41st Annual Howard Weil Energy ConferenceInvestor PresentationMarch 20, 2013

NYSE: PVA

Forward-Looking Statements, Oil and Gas Reserves and Definitions

1

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 oil, natural gas liquids and natural gas; our ability to develop, explore for, acquire and replace oil andgas reserves and sustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; anyimpairments, write-downs or write-offs of our reserves or assets; the projected demand for and supply of oil, natural gas liquids and natural gas; reductions in theborrowing base under our revolving credit facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequatepipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; theuncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and gasreserves; drilling and operating risks; our ability to compete effectively against other independent and major oil and natural gas companies; our ability to successfullymonetize select assets and repay our debt; leasehold terms expiring before production can be established; environmental liabilities that are not covered by an effectiveindemnity or insurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintainadequate financial liquidity and to access adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including forcemajeure events; our ability to retain or attract senior management and key technical employees; counterparty risk related to their ability to meet their futureobligations; changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relatingto general domestic and international economic and political conditions; and other risks set forth in our filings with the 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. Many of the factors that willdetermine our future results are beyond the ability of management to control or predict. 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 otherforward-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, 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 quantities of oil and gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to beeconomically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulationbefore the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether theestimate is a deterministic estimate or probabilistic estimate. Probable reserves are those additional reserves that are less certain to be recovered than provedreserves, but which are as likely than not to be recoverable (there should be at least a 50% probability that the quantities actually recovered will equal or exceed theproved plus probable reserve estimates). Possible reserves are those additional reserves that are less certain to be recoverable than probable reserves (there should beat least a 10% probability that the total quantities actually recovered will equal or exceed the proved plus probable plus possible reserve estimates). “3P” reserves referto 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 productionas of that date.

PVA Overview

• Small-cap domestic onshore E&P company • The past two years have been transformational, as we have diversified our portfolio towards oil and liquids• Very active in the Eagle Ford Shale oil play with excellent results to date• HBP natural gas reserves in East Texas, the Mid-Continent and Mississippi

• Executing a strategy of growth in oil and NGL rich plays• Successful drilling results in the Eagle Ford Shale – 69 wells on-line (54 in Gonzales Co. and 15 in Lavaca Co.)• Adding to Eagle Ford drilling inventory

– Successful exploratory results to date in Lavaca County– Continued lease acquisition activity– Approximately 300 drilling locations remaining currently

• Strategy has resulted in significant growth in EBITDAX and cash operating margins• Proved reserves were approximately 40% oil and NGLs at YE12 (24% at YE11)• Over 60% of 2013 production is expected to be oil and NGLs

– Over 85% of 2013 product revenues expected to be oil and NGLs

• Focused on improving liquidity• Cash plus revolver availability of $316MM at YE12• Leverage ratio of ~2.4x at YE12• 69% of 2013E (midpoint) oil production hedged at weighted average floor/swap price of $96.67 per barrel (WTI)• 68% of 2013E (midpoint) gas production hedged at weighted average floor/swap price of $3.77 per MMBtu (HH)

2

• “Gas-to-Oil” transition• Grew overall oil/NGL production 253% to 8,673 Bbls/day from 2Q10 to 4Q12

− Up 21% from 7,194 Bbls/day in 4Q11− Oil / NGLs contributed 56% of production and 83% of product revenues in 4Q12− Daily oil production alone grew 24% from 4Q11 to 4Q12

• Eagle Ford position built from initial 6,800 net acres in August 2010 to 33,000 net acres currently(1)

− Up to 366 total well locations, with up to approximately 300 remaining drilling locations− Includes 160 down-spaced locations

• Expansion of oil and liquids reserves and drilling inventory• Continued leasing and expansion of Eagle Ford• Exploration of other oil prospects

− New ventures team is assessing new high impact oil resource plays

• Growth in oil and liquids production and cash flows• Eagle Ford drilling emphasis in 2013, with approximately 88% of CAPEX expected in the play• 38 (28.8 net) Eagle Ford wells in 2013 - 22 (15.2 net) in Gonzales County and 16 (13.6 net) in Lavaca County• Continued focus on optimizing drilling and completion costs in the Eagle Ford

• Retain substantial gas assets for eventual price recovery• Haynesville Shale, Cotton Valley and Mississippi Selma Chalk are primarily HBP

Business Strategy

3(1) Net acreage in Lavaca County is expected to increase due to non-consents by our partner on initial wells in 17 drilling units.

