Filed by Penn Virginia Resource Partners, L.P. pursuant to Rule 425 under the

Securities Act of 1933 and

deemed filed pursuant to Rule 14a-12 under the Securities Exchange Act of 1934

Subject Company: Penn Virginia GP Holdings, L.P.

Commission File No.: 001-33171

Penn Virginia Resource Partners, L.P American Association of Individual Investors Philadelphia Chapter 10/26/2010 NYSE: PVR www.pvresource.com

2 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 coal; our ability to access external sources of capital; any impairment write-downs of our assets; the relationship between natural gas, NGL and coal prices; the projected demand for and supply of natural gas, NGLs and coal; competition among producers in the coal industry generally and among natural gas midstream companies; the extent to which the amount and quality of actual production of our coal differs from estimated recoverable coal reserves; our ability to generate sufficient cash from our businesses to maintain and pay the quarterly distribution to our general partner and our unitholders; the experience and financial condition of our coal lessees and natural gas midstream customers, including our lessees’ ability to satisfy their royalty, environmental, reclamation and other obligations to us and others; operating risks, including unanticipated geological problems, incidental to our coal and natural resource management or natural gas midstream businesses; our ability to acquire new coal reserves or natural gas midstream assets and new sources of natural gas supply and connections to third-party pipelines on satisfactory terms; our ability to retain existing or acquire new natural gas midstream customers and coal lessees; the ability of our lessees to produce sufficient quantities of coal on an economic basis from our reserves and obtain favorable contracts for such production; the occurrence of unusual weather or operating conditions including force majeure events; delays in anticipated start-up dates of our lessees’ mining operations and related coal infrastructure projects and new processing plants in our natural gas midstream business; environmental risks affecting the mining of coal reserves or the production, gathering and processing of natural gas; the timing of receipt of necessary governmental permits by us or our lessees; hedging results; accidents; changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with respect to emissions levels applicable to coal-burning power generators; uncertainties relating to the outcome of current and future litigation regarding mine permitting; risks and uncertainties relating to general domestic and international economic (including inflation, interest rates and financial and credit markets) and political conditions (including the impact of potential terrorist attacks); and other risks set forth in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission, including our Annual Report on Form 10-K for the year ended December 31, 2009.  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.

3 Diversified, Relatively Low-Risk Asset Base Strategically Located Coal Reserves and Midstream Assets Stable and Predictable Coal Royalty Business Solid Balance Sheet and Attractive Yield Stable Cash Flows and Distribution Coverage Well Positioned to Capitalize on Partnership Momentum & Industry Trends Hedged Midstream Business with Growing Fee-Based Volumes Key Investment Highlights

4 Current Structure Penn Virginia Resource Partners, L.P. (NYSE: PVR) Public Unitholders 32.7 MM Common Units 60.4% LP interest Penn Virginia GP Holdings, L.P. (NYSE: PVG) Public Unitholders 39.1 MM Common Units 100% LP interest Penn Virginia Resource GP, LLC 100% ownership 2% GP Interest and Incentive Distribution Rights 37.6% LP interest 19.6 MM PVR Common Units Notes: 1) Chart displays simplified organizational structure 2) Units outstanding and ownership interests are rounded approximations Penn Virginia Operating Co., LLC and its subsidiaries

5 Coal royalty business, not coal mining Managed coal properties since 1882 Controls 829 MM tons of high quality coal reserves (24 year R/P ratio) Long-term leases with experienced operators Ancillary businesses include coal services, timber and gas royalties Coal & Natural Resource Management ~ 2/3 of 2009 Adjusted EBITDA (1) Natural Gas Midstream ~ 1/3 of 2009 Adjusted EBITDA (1) $185 million of 2009 Adjusted EBITDA (1) Traditional gathering and processing business Assets are located in attractive natural gas basins with long-lived reserves – 4,118 miles of pipelines – 6 processing facilities – 400 MMcfd of capacity Average throughput volume 332 MMcfd in 2009 (1) Adjusted EBITDA is a non-GAAP financial measure. See Appendix for a reconciliation of Adjusted EBITDA to net income and cash flow from operations Overview

6 Coal & Natural Resource Management San Juan Basin Northern Appalachia Illinois Basin Central Appalachia Coal reserves located in major supply basins Access to major coal hauling railroads and inland waterways Close proximity to power generation facilities Gathering systems located in major gas basins Reserves in Oklahoma, North Texas and East Texas are moderately declining and long- lived Significant growth potential from Marcellus Shale Crossroads Arkoma Panhandle North Texas Thunder Creek Hamlin Natural Gas Midstream Marcellus Crescent Strategically Located Assets

