This document provides an investor presentation for PVA. It discusses PVA's transition to focus on oil and natural gas liquid plays like the Eagle Ford Shale. PVA has grown its Eagle Ford acreage position and drilling inventory significantly. It is continuing to expand through additional leasing and exploration of other oil prospects. PVA's strategy is focused on growing its oil and liquids production and cash flows by continuing development in the Eagle Ford with multiple drilling rigs. The company also retains natural gas assets and will benefit from any future price recovery in natural gas.

1. October 2012
Investor Presentation
NYSE: PVA

2. Forward-Looking Statements, Oil and Gas Reserves and Definitions
Forward-Looking Statements
Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities
Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies,
actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are
not limited to, the following: the volatility of commodity prices for 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

3. PVA Overview
• Small-cap domestic onshore E&P company
• Very active in the Eagle Ford Shale oil play with excellent results to date
• HBP positions in East Texas, the Mid-Continent and Mississippi
• While transitioning to oil and liquids, we remain leveraged to an improvement in natural gas prices
• Executing a strategy of growth in oil and NGL rich plays
• The past two years have been transformational, as we have diversified our portfolio towards oil and liquids
• Successful drilling results in the Eagle Ford Shale – 57 wells on-line (50 in Gonzales Co. and 7 in Lavaca Co.)
• Adding to Eagle Ford drilling inventory
• AMI in Lavaca County with successful exploratory results to date
• Continued leasing and lease acquisition activity
• Strategy has resulted in significant growth in EBITDAX and cash operating margins
• Focused on improving liquidity
• Sold $155MM of common and preferred equity in October 2012
• Sold Appalachia (excluding the Marcellus Shale) for $100MM and eliminated $10MM per year dividend in 3Q12
• Received $32MM federal income tax refund in 3Q12
• Current borrowing base of $300MM, with >$350MM of pro forma liquidity and a zero revolver balance
• Oil production hedged from 4Q 2012 through 2014 at weighted average price of ~$100 per barrel
• Added in 2013 natural gas hedges
2

4. Business Strategy
• Continue our “Gas-to-Oil” transition
• Grew overall oil/NGL production 257% to 8,780 Bbls/day from 2Q10 to 2Q12
− Up ~70% from 5,165 Bbls/day in 2Q11
− Oil/NGLs contributed 55% of total pro forma production and 86% of product revenues in 2Q12
− Daily oil production alone grew 160% from 2Q11 to 2Q12
• Eagle Ford position built from initial 6,800 net acres a year and a half ago to ~30,000 net acres currently
− Up to 342 total well locations, with up to 285 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 – recently acquired ~3,000 net acres plus ~2,000 net acres
associated with non-consents and miscellaneous leasing
• Exploration of other oil prospects
− Initial well in Viola Lime prospect in Oklahoma did not meet our expectations partially due to shorter-than-
planned lateral, but prospect is not condemned – additional drilling will be necessary
• 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
• Continued focus on optimizing drilling and completion costs
• Continue to retain substantial gas assets for eventual price recovery
• Haynesville Shale, Cotton Valley and Mississippi Selma Chalk are primarily HBP
3

5. Value Has Shifted to Oil
• In mid-2010, PVA implemented a strategy to transition from dry gas to oil
• 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 (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 = 6Mcfe) Pre-hedging: $MM
120
100 14%
80
~45%
60
86%
40
~55%
20
0
Oil NGLs Base Gas Shale 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.

6. 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 2Q12(1)
Quarterly Adjusted EBITDAX and EBITDAX Margin per Mcfe Comparative EBITDAX Margins (2Q2012 EBITDAX / Mcfe)(2)
$70 $7 $6.00
$5.63
$5.40 $5.45
$60 $6 $5.00 $4.83
$4.62
$4.46
$50 $5 $3.99
$4.00
$3.53
$40 $4 $3.23
$ per Mcfe
$ per Mcfe
$ Millions
$2.94
$3.00
$30 $3 $2.41
$2.24
$2.12
$2.00 $1.87
$20 $2
$1.00
$10 $1
$0 $0 $0.00
Adjusted EBITDAX Adjusted EBITDAX Margin
Source: Company filings.
(1) Excludes regional and corporate G&A expenses.
(2) PVA 2Q2012 EBITDAX of $60mm per Company press release. See Appendix for PVA’s reconciliation to EBITDAX method. EBITDAX 5
for peers calculated as total revenues less lease operating expenses and cash G&A unless otherwise disclosed by the company.

