PVA BMO Investor Presentation a2013

The BMO Capital Markets 10th Annual
Unconventional Resource Conference
Investor Presentation
January 8, 2012

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 oil, natural gas liquids (NGLs) and natural gas; our ability to develop, explore for, acquire and replace
oil and gas reserves and sustain 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 oil, NGLs and natural gas; 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; our ability to successfully monetize select assets
and repay our debt; leasehold terms expiring before production can be established; 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 regulations or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general
domestic and international economic and 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 on
Form 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 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, 2011, which is 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 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 date forward, 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, unless evidence 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 less certain 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 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.

1

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 – 66 wells on-line (53 in Gonzales Co. and 13 in Lavaca Co.)
• Adding to Eagle Ford drilling inventory
• Successful exploratory results to date in Lavaca County
• Continued lease acquisition activity
• Strategy has resulted in significant growth in EBITDAX and cash operating margins
• Focused on improving liquidity
• Sold Appalachia (excluding the Marcellus Shale) for $100MM and eliminated $10MM per year dividend in 3Q12
• Received $32MM federal income tax refund in 3Q12
• Increased borrowing base by $70MM to $300MM in October 2012
• Sold $161MM of common and preferred equity in October 2012
• Oil production hedged from 4Q 2012 through 2014 at weighted average price of ~$100 per barrel
• Recently added 2013 natural gas hedges

2

Business Strategy

• Continue our “Gas-to-Oil” transition
• Grew overall oil/NGL production 246% to 8,523 Bbls/day from 2Q10 to 3Q12
− Up ~20% from 5,165 Bbls/day in 3Q11
− Oil / NGLs contributed ~55% of pro forma production and 84% of product revenues in 3Q12
− Daily oil production alone grew 34% from 3Q11 to 3Q12
• Eagle Ford position built from initial 6,800 net acres two years ago to 32,500 net acres currently(1)
− Up to 342 total well locations, with up to 276 remaining drilling locations
− Includes 117 down-spaced development and exploratory locations
• Continue to expand oil and liquids reserves and drilling inventory
• Continued leasing and expansion of Eagle Ford
• Exploration of other oil prospects
− New ventures team is assessing low-entry cost, high impact oil resource plays
• Continue to grow oil and liquids production and cash flows
• Eagle Ford drilling emphasis in 2012 and 2013, recently increased from 2 to 3 rigs
• 35 to 40 Eagle Ford wells in 2013, slightly more than half of which will be Lavaca County
• Continued focus on optimizing drilling and completion costs in the Eagle Ford
• Continue to retain substantial gas assets for eventual price recovery
• Haynesville Shale, Cotton Valley and Mississippi Selma Chalk are primarily HBP

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.

Value Has Shifted to Oil

• 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

Perception: “6-to-1” Equivalent Environment Reality: “20-to-1” Price Environment
Gas Producer With Little to No Production Growth Oil/NGL Producer With Revenue Growth
Pro Forma Production by Commodity Quarterly Revenue by Commodity
MMcfe per day (1 Bbl = 6 Mcfe) Pre-Hedging; $MM
120 $90

100
$68 16%
80
45%
60 $45
84%
40
55% $23
20

0 $0

Oil NGLs Base NG Shale NG Oil NGLs Gas

Note: Pro forma production excludes contributions from South Texas and South Louisiana assets sold in January 2010, Arkoma Basin assets sold in 4
August 2011 and Appalachian assets sold in July 2012. Revenues are actual amounts received, prior to the impact of derivatives.

Strong Margins vs. Peers
• EBITDAX has increased significantly since mid-2010 when we shifted our strategy to oil and NGLs
• Cash margin per Mcfe has also improved significantly due to the increase in oil prices and
declining operating costs per unit
• Eagle Ford cash margin was ~$14 per Mcfe (~$84 per BOE) in 3Q12(1)
Quarterly Adjusted EBITDAX and EBITDAX Margin per Mcfe Comparative EBITDAX Margins (3Q2012 EBITDAX / Mcfe)(2)

$80 $8 $8

$70 $7 $7 $6.78

$6.12 $6.18
$5.89
$60 $6 $6

$50 $5 $5 $4.61
$ per Mcfe

$ per Mcfe
$ Millions

$4.29

$40 $4 $4 $3.58 $3.61 $3.68
$3.31

$30 $3 $3 $2.61

$2.05 $2.08
$20 $2 $2 $1.73

$10 $1 $1

$0 $0 $0
1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12

Adjusted EBITDAX ($MM) Adjusted EBITDAX Margin per Mcfe

Source: Company filings.
(1) Excludes regional and corporate G&A expenses.
(2) PVA 3Q2012 EBITDAX of $61mm per Company press release. See Appendix for PVA’s reconciliation of EBITDAX. EBITDAX for peers 5
calculated as total revenues less lease operating expenses and cash G&A unless otherwise disclosed by the peer company.

