UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 20062007

Commission File Number:file number: 1-13283

Penn Virginia Corporation

(Exact name of registrant as specified in its charter)

Three Radnor Corporate Center, Suite 300

100 Matsonford Road

Radnor, Pennsylvania 19087

(Address of principal executive offices)

Registrant’s telephone number, including area code: (610) 687-8900

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Indicate by check mark if the registrant is a well known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.    Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a non-accelerated filer.smaller reporting company. See definitionthe definitions of “large accelerated filer,” “accelerated filerfiler” and large accelerated filer”“smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One)

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

The aggregate market value of common stock held by non-affiliates of the registrant was $1,289,572,927$1,506,589,912 as of June 30, 20062007 (the last business day of its most recently completed second fiscal quarter), based on the last sale price of such stock as quoted on the New York Stock Exchange. For purposes of making this calculation only, the registrant has defined affiliates as including all directors and all executive officers of the registrant, but excluding any institutional shareholders. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of February 28, 2007, 18,791,8692008, 41,632,971 shares of common stock of the registrant were issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

Table of Contents

PARTPart I

General

Penn Virginia Corporation (NYSE: PVA) is a Virginia corporation founded in 1882 whose common stock is traded on the New York Stock Exchange under the symbol “PVA.” We arean independent oil and gas company primarily engaged in the exploration, development and production of crudenatural gas and oil in various onshore U.S. regions including East Texas, the Mid-Continent, Appalachia, Mississippi and the Gulf Coast. We also indirectly own partner interests in Penn Virginia Resource Partners, L.P. (NYSE: PVR), or PVR, a publicly traded limited partnership which is engaged in the coal and natural resource management and natural gas primarilymidstream businesses. Our ownership interests in the Appalachian, Mississippi, Mid-ContinentPVR are held principally through our general partner interest and Gulf Coast onshore areasour 82% limited partner interest in Penn Virginia GP Holdings, L.P. (NYSE: PVG), or PVG, a publicly traded limited partnership. PVG owns 100% of the United States.general partner of PVR, which holds a 2% general partner interest in PVR, and an approximately 42% limited partner interest in PVR. See “—Corporate Structure.” We also collect royaltiesconsolidate PVG’s results into our financial statements. In 2007, we had an approximately 82% interest in PVG’s net income. We received cash distributions of $29.6 million, $28.3 million and $21.2 million for the years ended December 31, 2007, 2006 and 2005 on various oilaccount of our partner interests in PVG and gas propertiesPVR. Our operating income was $192.6 million in which we own a mineral fee interest.2007, compared to $170.5 million in 2006 and $162.0 million in 2005. Unless the context requires otherwise, references to the “Company,” “we,” “us” or “our” in this Annual Report on Form 10-K refer to Penn Virginia Corporation and its subsidiaries.

We are also indirectly involved in the businesses engaged in by Penn Virginia Resource Partners, L.P., or PVR, a Delaware limited partnership whose common units are traded on the New York Stock Exchange under the symbol “PVR.” We own PVG GP, LLC, the sole general partner of Penn Virginia GP Holdings, L.P., or PVG, a Delaware limited partnership whose common units are traded on the New York Stock Exchange under the symbol “PVG.” We also own an approximately 82% limited partner interest in PVG. As of December 31, 2006, PVG owned approximately 44% of PVR, consisting of a 2% general partner interest and an approximately 42% limited partner interest in PVR. We directly own an additional 0.6% interest in PVR. As part of its ownership of PVR’s general partner, PVG also own the rights, referred to as “incentive distribution rights,” to receive an increasing percentage of PVR’s quarterly distributions of available cash from operating surplus after certain levels of cash distributions have been achieved. See Item 1, “Business—Partnership Distributions,” for more information on incentive distribution rights.

PVR conducts operations in two business segments: coal and natural gas midstream. PVR does not operate any coal mines, but rather leases its coal reserves to various mining operators in exchange for royalty payments. Additionally, PVR provides fee-based coal preparation and loading facilities to some of its lessees and to other third party industrial end-users. With the acquisition of a natural gas midstream business in March 2005, PVR entered the midstream gas gathering and processing business with primary locations in the Mid-Continent area of Oklahoma and the Texas panhandle.

Segments

We operateare engaged in three primary business segments. We are in the crudesegments: (1) oil and gas, (2) coal and natural resource management and (3) natural gas explorationmidstream. We operate our oil and production businessgas segment. PVR operates our coal and through our direct and indirect ownership interests in PVR, we are in the coalnatural resource management and natural gas midstream businesses.segments. In 2006, approximately 50% of our operating income was attributable to our2007, the oil and gas segment 43% was attributable to ourcontributed $104.0 million, or 54%, the PVR coal and natural resource management segment contributed $69.0 million, or 36%, and 17% was attributable to ourthe PVR natural gas midstream segment less a 10%contributed $48.9 million, or 25%, to operating loss related to corporateincome. Corporate and other functions. See Note 20functions resulted in the Notes to Consolidated Financial Statements for financial information concerning our business segments.$29.3 million of operating expenses.

Oil and Gas Segment Overview

We have a geographically diverse asset base with core areas of operation in East Texas, the Mid-Continent, Appalachia, Mississippi and the South Louisiana and South Texas Gulf Coast regions of the United States. As of December 31, 2007, we had proved natural gas and oil reserves of approximately 680 Bcfe, of which 87% were natural gas and 59% were proved developed. As of December 31, 2007, 95% of our proved reserves were located in primarily longer-lived, lower-risk basins in East Texas, the Mid-Continent, Appalachia and Mississippi. Wells in these regions are generally characterized by predictable production profiles. Our Gulf Coast properties, representing 5% of proved reserves, are shorter-lived and have higher impact drilling prospects that provide a complementary counterbalance to our longer-lived assets. In 2007, we produced 40.6 Bcfe, a 30% increase compared to 31.3 Bcfe in 2006. As of December 31, 2007, we operated approximately 95% of the net wells in which we held a working interest. In the three years ended December 31, 2007, we drilled 677 gross (507.0 net) wells, of which 95% were successful in producing natural gas in commercial quantities. For a more detailed discussion of our reserves and production, see Item 2, “Properties.”

We have grown our reserves and production primarily through development and exploratory drilling, complemented by strategic acquisitions. In 2007, we added 255 Bcfe of proved reserves, 71% of which was added through the drillbit, for a total reserve replacement rate of 628% of production. In 2007, capital expenditures in our oil and gas segment were $520.4 million, of which $333.2 million, or 64%, was related to development drilling and facilities, $141.9 million, or 27%, was related to acquisitions and $45.3 million, or 9%, was related to exploratory activity. During 2007, we explore for, develop, produceacquired properties with 74.4 Bcfe of proved reserves and sell crude oil, condensatesold properties with 21.5 Bcfe of proved reserves. For a more detailed discussion of our acquisitions, see Item 7, “Management’s Discussion and natural gas primarily in the Appalachian, Mississippi, Mid-ContinentAnalysis of Financial Condition and Gulf Coast onshore regionsResults of the United States. At December 31, 2006, we had proved oilOperations—Acquisitions, Dispositions and natural gas reserves of approximately 5 million barrels of oil and condensate and 457 billion cubic feet (or Bcf) of natural gas, or 487 billion cubic feet equivalent (or Bcfe). Oil and natural gas production from our properties increased to 31.3 Bcfe in 2006, an increase of 14% from 27.4 Bcfe produced in 2005.

Our revenues, profitability and future rate of growth are highly dependent on the prevailing prices for oil and natural gas, which are affected by numerous factors that are generally beyond our control. Crude oil prices are generally determined by global supply and demand. Natural gas prices are influenced by national andInvestments.”

regional supplyOur operations include both conventional and demand. A substantial or extended decline in the price of oil or natural gas could have a material adverse effect on our revenues, profitability and cash flow and could, under certain circumstances, result in an impairment ofunconventional developmental drilling opportunities, as well as some of our oil and natural gas properties. Our future profitability and growth is also highly dependent on the results of our exploratory and development drilling programs.

prospects. In addition to our conventional development program, we have continued to expand our development of unconventional plays such as coal bed methane (or CBM) gas reserves in Appalachia and Mid-Continent and the Cotton Valley play in east Texas.East Texas, we drilled 120 gross wells in 2007 and added a sixth drilling rig in the second half of 2007. We are committedshifting focus to expanding our oil and gasinfill drilling on 20-acre spacing, which may increase proved reserves and production primarily by developing our existing inventory of drilling locationslevels. In Appalachia, we drilled 41 gross wells in 2007, including 27 gross horizontal coalbed methane locations. In the Selma Chalk play in Mississippi, we drilled 73 gross wells in 2007, including two successful horizontal wells. We also have unconventional development programs in the Mid-Continent and by using our ability to internally generatesome higher-impact exploratory prospects and development drilling programs.in the Gulf Coast.

PVR Coal and Natural Resource Management Segment Overview

PVR’sThe PVR coal and natural resource management segment includesprimarily involves the management and leasing of coal and natural resource properties and the subsequent collection of royalties. Substantially all of PVR’s leases require the lessee to pay minimum rental payments to PVR in monthly or annual installments. PVR actively works with its lessees to develop efficient methods to exploit its reserves and to maximize production from its properties. PVR also earns revenues from providingthe provision of fee-based coal preparation and transportationloading services, tofrom the sale of standing timber on its lessees, which enhance their production levels and generate additional coal royalty revenues, and from industrial third party coal end-users by owning and operating coal handling facilities through its joint venture with Massey Energy Company, or Massey. In addition, PVR earns revenuesproperties, from oil and gas royalty interests it owns and from coal transportation, or wheelage, rights and from the sale of standing timber on its properties.fees.

As of December 31, 2006,2007, PVR owned or controlled approximately 765818 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. As of December 31, 2006,2007, approximately 87%89% of PVR’s proven and probable coal reserves waswere “steam” coal used primarily by electric generation utilities, and the remaining 13% was11% were metallurgical coal used primarily by steel manufacturers. PVR enters into long-term leases with experienced, third-party mine operators, providing them the right to mine its coal reserves in exchange for royalty payments. PVR actively works with its lessees to develop efficient methods to exploit its reserves and to maximize production from its properties. PVR does not operate any mines. In 2006,2007, PVR’s lessees produced 32.832.5 million tons of coal from its properties and paid to PVR coal royaltyroyalties revenues of $98.2$94.1 million, for an average gross coal royalty per ton of $2.99.$2.89. Approximately 81% of PVR’s coal royalties revenues in 2007 and 84% of PVR’s coal royaltyroyalties revenues in 2006 and 83% of PVR’s coal royalty revenues in 2005 were derived from coal mined on its properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of PVR’s coal royaltyroyalties revenues for the respective periods was derived from coal mined on its properties under leases containing fixed royalty rates that escalate annually.

