Brean Murray, Carret & Company2012 Global Resources & Infrastructure ConferenceInvestor PresentationMarch 1, 2012NYSE: PVA

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, NGLs and oil; our ability to develop, explore for and replace oil and gas reserves andsustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; 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 revolvingcredit facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oiland 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 ofproduction for our wells and the extent to which actual production differs from estimated proved oil and gas reserves; drilling and operating risks; our ability tocompete effectively against other independent and major oil and natural gas companies; our ability to successfully monetize select assets and repay our debt; leaseholdterms expiring before production can be established; environmental liabilities that are not covered by an effective indemnity or insurance; the timing of receipt ofnecessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintain adequate financial liquidity and to accessadequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain orattract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations; changes in governmental regulationor enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general domestic and international economicand political conditions; and other risks set forth in our filings with the U.S. Securities and Exchange Commission (SEC).

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC, including our Annual Report onForm 10‐K for the year ended December 31, 2011. Readers should not place undue reliance on forward‐looking statements, which reflect management’s views only asof 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 aresult 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, 2011, which is available from PVA at Four Radnor Corporate Center, Suite 200, Radnor, PA19087 (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

2

PVA Overview

• Small‐cap domestic onshore E&P company • Active in the Eagle Ford Shale oil play with excellent results to date: YE11 PV‐10 of $278 MM• HBP positions in Granite Wash, East Texas, Mississippi and Appalachia: YE11 PV‐10 of $596 MM

• PVA is executing a strategy of growth in oil and NGL rich plays• 2010 and 2011 have been transformational years, diversifying our portfolio towards oil / NGLs• Successful drilling results in the Eagle Ford Shale – 36 wells on‐line as of 2/29/12• Adding to Eagle Ford drilling inventory – recent AMI in Lavaca County

• Considering ways to increase liquidity• Considering a significant asset sale during 1H12

• 2012 CAPEX fully‐funded; no material debt maturities until 2016; pending borrowing base expected to be similar to current commitment amount of $300 MM in April 2012 

– Immediate liquidity of approximately $184 MM at 2/29/12 and 2012E cash flow outspend of $107‐157 MM• Asset sale proceeds would reduce bank debt and increase liquidity – preclude any need for capital markets

• Reduced capital expenditures• 2012 capital program of $300‐325 MM is 27‐33% less than $446 MM in 2011• 85% Eagle Ford (oily) and 8% Granite Wash (NGLs/oil) ‐ no natural gas drilling due to very weak prices

• Continued hedging• Oil: 62% hedged for 2012 at weighted average of $99.40 per barrel (floor/swap)• Gas: 31% hedged for 2012 at weighted average of $5.43 per MMBtu (floor/swap)• 2013: 2,560 BOPD hedged at weighted average of $96.21 per barrel (floor/swap); no gas hedges 3

Gas‐to‐Oil / Liquids Has Increased Revenues and Cash Flows

PVA’s Growth Strategy is Sound

• We commenced our “Gas‐to‐Oil” transition in mid‐2010

• Built Eagle Ford position from initial 6,800 net acres to at least 23,000 net acres in just over one year

– Up to approximately 190 well locations (39 drilled and up to ~150 drilling locations)

– Includes acreage and locations to be earned in recently announced AMI in Lavaca County

• Grew oil/NGL production from 2,461 Bbls/day in 2Q10 to 7,194 Bbls/day in 4Q11 (+192%)

– Up 43% from 5,033 Bbls/day in 4Q10

• Other oily / liquids‐rich plays include the Cotton Valley and Granite Wash

• Retain substantial core gas assets for eventual gas price recovery

• East Texas Haynesville Shale, Mississippi Selma Chalk and Appalachia

• Make selective divestitures to increase margins, operational focus, liquidity

• Continue to expand oil and liquids reserves and drilling inventory

• Will test a horizontal oil prospect in the Mid‐Continent in the 2nd quarter

• Continue to grow oil and liquids production and cash flows4

$0

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Pro Forma Quarterly Revenue by CommodityPre‐Hedging; $MM

Gas Oil NGLs

0

40

80

120

160

Pro Forma 2008 ‐ 2012 Production by CommodityMMcfe per day (1 Bbl = 6 Mcfe)

