PVA IPAA Investor Presentation 2012

Independent Petroleum Association of AmericaOGIS FloridaInvestor PresentationFebruary 2, 2012NYSE: PVA

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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 natural gas, natural gas liquids and oil; our ability to develop, explore for, acquire and replace oil andgas reserves and sustain production; any impairments, write‐downs or write‐offs of our reserves or assets; the projected demand for and supply of natural gas, naturalgas liquids and oil; 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 costs and to sell the production at, or at reasonablediscounts to, market prices; the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs fromestimated proved oil and gas reserves; drilling and operating risks; our ability to compete effectively against other independent and major oil and natural gascompanies; uncertainties related to expected benefits from acquisitions of oil and natural gas properties; environmental liabilities that are not covered by an effectiveindemnity or insurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintainadequate financial liquidity and to access adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including forcemajeure events; our ability to retain or attract senior management and key technical employees; counterparty risk related to their ability to meet their futureobligations; changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relatingto 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 onForm 10‐K for the year ended December 31, 2010. 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, 2010, 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 estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be economicallyproducible in future years from known oil and gas reservoirs under existing economic and operating conditions and government regulation prior to the expiration of thecontracts providing the right to operate, unless renewal of such contracts is reasonably certain. Probable reserves are those additional reserves that are less certain tobe recovered than proved reserves, but which are more likely than not to be recoverable (there should be at least a 50% probability that the quantities actuallyrecovered will equal or exceed the proved plus probable reserve estimates). Possible reserves are those additional reserves that are less certain to be recoverable thanprobable reserves (there should be at least a 10% probability that the total quantities actually recovered will equal or exceed the proved plus probable plus possiblereserve estimates). “3P” reserves refer to the sum of proved, probable and possible reserves. Estimated ultimate recovery (EUR) is the sum of reserves remaining as ofa given date and cumulative production as of that date.

Forward‐Looking Statements, Oil and Gas Reserves and Definitions

PVA Overview

• Small‐cap domestic onshore E&P company primarily active in the Eagle Ford Shale oil play with excellent results• Significant HBP positions in Cotton Valley, Haynesville Shale, Selma Chalk, and Appalachia• Also active in the Granite Wash

• PVA is executing a strategy of growth in oil and NGL rich plays• 2010 and 2011 have been transformational years, diversifying our portfolio towards oil / NGLs• Initial drilling in the Eagle Ford Shale during 2011 ‐ 31 wells on‐line as of 1/10/12• Continue to add to Eagle Ford drilling inventory – recent AMI with a “major” oil company in 

Lavaca County

• Considering ways to increase liquidity• Considering selective asset sales

• No material debt maturities until 2016; proceeds could therefore be used to reduce revolver balance

• Reducing capital expenditures• 2012 capital program is expected to be less than 2011• No anticipated natural gas drilling; focus on Eagle Ford Shale

• Continued hedging• Oil – approximately 3,000 BOPD hedged for 2012 at about $97 per barrel (wavg. floor/swap)• Gas – approximately 20,000 MMBtu hedged for 2012 at about $5.40 per MMBtu (wavg. floor/swap) 3

Gas‐to‐Oil / Liquids Has Increased Revenues and Cash Flows

PVA’s Growth Strategy is Sound

• “Gas‐to‐Oil” transition underway

• Built Eagle Ford position from initial 6,800 net acres to over 21,000 net acres in just over one year

– Up to approximately 160 remaining drilling locations

– Includes acreage and locations to be earned in recently announced AMI in Lavaca County

• Grew oil/NGL production from 2,461 Bbls/day in 2Q10 to 7,057 Bbls/day in 3Q11 (+187%)