PVR’s management continues to focus on acquisitions that increase See “—Contracts—PVR Coal and diversify its sources of cash flow. During 2006, PVR increased its coal reserves by 96 million tons, or 14%, from its coal reserves as of December 31, 2005, by completing three coal reserve acquisitions with an aggregate purchase price of approximately $76 million. ForNatural Resource Management Segment” for a more detailed discussiondescription of PVR’s acquisitions, see Item 7, “Managements’ Discussion and Analysis of Financial Condition and Results of Operations—Acquisitions and Investments.”coal leases.

PVR Natural Gas Midstream Segment Overview

The PVR natural gas midstream segment is engaged in providing gas processing, gathering and other related natural gas services. PVR owns and operates natural gas midstream assets thatlocated in Oklahoma and the panhandle of Texas. These assets include approximately 3,6313,682 miles of natural gas gathering pipelines and three natural gas processing facilities located in Oklahoma and the panhandle of Texas, which havehaving 160 million cubic feet per day (or MMcfd)MMcfd of total capacity. PVR’s natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines. PVR acquired its first natural gas midstream assets fromthrough the acquisition of Cantera Gas Resources, LLC, or Cantera, in March 2005. PVR’s management believes that this acquisition established a

platform for future growth in the natural gas midstream sector and diversified its cash flows into another long-lived asset base. Since acquiring these assets, PVR has expanded its natural gas midstream business by adding 181 miles of new gathering lines.

For the year ended December 31, 2006, inletIn 2007, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 56.067.8 Bcf, or approximately 153186 MMcfd. TwoIn 2007, one of PVR’s natural gas midstream customers, ConocoPhillips Company, and BP Canada Energy Marketing Corp., accounted for 32% and 17%25% of PVR’s natural gas midstream revenues in 2006.and 13% of our total consolidated revenues.

Corporate and Other

Corporate and other primarily represents corporate functions.

Business Strategy

We intend to pursue the following business strategies:

acreageacquisitions, see Item 7, “Management’s Discussion and by contracting for natural gas that has been released from competitors’ systems. In 2006, PVR added approximately 181 milesAnalysis of new gathering lines, allowing it to connect 158 new wells to its systems.Financial Condition and Results of Operations—Acquisitions, Dispositions and Investments.”

Contracts

Oil and Gas Segment

Transportation.Transportation. The majority of our natural gas production is transported to market on three major pipeline or transmission systems. NiSource Inc., Crosstex Energy Services L.P. and Gulf South Pipeline Company, LPDuke Energy Corporation transported 32%approximately 16%, 20%19% and 19%21% of our 20062007 natural gas production. The remainder of our natural gas production was transported by several pipeline companies in Louisiana, Texas and West Virginia. In almost all cases, our natural gas is sold at interconnects with transmission pipelines.

We have entered into contracts which provide firm transportation capacity rights for specified volumes per day on a pipeline system for terms ranging from one to 15 years. The contracts require us to pay transportation demand charges regardless of the amount of pipeline capacity we use. We may sell excess capacity to third parties at our discretion.

Marketing.Marketing. We generally sell our natural gas using spot market and short-term fixed price physical contracts. For the year ended December 31, 2006, three customers2007, two of our oil and gas segment,customers, Crosstex Gulfcoast Marketing Dominion Field Services and Amerada HessDuke Energy Corporation, accounted for approximately 24%, 22%17% and 11%18% of our natural gas and oil and condensate revenues and 6% and 6% of $234.2 million.our total consolidated revenues.

PVR Coal and Natural Resource Management Segment

PVR earns most of its coal royaltyroyalties revenues under long-term leases that generally require its lessees to make royalty payments to it based on the higher of a percentage of the gross sales price or a fixed price per ton of coal they sell. The balance of PVR’s coal royaltyroyalties revenues are earned under two long-term leases with affiliates of Peabody Energy Corporation (NYSE: BTU), or Peabody, that require the lessees to make royalty payments to PVR based on fixed royalty rates which escalate annually. A typical lease either expires upon exhaustion of the leased reserves which is the case with the two Peabody leases, or has a five to ten-year base term, with the lessee having an option to extend the lease for at least five years after the expiration of the base term.

Substantially all of PVR’s leases require the lessee to pay minimum rental payments to PVR in monthly or annual installments, even if no mining activities are ongoing. These minimum rentals are recoupable, usually over a period from one to three years from the time of payment, against the production royalties owed to PVR once coal production commences.

In addition to the terms described above, substantiallySubstantially all of PVR’s leases impose obligations on the lessees to diligently mine the leased coal using modern mining techniques, indemnify PVR for any damages it incurs in connection with the lessee’s mining operations, including any damages itPVR may incur due to the lessee’s failure to fulfill reclamation or other environmental obligations, conduct mining operations in compliance with all

applicable laws, obtain ourits written consent prior to assigning the lease and maintain commercially reasonable amounts of general liability and other insurance. Substantially all of the leases grant PVR the right to review all lessee mining plans and maps, enter the leased premises to examine mine workings and conduct audits of lessees’ compliance with lease terms. In the event of a default by a lessee, substantially all of the leases give PVR the right to terminate the lease and take possession of the leased premises.

In addition, PVR earns revenues under coal services contracts, timber contracts and oil and gas leases. PVR’s coal services contracts generally provide that the users of PVR’s coal services pay PVR a fixed fee per ton of coal processed at its facilities. All of PVR’s coal services contracts are with lessees of PVR’s coal reserves and these contracts generally have terms that run concurrently with the related coal lease. PVR’s timber contracts generally provide that the timber companies pay us a fixed price per thousand board feet of timber harvested from our property. PVR receives royalties under its oil and gas leases based on a percentage of the revenues the producers receive for the oil and gas they sell.

PVR Natural Gas Midstream Segment

PVR’s natural gas midstream segment is engaged in providing gas processing, gathering and other related natural gas services. PVR’s midstream business generates revenues primarily from gas purchase and processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. During the year ended December 31, 2006,2007, PVR’s natural gas midstream business generated a majority of its gross margin from two types of contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and natural gas liquids (or NGLs):NGLs: (i) percentage-of-proceeds and (ii) keep-whole arrangements. In 2006,As of December 31, 2007, approximately 50%37% of PVR’s natural gassystem throughput volumes were processed under gas purchase/keep-whole contracts, 25%34% were processed under percentage of proceedspercentage-of-proceeds contracts, and 25%29% were processed under fee-based gathering contracts. A majority of the gas purchase/keep-whole and percentage of proceedspercentage-of-proceeds contracts include fee-based components such as gathering and compression charges. There is also a processing fee floor included in many of the gas purchase/keep-whole contracts that ensures a minimum processing margin should the actual margins fall below the floor.

Gas purchase/keep-whole arrangementsPurchase/Keep-Whole Arrangements. Under these arrangements, PVR generally purchases natural gas at the wellhead at either (i) a percentage discount to a specified index price, (ii) a specified index price less a fixed amount or (iii) a combination of (i) and (ii). PVR then gathers the natural gas to one of its plants where it is processed to extract the entrained NGLs, which are then sold to third parties at market prices. PVR resells the remaining natural gas to third parties at an index price which typically corresponds to the specified purchase index. Because the extraction of the NGLs from the natural gas during processing reduces the British thermal unit (or BTU)BTU content of the natural gas, PVR retains a reduced volume of gas to sell after processing. Accordingly, under these arrangements, PVR’s revenues and gross margins increase as the price of NGLs increases relative to the price of natural gas, and its revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. PVR has generally been able to mitigate its exposure in the latter case by requiring the payment under many of its gas purchase/keep-whole arrangements of minimum processing charges which ensuresensure that PVR receives a minimum amount of processing revenue.revenues. The gross margins that PVR realizes under the arrangements described in clauses (i) and (iii) above also decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price.

Percentage-of-proceeds arrangements.Percentage-of-Proceeds Arrangements. Under percentage-of-proceeds arrangements, PVR generally gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed uponagreed-upon percentage of the proceeds of those sales based on either an index price or the price actually received for the gas and NGLs. Under these types of arrangements, PVR’s revenues and gross margins increase as natural gas prices and NGL prices increase, and its revenues and gross margins decrease as natural gas prices and NGL prices decrease.

Fee-based arrangements.Fee-Based Arrangements. Under fee-based arrangements, PVR receives fees for gathering, compressing and/or processing natural gas. The revenuerevenues PVR earns from these arrangements isare directly dependent on the volume of natural gas that flows through its systems and isare independent of commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, PVR’s revenues from these arrangements would be reduced due to the related reduction in drilling and development of new supply.

In many cases, PVR provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of itsPVR’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts were signed and customer requirements. The contract mix and, accordingly,

exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.

PVR is also engaged in natural gas marketing by aggregating third-party volumes and selling those volumes into interstate and intrastate pipeline systems such as Enogex and ONEOK and at market hubs accessed by various interstate pipelines. Connect Energy Services, LLC, a wholly-owned subsidiary of PVR, earned fees for marketing a portion of Penn Virginia Oil & Gas, L.P.’s natural gas production during 2007 and 2006. Penn Virginia Oil & Gas, L.P. is a wholly-owned subsidiary of us. The largest third-party customer is Chesapeake Energy Corp. with volumes contracted through 2007. Revenuemarketing agreement was effective September 1, 2006. Revenues from this business doesdo not generate qualifying income for a masterpublicly traded limited partnership, but PVR does not expect it to have an impact on its tax status, as it does not represent a significant percentage of itsPVR’s operating income. For the yearyears ended December 31, 2007 and 2006, this businessnatural gas marketing activities generated $4.6 million and $2.2 million in net revenue.revenues.

Commodity Derivative Contracts

Our oil and gas segment and the PVR natural gas midstream segmentssegment utilize costless collars,collar, three-way collarsoption and swap derivative contracts to hedge against the variability in cash flows associated with forecasted oil and gas revenues and natural gas midstream revenues and cost of midstream gas purchased. The PVR natural gas midstream segment also utilizes swap derivative contracts to hedge against the variability in its “frac spread.” PVR’s frac spread is the spread between the purchase price for the natural gas PVR purchases from producers and the sale price for the NGLs that PVR sells after processing. PVR hedges against the variability in its frac spread by entering into swap derivative contracts to sell NGLs forward at a predetermined swap price and to purchase an equivalent volume of natural gas forward on an MMbtu basis. While the use of derivative instruments limits the risk of adverse price movements, their use also may limit future revenues or cost savings from favorable price movements.

With respect to a costless collar contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract.

A three-way collaroption contract consists of a collar contract as described above plus a put option contract sold by us with a price below the floor price of the collar. This additional put requires us to make a payment to the counterparty if the settlement price for any settlement period is below the put option price. By combining the collar contract with the additional put option, we are entitled to a net payment equal to the difference between the floor price of the collar contract and the additional put option price if the settlement price is equal to or less than the additional put option price. If the settlement price is greater than the additional put option price, the result is the same as it would have been with a collar contract only. This strategy enables us to increase the floor and the ceiling priceprices of the collar beyond the range of a traditional collar contract while defraying the associated cost with the sale of the additional put option.

