Investor Presentation

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Investor Presentation June 14‐16, 2011 NYSE: PVA

Eagle Ford Shale Drilling Rig Gonzales County, Texas

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

Strategic Road Map Near‐Term and Long‐Term Strategies for Generating Value

 Maintain liquidity •

Completed $300 million senior note offering, netting over $50MM in cash

 Increase oil/NGL exposure •

Targeting high rate of return projects in low gas price environment



Considering sale of non‐core gas assets to fund growth in oilier plays

 Retain optionality of core gas assets •

Horizontal Cotton Valley, Haynesville Shale, Selma Chalk, etc.

 Explore and develop:  •

Eagle Ford Shale ‐



Marcellus Shale ‐



Continue to build acreage position; drill multi‐year inventory

Continue to de‐risk acreage and consider alternatives

Mid‐Continent ‐

Upside associated with exploration program  3

Strategy Core Competencies for Value Growth



Rate‐of‐Return Based Decisions – Conservative commodity price outlook – Diversified portfolio allows for efficient  allocation of capital to projects and plays  offering the best returns



Fiscal Discipline

High‐Quality Operating Assets – Pursue predictable, profitable growth 

Production and reserves have annually grown 16%  and 23%, respectively, over the last five years

– Organic growth enhanced by periodic  acquisitions to replenish multi‐year drilling  inventory – Prefer operatorship and “reasonably long”  runway of prospects; not a land bank – Divestitures of non‐core assets narrows focus  and provides supplemental liquidity



Strong Technical Staff – Continuously generate new ideas  – Focus on driving down unit costs, driving up  margins and increasing efficiencies



Value Creation

Engineering Excellence

Focused Geology

Strong Financial Position – Maintain strong credit statistics and liquidity

4

Core Operating Regions Emerging Oil and Liquids‐Rich Plays Plus “Option” in Significant Gas Plays 2011E CAPEX: $320MM ‐ $370MM 77% Oil & Liquids‐Rich Plays 2011E Production: 50‐54 Bcfe 28‐30% Oil & Liquids; 35% by 4Q11 2011E Production

2010 Proved Reserves: 942 Bcfe Oil / Liquids Wet Gas  Dry Gas 5 Note: 2011 data based on latest guidance announced 5/4/11

Track Record of Growth Quality Assets are the Foundation for Growth in All Cycles

• •

Solid growth over the past five years Increasing proportion of growth from oil and NGLs – Trend should accelerate as a majority of future drilling activity is for oil and NGLs



Retention of “gas option,” allowing for flexibility in future periods

1 ‐ Pro forma to exclude proved reserves and production from Gulf Coast assets divested in January 2010;  2011 data based on latest guidance announced 5/4/11

6

Track Record of Value Creation Experienced People Provide the Foundation of Value Creation



Record of delivering growth at relatively low operating cost – Along with hedges, helps preserve margins when commodity prices are low



Historically ranking among the best in drill‐bit reserve replacement and value  associated with investment; 2010 was no exception Lease Operating Expenses

2010E High‐Return Reserve Replacement

$/Mcfe 1.40

1

$14

60%

$12

50%

$10

40%

0.80

$8

30%

0.60

$6

20%

0.40

$4

0.20

$2

0.00

$0

$1.27

1.20 1.00

$1.15

$1.09

$1.06

$0.88

2006

2007

2008

2009

2010

Median: 13.7%

10%

Median: $2.91/ Mcfe

0% ‐10%

PVA

Ex‐Leasehold PD F&D ($/Mcfe, left axis)

1 ‐ Source: JPMorgan PD F&D Survey (3/14/11); peers: APA, APC, AREX, ATPG, BEXP, BRY, CHK, CLR, COG, CRZO, CXO, DNR, DPTR, DVN, EOG, EP, EQT, GDP, HK, MMR, NBL, NFX, PETD, PQ, PXD, PXP, QEP, RRC, SD, SFY, SM, SWN, UPL, VQ, WLL, WMB, XEC

Return on Drilling Dollars (right axis)