7. 2012 Capital Plan
2012 Capital Spending Focused on Eagle Ford Drilling and Defining New Oily Plays
• Full-year 2012 capital expenditures are expected to be $315 million to $340 million
• Spending ~92% on Eagle Ford
• Spending ~7% in the Mid-Continent
• Includes new capital expenditures related to acreage acquisitions and increased working interests in
the Eagle Ford
• Maintenance capital for other areas
• Expect 2013 capital expenditures to be similar to 2012
Capital Expenditures by Area(1) Capital Expenditures by Type(1)
6
(1) Mid-point of full-year 2012 guidance.

8. Rationale for Recent Equity Offerings
• Prefunds capital expenditures in high-return Eagle Ford Shale
• Provides capital to continue momentum of increased oil production, oil reserves, operating
margins and cash flows
• Current liquidity of >$350 million and zero revolver balance with use of proceeds
• Repay outstanding balances on the revolving credit facility
• Cash of ~$55 million, undrawn revolver of $300 million and ~$2 million of letters of credit
• Offerings expected to “plug” funding gap through year end 2013, with revolver to cover future outspends
• Enhances flexibility to expand acreage in and maintain pace of development of the Eagle Ford
Shale
• Ongoing growth of cash flows and production
• Continued expansion of drilling inventory
• Improves positioning to explore or acquire additional oil prospects
7

9. Financial Strategy
Crude Oil Hedges (Swaps and Collars)(1)
• Penn Virginia employs a conservative financial strategy
4,500 $110
• Capital spending driven primarily by rates of return across all Weighted Average Floor /
Weighted Avg. Floors and Swaps ($/Bbl.)
Swap Price by Quarter
4,000 $105
operating areas $101 $101 $100 $100 $100 $100
$99 $99
3,500 $98 $98 $100
• Capital budget focused on high return, oil / liquids areas
3,000 $95
Barrels per Day
• Margins and EBITDAX projected to increase on a pro forma 2,500 $90
basis by year-end 2012 based on capital plan
2,000 $85
• Maintain conservative balance sheet 1,500 $80
• Continue to increase Senior Credit Facility borrowing base 1,000 $75
through reserves additions from organic growth to 500 $70
maximize liquidity 0 $65
• Target net debt / EBITDAX of less than 3.0x by year-end 3Q12 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 $5.31
•
$5.10
Maintain sufficient liquidity to provide capital to continue MMBtu per Day (000s)
30 $5
drilling and our transition to oil
• Maintain an active oil-focused hedging program to support Weighted Average Floor /
Swap Price by Quarter
20 $4
economic returns and ensure strong coverage metrics $3.68 $3.68 $3.68 $3.68
• 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
3Q12 4Q12 1Q13 2Q13 3Q13 4Q13
8
(1) As of 10/17/12.

10. Production Mix and Operating Margins
Production Mix Over Time Cash Margin Over Time ($/Mcfe)
$8.27 Realized
price
$1.07
$7.16
$6.45 $0.38
45.0%
$0.98
55.0% $0.81
$0.88 $0.41
72.0% $5.32
$0.29 $0.87
82.0% $0.33
$1.07
$0.79
$0.29
$0.30
$0.76 Cash
$6.04
margins
55.0% $4.92
45.0% $4.16
$2.90
28.0%
18.0%
(1)
FY2010 FY2011 2Q2012 PF 2Q2012 FY2010 FY2011 2Q2012 (2) PF 2Q2012 (1,2)
Oil & Condensate 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.
(1) Pro forma for the sale of Appalachian assets and related regional G&A elimination. 9
(2) Production taxes of $(0.02)/Mcfe for 2Q2012 and $(0.03)/Mcfe for PF 2Q2012.

