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 natural gas, NGLs and oil; our ability to develop, explore for 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 natural gas, NGLs 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 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 regulation
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 will be 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 economically
producible in future years from known oil and gas reservoirs under existing economic and operating conditions and government regulation prior to the expiration of the
contracts providing the right to operate, unless renewal of such contracts is reasonably certain. Probable reserves are those additional reserves that are less certain to
be 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 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.
2
3. PVA Overview
• Small‐cap domestic onshore E&P company
• Active in the Eagle Ford Shale oil play with excellent results to date: YE11 PV‐10 of $278 MM
• HBP positions in Granite Wash, East Texas, Mississippi and Appalachia: YE11 PV‐10 of $596 MM
• 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
• Successful drilling results in the Eagle Ford Shale – 35 wells on‐line as of 2/23/12
• Adding to Eagle Ford drilling inventory – recent AMI in Lavaca County
• Considering ways to increase liquidity
• Considering a significant asset sale during 1H12
• 2012 CAPEX fully‐funded; no material debt maturities until 2016; pending borrowing base expected to be
similar to current commitment amount of $300 MM in April 2012
– Immediate liquidity of approximately $183 MM at 2/23/12 and 2012E cash flow outspend of $107‐157 MM
• Asset sale proceeds would reduce bank debt and increase liquidity – preclude any need for capital markets
• Reduced capital expenditures
• 2012 capital program of $300‐325 MM is 27‐33% less than $446 MM in 2011
• 85% Eagle Ford (oily) and 8% Granite Wash (NGLs/oil) ‐ no natural gas drilling due to very weak prices
• Continued hedging
• Oil: 62% hedged for 2012 at weighted average of $99.40 per barrel (floor/swap)
• Gas: 31% hedged for 2012 at weighted average of $5.43 per MMBtu (floor/swap)
• 2013: 2,560 BOPD hedged at weighted average of $96.21 per barrel (floor/swap); no gas hedges 3
4. PVA’s Growth Strategy is Sound
Gas‐to‐Oil / Liquids Has Increased Revenues and Cash Flows
• We commenced our “Gas‐to‐Oil” transition in mid‐2010
• Built Eagle Ford position from initial 6,800 net acres to at least 23,000 net acres in just over one year
– Up to approximately 190 well locations (39 drilled and up to ~150 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 7,194 Bbls/day in 4Q11 (+192%)
– Up 43% from 5,033 Bbls/day in 4Q10
• Other oily / liquids‐rich plays include the Cotton Valley and Granite Wash
• Retain substantial core gas assets 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
• Will test a horizontal oil prospect in the Mid‐Continent in the 2nd quarter
• Continue to grow oil and liquids production and cash flows
4
5. Value Has Shifted to Oil/Liquids
Value Growth From 2009‐2012 Due to Drive Towards Oil & NGLs
• 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
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 2008 ‐ 2012 Production by Commodity Pro Forma Quarterly Revenue by Commodity
MMcfe per day (1 Bbl = 6 Mcfe) Pre‐Hedging; $MM
160 $80
120 $60
~70%
~40%
80 $40
40 $20
~60%
~30%
0 $0
Base Gas Shale Gas Oil NGLs Gas Oil NGLs
5
Note: Pro forma to exclude South Texas and South Louisiana assets sold in January 2010 and primarily Arkoma Basin assets sold in August 2011
6. EBITDAX and Cash Margin Growth
Shift to Oil/Liquids Strategy Has Dramatically Improved Cash Flow Margins
• 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 operating costs per unit
Quarterly EBITDAX and Cash Margins
$70 $7
$60 $6
$50 $5
$ per Mcfe
$ Millions
$40 $4
$30 $3
$20 $2
$10 $1
$0 $0
1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11
Adjusted EBITDAX ($MM) Gross Operating Margin per Mcfe 6
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
7. PVA Appears Undervalued and Oversold
Valuation Multiples Below Peers Who are Also Leveraged, But Have Less Oil and Liquids
• Trades at 1.3x analysts’ mean 2012E CFPS1
– Selected peers trade at a mean of 3.6x1
• Trades at 3.5x analysts’ mean 2012E EBITDAX
– Selected peers trade at a mean of 5.5x1
• Trades at 71% of analysts’ mean target price1
– Selected peers trade at mean of 79%1
2012E CFPS and EBITDAX Multiples % of Target Price
8.0x 90%
80%
6.0x
70%
4.0x 60%
50%
2.0x
40%
0.0x 30%
PVA Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 PVA Peer 1 Peer 3 Peer 4 Peer 2 Peer 5