Coal and Natural Resource Management 7

8 ~ 2/3 of 2009 Adjusted EBITDA (1) (1) Adjusted EBITDA is a non-GAAP financial measure. See Appendix for a reconciliation of Adjusted EBITDA to net income and cash flow from operations (2) Does not include June 2010 acquisition of 10 millions tons of Pittsburgh Seam reserves.  With that acquisition, the N. Appalachia R/P ratio is 8.8 years Coal & Natural Resource Management 33.0 603.9 18.3 Central Appalachia 5.0 37.4 7.5 San Juan Basin 34.9 163.9 4.7 Illinois Basin 6.2 23.4 3.8 Northern Appalachia (2) R/P Ratio (years) Proven / Probable Reserves (MM tons) 2009 Lease Production (MM tons) Region 24.2 years R/P Ratio: 828.6 MM tons Proved / Probable Reserves: 34.3 MM tons 2009 Lease Production Coal Production & Reserves

9 Coal – Attractive Long Term Fundamentals EIA (1) forecasts that coal: usage will continue to increase for next 25 years will continue to be the dominant fuel for electric power generation in the U.S. will retain its cost advantage as the cheapest energy source (1) Annual Energy Outlook 2010 (March 2010), Energy Information Administration (EIA) Coal Liquid Fuels Natural Gas Other 0 20 40 60 80 100 120 140 U.S. Energy Supply Composition By Primary Source Fuel Oil Natural Gas Steam Coal 0 5 10 15 20 25 Coal Petroleum Natural Gas Nuclear Other 0 1000 2000 3000 4000 5000 6000 Energy Prices (2) U.S. Electrical Generation By Fuel Type (2) Prices paid for energy by Electric Generation Sector as reported by EIA

10 Coal Royalty vs. Coal Operator Coal royalty – not a coal mining operation Historical Coal Prices vs. Coal Royalty Revenue Majority of our royalty payments (82%) are based on the higher of a percentage of the gross sales price or a fixed price per ton – Our lessees generally sell their coal under long-term fixed-price contracts (1 – 5 years), which provides cash flow stability Contracts with our lessees are long-term, with an average life of 10 – 15 years No direct exposure to mine operating costs and risks or reclamation costs Minimal maintenance capital expenditure requirements Coal Royalty Business - Stable and Predictable High Low Reclamation Exposure High Low Social Costs (e.g. benefits, black lung) High Medium Reinvestment Requirements Variable High Cash Flow Stability Variable High Operating Margins Coal Operator Coal Royalty Characteristic 0 20 40 60 80 100 120 140 0 5 10 15 20 25 30 35 40 Quarterly Coal Royalty Revenue Central Appalacia Illinois Basin

Consists of a combination of surface and underground mines located in KY, VA and WV Lessees customers are primarily electric utilities Coal is higher quality, lower sulfur Proximity to East Coast ports make these mines an ideal source of exports Central Appalachia (73% of Reserves) Illinois Basin (20% of Reserves) Comprised of properties in southern Illinois and western Kentucky Acquired 169 MM tons of reserves in the Illinois Basin beginning in 2005 The installation of scrubbers by Eastern and Midwestern utilities has increased demand for the high sulfur coal in the Illinois Basin Primary Coal Basins 11

Northern Appalachia (3% of Reserves) San Juan Basin (4% of Reserves) Northern Appalachia holdings consist of the Federal and Upshur properties Reserves are 100% owned and 98% have been leased to operators Our Lee Ranch property is located in the San Juan Basin of northwestern New Mexico and contains only surface coal mines Increased production from 2006 to 2007, whereas statewide coal production dropped Other Coal Basins 12

13 Changes in Coal Reserves: 2002 – 2009 Coal Production Reserves by Type – 2009 Net Royalties by Region – 2009 Reserves by Region – 2009 Coal – Operations 492.8 571.3 (235.5) 0 200 400 600 800 1000          Reserves         12/31/01        Production      2002-2009        Acquired        2003-2009 828.6 0 5 10 15 20 25 30 35 40 2004 2005 2006 2007 2008 2009 Central Appalachia San Jaun Basin Illinois Basin Northern Appalachia Central Appalachia 69% San Juan Basin 14% Illinois Basin 11% Northern Appalachia 6% Central Appalachia 73% San Juan Basin 4% Illinois Basin 20% Northern Appalachia 3% Steam 89% Metallurgical 11%