$0

$23

$45

$68

$90

Quarterly Revenue by CommodityPre-Hedging; $MM

Oil NGLs Gas

0

4

8

12

16

20

Pro Forma Production by CommodityMBOE per day (1 BOE = 6 Mcf)

Oil NGLs Base NG Shale NG

Value Has Shifted to Oil

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 production excludes contributions from South Texas and South Louisiana assets sold in January 2010, Arkoma Basin assets sold in August 2011 and Appalachian assets sold in July 2012. Revenues are actual amounts received, prior to the impact of derivatives.

56%

44%

• In mid-2010, PVA implemented a strategy to transition from dry gas to oil and liquids

• Since then, the decrease in gas prices and increase in oil and liquids prices has shifted the market from a “6:1” to a “20:1” liquids-to-gas price environment (25:1 for oil)

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

83%

17%

4

$0

$6

$12

$18

$24

$30

$36

$42

$48

$0

$10

$20

$30

$40

$50

$60

$70

$80

1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12

$ per BOE$

Mill

ions

Adjusted EBITDAX ($MM) Adjusted EBITDAX Margin per BOE

Strong Margins vs. Peers

• EBITDAX has increased significantly since mid-2010 when we shifted our strategy to oil and NGLs

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

• Eagle Ford cash margin was $79 per BOE in 4Q12(1)

Quarterly Adjusted EBITDAX and EBITDAX Margin per BOE Comparative EBITDAX Margins (4Q2012 EBITDAX / BOE)(2)

5Source: Company filings.(1) Excludes regional and corporate G&A expenses.(2) PVA 4Q2012 EBITDAX of $62.3MM per its earnings release. See Appendix for PVA’s reconciliation of EBITDAX. EBITDAX for peers

calculated as total revenues less lease operating expenses and cash G&A unless otherwise disclosed by the peer company.

$17.40

$24.96

$34.11 $39.29 $4.56

$4.74

$4.13

$4.68

$1.80

$1.98

$2.08

$1.78

$1.74

$1.74

$3.05

$1.91

$6.42

$5.28

$6.88

$5.82

FY 2010 FY 2011 3Q 2012 4Q 2012Cash Margin LOE

G&P and transportation Production taxes

Cash G&A (excludes share-based compensation)

$31.92

$38.70

$50.25$53.48

18%28%

52% 56%

82%72%

48% 44%

FY 2010 FY 2011 3Q 2012 4Q 2012Oil & Condensate Natural Gas

Production Mix and Operating Margins

Production Mix Over Time Cash Margin Over Time ($/BOE)

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

Realized Price

Cash Margin

6

Note: Based on 1/29/13 operational release and YE12 reserve report prepared by Wright & Company, Inc.

Asset OverviewEmerging Oil and Liquids-Rich Plays Plus “Option” in Significant Gas Plays

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Oil / Liquids

Wet Gas

Dry Gas

TX

OK

PA

MS

Selma ChalkYE12 Proved reserves: 17.6 MMBOE

% Gas: 100%% PDP: 54%

2012 Production: 847 MBOE

Mid-ContinentYE12 Proved reserves: 12.4 MMBOE

% Oil/NGLs: 47%% PDP: 79%

2012 Production: 1,211 MBOE

MarcellusYE12 Proved reserves: 0.5 MMBOE

% Gas: 100%% PDP: 23%

2012 Production: 43 MBOE

HaynesvilleYE12 Proved reserves: 17.2 MMBOE

% Gas: 86%% PDP: 26%

2012 Production: 454 MBOE

Cotton ValleyYE12 Proved reserves: 39.6 MMBOE

% Oil/NGLs: 34%% PDP: 34%

2012 Production: 882 MBOE

Eagle FordYE12 Proved reserves: 26.2 MMBOE

% Oil/NGLs: 90%% PDP: 37%

2012 Production: 2,334 MBOE

Penn VirginiaYE12 Proved reserves: 113.5 MMBOE

% Oil/NGLs: 40%% PDP: 41%

2012 Production: 5,771 MBOE

• 41,900 gross (≥33,000 net) acres in Gonzales and Lavaca Counties, TX(1)

• Operator in Gonzales with 83% WI• Operator in Lavaca with a ~94% WI(1)

