Investor PresentationNovember 2016– September 25-27, 2017 –

Nasdaq Ticker: PVAC

Johnson Rice 2017 Energy Conference

1

Forward Looking and Cautionary StatementsCertain 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 Section21E of the Securities Exchange Act of 1934, as amended. Words such as “expects,” “guidance,” “highlights,” “will”, “plan”, “intend” and variations of such words or similar expressions are used to identifyforward-looking statements. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-lookingstatements. These risks, uncertainties and contingencies include, but are not limited to, the following: timing, costs and unknown risks related to the pending acquisition and our ability to realize expectedbenefits of the pending acquisition and the risk that the acquisition is not consummated; potential adverse effects of the completed bankruptcy proceedings on our liquidity, results of operations, businessprospects, ability to retain financing and other risks and uncertainties related to our emergence from bankruptcy; our ability to satisfy our short-term and long-term liquidity needs, including our inability togenerate sufficient cash flows from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs; negative events or publicity adversely affecting our ability tomaintain our relationships with our suppliers, service providers, customers, employees, and other third parties; new capital structure and the adoption of fresh start accounting, including the risk thatassumptions and factors used in estimating enterprise value vary significantly from the current estimates in connection with the application of fresh start accounting; plans, objectives, expectations andintentions contained in this presentation that are not historical; our ability to execute our business plan in the current commodity price environment; any decline in and volatility of commodity prices for oil,NGLs, and natural gas; our anticipated production and development results; our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production; our ability to generateprofits 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 andsupply of oil, NGLs and natural gas; our ability to contract for drilling rigs, frac crews, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil andgas 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 towhich actual production differs from that estimated in our proved oil and natural gas reserves; drilling and operating risks; concentration of assets; our ability to compete effectively against other oil and gascompanies; leasehold terms expiring before production can be established and our ability to replace expired leases; costs or results of any strategic initiatives; environmental obligations, results of newdrilling activities, locations and methods, costs and liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of necessary regulatory permits; the effect of commodity andfinancial derivative arrangements; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain or attract senior management and key employees;counterparty risk related to the ability of these parties to meet their future obligations; compliance with and changes in governmental regulations or enforcement practices, especially with respect toenvironmental, health and safety matters; physical, electronic and cybersecurity breaches; litigation that impacts us, our assets or our midstream service providers; uncertainties relating to general domesticand international economic and political conditions; and other risks set forth in our filings with the SEC.

Additional information concerning these and other factors can be found in our press releases and public filings with the SEC. Many of the factors that will determine our future results are beyond the abilityof 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. The statements in thispresentation speak only as of the date of this presentation. 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, except as may be required by applicable law.

Oil and Gas ReservesStatements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Investors are urged to consider closely the disclosure in Penn Virginia’s Annual Reporton Form 10-K for the fiscal year ended December 31, 2016 and subsequent Quarterly Reports on Form 10-Q, which are available on its website at www.pennvirginia.com under Investors – SEC Filings. Youcan also obtain these reports from the SEC’s website at www.sec.gov.

DefinitionsProved reserves are those quantities of oil and gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible from a given dateforward, from known reservoirs, and under existing economic conditions, operating methods and government regulation before the time at which contracts providing the right to operate expire, unlessevidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate. Probable reserves are those additional reserves that are lesscertain to be recovered than proved reserves, 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 be at least a 10% probability that thetotal quantities actually recovered will equal or exceed the proved plus probable plus possible reserve estimates). Estimated ultimate recovery (EUR) is the sum of reserves remaining as of a given date andcumulative production as of that date. EUR is a measure that by its nature is more speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly is lesscertain.