11. 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: 0.4 Bcfe
% Gas: 54% Avg. working interest: 79%
% PDP: 69% Avg. net revenue interest: 66%
2012E Production: 7.0 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
Proved reserves: 261 Bcfe
% Gas: 67%
% PDP: 29%
2012E Production: 5.3 Bcfe
Avg. working interest: 76%
Avg. net revenue interest: 60%
Operated wells: 423
OK Non-operated wells: 34
Eagle Ford MS
Proved reserves: 60 Bcfe Selma Chalk
% Gas: 5%
TX
Proved reserves: 170 Bcfe
% PDP: 45% % Gas: 99%
2012E Production: 13.3 Bcfe % PDP: 47%
Avg. working interest: 82% 2012E Production: 2.7 Bcfe
Avg. net revenue interest: 62% Haynesville Avg. working interest: 96%
Operated wells: 55 Proved reserves: 147 Bcfe Avg. net revenue interest: 74%
% Gas: 84% Operated wells: 568
% PDP: 24%
Oil / Liquids 2012E Production: 2.7 Bcfe
Avg. working interest: 76%
Wet Gas
Avg. net revenue interest: 59%
Dry Gas Operated wells: 22
Note: Based on 8/1/12 operational update; pro forma for the sale of Appalachian assets in July 2012.
10

12. Eagle Ford Shale
Premier Shale Oil & Liquids Play • ~40,000 gross (≥~30,000 net) acres in
Volatile Oil
Gonzales and Lavaca Counties, TX
Condensate – Operator in Gonzales with 83% WI
Gonzales Rich Gas – 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(1)
Bexar Wilson Lavaca – Lavaca type curve of EUR of ~500 MBOE(1)
– Initial Lavaca wells met/exceeded expectations
– 84% oil, 9% NGLs and 7% gas, post processing
Atascosa
– Reduced proppant and chemical costs
Karnes DeWitt – Significant initial choking thought to improve
EURs
– Initial positive down-spacing test of 3-well pad
Victoria
• Up to 285 remaining drilling locations
Goliad
– 57 wells producing
– Includes AMI locations and down-spaced
locations
McMullen Live Oak Bee Texas • Rigs, infrastructure in place
Acreage Valuations – Dedicated rigs and frac crew
Have Increased – Recently increased from 2 to 3 rigs
Significantly in Recent – Gas gathering and processing in place
EFS Transactions
(1) Internally generated type curve based on production history of wells drilled to date by PVA; YE11 reserve report was prepared by Wright & Company,
11
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.

13. Eagle Ford Shale
Premier Acreage Position in Volatile Oil Window; Lavaca AMI Provides Additional Upside
PVA’s Eagle Ford Acreage
and Potential is Well- Gonzales County Type Curve
Positioned Based on
Overall Excellent Industry
Results in Area
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 Schacherl #1H (Lavaca) 1,277
Hawn Holt 9H 1,877 Hawn Holt 15H 1,298 Rock Creek Ranch 1H 1,257 Henning 2H 1,002 Rock Creek Ranch 9H 865
Hawn Holt 10H 1,188 Munson Ranch 1H 1,921 Schaefer 3H 1,129 Rock Creek Ranch 5H 969 Rock Creek Ranch 10H 1,036
Hawn Holt 11H 1,190 Munson Ranch 3H 1,538 Munson Ranch 5H 1,164 Rock Creek Ranch 6H 960 Sralla #1H (Lavaca) 827
Hawn Holt 12H 1,495 Munson Ranch 4H 1,416 D. Foreman 1H 1,202 Effenberger #1H (Lavaca) 922 McCreary #1H (Lavaca) 1,036
Note: Wellhead rates (pre-processing); production “windows” are PVA’s approximation. 12

14. 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 ~40,000 gross (~30,000 net) acres primarily in the volatile oil window
• We also have a multi-year inventory of up to 285 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
• Unitizations with other industry participants and continued leasing are expected to yield additional
locations
Producing Remaining Total Well Gross Acres /
Area Wells Locations Locations Acreage Net Acreage Location
Gonzales 50 189 239 24,408 20,519 102
Lavaca 7 96 103 15,670 9,497 152
Total 57 285 342 40,078 30,016 117
13

