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, natural gas liquids (NGLs) and oil; our ability to develop, explore for, acquire and replace
oil and gas 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,
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; uncertainties
related to expected benefits from acquisitions of oil and natural gas properties; 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 the other risks, uncertainties and contingencies set forth in PVA’s Annual Report on Form 10‐K for the fiscal year
ended December 31, 2010.
Additional information concerning these and other factors can be found in our press releases and public periodic filings with the U.S. Securities and Exchange
Commission (SEC), including our Annual Report on Form 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 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, 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 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
• PVA is positioned in a number of prominent oil and gas plays in the U.S.
• Active in the Eagle Ford Shale, Granite Wash and Marcellus Shale
• Significant HBP positions in the Cotton Valley, Haynesville Shale, Selma Chalk and Appalachia
• PVA is executing a strategy of growth in oil and NGL rich plays
• 2010 and 2011 have been transformational years, diversifying our portfolio
• Initial well drilled in the Eagle Ford Shale in February and up to 34 wells planned for 2011
• Continuing to add to drilling inventory
• PVA is financially sound
• Ample liquidity to fund 2011 and 2012 drilling program
• Very little drawn on the revolver with a $380 million borrowing base
• No material debt maturities in the next five years
• High rate of return projects are increasing cash flow, borrowing base and liquidity
3
4. PVA’s Growth Strategy is Sound
Cash Flow Ramp Expected, Along With Higher Oil/Liquids Reserves and Production
• “Gas‐to‐Oil” transition underway
• Built Eagle Ford position from initial 4,000 acres to current 14,700 acres in one year
• Grown oil/NGL production from 2,461 Bbls/day in Q210 to 5,187 Bbls/day in Q211 (+111%)
• Rated among the highest‐return drillers in 2010
• Other oily / liquids‐rich plays include the horizontal Cotton Valley and Granite Wash
– Current PV‐10 value for producing wells in both of these plays of $307MM1
• Substantial core gas assets retained for eventual gas price recovery
• Haynesville Shale in east Texas, Selma Chalk in Mississippi and Appalachia
– Largely HBP with current PV‐10 value for producing wells of $393MM1
• Divestitures increase margins and operational focus, enhance liquidity
• Nearly $530MM in non‐core asset divestitures from 2009 to 2011
• Efforts continue to expand oil/liquids reserves and drilling inventory
• May include play types in new areas
• Expected growth in cash flows should drive recovery in equity valuation
4
1 – Pretax PV‐10 of YE10 proved developed producing reserves at futures strip pricing at close on 10/7/11
5. PVA is Financially Sound
Liquidity and Cash Flows Among Best for High‐Growth, Small‐Cap E&Ps
Conservative Leverage
• Liquidity is strong; expected to increase
• Immediate liquidity of $264MM at June 30, 2011, 4.5x 45%
4.0x 37.9% 40%
expected to grow with cash flow ramp 35.9% 35.6%
3.5x 31.6% 35%
• Current borrowing base of $380MM, also expected 3.0x
30.0%
28.2%
3.0x
30%
to grow with Eagle Ford Shale drilling 2.5x 2.3x 2.2x 25%
2.0x 1.8x 20%
• Dividend paid for ~115 years (3.85% yield) 1.7x
1.5x 1.2x 15%
• Indebtedness is not an issue either 1.0x 10%
0.5x 5%
• No maturities for five years
0.0x 0%
• Relatively low yield on notes of 8.5% 2006 2007 2008 2009 2010 Pro Forma 1
2Q11
• BB‐/B1 corporate rating; BB‐/B2 rated public debt Net Debt/EBITDAX Net Debt/Capitalization
• New credit facility reflects high quality assets
• 5‐year maturity at a 0.5% lower interest rate