• Avg. IP/30-day rates of 972/651 BOEPD(2)

• Gonzales type curve EUR of ≥400 MBOE(2)

• Lavaca type curve of EUR of ≥500 MBOE(2)

• Proved reserves increased from 10 MMBOE at year-end 2011 to 26 MMBOE at year-end 2012• 3P reserves increased from 25 MMBOE at year-end 2011 to 71 MMBOE at year-end 2012• 80-85% oil, 5-10% NGLs and 5-10% gas, post processing; crude oil is 48o or less API gravity

− Weighted average oil gravity – 44o

• Reduced proppant and chemical costs• 69 wells producing (15 in Lavaca County)• Objective is to lower well costs by 10-15% in 2013

• Up to ~300 remaining drilling locations• Initial positive down-spacing test of 3-well pad• Includes 160 down-spaced locations

• Rigs, infrastructure in place• Dedicated rigs and frac crew• Gas gathering and processing in place• Receiving premium LLS base pricing

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Eagle Ford Shale

(1) Net acreage in Lavaca County is expected to increase due to non-consents by our partner on initial wells in 17 drilling units.(2) Based on 1/29/13 operational release and YE12 reserve report prepared by Wright & Company, Inc.

Summary of PVA’s Positioning

(1) Based on latest company presentations, as well as industry publications. Some industry publication information may be out of date.

Eagle Ford Shale

9

Operators in Eastern Volatile Oil and Condensate Rich Gas Windows(1)

Gonzales

Lavaca

Victoria

Goliad

BeeLive OakMcMullen

Wilson

Atascosa

Bexar

San Antonio

Volatile Oil

CondensateRich Gas

Texas

PVABHPCHKCOGCOPCRK

CRZOEOGFST

HuntMHRMROMURNFXPXDPXPSFYSTOTLM

EFS Operators

Eagle Ford ShalePremier Acreage Position in Volatile Oil Window

Notable PVA Results

Note: Wellhead rates (pre-processing); production “windows” are PVA’s approximation.

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PVA Well NameIP Rates(BOEPD) PVA Well Name

IP Rates(BOEPD) PVA Well Name

IP Rates(BOEPD) PVA Well Name

IP Rates(BOEPD) PVA Well Name

IP Rates(BOEPD)

Gardner 1H 1,247 Hawn Holt 13H 1,399 Munson Ranch 6H 1,808 Henning 1H 1,115 McCreary 1H (Lavaca) 1,036

Hawn Holt 9H 1,847 Hawn Holt 15H 1,298 Rock Creek Ranch 1H 1,257 Effenberger 1H (Lavaca) 922 Matias 1H (Lavaca) 1,013

Hawn Holt 10H 1,188 Munson Ranch 1H 1,921 Schaefer 3H 1,129 Schacherl 1H (Lavaca) 1,277 Arledge Ranch 1H 1,117

Hawn Holt 11H 1,190 Munson Ranch 3H 1,538 Munson Ranch 5H 1,164 Rock Creek Ranch 10H 1,036 Freytag 1H (Lavaca) 1,195

Hawn Holt 12H 1,495 Munson Ranch 4H 1,416 D. Foreman 1H 1,202 Henning 2H 1,002 Technik 1H (Lavaca) 1,445

Eagle Ford Shale Wellhead Production – Gonzales Co.

Eagle Ford Shale

11

Detailed Map of Primary Eagle Ford Shale Operating Area, With New Lavaca County Wells

0 10,000

FEET

Cortez

RockCreek Ranch

CannonadeRanch

Shiner

GonzalesCounty

LavacaCounty

Energy Transfer Pipelines

McCreary #1H

Schacherl #1H Vana #1H

Effen-berger

#1H

Sralla#1H

Pavlicek #1H

Smith #1H

Leal #1H

Matias #1H

Freytag #1HBarazza #1H

Rabb #1H

Kleihege #1H

Penn Virginia Pipelines

Technik #1H

Targac#1H

Eagle Ford ShaleStrong Early Results in Lavaca County

Well Name

WellheadIP Rates(BOEPD)

Post-Processing

IP Rates(BOEPD)(1)

30-Day WellheadIP Rates(BOEPD)

30 –Day Post-Processing

IP Rates(BOEPD) (1)

No. ofFrac

Stages

InitialChoke

Size

LateralLength(feet)

Post-Proc. CumulativeProduction(MBOE) (1)

Avg. DailyPost-Proc.