15. Eagle Ford Shale
Positive Trend: Volumes Up
• During 2011 and into early 2012, we have quickly ramped up the Eagle Ford Shale
• Approximately 95% of volumes are liquids - primarily crude oil
• Oil is sold into the Gulf Coast LLS market through multiple purchasers–premium pricing to WTI
2011-2012 Sales Volumes by Commodity
700
600
500
400
MBOE
300
200
100
0
1Q11 2Q11 3Q11 4Q11 1Q12 2Q12
Net Oil Sales Net NGL Sales Net Gas Sales
14

16. 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; excludes Vana #1H well due to it having a shorter-than-typical lateral length. 15

17. PVA’s Well Economics Compare Favorably Against Peers
Economics by Operator
% Wellhead Liquids
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Break-Even WTI ($/bbl)
COP $47
EOG 48
200 CRZO 50
APC 50
ROSE 52
180 PVA 54
CRK 56
160 PXD 58
Break-Even WTI ($/bbl)
BHP 58
PXP 60
140 CHK 61
MHR 63
120 MRO 64
COG 66
EP 69
100 Riley 75
MUR 77
80 SM
Other
81
88
TLM 91
60 SFY 98
XOM 103
RDS 103
40 FST 116
Lewis BP 120
20 NFX 137
Laredo 161
0
16
Source: ITG IR, raw data provided by didesktop, Texas RRC.

18. Multi-Year Drilling Inventory
PVA is Well-Positioned in a Number of Leading Oil & Gas Plays
• Total inventory of up to 833 gross undrilled locations
• Approximately 360 gross undrilled locations 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 285 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
Total 833
(1) Eagle Ford EUR per well in MBOE.
17

19. Investment Highlights
• Strategic balance between oil / liquids and natural gas
• Strengthened balance sheet and liquidity
• Core positioning 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
• Ongoing growth in oil production and cash flow
• Continued expansion of the Eagle Ford and other oily prospects
18

20. Appendix
19

21. 2012 Guidance Table
As of August 1, 2012
($ in millions, except per unit data)
1st Quarter 2nd Quarter Average Quarter for Full-Year
2012 2012 3Q12 - 4Q12 2012 Guidance
Production:
Natural gas (Bcf) 6.3 5.9 3.8 - 4.4 19.8 - 21.0
Crude oil (MBbls) 549 572 520 - 585 2,160 - 2,290
NGLs (MBbls) 215 227 166 - 191 775 - 825
Equivalent production (Bcfe) 10.9 10.7 7.9 - 9.1 37.4 - 39.7
Equivalent daily production (MMcfe per day) 119.5 117.1 86.3 98.7 102.2 - 108.4
Equivalent production (MBOE) 1,812 1,775 1,324 - 1,514 6,235 - 6,615
Equivalent daily production (MBOE per day) 19.9 19.5 14.4 - 16.5 17.0 - 18.1
Percent crude oil and NGLs 42.1% 45.0% 44.3% - 57.9% 43.9% - 50.1%
Production revenues:
Natural gas $ 14.9 10.3 10.0 - 12.4 45.2 - 49.9
Crude oil $ 58.7 58.4 46.9 - 53.3 211.0 - 223.7
NGLs $ 9.1 7.6 5.4 - 6.2 27.5 - 29.0
Total product revenues $ 82.7 76.2 62.4 - 71.8 283.7 - 302.6
Total product revenues ($ per Mcfe) $ 7.60 7.16 7.85 - 7.91 7.58 - 7.62
Total product revenues ($ per BOE) $ 45.62 42.94 47.12 - 47.46 45.50 - 45.74
Percent crude oil and NGLs 82.0% 86.5% 80.2% - 84.0% 82.4% - 84.1%
Operating expenses:
Lease operating ($ per Mcfe) $ 0.84 0.87 0.82 - 0.85
Lease operating ($ per BOE) $ 5.04 5.22 4.92 - 5.10
Gathering, processing and transportation costs ($ per Mcfe) $ 0.38 0.41 0.34 - 0.38
Gathering, processing and transportation costs ($ per BOE) $ 2.29 2.47 2.04 - 2.28
Production and ad valorem taxes (percent of oil and gas revenues) 4.3% -0.3% 3.5% - 4.0%
General and administrative:
Recurring general and administrative $ 10.5 10.4 8.8 - 9.5 38.5 - 40.0
Share-based compensation $ 1.6 1.3 1.5 - 1.8 6.0 - 6.5
Share-based compensation $ - (0.1) 1.1 - 1.6 2.0 - 3.0
Total reported G&A $ 12.1 11.7 11.3 - 12.8 46.5 - 49.5
Exploration expense $ 8.0 9.4 9.3 - 11.3 36.0 - 40.0
Unproved property amortization $ 8.2 8.3 6.8 - 7.8 30.0 - 32.0
Depreciation, depletion and amortization ($ per Mcfe) $ 4.67 4.86 4.90 - 5.10
Depreciation, depletion and amortization ($ per BOE) $ 28.04 29.14 29.40 - 30.60
Adjusted EBITDAX $ 64.2 60.0 50.4 - 60.4 225.0 - 245.0
Capital expenditures(1):
Drilling and completion $ 82.6 79.8 56.3 - 61.3 275.0 - 285.0
Pipeline, gathering, facilities $ 3.9 4.4 0.8 - 3.3 10.0 - 15.0
Seismic $ (0.4) 0.7 1.3 - 2.3 3.0 - 5.0
Lease acquisitions, field projects and other $ 4.3 6.6 0.6 - 4.6 12.0 - 20.0
Total oil and gas capital expenditures $ 90.4 91.5 59.0 - 71.5 300.0 - 325.0
(1) Capex guidance as of August 1, 2012. Capex guidance has been revised to $315 million to $340 million since the Company's latest Eagle Ford Shale acquisition in October 2012.
20

