PENNVIRGINIA CORPORATION NYSE: PVA John S. Herold, Inc.s - - PowerPoint PPT Presentation

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PENNVIRGINIA CORPORATION NYSE: PVA John S. Herold, Inc.s - - PowerPoint PPT Presentation

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PENNVIRGINIA CORPORATION NYSE: PVA John S. Herold, Inc.s Pacesetters Energy Conference Take Another Road Unconventional Resources Old Greenwich, CT September 27, 2007 Penn Virginia Oil & Gas Corp. (PVOG) PENN VIRGINIA

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SLIDE 1

PENNVIRGINIA CORPORATION

John S. Herold, Inc.’s Pacesetters Energy Conference

“Take Another Road” – Unconventional Resources

Old Greenwich, CT September 27, 2007

NYSE: PVA

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SLIDE 2

2 PENN VIRGINIA CORPORATION

Penn Virginia Oil & Gas Corp. (PVOG)

1 As of December 31, 2006

  • Exploration and Production
  • 487 Bcfe of Proved Reserves1

94% gas and 71% developed1

  • 2Q 2007 Production Rate of 111 MMcfe/d
  • Primarily Low-Risk Development, With

Exploration Upside

  • Unconventional Drilling is ~90% of

Program Spending

  • Projects in Five Main Areas:
  • Cotton Valley
  • Appalachia
  • Mid-Continent
  • Gulf Coast Onshore
  • Mississippi
  • Growth-via-Drillbit Focus, Supplemented by Acquisitions
  • Strong Financial Condition and Cash Flows Help

Position PVA Favorably for Acquisitions and Growth

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SLIDE 3

3 PENN VIRGINIA CORPORATION

PVOG: Production, Reserves and Upsides

E&P Operating Areas

Exploratory Potential (300 Bcfe)2: Devonian and Other Shales / CBM (~150 Bcfe) Gulf Coast Onshore (~100 Bcfe) Fayetteville Shale (~50 Bcfe)

Mid-Continent Cotton Valley Appalachia Mississippi Gulf Coast

1 Excludes effects of 2007 additions, extensions, discoveries, acquisitions and revisions and production; not reflective of downspacing or horizontal drilling in Cotton Valley and Mississippi 2 Exploratory potential (not included in “3P” volumes in the table) are PVOG estimates which have not been reviewed by its outside reserve engineering firm

# of 2Q07 Gross Daily Reserves (12/31/06)1 R/P Addl. Areas of

  • Prod. Proved

PD “3P” Ratio Well Operations

(MMcfe/d) (Bcfe) (Bcfe) (Bcfe) (Years)

Locs. Appalachia 34.3 156 136 219 12.5 343

(1980) 31% 32% 39% 16% 15%

Mississippi 20.2 121 87 181 16.4 430

(1999) 18% 25% 25% 13% 18%

Gulf Coast 28.7 49 38 187 4.7 237

(2001) 26% 10% 11% 14% 10%

Cotton Valley 17.9 109 54 606 16.7 830

(2004) 16% 22% 16% 45% 36%

Mid-Continent 9.5 52 30 148 15.1 497

(2006) 9% 11% 9% 11% 21%

_____ ___ ___ _____ _____ TOTALS 110.5 487 345 1,341 12.1 2,337

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SLIDE 4

4 PENN VIRGINIA CORPORATION

Why Unconventional / Resource Plays?

  • Primary Remaining Domestic Resource
  • Lesser numbers of high-quality conventional drilling opportunities remain
  • Significant Reserves Associated With These Resource Plays
  • Generally Lower-Risk “Manufacturing” Plays Which Provide More

Predictable Growth in Production and Reserves

  • Smaller Firms Can be Competitive
  • Today’s Gas Prices Support These Play Types With Attractive Returns
  • These Play Types are Often Associated With Legacy Assets Which Have

Paid for Themselves Many Times Over

  • Little to no acreage acquisition costs
  • Provides Long-Term Inventory of Drilling Opportunities
  • Resource plays cover larger, typically blanketed land areas
  • Horizontal Drilling Application Has Improved Economics
  • These Play Types are Easier for Wall St. to Understand, Model and Value
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SLIDE 5