Price‐to‐2012E CFPS TEV‐to‐2012E EBITDAX Price‐to‐Mean Target Price
7
1 – Sources: First Call; peers: CRK, FST, GDP, PETD and PQ; as of 2/23/12
8. What is Our Response?
Continued Momentum Towards Oil and NGL, Higher Revenues and Margins
Continue to increase oil and liquids exposure
• 37% of 4Q11 production vs. 18% in FY10; ~50% by 4Q12
• 42% of 2012E production and 78% of 2012E product revenues
• Eagle Ford‐driven with long‐term goal to add more of this play and other oily inventory
Retain long‐term optionality of core gas assets
• East Texas, Mississippi, Granite Wash and Appalachia – largely HBP
Improve liquidity and financial position
• Fully‐funded 2012 CAPEX plan, looking to make a 1H12 asset sale to boost liquidity
Communicate story: stress attractive valuation, leverage to oil
and liquids, and retained exposure to gas price recovery
• 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 4.5% – attractive relative to other E&P firms who
typically pay zero dividends
8
9. Core Operating Regions
Emerging Oil and Liquids‐Rich Plays Plus “Option” in Significant Gas Plays
2012E CAPEX: $300MM ‐ $325MM
~85% Eagle Ford / ~30% Less than 2011
2012E Production: 40.0‐43.0 Bcfe
~42% Oil & Liquids; ~50% in 4Q12E
2012E Production: 41.5 Bcfe
2011 Proved Reserves: 883 Bcfe
Oil / Liquids
Wet Gas
Dry Gas
9
Note: Based on 2/22/12 operational update; see Appendix
10. Eagle Ford Shale
The Most Economic Eagle Ford Shale Wells are in the Volatile Oil & Condensate Rich Gas Windows
Premier Shale Oil & Liquids Play Volatile Oil • 31,400 (≥23,100 net) acres in Gonzales and
Lavaca Counties, TX1
Condensate
Gonzales Rich Gas – Operator in Gonzales with 83% WI
– Operator in Lavaca with at least a 57%WI1
San Antonio – Avg. IP/30‐day rates of 1,025/675 BOEPD
Wilson Lavaca – Type curve EUR of ~400 MBOE2
Bexar
– 89% oil, 5% NGLs and 5% gas, post processing
– 4Q11 D&C costs: estimated $8.0MM per well
Atascosa
– Reduced proppant costs and stage sizes
Karnes DeWitt
– Avg. spud‐to‐TD / spud‐to‐sales: 22/54 days
– Initial positive down‐spacing test of 3‐well pad
Victoria • Up to ~150 remaining drilling locations1
Goliad – 35 wells producing ~10,000 BOEPD (~6,300
BOEPD, net); 3 wells completing & 1 well WOC
– Excludes any potential Austin Chalk locations
Texas • Rigs, infrastructure in place
McMullen Live Oak Bee
– Dedicated rigs and fracturing crew
Acreage Valuations – Net oil price at $8‐10/barrel premium to WTI
Have Increased
– Gas gathering and processing in place
Significantly in Recent
EFS Transactions
1 – Includes approximately 13,500 (8,025 net) acres and up to 40 potential 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
10
11. Eagle Ford Shale
Premier Acreage Position in Volatile Oil Window; Lavaca AMI Provides Additional Upside
PVA’s Eagle Ford Acreage
Volatile Oil Window
and Potential is Well‐ Gonzales
Notable PVA & Industry Results
Positioned Based on County
PVA Well Name IP Rates
Overall Excellent MHR Gardner 1H 1,247 BOEPD
Hawn Holt 9H 1,877 BOEPD
Industry Results in Area Hawn Holt 10H 1,188 BOEPD
Hawn Holt 11H 1,190 BOEPD
Hawn Holt 12H 1,495 BOEPD
Hawn Holt 13H 1,399 BOEPD
Hawn Holt 15H 1,298 BOEPD
Munson Ranch 1H 1,921 BOEPD
Munson Ranch 3H 1,538 BOEPD
Munson Ranch 4H 1,416 BOEPD
Lavaca Munson Ranch 6H
Rock Creek Ranch 1H
1,808 BOEPD
1,257 BOEPD
County Schaefer 3H 1,129 BOEPD
Munson Ranch 5H 1,164 BOEPD
Other Operators IP Rates
