Credit Suisse’s2012 Small & Mid Cap ConferenceSeptember 21, 2012Investor PresentationNYSE: PVA

Forward‐Looking Statements

Certain statements contained herein that are not descriptions of historical facts are “forward‐looking” statements within the meaning of Section 27A of the SecuritiesAct of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies,actual results may differ materially from those expressed or implied by such forward‐looking statements. These risks, uncertainties and contingencies include, but arenot limited to, the following: the volatility of commodity prices for oil, natural gas liquids (NGLs) and natural gas; our ability to develop, explore for, acquire and replaceoil 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 borrowingbase under our revolving credit facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipelinetransportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertaintiesinherent 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 andoperating risks; our ability to compete effectively against other independent and major oil and natural gas companies; our ability to successfully monetize select assetsand repay our debt; leasehold terms expiring before production can be established; environmental liabilities that are not covered by an effective indemnity orinsurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintain adequatefinancial liquidity and to access adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeureevents; 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 generaldomestic 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 onForm 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 asof 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 aresult of new information, future events or otherwise.

Oil and Gas Reserves

Effective January 1, 2010, the SEC permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves, but also “probable” reserves and“possible” reserves. As noted above, statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Anyreserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves notnecessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure inPVA’s Annual Report on Form 10‐K for the fiscal year ended December 31, 2011, which is available from PVA at Four Radnor Corporate Center, Suite 200, Radnor, PA19087 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1‐800‐SEC‐0330 or from the SEC’s website at www.sec.gov.

Definitions

Proved reserves are those quantities of oil and gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to beeconomically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulationbefore the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether theestimate is a deterministic estimate or probabilistic estimate. Probable reserves are those additional reserves that are less certain to be recovered than provedreserves, but which are as likely than not to be recoverable (there should be at least a 50% probability that the quantities actually recovered will equal or exceed theproved plus probable reserve estimates). Possible reserves are those additional reserves that are less certain to be recoverable than probable reserves (there should beat least a 10% probability that the total quantities actually recovered will equal or exceed the proved plus probable plus possible reserve estimates). “3P” reserves referto the sum of proved, probable and possible reserves. Estimated ultimate recovery (EUR) is the sum of reserves remaining as of a given date and cumulative productionas of that date.

Forward‐Looking Statements, Oil and Gas Reserves and Definitions

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PVA Overview

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• 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

• PVA is 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 – 54 wells on‐line (48 in Gonzales Co. and 6 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• Recently sold Appalachia (excluding the Marcellus Shale) for $100 MM and cut our $10 MM per year dividend

• Current borrowing base of $230 MM, with $125 MM of current availability

• Have reduced capital spending in 2012 – 30% less than 2011

• Oil hedges: ~67% hedged for second half of 2012 at weighted average price of ~$101 per barrel 

PVA’s Catalysts / Challenges

• Catalysts

• Eagle Ford exploratory success in Lavaca County, TX

• Continued strong Eagle Ford development drilling results 

• Increasing oil production and oil reserves, operating margins and cash flows

• Exploration of other oil prospects

• Attractive natural gas asset base that is primarily HBP

• Challenges

• Capital intensive industry with greatly diminished cash flows from natural gas

• Maintaining financial liquidity to fund future Eagle Ford Shale and other oily drilling

• Ongoing expansion of our drilling inventory

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Business Strategy

• Continue our “Gas‐to‐Oil” transition• We have built up our Eagle Ford position from initial 6,800 net acres to ~25,000 net acres currently

– Up to approximately 250 total well locations, including locations in AMI in Lavaca County– Includes down‐spaced development and exploratory locations

• Grew overall oil/NGL production from 2,461 Bbls/day in 2Q10 to 8,780 Bbls/day in 2Q12 (+257%)– Up approximately 70% from 5,165 Bbls/day in 2Q11– Contributed 45% of total production and 86% of product revenues in 2Q12– Daily oil production alone grew 160% from 2Q11 to 2Q12

• Continue to retain substantial gas assets for eventual gas price recovery• Haynesville Shale, Cotton Valley and Mississippi Selma Chalk

• Take steps to build financial liquidity and improve operational focus• Sold Appalachian assets for $100 MM in July 2012• Discontinued common dividend, adding over $10 MM annually for capital program• Sold Arkoma assets for $30 MM in August 2011

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

• Continue to grow oil and liquids production and cash flows• Eagle Ford drilling emphasis in 2012 and 2013, increasing from 2 to 3 rigs in 3Q12• Continued focus on optimizing drilling, completion and operating costs

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0

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Pro Forma Production by CommodityMMcfe per day (1 Bbl = 6 Mcfe)

Oil NGLs Base Gas Shale Gas

$0

$23

$45

$68

$90

Quarterly Revenue by CommodityPre‐Hedging; $MM

Oil NGLs Gas

• 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

Value Has Shifted to Oil

Perception: “6‐to‐1” Equivalent EnvironmentGas Producer With Little to No Production Growth