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

Marcellus
Proved reserves: 40 Bcfe
% Gas: 100%
Granite Wash % PDP: 16%
Proved reserves: 96 Bcfe 2012E Production: 0.3 Bcfe
% Oil/NGLs: 46% Avg. working interest: 79%
% PDP: 69% Avg. net revenue interest: 66%
2012E Production: 6.9 Bcfe Operated wells: 4
Avg. working interest: 29% Non-operated wells: 0
Avg. net revenue interest: 23%
Operated wells: 33
Non-operated wells: 58 Cotton Valley
PA
% Oil/NGLs: 33%
% PDP: 29%
2012E Production: 5.4 Bcfe
Avg. working interest: 76%
Operated wells: 423
OK Non-operated wells: 34

Eagle Ford MS
Proved reserves: 60 Bcfe Selma Chalk
% Oil/NGLs: 95%
TX
% PDP: 45% % Gas: 99%
2012E Production: 13.5 Bcfe % PDP: 47%
Avg. working interest: 82% 2012E Production: 5.1 Bcfe
Avg. net revenue interest: 62% Haynesville Avg. working interest: 96%
Operated wells: 66 Proved reserves: 147 Bcfe Avg. net revenue interest: 74%
% Gas: 84% Operated wells: 568
% PDP: 24%
Oil / Liquids 2012E Production: 2.8 Bcfe
Avg. working interest: 76%
Wet Gas
Dry Gas Operated wells: 22

Note: Based on 10/31/12 operational update
6

Eagle Ford Shale
Premier Shale Oil & Liquids Play • 40,300 gross (≥32,500 net) acres in
Volatile Oil
Gonzales and Lavaca Counties, TX(1)
Condensate
Gonzales Rich Gas
– Operator in Gonzales with 83% WI
– Operator in Lavaca with at least a 57% WI
– Avg. IP/30-day rates of 1,001/657 BOEPD
San Antonio
– Gonzales type curve EUR of ~400 MBOE(2)
Wilson Lavaca
Bexar – Lavaca type curve of EUR of ~500 MBOE(2)
– Initial Lavaca wells met/exceeded expectations
Atascosa – 84% oil, 9% NGLs and 7% gas, post processing
– Reduced proppant and chemical costs
Karnes DeWitt
– Significant initial choking thought to improve
EURs
Victoria – 66 wells producing (13 in Lavaca County)
Goliad • Up to 276 remaining drilling locations
– Initial positive down-spacing test of 3-well pad
– Includes 117 down-spaced locations
McMullen Live Oak Bee Texas
• Rigs, infrastructure in place
– Dedicated rigs and frac crew
Acreage Valuations – Recently increased from 2 to 3 rigs
Have Increased – Gas gathering and processing in place
Significantly in Recent
EFS Transactions
(1) Net acreage in Lavaca County is expected to increase due to non-consents by our partner on initial wells in 17 drilling units. 7
(2) Internally generated type curve based on production history of wells drilled to date by PVA; YE11 reserve report was prepared by Wright & Company,
Inc. and reflected a type curve EUR of 341 MBOE for Gonzales County based on the production history only for the wells completed through YE11.

Eagle Ford Shale
Premier Acreage Position in Volatile Oil Window

Eagle Ford Shale Wellhead Production – Gonzales Co.

Notable PVA Results
IP Rates IP Rates IP Rates IP Rates IP Rates
PVA Well Name (BOEPD) PVA Well Name (BOEPD) PVA Well Name (BOEPD) PVA Well Name (BOEPD) PVA Well Name (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 Leal 1H (Lavaca) 832

Hawn Holt 10H 1,188 Munson Ranch 1H 1,921 Schaefer 3H 1,129 Schacherl 1H (Lavaca) 1,277 Matias 1H (Lavaca) 1,013

Hawn Holt 11H 1,190 Munson Ranch 3H 1,538 Munson Ranch 5H 1,164 Rock Creek Ranch 10H 1,036 Arledge Ranch 1H 1,117

Hawn Holt 12H 1,495 Munson Ranch 4H 1,416 D. Foreman 1H 1,202 Sralla 1H (Lavaca) 827 Freytag 1H (Lavaca) 1,194
8
Note: Wellhead rates (pre-processing); production “windows” are PVA’s approximation.