Base Gas Shale Gas Oil NGLs

• In mid‐2010, PVA implemented a strategy to transition from dry gas to oil & liquids• Since then, the decrease in gas prices and increase in oil & liquids prices has shifted the market from a “6:1” to a “20:1” liquids‐to‐gas price environment

• Examining revenue growth by commodity type reveals PVA’s true growth in value

Value Growth From 2009‐2012 Due to Drive Towards Oil & NGLs

Value Has Shifted to Oil/Liquids

Perception: “6‐to‐1” Equivalent EnvironmentGas Producer With Little to No Production Growth

Reality: “20‐to‐1” Price EnvironmentOil/NGL Producer With Revenue Growth

Note: Pro forma to exclude South Texas and South Louisiana assets sold in January 2010 and primarily Arkoma Basin assets sold in August 2011

~40%

~60%

~70%

~30%

5

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$20

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$70

1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11

$ per Mcfe$ 

Millions

Quarterly EBITDAX and Cash Margins

Adjusted EBITDAX ($MM) Gross Operating Margin per Mcfe

• EBITDAX has increased significantly since mid‐2010 when we began our strategic shift towards oil and NGL growth

• Gross operating margin per Mcfe has also improved significantly due to the increase in oil prices and declining operating costs per unit

Shift to Oil/Liquids Strategy Has Dramatically Improved Cash Flow Margins

EBITDAX and Cash Margin Growth

Note: Gross operating margin per Mcfe is defined as total product revenues, excluding the impact of hedges, less direct operating expenses per unit of equivalent production

6

• Trades at 1.3x analysts’ mean 2012E CFPS1

– Trades at a 62% discount to selected peers which trade at an average of 3.4x

• Trades at 3.7x analysts’ mean 2012E EBITDAX1

– Trades at a 30% discount to selected peers which trade at an average of 5.3x

• $914MM enterprise value is only $40MM ($0.87/share) above YE11 PV‐10 of $874MM1,2

– Proved reserve value only, with ±$1/MMBtu gas price sensitivity of ±$260MM ($5.67/share)– ±$10/Bbl oil price sensitivity of ±$115MM ($2.51/share)

1 – Sources: First Call; peers: CRK, FST, GDP, PETD and PQ; as of 2/29/122 – PV‐10 pretax value of $874MM based on SEC pricing of $96.19 per Bbl for oil and $4.12 per MMBtu for natural gas

Valuation Multiples Below Peers Who are Also Leveraged, Have Less Oil & Liquids and No Dividend

PVA Appears Undervalued

0.0x

2.0x

4.0x

6.0x

PVA Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

2012E CFPS and EBITDAX Multiples

Price‐to‐2012E CFPS TEV‐to‐2012E EBITDAX

7

Continue to increase oil and liquids exposure• 37% of 4Q11 production vs. 18% in FY10; ~50% by 4Q12

• 42% of 2012E production and 78% of 2012E product revenues

• Eagle Ford‐driven with long‐term goal to add more of this play and other oily inventory

Retain long‐term optionality of core gas assets• East Texas, Mississippi, Granite Wash and Appalachia – largely HBP

Improve liquidity and financial position• Fully‐funded 2012 CAPEX plan, looking to make a 1H12 asset sale to boost liquidity

Communicate story: stress attractive valuation, leverage to oil and liquids, and retained exposure to gas price recovery• Undervalued on most metrics, despite solid operations and cash flow growth

• Change perception of PVA as a gas‐weighted producer to that of an oil & liquids producer

• Common dividend yield currently about 4.6% – attractive relative to other small E&P firms who invariably pay zero dividends

What is Our Response?Continued Momentum Towards Oil and NGL, Higher Revenues and Margins

8

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

Core Operating Regions

Note: Based on 2/22/12 operational update; see Appendix

2011 Proved Reserves: 883 Bcfe

2012E CAPEX: $300MM ‐ $325MM~85% Eagle Ford / ~30% Less than 2011

2012E Production: 40.0‐43.0 Bcfe~42% Oil & Liquids; ~50% in 4Q12E

Oil / Liquids

Wet Gas 

Dry Gas

2012E Production: 41.5 Bcfe

9

The Most Economic Eagle Ford Shale Wells are in the Volatile Oil & Condensate Rich Gas Windows