Cum. Prod. / Days Online(MBOEPD)(1)

Effenberger 1H 922 954 778 816 20 12/64” 4,950 131.9 395 / 334

Vana 1H 709 731 498 526 13 16/64” 3,192 66.4 201 / 330

Schacherl 1H 1,277 1,329 709 757 22 14/64” 5,453 113.4 392 / 289

Sralla 1H 827 851 698 725 18 12/64” 4,453 97.2 390 / 249

McCreary 1H 1,036 1,112 709 767 18 13/64” 4,453 73.5 340 / 216

Pavlicek 1H 663 700 450 490 20 14/64” 4,870 25.9 142 / 183

Smith 1H 943 1,032 629 689 18 16/64” 4,459 62.4 383 / 163

Matias 1H 1,013 1,061 652 712 20 12/64” 4,453 58.1 480 / 121

Leal 1H 832 921 725 814 17 13/64” 4,201 73.1 537 / 136

Freytag 1H 1,195 1,247 689 735 25 14/64” 4,952 47.5 461 / 103

Kleihege 1H 629 690 515 563 26 16/64” 5,155 42.7 459 / 93

Raab 1H 1,046 1,146 832 913 22 17/64” 5,450 52.0 666 / 78

Barraza 1H 680 725 474 509 16 15/64” 3,952 26.9 414 / 65

Technik 1H 1,445 1,575 789 869 18 25/64” 4,452 29.3 793 / 37

Targac 1H 865 919 520 566 16 14/64” 4,300 23.1 525 / 44

Averages 939 999 644 697 19.3 15/64” 4,583 61.6 439 / 163

Adj. Averages(2) 978 1,043 670 726 19.7 15/64” 4,668 63.9 480 / 148

• We currently have 15 Lavaca wells on line

• The average wellhead IP and 30-day rates are 939 and 644 BOEPD

• Excluding two wells with issues, the averages were 978 and 670 BOEPD(2)

• Including estimated post-processing NGL barrels, net of gas shrink, the averages were 1,043 and 726 BOEPD(1)

• Have tested most of our acreage at this point and are confident in the prospectivity of the total Lavaca County acreage

• Our “major” partner has elected to go non-consent on the WI in the last 10 wells, but will retain an overriding royalty interest

• Currently believe well quality and reserves are higher on Lavaca County acreage due to increased pressure gradients and ability to drill longer laterals

(1) Assumes 124.45 barrels of NGLs per MMcf of gas. Assume s 32.6% fuel and processing shrink for wet gas.(2) Excludes the Vana 1H (short lateral) and Pavlicek 1H (completion issues) from the averages.

24 82

300 344

460 502 490 508

23

29

34

52 50 70

20

25

31

42 42

54

1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12Oil and Condensate NGLs Natural Gas

• During 2011 and into early 2012, we quickly ramped up the Eagle Ford Shale, and expect to increase production again during 2013

• Approximately 91% of sales volumes are liquids - primarily crude oil• Oil is sold into the Gulf Coast LLS market through multiple purchasers at premium pricing to WTI

Eagle Ford ShalePositive Trend: Volumes Up

2011-2012 Net Quarterly Sales Volumes by Commodity (MBOE)

13

Gonzales County Lavaca County(1)

• Assumptions• Longer lateral lengths in 2013 vs. PUD assumption• 590 MBOE EUR type curve (80 Bbls of oil per foot)• Drilling and completion (D&C) costs of $10.1MM

• Key takeaways• 37%-52% IRRs and BTAX PV-10 of $6.1 - $8.2MM per

well assuming a flat $90 per barrel WTI oil price• BTAX PV-10 breakeven WTI oil pricing of $47 to $57

per barrel

(1) Based on YE12 PUDs, excluding short-length lateral wells, applied to longer length laterals in 2013 program.