7

Resource Profile PVA is Positioned in a Number of Leading Oil & Gas Plays

Gross  Undrilled  Locations

Average  Working  Interest

Gross EUR  (Bcfe/Well)1

Net  Risked  Reserve  Potential  (Bcfe)2

90‐115

83%

280 – 3801,4

‐‐‐

N/A

81

28%

4.1

174

$1.14

Marcellus Shale – Core

200‐250

90%

4.0 – 6.04

‐‐‐

$3.48

Horizontal Cotton Valley

79

79%

5.0

267

$2.54

Haynesville Shale

183

74%

6.7

505

$3.50

Selma Chalk

183

97%

1.7

279

$3.84

Play Eagle Ford Shale Granite Wash – S. Clinton

1 – Eagle Ford in MBOE 2 – 3P reserves as of 12/31/10; no reserve potential reflected for Eagle Ford or Marcellus Shales and other prospects 3 – Well economics; price per MMBtu Henry Hub; assumes oil price of $85.00 per barrel WTI and NGL price of $42.00 per barrel 4 – There were no Eagle Ford and Marcellus Shale proved or unproved reserves at year‐end 2010

Henry Hub Gas Price for  10% IRR3

8

Rates of Return Balance Between Plays in Low Gas Price Environment

Pre‐Tax Rates of Return Gas Price Sensitivity 80 70 60 50 40 30 20 10 0

$3

$4

$5

$6

$7

NYMEX Gas Price (Flat) ‐ $/MMBtu   Eagle Ford Shale      (EUR = 371 MMBOE (8/8ths) / Capex = $7.000 MM)   Selma Chalk      (EUR = 1.7 Bcfe (8/8ths) / Capex = $2.380 MM)   Marcellus Shale      (EUR = 4.2 Bcfe (8/8ths) / Capex = $4.500 MM)

  Horizontal Cotton Valley      (EUR = 5.0 Bcfe (8/8ths) / Capex = $5.770 MM)   Haynesville Shale      (EUR = 6.7 Bcfe (8/8ths) / Capex = $10.000 MM)   Granite Wash ‐ South Clinton      (EUR = 4.1 Bcfe (8/8ths) / Capex = $7.000 MM)

9 Note: Well economics; assumes oil price of $85.00 per barrel WTI and NGL price of $42.00 per barrel

Investing More in Oil & Liquids 2007 ‐ 2011 Capital Spending Increasingly Allocated to Oil & NGLs

10 Note: 2011 data based on latest guidance announced 5/4/11; see Appendix

2011 Capital Expenditures $320 ‐ $370MM of 2011 Capital Spending, 77% Targeting Oil & Liquids‐Rich Plays

Forecast uses $4.25/MMBtu and $90.00/Barrel

11 Note: 2011 data based on latest guidance announced 5/4/11; see Appendix

Eagle Ford Shale: Volatile Oil Promising Early Results and Expanding Acreage Position in Emerging Oily Core Area 

Eagle Ford Shale



Positioning – – – – –



~12,700 net acres in Gonzales Co., TX Operator with 83% WI and 63% NRI 92 to 122 gross drilling locations 6 wells currently producing 4,440 BOEPD (gross) Midstream on‐line; fracturing services  agreement extended

Reserve Characteristics / Geology – Volatile oil window: 75% oil, 15% NGLs, 10% gas – First well IP’d at 1,250 BOE/d; 78MBOE to date – Next five wells IP’d at 582‐1,876 BOE/d  – 997 BOE/d average IP rate



2011 Activity – 3 rigs drilling; up to 29 (24.3 net) wells – Up to $187MM of CAPEX (52% of total) – 11% of 2011E production (20% of 4Q11E) 12

Note: 2011 data based on latest guidance announced 5/4/11

Eagle Ford Shale: Play Activity Map Located in the “Volatile Oil” Window Near Strong, Early Industry Results

• PVA’s Gonzales County Eagle  Ford Acreage and Potential  is Well‐Positioned Based  on Overall Excellent  Industry Results in Area

Peers With Acreage Near PVA EOG MRO MHR FST Hunt

Peers PVA

PVA / MHR / EOG Gardner 1H (1,250 BOEPD) Southern Hunter 1H (1,335 BOEPD) Gonzo North 1H (1,039 BOEPD) Furrh 1H (>900 BOEPD) Hawn Holt Unit (582‐1,876 BOEPD) Hill Unit 2H (1,347 BOEPD)

