unit (668‐914 BOEPD)
County Harper Unit (695‐1,070 BOEPD) Dewitt
Dulling (1,255‐1,353 BOEPD) County
12
Note ‐ Industry results based on peers’ investor presentations and reported IP wellhead rates (pre‐processing); production “windows” are PVA’s approximation

13. Marcellus Shale
Exploration Efforts Under Way in North Central Pennsylvania
• Positioning
Marcellus Shale – ~55,000 net acres primarily in Pennsylvania
• ~35,000 net acres in Potter / Tioga Cos.
• ~20,000 net acres in SW PA
– Operator with ~87% WI and 76% NRI
– 200 to 250 gross drilling locations
• Reserve Characteristics / Geology
– Moderate depth and thickness
– Dry gas window
• 2011 Activity
– Focus on testing of eastern acreage in 2H11
– Continuing to consider alternatives for
Marcellus acreage position
13
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
• In 2H11, PVA Plans to Test
the Eastern Portion of its
McKean
Acreage Position (~20K County
PVA Acreage
~35,000 Net Acres
net acres) in Potter / XOM / PGE
Tioga Acreage, Initially
With Vertical Wells RRC
NFG
Potter
County UPL
NFG/PVA Button 3H, 4H (7‐12 MMcfd) Tioga
Risser (2.8‐3.1 MMcfd) Kenton 1H,4H (7.2‐11.3 MMcfd)
XOM / PGE Dunn (4.0 MMcfd) Mitchell 5H (7.7 MMcfd) County
SM Block 001 (4.5 MMcfd) Thomas 1H (4.9 MMcfd)
Potato Cr. 1H, 3H Geneseo (~3 MMcfd) Pierson 8H (10.0 MMcfd)
(4‐11 MMcfd)
Cameron Peer Wells Clinton Lycoming
County PVA Wells County County
14
Note ‐ Industry results and locations based on peers’ investor and other presentations and reported IP wellhead rates

15. Mid‐Continent: Liquids‐Rich Play Types
High‐Margin, Liquid‐Rich Reserves and Production
• Positioning
Anadarko Basin – CHK development drilling JV
• ~10,000 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
– Granite Wash: 48% liquids; attractive IRRs
– Other play types
• Tonkawa, Cleveland, St. Louis, Springer,
Viola, other
• 2011 Activity
– Up to 21 (9.7 net) Granite Wash wells
– Non‐operated drilling through YE11
– Up to $85MM of CAPEX (23% of total)
15
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 • ETX ‐ Horizontal Cotton Valley
Selma Chalk – 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
Wet Gas – 183 gross drilling locations
– 505 Bcfe of 3P reserves at YE10
Dry Gas
• Mississippi ‐ Selma Chalk
– 1.7 Bcfe PUDs; dry gas
Summary of Gas Option – $3.84 PV10 breakeven gas price
445 gross locations – 183 gross drilling locations
1.1 Tcfe of 3P reserves – 279 Bcfe of 3P reserves at YE10
16
Well economics assume $5.00 gas price per MMBtu Henry Hub, oil price of $85.00 per barrel WTI and NGL price of $42.00 per barrel

17. Solid 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
4.0x 40%
35.9% 35.6% 34.7%
31.6%
30.0% 3.0x
3.0x 28.2% 30%
2.3x
2.2x
2.0x 1.7x
1.8x 20%
1.2x
1.0x 10%
0.0x 0%
1 1
2006 2007 2008 2009 2010 Pro Forma
1Q11
Net Debt/EBITDAX Net Debt/Capitalization
1 ‐ Pro forma for 4/5/11 offering of $300MM of senior notes and convert tender offer; pro forma liquidity at 3/31/11 of $310MM is comprised of pro forma cash of approximately 17
$100MM and availability under our revolving credit facility of approximately $210MM (an approximately $398MM pro forma borrowing base)

18. Natural Gas Hedges
Protecting our Capital Budget and Well Economics
• 57% of our natural gas price exposure is hedged for the remainder of 2011
18
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 to be Significantly Undervalued on a “Sum‐of‐the‐Parts” NAV per Share
YE 2010 Net Asset Value @ Flat
SEC Pricing NYMEX Pricing of:
$4.38 1 $5.00 2 $6.00 2
Proved Developed Reserves3 $786.2 $918.6 $1,093.9
3
Proved Undeveloped Reserves 92.0 191.5 310.4
3
Probable and Possible Reserves 95.8 311.3 607.1
3P Reserves3 $973.9 $1,421.4 $2,011.4
4
Eagle Ford Shale 210.0 210.0 210.0
Marcellus Shale5 123.8 123.8 123.8
Asset Value $1,307.7 $1,755.2 $2,345.1
6
Less: Long‐Term Debt (net of cash; pro forma 12/31/10) (418.9) (418.9) (418.9)
Net Asset Value (NAV) $888.7 $1,336.3 $1,926.2
Shares Outstanding 45.7 45.7 45.7
NAV per Share $19.46 $29.26 $42.18
Recent Stock Price (7/15/11) $13.01 $13.01 $13.01
Upside to NAV per Share 50% 125% 224%
Asset Value Per Proved Reserve ($/Mcfe; 941.8 Bcfe @ 12/31/10) $ 1.39 $ 1.86 $ 2.49
2H11 2012 2013 2014
NYMEX Gas Futures Strip Prices @ 7/15/11 $4.62 $4.91 $5.24 $5.50
NYMEX Oil Futures Strip Prices @ 7/15/11 $98.17 $101.37 $103.25 $103.36
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 14,000 net Eagle Ford acres, using midpoint of estimated value range between $10K and $20K per net acre.
5 ‐ Approximately 55,000 net Marcellus acres, using midpoint of estimated value range between $500 and $4K per net acre.
6 ‐ Pro forma 12/31/10 net debt for 4/5/11 offering of $300MM of senior notes and convert tender offer
19

20. Why PVA?
A Track Record of Growth and Value Generation
• Diversified portfolio of high‐quality assets
• Track record of low‐cost, high‐return operations
• Allocating capital to build oil and liquids production
• High rate of return play types
• Option on natural gas assets
• Good liquidity
• Value proposition
20

21. Appendix
Granite Wash Pump Jack
Washita County, Oklahoma

22. 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
22
Dollars in millions, except per unit data; based on latest guidance announced 5/4/11

23. Non‐GAAP Reconciliations
Year ended December 31, LTM 3 Mos. Ended
2006 2007 2008 2009 2010 1Q11 Mar‐10 Mar‐11
EBITDAX 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
23

24. Penn Virginia Corporation
4 Radnor Corporate Center, Suite 200
Radnor, PA 19087
610‐687‐8900
www.pennvirginia.com
Granite Wash Drilling Rigs
Washita County, Oklahoma