• Maximum leverage of up to 4.5x through June 2013
• Non‐core asset sales further bolster liquidity
• Closed $30.5MM sale of primarily Arkoma assets
• Will consider asset sales / partnering opportunities
• Will reinvest proceeds into oil / liquids inventory
1 – Pro forma for sale of non‐core Mid‐Continent gas assets; pro forma liquidity at 6/30/11 of $440MM
is comprised of a pro forma and undrawn borrowing base of $380MM and approximately $60MM
of cash; future ability to borrow under the revolver will be subject to a maximum leverage ratio of 1
4.5x (through 6/30/13) and 4.0x (from 9/30/13 through 6/30/16) net debt‐to‐EBITDAX, as well as
future borrowing base amounts 5
6. Cash Flow Growth is Expected
CFPS and EBITDAX Growth in Line With Most Peers Who Have Smaller Bases to Grow From
• Expected growth in cash flow is in line with peers through 20121
• Growth is fully‐funded
• Expected growth in EBITDAX1 will drive additional debt capacity and increases in the
borrowing base during 2012 and beyond
2012E CFPS and EBITDAX Growth
60%
50%
40%
30%
20%
10%
0%
PVA Peer 1 Peer 2 Peer 3 Peer 4 Peer 5
2011E‐2012E CFPS Growth 2011E‐2012E EBITDAX Growth
1 – Source: First Call; peers: CRK, GDP, GMXR, PETD and PQ; as of close on 10/11/11 6
7. PVA Appears Undervalued and Oversold
Valuation Multiples At or Below Low End of Ranges for Less Liquid and Smaller Peers
2012E CFPS and EBITDAX Multiples
• Trades at 1.2x analysts’ mean 2012E CFPS1 5.0x
• Selected peers trade at a mean of 2.3x1 4.0x
• Trades at 2.9x analysts’ mean 2012E EBITDAX
3.0x
• Selected peers trade at a mean of 3.6x1
• Trades at 43% of analysts’ mean target price1 2.0x
• Selected peers trade at mean of 54%1 1.0x
• Trades at 36% of its “sum‐of‐the‐parts” NAV1,2
0.0x
• NAV based on YE10 prices PVA Peer 2 Peer 4 Peer 5 Peer 1 Peer 3
Price‐to‐2012E CFPS TEV‐to‐2012E EBITDAX
• PVA has a current PDP PV‐10 of $700MM3
• Covers net debt of $567MM at 6/30/11, with $133MM % of Target Price and 52‐Wk. High
70%
($2.90 / share) left over
65%
• Implies only $135MM ($2.95/ share) of remaining equity 60%
value for: (i) all YE10 PUDs; (ii) Eagle Ford Shale; (iii) 55%
Marcellus Shale and (iii) other 3P reserve value in east
50%
Texas, the Anadarko Basin, Mississippi and Appalachia
45%
40%
35%
1 – Sources: First Call; peers: CRK, GDP, GMXR, PETD and PQ (see previous page); as of 10/11/11 30%
PVA Peer 2 Peer 1 Peer 4 Peer 5 Peer 3
2 – See Appendix for PVA‐calculated “sum‐of‐the‐parts” NAV of $16.21 per share using YE10 pricing
3 – Pretax PV‐10 of YE10 proved developed producing reserves (i.e., no Eagle Ford Shale, no Marcellus Shale, Price‐to‐Mean Target Price Price‐to‐52 Week High
7
no upside value) at futures strip pricing at close on 10/7/11
8. What is Our Response?
Focus on Drilling the Eagle Ford and Look to Expand Our Oil Inventory in the Near‐Term
Continue to increase oil and liquids exposure
• 40‐45% of 4Q11 production vs. 18% in 2010; cash flows expected to accelerate
• Eagle Ford‐driven, with goal to add more Eagle Ford / other oily inventory
Retain long‐term optionality of core gas assets
• E. Texas, Mississippi and Appalachia – largely HBP; wait on gas prices
• Continued testing of Marcellus Shale position, with or without a partner
Further build liquidity and maintain solid financial position
• No maturities for five years and ample liquidity to fund CAPEX until free cash flow positive
• Continuing to drill and prove up reserves increases cash flow, borrowing base value and
liquidity
Look at the value:
• Proved developed PV‐10 value of $700MM pays debt off plus $2.90 per share of value
• Implied remaining equity value of $135MM for 14,700 acres of excellent Eagle Ford
acreage, 55,000 of Marcellus acreage, all company PUDs and 3P value
• Trading at 1.2x 2012E cash flow per share and 2.9x EBITDAX
8
9. Core Operating Regions