Gonzales County

Fayette County

PVA Acreage 13,900 Net Acres

MHR Gonzo Hunter 1H (605 BOEPD)

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) Ullman 2H (925 BOEPD) HFS / Sweet (1,403‐1,578 BOEPD)

Lavaca County EOG / Riley Expl. / EOG Edwards Unit (962 BOEPD) Maali 1H (968 BOEPD)

Wilson County Karnes County

EOG Milton Unit (668‐914 BOEPD) Harper Unit (695‐1,070 BOEPD) Dulling (1,255‐1,353 BOEPD)

Dewitt County 13

Note ‐ Industry results based on peers’ investor presentations; IP wellhead rates (pre‐processing); production “windows” are PVA’s approximation

Marcellus Shale: Economic Gas Exploration Efforts Under Way in North Central Pennsylvania

Marcellus Shale



Positioning – ~42,000 net core acres • Potter / Tioga Cos. ~35,000 net acres • SW PA / NY ~7,000 net acres – ~13,000 net non‐core acres – Operator with ~87% WI and 76% NRI – 200 to 250 gross drilling locations



Reserve Characteristics / Geology – Moderate depth and thickness – Expected to be dry gas



2011 Activity – 1 rig drilling; up to 11 (10.0 net) wells – Up to $64MM of CAPEX (18% of total) – 2% of 2011E production (3% of 4Q11E)

14 Note: 2011 data based on latest guidance announced 5/4/11

Marcellus Shale: Play Activity Map Located in the North Central “Dry Gas” Part of the Play Near Encouraging Industry Results 



PVA’s Potter / Tioga  Marcellus Position is  Located in Areas With Strong Well IP Results Reported by Peers

McKean County

PVA Acreage ~35,000 Net Acres

XOM / PGE

RRC NFG

Potter County

XOM / PGE

NFG‐DCNR Block 001 (4.5 MMcfd) Geneseo (~3 MMcfd)

SM Potato Cr. 1H, 3H (4‐11 MMcfd)

Cameron County

Peer Wells PVA Wells

Clinton County

UPL Button 3H, 4H (7‐12 MMcfd) Kenton 1H,4H (7.2‐11.3 MMcfd) Mitchell 5H (7.7 MMcfd) Thomas 1H (4.9 MMcfd) Pierson 8H (10.0 MMcfd)

Tioga County

Lycoming County

15 Note ‐ Industry results and locations based on peers’ investor and other presentations; IP wellhead rates

Mid‐Continent: Liquids Rich Play Types High‐Margin, Liquid‐Rich Reserves and Production

Anadarko Basin



Positioning – CHK development drilling JV • ~9,700 net acres in Washita Co. • Operate about 1/3rd; ~35% WI • ~80 drilling locations in JV – ~40,000 net acres in exploratory plays



Reserve Characteristics / Geology – Granite Wash: 48% liquids; attractive IRRs – Pursuing liquids‐rich play types • Tonkawa, Cleveland, Granite Wash,  other exploratory plays



2011 Activity – Up to 21 (9.7 net) Granite Wash wells – Non‐operated drilling through YE11 – Up to $85MM of CAPEX (23% of total)

16 Note: 2011 data based on latest guidance announced 5/4/11

East Texas & Mississippi: Gas Optionality Low‐Cost, High‐Potential 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 – – – –

Wet Gas  Dry Gas

6.7 Bcfe PUDs; dry gas $3.50 PV10 breakeven gas price 183 gross drilling locations 505 Bcfe of 3P reserves at YE10

• Mississippi ‐ Selma Chalk

Summary of Gas Option 445 gross locations 1.1 Tcfe of 3P reserves

– – – –

1.7 Bcfe PUDs; dry gas $3.84 PV10 breakeven gas price 183 gross drilling locations 279 Bcfe of 3P reserves at YE10 17

Well economics; price per MMBtu Henry Hub; assumes oil price of $85.00 per barrel WTI and NGL price of $42.00 per barrel