Eagle Ford Shale

• 31,400 (≥23,100 net) acres in Gonzales and Lavaca Counties, TX1

– Operator in Gonzales with 83% WI– Operator in Lavaca with at least a 57%WI1

– Avg. IP/30‐day rates of 1,025/675 BOEPD– Type curve EUR of ~400 MBOE2

– 89% oil, 5% NGLs and 5% gas, post processing– 4Q11 D&C costs: estimated $8.0MM per well– Reduced proppant costs and stage sizes– Avg. spud‐to‐TD / spud‐to‐sales: 22/54 days– Initial positive down‐spacing test of 3‐well pad

• Up to ~150 remaining drilling locations1

– 35 wells producing ~10,000 BOEPD (~6,300 BOEPD, net); 3 wells completing  & 1 well WOC

– Excludes any potential Austin Chalk locations• Rigs, infrastructure in place

– Dedicated rigs and fracturing crew– Net oil price at $8‐10/barrel premium to WTI– Gas gathering and processing in place

Gonzales

Lavaca

DeWitt

Victoria

Goliad

BeeLive OakMcMullen

Wilson

Atascosa

Karnes

Bexar

San Antonio

Volatile Oil

CondensateRich Gas

Acreage Valuations Have Increased 

Significantly in Recent EFS Transactions

Texas

Premier Shale Oil & Liquids Play

1 – Includes approximately 13,500 (8,025 net) acres and up to 40 potential locations to be earned in the recently announced AMI in Lavaca Co.2 – Internally generated type curve based on production history of wells drilled to date by PVA

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GonzalesCounty

LavacaCounty

Volatile Oil Window

PVA Well Name IP RatesGardner 1H 1,247 BOEPDHawn Holt 9H 1,877 BOEPDHawn Holt 10H 1,188 BOEPDHawn Holt 11H 1,190 BOEPDHawn Holt 12H 1,495 BOEPDHawn Holt 13H 1,399 BOEPDHawn Holt 15H 1,298 BOEPDMunson Ranch 1H 1,921 BOEPDMunson Ranch 3H 1,538 BOEPDMunson Ranch 4H 1,416 BOEPDMunson Ranch 6H 1,808 BOEPDRock Creek Ranch 1H 1,257 BOEPDSchaefer 3H 1,129 BOEPDMunson Ranch 5H 1,164 BOEPDD. Foreman 1H 1,202 BOEPD

Other Operators IP RatesMHR – Oryx Hunter 1H 2,044 BOEPDMHR – Kudu Hunter 1H 1,590 BOEPDMHR – Southern Hunter 1H 1,321 BOEPDMHR – Furrh 2H 1,275 BOEPDMHR – Snipe Hunter 1H 2,033 BOEPDMHR – Leopard Hunter 1H 1,333 BOEPDEOG – King Fehner Unit 1.4 – 1.7 MBOEPDEOG – Kerner Carson Unit 1.8 – 2.6 MBOEPDEOG – Hill Unit 1.6 – 2.0 MBOEPDEOG – Meyer Unit 1.9 – 3.4 MBOEPDEOG – Mitchell Unit 3.3 – 3.6 MBOEPDEOG – Central Gonzales avg. 1,465 BOEPD

EOG

MHR

Premier Acreage Position in Volatile Oil Window; Lavaca AMI Provides Additional Upside

Eagle Ford Shale

PVA’s Eagle Ford Acreage and Potential is Well‐Positioned Based on Overall Excellent 

Industry Results in Area

Notable PVA & Industry Results

1 – Includes approximately 13,500 (8,025 net) acres and up to 40 locations to be earned in the recently announced AMI in Lavaca Co.Note: Industry results based on peers’ investor presentations  and reported IP wellhead rates (pre‐processing);  production “windows” are PVA’s approximation

PVA AcreagePVA AMI with “Major”13‐D Seismic SurveyNotable PVA ResultsNotable Industry Results

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3Q11 4Q11

$ Millions

2H11 Drilling & Completion Costs

Average Total Well Cost Average Completion Cost

11 Wells 13 Wells

• During 2011 and into early 2012, we have quickly ramped up the Eagle Ford Shale• We also reduced our average well cost during the second half of 2011 which, combined with strong oil prices, has contributed to increased rates of return and margins

• The cost decline is due primarily to drilling efficiencies and altered completion design