Emerging Oil and Liquids‐Rich Plays Plus “Option” in Significant Gas Plays
2011E CAPEX: $360MM ‐ $380MM
86% Oil & Liquids‐Rich Plays
2011E Production: 48.5‐50.5 Bcfe
30‐32% Oil & Liquids; 40‐45% by 4Q11
2011E Production: ~50 Bcfe
2010 Proved Reserves: 942 Bcfe
Oil / Liquids
Wet Gas
Dry Gas
9
Note: 2011 data based on latest guidance announced 8/3/11
10. Eagle Ford Shale: Volatile Oil
Excellent Early Results; Looking to Expand Acreage Position
• Positioning
Eagle Ford Shale – ~14,700 net acres in Gonzales Co., TX
– Operator with 83% WI and 63% NRI
– 17 wells currently producing
– Up to 130 remaining gross drilling locations
– Fracturing, gathering and processing in place
• Reserve Characteristics / Geology
– Volatile oil window: 80% oil, 10% NGLs, 10% gas
– First 12 wells IP’d at 582‐1,921 BOE/d
– 1,105 BOE/d average IP rate
– Results support a 500 MBOE type curve
• 2011 Activity
– 3 rigs drilling; up to 34 (27.9 net) wells
– Up to $226MM of CAPEX (60% of total)
– 14% of 2011E production (~30% of 4Q11E)
10
Note: Based on 8/3/11 operational update
11. Eagle Ford Shale: Play Activity Map
Located in the “Volatile Oil” Window Near Strong, Early Industry Results
• PVA’s Gonzales County Eagle Peers With Peers
Fayette
County
Ford Acreage and Potential Acreage PVA
PVA / MHR / EOG
Near PVA
is Well‐Positioned Based PVA (582‐1,921 BOEPD)
MHR (900‐1,335 BOEPD)
EOG EOG Hill Unit 2H (1,347 BOEPD)
on Overall Excellent MRO MHR
Gonzo Hunter 1H
Industry Results in MHR Gonzales
PVA Acreage
~14,700 Net Acres (605 BOEPD)
FST County
Area Hunt
EOG
Brothers Unit (1,798‐2,508 BOEPD)
EOG
Marshall Unit (703‐1,658 BOEPD)
Cusack Clampit (1,044‐2,107 BOEPD)
Hansen‐Kullin 3H (1,791 BOEPD)
Lavaca
Ullman 2H (925 BOEPD) County
HFS / Sweet (1,403‐1,578 BOEPD)
EOG / Riley Expl.
Wilson Edwards Unit (962 BOEPD)
County Maali 1H (968 BOEPD)
Karnes EOG
Milton Unit (668‐914 BOEPD)
County Harper Unit (695‐1,070 BOEPD) Dewitt
Dulling (1,255‐1,353 BOEPD) County
11
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: Excellent Early Results
PVA Has Reported Some of the Best Industry Results in the Volatile Oil Window
• Initial 12 wells had an average peak gross production rate of 1,105 BOEPD
• Average 30‐day gross production rate of 764 BOEPD
– On line an average of 116 days (through 9/30/11) with production averaging 533 BOEPD
• Well results provides the basis for our 461 MBOE EUR type curve
30‐Day
Cumulative Peak Gross Daily Average Gross Daily
Gross Production1 Production Rates1 Production Rates1
Lateral Frac Equivalent Days On Oil Equivalent Oil Equivalent
Well Name Length Stages Production Line Rate Rate Rate Rate
feet BOE BOPD BOEPD BOPD BOEPD
On‐Line Wells
Gardner #1H 4,792 16 121,392 246 1,084 1,247 732 881
Hawn Holt #1H 4,053 15 67,067 153 759 837 606 668
Hawn Holt #2H 4,476 17 62,743 120 869 986 668 728
Hawn Holt #4H 4,106 14 40,825 150 534 582 357 394
Hawn Holt #6H 4,166 17 39,498 121 670 711 342 370
Hawn Holt #9H 4,453 18 78,876 116 1,652 1,877 1,044 1,153
Hawn Holt #10H 3,913 16 52,543 92 1,080 1,188 771 839
Hawn Holt #3H 3,800 15 34,748 85 607 651 478 522
Hawn Holt #5H 3,950 16 27,367 84 474 528 321 349
Munson Ranch #1H 4,163 17 75,724 75 1,755 1,921 1,207 1,315
Munson Ranch #3H 3,953 16 41,762 70 1,448 1,538 786 860
Hawn Holt #11H 3,931 17 55,620 74 1,120 1,190 1,007 1,092
Averages 4,146 16 58,180 116 1,004 1,105 693 764
Maximums 4,792 18 1,755 1,921 1,207 1,315
Minimums 3,800 14 474 528 321 349
Note: Based on 8/3/11 operational update 12
1 Wellhead rates only; the natural gas associated with these wells is yielding approximately 150 barrels of NGLs per MMcf
13. 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
• ~80 drilling locations in JV
– ~40,000 net acres in other exploratory plays
• Testing to resume in 2012 or 2013
• Reserve Characteristics / Geology
– Granite Wash: 48% liquids; attractive IRRs
– Other play types: Tonkawa, Cleveland, St.