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Penn Virginia Corporation - Company Overview

Houston(HQ)

§ Penn Virginia (NASDAQ:PVAC) – TEV > $600MM(1)

• Independent E&P company focused in “volatile oil window” of Eagle Ford shale with ~57,000 net acres(2) (~93% HBP / >70% oil)

• Substantial inventory of ~525 gross locations (~353 net) (Area 1: ~365 (~214 net); Area 2: ~160 (~139 net)

§ Strong financial performance (2017 Q2 vs Q1)• Product revenues increased 5% to $36.3 million (89% oil)

• Direct operating expenses(3) decreased 6% on per BOE basis

• Adj. EBITDAX(4) of $23.1 million, an increase of almost 15%

• Borrowing base increased over 55% to $200 million

§ Strong operating performance (1)

• Lager 3H (Area 2) well online for 140 days with cumulative production of 176 MBOE (First slick water completion XRL Gen-4)

• Zebra (Area 1) 6H and 7H wells online for 84 days with cumulative production of 117 MBOE (First Gen-5 completion)

§ Strategic acquisition accretive on all measures• Anticipate closing previously announced acquisition of Devon’s

Eagle Ford assets by September 30, 2017

• Increases net acreage by 34% and production by 30%

Focused Eagle Ford Pure Play

1) As of September 22, 2017.2) As of August 7, 2017, including acreage leased in 2017. Excludes net acreage expiring in 2017. 3) Includes lease operating; gathering, processing and transportation; production and ad valorem taxes; and, general and administrative expenses.4) Adj. EBITDAX is a non-GAAP measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based measures appear in the Appendix to this presentation. 5) As of December 31, 2016. PVAC also holds a small position in the Granite Wash play (See Appendix for additional information).

Eagle Ford

Core Net Acreage: ~57,0002 (93% HBP)Drilling Locations: ~525 gross locationsEconomics: ~50% IRR at $50 WTI oil Q2 2017 Production: 864 MBOE (9,498 BOEPD)Proved Reserves: 47.0 MMBOE(5)

Gonzales Office

3

Devon Eagle Ford Acquisition

Pro Forma Asset Map

Transaction Summary• $205 MM acquisition of Devon Energy Corporation’s Eagle Ford assets located primarily in Lavaca County, TX

• Target closing: September 30, 2017; effective date: March 1, 2017

• Purchase price expected to be adjusted downwards by ~$15 MM to reflect net cash flows from effective date to closing, resulting in ~$190 MM net purchase price

• Intend to fund with $150 MM of new committed debt financing and borrowings under credit facility

• Transaction subject to customary purchase price and closing adjustments

Significant Benefits of Acquisition

Increases Core Leasehold Position and Production By Approximately 30%

• Acquiring ~19,600 net acres contiguous to core operations

• Offers potential for extended reach lateral (“XRL”) well inventory with PV10 breakeven pricing of less than $30/Bbl

• Increases net production by ~30%, or ~3,000 BOEPD (~64% oil)

• Accretive under all measures, including earnings, cash flow and net asset value per share

• Acquiring at attractive price of ~$2,900/net acre after reducing for:- Net production value of ~$105 MM ($35,000 per flowing BOEPD)

- ~$15 MM to reflect net cash flows from effective date to closing

- ORRI in non-acquired acreage of ~$8 MM

- Midstream assets valued at ~$20 MM

• Modifying development program by shifting one of PVAC’s drilling rigs to Area 2 predominantly in the acquired acreage, which is expected to have higher returns and where PVAC will have increased working interest and drive 2018 production higher

• Significant upside potential in the upper Eagle Ford and Austin Chalk formations

• ~$40 MM of identified operational synergies

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PVAC Pro Forma

Net Production

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PVAC Pro Forma

Net Acreage

Acre

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PVAC Pro Forma

Net Drilling Inventory

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Transaction and Asset Highlights

• Expands PVAC’s core leasehold position by 34%, or ~19,600 net acres (90% held by production), which includes 42 drilling units (including 16 units, or 35% of total, currently operated by PVAC) and average WI and NRI of ~98% and ~76%, respectively

• Significant de-risked inventory of 91 gross locations (including six in drilling units currently operated by PVAC) targeting the lower Eagle Ford formation

- XRLs are identified for 43 gross (41 net) locations, including 26 gross (25 net) locations with average lateral length of 10,000’ or greater • Net PDP reserves of ~6.3 MMBOE (~62% oil). Total resource potential estimated at >60 MMBOE• Includes infield gathering and compression system with no volume commitments or acreage dedications

Capitalizes on Strong Recent Well Results and Adds Drilling Inventory

(1) For the month of June 2017.(2) PVAC net acreage and drilling inventory as of August 7, 2017.(3) Acquisition locations exclude six gross locations currently operated by PVAC.(4) Represents total treatable lateral length in net drilling inventory.

