2. Forward‐Looking Statements, Oil and Gas Reserves and Definitions
Forward‐Looking Statements
Certain statements contained herein that are not descriptions of historical facts are “forward‐looking” statements within the meaning of Section 27A of the Securities
Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies,
actual results may differ materially from those expressed or implied by such forward‐looking statements. These risks, uncertainties and contingencies include, but are
not limited to, the following: the volatility of commodity prices for oil, natural gas liquids (NGLs) and natural gas; our ability to develop, explore for, acquire and replace
oil and gas reserves and sustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations;
any impairments, write‐downs or write‐offs of our reserves or assets; the projected demand for and supply of oil, NGLs and natural gas; reductions in the borrowing
base under our revolving credit facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline
transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertainties
inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and gas reserves; drilling and
operating risks; our ability to compete effectively against other independent and major oil and natural gas companies; our ability to successfully monetize select assets
and repay our debt; leasehold terms expiring before production can be established; environmental liabilities that are not covered by an effective indemnity or
insurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintain adequate
financial liquidity and to access adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure
events; our ability to retain or attract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations;
changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general
domestic and international economic and political conditions; and other risks set forth in our filings with the U.S. Securities and Exchange Commission (SEC).
Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC, including our Annual Report on
Form 10‐K for the year ended December 31, 2011. Readers should not place undue reliance on forward‐looking statements, which reflect management’s views only as
of the date hereof. We undertake no obligation to revise or update any forward‐looking statements, or to make any other forward‐looking statements, whether as a
result of new information, future events or otherwise.
Oil and Gas Reserves
Effective January 1, 2010, the SEC permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves, but also “probable” reserves and
“possible” reserves. As noted above, statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any
reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not
necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in
PVA’s Annual Report on Form 10‐K for the fiscal year ended December 31, 2011, which is available from PVA at Four Radnor Corporate Center, Suite 200, Radnor, PA
19087 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1‐800‐SEC‐0330 or from the SEC’s website at www.sec.gov.
Definitions
Proved reserves are those quantities of oil and gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be
economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulation
before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the
estimate is a deterministic estimate or probabilistic estimate. Probable reserves are those additional reserves that are less certain to be recovered than proved
reserves, but which are as likely than not to be recoverable (there should be at least a 50% probability that the quantities actually recovered will equal or exceed the
proved plus probable reserve estimates). Possible reserves are those additional reserves that are less certain to be recoverable than probable reserves (there should be
at least a 10% probability that the total quantities actually recovered will equal or exceed the proved plus probable plus possible reserve estimates). “3P” reserves refer
to the sum of proved, probable and possible reserves. Estimated ultimate recovery (EUR) is the sum of reserves remaining as of a given date and cumulative production
as of that date.
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3. PVA Overview
• Small‐cap domestic onshore E&P company
• Very active in the Eagle Ford Shale oil play with excellent results to date
• HBP positions in East Texas, the Mid‐Continent and Mississippi
• While transitioning to oil and liquids, we remain leveraged to an improvement in natural gas prices
• 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
3
4. 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
4
5. 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
5
6. Value Has Shifted to Oil
• In mid‐2010, PVA implemented a strategy to transition from dry gas to oil
• Since then, the decrease in gas prices and increase in oil & liquids prices has shifted the
market from a “6:1” to a “20:1” liquids‐to‐gas price environment (25:1 for oil)
• Examining revenue growth by commodity type reveals PVA’s true growth in value
Perception: “6‐to‐1” Equivalent Environment Reality: “20‐to‐1” Price Environment
Gas Producer With Little to No Production Growth Oil/NGL Producer With Revenue Growth
Pro Forma Production by Commodity Quarterly Revenue by Commodity
MMcfe per day (1 Bbl = 6 Mcfe) Pre‐Hedging; $MM
120 $90
100
14%
$68
80
~45%
60 $45
40 86%
~55% $23
20
0 $0
Oil NGLs Base Gas Shale Gas 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 August 2011
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and Appalachian assets sold in July 2012. Revenues are actual reported amounts, prior to the impact of derivatives.