22. Non-GAAP Reconciliation
Adjusted EBITDAX
($ in millions)
Year ended December 31, LTM 6 Mos. Ended
2007 2008 2009 2010 2011 2Q12 June-11 June-12
Net income (loss) from continuing operations $26.5 $93.6 ($130.9) ($65.3) ($132.9) ($52.2) ($98.3) ($17.5)
Add: Income tax expense (benefit) 30.5 55.6 (85.9) (42.9) (88.2) (44.1) (54.2) (10.2)
Add: Interest expense 20.1 24.6 44.2 53.7 56.2 58.4 27.6 29.9
Add: Depreciation, depletion and amortization 88.0 135.7 154.4 134.7 162.5 197.2 67.9 102.6
Add: Exploration 28.6 42.4 57.8 49.6 78.9 47.4 48.9 17.4
Add: Share-based compensation expense 1.6 6.0 9.1 7.8 7.4 6.6 3.8 3.0
EBITDAX $195.3 $357.9 $48.7 $137.7 $84.1 $213.3 ($4.3) $125.0
Add/Less: Non-cash derivative loss (gain) 16.1 (37.4) 26.6 (9.1) 11.7 (20.3) 3.4 (28.6)
Add: Impairments 2.6 20.0 106.4 46.0 104.7 62.2 71.1 28.6
Add/Less: Loss (gain) on property and equipment (12.6) (31.4) (0.8) 0.1 (2.5) (2.9) (0.5) (0.8)
Less: Gain on other asset sales – (1.7) (1.2) (1.2) (0.9) (0.9) – –
Add: Loss on extinguishment of debt – – – – 25.4 1.2 24.2 –
(1)
Add: Distributions receved from PVG and PVR 29.8 44.0 42.3 11.2 – – – –
Adjusted EBITDAX $231.2 $351.4 $222.0 $184.6 $222.5 $252.7 $94.0 $124.2
(1) In June 2010, PVA disposed of its remaining ownership interests in Penn Virginia GP Holdings, L.P. (“PVG”), and Penn Virginia Resource Partners, L.P.(“PVR”).
The data reflects distributions PVA received from PVG and PVR with respect to the first quarter of 2010 and each of the four quarters of 2009.
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23. Penn Virginia Corporation
4 Radnor Corporate Center, Suite 200
Radnor, PA 19087
610-687-8900
www.pennvirginia.com