With respect to a swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price for such contract, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price for such contract.

See Note 1011 in the Notes to Consolidated Financial Statements for a further description of our derivative program.and PVR’s derivatives programs.

Corporate Structure

As of December 31, 2007, we owned the general partner of PVG and an approximately 82% limited partner interest in PVG. PVG owns the general partner of PVR, which holds a 2% general partner interest in PVR and all the incentive distribution rights, and an approximately 42% limited partner interest in PVR. We directly owned an additional 0.5% limited partner interest in PVR as of December 31, 2007. The following diagram depicts our ownership of PVG and PVR as of December 31, 2007:

Because we control the general partner of PVG, the financial results of PVG are included in our consolidated financial statements. Because PVG controls the general partner of PVR, the financial results of PVG include those of PVR.PVR are included in PVG’s consolidated financial statements. However, PVG and PVR function with a capital structurestructures that isare independent of each other and us, with each having publicly traded common units and PVR having its own debt instruments. PVG does not currently have any debt instruments. The following diagram depicts our ownershipWhile we report consolidated financial results of PVR’s coal and natural resources management and natural gas midstream businesses, the only cash we receive from those businesses is in the form of cash distributions we receive from PVG and PVR asin respect of December 31, 2006 (after giving effect to the exerciseour partner interests in each of the underwriters’ option to purchase additional PVG common units granted in connection with PVG’s initial public offering, or the PVG IPO):

them.

Partnership Distributions

PVG Cash Distributions

PVG paid a cash distributiondistributions of $0.07$0.91 per common unit on February 14, 2007, which representedduring the year ended December 31, 2007. In the first quarter of 2008, PVG paid a $0.96 per unitquarterly distribution of $0.32 ($1.28 on an annualized basis that was prorated forbasis) per common unit with respect to the period beginning on December 5, 2006, the initial trading datefourth quarter of PVG’s common units on the New York Stock Exchange, and ending on December 31, 2006. We received total distributions from PVG of $2.2 million in February 2007. For the remainder of 2007,2008, PVG expects to makepay quarterly distributions of $0.24at least $0.32 ($0.961.28 on an annualized basis) or more per common unit.

PVR Cash Distributions

PVR paid cash distributions of $1.475$1.66 per common and subordinatedClass B unit during the year ended December 31, 2006.2007. In the first quarter of 2007,2008, PVR paid a quarterly distribution of $0.40$0.44 ($1.601.76 on an annualized basis) per common unit with respect to the fourth quarter of 2006.2007. For the remainder of 2007,2008, PVR expects to pay quarterly distributions of $0.40at least $0.44 ($1.601.76 on an annualized basis) or more per common and Class B unit.

Prior to the PVG IPO in December 2006, we indirectly owned common units representing an approximately 37% limited partner interest in PVR, as well as the sole 2% general partner interest and all of the incentive distribution rights in PVR. We received total distributions from PVR of $28.3 million and $21.2 million in 2006 and 2005, as shown in the following table (in thousands):

gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. The effect of these regulations is to limit the amounts of crude oil and natural gas we can produce from our wells and to limit the number of wells or the locations at which we can drill.

Federal Energy Regulatory Commission. The Federal Energy Regulatory Commission, (oror the FERC)FERC, regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938, (oror the NGA)NGA, and the Natural Gas Policy Act of 1978, (oror the NGPA).NGPA. In the past, the federal government has regulated the prices at which oil and gas could be sold. The Natural Gas Wellhead Decontrol Act of 1989 removed all NGA and NGPA price and nonprice controls affecting producers’ wellhead sales of natural gas effective January 1, 1993. While sales by producers of their own natural gas production and all sales of crude oil, condensate and natural gas liquids can currently be made at market prices, Congress could reenact price controls in the future.

Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and 636-C, (oror Order No. 636),636, which require interstate pipelines to provide transportation separate, or “unbundled,” from the pipelines’ sale of gas. Also, Order No. 636 requires pipelines to provide open-access transportation on a basis that is equal for all gas supplies. Although Order No. 636 does not directly regulate gas producers like us, the FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its open access regulations. In particular, the FERC has issued Order Nos. 637, 637-A and 637-B which, among other things, (i) permit pipelines to charge different maximum cost-based rates for peak and off-peak periods, (ii) encourage auctions for pipeline capacity, (iii) require pipelines to implement imbalance management services and (iv) restrict the ability of pipelines to impose penalties for imbalances, overruns and non-compliance with operational flow orders.

The Energy Policy Act of 2005 amended the NGA and the NGPA and gave the FERC the authority to assess civil penalties of up to $1 million per day per violation for violations of rules, regulations, and orders issued under these acts. In addition, the FERC has issued regulations that make it unlawful for any entity in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of the FERC to use any manipulative or deceptive device or contrivance.

While any additional FERC action on these matters would affect us only indirectly, these changes are intended to further enhance competition in, and prevent manipulation of, natural gas markets. We cannot predict what further action the FERC will take on these matters, nor can we predict whether the FERC’s actions will achieve its stated goal of increasing competition in, and preventing manipulation of, natural gas markets. However, we do not believe that we will be treated materially differently than other natural gas producers with which we compete.

Environmental Matters.Matters. Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup

costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and

regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material adverse impact on us. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws have the potential to adversely affect our operations.

OSHA.OSHA. We are subject to the requirements of the Occupational Safety and Health Act, (or OSHA)or OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizenscitizens.

PVR Coal and Natural Resource Management Segment

General Regulation Applicable to Coal Lessees.Lessees. PVR’s lessees are obligated to conduct mining operations in compliance with all applicable federal, state and local laws and regulations. These laws and regulations include matters involving the discharge of materials into the environment, employee health and safety, mine permits and other licensing requirements, reclamation and restoration of mining properties after mining is completed, management of materials generated by mining operations, surface subsidence from underground mining, water pollution, legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, plant and wildlife protection, limitations on land use, storage of petroleum products and substances which are regarded as hazardous under applicable laws and management of electrical equipment containing polychlorinated biphenyls, (or PCBs). Because ofor PCBs. These extensive and comprehensive regulatory requirements are closely enforced, PVR’s lessees regularly have on-site inspections and violations during mining operations are not unusual in the industry, and, notwithstanding compliance efforts PVR does not believe violations by its lessees can be eliminated completely.PVR’s lessees. However, none of the violations to date, or the monetary penalties assessed, have been material to us, PVR or, to our knowledge, to PVR’s lessees. Although many new safety requirements have been instituted recently, PVR does not currently expect that future compliance will have a material adverse effect on PVR.

While it is not possible to quantify the costs of compliance by PVR’s lessees with all applicable federal, state and local laws and regulations, those costs have been and are expected to continue to be significant. The lessees post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. We do not accrue for such costs because PVR’s lessees are contractually liable for all costs relating to their mining operations, including the costs of reclamation and mine closure. However, PVR does require some smaller lessees to deposit into escrow certain funds for reclamation and mine closure costs or post performance bonds for these costs. Although we believe that the lessees typically accrue adequate amounts for these costs, their future operating results would be adversely affected if they later determined these accruals to be insufficient. Compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers.

In addition, the utility industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities which could affect demand for coal mined by PVR’s lessees. The possibility exists that new legislation or regulations may be adopted which have a significant impact on the mining operations of PVR’s lessees or their customers’ ability to use coal and may require PVR, its lessees or their customers to change operations significantly or incur substantial costs.

Air Emissions.Emissions. The federal Clean Air Act, or the CAA, and corresponding state and local laws and regulations affect all aspects of PVR’s business.business, both directly and indirectly. The Clean Air ActCAA directly impacts PVR’s lessees’ coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The Clean Air ActCAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants. There have been a series of recent federal rulemakings that are focused on emissions

from coal-fired electric generating facilities. Installation of additional emissions control technology and additional measures required under U.S. Environmental Protection Agency, (oror the EPA)EPA, laws and regulations will make it more costly to build and operate coal-fired power plants and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel alternative in the planning and building of power plants in the future. Any reduction in coal’s share of power generating capacity could negatively impact PVR’s lessees’ ability to sell coal, which could have a material effect on PVR’s coal royaltyroyalties revenues.

The EPA’s Acid Rain Program, provided in Title IV of the Clean Air Act,CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels.

The EPA has promulgated rules, referred to as the “NOx SIP Call,” that require coal-fired power plants and other large stationary sources in 21 eastern states and Washington D.C. to make substantial reductions in nitrogen oxide emissions in an effort to reduce the impacts of ozone transport between states. Additionally, in March 2005, the EPA issued the final Clean Air Interstate Rule, (or CAIR),or CAIR, which will permanently cap nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.CD.C. beginning in 2009 and 2010, respectively.2010. CAIR requires these states to achieve the required emission reductions by requiring power plants to either participate in an EPA-administered “cap-and-trade” program that caps emission in two phases, or by meeting an individual state emissions budget through measures established by the state. The stringency of the caps under CAIR may require many coal-fired sources to install additional pollution control equipment, such as wet scrubbers, to comply. This increased sulfur emission removal capability required by CAIR could result in decreased demand for lower sulfur coal, which may potentially drive down prices for lower sulfur coal.

In March 2005, the EPA finalized the Clean Air Mercury Rule, (or CAMR),or CAMR, which establisheswas to establish a two-part, nationwide cap on mercury emissions from coal-fired power plants beginning in 2010. While currentlyIt was the subject of extensive controversy and litigation and, in February 2008, the U.S. Circuit Court of Appeals for the District of Columbia vacated CAMR. EPA has not yet indicated if fully implemented, CAMR would permitit will appeal the decision or how it will proceed with the regulation of mercury emissions. Various states to implement their ownhave promulgated or are considering more stringent emission limits on mercury control regulations or participate in an interstate cap-and-trade program for mercury emission allowances.emissions from coal-fired electric generating units.

The EPA has adopted new, more stringent national air quality standards for ozone and fine particulate matter. As a result, some states will be required to amend their existing state implementation plans to attain and maintain compliance with the new air quality standards. For example, in December 2004, the EPA designated specific areas in the United States as in “non-attainment” with the new national ambient air quality standard for fine particulate matter. In November 2005,March 2007, the EPA published proposedfinal rules addressing how states would implement plans to bring applicableregions designated as non-attainment regionsfor fine particulate matter into compliance with the new air quality standard. Under the EPA’s proposed rulemaking,final rule, states would have until April 2008 to submit their implementation plans to the EPA for approval. Because coal mining operations and coal-fired electric generating facilities emit particulate matter, PVR’s lessees’ mining operations and their customers could be affected when the new standards are implemented by the applicable states.