7. EBITDAX and Cash Margin Growth
• 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
Quarterly EBITDAX and Cash Margins
$70 $7
$60 $6
$50 $5
$ per Mcfe
$ Millions
$40 $4
$30 $3
$20 $2
$10 $1
$0 $0
1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12
Adjusted EBITDAX ($MM) Gross Operating Margin per Mcfe
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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
8. Asset Overview
Emerging Oil and Liquids‐Rich Plays Plus “Option” in Significant Gas Plays
2012E CAPEX: $300MM ‐ $325MM
92% Eagle Ford / 30% Less than 2011
2012E Production: 37.4‐39.7 Bcfe
47% Oil & Liquids
2012E Production: 38.6 Bcfe
2011 Pro Forma Proved Reserves: 778 Bcfe
Oil / Liquids
Wet Gas
Dry Gas
8
Note: Based on 8/1/12 operational update; pro forma to exclude Appalachian proved reserves sold in July 2012
9. 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 • ~37,000 gross (≥~25,000 net) acres in
Gonzales and Lavaca Counties, TX
Condensate
Gonzales Rich Gas – Operator in Gonzales with 83% WI
– Operator in Lavaca with at least a 57% WI
San Antonio – Avg. IP/30‐day rates of 1,001/657 BOEPD
– Gonzales type curve EUR of ~400 MBOE1
Bexar Wilson Lavaca
– 84% oil, 9% NGLs and 7% gas, post processing
– Reduced proppant and chemical costs
Atascosa – Significant initial choking expected to improve
Karnes DeWitt EURs
– Initial Lavaca wells met/exceeded expectations
– Initial positive down‐spacing test of 3‐well pad
Victoria
• Up to ~200 remaining drilling locations
Goliad
– 54 wells producing
– Includes AMI locations and down‐spaced
locations
McMullen Live Oak Bee Texas • Rigs, infrastructure in place
Acreage Valuations – Dedicated rigs and frac crew
Have Increased – Increase from 2 to 3 rigs in 3Q12
Significantly in Recent – Gas gathering and processing in place
EFS Transactions
1 – Internally generated type curve based on production history of wells drilled to date by PVA in Gonzales County; YE11 reserve report was 9
prepared by Wright & Company, Inc. and reflects a type curve EUR of 341 MBOE based on the production history of the wells through YE11
10. Eagle Ford Shale
Premier Acreage Position in Volatile Oil Window; Lavaca AMI Provides Additional Upside
PVA’s Eagle Ford Acreage
Volatile Oil Window Notable PVA Results
and Potential is Well‐ Gonzales
PVA Well Name IP Rates
Positioned Based on County Gardner 1H 1,247 BOEPD
Hawn Holt 9H 1,877 BOEPD
Overall Excellent MHR Hawn Holt 10H 1,188 BOEPD
NFR Hawn Holt 11H 1,190 BOEPD
Industry Results in Area 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
Munson Ranch 6H 1,808 BOEPD
Rock Creek Ranch 1H 1,257 BOEPD
Lavaca Schaefer 3H 1,129 BOEPD
Munson Ranch 5H 1,164 BOEPD
County D. Foreman 1H 1,202 BOEPD
Henning 1H 1,115 BOEPD
Rock Creek Ranch 5H 969 BOEPD
Rock Creek Ranch 6H 960 BOEPD
EOG Effenberger #1H (Lavaca) 922 BOEPD
Schacherl #1H (Lavaca) 1,277 BOEPD
Rock Creek Ranch 9H 865 BOEPD
Rock Creek Ranch 10H 1,036 BOEPD
PVA Acreage Sralla #1H (Lavaca) 827 BOEPD
McCreary #1H (Lavaca) 1,036 BOEPD
PVA AMI with “Major”
3‐D Seismic Survey
Notable PVA Results
Notable Industry Results
10
Note: Wellhead rates (pre‐processing); production “windows” are PVA’s approximation
12. Eagle Ford Shale
Multi‐Year Inventory of Oily Locations
• 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
Producing Remaining Total Well Gross Net Acres /
Area Wells Locations Locations Acreage Acreage 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
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13. Eagle Ford Shale
Positive Trend: Volumes Up
• During 2011 and into early 2012, we have quickly ramped up the Eagle Ford Shale
• Approximately 95% of volumes are liquids ‐ primarily crude oil
• Oil is sold into the Gulf Coast LLS market through multiple purchasers–premium pricing to WTI
2011‐12 Sales Volumes by Commodity
600
500
400
MBOE
300
200
100
0
1Q11 2Q11 3Q11 4Q11 1Q12 2Q12
Net Oil Sales Net NGL Sales Net Gas Sales
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14. Gonzales County
Compelling Economics & Value at Varying Costs and Oil Prices
• 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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15. Lavaca County
Preliminary Economics & Value Look Excellent in 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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Note: Preliminary estimates of economics and EURs; excludes Vana #1H well due to it having a shorter‐than‐typical lateral length
16. Comparison of Gonzales and Lavaca Counties
• 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
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17. Why PVA?
Investment Highlights
• 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
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19. Crude Oil Hedges
Protecting 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
Crude Oil Hedges1
Swaps and Collars
4,500 $110
Weighted Average Floor /
Weighted Avg. Floors and Swaps ($/Bbl.)