EOG MHR – Oryx Hunter 1H 2,044 BOEPD
MHR – Kudu Hunter 1H 1,590 BOEPD
MHR – Southern Hunter 1H 1,321 BOEPD
MHR – Furrh 2H 1,275 BOEPD
PVA Acreage MHR – Snipe Hunter 1H
MHR – Leopard Hunter 1H
2,033 BOEPD
1,333 BOEPD
PVA AMI with “Major”1 EOG – King Fehner Unit 1.4 – 1.7 MBOEPD
EOG – Kerner Carson Unit 1.8 – 2.6 MBOEPD
3‐D Seismic Survey EOG – Hill Unit 1.6 – 2.0 MBOEPD
EOG – Meyer Unit 1.9 – 3.4 MBOEPD
Notable PVA Results EOG – Mitchell Unit 3.3 – 3.6 MBOEPD
EOG – Central Gonzales avg. 1,465 BOEPD
Notable Industry Results
11
1 – Includes approximately 13,500 (8,025 net) acres and up to 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
12. Eagle Ford Shale
Positive Trends: Volumes Up, Costs Down
• During 2011 and into early 2012, we have quickly ramped up the Eagle Ford Shale
• 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
2011‐2012 Sales Volumes by Commodity 2H11 Drilling & Completion Costs
600 $12
500 $10
400 $8
$ Millions
MBOE
300 $6
200 $4
11 Wells 13 Wells
100 $2
0 $0
1Q11 2Q11 3Q11 4Q11 Jan 2012 3Q11 4Q11
x 2.9*
Net Oil Sales Net NGL Sales Net Gas Sales Average Total Well Cost Average Completion Cost
12
* January 2012 production multiplied by 91/31 or 2.9x
13. Eagle Ford Shale
Gonzales Type Curve Supported by Actual Wells Results
• Current type curve EUR of ~400 MBOE; previously ~280 MBOE
• Assuming $8.0 MM well costs, the pre‐tax rate of return for our average Eagle Ford well
is approximately 50% at $100 flat oil, with $6MM of NPV (BTAX)
• Typical completion consists of 15‐16 stages over 4,000’ lateral
• Efforts will continue to drive down drilling and completion costs
Eagle Ford Shale ‐ Gonzales Type Curve
800
700
Current Type Curve (~400 MBOE)
600
Old (Exponential) Type Curve (~280 MBOE)
500
BOEPD
400
300
200
100
0
0 6 12 18 24 30 36
Production Month
Note: Internally generated type curve based on production history of wells drilled to date by PVA
13
14. Why PVA?
Investment Highlights
• 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
14
16. Mid‐Continent: Liquids‐Rich Play Types
High‐Margin, Liquid‐Rich Reserves and Production
• Positioning
Anadarko Basin – CHK development drilling JV
• ~10,000 net acres in Washita Co.
• operate about one‐third; ~28% WI
– ~40,000 net acres in other exploratory plays
• Viola Lime 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 PV‐10 breakeven gas price ($90 per
barrel oil price)
• 2012 Activity
– Up to 7 (2.3 net) Granite Wash wells and
1 (0.5 net) Viola Lime test well
– Granite Wash non‐operated drilling
– Up to $20‐25MM of CAPEX (~8% of total)
16
Note: Based on 2/22/12 operational update
17. Crude Oil Hedges
Protecting 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
Crude Oil Hedges1
Swaps and Collars
4,500 $110
Weighted Avg. Floors and Swaps ($/Bbl.)
4,000 $105
Weighted Average Floor /
$99.79 $99.59 $99.59 Swap Price by Quarter
3,500 $98.53 $100
$96.65 $96.53 $95.90 $95.62
3,000 $95
Barrels per Day
Forecast Price by Quarter
2,500 $90
2,000 $85
1,500 $80
1,000 $75
500 $70
0 $65
1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13
17
1 – As of 2/23/12
18. Natural Gas Hedges
Protecting our Cash Flows During Depressed Gas Price Environment
• Our 2012 natural gas hedges have locked in prices well above the forecast
• Nevertheless, we are not drilling dry gas plays as the commodity remain oversupplied
Natural Gas Hedges1
Swaps and Collars
40 $6