Louis, Springer, Viola, other
– Historical EURs > 5.0 Bcfe; assuming 4.0 Bcfe
for remaining wells
• 2011 Activity
– Up to 20 (8.7 net) Granite Wash wells
– Non‐operated drilling through YE11
– Will reduce activity level going forward
– Up to $88MM of CAPEX (23% of total)
13
Note: Based on 8/3/11 operational update
14. Marcellus Shale
Exploration Efforts Under Way in North Central Pennsylvania
• Positioning
Marcellus Shale – ~55,000 net acres primarily in Pennsylvania
• ~35,000 net acres in Potter / Tioga Cos.
• ~20,000 net acres in SW PA
– Operator with ~87% WI and 76% NRI
– Over 200 gross drilling locations
• Reserve Characteristics / Geology
– Moderate depth and thickness
– Dry gas window
– Attempting to establish minimum 4.0 Bcfe EUR wells
in Potter and Tioga Counties
• 2011 Activity
– Drilled and tested three wells in Potter County – will
turn in line soon
– Focus on testing of eastern acreage in 2012; most of
2011’s CAPEX incurred in 1H11
– Will adjust lateral direction and completion
14
Note: Based on 8/3/11 operational update
15. East Texas & Mississippi: Gas Optionality
Low‐Cost, High‐Potential, Largely HBP Natural Gas
Cotton Valley / Haynesville Shale • ETX ‐ Horizontal Cotton Valley
Selma Chalk – 5.0 Bcfe PUDs; 35% liquids
– $2.54 PV10 breakeven gas price
– 79 gross drilling locations
– 267 Bcfe of 3P reserves at YE10
• ETX ‐ Haynesville Shale
– 6.7 Bcfe PUDs; dry gas
– $3.25 PV10 breakeven gas price
Wet Gas – 183 gross drilling locations
– 505 Bcfe of 3P reserves at YE10
Dry Gas
• Mississippi ‐ Selma Chalk
– 1.7 Bcfe PUDs; dry gas
Summary of Gas Option – $3.84 PV10 breakeven gas price
445 gross locations – 183 gross drilling locations
1.1 Tcfe of 3P reserves – 279 Bcfe of 3P reserves at YE10
15
16. Quality Inventory of Drilling Locations
PVA is Well‐Positioned in a Number of Leading Oil & Gas Plays
• All core plays are economic at 2012‐2013 future strip pricing
• Focused on Eagle Ford Shale and Granite Wash in 2011
• Significant inventory of natural gas opportunities
Net Henry Hub WTI
Risked Breakeven Breakeven
Gross Average Reserve Gas Price Oil Price
Undrilled Working Gross EUR Potential for for
Play Locations Interest (Bcfe/Well)1 (Bcfe)2 10% IRR3 10% IRR4
Eagle Ford Shale 130 83% 4611 ‐‐‐5 N/A $57‐66
Granite Wash 81 28% 6601 174 $2.20 $63
Horizontal Cotton Valley 79 79% 5.0 267 $2.54 $50
Haynesville Shale 183 74% 6.7 505 $3.25 N/A
Selma Chalk 183 97% 1.7 279 $3.84 N/A
Marcellus Shale >200 90% 4.0 – 6.0 ‐‐‐5 $3.48 N/A
1 – Eagle Ford and Granite Wash EURs in MBOE
2 – 3P reserves as of 12/31/10
3 – Pretax well economics assuming $85.00 oil price per barrel WTI
16
4 – Pretax well economics assuming $4.50 gas price per MMBtu Henry Hub
5 – No Eagle Ford Shale or Marcellus Shale proved or unproved reserves were included in the reserve report at year‐end 2010
17. Spending Less Overall, But More in Oil & Liquids
2007 ‐ 2011 Capital Spending Increasingly Allocated to Oil & NGLs
• 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
17
Note: 2011 data based on latest guidance announced 8/3/11; see Appendix
18. 2011 Capital Expenditures
$360 ‐ $380MM of 2011 Capital Spending, 86% Targeting Oil & Liquids‐Rich Plays
Expected 2011‐12 Capital Programs: Fully Funded
18
Note: 2011 data based on latest guidance announced 8/3/11; see Appendix
19. Track Record of Value Creation
Lower Drill‐Bit F&D and Higher Rates of Return on Drilling Relative to Peers in 2010
• Historical statistics place PVA among the “best in class” ‐ 2010 was no exception
– Ranked 3rd in drill‐bit F&D and 7th in return on drilling dollars out of 38 top E&P firms1
– 2010 results driven by the Granite Wash; 2011 and 2012 results will be driven by the Eagle
Ford Shale
2010E Ex‐Leasehold PD F&D1 2010E Return on Drilling Dollars1
$14 60%
$12 50%
$10 40%
$8 30%
$6 20%
Median: 13.7%
$4 10%
Median: $2.91/ Mcfe
$2 0%
$0 ‐10%
PVA PVA
1 ‐ Source: JPMorgan PD F&D Survey (March 2011); peers: APA, APC, AREX, ATPG, BEXP, BRY, CHK, CLR, COG, CRZO, CXO, DNR, DPTR, DVN, 19
EOG, EP, EQT, GDP, HK, MMR, NBL, NFX, PETD, PQ, PXD, PXP, QEP, RRC, SD, SFY, SM, SWN, UPL, VQ, WLL, WMB, XEC
20. Oil & Gas Price Sensitivities
Plenty to Do Despite Uncertain / Weak Commodity Price Environment
• All core plays are economic at current 2012‐2013 futures strip pricing
• Our drilling is rate‐of‐return driven; our outspend is highly accretive and funded
• We’re well above peers in return on drilling dollars – these charts show how we do that