Strong Financial Position Financial Flexibility to Execute Growth Plan •

Over the past few years, we have prudently managed our balance sheet 



Liquidity has remained strong over the past few years



PVA remains well‐positioned to fund its 2011 capital spending plan Conservative Leverage

4.0x

40%

35.9%

35.6% 31.6%

30.0%

3.0x

34.7% 28.2% 2.3x

2.0x

1.7x

3.0x

30%

2.2x

20%

1.8x

1.2x

10%

1.0x

0.0x 2006

2007

2008

Net Debt/EBITDAX

2009

2010

Pro Forma 1Q11

1

0%

1

Net Debt/Capitalization

1 ‐ Pro forma for 4/5/11 offering of $300MM of senior notes; pro forma liquidity at 3/31/11 of $310MM is comprised of pro forma cash of approximately $100MM and  availability under our revolving credit facility, subject to covenant compliance, of approximately $210MM (approximately $398MM pro forma borrowing base)

18

Natural Gas Hedges Protecting our Capital Budget and Well Economics •

57% of our natural gas price exposure is hedged for the remainder of 2011 1

Natural Gas Hedges Swaps and Collars

$8

MMBtu per Day (000s)

70 60

$7

Weighted Average Floor / Swap Price by Quarter

$5.67

$5.65 $4.96

$5.70 $5.31

$5.31

$5.00

$5.00

$4.96

$6 $5.10

50

$5 $5.00

40

$4.25

$4.25

$4.25

$5.00

Budget Price by Quarter

$4.25

$4

30

$3

20

$2

10

$1

0

$0 1Q11

2Q11

3Q11

4Q11

1Q12

2Q12

1 – As of 5/4/11; crude oil hedges include 425 BOPD @ $80 x $102 for 1H11, 860 BOPD @ $97 x $107 for 2H11 and  500 BOPD @ $100 x $120 for CY12

3Q12

   Weighted Avg. Floors and Swaps  ($/MMBtu)

80

4Q12

19

Value Proposition PVA Appears Significantly Undervalued on a “Sum‐of‐the‐Parts” NAV per Share YE 2010 SEC Pricing Proved Developed Reserves3 3

Proved Undeveloped Reserves

3

Probable and Possible Reserves 3

3P Reserves

4

Eagle Ford Shale

Marcellus Shale5 Mid‐Continent Exploratory Asset Value

6

7

Less: Long‐Term Debt (net of cash; pro forma 3/31/11) Net Asset Value (NAV) Shares Outstanding (4/29/11) NAV per Share Recent Stock Price (6/10/11 close) Upside to NAV per Share Asset Value Per Proved Reserve ($/Mcfe; 941.8 Bcfe)

NYMEX Gas Futures Strip Prices @ 6/10/11 close NYMEX Oil Futures Strip Prices @ 6/10/11 close

$4.38 1 

$5.00 2 

$786.2

$918.6

$1,093.9

92.0

191.5

310.4

95.8

311.3

607.1

$973.9

$1,421.4

$2,011.4

95.3

95.3

95.3

168.0

168.0

168.0

50.0

50.0

50.0

$1,287.2

$1,734.7

$2,324.6

(497.1)

(497.1)

(497.1)

$790.1

$1,237.6

$1,827.6

45.7

45.7

45.7

$17.30

$27.10

$40.02

$15.28 13% $             1.37 2H11   $4.88 $100.10

Net Asset Value @ Flat  NYMEX Pricing of:

2012   $5.12 $102.48

$6.00 2 

$15.28 $15.28 77% 162% $           1.84 $             2.47 2013   $5.35 $101.96

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 12,700 net Eagle Ford acres, using midpoint of recent transactions’ value range of between $5K and $10K per net acre 5 ‐ Approximately 42,000 net Marcellus acres, using midpoint of PVA’s estimated value range of between $3K and $5K per net acre 6 ‐ Approximately 40,000 net exploratory acres, using midpoint of PVA’s estimated value range of between $500 and $2,000 per net acre 7 ‐ Pro forma for 4/5/11 offering of $300MM of senior notes