In June 2005,Likewise, the EPA announced final amendments to itsEPA’s regional haze program originally developed in 1999 to improve visibility in national parks and wilderness areas. As part of the new rules,areas required affected states mustto develop implementation plans by December 2007 that, among other things, identify facilities that will have to reduce emissions and comply with stricter emission limitations. This program may restrict construction of new coal-fired power plants where emissions are projected to reduce visibility in protected areas. In addition, this program may require certain existing coal-fired power plants to install emissions control equipment to reduce haze-causing emissions such as sulfur dioxide, nitrogen oxide and particulate matter.

The U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the new source review provisions of the Clean Air Act.CAA. The

EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issuedrequired under the new source review program. Several of these lawsuits have settled, but others remain pending. On April 2, 2007, the United States Supreme Court ruled in one such case,Environmental Defense v. Duke Energy Corp. The Court held that EPA is not required to use an “hourly rate test” in determining whether a modification to a coal burning utility requires a permit under the new source review program, thus allowing the EPA to apply a test based on average annual emissions. The use of an annual emissions test could subject more coal-fired utility modification projects to the permitting requirements of the CAA New Source Review Program, such as those that allow plants to run for more hours in a given year. However, Duke is expected to continue to contest remaining issues in the case, and so litigation in this and other pending cases will likely continue. Depending on the ultimate resolution of these cases, demand for PVR’s coal could be affected, which could have an adverse effect on PVR’s coal royaltyroyalties revenues.

Carbon Dioxide Emissions.Emissions. The Kyoto Protocol to the United Nations Framework Convention on Climate Change calls for developed nations to reduce their emissions of greenhouse gases to 5% below 1990 levels by 2012. Carbon dioxide, which is a major byproduct of the combustion of coal and other fossil fuels, is subject to the Kyoto Protocol. The Kyoto Protocol went into effect on February 16, 2005 for those nations that ratified the treaty.

In 2002, the United States withdrew

its support for the Kyoto Protocol.Protocol, and the United States is not participating in this treaty. Since the Kyoto Protocol became effective, there has been increasing international pressure on the United States to adopt mandatory restrictions on carbon dioxide emissions. TheIn addition, on April 2, 2007 the United States Congress has considered billsSupreme Court held inMassachusetts v. EPA that unless the EPA affirmatively concludes that greenhouse gases are not causing climate change, the EPA must regulate greenhouse gas emissions from new automobiles under the CAA. The Supreme Court remanded the matter to the EPA for further consideration. This litigation did not directly concern the EPA’s authority to regulate greenhouse gas emissions from stationary sources, such as coal mining operations or coal-fired power plants. However, the Court’s decision is likely to influence another lawsuit currently pending in the past that wouldU.S. Court of Appeals for the District of Columbia Circuit, involving a challenge to the EPA’s decision not to regulate domestic carbon dioxide from power plants and other stationary sources under a CAA new source performance standard rule, which specifies emissions limits for new facilities. The court remanded that question to EPA for further consideration in light of the ruling inMassachusetts v. EPA, but such billsany decision in this case or any regulatory action by the EPA limiting greenhouse gas emissions from power plants could impact the demand for PVR’s coal, which could have not yet received sufficient Congressional supportan adverse effect on PVR’s coal royalties revenues.

The permitting of a number of proposed new coal-fired power plants has also recently been contested by environmental organizations for passage into law. concerns related to greenhouse gas emissions from new plants. In October 2007, state regulators in Kansas became the first to deny an air emissions construction permit for a new coal-fired power plant based on the plant’s projected emissions of carbon dioxide. State regulatory authorities in Florida and North Carolina have also rejected the construction of new coal-fired power plants based on the uncertainty surrounding the potential costs associated with greenhouse gas emissions from these plants under future laws limiting the emission of carbon dioxide. In addition, permits for several new coal-fired power plants without limits imposed on their greenhouse gas emissions have been appealed by environmental organizations to the U.S. EPA’s Environmental Appeals Board.

Several states have also either passed legislation or announced initiatives focused on decreasing or stabilizing carbon dioxide emissions associated with the combustion of fossil fuels, and many of these measures have focused on emissions from coal-fired electric generating facilities. For example, in December 2005, seven northeastern states agreed to implement a regional cap-and-trade program, referred to as the Regional Greenhouse Gas Initiative, or the RGGI, to stabilize carbon dioxide emissions from regional power plants beginning in 2009. This initiative aims to reduce emissions of carbon dioxide to levels roughly corresponding to average annual emissions between 2000 and 2004. Recently, in February 2007, Massachusetts and Rhode Island agreed to join this group.group in February 2007 and Maryland is requiredagreed to join the group in April 2007. The members of RGGI agreed to seek to establish in statute and/or regulation a carbon dioxide trading program and have each state’s component of the regional program effective no later than December 31, 2008. Following the RGGI model, seven Western states have also formed a regional greenhouse gas reduction initiative known as the Western Regional Climate Action Initiative, which calls for an overall reduction of regional greenhouse gas emissions from major industrial and commercial sources in participating states through trading of emissions credits beginning in 2012. Also, in 2006, the governor of California signed Assembly Bill 32 into law, requiring the California Air Resources Board to develop regulations and market mechanisms to reduce California’s greenhouse gas emissions by June25% by 2020 with mandatory caps beginning in 2012 for significant sources.

Several different pieces of legislation were introduced in Congress in 2007 but implementing regulations have not been finalized as of yet.

to reduce greenhouse gas emissions in the United States. Such or similar federal legislation could be taken in 2008 or later years. It is possible that future federal and state initiatives to control and put a price on carbon dioxide emissions could result in increased costs associated with coal consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for coal consumption could result in some customers switching to alternative sources of fuel, which could negatively impact PVR’s lessees’ coal sales, and thereby have an adverse affecteffect on PVR’s coal royaltyroyalties revenues.

Surface Mining Control and Reclamation Act of 1977.1977. The Surface Mining Control and Reclamation Act of 1977, (or SMCRA)or SMCRA, and similar state statutes imposeestablish minimum national operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of mining activities. SMCRA also imposes on mine operators the responsibility of restoring the land to its original state and compensating the landowner for types of damages occurring as a result of mining operations, and require mine operators to post performance bonds to ensure compliance with any reclamation obligations.obligations on the theory that PVR “owned” or “controlled” the mine operator in such a way for liability to attach. Regulatory authorities may attempt to assign the liabilities of PVR’s coal lessees to itanother entity such as PVR if any of thoseits lessees are not financially capable of fulfilling those obligations. To our knowledge, no such claims have been asserted against PVR to date. In conjunction with mining the property, PVR’s coal lessees are contractually obligated under the terms of their leases to comply with all state and local laws, including SMCRA, with obligations including the reclamation and restoration of the mined areas by grading, shaping and reseeding the soil. Upon completion of the mining, reclamation generally is completed by seeding with grasses or planting trees for use as pasture or timberland, as

specified in the approved reclamation plan. Additionally, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is 31.5 cents per ton on surface-mined coal and 13.5 cents per ton on underground-mined coal. This tax was set to expire on June 30, 2006, but the program was extended until September 30, 2021.

Federal and state laws require bonds to secure our lessees’ obligations to reclaim lands used for mining and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for mining companies to secure new surety bonds without the posting of partial collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable. It is possible that surety bonds issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Any failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on PVR’s lessees’ ability to produce coal, which could affect PVR’s coal royalties revenues.

Hazardous Materials and Wastes.Wastes. The Federal Comprehensive Environmental Response, Compensation and Liability Act, (oror CERCLA, or the Superfund law),law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources.

Some products used by coal companies in operations generate waste containing hazardous substances. PVR could become liable under federal and state Superfund and waste management statutes if PVR’sits lessees are

unable to pay environmental cleanup costs. CERCLA authorizes the EPA and, in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek recovery from the responsible classes of persons of the costs they incurred in connection with such response. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other wastes released into the environment. The Resource Conservation and Recovery Act, or RCRA, and corresponding state laws and regulations exclude many mining wastes from the regulatory definition of hazardous wastes. Currently, the management and disposal of coal combustion by-products are also not regulated at the federal level and not uniformly at the state level. If rules are adopted to regulate the management and disposal of these by-products, they could add additional costs to the use of coal as a fuel and may encourage power plant operators to switch to a different fuel.

Clean Water Discharges.Act. PVR’s coal lessees’ operations can result inare regulated under the Clean Water Act, or the CWA, with respect to discharges of pollutants, into waters. The Clean Water Act and analogous state laws and regulations impose restrictions and strict controls regarding the discharge of pollutantsincluding dredged or fill material into waters of the United StatesStates. Individual or state waters. The unpermitted dischargegeneral permits under Section 404 of pollutants such as from spillthe CWA are required to conduct dredge or leak incidents is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of fill material and certain other activities in wetlands unless authorized by an appropriatelyjurisdictional waters of the United States. Surface coal mining operators obtain these permits to authorize such activities as the creation of slurry ponds, stream impoundments and valley fills. Uncertainty over what legally constitutes a navigable water of the United States within the CWA’s regulatory scope may adversely impact the ability of PVR’s coal lessees to secure the necessary permits for their mining activities. Some surface mining activities require a CWA Section 404 “dredge and fill” permit under the CWA for valley fills and the associated sediment control ponds. On June 5, 2007, in response to the U.S. Supreme Court’s divided opinion inRapanos v. United States, the EPA and the U.S. Army Corps of Engineers, or the Corps, issued permit.joint guidance to EPA regions and Corps districts interpreting the geographic extent of regulatory jurisdiction under Section 404 of the CWA. Specifically, the guidance places jurisdictional water bodies into two groups: waters where the agencies will assert regulatory jurisdiction “categorically” and waters where the agencies will assert jurisdiction on a case-by-case basis following a “significant nexus analysis.” It remains to be seen how this guidance will affect the permitting process for obtaining additional permits for valley fills and sediment ponds although it is likely to add uncertainty and delays in the issuance of new permits. Some valley fill surface mining activities have the potential to impact headwater streams that are not relatively permanent, which could therefore trigger a detailed “significant nexus analysis” to determine whether a Section 404 permit would be required. Such analyses could require the extensive collection of additional field data and could lead to delays in the issuance of CWA Section 404 permits for valley fill surface mining operations.