• Assumptions• Longer lateral lengths in 2013 vs. PUD assumption• 460 MBOE EUR type curve (80 Bbls of oil per foot)• Drilling and completion (D&C) costs of $9.1MM

• Key takeaways• 40%-52% IRRs and BTAX PV-10 of $5.6 - $7.4MM per

well assuming a flat $90 per barrel WTI oil price• BTAX PV-10 breakeven WTI oil pricing of $47 to $57

per barrel

14

Compelling Economics & Value at Varying Oil Prices

Eagle Ford Shale

Eagle Ford ShaleMulti-Year Drilling Inventory

• Due to acreage acquisitions and leasing efforts over the past two years, we have expanded our acreage position to 41,900 gross (33,000 net) acres primarily in the volatile oil window(1)

• We also have a multi-year inventory of up to 297 additional drilling locations

• Down-spacing has added 160 potential locations to our inventory

• Locations will vary over time in terms of lateral length, frac stages, spacing and geology

• Recent successful wells in the southern and eastern portions of our Lavaca acreage have further “de-risked” our inventory

• Unitizations with other industry participants and continued leasing are expected to yield additional locations

15(1) Net acreage in Lavaca County is expected to increase due to non-consents by our partner on initial wells in 17 drilling units.

AreaProducing

WellsRemaining Locations

Total WellLocations

Gross Acreage

Net Acreage(1)

Acres / Location

Gonzales 54 190 244 26,209 21,236 107

Lavaca 15 107 122 15,670 11,751 128

Totals 69 297 366 41,879 32,987 114

(1) Median gross EUR for all PUD locations.

• Total inventory of up to 790 gross undrilled locations (609 horizontal locations)• Up to 349 gross horizontal drilling locations in the Eagle Ford and Granite Wash• Significant upside in inventory of “gassy” locations

Pro Forma PVA Has a Healthy Inventory of Drilling Locations

16

PlayGross Undrilled

LocationsAverage Working

InterestGross EUR

(MBOE/Well)(1)

Eagle Ford (Gonzales) 190 83% 394

Eagle Ford (Lavaca) 107 94% 513

Granite Wash 52 18% 809

Cotton Valley 78 71% 903

Haynesville 78 77% 869

Cotton Valley (vertical) 181 71% 172

Selma Chalk 104 96% 302

Totals 790

Eagle Ford Shale

Financial Strategy

Crude Oil Hedges (Swaps and Collars)(1)

Natural Gas Hedges (Swaps and Collars) (1)

• Penn Virginia employs a conservative financial strategy• Capital spending driven primarily by rates of return across all

operating areas

• Capital budget focused on high return, oil / liquids areas

• Margins and EBITDAX projected to increase

• Maintain conservative balance sheet

• Continue to increase senior credit facility borrowing base through reserve additions from organic growth to maximize liquidity

• Target net debt / EBITDAX of less than 3.0x by year-end 2013 (~2.4x at YE12)

• Maintain conservative financial ratios with recent common and preferred issuances, along with cash flow growth and asset sales

• Maintain sufficient liquidity to provide capital to continue drilling and our transition to oil

• Maintain an active oil-focused hedging program to support economic returns and ensure strong coverage metrics

• Hedges in place to protect cash flow and well economics

• Plans to layer in additional oil and gas hedges as prices permit

(1) As of 3/13/13.17

1.8x

2.1x

2.4x

2.7x

3.0x

3.3x

3.6x

$0

$100

$200

$300

$400

$500

$600

4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12

Financial Liquidity and Leverage

Cash Revolver Availability Excess Debt Capacity Debt-to-EBITDAX

Financial Liquidity and Leverage

• Penn Virginia has taken steps recently to ensure that its financial liquidity is more than sufficient to fund upcoming operations during 2012 and 2013• Several liquidity events during 2012 have increased financial liquidity from less than $400MM

to over $550MM• In addition, financial leverage has decreased markedly from over 3.0x EBITDAX to 2.4 EBITDAX

at year-end 2012

18Note: dollars in millions; excess debt capacity assumes leverage up to 4.5x EBITDAX

• Strategic balance between oil / liquids and natural gas

• Strengthened balance sheet and liquidity

• Core position in the volatile oil window of the Eagle Ford Shale

• Multi-year inventory of attractive drilling opportunities

• Optionality of natural gas assets has been retained

Investment Highlights

19

Appendix

20

Attractive Valuation Relative to Peers

Notes: Sources: Company filings, press releases, First Call; market data as of 3/14/13. PV-10 (non-GAAP) as of 12/31/12 using 2012 SEC pricing methodology.