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

Energy Transfer Pipelines
Penn Virginia Pipelines
Barazza #1H Freytag #1H

Pavlicek #1H

Schacherl #1H Vana #1H

Gonzales
Cortez Rabb #1H
County
Smith #1H
Effen- Kleihege #1H
berger McCreary #1H
#1H

Leal #1H
Cannonade Sralla
Ranch #1H
Matias #1H

Shiner
Rock
Creek
Ranch

Lavaca
County

0 10,000

FEET

9

Eagle Ford Shale
Positive Trend: Volumes Up

• During 2011 and into early 2012, we quickly ramped up the Eagle Ford Shale, and expect to
increase production again during 2013
• Approximately 93% 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
2011-2012 Net Quarterly Sales Volumes by Commodity (MBOE)

42
42
52 50
31
34

25
29
20
23

502 490
460

344
300

82
24

1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12
Oil and Condensate NGLs Natural Gas
10

Compelling Economics & Value at Varying Costs and Oil Prices

Gonzales County Lavaca County(1)
• Major assumptions • Major assumptions
• ~400 MBOE EUR type curve (~1,000 BOEPD IP rate, • ~500 MBOE EUR type curve (~1,000 BOEPD IP rate,
~650 BOEPD 30-day avg.) ~670 BOEPD 30-day avg.)
• Drilling and completion (D&C) costs of $7.0 - $8.0MM • Drilling and completion (D&C) costs of $8.5 - $9.5MM
• Key takeaways • Key takeaways
• BTAX PV-10 of $3.8 - $4.8MM per well assuming a flat • BTAX PV-10 of $4.7 - $5.7MM per well assuming a
$85 per barrel NYMEX (WTI) oil price flat $85 per barrel NYMEX (WTI) oil price
• BTAX PV-10 breakeven NYMEX oil pricing of $50 to • BTAX PV-10 breakeven NYMEX oil pricing of $51 to
$57 per barrel $57 per barrel

(1) Preliminary estimates of economics and EURs 11

Eagle Ford Shale
Multi-Year Drilling Inventory

• Due to acreage acquisitions and leasing efforts over the past two years, we have expanded
our acreage position to 40,300 gross (32,500 net) acres primarily in the volatile oil window(1)
• We also have a multi-year inventory of up to 276 additional locations
• Successful down-spacing testing has added 117 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

Producing Remaining Total Well Gross Net Acres /
Area Wells Locations Locations Acreage Acreage(1) Location

Gonzales 53 186 239 24,662 20,786 103

Lavaca 13 90 103 15,670 11,751 152

Totals 66 276 342 40,332 32,537 117

12
(1) Net acreage in Lavaca County is expected to increase due to non-consents by our partner on initial wells in 17 drilling units.

Multi-Year Drilling Inventory
PVA is Well-Positioned in a Number of Leading Oil & Gas Plays

• Total inventory of up to 824 gross undrilled locations
• Approximately 249 gross undrilled locations in the Eagle Ford Shale and Granite Wash are
economic at today’s commodity prices
• Significant upside in inventory of “gassy” locations

Gross Undrilled Average Working Gross EUR
Play Locations Interest (Bcfe/Well)(1)

Eagle Ford Shale 276 70% ~400-5001

Granite Wash 73 26% 3.7

Horizontal Cotton Valley 82 80% 4.9

Haynesville Shale 149 74% 5.0

Selma Chalk 94 96% 1.8

Marcellus Shale 150 79% 4.0

Totals 824

(1) Eagle Ford EUR per well in MBOE.
13

Financial Strategy

Crude Oil Hedges (Swaps and Collars)(1)
• Penn Virginia employs a conservative financial strategy
4,500 $110
• Capital spending driven primarily by rates of return across all

Weighted Avg. Floors and Swaps ($/Bbl.)
4,000 $108
operating areas Weighted Average Ceiling /
Swap Price by Quarter
3,500 $105
• Capital budget focused on high return, oil / liquids areas $103 $102 $102
3,000 $102 $102 $103

Barrels per Day
• Margins and EBITDAX projected to increase on a pro forma 2,500 $101
$99 $99
$100 $100 $100 $100
$100
basis by year-end 2012 based on capital plan $98 $98
Weighted Average Floor /
2,000 $98
• Maintain conservative balance sheet 1,500 $95