• Other oily / liquids‐rich plays include the Cotton Valley and Granite Wash

• Substantial core gas assets retained for eventual gas price recovery

• East Texas Haynesville Shale, Mississippi Selma Chalk and Appalachia

• Make selective divestitures to increase margins, operational focus, liquidity

• Continue to expand oil and liquids reserves and drilling inventory

• Continue to grow oil and liquids production and reserves

4

$0

$20

$40

$60

$80

Pro Forma Quarterly Revenue by CommodityPre‐Hedging; $MM

Gas Oil NGLs

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• In mid‐2010, PVA implemented a strategy to transition from dry gas to oil & liquids• 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

• Examining revenue growth by commodity type reveals PVA’s true growth in value

Value Growth From 2009‐2011 Due to Drive Towards Oil & NGLs

Production Growth is Shifting to Oil/Liquids

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 to exclude South Texas and South Louisiana assets sold in January 2010 and primarily Arkoma Basin assets sold in August 2011

~35%

~65%

~60%

~40%

• EBITDAX has increased significantly since mid‐2010 when we began our strategic shift towards oil and NGL growth

• Gross operating margin per Mcfe has also improved significantly due to the increase in oil prices and declining unit cash operating expenses

Shift to Oil/Liquids Strategy Has Dramatically Improved Cash Flow Margins

EBITDAX and Cash Margin Growth

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

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30%

40%

50%

60%

70%

80%

90%

100%

PVA Peer 1 Peer 4 Peer 2 Peer 5 Peer 3

% of Target Price

Price‐to‐Mean Target Price

0.0x

2.0x

4.0x

6.0x

8.0x

PVA Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

2012E CFPS and EBITDAX Multiples

Price‐to‐2012E CFPS TEV‐to‐2012E EBITDAX

• Trades at 1.1x analysts’ mean 2012E CFPS1

– Selected peers trade at a mean of 3.3x1

• Trades at 3.0x analysts’ mean 2012E EBITDAX– Selected peers trade at a mean of 5.0x1

• Trades at 63% of analysts’ mean target price1

– Selected peers trade at mean of 73%1

1 – Sources: First Call; peers: CRK, FST, GDP, PETD and PQ; as of 1/27/12

Valuation Multiples Well Below Gas‐Levered Peers

PVA Appears Undervalued and Oversold

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Continue to increase oil and liquids exposure• 36% of 4Q11 production guidance vs. 18% in FY10

• Eagle Ford‐driven with goal to add more Eagle Ford and other oily inventory

Retain long‐term optionality of core gas assets• East Texas, Mississippi and Appalachia – largely HBP

Plan to improve liquidity and financial position• Consider selective divestitures

• Reduce capital spending

• Continue to exploit oil drilling inventory which is expected to fuel cash flow growth

• No significant debt maturities until 2016

Communicate growth and value story• Undervalued on most metrics, despite solid operations and cash flow growth

• Change perception of PVA as a gas‐weighted producer to that of an oil & liquids producer

• Common dividend yield currently about 4.8% – dividend paid for 115 years in a row

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What is Our Response?Focus on Drilling the Eagle Ford and Look to Expand Our Oil Inventory

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

Core Operating Regions

Note: Based on 11/2/11 and 12/13/11 operational updates; see Appendix

2010 Proved Reserves: 942 Bcfe

2011E CAPEX: $433MM ‐ $443MM89% Oil & Liquids‐Rich Plays

2011E Production: 46.5‐46.8 Bcfe28% Oil & Liquids; 36% in 4Q11E

Oil / Liquids

Wet Gas 

Dry Gas

2011E Production: ~47 Bcfe

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

Eagle Ford Shale

• Over 31,000 (22,000 net) acres in Gonzales and Lavaca Counties, TX1

– Operator in Gonzales with 83% WI– Operator in Lavaca with at least a 50%WI1

– Avg. IP/30‐day rates of ~1,000/700 BOEPD– Type curve EUR of approximately 400 MBOE2

– 93‐95% oil/NGLs, post processing– 4Q11 D&C costs: estimated $8.0MM per well 

(13 wells)– Reduced proppant costs and stage sizes– Avg. spud‐to‐TD / spud‐to‐sales: 22/54 days– Initial positive down‐spacing test of 3‐well pad