$4.50 per MMBtu $85 per Barrel
Flat HH Gas Price Flat WTI Oil Price
20
21. Why PVA?
A Track Record of Growth and Value Generation
• Diversified and valuable portfolio of high‐quality assets
• Track record of low‐cost, high‐return operations
• Allocating capital to build oil and liquids production
• Ample supply of economic drilling locations
• Drilling and acquisitions focused on high return play types
• Retained optionality of natural gas assets
• Financial condition and liquidity is solid
• Production and cash flow growth expected
• Compelling value proposition
21
23. Value Proposition
PVA Appears to be Significantly Undervalued on a Reasonable “Sum‐of‐the‐Parts” Basis
• PVA trades at about 36% of its “sum‐of‐the‐parts” NAV, even though that value assumes
an oil price lower than and a gas price within a recent futures strip for 2012‐13
YE 2010 Net Asset Value @ Flat
SEC Pricing NYMEX Pricing of:
$4.38 1 $5.00 2 $6.00 2
3
Proved Developed Reserves $786.2 $918.6 $1,093.9
3
Proved Undeveloped Reserves 92.0 191.5 310.4
Probable and Possible Reserves3 95.8 311.3 607.1
3
3P Reserves $973.9 $1,421.4 $2,011.4
4
Eagle Ford Shale 210.0 210.0 210.0
5
Marcellus Shale 123.8 123.8 123.8
Asset Value $1,307.7 $1,755.2 $2,345.1
Less: Long‐Term Debt (net of cash; 6/30/11) (567.0) (567.0) (567.0)
Net Asset Value (NAV) $740.7 $1,188.2 $1,778.2
Shares Outstanding (7/29/11) 45.7 45.7 45.7
NAV per Share $16.21 $26.00 $38.91
Recent Stock Price (10/11/11 close) $5.85 $5.85 $5.85
Upside to NAV per Share 177% 344% 565%
Asset Value Per Proved Reserve ($/Mcfe; 941.8 Bcfe) $ 1.39 $ 1.86 $ 2.49
PVA is trading at: $ 0.89 $ 0.89 $ 0.89
NAV per Share to 2012E CFPS (First Call Mean of $5.01 per share at 10/11/11) 3.3x 5.3x 8.0x
PVA is trading at: 1.2x 1.2x 1.2x
4Q11 2012 2013 2014
NYMEX Gas Futures Strip Prices @ 10/11/11 close $3.73 $4.13 $4.66 $4.96
NYMEX Oil Futures Strip Prices @ 10/11/11 close $85.56 $86.53 $88.02 $88.68
1 ‐ SEC pricing of $4.38 per MMBtu (natural gas) and $79.43 per barrel (crude oil)
2 ‐ Natural gas price varies between $5 and $6 per MMBtu, while assuming an $85 per barrel WTI price and $42 per barrel NGL price
3 ‐ Third‐party 3P reserve report as of 12/31/10; pretax PV‐10% values
4 ‐ Approximately 14,000 net Eagle Ford acres, using midpoint of estimated value range between $10K and $20K per net acre. 23
5 ‐ Approximately 55,000 net Marcellus acres, using midpoint of estimated value range between $500 and $4K per net acre.
24. Natural Gas Hedges
Protecting our Capital Budget and Well Economics
• ~60% of our natural gas price exposure is hedged for the remainder of 2011
1 – As of 8/3/11; crude oil hedges include 360 BOPD collars @ $80 x $103 and 500 BOPD swaps @ $109 for 2H11 and 24
500 BOPD @ $100 x $120 for CY12
25. 2011 Guidance Table
As of August 3, 2011
25
Dollars in millions, except per unit data; based on latest guidance announced 8/3/11