Fees charged to lessees for use of coal preparation and loading facilities JV formed in July 2004 – Fee-based revenues – Predictable cash flows Services 5% of Coal & NRM Net Revenue (1) Approximately 243,000 acres of forestland in Kentucky, Virginia and West Virginia – Premium quality hardwood primarily used for furniture Timber 4% of Coal & NRM Net Revenue (1) In October 2007, we purchased oil and gas royalties located on 165,000 acres in eastern Kentucky and southwestern Virginia – Almost all of our oil and gas royalty interests are associated with leases of these properties Oil & Gas Royalties 2% of Coal & NRM Net Revenue (1) Services, Timber & Oil & Gas Royalties 14 Represents 2009 Coal & NRM revenue less Coal Royalty expenses (1)

Natural Gas Midstream 15

16 ~ 1/3 of 2009 Adjusted EBITDA (1) (1) Adjusted EBITDA is a non-GAAP financial measure. See Appendix for a reconciliation of Adjusted EBITDA to net income and cash flow from operations Natural Gas Midstream Overview 47 80 8 Crossroads 8 20 AMIs with Range Resources and a private E&P company Marcellus 18 N/A 134 North Texas 13 N/A 78 Arkoma 224 260 1,681 Panhandle 516 Hamlin 22 40 1,701 Crescent 375 N/A 588 Thunder Creek (25% JV) 2009 Volume (MMcfd) Processing Capacity (MMcfd) Gathering Pipeline (Miles) System 332 MMcfd 2009 Avg. System Throughput Vol: 400 MMcfd Natural Gas Processing Capacity: 4,118 Miles Gathering Pipeline: Natural Gas Midstream Systems

17 Significant organic fee-based growth potential from Crossroads, Thunder Creek and Marcellus project (initial start-up in late 2010 / early 2011) Target hedging 50-60% of remaining commodity-sensitive volumes over 2 years – Currently, 60% of 2010 and 58% of 2011 price-sensitive volumes are hedged Additionally, many gas purchase / keep-whole contracts contain a processing fee floor Volumes by Contract – 2004 Volumes by Contract – 2009 Since entering the midstream business, we have focused on reducing commodity price risk: – Acquiring fee-based businesses (North Texas and Thunder Creek) – Pursuing green field projects backed by fee-based contracts (Crossroads and Marcellus) – Converting a portion of existing keep-whole contracts to fee-based or POP Hedged Midstream Business with Growing Fee-Based Volumes Fee- Based 14% Keep- Whole 52% Percent-of- Proceeds 34% Fee-Based 19% Keep- Whole 28% Percent-of- Proceeds 53%

18 Gas Rig Count vs. Natural Gas Production Lower 48 State On-Shore Gas Production Oil-to-Natural Gas Price Ratio Source: Energy Information Administration, Baker Hughes, and Bloomberg Our assets are well positioned to benefit from increasing activity in emerging resource plays: – Granite Wash – Marcellus Shale – Haynesville Shale / Horizontal Cotton Valley Attractive processing economics are expected to persist Well Positioned Asset Base 0 200 400 600 800 1000 1200 1400 1600 1800 50 52 54 56 58 60 62 64 66 Rig Count Production 0 2 4 6 8 10 12 14 16 18 20 Shale gas drives future production growth 0.0x 5.0x 10.0x 15.0x 20.0x 25.0x 1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 Conventional Shale Gas Coalbed Methane Oil Associated

19 Gathering system in the Anadarko Basin of Texas and Oklahoma Comprised of a number of major gathering systems and compressor stations – Beaver / Spearman plants – 200 MMcfd of inlet capacity – Sweetwater plant – Acquired in July 2009, 60 MMcfd of inlet capacity Approximately 203 producers pursuant to 332 contracts Positioned to capitalize on the development of the Granite Wash Overview Operating Statistics Processing Plants 3 Processing Capacity (MMcfd) 260 Gathering System Length (miles) 1,681 Panhandle System