All numbers are approximatePre-AcquisitionPenn Virginia Acquisition Post-Acquisition

Penn VirginiaPercent Change

Net production (BOEPD)(1) 10,100 3,000 13,100 30%

Oil - percent of BOEPD(1) 75% 64% 72% (3%)

Net acreage(2) 57,000 19,600 76,600 34%

Gross drilling inventory(2)(3) 525 85 610 16%

Net drilling inventory(2) 353 81 434 23%

Net treatable lateral length(4) 2.1 MM feet 0.7 MM feet 2.8 MM feet 33%

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Devon North & South Areas

1) Type curve is management’s estimate and adjusted for GOR. North Area based on PVAC’s Area 1 type curve and South Area based on PVAC’s Area 2 type curve.2) Wellhead rate, pre-processing.

North Area Type Curve(1)

North Area Assumptions(1)

Well Costs $7.7 million

Frac Stages 42

Average Lateral Length (Ft.) 8,300

Production Mix2 81% Oil

Gross EUR (MBOE) 725

GOR 1,600

South Area Type Curve(1)

South Area Assumptions(1)

Well Costs $8.0 million

Frac Stages 42

Average Lateral Length (Ft.) 8,300

Production Mix2 41% Oil

Gross EUR (MBOE) 1,520

GOR 7,000

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Eagle Ford Economics – XRLs Uplift Effect

Note: Based on management’s internal estimates.

North Area Assumptions

Well Costs $6.5 MM $8.8 MM

Frac Stages 30 50

Average Lateral Length (Ft.) 6,000 10,000

Production Mix2 81% Oil 81% Oil

Gross EUR (MBOE) 522 870

GOR 1,600 1,600

South Area Assumptions

Well Costs $6.7 MM $9.0 MM

Frac Stages 30 50

Average Lateral Length (Ft.) 6,000 10,000

Production Mix2 41% Oil 41% Oil

Gross EUR (MBOE) 1,096 1,826

GOR 7,000 7,000

NorthArea SouthArea

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Fayette County

Gonzales County

Lavaca County

Dewitt County

TXLegend

Penn Virginia Corporation

Devon

Devon / PVAC Operated

Preliminary 2018 Plan of Development

One Rig in Area 2

Drill: ~15 Gross Wells

Working Interest: 60-98%

Start in North and PVAC Legacy Acreage

Expand into South Acreage

One Rig in Area 1

Drill: ~22-25 Goss Wells

Working Interest: ~45-55%

Lager UnitArea 2: 3H - First Slick Water Test

Online for 140 Days with Cumulative Production of 176 MBOE

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Transaction Financing and Pro Forma Liquidity

§ Ended 2017 Q2 with liquidity of $172 MM

- Liquidity of $158 MM- $47 MM drawn on credit facility,

$6 MM in cash

§ Expected transaction financing(1)

- $150 MM of new committed debt- ~$40 MM from credit facility

§ In discussions to further amend and increase borrowing base

- Expect meaningful increase in borrowing base

§ Focused on maintaining a healthy balance sheet

- Targeting 1.5x leverage

Pro Forma Liquidity of ~$132 MM

Milli

on

Current Borrowing

Base

Current Drawn Letters of Credit

Cash Acquisition Financing

Pro Forma Liquidity

(1) Assumes net purchase price of ~$190 MM including ~$15 MM adjustment to reflect net cash flows from effective date to closing. Excludes transaction financing costs.(2) As of June 30, 2017.

$200.0 $132.3$10.1(2)($37.0)(2) ($0.8)(2) ($40.0)(1)

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1,0001,5002,0002,5003,0003,5004,0004,5005,000

2017 2018 2019

Substantial Oil Hedges in PlaceBa

rrelsP

erDay

$48.59 $49.37

$49.75

Oil Volumes (Barrels Per Day)

Average Swap Price ($ Per Barrel)

2017 (remaining) 4,408 $48.59

2018 4,476 $49.37

2019 2,916 $49.75

Note: As of July, 31 2017

• PVACExpectstoOpportunisticallyHedgeaSignificantPortionoftheOilandNaturalGasProductionAssociatedwiththeDevonAcquisition

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4Q 2016 2017 Exit 2018 Exit

§ Attractive and growing asset base in core of the Eagle Ford

§ Consistent operational execution and strong production growth

§ Extensive multi-year drilling inventory of XRLs with superior economics

§ Solid balance sheet with low leverage and ample liquidity

§ Ability to capitalize on opportunistic accretive transactions

Production Growth Builds Into 2018 (1)(2)Key Highlights

Why Penn Virginia?