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1Q11 2Q11 3Q11 4Q11 Jan 2012x 2.9

MBO

E

2011‐2012 Sales Volumes by Commodity

Net Oil Sales Net NGL Sales Net Gas Sales

Positive Trends: Volumes Up, Costs Down

Eagle Ford Shale

* January 2012 production multiplied by 91/31 or 2.9x

*

12

• Current type curve EUR of ~400 MBOE; previously ~280 MBOE• Assuming $8.0 MM well costs, the pre‐tax rate of return for our average Eagle Ford well is approximately 50% at $100 flat oil, with $6MM of NPV (BTAX)

• Typical completion consists of 15‐16 stages over 4,000’ lateral• Efforts will continue to drive down drilling and completion costs

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0 6 12 18 24 30 36

BOEP

D

Production Month

Eagle Ford Shale ‐ Gonzales Type Curve

  Current Type Curve (~400 MBOE)  Old (Exponential) Type Curve (~280 MBOE)

Gonzales Type Curve Supported by Actual Wells Results

Eagle Ford Shale

Note: Internally generated type curve based on production history of wells drilled to date by PVA

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• Diversified and valuable portfolio of high‐quality assets

• Track record of low‐cost, high‐return operations

• Drilling and acquisitions focused on high return play types

• Successful transition from dry gas to oil and liquids

• Ample supply of economic drilling locations

• Retained optionality of natural gas assets

• Compelling value proposition

Why PVA?Investment Highlights

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Appendix

High‐Margin, Liquid‐Rich Reserves and Production

Mid‐Continent: Liquids‐Rich Play Types

Anadarko Basin• Positioning

– CHK development drilling JV• ~10,000 net acres in Washita Co.• operate about one‐third; ~28% WI

– ~40,000 net acres in other exploratory plays• Viola Lime test in 1H12 (oily)

• Reserve Characteristics / Geology– Granite Wash: 48% liquids; attractive IRRs– Historical EURs > 5.0 Bcfe; assuming 4.0 Bcfe 

for remaining wells– $1.66 PV‐10 breakeven gas price ($90 per 

barrel oil price)• 2012 Activity

– Up to 7 (2.3 net) Granite Wash wells and       1 (0.5 net) Viola Lime test well

– Granite Wash non‐operated drilling– Up to $20‐25MM of CAPEX (~8% of total)

Note: Based on 2/22/12 operational update16

$98.53 $99.79  $99.59  $99.59 

$96.65  $96.53  $95.90  $95.62 

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0

500

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1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13

Barrels p

er Day

Crude Oil Hedges1Swaps and Collars

Weighted Avg. Floors and Sw

aps  ($/Bbl.)

Weighted Average Floor /Swap Price by Quarter

Forecast Price by Quarter

Crude Oil HedgesProtecting our Capital Budget and Well Economics

• We have recently expanded our crude oil hedges given our increased oil drilling activity• Our oil hedges thus far are equal to or greater than our forecasted oil price for 2012‐2013

1 – As of 2/23/1217

$5.70 

$5.31  $5.31 $5.10 

$2.74 $2.87 

$3.03 

$3.36 

$2

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$6

0

10

20

30

40

1Q12 2Q12 3Q12 4Q12

MMBtu pe

r Day (0

00s)

Natural Gas Hedges1Swaps and Collars

Weighted Avg. Floors and Sw

aps  ($/MMBtu)

Weighted Average Floor /Swap Price by Quarter

Forecast Price by Quarter

Natural Gas Hedges

1 – As of 2/23/12

• Our 2012 natural gas hedges have locked in prices well above the forecast• Nevertheless, we are not drilling dry gas plays as the commodity remain oversupplied

Protecting our Cash Flows During Depressed Gas Price Environment

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2012 Guidance TableAs of February 22, 2011

Dollars in millions, except unit data 4th Quarter Full Year2011 2011

Production:Natural gas (Bcf)                   6.8                  33.4          23.5  ‐          24.4 Crude oil (MBbls)                 450               1,283       2,000  ‐       2,275 NGLs (MBbls)                  212                   907           750  ‐           825 Equivalent production (Bcfe)                10.7                  46.6          40.0  ‐          43.0 Equivalent daily production (MMcfe per day)             116.7               127.5       109.3  ‐       117.5 Equivalent production (MBOE)             1,789               7,759       6,667  ‐       7,167 Equivalent daily production (MBOE per day)                19.4                  21.3          18.2  ‐          19.6 Percent crude oil and NGLs 37.0% 28.2% 41.3% ‐  43.3%