PVR’s lessees’ mining operations are strictly regulated by the Clean Water Act, particularly with respect to the discharge of overburden and fill material into jurisdictional waters, including wetlands. Recent federal district court decisions in West Virginia, and related litigation filed in federal district court in Kentucky, have created additional uncertainty regarding the future ability to obtain certain general permits authorizing the construction of valley fills for the disposal of overburden from mining operations. The Corps is authorized by Section 404 of the CWA to issue “nationwide” permits for specific categories of dredging and filling activities that are similar in nature and that are determined to have minimal adverse environmental effects. Nationwide Permit 21 authorizes the disposal of dredged or fill material from surface coal mining activities into the waters of the United States. A July 2004 decision by the Southern District of West Virginia inOhio Valley Environmental Coalition v. Bulen enjoined the Huntington District of the U.S. Army Corps of Engineers

from issuing further permits pursuant to Nationwide Permit 21, which is a general permit issued by the U.S. Army Corps of Engineers to streamline the process for obtaining permits under Section 404 of the Clean Water Act.21. While the decision was vacated by the Fourth Circuit Court of Appeals in November 2005, it has been remanded to the District Court for the Southern District of West Virginia for further proceedings. Moreover, a similar lawsuit has been filed in federal district court inthe U.S. District Court for the Eastern District of Kentucky that seeks to enjoin the issuance of permits pursuant to Nationwide Permit 21 by the Louisville District of the U.S. Army Corps of Engineers. Corps.

In the event similar lawsuits prove to be successful in adjoining jurisdictions, PVR’s lessees may be required to apply for individual discharge permits pursuant to Section 404 of the Clean Water ActCWA in areas where they would have otherwise utilized Nationwide Permit 21. Such a change could result in delays in PVR’s lessees obtaining the required mining permits to conduct their operations, which could in turn have an adverse effect on PVR’s coal royaltyroyalties revenues. Moreover, such individual

Individual CWA Section 404 permits for valley fills associated with surface mining activities are also subject to challenge.certain legal challenges and uncertainty. On September 22, 2005, in the caseOhio Valley Environmental Coalition (“OVEC”) v. United States Army Corps of Engineers, environmental group plaintiffs filed suit in the U.S. District Court for the Southern District of West Virginia challenging the Corps’ decision to issue individual CWA Section 404 permits for certain mining projects. Alex Energy, Inc., or Alex Energy, a lessee of PVR lessee operatingthat operates the Republic No. 2 Mine in Kanawha County, West Virginia, is currentlyintervened as a defendant inOhio Valley Environmental Coalition vs. U.S. Army Corps of Engineers, a lawsuit in this litigation when the Southern District of West Virginia in which environmental groups challengedplaintiffs’ amended their complaint to add the issuance ofDecember 22, 2005 individual valley fill permits to multiple coal operators in the state. On June 13, 2006, the Corps of Engineers suspended the valley fill permits at issue in the case, including theCWA Section 404 permit under which PVR’s lessee operates. The court has since stayed all proceedings pending further action by the Corps on these permits. Although portions offor the Republic No. 2 Mine, or the Republic No. 2 Permit. On March 23, 2007, the district court rescinded several challenged CWA Section 404 permits, including the Republic No. 2 Permit, and remanded the permit applications to the Corps for further proceedings. In addition, the district court enjoined the permit holders, including Alex Energy, from all activities authorized under the rescinded permits. As part of theOVEC litigation, the environmental groups have also challenged the CWA Section 404 permit issued to Alex Energy for the Republic No. 1 Mine, also located in Kanawha County, West Virginia.

On April 10, 2007, Alex Energy filed a notice of appeal of the March 23, 2007 ruling to the United States Court of Appeals. On May 18, 2007, the Corps and the West Virginia Mining Association also filed notices of appeal as defendants. On April 20, 2007, the district court granted a limited stay of its previous order to allow certain valley fills already partially constructed where the receiving waters had been filled. This limited stay specifically allows Alex Energy to continue to operate under separate authorizations, delaysuse Valley Fill No. 1 with respect to the Republic No. 2 Mine; however, construction of the other valley fills and sediment ponds remain enjoined pending appeal. In December 2007, plaintiff environmental groups brought a similar suit against the issuance of a CWA Section 404 permit for a surface coal mine in securing additional permit authorizationthe U.S. District Court for the areas affected byEastern District of Kentucky, alleging identical violations. The Corps has voluntarily suspended its consideration of the aforementioned permit withdrawalapplication in that case for agency re-evaluation. While the final outcome of these cases remains uncertain, if theOVEClawsuit ultimately limits or prohibits the mining methods or operations of PVR’s lessees, it could have an adverse effect on PVR’s coal royaltyroyalties revenues. In addition, it is possible that similar litigation affecting recently issued, pending or future individual or general CWA Section 404 permits relevant to the mining and related operations of PVR’s lessees could adversely impact PVR’s coal royalties revenues.

Total Maximum Daily Load, or TMDL, regulations under the CWA establish a process to calculate the maximum amount of a pollutant that a water body can receive and still meet state water quality standards and to allocate pollutant loads among the point- and non-point pollutant sources discharging into that water body. This process applies to those waters that states have designated as impaired (not meeting present water quality standards). Industrial dischargers, including coal mines, discharging to such waters will be required to meet new TMDL load allocations for these stream segments. The Clean Water Actadoption of new TMDL-related allocations for streams to which PVR’s lessees’ coal mining operations discharge could require more costly water treatment and could adversely affect PVR’s lessees’ coal production.

The CWA also requires states to develop anti-degradation policies to ensure non-impaired waterbodieswater bodies in the state do not fall below applicable water quality standards. These and other regulatory developments may restrict PVR’s lessees’ ability to develop new mines or could require itsPVR’s lessees to modify existing operations, which could have an adverse effect on PVR’s coal business.

The Federal Safe Drinking Water Act, (oror the SDWA)SDWA, and its state equivalents affect coal mining operations by imposing requirements on the underground injection of fine coal slurries, fly ash and flue gas scrubber sludge, and by requiring permits to conduct such underground injection activities. In addition to establishing the underground injection control program, the SDWA also imposes regulatory requirements on owners and operators of “public water systems.” This regulatory program could impact PVR’s lessees’ reclamation operations where subsidence or other mining-related problems require the provision of drinking water to affected adjacent homeowners.

Endangered Species Act. The Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying PVR’s

lessees from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. A number of species indigenous to areas where PVR’s properties are located are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect PVR’s lessees’ ability to mine coal from PVR’s properties in accordance with current mining plans.

Mine Health and Safety Laws.Laws. The operations of PVR’s coal lessees are subject to stringent health and safety standards that have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of

1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs and reduced productivity. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposes comprehensive health and safety standards on all mining operations. In addition, as part of the Mine Health and Safety Acts of 1969 and 1977, the Black Lung Acts require payments of benefits by all businesses conducting current mining operations to coal miners with black lung or pneumoconiosis and to some beneficiaries of miners who have died from this disease.

Recent mining accidents in West Virginia and Kentucky have received national attention and instigated responses at the state and national level that are likely to result in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. In January 2006, West Virginia passed a law imposing stringent new mine safety and accident reporting requirements and increased civil and criminal penalties for violations of mine safety laws. On March 7, 2006, New Mexico Governor Bill Richardson signed into law an expanded miner safety program including more stringent requirements for accident reporting and the installation of additional mine safety equipment at underground mines. Similarly, on April 27, 2006, Kentucky Governor Ernie Fletcher signed mine safety legislation that includes requirements for increased inspections of underground mines and additional mine safety equipment and authorizes the assessment of penalties of up to $5,000 per incident for violations of mine ventilation or roof control requirements.

On June 15, 2006, the President signed the “Miner Act,” which was new mining safety legislation that mandates similar improvements in mine safety practices, increases civil and criminal penalties for non-compliance, requires the creation of additional mine rescue teams and expands the scope of federal oversight, inspection and enforcement activities. Earlier,Pursuant to the federalMiner Act, the Mine Safety Health Administration, announced the promulgation ofor MSHA, has promulgated new emergency rules on mine safety that took effect immediately upon their publicationand revised MSHA’s civil penalty assessment regulations, which resulted in an across-the-board increase in penalties from theFederal Register on March 9, 2006. existing regulations. These rules address mine safety equipment, training,requirements may add significant costs to PVR’s lessees’ operations, particularly for underground mines, and emergency reporting requirements. could affect the financial performance of PVR’s lessees’ operations.

Implementing and complying with these new laws and regulations could adversely affect PVR’s lessees’ coal production and could therefore have an adverse affecteffect on PVR’s coal royaltyroyalties revenues.

Mining Permits and Approvals.Approvals. Numerous governmental permits or approvals are required for mining operations. In connection with obtaining these permits and approvals, PVR’s coal lessees may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations.

Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations which have outstanding environmental violations. Although, like other coal companies, PVR’s lessees’ have been cited for violations in the ordinary course of business, to our knowledge, none of them have had one of their permits suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including PVR’s lessees, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically, PVR’s lessees submit the necessary permit applications between 12 and 24 months before they plan to begin mining a new area. In PVR’s experience, permits generally are approved within 12 months after a completed application is submitted. In the past, PVR’s lessees have generally obtained their mining permits without significant delay. PVR’s lessees have obtained or applied for permits to mine a majority of the reserves that are currently planned to be mined over the next five years. PVR’s lessees are also in the planning phase for obtaining permits for the additional reserves planned to be mined over the following five years. However, there are no

assurances that they will not experience difficulty in obtaining mining permits in the future. See “—PVR Coal and Natural Resource Management Segment—Clean Water Discharges.Act.”

OSHA.OSHA. PVR’s lessees and itsPVR’s own business are subject to OSHA. See “—Oil and Gas Segment—OSHA.”

PVR Natural Gas Midstream Segment

General Regulation.Regulation. PVR’s natural gas gathering facilities generally are exempt from the FERC’s jurisdiction under the NGA, but FERC regulation nevertheless could significantly affect PVR’s gathering business and the market for its services. In recent years, the FERC has pursued pro-competitive policies in its

regulation of interstate natural gas pipelines into which PVR’s gathering pipelines deliver. However, we cannot assure you that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.capacity.

For example, the FERC will assert jurisdiction over an affiliated gatherer that acts to benefit its pipeline affiliate in a manner that is contrary to the FERC’s policies concerning jurisdictional services adopted pursuant to the NGA. In addition, natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that the FERC has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. PVR’s gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. PVR’s gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on PVR’s natural gas midstream operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

In Texas, PVR’s gathering facilities are subject to regulation by the Texas Railroad Commission, which has the authority to ensure that rates, terms and conditions of gas utilities, including certain gathering facilities, are just and reasonable and not discriminatory. PVR’s operations in Oklahoma are regulated by the Oklahoma Corporation Commission, which prohibits PVR from charging any unduly discriminatory fees for its gathering services. PVRWe cannot predict whether itsPVR’s gathering rates will be found to be unjust, unreasonable or unduly discriminatory.

PVR is subject to ratable take and common purchaser statutes in Texas and Oklahoma. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting PVR’s right as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and Texas and Oklahoma have adopted complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering rates and access. We cannot assure you that federal and state authorities will retain their current regulatory policies in the future.

Texas and Oklahoma administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, as amended (oror the NGPSA),NGPSA, which requires certain pipelines to comply with safety standards in constructing and operating the pipelines, and subjects pipelines to regular inspections. In response to recent pipeline accidents, Congress and the U.S. Department of Transportation have recently instituted heightened pipeline safety requirements. Certain of PVR’s gathering facilities are exempt from these federal pipeline safety requirements under the rural gathering exemption. We cannot assure you that the rural gathering exemption will be retained in its current form in the future.

