1. Wells Fargo 2013 E&P Forum
Investor Presentation
March 7, 2013
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 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, natural gas liquids 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 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 will
determine 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 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
• 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
• 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
• Over 55% of 2013 oil production hedged at weighted average price of ~$97 per barrel (WTI)
• Over 53% of 2013 gas production hedged at weighted average price of ~$3.75 per MMBtu (HH)
2

4. Business Strategy
• “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 development and exploratory 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 low-entry cost, 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
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.

5. 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
MBOE per day (1 BOE = 6 Mcf) Pre-Hedging; $MM
20 $90
16 $68
17%
12 44%
$45
8 83%
56% $23
4
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.

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 $79 per BOE in 4Q12(1)
Quarterly Adjusted EBITDAX and EBITDAX Margin per BOE Comparative EBITDAX Margins (4Q2012 EBITDAX / BOE)(2)
$80 $48 $50
$45.89
$45 $43.83
$70 $42
$40 $39.08
$60 $36
$35 $33.46
$30.73
$50 $30 $30 $29.13
$ per BOE $27.94
$ Millions
$ per BOE
$24.49
$40 $24 $25 $23.15 $23.23
$20
$30 $18 $16.70
$15 $13.72 $14.57
$20 $12
$10
$10 $6
$5
$0 $0 $0
1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 KWK PQ XCO REXX CRK BBG FST PDCE ROSE SFY CRZO PVA GDP
Adjusted EBITDAX ($MM) Adjusted EBITDAX Margin per Mcfe
Source: 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 5
calculated as total revenues less lease operating expenses and cash G&A unless otherwise disclosed by the peer company.

7. Production Mix and Operating Margins
Production Mix Over Time Cash Margin Over Time ($/Mcfe)
Realized
$53.48
Price
$50.25
$5.82
44% $6.88 $1.91
48% $1.78
$38.70 $3.05 $4.68
$2.08
72%
$5.28 $4.13
82% $31.92
$1.74
$1.98
$6.42
$4.74
$1.74
$1.80
Cash
$4.56 $39.29 Margin
56% $34.11
52%
$24.96
28% $17.40
18%
FY 2010 FY 2011 3Q 2012 4Q 2012 FY 2010 FY 2011 3Q 2012 4Q 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
6
equivalent production.

8. Asset Overview
Emerging Oil and Liquids-Rich Plays Plus “Option” in Significant Gas Plays
Marcellus
Mid-Continent YE12 Proved reserves: 0.5 MMBOE
YE12 Proved reserves: 12.4 MMBOE % Gas: 100%
% Oil/NGLs: 47% % PDP: 23%
% PDP: 79% 2012 Production: 43 MBOE
2012 Production: 1,211 MBOE
PA
Cotton Valley
YE12 Proved reserves: 39.6 MMBOE
% Oil/NGLs: 34%
% PDP: 34%
2012 Production: 882 MBOE
OK
Eagle Ford MS
YE12 Proved reserves: 26.2 MMBOE
% Oil/NGLs: 90%
TX
% PDP: 37% Selma Chalk
2012 Production: 2,334 MBOE YE12 Proved reserves: 17.6 MMBOE
% Gas: 100%
% PDP: 54%
Haynesville
2012 Production: 847 MBOE
YE12 Proved reserves: 17.2 MMBOE
% Gas: 86%
Penn Virginia % PDP: 26%
YE12 Proved reserves: 113.5 MMBOE Oil / Liquids 2012 Production: 454 MBOE
% Oil/NGLs: 40%
% PDP: 41% Wet Gas
2012 Production: 5,771 MBOE Dry Gas
7
Note: Based on 1/29/13 operational release and YE12 reserve report prepared by Wright & Company, Inc.

9. Eagle Ford Shale
Premier Shale Oil & Liquids Play • 41,900 gross (≥33,000 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 a ~94% WI(1)
– Avg. IP/30-day rates of 972/651 BOEPD(2)
San Antonio
– Gonzales type curve EUR of ≥400 MBOE(2)
Wilson Lavaca
Bexar – Lavaca type curve of EUR of ≥500 MBOE(2)
– 80-85% oil, 5-10% NGLs and 5-10% gas, post
Atascosa processing; crude oil is 48° or less API gravity
– Reduced proppant and chemical costs
Karnes DeWitt
– Significant initial choking thought to improve
EURs
Victoria – 69 wells producing (15 in Lavaca County)
– Seeking to lower well costs by 10-15% in 2013
Goliad
• Up to ~300 remaining drilling locations
– Initial positive down-spacing test of 3-well pad
– Includes 160 down-spaced locations
McMullen Live Oak Bee Texas
• Rigs, infrastructure in place
Acreage Valuations – Dedicated rigs and frac crew
Have Increased – Gas gathering and processing in place
Significantly in Recent – Receiving premium LLS pricing
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. 8
(2) Based on 1/29/13 operational release and YE12 reserve report prepared by Wright & Company, Inc.

10. 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 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
9
Note: Wellhead rates (pre-processing); production “windows” are PVA’s approximation.