5 PENN VIRGINIA CORPORATION

Economic Sensitivities for PVOG by Major Play

10 20 30 40 50 60 70 80 90 100 4 5 6 7 8 9 10

NYMEX Gas Price (Flat) - $/MMBtu Rate or Return AFIT - %

  • PVOG’s Plays Generate Attractive After-Tax Returns Even at Prices Below Current

Levels (current 12-month NYMEX strip $7.74 / MMBtu)

  • Hedges Protect the Downside Economics of Certain Plays (e.g., Cotton Valley,

Hartshorne CBM) During “Shoulder” Periods

9/24/07 Avg. NYMEX 12-Month Strip Price S . L A P r

  • s

p e c t Appalachian HCBM Selma Chalk (Mississippi) Hartshorne HCBM (Mid-Continent) Cotton Valley (East Texas)

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SLIDE 6

6 PENN VIRGINIA CORPORATION

Penn Virginia’s “Take Another Road”

  • Horizontal Multi-Lateral CBM in Appalachia – Very Unique and Economic
  • Higher cost, lower risk, but with a Gulf Coast production profile
  • Selma Chalk – Largest Chalk Producer in MS and That Will Increase With

Horizontal Drilling Application

  • Very Active Cotton Valley Drilling Program in East Texas – 5 Rigs Drilling

With a 6th Rig to be Added Soon

  • Exposure to Multiple, Geographically Diverse Unconventional Play Types
  • Also Important to our Strategy is Some Exploration Exposure in South

Louisiana and South Texas

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SLIDE 7

7 PENN VIRGINIA CORPORATION

Unconventional Play #1: Multi-Lateral HCBM

Appalachian Basin - West Virginia

Horizontal Devonian Shale Horizontal CBM Unconventional Tight Sand

  • Snapshot
  • Proved reserves: 156 Bcfe (32% of total)
  • Probable / possible reserves: 63 Bcfe (7% of total)
  • 343 future drilling locations in inventory (12/31/06)

includes only HCBM (~50%) and non-shale (~50%) wells

  • 2Q 2007 daily production: 34.3 MMcfe/d (31% of total)
  • Drilled 33 (14.7 net) 100% successful wells in 2006
  • Drilled 21 (11.6 net) 90% successful wells in 1H07
  • Horizontal CBM (HCBM)
  • 2007 drilling forecast: up to 28 (14.2 net) locations planned
  • AMI with CDX Gas (see map, gray area; blue dots)
  • Active acreage acquisition within AMI
  • Water disposal issues resolved in 1Q 2007

production ramping up (7% sequential growth 1Q-2Q07)

  • Devonian Shale
  • 2007 drilling forecast: up to 5 (4.0 net) locations planned
  • Horizontal Devonian Shale play

80,000 net prospective acres (see map, red dots)

  • Unconventional Tight Sand / Other
  • 2007 drilling forecast: up to 22 (17.0 net) locations planned
  • Infield drilling on legacy mineral fee acreage
  • Recently announced divestiture of 13.3 Bcfe of proved reserves

in Virginia

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SLIDE 8

8 PENN VIRGINIA CORPORATION

Unconventional Play #1: Multi-Lateral HCBM

Appalachian Basin - West Virginia

50 100 150 200 250 300 350 400 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Year MMcf per Year

Conventional Development Horizontal Development Horizontal Patterns

3 6 15 14 15 18 5 10 15 20 25 2003 2004 2005 2006 YTD07 Sep 07 MTD

Appalachian HCBM Avg. Daily Production (MMcfe/d)

  • Play Economics
  • Well Spacing / Type:

400 - 800-acre / multi-lateral horizontal

  • Typical Gross Reserves:

0.7 - 1.4 Bcfe

  • Typical WI / NRI:

50% / 44%

  • Typical D&C CAPEX:

$1.6 - $2.5 MM per well

  • Typical F&D Costs:

$2.03 / Mcf - $2.60 / Mcf

  • Type Curve ROR:

Flat $6 - $8 / MMBtu gas prices yield 27% - 63% ROR (after-tax)

  • Drilling History (‘02-2Q07):

111 gross wells drilled

  • Typical Depth:

~1,000 feet (800’ - 1,500’ range)