Failure to comply with applicable regulations under the NGA, the NGPSA and certain state laws can result in the imposition of administrative, civil and criminal remedies.

Air Emissions.Emissions. PVR’s natural gas midstream operations are subject to the Clean Air ActCAA and comparable state laws and regulations. See “—PVR Coal and Natural Resource Management Segment—Air Emissions.” These laws and regulations govern emissions of pollutants into the air resulting from the activities of PVR’s processing plants and compressor stations and also impose procedural requirements on how PVR conducts its natural gas midstream operations. Such laws and regulations may include requirements that PVR obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, strictly comply with the emissions and operational limitations of air emissions permits PVR is required to obtain or utilize specific equipment or technologies to control emissions.

PVR’s failure to comply with these requirements could subject PVRit to monetary penalties, injunctions, conditions or restrictions on operations, and

potentially criminal enforcement actions. PVR will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

Hazardous Materials and Wastes.Wastes. PVR’s natural gas midstream operations could incur liability under CERCLA and comparable state laws resulting from the disposal or other release of hazardous substances or wastes originating from properties PVR owns or operates, regardless of whether such disposal or release occurred during or prior to PVR’s acquisition of such properties. See “—PVR Coal and Natural Resource Management Segment—Hazardous Materials and Waste.” Although petroleum, including natural gas and NGLs are generally excluded from CERCLA’s definition of “hazardous substance,” PVR’s natural gas midstream operations do generate wastes in the course of ordinary operations that may fall within the definition of a “hazardous substance.”

PVR’s natural gas midstream operations generate wastes, including some hazardous wastes, thatwhich are subject to the Resource Conservation and Recovery Act (or RCRA)RCRA and comparable state laws. However, RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy. Unrecovered petroleum product wastes, however, may still be regulated under RCRA as solid waste. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas and NGLs in pipelines may also generate some hazardous wastes. Although PVR believes that it is unlikely that the RCRA exemption will be repealed in the near future, repeal would increase costs for waste disposal and environmental remediation at PVR’s facilities.

PVR currently owns or leases numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas and NGLs. Although we believePVR believes that the operators of such properties used operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under such properties or on or under other locations where such wastes have been taken for disposal. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, PVR could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination, whether from prior owners or operators or other historic activities or spills) or to perform remedial plugging or pit closure operations to prevent future contamination. PVR has ongoing remediation projects underway at several sites, but it does not believe that the costs associated with such cleanups will have a material adverse impact on PVR’s operations or revenues.

Water Discharges.Discharges. PVR’s natural gas midstream operations are subject to the Clean Water Act.CWA. See “—PVR Coal and Natural Resource Management Segment—Clean Water Discharges.Act.” Any unpermitted release of pollutants, including NGLs or condensates, from PVR’s systems or facilities could result in fines or penalties as well as significant remedial obligations.

OSHA.OSHAPVR midstream’s. PVR’s natural gas midstream operations are subject to OSHA. See “—Oil and Gas Segment—OSHA.”

Employees and Labor Relations

We and our subsidiaries had a total of 282314 employees at December 31, 2006,2007, including 122129 employees who directly provide services for PVR. We consider our current employee relations to be favorable.

Available Information

Our internet address is www.pennvirginia.com.http://www.pennvirginia.com. We make available free of charge on or through our internet website our Corporate Governance Principles, Code of Business Conduct and Ethics, Executive and Financial Officer Code of Ethics, Audit Committee Charter, Compensation and Benefits Committee Charter and Nominating and Governance Committee Charter and

Compensation and Benefits Committee Charter and we will provide copies of such documents to any shareholder who so requests. We also make available free of charge on or through our website our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, (oror the Exchange Act)Act, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission, (oror the SEC).SEC.

Executive Officers of the Company

The following table sets forth information concerning our executive officers. Each officer is elected annually by the Boardour board of Directorsdirectors and serves at the pleasure of the Boardour board of Directors.directors.

A. James Dearlove has served as our President and Chief Executive Officer since May 1996 and as a director since February 1996, as our President and Chief Operating Officer from 1994 to May 1996, as our Senior Vice President from 1992 to 1994 and as our Vice President from 1986 to 1992. Mr. Dearlove has also served as Chief Executive Officer and Chairman of the Board of PVG GP, LLC, the general partner of Penn Virginia GP Holdings, L.P., since September 2006 and as Chief Executive Officer and Chairman of the Board of Penn Virginia Resource GP, LLC, the general partner of Penn Virginia Resource Partners, L.P., since July 2001 and December 2002. Mr. Dearlove also serves as a director of the National Council of Coal Lessors.

Keith D. Horton has served as our Executive Vice President and as a director since December 2000, as Vice President—Eastern Operations from February 1999 to December 2000, as Vice President from February 1996 to February 1999, as President of Penn Virginia Coal Company from February 1996 to October 2001, as Vice President of Penn Virginia Coal Company from March 1994 to February 1996, as Vice President of Penn Virginia Resources Corporation from January 1990 to December 1998 and as Manager, Coal Operations of Penn Virginia Resources Corporation from July 1982 to December 1989. Mr. Horton has also served as Co-President and Chief Operating Officer—Coal of Penn Virginia Resource GP, LLC since May 2006 and as President and Chief Operating Officer of Penn Virginia Resource GP, LLC from July 2001 to May 2006. Mr. Horton has also served as President of Penn Virginia Operating Co., LLC since September 2001. Mr. Horton serves as a director of the Virginia Mining Association, the Powell River Project and the Eastern Coal Council.

Ronald K. Pagehas served as our Vice President since May 2005 and as our Vice President, Corporate Development from July 2003 to May 2005. Mr. Page has also served as Co-President and Chief Operating Officer—Midstream of Penn Virginia Resource GP, LLC since May 2006 and as Vice President, Corporate Development of Penn Virginia Resource GP, LLC from July 2003 to May 2006. Mr. Page has also served as President of PVR Midstream LLC since January 2005. From January 1998 to May 2003, Mr. Page served in various positions with El Paso Field Services Company, including Vice President of Commercial Operations—Texas Pipelines and Processing from 2001 to 2003, Vice President of Business Development from 2000 to 2001 and Director of Business Development from 1999 to 2000.

Frank A. Picihas served as our Executive Vice President and Chief Financial Officer since September 2001. Mr. Pici has also served as Vice President and Chief Financial Officer and as a director of PVG GP, LLC since September 2006 and as Vice President and Chief Financial Officer and as a director of Penn Virginia Resource GP, LLC since September 2001 and October 2002. From 1996 to 2001, Mr. Pici served as Vice President—Finance and Chief Financial Officer of Mariner Energy, Inc., or Mariner, a Houston, Texas-based oil

and gas exploration and production company, where he managed all financial aspects of Mariner, including accounting, tax, finance, banking, investor relations, planning and budgeting and information technology. From 1994 to 1996, Mr. Pici served as Corporate Controller of Cabot Oil & Gas Corporation, or Cabot, an oil and gas exploration and production company, from 1984 to 1989.company.

Nancy M. Snyderhas served as our Executive Vice President since May 2006, as our Senior Vice President from February 2003 to May 2006, as our Vice President from December 2000 to February 2003 and as our General Counsel and Corporate Secretary since 1997. Ms. Snyder has also served as Vice President and General Counsel and as a director of PVG GP, LLC since September 2006 and as Vice President and General Counsel and as a director of Penn Virginia Resource GP, LLC since July 2001. From 1993 to 1997, Ms. Snyder was a solo practitioner representing clients generally in connection with mergers and acquisitions and general corporate matters.

H. Baird Whiteheadhas served as our Executive Vice President since January 2001 and as President of Penn Virginia Oil & Gas Corporation since January 2001. Prior to joining the Company, Mr. Whitehead served in various positions with Cabot. From 1998 to 2001, Mr. Whitehead served as Senior Vice President during which time he oversaw Cabot’s drilling, production and exploration activity in the Appalachian, Rocky Mountain, Mid-Continent and Gulf Coast areas. From 1992 to 1998, Mr. Whitehead served as Vice President and Regional Manager of Cabot’s Appalachian business. From 1989 to 1992, Mr. Whitehead served as Vice President and Regional Manager of Cabot’s Anadarko business unit.

Common Abbreviations and Definitions

The following terms haveare abbreviations and definitions commonly used in the meanings indicated below whencoal and oil and gas industries that are used in this Annual Report on Form 10-K.

MMbtu— MMbtu		one million British thermal units
MMcf— MMcf		one million cubic feet
MMcfe— MMcfd		one million cubic feet per day
MMcfe		one million cubic feet equivalent with one barrel of oil or condensate converted to six thousand cubic feet of natural gas based on the estimated relative energy content
Net acre or well— well		gross acres or wells multiplied by the owned working interest in those gross acres or wells

NGL— NGL		natural gas liquid
NYMEX— NYMEX		New York Mercantile Exchange
Present value of proved reserves— reserves		the present value (discounted at 10%) of estimated future cash flows from proved oil and natural gas reserves, as estimated by our independent engineers, reduced by additional estimated future operating expenses, development expenditures and abandonment costs (net of salvage value) associated therewith (before income taxes)
Probable coal reserves— reserves		those reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation
Productive wells— wells		wells that are producing oil or gas or that are capable of production
Proved developed reserves— reserves		reserves that can be expected to be recovered through existing wells with existing equipment and operating methods
Proved reserves— reserves		those estimated quantities of crude oil, condensate and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years
Proved undeveloped reserves— reserves		reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion
Proven coal reserves— reserves		those reserves for which: (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling; and (b) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well defined, that the size, shape, depth and mineral content of reserves are well-established
Standardized measure— measure		present value of proved reserves further reduced by the present value (discounted at 10%) of estimated future income taxes on cash flows using prices in effect at a fiscal year end and estimated future costs as of that fiscal year end. Prices are held constant throughout the life of the properties except where SEC guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations.
Undeveloped acreage— acreage		lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas, regardless of whether such acreage contains estimated net proved reserves
Working interest— interest		a cost-bearing interest under an oil and gas lease that gives the holder the right to develop and produce the minerals under the lease

Item 1A

Risk Factors

Our business and operations are subject to a number of risks and uncertainties as described below. However, the risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we may currently deem immaterial, may become important factors that harm our business, financial condition or results of operations. If any of the following risks actually occur, our business, financial condition or results of operations could suffer.

Risks Related to ourOur Oil and Gas Business

Natural gas and crude oil prices are volatile, and a substantial or extended decline in prices would hurt our profitability and financial condition.