• Up to 160 remaining drilling locations1

– 31 wells producing ~11,300 BOEPD (~7,050 BOEPD, net) at 1/10/12

– Excludes any potential Austin Chalk locations• Rigs, infrastructure in place

– Dedicated rigs and fracturing crew– Net oil price at $4‐5/barrel premium to WTI– Gas gathering and processing in place

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

101 – Includes approximately 13,000 (6,500 net) acres and over 40 locations to be earned in the recently announced AMI in Lavaca Co.2 – Internally generated type curve based on production history of wells drilled to date by PVA

GonzalesCounty

LavacaCounty

Volatile Oil Window

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 BOEPD

Other Operators IP RatesMHR – Oryx Hunter 1H 2,044 BOEPDMHR – Kudu Hunter 1H 1,590 BOEPDMHR – Southern Hunter 1H 1,321 BOEPDMHR – Furrh 2H 1,275 BOEPDMHR – Snipe Hunter 1H 2,033 BOEPDMHR – Leopard Hunter 1H 1,333 BOEPDEOG – King Fehner Unit 1.4 – 1.7 MBOEPDEOG – Kerner Carson Unit 1.8 – 2.6 MBOEPDEOG – Hill Unit 1.6 – 2.0 MBOEPDEOG – Meyer Unit 1.9 – 3.4 MBOEPDEOG – Mitchell Unit 3.3 – 3.6 MBOEPDEOG – Central Gonzales avg. 1,465 BOEPD

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 Industry Results

1 – Includes approximately 13,000 (6,500 net) acres and over 40 locations to be earned in the recently announced AMI in Lavaca Co.Note: Industry results based on peers’ investor presentations  and reported IP wellhead rates (pre‐processing);  production “windows” are PVA’s approximation

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PVA AcreagePVA AMI with “Major”13‐D Seismic SurveyNotable PVA ResultsNotable Industry Results

$0

$2

$4

$6

$8

$10

$12

3Q11 4Q11 ‐ Prelim.

$ Millions

2H11 Drilling & Completion Costs

Average Total Well Cost Average Completion Cost

11 Wells 13 Wells

• During 2011, we quickly ramped up the Eagle Ford Shale to be our leading play• We also reduced our average well cost during the second half of 2011 which, combined with strong oil prices, has contributed to increased rates of return and margins

• The cost decline is due primarily to drilling efficiencies and altered completion design

Positive Trends: Volumes Up, Costs Down

Eagle Ford Shale

0

100

200

300

400

500

1Q11 2Q11 3Q11 4Q11 ‐ Prelim.

MBO

E

2011 Net Sales Volumes by Commodity

Net Oil Sales Net NGL Sales Net Gas Sales

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• Current type curve EUR of ~400 MBOE; previously ~280 MBOE• Assuming $8.0 MM drilling and completion costs, the pre‐tax rate of return for our average Eagle Ford well is approximately 50% at $100 flat oil

• Typical completion consists of 15‐16 stages over 4,000’ lateral• Efforts will continue to lower well costs, as well as to enhance production performance

0

100

200

300

400

500

600

700

800

0 6 12 18 24 30 36

BOEP

D

Production Month

Eagle Ford Shale ‐ Gonzales Type Curve

  Current Type Curve (~400 MBOE)  Old (Exponential) Type Curve (~280 MBOE)

Gonzales Type Curve Supported by Actual Wells Results

Eagle Ford Shale

Note: Internally generated type curve based on production history of wells drilled to date by PVA13

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2007 ‐ 2011 Capital Spending Increasingly Allocated to Oil & NGLs

Spending Less Overall, But More in Oil & Liquids

Note: 2011 data based on guidance announced 11/2/11; see Appendix

• In 2010 we focused CAPEX on drilling in the Granite Wash with high rates of return• For 2011 and beyond, we’ll be focused on drilling and expanding our position in the 