  • Other:

Horizontal laterals have ranged between 15K - 86K feet per well with open-hole completions

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SLIDE 9

9 PENN VIRGINIA CORPORATION

Unconventional Play #2: Selma Chalk

Mississippi

Washington Tangipahoa

  • St. Helena
  • St. Tammany

Livingston Pearl River Stone Harrison Hancock F r a n k l i n Marion J e f f e r s

  • n

D a v i s Amite Pike Walthall L i n c

  • l

n L a w r e n c e Forrest Lamar C

  • v

i n g t

  • n

J

  • n

e s

Louisiana Mississippi

Gwinville

11 Wells

Maxie

14 Wells

Baxterville

60 Wells 10 13 14 18 20 5 10 15 20 25 2003 2004 2005 2006 Q2 2007

Selma Chalk (MS) Avg. Daily Production (MMcfe/d)

  • Snapshot
  • Proved reserves: 121 Bcfe (25% of total)
  • Probable / possible reserves: 60 Bcfe (7% of total)
  • 430 future drilling locations in inventory

excludes horizontals and 10-ac. spaced wells

  • 2Q 2007 daily production: 20.2 MMcfe/d (18% of total)
  • Drilled 80 (79.6 net) 100% successful wells in 2006
  • Drilled 41 (40.8 net) 100% successful wells in 1H07
  • Highlights
  • 2007 drilling forecast: up to 85 (82.2 net) locations planned
  • 2 horizontal test wells have been drilled - successful, with the

Baxterville well exceeding expectations and the Gwinville well meeting expectations

  • Additional horizontal drilling planned with up to 3 additional wells

in 2H07 and a “ramp up” in 2008

  • Recently announced acquisition of 11.2 Bcfe of proved reserves

in Gwinville

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SLIDE 10

10 PENN VIRGINIA CORPORATION

Unconventional Play #2: Selma Chalk

Mississippi

Cumulative Horizontal Production

20 40 60 80 100 120

28 56 84 112

Days Cumulative MMcfe Produced

Cumulative Vertical PUD Production

  • Play Economics
  • Well Spacing / Type:

20-acre / vertical

  • Typical Gross Reserves:

0.375 - 0.400 Bcfe

  • Typical WI / NRI:

100% / 80%

  • Typical D&C CAPEX:

$0.450 - $0.500 MM per well

  • Typical F&D Costs:

$1.15 / Mcf - $2.00 / Mcf

  • Type Curve ROR:

Flat $6 - $8 / MMBtu gas prices yield 25% - 40% ROR (after-tax)

  • Drilling History (‘99-2Q07):

~440 gross wells drilled

  • Typical Depth:

~ 6,000 feet

  • Other:

Initial success with horizontal wells, particularly in Baxterville (see chart at right) should allow for higher rates

  • f returns and recoveries assuming

implementation of horizontal develop- ment drilling program

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SLIDE 11

11 PENN VIRGINIA CORPORATION

Columbia Lafayette Miller Bossier De Soto Red River Sabine Webster Angelina Camp Cass Gregg Harrison Marion Morris Nacogdoches Panola Rusk Sabine San Augustine Shelby Titus Upshur Cherokee Caddo Rosewood Field Woodlawn Field Carthage Field Waskom Field

Louisiana

Panola Phase II: PVOG 50% WI PVOG 100% WI Phase I: PVOG 70% WI Hallsville Field

Texas

Unconventional Play #3: Cotton Valley

East Texas

  • Snapshot
  • Proved reserves: 109 Bcfe (22% of total)
  • Probable / possible reserves: 497 Bcfe (58% of total)
  • 830 future drilling locations in inventory (12/31/06)

40-ac. spaced CV wells; excludes horizontals and 20-ac. spaced wells

  • 2Q 2007 daily production: 17.9 MMcfe/d (16% of total)
  • Drilled 53 (36.3 net) 100% successful wells in 2006
  • Drilled 51 (35.7 net) 100% successful wells in 1H07
  • 52,000 (43,000 net) acres

11,000 net acres JV with GMX Resources (NASDAQ: GMXR) 32,000 net acres with approximate 100% WI acreage

