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 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. State of the Oil & Gas Industry
• Sustained high global oil prices
• Global demand remains solid
• Tensions in the Middle East and North Africa continue to weigh on oil prices
• Increasing demand for oil in emerging countries
• Domestic supply is now increasing whereas imports have decreased from ~65% to less than 50% of
demand
• Natural gas prices near 10‐year low levels with little to no relief in sight
• Record storage inventory
• Domestic supply continues to grow primarily associated with “shale” plays
• Drilling rig count reduction has begun to occur only recently; shut‐ins not prevalent yet
• No legitimate near‐term possibility for increased gas demand – longer term solution
• Efforts are underway in the industry to reduce gas drilling and production,
with most E&Ps attempting to shift capital to oily or liquids‐rich plays
• Property values for oil prospects are at a premium
• Private equity money is plentiful
• Drilling expansion of oily resource plays continue – MS Lime, Marcellus, Utica, Eagle Ford, Niobrara,
Bakken, New Albany
3
4. Oil and Gas Industry Overview
Since 2009, Spot Gas Prices Have Collapsed,
Gas Production Has Grown 30% Since 2007
Meanwhile Spot Oil Prices Have Boomed
Gross U.S. Natural Gas Production (2005 - 2012)
75
70
65
Gas Production- Bcf/d
60
55
50
45
40
35
30
2005 2006 2007 2008 2009 2010 2011 2012
Total (Lower 48) Onshore (Lower 48)
(Source: EIA/DOE; EIA‐914 Estimate)
Gas Storage is at “Multi‐Decade” Highs With the Gas Drilling Has Only Recently Declined; However, Wet Gas
“Fixes” Both Uncertain and Likely Not Near‐Term Plays/Horizontal Efficiency Have Kept Gas Supply High
2,250
2,000
1,750
Rig Count 1,500
1,250
1,000
750
500
250
0
2007 2008 2009 2010 2011 2012
Total Horizontal Oil Gas 4
5. PVA Overview
• Small‐cap domestic onshore E&P company
• Very 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
• Still significantly leveraged to natural gas prices
• PVA is executing a strategy of growth in oil and NGL rich plays
• 2010 and 2011 were transformational years, diversifying our portfolio towards oil / NGLs
• Successful drilling results in the Eagle Ford Shale – 44 wells on‐line
• Adding to Eagle Ford drilling inventory – recent AMI in Lavaca County and exploration under way
• Strategy has resulted in excellent growth in EBITDAX and cash operating margins
• Focused on improving liquidity
• Have launched asset sale process – expect to close in early third quarter
• Borrowing base of $300 MM following April 2012 redetermination/$180 MM of liquidity at 1Q12
• Have reduced capital spending in 2012 – 30% less than 2011
• Oil: ~70% hedged for balance of 2012 at weighted average price of $102 per barrel
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6. PVA’s Growth Strategy is Sound
Gas‐to‐Oil / Liquids Has Increased Revenues and Cash Flows
• Commenced our “Gas‐to‐Oil” transition in mid‐2010
• Built Eagle Ford position from initial 6,800 net acres to in excess of 23,000 net acres currently
– Up to approximately 190 well locations
– Includes acreage and locations expected to be earned in recently announced AMI in Lavaca County
• Grew oil/NGL production from 2,461 Bbls/day in 2Q10 to 8,387 Bbls/day in 1Q12 (+241%)
– Up 17% from 7,194 Bbls/day in 4Q11
– 42% of total production and 82% of product revenues
– Oil production alone grew 22% from 4Q11 to 1Q12
• Other oily / liquids‐rich plays include the Cotton Valley and Granite Wash
• Retain substantial core gas assets for eventual gas price recovery
• Haynesville Shale, Cotton Valley, Mississippi Selma Chalk, and Marcellus
• Make selective divestitures to improve operational focus and liquidity
• Have launched Mid‐Continent asset sale process – expect to close in early third quarter
• Continue to expand oil and liquids reserves and drilling inventory
• Will test a horizontal Viola oil prospect in the Mid‐Continent in 2012
• Continue to grow oil and liquids production and cash flows
• Eagle Ford drilling emphasis in 2012
• Continued focus on optimizing drilling, completion and operating costs
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7. PVA Overview
Emerging Oil and Liquids‐Rich Plays Plus “Option” in Significant Gas Plays
2012E CAPEX: $300MM ‐ $325MM
~89% Eagle Ford / ~30% Less than 2011
2012E Production: 40.0‐43.0 Bcfe
~43% Oil & Liquids
2012E Production: 41.5 Bcfe
2011 Proved Reserves: 883 Bcfe
Oil / Liquids
Wet Gas
Dry Gas
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Note: Based on 5/2/12 operational update; see Appendix
8. Value Has Shifted to Oil
Value Growth From 2009‐2012 Due to Drive Towards 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 (50:1 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 Pro Forma Quarterly Revenue by Commodity
MMcfe per day (1 Bbl = 6 Mcfe) Pre‐Hedging; $MM
160 $90
120 $68
82%
~43%
80 $45
40 $23
~57%
18%
0 $0
Base Gas Shale Gas Oil NGLs Gas Oil NGLs
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Note: Pro forma to exclude South Texas and South Louisiana assets sold in January 2010 and primarily Arkoma Basin assets sold in August 2011
9. 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 growth
• Gross operating margin per Mcfe has also improved significantly due to the increase in
oil prices and declining operating costs per unit
• Eagle Ford margin almost $15 per Mcfe
Quarterly EBITDAX and Cash Margins
$70 $7
$60 $6
$50 $5
$ per Mcfe
$ Millions
$40 $4
$30 $3
$20 $2
$10 $1
$0 $0
1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12
Adjusted EBITDAX ($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
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 1,001/645 BOEPD
Wilson Lavaca – Type curve EUR of ≥400 MBOE2
Bexar
– 88% oil, 6% NGLs and 6% gas, post processing
– 1Q12 D&C costs: estimated $7.5MM per well
Atascosa
– Reduced proppant costs and stage sizes
Karnes DeWitt
– Initial Lavaca wells met/exceeded expectations
– Initial positive down‐spacing test of 3‐well pad
Victoria • Up to ~150 remaining drilling locations1
Goliad – 44 wells producing ~12,000 BOEPD
(>7,000 BOEPD, net)
• Rigs, infrastructure in place
McMullen Live Oak Bee Texas – Dedicated rigs and fracturing crew
Acreage Valuations – Current oil price at ~$9/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.
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2 – Internally generated type curve based on production history of wells drilled to date by PVA; year‐end 2011 reserve report was prepared by
Wright & Company, Inc. and reflects a type curve of 341 MBOE based on the production history of the wells through year‐end 2011
11. PVA’s Catalysts / Challenges
• Challenges
• Managing liquidity in light of our higher cost of capital
• Maintaining three‐plus years of oily drilling inventory
• Very capital intensive industry
• Catalysts
• Eagle Ford exploratory success in Lavaca County, TX
• Strong Eagle Ford development drilling results
• Success in lowering Eagle Ford drilling and completion costs
• Increasing Eagle Ford production, margins and cash flows
• Mid‐Continent sale process will increase liquidity and reduce leverage
• Mid‐Continent oil prospect will be drilled and completed in 3Q12
• Attractive natural gas asset base that is primarily HBP
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