Weighted Avg. Floors and Swaps ($/MMBtu)
Weighted Average Floor /
$5.70 Swap Price by Quarter
$5.31 $5.31
30 $5.10
$5
MMBtu per Day (000s)
20 $4
Forecast Price by Quarter
$3.36
$3.03
10 $2.87 $3
$2.74
0 $2
1Q12 2Q12 3Q12 4Q12
18
1 – As of 2/23/12
19. 2012 Guidance Table
As of February 22, 2011
4th Quarter Full Year Full‐Year
Dollars in millions, except unit data 2011 2011 2012 Guidance
Production:
Natural gas (Bcf) 6.8 33.4 23.5 ‐ 24.4
Crude oil (MBbls) 450 1,283 2,000 ‐ 2,275
NGLs (MBbls) 212 907 750 ‐ 825
Equivalent production (Bcfe) 10.7 46.6 40.0 ‐ 43.0
Equivalent daily production (MMcfe per day) 116.7 127.5 109.3 ‐ 117.5
Equivalent production (MBOE) 1,789 7,759 6,667 ‐ 7,167
Equivalent daily production (MBOE per day) 19.4 21.3 18.2 ‐ 19.6
Percent crude oil and NGLs 37.0% 28.2% 41.3% ‐ 43.3%
Production revenues:
Natural gas $ 23.4 137.1 66.5 ‐ 69.1
Crude oil $ 44.3 119.6 189.0 ‐ 215.0
NGLs $ 9.6 43.4 32.0 ‐ 35.2
Total product revenues $ 77.4 300.0 287.5 ‐ 319.2
Total product revenues ($ per Mcfe) $ 7.20 6.45 7.19 ‐ 7.42
Total product revenues ($ per BOE) $ 43.23 38.67 43.12 ‐ 44.54
Percent crude oil and NGLs 69.7% 54.3% 76.9% ‐ 78.4%
Operating expenses:
Lease operating ($ per Mcfe) $ 0.70 0.79 0.80 ‐ 0.85
Lease operating ($ per BOE) $ 4.17 4.77 4.80 ‐ 5.10
Gathering, processing and transportation costs ($ per Mcfe) $ 0.36 0.33 0.28 ‐ 0.33
Gathering, processing and transportation costs ($ per BOE) $ 2.18 1.95 1.68 ‐ 1.98
Production and ad valorem taxes (percent of oil and gas revenues) 3.1% 4.6% 4.0% ‐ 4.5%
General and administrative:
Recurring general and administrative $ 6.9 38.5 39.0 ‐ 41.0
Share‐based compensation $ 1.8 7.4 6.5 ‐ 7.0
Restructuring $ 0.7 2.4
Total reported G&A $ 9.4 48.3 45.5 ‐ 48.0
Exploration expense $ 10.7 78.9 43.0 ‐ 46.0
Unproved property amortization $ 8.5 42.0 36.0 ‐ 38.0
Depreciation, depletion and amortization ($ per Mcfe) $ 4.59 3.49 4.75 ‐ 5.25
Depreciation, depletion and amortization ($ per BOE) $ 27.56 20.95 28.50 ‐ 31.50
Adjusted EBITDAX $ 62.2 219.5 200.0 ‐ 240.0
Net cash provided by operating activities $ 41.6 144.7 175.0 ‐ 205.0
Capital expenditures:
Development drilling $ 99.9 307.8 240.0 ‐ 245.0
Exploratory drilling $ 10.9 64.1 30.0 ‐ 35.0
Pipeline, gathering, facilities $ 6.2 12.5 5.0 ‐ 10.0
Seismic $ 2.2 11.2 5.0 ‐ 10.0
Lease acquisitions, field projects and other $ 3.6 50.0 20.0 ‐ 25.0 19
Total oil and gas capital expenditures $ 122.8 445.6 300.0 ‐ 325.0
20. Non‐GAAP Reconciliations
Adjusted EBITDAX
Year ended December 31,
2006 2007 2008 2009 2010 2011
Adjusted EBITDAX dollars in millions
Net income (loss) from continuing operations $ 44.2 $ 26.5 $ 93.6 $ (130.9) $ (65.3) $ (132.9)
Add: Income tax expense (benefit) 50.0 30.5 55.6 (85.9) (42.9) (88.2)
Add: Interest expense 6.0 20.1 24.6 44.2 53.7 56.2
Add: Depreciation, depletion and amortization 56.7 88.0 135.7 154.4 134.7 162.5
Add: Exploration 34.3 28.6 42.4 57.8 49.6 78.9
Add: Share‐based compensation expense 1.1 1.6 6.0 9.1 7.8 7.4
Add/Less: Derivatives (income) expense included in net income (30.7) 2.0 (29.7) (31.6) (41.9) (15.7)
Add/Less: Cash receipts (payments) to settle derivatives 10.5 14.1 (7.6) 58.1 32.8 27.4
Add: Impairments 8.5 2.6 20.0 106.4 46.0 104.7
Add/Less: Net loss (gain) on sale of assets, other ‐ (12.6) (33.2) (2.0) (1.2) 19.1
Adjusted EBITDAX $ 180.6 $ 201.5 $ 307.4 $ 179.7 $ 173.3 $ 219.5
20