  • Highlights
  • Large part of PVOG’s upside and a focus of near-term drilling
  • 2007 drilling forecast: up to 92 gross (61.2 net) locations planned
  • 22 wells drilled on 100% WI, non-JV acreage through 6/30/07
  • Recently approved downspacing to 20 acres could increase

number of locations and reserves; up to 5-10 wells planned 2H07

  • Drilling of horizontal Taylor CV test well to commence 4Q07/1Q08
  • Drilling of second horizontal Lower Bossier test well 4Q07/1Q08
  • Results of Lower Bossier and Taylor CV horizontals could impact

future drilling approach; peer firms’ results mixed to date

  • Announced PVR-constructed processing plant on line in 1Q08

provides benefit of liquids value from processed gas (currently zero)

  • Recently announced acquisition of 19.5 Bcfe of proved reserves

in the Woodlawn Field

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SLIDE 12

12 PENN VIRGINIA CORPORATION

Cotton Valley PUD Type Curve Cotton Valley Cross- Section

200 400 600 800 1,000 1,200 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204 216 228 240

Production Month Average MMcfe per Day

Unconventional Play #3: Cotton Valley

East Texas

3 7 12 18 5 10 15 20 25 2004 2005 2006 Q2 2007

Cotton Valley Avg. Daily Production (MMcfe/d)

  • Play Economics
  • Well Spacing / Type:

40-acre / vertical

  • Typical Gross Reserves:

1.0 - 2.2 Bcfe (1.1 Bcfe 2006 avg.)

  • Typical WI / NRI:

JV Phase I (north): 70% / 56% JV Phase II (south): 50% / 40% Non-JV Area: 100% /80%

  • Typical D&C CAPEX:

$2.1 MM per well

  • Typical F&D Costs:

$2.40 / Mcfe net

  • Type Curve ROR:

Flat $6 - $8 / MMBtu gas prices yield 12% - 23% ROR (after-tax)

  • Drilling History (‘04-2Q07):

121 gross wells drilled within JV 22 gross wells drilled outside JV

  • Typical Depth:

~ 10,000 feet

  • Other:

Typically 2-3 pay intervals completed within the overall Cotton Valley section

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SLIDE 13

13 PENN VIRGINIA CORPORATION

Unconventional Plays

Mid-Continent Region

GRANITE WASH HARTSHORNE CBM FAYETTEVILLE SHALE

  • Snapshot
  • Proved reserves: 52 Bcfe (11% of total)

includes Hartshorne CBM (~30%), Granite Wash (~30%) and other conventional wells (~40%)

  • Probable / possible reserves: 96 Bcfe (11% of total)
  • 497 future drilling locations in inventory

includes Hartshorne CBM (~60%), Fayetteville Shale, Granite Wash, and other wells

  • 2Q 2007 daily production : 9.5 MMcfe/d (9% of total)
  • Drilled 28 (19.5 net) 96% successful wells in 1H07
  • >80,000 gross acres

includes Fayetteville, Woodford and Caney shales and other

  • Highlights
  • 2007 drilling forecast: up to 73 gross (41.9 net) locations planned
  • Up to 47 (30.7 net) horizontal Hartshorne CBM wells
  • Up to 13 (4.3 net) Granite Wash and other wells
  • Up to 13 (6.9 net) Fayetteville Shale and other exploratory wells
  • Recently announced acquisition of 18.8 Bcfe of proved reserves

in the Arkoma Basin (Hartshorne CBM)

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SLIDE 14

14 PENN VIRGINIA CORPORATION

50 100 150 200 250 300 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204 216 228 240

Production Month Average MMcfe per Day

Unconventional Play #4: Hartshorne HCBM

Arkoma Basin - Oklahoma

Hartshorne HCBM PUD Type Curve

  • Play Economics
  • Well Spacing / Type:

100 - 160-acre / horizontal

  • Typical Gross Reserves:

0.500 Bcfe

  • Typical WI / NRI:

50% / 40%

  • Typical D&C CAPEX:

$0.600 - $0.700 MM per well

  • Typical F&D Costs:

$1.50 / Mcf - $1.75 / Mcf

  • Type Curve ROR:

Flat $6 - $8 / MMBtu gas prices yield 15% - 29% ROR (after-tax)