1) Graphical representation of 2017 and 2018 production growth profile only. Not to scale. 2) Pro forma for Devon Acquisition

Strong Multi-Year Inventory of High Rate of Return Drilling Locations

Johnson Rice 2017 Energy Conference

Appendix

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1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Dai

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il Pr

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tion

-BO

PD

Months on Production

Daily Oil Production (BOPD)

Cumulative Oil Production (MBO)

Approximately 50% Estimated Rate of Return at $50/barrel WTI Oil Price

Attractive Eagle Ford Type Curve and Economics

1) Type curve is management’s estimate. Calculated predominantly with data from wells with Gen 1 to 3 slickwater completion designs. 2) Wellhead rate, pre-processing. Post processing type curve production mix is 86% oil, 7% natural gas, 7% NGLs

Area 1 Lower Eagle Ford Type Curve1

Area 1 Lower Eagle Ford Type Curve1

Well Costs $5.0 – $5.2 million

Frac Stages 24

Lateral Length (Ft.) 6,000

Production Mix2 90% Oil, 10% Natural Gas

Gross EUR (MBOE) 490

GOR 700

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$35 $40 $45 $50 $55 $60

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NYMEX Oil Price (Assumed flat) - $/Bbl

Slickwater Completion

Previous Hybrid Completion

Gas Price assumed $3.00 Flat

Well Economics Have Improved Substantially

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Highlights (compared to Q1 2017)

§ Total product revenues increased 5% to $36.3 million, of which 89% was crude oil sales

§ Total direct operating expenses decreased 6% on a per BOE basis

§ Operating income was $11.4 million, down ~1%

§ Net income was $21.3 million (EPS $1.42) as compared to $28.1 million (EPS $1.87) with the decrease primarily associated with lower derivatives income

§ Adjusted EBITDAX(1) was $23.1 million, an increase of almost 15%

Q2 2017 Financial Overview

1 Adjusted EBITDAX is a non-GAAP measure, reconciled to net income in the Appendix of this presentation.

(in thousands) Three Months Three MonthsEnded Ended

June 30, March 31,2017 2017

RevenuesCrude oil 32,351$ 30,073$ Natural gas liquids (NGLs) 2,043 2,302 Natural gas 1,880 2,343

Total product revenues 36,274 34,718 Gain (loss) on sales of assets, net (134) 65 Other, net 142 203

Total revenues 36,282 34,986 Operating expenses

Lease operating 5,370 4,916 Gathering, processing and transportation 2,555 2,551 Production and ad valorem taxes 2,119 1,979 General and administrative 2,873 3,281

Total direct operating expenses 12,917 12,727 Share-based compensation - equity classified awards 848 846 Depreciation, depletion and amortization 11,076 9,810

Total operating expenses 24,841 23,383

Operating income 11,441 11,603

Other income (expense)Interest expense (1,274) (538) Derivatives 11,061 17,016 Other 101 - Reorganization items, net - -

Income (loss) before income taxes 21,329 28,081 Income tax benefit (expense) - -

Net income 21,329$ 28,081$

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Updated Guidance

The table below sets forth current operational guidance for the full year 2017 and 2018 and production guidance for Q3 2017. Guidance assumes closing the acquisition on September 30, 2017:

• “Super pad” is now expected to be turned to sales in late Q3 2017. Average daily production for Q3 2017 is expected to be 9,200-9,600 BOEPD (74% oil)

• Expect total 2017 production volumes at 3.9-4.1 MMBOE, or 10,600-11,200 BOEPD (73% oil)

• Capital spending for 2017 anticipated at $140MM-$160MM, with ~90% directed to drilling and completing in Eagle Ford

• On average, Area 1 Gen 3 wells anticipated to cost $5.0 MM to $5.2 MM and Gen 4 wells anticipated to cost $5.3 MM to $5.7 MM