Our revenues, operating results, cash flow, profitability, future rate of growth and the carrying value of our oil and gas properties depend heavily on prevailing market prices for natural gas and crude oil. Historically, natural gas and crude oil prices have been volatile, and they are likely to continue to be volatile. Wide fluctuations in natural gas and crude oil prices may result from relatively minor changes in the supply of and demand for oil and gas, market uncertainty and other factors that are beyond our control, including:

Some of our projections and estimates are based on assumptions as to the future prices of natural gas and crude oil. These price assumptions are used for planning purposes. We expect our assumptions will change over time and that actual prices in the future will likely differ from our estimates. Any substantial or extended decline in the actual prices of natural gas or crude oil would have a material adverse effect on our financial position and results of operations (including reduced cash flow and borrowing capacity)capacity and possible asset impairment), the quantities of natural gas and crude oil reserves that we can economically produce, the quantity of estimated proved reserves that may be attributed to our properties and our ability to fund our capital program.

Our future performance depends on our ability to find or acquire additional oil and gas reserves that are economically recoverable.

Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in oil and gas production and lower revenues and cash flows from operations. We have historically succeeded in substantially replacing reserves through acquisitions, exploration and development. We have conducted such activities on our existing oil and gas properties as well as on newly acquired properties. We may not be able to continue to replace reserves from such activities at acceptable costs. Lower oil and gas prices may further limit the types of reserves that can be developed at acceptable costs. Lower prices also decrease our cash flows and may cause us to reduce capital expenditures. The business of exploring for, developing or acquiring reserves is capital intensive. We may not be able to make the necessary capital investments to maintain or expand our oil and gas reserves if cash flows from operations are reduced and external sources of capital become limited or unavailable. In addition, exploration and development activities involve numerous risks that may result in dry holes, the failure to produce oil and gas in commercial quantities and the inability to fully produce discovered reserves.

We are continually identifying and evaluating acquisition opportunities, including acquisitions that would be significantly larger than those we have consummated to date. However, competition for producing oil and gas

properties is intense and many of our competitors have financial and other resources substantially greater than those available to us. We cannot ensure that we will successfully consummate any acquisition, that we will be able to acquire producing oil and gas properties that contain economically recoverable reserves or that any acquisition will be profitably integrated into our operations.

We may not be able to fund our planned capital expenditures.

We make, and will continue to make, substantial capital expenditures to find, acquire, develop, exploit and produce oil and natural gas reserves. Our capital expenditures for oil and gas properties were $338.5$520.4 million for 2006,2007, and we have budgeted total capital expenditures of $310 million to $345approximately $475 million in 2007.2008. If oil and gas prices decrease or we encounter operating difficulties that result in our cash flow from operations being less than expected, we may have to reduce the capital

we can spend unless we raise additional funds through debt or equity financing. Debt or equity financing, cash generated by operations or borrowing capacity may not be available to us in sufficient amounts or on acceptable terms to meet these requirements.

Future cash flows and the availability of financing will be subject to a number of variables, such as:

Issuing equity securities to satisfy our financing requirements could cause substantial dilution to existing shareholders. Debt financing could lead to us being more vulnerable to competitive pressures and economic downturns.

If our revenues were to decrease due to lower oil and natural gas prices, decreased production or other reasons, and if we could not obtain capital through our revolving credit facility or otherwise, our ability to execute our development plans, replace our reserves or maintain production levels could be greatly limited.

Exploration and development drilling may not result in commercially productive reserves.

Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive natural gas or oil reserves will be found. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

The prevailing prices of oil and gas also affect the cost of and the demand for drilling rigs, production equipment and related services. The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region.

Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays which jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to explore on or develop our properties.

The wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that natural gas or oil is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Drilling activities can result in dry wells or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover initial drilling costs.

Our future drilling activities may not be successful, nor can we be sure that our overall drilling success rate or our drilling success rate for activity within a particular area will not decline. Unsuccessful drilling activities could have a material adverse effect on our results of operations and financial condition. Also, we may not be able to obtain any options

or lease rights in potential drilling locations that we identify. Although we have identified numerous potential drilling locations, we may not be able to economically produce oil or natural gas from all of them.

We are exposed to the credit risk of our customers, and nonpayment or nonperformance by our customers would reduce our cash flows.

We are subject to risk from loss resulting from our customers’ nonperformance or nonpayment. We depend on a limited number of customers for a significant portion of revenues from our oil and gas segment. In 2007, two of our oil and gas customers accounted for 35% of our natural gas and oil and condensate revenues and 12% of our total consolidated revenues. Any nonpayment or nonperformance by our oil and gas customers would reduce our cash flows.

Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate.

Our operations are subject to all of the risks and hazards typically associated with the exploitation, development and exploration for, and the production and transportation of oil and natural gas. These operating risks include:

Any of these risks could result in substantial losses resulting from injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damages, clean-up responsibilities, regulatory investigations and penalties and suspension of operations. In addition, under certain circumstances, we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease or operate. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.

In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse affecteffect on our financial condition and operations.

Our business depends on transportation facilities owned by others.

We deliver substantially all of our oil and natural gas production through pipelines that we do not own. The marketability of our production depends upon the availability, proximity and capacity of these pipelines as well as gathering systems and processing facilities. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Federal, state and local regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and market our oil and natural gas.

Estimates of oil and natural gas reserves are not precise.

This Annual Report on Form 10-K contains estimates of our proved oil and gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. These estimates are dependent on many variables and, therefore, changes often occur as these variables evolve and commodity prices fluctuate.

Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed by us. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.

At December 31, 2006,2007, approximately 29%41% of our estimated proved reserves were proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is based on volumetric calculations and adjacent reserve performance data. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Production revenues from proved developed non-producing reserves will not be realized until some time in the future. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our reserves and the costs associated with these reserves in accordance with industry standards, these estimated costs may not be accurate, development may not occur as scheduled and actual results may not occur as estimated.

You should not assume that the present value of estimated future net cash flowflows (standardized measure) referred to herein is the current fair value of our estimated oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual current and future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. As a result, net present value estimates using actual prices and costs may be significantly less than the SEC estimate that is provided herein. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor for us.

We have limited control over the activities on properties we do not operate.

Other companies operate a portion of our net production. In 2006,2007, other companies operated approximately 28%17% of our net production. Our success in properties operated by others will depend upon a number of factors outside of our control, including timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other participants in drilling wells, selection of technology and maintenance of safety and environmental standards. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund for their

operation. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns or lead to unexpected future costs.

Certain working interest owners in our properties have the right to control the timing of drilling activities on our properties under certain circumstances.

Under certain circumstances, certain of the other working interest owners in our properties have the right to limit the amount of drilling activities that can take place on our properties at any given time. If these working interest owners chose to exercise this right, we could be required to scale back anticipated drilling activities on the affected properties. In such an event, production from the affected properties would be deferred, thereby decreasing production from the properties in the short-term.

Our producing property acquisitions carry significant risks.

Acquisition of producing oil and gas properties is a key element of maintaining and growing reserves and production. Competition for these assets has been and will continue to be intense. The success of any acquisition will depend on a number of factors, many of which are beyond our control. These factors include the purchase price, future oil and gas prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation and

development activities on the acquired properties and future abandonment and possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject properties will not necessarily reveal all existing or potential problems.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.

Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results, and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions.

Responses to recent coal mining accidents could have an adverse effect on our operations.

Our conventional and CBM drilling operations in Appalachia take place in close proximity to coal mining operations. Recent coal mining disasters in West Virginia and Kentucky have received state and national attention that is resulting in increased scrutiny of current safety practices and procedures at and around coal mining operations. This scrutiny could result in the promulgation of more stringent regulations for the permitting of oil and gas wells in close proximity to coal mining operations, which could make it more difficult, time consuming and costly for us to obtain such permits and could adversely affect our natural gas production and reduce our oil and natural gas revenues.

HedgingDerivative transactions may limit our potential gains and involve other risks.

In order to manage our exposure to price risks in the marketingsale of our oil and natural gas, we periodically enter into oil and gas price hedging arrangements with respect to a portion of our expected production. Our hedges are limited in duration, usually for periods of two years or less. While intended to reduce the effects of volatile oil and natural gas prices, such transactions may limit our potential gains if oil or natural gas prices were to rise over the price established by the hedging arrangements. In trying to maintain an appropriate balance, we may end up hedging too much or too little, depending upon how oil or natural gas prices fluctuate in the future. We cannot assure you that our hedging transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices.

In addition, hedgingderivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

In addition, hedging transactions using derivative instruments involve basis risk. Basis risk in a hedgingderivative contract occurs when the index upon which the contract is based is more or less variable than the index upon which the hedged asset is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of production may have more or less variability than the regional price index used for the sale of that production.

We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Exploration, development, production and sale of oil and gas are subject to extensive federal, state and local laws and regulations, including complex environmental laws. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations, inability to obtain necessary regulatory approvals or a failure to comply with existing legal requirements may harm our business, results of operations and financial condition. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection and taxation. Our operations create the risk of environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations, we may be charged with remedial costs. Laws and regulations protecting the environment have become more stringent in recent years, and may, in some circumstances, result in liability for environmental damage regardless of negligence or fault. In addition, pollution and similar environmental risks generally are not fully insurable. These liabilities and costs could have a material adverse effect on our financial condition and results of operations. See Item 1, “Business—Government Regulation and Environmental Matters—Oil and Gas Segment—Environmental Matters.”

Risks Related to ourOur Ownership Interests in PVG and PVR

We are not the only partners of PVG and PVR, and PVG’s and PVR’s respective partnership agreements require them to distribute all available cash to their respective partners, including public unitholders.

PVG and PVR are publicly traded limited partnerships. We own PVG GP, LLC, the sole general partner of PVG. As of December 31, 2007, we also owned an approximately 82% limited partner interest in PVG. As of December 31, 2007, PVG owned approximately 44% of PVR, consisting of a 2% general partner interest and an approximately 42% limited partner interest in PVR, as well as the incentive distribution rights in PVR. We directly owned an additional 0.5% limited partner interest in PVR as of December 31, 2007. The remainder of the outstanding limited partner interests in each of PVG and PVR are owned by public unitholders. Although PVG’s and PVR’s respective partnership agreements require them to distribute, on a quarterly basis, 100% of their available cash to their respective unitholders of record and their respective general partners, we are not the only limited partners of PVG and PVR and, therefore, we receive only our proportionate share of cash distributions from each of PVG and PVR based on our partner interests in each of them. The remainder of the quarterly cash distributions are distributed, pro rata, to the public unitholders.

For each of PVG and PVR, available cash is generally all cash on hand at the end of each quarter, after payment of fees and expenses and the establishment of cash reserves by their respective general partners. PVG’s and PVR’s general partners determine the amount and timing of cash distributions by PVG and PVR and have broad discretion to establish and make additions to the respective partnership’s reserves or the reserves of the respective partnership’s operating subsidiaries in amounts the general partner determines to be necessary or appropriate:

Accordingly, cash distributions we receive on our partner interests in PVG and PVR may be reduced at any time, or we may not receive any cash distributions from PVG or PVR, which would in turn reduce our cash available to service our debt.