Reality: “20‐to‐1” Price EnvironmentOil/NGL Producer With Revenue Growth

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

~55%

~45%

86%

14%

6

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$1

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

$ per Mcfe$ 

Millions

Quarterly EBITDAX and Cash Margins

Adjusted EBITDAX ($MM) Gross Operating Margin per Mcfe 7

EBITDAX and Cash Margin Growth

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

• EBITDAX has increased significantly since mid‐2010 when we shifted our strategy to oil• Gross operating margin per Mcfe has also significantly improved due to the increase in 

oil prices and declining operating costs per unit• Eagle Ford margin was approximately $14 per Mcfe in 2Q12

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Emerging Oil and Liquids‐Rich Plays Plus “Option” in Significant Gas Plays

Note: Based on 8/1/12 operational update; pro forma to exclude Appalachian proved reserves sold in July 2012

2011 Pro Forma Proved Reserves: 778 Bcfe

2012E CAPEX: $300MM ‐ $325MM92% Eagle Ford / 30% Less than 20112012E Production: 37.4‐39.7 Bcfe

47% Oil & Liquids

Oil / Liquids

Wet Gas 

Dry Gas

2012E Production: 38.6 Bcfe

Asset Overview

The Most Economic Eagle Ford Shale Wells are in the Volatile Oil & Condensate Rich Gas Windows

Eagle Ford Shale

Gonzales

Lavaca

DeWitt

Victoria

Goliad

BeeLive OakMcMullen

Wilson

Atascosa

Karnes

Bexar

San Antonio

Volatile Oil

CondensateRich Gas

Acreage Valuations Have Increased 

Significantly in Recent EFS Transactions

Texas

Premier Shale Oil & Liquids Play

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• ~37,000 gross (≥~25,000 net) acres in Gonzales and Lavaca Counties, TX– 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– Gonzales type curve EUR of ~400 MBOE1

– 84% oil, 9% NGLs and 7% gas, post processing– Reduced proppant and chemical costs– Significant initial choking expected to improve 

EURs– Initial Lavaca wells met/exceeded expectations– Initial positive down‐spacing test of 3‐well pad

• Up to ~200 remaining drilling locations– 54 wells producing– Includes AMI locations and down‐spaced 

locations• Rigs, infrastructure in place

– Dedicated rigs and frac crew– Increase from 2 to 3 rigs in 3Q12

– Gas gathering and processing in place

1 – Internally generated type curve based on production history of wells drilled to date by PVA in Gonzales County; YE11 reserve report was prepared by Wright & Company, Inc. and reflects a type curve EUR of 341 MBOE based on the production history of the wells through YE11

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PVA AcreagePVA AMI with “Major” 3‐D Seismic SurveyNotable PVA ResultsNotable Industry Results

GonzalesCounty

LavacaCounty

Volatile Oil Window

EOG

MHR

Premier Acreage Position in Volatile Oil Window; Lavaca AMI Provides Additional Upside

Eagle Ford Shale

PVA’s Eagle Ford Acreage and Potential is Well‐Positioned Based on Overall Excellent 

Industry Results in Area

Notable PVA Results

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

PVA Well Name IP RatesGardner 1H 1,247 BOEPDHawn Holt 9H 1,877 BOEPDHawn Holt 10H 1,188 BOEPDHawn Holt 11H 1,190 BOEPDHawn Holt 12H 1,495 BOEPDHawn Holt 13H 1,399 BOEPDHawn Holt 15H 1,298 BOEPDMunson Ranch 1H 1,921 BOEPDMunson Ranch 3H 1,538 BOEPDMunson Ranch 4H 1,416 BOEPDMunson Ranch 6H 1,808 BOEPDRock Creek Ranch 1H 1,257 BOEPDSchaefer 3H 1,129 BOEPDMunson Ranch 5H 1,164 BOEPDD. Foreman 1H 1,202 BOEPDHenning 1H 1,115 BOEPDRock Creek Ranch 5H 969 BOEPDRock Creek Ranch 6H 960 BOEPDEffenberger #1H (Lavaca) 922 BOEPDSchacherl #1H (Lavaca) 1,277 BOEPDRock Creek Ranch 9H 865 BOEPDRock Creek Ranch 10H 1,036 BOEPDSralla #1H  (Lavaca) 827 BOEPDMcCreary #1H (Lavaca) 1,036 BOEPD

NFR

Eagle Ford Shale

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Detailed Map of Primary Eagle Ford Shale Operating Area

0 10,000

FEET

Cortez Area

RockCreek RanchArea

CannonadeRanchArea

ShinerProspect

(AMI; acreage not 100%contiguous)