2017 2018Production(BOEPD) %oil %oil

Thirdquarter 9,200-9,600 74%Fourthquarter(exitrate) 14,600-15,200 74% 21,000-23,000 74%Fullyear 10,600-11,200 73% 20,000-22,000 74%

RealizedPriceDifferentialsOil(offWTI,perbarrel) $2.00-$2.50Naturalgas(offHenryHub,perMMBtu) $0.10-$0.20

DirectoperatingexpensesCashG&Aexpense($millions) $12-$14Leaseoperatingexpense(perBOE) $5.00-$5.50GPTexpense(perBOE) $2.75-$3.00Advaloremandproductiontaxes(%ofproductionrevenues) 5.75%-6.25%

Capitalexpenditures($millions) $140-$160 $220-$240

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Eagle Ford Peer Acreage Positions

Others

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Fayette County

Gonzales County

Lavaca County

Dewitt County

(1) Results are based on 24-hour IPs of the listed wells. EOG results are as reported to the Texas Railroad Commission.(2) IP measured with only 9 stages flowing. he remaining 14 stages were drilled out after the recording of the metric.

Strong Well Results, Including Recent Lager 3H and Zebra PadAcreage Map & Recent Well Results(1)

Kudu Unit 9H: IP 2,005 BOE/D8H: IP 1,188 BOE/D7H: IP 1,284 BOE/D6H: IP 1,411 BOE/D

Sable Unit 6H: IP 1,045 BOE/D(2)

5H: IP 3,418 BOE/D4H: IP 2,077 BOE/D

Zebra Unit6H: IP 1,269 BOEPD 7H: IP 1,785 BOEPD

Schacherl-EffenbergerArea 2 Test

Spud 2 Wells 4Q17

Lager UnitArea 2 Test

3H: IP 2,511 BOEPD

TX

Axis Unit 1H: IP 1,740 BOE/D2H: IP 1,795 BOE/D3H: IP 2,806 BOE/D

EOG Boedecker Unit 18H: IP 3,923 BOE/D19H: IP 3,185 BOE/D

EOG Novosad Unit10H: IP 969 BOE/D (Chalk)

EOG Kasper Unit1H: IP 3,586 BOE/D2H: IP 1,473 BOE/D3H: IP 2,464 BOE/D4H: IP 2,727 BOE/D

EOG Guadalupe Unit14H: IP 3,678 BOE/D

“Super Pad”Jake Berger Unit2H, 3H, 4H & 5H:

CompletingChicken Hawk Unit

2H, 3H, 4H & 5H: Completing

LegendPenn Virginia Corporation

Devon

Devon / PVAC Operated

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Penn Virginia Overview

1) As of September 22, 2017.2) As of June 30, 2017.3) For the second quarter of 2017.4) As of December 31, 2016. PV-10 is a non-GAAP measure reconciled in the Appendix to this presentation. PV-10 value is calculated using strip pricing as of December 31, 2016.

Exchange: Ticker NASDAQ: PVAC

Share Price (1) $39.46

Shares Outstanding (MM) (2) 15.0

Market Capitalization ($ MM) $591.9

Cash ($ MM) (2) 10.1

Long Term Debt ($ MM) (2) 37.0

Enterprise Value ($ MM) $618.8

Avg Daily Production (BOEPD) (3) 10,159 (74% oil)

2016 Proved Reserves (MMBOE) (4) 49.5

% PDP / % Oil 53% / 74%

Financial & Operational Profile

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§ Recent results outperforming type curves by more than 25%

§ Results on Lager 3H in Area 2 are very encouraging§ 24-hour IP of 2,511 BOEPD(1) (77% oil) at 4,371 PSI on 20/64” choke§ 30-day IP of 1,899 BOEPD(1) (72% oil) on active choke management

§ Accelerated drilling in Area 2 due to positive Lager 3H results:§ Expanded Schacherl-Effenberger pad to 2 wells; drilling to commence in 4Q2017§ Potential to increase drilling in Area 2 by possibly adding third rig

§ Zebra 6H and 7H wells had 24-hour IP rates 1,269 BOEPD(1) and 1,785 BOEPD(1), respectively

§ Zebra 6H and 7H wells had 30-day IP rates 918 BOEPD(1) and 1,196 BOEPD(1), respectively

§ Jake Berger / Chicken Hawk super-pad on track to deliver first production late in 3Q2017

Encouraging Well Results Support 2017 Drilling Objectives

1) Wellhead rate only. The natural gas liquids yield is 135 to 155 barrels per million cubic feet of natural gas.2) Excludes the Sable 6H which had operational issues and only had 9 open stages at the time of measuring the 24-hour and 30-day IP rates. The remaining stages were subsequently opened to flow. 3) Choke management in effect.