Production revenues:Natural gas $                23.4               137.1          66.5  ‐          69.1 Crude oil  $                44.3               119.6       189.0  ‐       215.0 NGLs  $                  9.6                  43.4          32.0  ‐          35.2 Total product revenues $                77.4               300.0       287.5  ‐       319.2 Total product revenues ($ per Mcfe) $                7.20                  6.45          7.19  ‐          7.42 Total product revenues ($ per BOE) $             43.23               38.67       43.12  ‐       44.54 Percent crude oil and NGLs 69.7% 54.3% 76.9% ‐  78.4%

Operating expenses:  Lease operating ($ per Mcfe) $                0.70                  0.79          0.80  ‐          0.85   Lease operating ($ per BOE) $                4.17                  4.77          4.80  ‐          5.10   Gathering, processing and transportation costs ($ per Mcfe) $                0.36                  0.33          0.28  ‐          0.33   Gathering, processing and transportation costs ($ per BOE) $                2.18                  1.95          1.68  ‐          1.98   Production and ad valorem taxes (percent of oil and gas revenues) 3.1% 4.6% 4.0% ‐  4.5%  General and administrative:Recurring general and administrative $                  6.9                  38.5          39.0  ‐          41.0 Share‐based compensation $                  1.8                    7.4            6.5  ‐            7.0 Restructuring $                  0.7                    2.4 Total reported G&A $                  9.4                  48.3          45.5  ‐          48.0 

Exploration expense $                10.7                  78.9          43.0  ‐          46.0   Unproved property amortization $                  8.5                  42.0          36.0  ‐          38.0 

Depreciation, depletion and amortization ($ per Mcfe) $                4.59                  3.49          4.75  ‐          5.25 Depreciation, depletion and amortization ($ per BOE) $             27.56               20.95       28.50  ‐       31.50 

Adjusted EBITDAX $                62.2               219.5       200.0  ‐       240.0 Net cash provided by operating activities $                41.6               144.7       175.0  ‐       205.0 

Capital expenditures:Development drilling  $                99.9               307.8       240.0  ‐       245.0 Exploratory drilling $                10.9                  64.1          30.0  ‐          35.0 Pipeline, gathering, facilities $                  6.2                  12.5            5.0  ‐          10.0 Seismic $                  2.2                  11.2            5.0  ‐          10.0 Lease acquisitions, field projects and other $                  3.6                  50.0          20.0  ‐          25.0   Total oil and gas capital expenditures $             122.8               445.6       300.0  ‐       325.0 

Full‐Year2012 Guidance

19

Non‐GAAP ReconciliationsAdjusted EBITDAX

2006 2007 2008 2009 2010 2011Adjusted EBITDAX

Net income (loss) from continuing operations $       44.2  $      26.5  $      93.6  $  (130.9) $    (65.3) $  (132.9)

Add: Income tax expense (benefit)          50.0          30.5          55.6        (85.9) (42.9)      (88.2)     

Add: Interest expense            6.0          20.1          24.6          44.2  53.7       56.2      

Add: Depreciation, depletion and amortization          56.7          88.0        135.7  154.4     134.7     162.5    

Add: Exploration          34.3          28.6          42.4  57.8       49.6       78.9      

Add: Share‐based compensation expense            1.1            1.6            6.0  9.1         7.8         7.4        

Add/Less: Derivatives (income) expense included in net income         (30.7)           2.0        (29.7) (31.6)      (41.9)      (15.7)     

Add/Less: Cash receipts (payments) to settle derivatives          10.5          14.1          (7.6)         58.1          32.8          27.4 

Add: Impairments            8.5            2.6          20.0  106.4     46.0       104.7    Add/Less: Net loss (gain) on sale of assets, other                ‐          (12.6)        (33.2)          (2.0)          (1.2)          19.1 

Adjusted EBITDAX  $     180.6   $    201.5   $    307.4   $    179.7   $    173.3   $    219.5 

Year ended December 31,

dollars in millions

20

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