20 Crossroads Gathering system in Oklahoma’s Sooner Trend Consists of 1,701 miles of pipeline and 15 related compressor stations – Crescent processing plant – NGL recovery plant with capacity of 40 MMcfd Wells are generally low-volume and long-lived with large NGL quantities Crescent Thunder Creek Gas Services Hamlin Arkoma North Texas Gathering system stretching over West Central Texas with the Hamlin processing plant located in Fisher County, Texas Consists of 500+ miles of pipeline and 8 related compressor stations – Hamlin plant – 20 MMcfd capacity Consists of three separate stand- alone gathering systems in southeastern Oklahoma’s Arkoma Basin – Two systems are 100% owned, third system is 49% owned – Average 2009 throughput volume of 13 MMcfd Purchased 25% JV interest in Thunder Creek from Kinder Morgan Energy Partners (April ‘08) in Wyoming’s Powder River Basin – Devon Energy owns the other 75% interest 100% fee-based model Average 2009 throughput volume of 375 MMcfd Located in the southeast portion of Harrison County, Texas Anchored by a long-term commitment under a fee-based arrangement 80 MMcfd of inlet capacity Centered around 5 major producers Positioned for growth from Haynesville Shale Acquired gas gathering and transportation assets in the Barnett Shale play in the Fort Worth Basin – 134 miles of gathering pipeline – Approximately 240,000 acres 100% fee-based revenues – Potential to increase revenues through addition of processing, treating and other services Natural Gas Midstream – Other Systems

21 AMI with Range Resources in Lycoming, Bradford and Tioga Counties, PA – PVR to provide gathering, compression and related services – Range to initially dedicate over 75,000 acres with ongoing active lease acquisition program within the Area of Mutual Interest (“AMI”) – Gathering system will have over 700 MMcfd of throughput capacity Total capital investment: – Expect $170 – $200 million between 2010 and 2015 (approx. $60 million in 2010) 100% fee-based: – Firm reservation charges that provide a floor on returns – Additional volumetric fees based upon delivered volumes Area Infrastructure and Range Positions Tennessee 300 Line • Connects Gulf coast and Rockies supply with northeastern markets • Capability to move 400 MMcfd of Marcellus production Transco Leidy Lateral • Connects Leidy storage facility   with northeastern markets • Capability to move 1.5 Bcfd of Marcellus production through physical or backhaul transport Columbia Gas Transmission / Columbia Gulf Marcellus Fairway Areas under development Texas Eastern Transmission Tennessee Gas Pipeline Dominion Transmission Transcontinental Gas Pipeline Marcellus Project Provides Significant Fee-Based Growth

22 Distributable Cash Flow (1) vs. Distributions Annual Adjusted EBITDA (1) $0 $40 $80 $120 $160 $200 2005 2006 2007 2008 2009 $0 $35 $70 $105 $140 $175 2005 2006 2007 2008 2009 Distributions DCF (1) Adjusted EBITDA and Distributable Cash Flows are non-GAAP financial measures. See Appendix for a reconciliations of these measures to GAAP financial measures Relatively moderate maintenance capital expenditure requirements Target distribution coverage ratio of 1.2x Target long-term debt / EBITDA ratio of < 3.5x Growth financed 50% debt / 50% equity Debt / Adjusted EBITDA (1) Average: 2.7x 0.0x 1.0x 2.0x 3.0x 4.0x 2005 2006 2007 2008 2009 Financial Overview

23 Conservative Pro Forma Leverage with Strong Liquidity Profile Balance Sheet as of June 30, 2010 (1) Adjusted EBITDA is a non-GAAP financial measure.  See Appendix for a reconciliation of Adjusted EBITDA to operating income and cash flows from operations (2) On August 13, 2010, PVR closed on an amended 5 year credit facility of $850 million (3) Revolver availability includes adjustment for $1.6 million in letters of credit Conservative Capitalization Total Debt 646.5 $      Partners' Capital 459.4          Total Capitalization 1,105.9 $   LTM Adjusted EBITDA (1) 190.6          Debt / Adjusted EBITDA 3.4x Debt / Capitalization 58% Revolver Capacity (2) 850.0          Revolver Availability (3) 501.9

Diversified, Relatively Low-Risk Asset Base Strategically Located Coal Reserves and Midstream Assets Stable and Predictable Coal Royalty Business Solid Balance Sheet and Attractive Yield Stable Cash Flows and Distribution Coverage Well Positioned to Capitalize on Partnership Momentum & Industry Trends Hedged Midstream Business with Growing Fee-Based Volumes Conclusion: Key Investment Highlights 24