Eagle Ford Shale and, potentially, other oily or liquids‐rich play types

• Diversified and valuable portfolio of high‐quality assets

• Track record of low‐cost, high‐return operations

• Drilling and acquisitions focused on high return play types

• Successful transition from dry gas to oil and liquids

• Ample supply of economic drilling locations

• Retained optionality of natural gas assets

• Compelling value proposition

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Why PVA?Investment Highlights

Appendix

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High‐Margin, Liquid‐Rich Reserves and Production

Mid‐Continent: Liquids‐Rich Play Types

Anadarko Basin• Positioning

– CHK development drilling JV• ~10,000 net acres in Washita Co.• Operate about one‐third; ~28% WI• ~80 drilling locations in JV as of YE10

– ~40,000 net acres in other exploratory plays• Viola test in 1H12 (oily)

• Reserve Characteristics / Geology– Granite Wash: 48% liquids; attractive IRRs– Historical EURs > 5.0 Bcfe; assuming 4.0 Bcfe 

for remaining wells– $1.66 PV10 breakeven gas price ($90 per 

barrel oil price)• 2011 Activity

– Up to 20 (8.7 net) Granite Wash wells– Non‐operated drilling– Up to $89MM of CAPEX (20% of total)

Note: Based on 11/2/11 and 12/13/11 operational updates

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Low‐Cost, High‐Potential, Largely HBP Natural Gas

• ETX ‐ Horizontal Cotton Valley– 5.0 Bcfe PUDs; 35% liquids– $3.82 PV10 breakeven gas price– 79 gross drilling locations– 267 Bcfe of 3P reserves at YE10

• ETX ‐ Haynesville Shale– 6.7 Bcfe PUDs; dry gas– $3.14 PV10 breakeven gas price– 183 gross drilling locations– 505 Bcfe of 3P reserves at YE10

• Mississippi ‐ Selma Chalk– 1.7 Bcfe PUDs; dry gas– $3.83 PV10 breakeven gas price– 183 gross drilling locations– 279 Bcfe of 3P reserves at YE10

East Texas & Mississippi: Gas Optionality

Cotton Valley / Haynesville Shale

Selma Chalk

YE10 Summary of Gas Option445 gross locations

1.1 Tcfe of 3P reserves

Wet Gas 

Dry Gas

$96.86  $97.58  $97.37  $96.60  $96.60 $94.54  $94.54 

$90.00  $90.00 $91.67 

$90.00  $90.00  $90.00  $90.00  $90.00  $90.00  $90.00  $90.00 

$65

$70

$75

$80

$85

$90

$95

$100

$105

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13

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

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Crude Oil HedgesProtecting our Capital Budget and Well Economics

• We have 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 2012‐2013

1 – As of 1/26/12

$5.67  $5.70 

$5.31  $5.31 $5.10 

$3.70 

$2.70  $2.70  $2.70  $2.70 

$0

$2

$4

$6

0

20

40

60

4Q11 1Q12 2Q12 3Q12 4Q12

MMBtu pe

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

20

Natural Gas Hedges

1 – As of 1/26/12

• Our 2012 natural gas hedges have locked in prices well above the forecast ($2.70/MMBtu)• Nevertheless, we are not drilling dry gas plays as the commodity remain oversupplied

Protecting our Cash Flows During Depressed Gas Price Environment

1Q ‐ 3Q2011

Production:Natural gas (Bcf)  26.6 6.8 ‐  7.0 33.5 ‐  33.7Crude oil (MBbls) 833 428 ‐  440 1,261 ‐  1,273NGLs (MBbls)  695 214 ‐  220 909 ‐  915Equivalent production (Bcfe) 35.8 10.7 ‐  11.0 46.5 ‐  46.8Equivalent daily production (MMcfe per day) 131.2 116.3 ‐  119.6 127.4 ‐  128.3Percentage crude oil and NGLs 25.6% 36.0% ‐  36.0% 28.0% ‐  28.0%