Lower Eagle Ford Production Results and Related Operating Information

24HourIPAverageGrossDailyProductionRates(1) 30-DayAverageGrossDailyProductionRates(1)

Gross/NetWells LateralLength FracStages Proppant(lbperfoot) OilRate EquivalentRate OilPercentage OilRate EquivalentRate OilPercentageFeet lbperfoot BOPD/1000ft BOEPD/1000ft BOPD/1000ft BOEPD/1000ft

2-StringArea1TypeCurve 6,000 30 2,000 225 251 90% 169 189 90%SablePad(4H-5H)(2) 3/1.5 6,401 32 2,404 399 423 94% 174 185 94%AxisPad(1H-3H) 3/1.9 7,056 35 2,484 278 299 93% 167 179 94%KuduPad(6H-9H) 4/1.7 5,429 27 2,415 261 283 92% 152 162 94%Lager3H(3) 1/.4 7,920 40 2,452 245 317 77% 175 240 73%ZebraPad(6H-7H)(3) 2/.9 4,726 28 2,876 287 322 89% 208 223 94%

20

PDP53%

PUD47%EagleFord

95%

Other 5%

43.7

49.5

$0

$30

4041424344454647484950

2015 2016SEC Oil Price: $50.28 $42.75

§ 49.5 MMBOE (53% PDP)

§ 74% oil, 14% NGL and 12% natural gas

§ Volumes increased 13% year-over-year despite a drop in SEC pricing

§ Standardized Measure / PV-10 value with SEC pricing of $317.6 million1

§ PV-10 valued at strip pricing of $577.7 million, with $371.5 million provided by PDP reserves2

§ Eagle Ford proved reserves increased 17% year-over-year to 47.0 MMBOE

Oil74%NGL14%

NaturalGas 12%

2016 Year-End Reserves Composition and Location

Proved Reserves (MMBOE) Growth 2016 Year-End Reserves Highlights

2016 Proved Reserves Growth

1) PV-10 is a non-GAAP measure reconciled to GAAP Standardized Measure in the Appendix of the presentation.2) Monthly NYMEX pricing as of closing on December 30, 2016. See Appendix for pricing. Proved reserves were not changed for the change in pricing.

§ Increased reserves despite decline in SEC oil price

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Non-GAAP Reconciliation – Adjusted EBITDAX

AdjustedEBITDAXrepresentsnetincome(loss)beforeinterestexpense,incometaxexpense(benefit),depreciation,depletionand amortizationexpense,andshare-basedcompensationexpense,furtheradjustedtoexcludetheeffectsofgainsorlossesonsaleofassets,accretionoffirmtransportationobligation,non-cashchangesinthefairvalueofderivatives,strategicandfinancialadvisorycosts,restructuringexpensesandothernon-cashitems.Webelievethispresentationiscommonlyusedbyinvestorsandprofessionalresearchanalystsinthevaluation,comparison,rating,investmentrecommendationsofcompanieswithintheoilandgasexplorationandproductionindustry.WeusethisinformationforcomparativepurposeswithinourIndustry.AdjustedEBITDAXisnotameasureoffinancialperformanceunderGAAPandshouldnotbeconsideredasameasureofliquidityorasanalternativetonetincome(loss).AdjustedEBITDAXasdefinedbyPennVirginiamaynotbecomparabletosimilarlytitledmeasuresusedbyothercompaniesandshouldbeconsideredinconjunctionwithnetincome(loss)andothermeasurespreparedinaccordancewith GAAP,suchasoperatingincomeorcashflowsfromoperatingactivities.AdjustedEBITDAXshouldnotbeconsideredinisolationorasasubstituteforananalysisofPennVirginia’sresultsasreported underGAAP.