25 Appendix • PVR / PVG Merger • Hedging Strategy • Financial Information

26 PVR and PVG will file a joint proxy statement/prospectus and other documents with the SEC in relation to the merger. Investors are urged to read these documents carefully when they become available because they will contain important information regarding PVR, PVG, and the transaction.  A definitive joint proxy statement/prospectus will be sent to unitholders of PVR and PVG seeking their approvals as contemplated by the merger agreement. Once available, investors may obtain a free copy of the joint proxy statement/prospectus and other documents containing information about PVR and PVG, without charge, at the SEC’s website at www.sec.gov. Copies of the joint proxy statement/prospectus and the SEC filings that will be incorporated by reference in the joint proxy statement/prospectus may also be obtained free of charge by contacting investor relations at 610-975-8204, or by accessing www.pvresource.com or www.pvgpholdings.com. PVR, PVG, and the officers and directors of the general partner of each partnership may be deemed to be participants in the solicitation of proxies from their security holders. Information about these entities and persons can be found in PVR’s and PVG’s Annual Reports on Form10-K for the year ended December 31, 2009. Additional information about such entities and persons may also be obtained from the joint proxy statement/prospectus when it becomes available. PVR / PVG Merger Legal Notices Certain statements by PVR and PVG contained herein that are not descriptions of historical facts are “forward-looking” statements by PVR and PVG 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. Words such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” and similar expressions are intended to identify such forward-looking statements.  These forward-looking statements include, without limitation, the anticipated benefits and other aspects of the proposed merger, future financial and operating results and expectations and intentions with respect to future operations and services, approval of the proposed transaction by PVR and PVG unitholders, the satisfaction of the closing conditions to the proposed transaction, and the timing of the completion of the proposed transaction.  Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements.   Many of the factors that will determine PVR’s and PVG's 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. PVR and PVG undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as the result of new information, future events or otherwise. These risks as well as other risks, uncertainties and contingencies are discussed in more detail in PVR’s and PVG's joint press release and public periodic filings with the Securities and Exchange Commission (“SEC”), including PVR’s and PVG's Annual Reports on Form 10-K for the year ended December 31, 2009 and most recent Quarterly Reports on Form 10-Q.

27 PVR / PVG Merger - Transaction Summary • The boards of directors of PVR and PVG have agreed to a merger of the two partnerships in a tax-free, 100% equity exchange – Terms of the merger were approved by the conflicts committees and boards of PVR and PVG – The merger is subject to approval by a majority of each of PVR’s and PVG’s unitholders – PVG has agreed to vote its approximate 37.6% interest in PVR units in favor of the merger • PVG unitholders will receive 0.98 PVR limited partnership (“LP”) units in exchange for each PVG LP unit they own • The merger would result in 38.3 million additional PVR units being issued and the cancellation of the approximate 19.6 million PVR LP units currently owned by PVG – Following the merger, the former PVG unitholders will own approximately 54% of PVR’s LP units • The merger would result in PVR owning its General Partner and the cancellation of PVG’s incentive distribution rights (“IDRs”) • The PVR management team will continue in their current roles • PVR’s unitholders will elect all of the directors of its general partner’s board of directors beginning in 2011 – All three of PVG’s independent directors are expected to join PVR’s board of directors • The transaction is expected to result in dilution of PVR’s distributable cash flow per unit of approximately 1.0% in 2011 (a) – Thereafter, the transaction is expected to be accretive as the economic benefits of the merger are realized (a) Accretion / dilution calculations are based on management assumptions – see PVR/PVG merger presentation dated 9/22/2010

28 Current Structure Penn Virginia Resource Partners, L.P. (NYSE: PVR) Public Unitholders 32.7 MM Common Units 60.4% LP interest Penn Virginia GP Holdings, L.P. (NYSE: PVG) Public Unitholders 39.1 MM Common Units 100% LP interest Penn Virginia Resource GP, LLC 100% ownership 2% GP Interest and Incentive Distribution Rights 37.6% LP interest 19.6 MM PVR Common Units Notes: 1) Chart displays simplified organizational structure 2) Units outstanding and ownership interests are rounded approximations Penn Virginia Operating Co., LLC and its subsidiaries

29 Post-Transaction Structure Penn Virginia Resource Partners, L.P. (NYSE: PVR) Public Unitholders 71.0 Million Common Units 100% LP interest Penn Virginia Operating Co., LLC and its subsidiaries Penn Virginia Resource GP, LLC 100% (Indirect) Non-economic GP interest Notes: 1) Chart displays simplified organizational structure 2) Units outstanding and ownership interests are rounded approximations