Swap Price by Quarter
4,000 $105
$101 $101 $100 $100 $100 $100
$99 $99
3,500 $100
3,000 $98 $98 $95
Barrels per Day
Forecast Price by Quarter
2,500 $90
2,000 $85
1,500 $80
1,000 $75
500 $70
0 $65
3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14
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1 – As of 9/18/12
20. 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 remains oversupplied
Natural Gas Hedges1
Swaps and Collars
40 $6
Weighted Avg. Floors and Swaps ($/MMBtu)
Weighted Average Floor /
Swap Price by Quarter
$5.31
30 $5.10
$5
MMBtu per Day (000s)
20 $4
Forecast Price by Quarter
10 $3
$2.85
$2.59
0 $2
3Q12 4Q12
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1 – As of 9/18/12
21. 2012 Guidance Table
As of August 1, 2012
Dollars in millions, except unit data 1st Quarter 2nd Quarter Average Quarter for Full‐Year
2012 2012 3Q12 ‐ 4Q12 2012 Guidance
Production:
Natural gas (Bcf) 6.3 5.9 3.8 ‐ 4.4 19.8 ‐ 21.0
Crude oil (MBbls) 549 572 520 ‐ 585 2,160 ‐ 2,290
NGLs (MBbls) 215 227 166 ‐ 191 775 ‐ 825
Equivalent production (Bcfe) 10.9 10.7 7.9 ‐ 9.1 37.4 ‐ 39.7
Equivalent daily production (MMcfe per day) 119.5 117.1 86.3 98.7 102.2 ‐ 108.4
Equivalent production (MBOE) 1,812 1,775 1,324 ‐ 1,514 6,235 ‐ 6,615
Equivalent daily production (MBOE per day) 19.9 19.5 14.4 ‐ 16.5 17.0 ‐ 18.1
Percent crude oil and NGLs 42.1% 45.0% 44.3% ‐ 57.9% 43.9% ‐ 50.1%
Production revenues:
Natural gas $ 14.9 10.3 10.0 ‐ 12.4 45.2 ‐ 49.9
Crude oil $ 58.7 58.4 46.9 ‐ 53.3 211.0 ‐ 223.7
NGLs $ 9.1 7.6 5.4 ‐ 6.2 27.5 ‐ 29.0
Total product revenues $ 82.7 76.2 62.4 ‐ 71.8 283.7 ‐ 302.6
Total product revenues ($ per Mcfe) $ 7.60 7.16 7.85 ‐ 7.91 7.58 ‐ 7.62
Total product revenues ($ per BOE) $ 45.62 42.94 47.12 ‐ 47.46 45.50 ‐ 45.74
Percent crude oil and NGLs 82.0% 86.5% 80.2% ‐ 84.0% 82.4% ‐ 84.1%
Operating expenses:
Lease operating ($ per Mcfe) $ 0.84 0.87 0.82 ‐ 0.85
Lease operating ($ per BOE) $ 5.04 5.22 4.92 ‐ 5.10
Gathering, processing and transportation costs ($ per Mcfe) $ 0.38 0.41 0.34 ‐ 0.38
Gathering, processing and transportation costs ($ per BOE) $ 2.29 2.47 2.04 ‐ 2.28
Production and ad valorem taxes (percent of oil and gas revenues) 4.3% ‐0.3% 3.5% ‐ 4.0%
General and administrative:
Recurring general and administrative $ 10.5 10.4 8.8 ‐ 9.5 38.5 ‐ 40.0
Share‐based compensation $ 1.6 1.3 1.5 ‐ 1.8 6.0 ‐ 6.5
Share‐based compensation $ ‐ (0.1) 1.1 ‐ 1.6 2.0 ‐ 3.0
Total reported G&A $ 12.1 11.7 11.3 ‐ 12.8 46.5 ‐ 49.5
Exploration expense $ 8.0 9.4 9.3 ‐ 11.3 36.0 ‐ 40.0
Unproved property amortization $ 8.2 8.3 6.8 ‐ 7.8 30.0 ‐ 32.0
Depreciation, depletion and amortization ($ per Mcfe) $ 4.67 4.86 4.90 ‐ 5.10
Depreciation, depletion and amortization ($ per BOE) $ 28.04 29.14 29.40 ‐ 30.60
Adjusted EBITDAX $ 64.2 60.0 50.4 ‐ 60.4 225.0 ‐ 245.0
Capital expenditures:
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
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Total oil and gas capital expenditures $ 90.4 91.5 59.0 ‐ 71.5 300.0 ‐ 325.0
22. Non‐GAAP Reconciliation
Adjusted EBITDAX
Year ended December 31, LTM 6 Mos. Ended
2007 2008 2009 2010 2011 2Q12 June‐11 June‐12
Adjusted EBITDAX dollars in millions
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
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