PENN VIRGINIA CORPORATIONCERTAIN NON-GAAP FINANCIAL MEASURES - unaudited

(in thousands)

Successor Successor Predecessor Successor PredecessorThree Months Three Months Three Months Six Months Six Months

Ended Ended Ended Ended Ended June 30, March 31, June 30, June 30, June 30,

2017 2017 2016 2017 2016Reconciliation of GAAP "Net income (loss)" to Non-GAAP "Adjusted EBITDAX"Net income (loss) 21,329$ 28,081$ (67,266)$ 49,410$ (100,739)$ Adjustments to reconcile to Adjusted EBITDAX:

Interest expense 1,274 538 32,221 1,812 56,655 Income tax (benefit) expense - - - - - Depreciation, depletion and amortization 11,076 9,810 11,746 20,886 25,558 Exploration - - 4,320 - 5,647 Share-based compensation expense (equity-classified) 848 846 1,966 1,694 1,364 Loss (gain) on sale of assets, net 134 (65) (910) 69 (757) Accretion of firm transportation obligation - - 142 - 317 Adjustments for derivatives:

Net losses (gains) (11,061) (17,016) 21,759 (28,077) 17,267 Cash settlements, net (466) (1,992) 16,393 (2,458) 46,952

Adjustment for special items:Reorganization items, net - - 7,380 - 7,380 Strategic and financial advisory costs - - 6,973 - 18,036 Restructuring expenses - (20) 351 (20) 1,099

Adjusted EBITDAX 23,134$ 20,182$ 35,075$ 43,316$ 78,779$

22

Q3 2016 Financial Overview(1)Q3 2016 Financial Overview(1)

Non-GAAP Reconciliation - PV-10

Successor PredecessorDecember 31, December 31,

2016 2015

Standardized measure of future discounted cash flows 317,550$ 323,311$ Present value of future income taxes discounted at 10% 1 - - PV-10 317,550$ 323,311$

Reconciliation of GAAP "Standardized Measure of Discounted Future Net Cash Flows" to Non-GAAP "PV-10"

Non-GAAP PV-10 value is the estimated future net cash flows from estimated proved reserves discounted at an annual rate of 10 percent before giving effect to income taxes. The standardized measure of discounted future net cash flows is the after-tax estimated future cash flows from estimated proved reserves discounted at an annual rate of 10 percent, determined in accordance with generally accepted accounting principles (GAAP). We use non-GAAP PV-10 value as one measure of the value of our estimated proved reserves and to compare relative values of proved reserves among exploration and production companies without regard to income taxes. We believe that securities analysts and rating agencies use PV-10 value in similar ways. Our management believes PV-10 value is a useful measure for comparison of proved reserve values among companies because, unlike standardized measure, it excludes future income taxes that often depend principally on the characteristics of the owner of the reserves rather than on the nature, location and quality of the reserves themselves.

1 Due primarily to our net operating loss carry forwards, our standardized measure of future discounted cash flows does not include any income tax effect.

(in thousands)

PENN VIRGINIA CORPORATIONCERTAIN NON-GAAP FINANCIAL MEASURES - unaudited

23

Q3 2016 Financial Overview(1)Q3 2016 Financial Overview(1)

Monthly Strip Pricing at December 31, 2016

PV-10 at Strip Pricing

Oil Natural Gas(per barrel) (per MMBtu)

2017 $56.19 $3.612018 $56.59 $3.142019 $56.10 $2.872020 $56.05 $2.882021 $56.21 $2.90

Calendar Year Average

TheCompanyusedthepostedmonthlyclosingpricesforNYMEXWTIoilthroughDecember2029,andforNYMEXHenryHubnaturalgasthroughDecember2022inthecalculation.Thefirstfiveyearsofcalendaraveragepricesareshown.

24

Houston (HQ)

Penn Virginia Operating Areas

Granite Wash

Net Acreage: ~7,1502 (100% HBP)Q2 2017 Production 61 MBOE (661 BOEPD)Proved Reserves: 2.5 MMBOE1

Eagle FordCore Net Acreage: ~57,0002 (93% HBP)Drilling Locations: 525 gross locationsEconomics: 50% IRR at $50 WTI oil Q2 2017 Production 864 MBOE (9,498 BOEPD)Proved Reserves: 47.0 MMBOE1

1) As of December 31, 2016.2) As of August 7, 2017, including acreage leased in 2017. Excludes net acreage expiring in 2017.