• Continue to increase senior credit facility borrowing base 1,000 $93
through reserve additions from organic growth to 500 $90
maximize liquidity 0 $88
• Target net debt / EBITDAX of less than 3.0x by year-end 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14

2013
Natural Gas Hedges (Swaps and Collars) (1)
• Maintain conservative financial ratios with recent common
and preferred issuances, along with cash flow growth and 40 $6

Weighted Avg. Floors and Swaps ($/MMBtu)
asset sales
•
$5.10 Weighted Average Ceiling /
Maintain sufficient liquidity to provide capital to continue MMBtu per Day (000s)
30
$5
drilling and our transition to oil $4.50 $4.50 $4.50
$4.21
• Maintain an active oil-focused hedging program to support $4.16 $4.16 $4.16
$4.00 $4.00 $4.00
20 $4
economic returns and ensure strong coverage metrics $3.68
Weighted Average Floor /
$3.76 $3.76 $3.76 Swap Price by Quarter

• Hedges in place to protect cash flow and well economics
10 $3
• Plans to layer in additional oil and gas hedges as prices
permit
0 $2
4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14

14
(1) As of 11/26/12.

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 nearly $700MM
• In addition, financial leverage has decreased markedly from over 3.0x EBITDAX to 2.1 EBITDAX,
pro forma for the October 2012 equity offerings

Financial Liquidity and Leverage
$800 3.6x

$700 3.4x

$600 3.2x

$500 3.0x

$400 2.8x

$300 2.6x

$200 2.4x

$100 2.2x

$0 2.0x

Cash Revolver Availability Excess Debt Capacity Debt-to-EBITDAX
15
Note: dollars in millions; excess debt capacity assumes leverage up to 4.5x EBITDAX

Investment Highlights

• 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

16

Production Mix and Operating Margins

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

Realized
$8.80
$8.37 Price

$1.23
$1.15
48% 45%
$0.52
$6.45 $0.51 $0.33
$0.35 $0.67
72%
$0.88 $0.69
82% $5.32
$0.29
$0.33
$1.07
$0.79
$0.29
$0.30
$0.76 Cash
$5.68 $6.06
55% Margin
52%
$4.16
28% $2.90
18%

(1) (1)
FY 2010 FY 2011 3Q 2012 PF 3Q 2012 FY 2010 FY 2011 3Q 2012 PF 3Q 2012
Oil & Condensate Natural Gas Cash Margin LOE
G&P and transportation Production taxes
Cash G&A (excludes share-based compensation)

Note: Cash margin per Mcfe is defined as total product revenues, excluding the impact of hedges, less direct operating expenses per unit of
equivalent production. 18
(1) Pro forma for the sale of Appalachian assets and related regional G&A elimination. Other columns are actual results.

2012 Guidance Table
As of October 31, 2012
($ in millions, except per unit data) Implied
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Full-Year
2012 2012 2012 2012 2012 Guidance
Production:
Natural gas (Bcf) 6.3 5.9 4.4 3.6 - 3.8 20.1 - 20.3
Crude oil (MBbls) 549 572 573 527 - 557 2,220 - 2,250
NGLs (MBbls) 215 227 202 190 - 200 835 - 845
Equivalent production (Bcfe) 10.9 10.7 9.0 7.9 - 8.3 38.4 - 38.9
Equivalent daily production (MMcfe per day) 119.5 117.1 98.1 85.6 - 90.4 105.0 - 106.2
Equivalent production (MBOE) 1,812 1,775 1,504 1,313 - 1,386 6,405 - 6,478
Equivalent daily production (MBOE per day) 19.9 19.5 16.5 14.3 - 15.1 17.5 - 17.7
Percent crude oil and NGLs 42.1% 45.0% 51.6% 52.1% - 57.0% 47.2% - 48.3%

Production revenues:
Natural gas $ 14.9 10.3 11.9 11.9 - 12.9 49.0 - 50.0
Crude oil $ 58.7 58.4 57.0 48.9 - 53.9 223.0 - 228.0
NGLs $ 9.1 7.6 6.7 5.4 - 5.9 28.7 - 29.2
Total product revenues $ 82.7 76.2 75.6 66.2 - 72.7 300.7 - 307.2
Total product revenues ($ per Mcfe) $ 7.60 7.16 8.37 8.40 - 8.74 7.82 - 7.90
Total product revenues ($ per BOE) $ 45.62 42.94 50.25 50.42 - 52.44 46.95 - 47.42
Percent crude oil and NGLs $ 82.0% 86.5% 84.2% 80.8% - 83.4% 83.4% - 84.0%