  • Drilling History (‘06-2Q07):

51 gross wells drilled

  • Typical Depth:

1,000 - 2,500 feet

  • Other:

Single lateral horizontals; Initial acquisition in mid-2006; and Additional “bolt-on” acquisitions of reserves and acreage

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SLIDE 15

15 PENN VIRGINIA CORPORATION

Other Unconventional Resource Plays

Exploration Efforts Listed by Stage of Maturity for PVOG

  • Fayetteville Shale (Arkoma Basin)
  • Pope County, Arkansas - ~15,000 net acres
  • Currently drilling additional wells - up to 3 additional operated wells in 2H07
  • 6 wells drilled to date with variable success (2 PVOG-operated and 4 SWN-operated)
  • Horizontal success in “fairway” in counties to immediate east (Conway, Van Buren, etc.);

statistical play in which the average and level of variability in Pope County are yet to be established on a consistent basis

  • Devonian Shale (Appalachian Basin)
  • West and south-central West Virginia - 3 primary areas of activity with ~80,000 net acres
  • Currently awaiting rig to complete first well of a 2007 program of up to 5 wells
  • Primary shale targets include Lower Huron and Marcellus shales
  • Shallow, vertical play is established to the southwest of PVA’s acreage and horizontal

efforts (industry-wide) remain in an early stage with some promising early results

  • Woodford / Caney Shales (Arkoma Basin)
  • Primarily in eastern Oklahoma - ~44,000 net acres
  • Initial exploration activity likely in 2008
  • Play remains in early stage (industry-wide) with some promising early results
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16 PENN VIRGINIA CORPORATION

Summary

  • PVA Has Demonstrated Success With its Unconventional “Take Another

Road” Strategy Across Multiple Plays in Differing Locations

  • 25%+ production growth expected in 2007 over 2006 levels
  • PVA Will Continue With Diverse Resource Plays, Targeting Types and

Geographical Locations That Ultimately Reduce Execution Risk

  • PVA Will Continue to Explore for New Unconventional Plays (i.e., shales,

CBM, tight sands, etc.) and Continue to Build its Inventory of Drilling Locations for Future Production Growth

  • PVA Will Continue to Seek Ways to Optimize its Unconventional / Resource

Plays (i.e., horizontal applications, improved completions, reduced drilling time, partnering arrangements, etc.)

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17 PENN VIRGINIA CORPORATION

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

  • f 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 cost of finding and successfully developing oil and gas reserves; our ability to acquire new oil and gas reserves and the price for which such reserves can be acquired; energy prices generally and specifically, the price of crude oil and natural gas; the volatility of commodity prices for crude oil and natural gas; the projected demand for crude oil and natural gas; the projected supply of crude oil and natural gas; our ability to obtain adequate pipeline transportation capacity for our

  • il and gas production; non-performance by third party operators in wells in which we own an interest; competition among producers in the oil and natural gas industry;

the extent to which the amount and quality of actual production of our oil and natural gas differs from estimated recoverable proved oil and gas reserves; hazards or

  • perating risks incidental to our business; unanticipated geological problems; the availability of required drilling rigs, materials and equipment; the occurrence of unusual

weather or operating conditions including force majeure events; the failure of equipment or processes to operate in accordance with specifications or expectations; delays in anticipated start-up dates of our oil and natural gas production; environmental risks affecting the drilling and producing of oil and gas wells; the risks associated with having or not having price risk management programs; labor relations and costs; accidents; changes in governmental regulation or enforcement practices; risks and uncertainties relating to general domestic and international economic (including inflation and interest rates) and political conditions (including the impact of potential terrorist attacks); changes in financial market conditions; and other risks set forth in “Risk Factors,” of our Annual Report on Form 10-K for the year ended December 31, 2006 and subsequently filed interim reports. Many of the factors that will determine our future results are beyond the ability of management to control or predict. 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. The U.S. Securities and Exchange Commission (“SEC”) has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating

  • conditions. We use the terms “estimated ultimate recovery,” “EUR,” “probable,” “possible,” and “non-proven” reserves, reserve “potential” or “upside” or other descriptions
  • f volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines may prohibit us from including in filings with the
  • SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually

realized by us.