11. 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
Technik #1H
Leal #1H
Cannonade Sralla
Ranch #1H
Matias #1H
Shiner
Rock
Creek
Ranch
Lavaca
County
0 10,000
FEET
10

12. 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 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
2011-2012 Net Quarterly Sales Volumes by Commodity (MBOE)
54
42
42
70
52 50
31
34
25
29
20
23
502 490 508
460
344
300
82
24
1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12
Oil and Condensate NGLs Natural Gas
11

13. Eagle Ford Shale
Compelling Economics & Value at Varying Oil Prices
Gonzales County Lavaca County(1)
• Major assumptions • Major assumptions
• Longer lateral lengths in 2013 vs. PUD assumption • Longer lateral lengths in 2013 vs. PUD assumption
• 460 MBOE EUR type curve • 590 MBOE EUR type curve
• Drilling and completion (D&C) costs of $9.1MM • Drilling and completion (D&C) costs of $10.1MM
• Key takeaways • Key takeaways
• 40%-52% IRRs and BTAX PV-10 of $5.6 - $7.4MM per • 37%-52% IRRs and BTAX PV-10 of $6.1 - $8.2MM per
well assuming a flat $90 per barrel WTI oil price well assuming a flat $90 per barrel WTI oil price
• BTAX PV-10 breakeven WTI oil pricing of $47 to $57 • BTAX PV-10 breakeven WTI oil pricing of $47 to $57
per barrel per barrel
12
(1) Based on YE12 PUDs, excluding short-length lateral wells, applied to longer length laterals in 2013 program.

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 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
• Successful down-spacing testing 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
Producing Remaining Total Well Gross Net Acres /
Area Wells Locations Locations Acreage Acreage(1) 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
13
(1) Net acreage in Lavaca County is expected to increase due to non-consents by our partner on initial wells in 17 drilling units.

15. Eagle Ford Shale
Pro Forma PVA Has a Healthy Inventory of Drilling 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
Gross Undrilled Average Working Gross EUR
Play Locations Interest (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
14
(1) Median gross EUR for all PUD locations.

16. Financial Strategy
Crude Oil Hedges (Swaps and Collars)(1)
• Penn Virginia employs a conservative financial strategy
5,500 $110
• Capital spending driven primarily by rates of return across all
Weighted Avg. Floors and Swaps ($/Bbl.)
Weighted Average Ceiling /
5,000 $108
operating areas 4,500
Swap Price by Quarter
$105
• Capital budget focused on high return, oil / liquids areas 4,000
$102 $101 $103
Barrels per Day
3,500
•
$101 $101 $100 $100
Margins and EBITDAX projected to increase $100 $100
$100
3,000
• Maintain conservative balance sheet 2,500 $98 $98
Weighted Average Floor /
Swap Price by Quarter $98
2,000
•
$97 $97
Continue to increase senior credit facility borrowing base $95
1,500
through reserve additions from organic growth to 1,000
$93
maximize liquidity 500 $90
• Target net debt / EBITDAX of less than 3.0x by year-end 0 $88
1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14
2013 (~2.4x at YE12)
• Maintain conservative financial ratios with recent common Natural Gas Hedges (Swaps and Collars) (1)
and preferred issuances, along with cash flow growth and
asset sales 25 $5
Weighted Avg. Floors and Swaps ($/MMBtu)
Weighted Average Ceiling /
$4.50
Swap Price by Quarter
• Maintain sufficient liquidity to provide capital to continue $4.16 $4.16 $4.16
$4.29
$4.00
drilling and our transition to oil MMBtu per Day (000s) 20 $4
$3.76 $3.76 $3.76 $3.76 Weighted Average Floor /
• Maintain an active oil-focused hedging program to support Swap Price by Quarter
15 $3
economic returns and ensure strong coverage metrics
• Hedges in place to protect cash flow and well economics 10 $2
• Plans to layer in additional oil and gas hedges as prices
permit 5 $1
0 $0
1Q13 2Q13 3Q13 4Q13 1Q14
15
(1) As of 2/20/13.

17. 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
Financial Liquidity and Leverage
$600 3.6x
$500 3.3x
$400 3.0x
$300 2.7x
$200 2.4x
$100 2.1x
$0 1.8x
4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12
Cash Revolver Availability Excess Debt Capacity Debt-to-EBITDAX
16
Note: dollars in millions; excess debt capacity assumes leverage up to 4.5x EBITDAX

18. 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
17

19. Appendix
18

20. Attractive Valuation Relative to Peers
19
Notes: Sources: Company filings, press releases, First Call; market data as of 3/1/13. PV-10 (non-GAAP) as of 12/31/12 using 2012 SEC pricing methodology.

21. 2013 Guidance Table
As of February 20, 2013
($ in millions, except per unit data)
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Full-Year Full-Year
2012 2012 2012 2012 2012 2013 Guidance
Production:
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
20

22. Non-GAAP Reconciliation
Adjusted EBITDAX
Year ended December 31,
2008 2009 2010 2011 2012
Adjusted EBITDAX dollars in millions
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
21

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