Operating expenses:
Lease operating ($ per Mcfe) $ 0.84 0.87 0.69 0.83 - 0.87 0.81 - 0.82
Lease operating ($ per BOE) $ 5.04 5.22 4.13 4.96 - 5.24 4.86 - 4.92
Gathering, processing and transportation costs ($ per Mcfe) $ 0.38 0.41 0.35 0.27 - 0.33 0.36 - 0.37
Gathering, processing and transportation costs ($ per BOE) $ 2.29 2.47 2.08 1.65 - 1.95 2.16 - 2.22
Production and ad valorem taxes (percent of oil and gas revenues) 4.3% -0.3% 6.1% 4.9% - 5.2% 3.7% - 3.8%
General and administrative:
Recurring general and administrative $ 10.5 10.6 8.9 8.5 - 9.0 38.5 - 39.0
Share-based compensation $ 1.6 1.3 1.3 1.1 - 1.3 5.3 - 5.5
Restructuring $ - (0.1) 1.4 - - - 1.3 - 1.3
Total reported G&A $ 12.1 11.7 11.6 9.6 - 10.3 45.1 - 45.8
Exploration: $ 8.0 9.4 9.3 11.4 - 12.4 38.0 - 39.0
Unproved property amortization $ 8.2 8.3 8.3 8.7 - 9.2 33.5 - 34.0
Depreciation, depletion and amortization ($ per Mcfe) $ 4.67 4.86 5.47 5.11 - 5.34 5.00 - 5.05
Depreciation, depletion and amortization ($ per BOE) $ 28.02 29.14 32.80 30.69 - 32.05 30.00 - 30.30

Adjusted EBITDAX $ 64.2 60.0 61.2 49.7 - 59.7 235.0 - 245.0

Capital expenditures:
Drilling and completion $ 82.6 79.8 73.1 55.5 - 65.5 291.0 - 301.0
Pipeline, gathering, facilities $ 3.9 4.4 5.0 2.7 - 3.7 16.0 - 17.0
Seismic $ (0.4) 0.7 0.1 2.6 - 3.6 3.0 - 4.0
Lease acquisitions, field projects and other $ 4.3 6.6 6.4 10.2 - 10.7 27.5 - 28.0
Total oil and gas capital expenditures $ 90.4 91.5 84.6 70.9 - 83.4 337.5 - 350.0

19

Non-GAAP Reconciliation
Adjusted EBITDAX

Year ended December 31, LTM 9 Mos. Ended
2007 2008 2009 2010 2011 3Q12 Sep-11 Sep-12
Adjusted EBITDAX dollars in millions

Net income (loss) from continuing operations $ 26.5 $ 93.6 $ (130.9) $ (65.3) $ (132.9) $ (78.1) $(105.0) $ (50.1)

Add: Income tax expense (benefit) 30.5 55.6 (85.9) (42.9) (88.2) (60.2) (60.4) (32.4)
Add: Interest expense 20.1 24.6 44.2 53.7 56.2 59.2 41.8 44.8
Add: Depreciation, depletion and amortization 88.0 135.7 154.4 134.7 162.5 201.2 113.2 151.9
Add: Exploration 28.6 42.4 57.8 49.6 78.9 37.4 68.2 26.6
Add: Share-based compensation expense 1.6 6.0 9.1 7.8 7.4 6.0 5.6 4.2
Add/Less: Derivatives (income) expense included in net income 2.0 (29.7) (31.6) (41.9) (15.7) (27.1) (19.8) (31.3)
Add/Less: Cash receipts (payments) to settle derivatives 14.1 (7.6) 58.1 32.8 27.4 31.3 20.3 24.2
Add/Less: Loss on firm transportation commitment - - - - - 17.3 - 17.3
Add: Impairments 2.6 20.0 106.4 46.0 104.7 62.9 71.1 29.3
Add/Less: Net loss (gain) on sale of assets, other (12.6) (33.2) (2.0) (1.2) 22.0 (2.4) 25.2 0.7

Adjusted EBITDAX $ 201.5 $ 307.4 $ 179.7 $ 173.3 $ 222.5 $ 247.6 $ 160.3 $ 185.3

20

Penn Virginia Corporation
4 Radnor Corporate Center, Suite 200
Radnor, PA 19087
610-687-8900
www.pennvirginia.com

PVA BMO Investor Presentation a2013

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