Operating expenses:Lease operating ($ per Mcfe) $ 0.82 0.73 ‐  0.81 0.80 ‐  0.82Gathering, processing and transportation costs ($ per Mcfe) $ 0.31 0.26 ‐  0.30 0.30 ‐  0.31Production and ad valorem taxes (percent of product revenues) 5.1% 5.0% ‐  5.5% 5.0% ‐  5.5%General and administrative:  Recurring general and administrative $ 31.7 9.0 ‐  9.5 40.7 ‐  41.2  Share‐based compensation $ 5.6 1.5 ‐  2.0 7.1 ‐  7.6  Restructuring $ 1.7 0.6  ‐  0.8 2.3  ‐  2.5

Total reported G&A $ 39.0 11.1 ‐  12.3 50.1 ‐  51.3Exploration:  Dry hole costs $ 18.9 0.0 ‐  0.2 18.9 ‐  19.1  Unproved property amortization $ 33.6 11.0 ‐  11.5 44.6 ‐  45.1  Other $ 15.7 2.0  ‐  4.0 17.7  ‐  19.7

Total reported exploration $ 68.2 13.0 ‐  15.7 81.2 ‐  83.9

Depreciation, depletion and amortization ($ per Mcfe) $ 3.16 4.67 ‐  4.86 3.55 ‐  3.60

Capital expenditures:Development drilling  $ 207.9 95.0 ‐  100.0 302.9 ‐  307.9Exploratory drilling $ 53.2 6.0 ‐  7.0 59.2 ‐  60.2Pipeline, gathering, facilities $ 6.3 4.0 ‐  6.0 10.3 ‐  12.3Seismic  $ 9.0 1.0 ‐  2.0 10.0 ‐  11.0Lease acquisitions, field projects and other $ 46.4 4.0  ‐  5.0 50.4  ‐  51.4  Total oil and gas capital expenditures $ 322.8 110.0 ‐  120.0 432.8 ‐  442.8

2011 GuidanceFull‐YearFourth Quarter

2011 Guidance

2011 Guidance TableAs of December 13, 2011

Dollars in millions, except per unit data21

2006 2007 2008 2009 2010 Sep‐10 Sep‐11Adjusted EBITDAX

Net income (loss) from continuing operations $       44.2  $      26.5  $      93.6   $  (130.9) $    (65.3) $    (129.8) $  (40.5) $(105.0)

Add: Income tax expense (benefit)          50.0          30.5          55.6         (85.9) (42.9)      (76.2)        (27.0)    (60.4)   

Add: Interest expense            6.0          20.1          24.6           44.2  53.7       55.3         40.2     41.8    

Add: Depreciation, depletion and amortization          56.7          88.0        135.7  154.4      134.7     152.6       95.4     113.2  

Add: Exploration          34.3          28.6          42.4  57.8        49.6       80.3         37.6     68.2    

Add: Share‐based compensation expense            1.1            1.6            6.0  9.1          7.8         7.0           6.4       5.6      

Add/Less: Derivatives (income) expense included in net income         (30.7)           2.0        (29.7) (31.6)       (41.9)      (17.3)        (44.4)    (19.8)   

Add/Less: Cash receipts (payments) to settle derivatives          10.5          14.1          (7.6)          58.1          32.8  28.8         24.3     20.3    

Add: Impairments            8.5            2.6          20.0  106.4      46.0       80.8         36.3     71.1    

Add/Less: Net loss (gain) on sale of assets, other                ‐          (12.6)        (33.2)          (2.0)          (1.2)            22.4         (1.4)       22.2 

Adjusted EBITDAX  $     180.6   $    201.5   $    307.4   $    179.7   $    173.3   $      203.9   $ 126.8   $ 157.3 

dollars in millions

Year ended December 31, 9 Mos. EndedLTM3Q11

22

Non‐GAAP ReconciliationsAdjusted EBITDAX

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