2014   $5.55 $100.96

20

Why PVA? A Track Record of Growth and Value Generation

• Diversified portfolio of high‐quality assets • Management team with a track record • Allocating capital to build oil and liquids production • High rate of return play types • Option on natural gas assets • Strong balance sheet • Value proposition 21

Appendix

Granite Wash Pump Jack Washita County, Oklahoma

2011 Guidance Table As of May 4, 2011 Full‐Year 2011 Guidance Production: Natural gas (Bcf)  Crude oil (MBbls) NGLs (MBbls)  Equivalent production (Bcfe) Equivalent daily production (MMcfe per day)

      36.2      1,300      1,000        50.0      137.0 

‐  ‐  ‐  ‐  ‐ 

          37.8         1,500         1,200            54.0         147.9 

Operating expenses: Lease operating ($ per Mcfe) Gathering, processing and transportation costs ($ per Mcfe) Production and ad valorem taxes (percent of oil and gas revenues) General and administrative:   Recurring general and administrative   Share‐based compensation   Restructuring Total reported G&A Exploration:   Dry hole costs   Unproved property amortization   Other Total reported Exploration Depreciation, depletion and amortization ($ per Mcfe)

$       18.5  ‐            19.5  $       40.0  ‐            42.0  $        11.5   ‐             13.5  $       70.0  ‐            75.0  $       3.00  ‐            3.25 

Capital expenditures: Development drilling  Exploratory drilling Pipeline, gathering, facilities Seismic  Lease acquisitions, field projects and other   Total oil and gas capital expenditures

$     225.0  ‐  $       35.0  ‐  $          7.0  ‐  $          8.0  ‐  $        45.0   ‐  $     320.0  ‐ 

$ $

      0.75  ‐            0.80        0.32  ‐            0.33  7.0% ‐  7.5%

$       44.5  ‐            45.5  $          6.0  ‐              8.0  $           0.1               0.1            53.6  $       50.6 

       255.0            50.0              8.0            10.0             47.0         370.0 

23 Dollars in millions, except per unit data; based on latest guidance announced 5/4/11

Non‐GAAP Reconciliations 2006 EBITDAX

Year ended December 31, 2007 2008 2009 dollars in millions

2010

LTM 1Q11

3 Mos. Ended Mar‐10 Mar‐11

$   10.8  $  (26.3)

Net income (loss) from continuing operations

$       44.2 

$      26.5 

$      93.6 

$  (130.9)

$    (65.3)

$    (102.4)

Add: Income tax expense (benefit)

         50.0 

        30.5 

        55.6 

      (85.9)

      (42.9)

        (63.8)

       6.8

   (14.2)

Add: Interest expense

           6.0 

        20.1 

        24.6 

        44.2 

       53.7

         53.5

     13.7

     13.5

Add: Depreciation, depletion and amortization

         56.7 

        88.0 

      135.7 

     154.4

     134.7

       139.5

     30.0

     34.8

Add: Exploration

         34.3 

        28.6 

        42.4 

       57.8

       49.6

         73.2

       6.0

     29.5

Add: Impairments

           8.5 

          2.6 

        20.0 

     106.4

       46.0

         46.0

        ‐

        ‐

Add: Share‐based compensation expense

           1.1 

          1.6 

          6.0 

         9.1

         7.8

           6.6

       3.0

       1.8

Add/Less: Derivatives (income) expense included in net income

        (30.7)

          2.0 

      (29.7)

      (31.6)

      (41.9)

        (13.4)

   (29.9)      (1.3)

Add/Less: Cash receipts (payments) to settle derivatives

         10.5 

        14.1 

        (7.6)

        58.1 

        32.8 

         31.1

Add/Less: Net loss (gain) on sale of assets

               ‐  

       (12.6)

       (33.2)

         (2.0)

         (1.2)

           (1.9)

        0.3         (0.5)

 $     180.6 

 $    201.5 

 $    307.4 

 $    179.7 

 $    173.3 

 $      168.3 

 $   49.1   $   44.1 

Adjusted EBITDAX

       8.4

       6.7

24

Penn Virginia Corporation 4 Radnor Corporate Center, Suite 200 Radnor, PA 19087 610‐687‐8900 www.pennvirginia.com

Marcellus Shale Drilling Rig Potter County, Pennsylvania

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