30 Expected Merger Benefits The merger is expected to provide benefits to both PVR and PVG unitholders, including: • Lower Cost of Capital – Elimination of the IDRs will reduce PVR’s cost of capital – Lower cost of capital enhances the cash accretion from investments in internal growth projects and acquisitions – Strengthens PVR’s overall competitive position when pursuing growth opportunities • Simplified Structure – Provides a capital structure more easily understood by the investing public – Streamlines governance of PVR – Eliminates the potential for conflicts of interest from dual management roles – Reduces G&A costs associated with the elimination of one publicly traded entity • Enhanced Investor and Market Profile – Improves transparency for debt and equity investors – Attracts a broader investor base by increasing the public float and trading liquidity of the market for PVR’s LP units – Provides PVR’s unitholders the right to elect all of the directors of its general partner’s board of directors • Based on the exchange ratio and upon closing of the merger, PVG unitholders quarterly cash distributions will increase 18%

31 Derivative Hedging Strategy • PVR is long NGLs and short natural gas • Active hedge strategy to mitigate commodity price risk – Exposed to “frac spread” risk through wellhead purchase contract and to direct commodity price risk through percent- of-proceeds contacts • Current and future hedges – 2010 hedges are 60% of current price-sensitive volumes – 2011 hedges are 58% of current price-sensitive volumes – Target hedging 50-60% of price sensitive exposure out 2 years • Sensitivity to commodity price changes is expected to decrease as a result of increasing fixed-fee volumes from the Marcellus Shale, Thunder Creek and Crossroads

32 $51.2 30.6 - 13.0 (4.8) 1.3 - (4.6) $86.7 $104.5 58.2 31.8 (11.4) (38.5) (0.2) - (14.5) $129.9 ($ in millions) Year Ended December 31, 2009 2008 2007 2006 2005 2004 Net Income DD&A Impairments Total derivative losses (gains) Cash settlements of derivatives Equity earnings from jv’s, net of distributions. Other Other CAPEX Distributable Cash Flow $34.3 18.6 - - - 0.6 - (0.1) $53.4 $73.9 37.5 - 13.2 (19.4) 1.3 4.6 (9.5) $101.6 $56.6 41.5 - 50.2 (17.8) (0.3) - (9.8) $120.5 $65.2 70.2 1.5 22.7 3.0 (2.5) - (8.4) $151.7 PVR - Historical Distributable Cash Flow Summary Distributable Cash Flow Reconciliation

33 (in thousands) 2009 2008 2007 2006 2005 Reconciliation of net income to Adjusted EBITDA: Net income $      65,215 $    104,500 $      56,623 $      73,928 $      51,161 Depreciation, depletion and amortization          70,235          58,166          41,512          37,493          30,628 Interest expense          24,653          24,672          17,338          18,821          14,054 EBITDA        160,103        187,338        115,473        130,242          95,843 Impairments            1,511          31,801                 -                   -                   -   Equity earnings, net of distributions received           (2,537)             (224)             (285)            1,317            1,269 Derivative losses (gains)          22,700         (11,357)          50,163          13,213          13,036 Net cash settlements of derivatives            3,000         (38,466)         (17,779)         (19,436)           (4,752) Adjusted EBITDA $    184,777 $    169,092 $    147,572 $    125,336 $    105,396 Reconciliation of cash flows from operating activities to Adjusted EBITDA: Cash flows from operating activities $    159,972 $    139,176 $    127,824 $    107,344 $      93,712 Changes in operating assets and liabilities            5,308            6,529            2,243               (60)             (635) Non-cash interest expense           (4,391)           (2,693)             (678)             (769)           (1,735) Interest expense          24,653          24,672          17,338          18,821          14,054 Equity earnings, net of distributions received            2,537              224              285           (1,317)           (1,269) Derivative gains (losses)         (22,700)          11,357         (50,163)         (13,213)         (13,036) Cash settlement on derivatives           (3,000)          38,466          17,779          19,436            4,752 Impairments           (1,511)         (31,801)                 -                   -                   -   Other             (765)            1,408              845                 -                   -   EBITDA        160,103        187,338        115,473        130,242          95,843 Impairments            1,511          31,801                 -                   -                   -   Equity earnings, net of distributions received           (2,537)             (224)             (285)            1,317            1,269 Derivative losses (gains)          22,700         (11,357)          50,163          13,213          13,036 Net cash settlements of derivatives            3,000         (38,466)         (17,779)         (19,436)           (4,752) Adjusted EBITDA $    184,777 $    169,092 $    147,572 $    125,336 $    105,396 Year Ended December 31, PVR - Historical Adjusted EBITDA Summary Reconciliation of Adjusted EBITDA