21

22

2013 Guidance TableAs of February 20, 2013

($ in millions, except per unit data)1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Full-Year

2012 2012 2012 2012 2012Production:

Crude oil (MBbls) 549 572 573 559 2,252 2,775 - 3,075 NGLs (MBbls) 215 227 202 239 884 730 - 820 Natural gas (MMcf) 6,294 5,859 4,371 3,737 20,262 13,000 - 13,650 Equivalent production (MBOE) 1,812 1,775 1,504 1,421 6,513 5,672 - 6,170

Equivalent daily production (MBOE per day) 19,916 19,511 16,348 15,444 17,794 15,539 - 16,904 Percent crude oil and NGLs 42.1% 45.0% 51.6% 56.2% 48.1% 59.9% - 64.9%

Production revenues:Crude oil $ 58.7 58.4 57.0 55.5 229.6 265.0 - 293.5 NGLs $ 9.1 7.6 6.7 7.8 31.1 21.5 - 24.5 Natural gas $ 14.9 10.3 11.9 12.8 49.9 43.5 - 45.5 Total product revenues $ 82.7 76.2 75.6 76.0 310.5 330.0 - 363.5

Total product revenues ($ per BOE) $ 45.62 42.94 50.25 50.25 50.25 58.18 - 58.91 Percent crude oil and NGLs 82.0% 86.5% 84.2% 83.2% 83.9% 86.2% - 88.0%

Operating expenses:Lease operating ($ per BOE) $ 5.04 5.22 4.13 4.68 4.80 4.60 - 5.00 Gathering, processing and transportation costs ($ per BOE) $ 2.29 2.47 2.08 1.78 2.18 1.70 - 1.90 Production and ad valorem taxes (percent of oil and gas revenues) 4.3% -0.3% 6.1% 3.6% 3.4% 6.3% - 6.9%General and administrative:

Recurring general and administrative $ 10.5 10.6 8.9 7.5 37.5 39.5 - 40.5 Share-based compensation $ 1.6 1.3 1.3 2.8 7.1 3.0 - 4.0 Restructuring $ - (0.1) 1.4 0.0 1.3

Total reported G&A $ 12.1 11.7 11.6 10.4 45.9 42.5 - 44.5 Exploration: $ 8.0 9.4 9.3 7.4 34.1 28.0 - 30.0

Unproved property amortization $ 8.2 8.3 8.3 7.9 32.6 21.0 - 22.0 Depreciation, depletion and amortization ($ per BOE) $ 28.02 29.14 32.80 38.32 31.68 36.00 - 39.00

Adjusted EBITDAX $ 64.2 60.0 61.2 62.3 247.6 234.5 - 280.0

Capital expenditures:Drilling and completion $ 82.6 79.8 73.1 99.4 334.9 310.0 - 345.0 Pipeline, gathering, facilities $ 3.9 4.4 5.0 4.9 18.2 17.0 - 18.0 Seismic $ (0.4) 0.7 0.1 0.4 0.8 5.0 - 7.0 Lease acquisitions, field projects and other $ 4.3 6.6 6.4 13.1 30.4 28.0 - 30.0

Total oil and gas capital expenditures $ 90.4 91.5 84.6 117.8 384.4 360.0 - 400.0

2013 GuidanceFull-Year

Non-GAAP ReconciliationAdjusted EBITDAX

23

2008 2009 2010 2011 2012Adjusted EBITDAX

Net income (loss) from continuing operations $ 93.6 $ (130.9) $ (65.3) $ (132.9) $ (104.6)

Add: Income tax expense (benefit) 55.6 (85.9) (42.9) (88.2) (68.7)

Add: Interest expense 24.6 44.2 53.7 56.2 59.3

Add: Depreciation, depletion and amortization 135.7 154.4 134.7 162.5 206.3

Add: Exploration 42.4 57.8 49.6 78.9 34.1

Add: Share-based compensation expense 6.0 9.1 7.8 7.4 6.3

Add/Less: Derivatives (income) expense included in net income (29.7) (31.6) (41.9) (15.7) (36.2)

Add/Less: Cash receipts (payments) to settle derivatives 29.7 (5.8) 68.5 27.4 29.7

Add/Less: Loss on firm transportation commitment - - - - 17.3

Add: Impairments 20.0 106.4 46.0 104.7 104.5 Add/Less: Net loss (gain) on sale of assets, other (33.2) (2.0) (1.2) 22.0 (0.6)

Adjusted EBITDAX $ 344.7 $ 115.7 $ 209.0 $ 222.5 $ 247.6

dollars in millions

Year ended December 31,

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