GonzalesCounty

LavacaCounty

PVOG PIPELINES

ETC PIPELINE

McCreary #1H

Schacherl #1H

Vana #1H

Effen‐berger#1H

Sralla#1H

Pavlicek #1H

AreaProducing

WellsRemainingLocations

Total WellLocations

GrossAcreage

NetAcreage

Acres / Location

Cortez 34 ~60 ~94 9,903 7,457 ~105

Cannonade 2 ~30 ~32 7,212 5,506 ~225

Rock Creek 11 ~10 ~21 2,200 1,833 ~105

SW Gonzales 1 ~10 ~11 2,199 2,199 ~200

Shiner 6 ~90 ~96 15,365 8,292 ~160

Totals 53 ~200 ~253 36,869 25,287 ~145

• Due to acreage acquisitions and leasing efforts over the past two years, we have expanded our acreage position to approximately 37,000 gross (25,000 net) acres primarily in the volatile oil window

• We also have a multi‐year inventory of approximately 200 additional locations• Successful down‐spacing testing has added potentially ~120 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

Eagle Ford Shale

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Multi‐Year Inventory of Oily Locations

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

MBO

E

2011‐12 Sales Volumes by Commodity

Net Oil Sales Net NGL Sales Net Gas Sales

• 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

Positive Trend: Volumes Up

Eagle Ford Shale

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Gonzales County

• Major assumptions• ~400 MBOE EUR type curve (~1,000 BOEPD IP rate, ~775 BOEPD 30‐day avg.)• Drilling and completion (D&C ) costs of $7.0 ‐ $8.0 MM

• Key takeaways• BTAX PV‐10 of $4.0 ‐ $5.0 MM per well assuming a flat $85 per barrel NYMEX (WTI) oil price• BTAX PV‐10 breakeven NYMEX oil pricing of $50 to $57 per barrel

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Compelling Economics & Value at Varying Costs and Oil Prices

Lavaca County

• Major assumptions• ~500 MBOE EUR type curve (~1,100 BOEPD IP rate, ~850 BOEPD 30‐day avg.)• Drilling and completion (D&C ) costs of $8.5 ‐ $9.5 MM

• Key takeaways• BTAX PV‐10 of $5.5 ‐ $6.5 MM per well assuming a flat $85 per barrel NYMEX (WTI) oil price• BTAX PV‐10 breakeven NYMEX oil pricing of $49 to $54 per barrel

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Preliminary Economics & Value Look Excellent in Lavaca County

Note: Preliminary estimates of economics and EURs; excludes Vana #1H well due to it having a shorter‐than‐typical lateral length

Comparison of Gonzales and Lavaca Counties

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• Depth of Eagle Ford Shale

• Gonzales: 8,500 – 10,500 feet

• Lavaca: 11,000 – 12,000 feet

• Reservoir pressure

• Geo‐pressured

• Increases with depth moving from Gonzales to Lavaca

• Gas‐oil ratio (GOR)

• Similar to date in both counties and within the “volatile oil” window

• Gross thickness of the Eagle Ford comparable from Gonzales to Lavaca

• Strategic balance between oil / liquids and natural gas

• Recently 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

Why PVA?Investment Highlights

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Appendix

$101 $101$99 $99

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3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14

Barrels p

er Day

Crude Oil Hedges1Swaps and Collars

Weighted Avg. Floors and Sw

aps  ($/Bbl.)

Weighted Average Floor /Swap Price by Quarter

Forecast Price by Quarter

Crude Oil HedgesProtecting our Capital Budget and Well Economics

• We recently expanded our crude oil hedges given our increased oil drilling activity• Our oil hedges thus far are equal to or greater than our forecasted oil price for 2012‐2014

1 – As of 9/18/1219

$5.31 $5.10 

$2.59 

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r Day (0

00s)

Natural Gas Hedges1Swaps and Collars

Weighted Avg. Floors and Sw

aps  ($/MMBtu)

Weighted Average Floor /Swap Price by Quarter

Forecast Price by Quarter

Natural Gas Hedges

1 – As of 9/18/12

• Our 2012 natural gas hedges have locked in prices well above the forecast• Nevertheless, we are not drilling dry gas plays as the commodity remains oversupplied

Protecting our Cash Flows During Depressed Gas Price Environment

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21

1st Quarter 2nd Quarter2012 2012

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: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 

Full‐Year2012 Guidance

Average Quarter for3Q12 ‐ 4Q12

2012 Guidance TableAs of August 1, 2012

Dollars in millions, except unit data

2007 2008 2009 2010 2011 June‐11 June‐12Adjusted EBITDAX

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      

Add/Less: Derivatives (income) expense included in net income            2.0        (29.7) (31.6)      (41.9)       (15.7)      (50.8)        (8.3)      (43.5)   

Add/Less: Cash receipts (payments) to settle derivatives          14.1          29.7          (5.8)          68.5          27.4  30.6         11.8     15.0    

Add: Impairments            2.6          20.0  106.4     46.0        104.7     62.2         71.1     28.6    Add/Less: Net loss (gain) on sale of assets, other          (12.6)        (33.2)          (2.0)          (1.2)          19.1             (5.5)       23.8         (0.8)

Adjusted EBITDAX  $     201.5   $    344.7   $    115.7   $    209.0   $    219.5   $      249.7   $   94.0   $ 124.2 

dollars in millions

Year ended December 31, 6 Mos. EndedLTM2Q12

Non‐GAAP ReconciliationAdjusted EBITDAX

22

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