PVG’s ability to make distributions to us is entirely dependent upon PVG’s receiving distributions from PVR, and the amount of cash that PVR will be able to distribute to its unitholders, including PVG, principally depends upon the amount of cash it can generate from its coal and natural gas midstream businesses.

If PVG had completed its initial public offering on January 1, 2006, assuming its current distribution level, we would have received $30.8 million of distributions from PVG in 2006. PVG’s earnings and cash flow consist exclusively of cash distributions from PVR. Consequently, a significant decline in PVR’s earnings or cash distributions would have a negative impact on its distributions to its partners, including us. The amount of cash that PVR will be able to distribute to its partners, including PVG, each quarter principally depends upon the amount of cash it can generate from its coal and natural resource management and natural gas midstream businesses. The amount of cash that PVR will generate will fluctuate from quarter to quarter based on, among other things:

In addition, the actual amount of cash that PVR will have available for distribution will depend on other factors, some of which are beyond its control, including:

Because of these factors, PVR may not have sufficient available cash each quarter to continue paying distributions at their current level or at all. If PVR reduces its per unit distribution, PVG will have less cash available for distribution to its unitholders, including us, and would probably be required to reduce its per unit distribution to its unitholders, including us. You should also be aware that the amount of cash that PVR has available for distribution depends primarily upon PVR’s cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, PVR may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records profits.

In addition, the timing and amount, if any, of an increase or decrease in distributions by PVR to its unitholders will not necessarily be comparable to the timing and amount of any changes in distributions made by PVG. PVG’s ability to distribute cash received from PVR to its unitholders, including us, is limited by a number of factors, including:

A portion of PVG’s partnership interests in PVR are subordinated to PVR’s common units, which would result in decreased distributions by PVR to PVG and, consequently, could result in decreased distributions from PVG to its unitholders, including us, if PVR is unable to meet its minimum quarterly distribution.

PVG owns 19,587,049 units representing limited partner interests in PVR, of which approximately 79.3% are common units and 20.7% are Class B units. Currently, the Class B units will not receive any distributions in a quarter until PVR has paid the minimum quarterly distribution of $0.25 per PVR unit, plus any arrearages in the payment of the minimum quarterly distribution from prior quarters, on all of the outstanding PVR common units. Distributions on the Class B units are, therefore, more uncertain than distributions on PVR’s common units. Furthermore, no distributions may be made on the incentive distribution rights until the minimum quarterly distribution has been paid on all outstanding PVR units. Therefore, distributions with respect to the incentive distribution rights are even more uncertain than distributions on the Class B units. Neither the Class B units nor the incentive distribution rights are entitled to any arrearages from prior quarters.

A reduction in PVR’s distributions will disproportionately affect the amount of cash distributions to which PVG is currently entitled, and, consequently, will affect the amount of cash distributions PVG is able to make to its unitholders, including us.

PVG’s ownership of the incentive distribution rights in PVR, through PVG’s ownership interests inof PVR’s general partner, the holder of the incentive distribution rights, entitles PVG to receive its pro rata share of specified percentages of total cash distributions made by PVR with respect to any particular quarter only in the event that PVR distributes more than $0.275 per unit for such quarter. As a result, the holders of PVR’s common units and Class B units have a priority over the holders of PVR’s incentive distribution rights to the extent of cash distributions by PVR up to and including $0.275 per unit for any quarter.

PVG’s incentive distribution rights entitle it to receive increasing percentages, up to 48%, of allincremental cash distributions above $1.50 per unit, on an annualized basis, distributed by PVR. Because PVG is at the maximum target cash distribution level on the incentive distribution rights, future growth in distributions PVG receives from PVR, and in distributions we receive from PVG, will not result from an increase in the target cash distribution level associated with the incentive distribution rights. Furthermore, a decrease in the amount of distributions by PVR to less than $0.375 per unit per quarter would reduce PVG’s percentage of the incremental cash distributions above $0.325 per common unit per quarter from 48% to 23%, consequently resulting in less cash available to PVG to distribute to its unitholders, including us. A decrease in the amount of distribution by PVR and, consequently, PVG may be caused by a variety of circumstances. PVR may generate less cash available for distributions or determine to create larger reserves in computing cash available for distribution. Even

if cash available for distribution remained stable, PVG and PVR may determine to modify the incentive distribution rights to reduce the percentage of incremental cash distributions such incentive distribution rights are entitled to receive.

PVR may issue additional limited partner interests or other equity securities, which may increase the risk that PVR will not have sufficient available cash to maintain or increase its cash distribution level, which in turn may reduce the available cash that PVG has to distribute to its unitholders, including us.

PVR has wide latitude to issue additional limited partner interests on the terms and conditions established by its general partner. PVG receives cash distributions from PVR on the general partner interests,interest, incentive distribution rights and the limited partner interestsinterest that PVG holds. Because a majority of the cash PVG receives from PVR is attributable to PVG’s ownership of the incentive distribution rights, payment of distributions on additional PVR limited partner interests may increase the risk that PVR will be unable to maintain or increase its quarterly cash distribution per unit, which in turn may reduce the amount of incentive distributions PVG receives and the available cash that PVG has to distribute to its unitholders, including us.

Conflicts of interest may arise because the board of directors of the respective general partners of PVG and PVR have a fiduciary duty to manage the general partners in a manner that is beneficial to their owners, and at the same time, in a manner that is beneficial to the respective unitholders of PVG and PVR.

We own the sole general partner of PVG and PVG owns the sole general partner of PVR. PVG and PVR are publicly traded limited partnerships. Each of the board of directors of the general partners owes a fiduciary duty to the respective unitholders of PVG and PVR, and not just to us and PVG as owners of the general partners. As a result of these conflicts, the board of directors of the general partners of PVG and PVR may favor the interests of the public unitholders of PVG and PVR over the interests of the respective owners of the general partners.

Our ability to sell our common units of PVG, and PVG’s ability to sell its partnershippartner interests in PVR, may be limited by securities law restrictions and liquidity constraints.

We ownAs of December 31, 2007, we owned 32,087,424 common units of PVG and PVG owns 15,541,738owned 19,587,049 common units and 4,045,311 Class B units of PVR, all of which are unregistered and restricted securities within the meaning of Rule 144 under the Securities Act of 1933.1933, or the Securities Act. Unless we or PVG were to register these units, we or PVG are limited to selling into the market in any three-month period an amount of PVG common units or PVR common units that does not exceed the greater of 1% of the total number of common units outstanding or the average weekly reported trading

volume of the common units for the four calendar weeks prior to the sale. Furthermore, there is no public market for PVR’s Class B units and we do not expect one to develop. If PVG were required to sell Class B units for any reason, it likely would receive a discount to the current market price of PVR’s common units, and that discount may be substantial. In addition, PVG faces contractual limitations on its ability to sell its general partner interest and incentive distribution rights in PVR and the market for such interests is illiquid.

Congress is considering proposed legislation that may, if enacted, negatively impact the value of our limited partner interests in PVG by precluding PVG from qualifying for treatment as a partnership for U.S. federal income tax purposes under the publicly traded partnership rules.

In response to recent public offerings of interests in the management operations of private equity funds and hedge funds, members of Congress are considering substantive changes to the definition of qualifying income under Section 7704(d) Internal Revenue Code and changing the characterization of certain types of income received from partnerships. In particular, one proposal recharacterizes certain income and gain received with respect to “investment service partnership interests” as ordinary income for the performance of services, which may not be treated as qualifying income for publicly traded partnerships. As such proposal is currently interpreted, a significant portion of PVG’s interests in PVR may be viewed as an investment service partnership interest. Although we are unable to predict whether the proposed legislation, or any other proposals, will ultimately be enacted, the enactment of any such legislation could negatively impact the value of our limited partner interests in PVG.

Risks Related to PVR’s Coal and Natural Resource Management Business

If PVR’s lessees do not manage their operations well, their production volumes and PVR’s coal royaltyroyalties revenues could decrease.

PVR depends on its lessees to effectively manage their operations on its properties. PVR’s lessees make their own business decisions with respect to their operations, including decisions relating to:

If PVR’s lessees do not manage their operations well, their production could be reduced, which would result in lower coal royaltyroyalties revenues to PVR and could adversely affect PVR’s ability to make its quarterly distributions.

The coal mining operations of PVR’s lessees are subject to numerous operational risks that could result in lower coal royaltyroyalties revenues.

PVR’s coal royaltyroyalties revenues are largely dependent on the level of production from its coal reserves achieved by its lessees. The level of PVR’s lessees’ production is subject to operating conditions or events that may increase PVR’s lessees’ cost of mining and delay or halt production at particular mines for varying lengths of time and that are beyond their or its control, including:

Any interruptions to the production of coal from PVR’s reserves could reduce its coal royaltyroyalties revenues and adversely affect its ability to make its quarterly distributions. In addition, PVR’s coal royaltyroyalties revenues are based upon sales of coal by its lessees to their customers. If PVR’s lessees do not receive payments for delivered coal on a timely basis from their customers, their cash flow would be adversely affected, which could cause PVR’s cash flow to be adversely affected and could adversely affect PVR’s ability to make its quarterly distributions.

A substantial or extended decline in coal prices could reduce PVR’s coal royaltyroyalties revenues and the value of PVR’s coal reserves.

A substantial or extended decline in coal prices from recent levels could have a material adverse effect on PVR’s lessees’ operations (including mine closures) and on the quantities of coal that may be economically produced from its properties. This, in turn, could reduce PVR’s coal royaltyroyalties revenues, its coal services revenues and the value of its coal reserves. Additionally, volatility in coal prices could make it difficult to estimate with precision the value of PVR’s coal reserves and any coal reserves that PVR may consider for acquisition.

PVR depends on a limited number of primary operators for a significant portion of its coal royaltyroyalties revenues and the loss of or reduction in production from any of PVR’s major lessees could reduce its coal royaltyroyalties revenues.

PVR depends on a limited number of primary operators for a significant portion of its coal royaltyroyalties revenues. During 2006,In 2007, five primary operators, each with multiple leases, accounted for 78%65% of PVR’s coal royaltyroyalties revenues and 12%7% of our total consolidated revenues. If any of these operators enters bankruptcy or decidedecides to cease operations or significantly reduce its production, PVR’s coal royaltyroyalties revenues could be reduced.

A failure on the part of PVR’s lessees to make coal royalty payments could give PVR the right to terminate the lease, repossess the property or obtain liquidation damages and/or enforce payment obligations under the lease. If PVR repossessed any of its properties, PVR would seek to find a replacement lessee. PVR may not be able to find a replacement lessee and, if it finds a replacement lessee, PVR may not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If PVR enters into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as the lessee it replaced. In addition, it may be difficult for PVR to secure new or replacement lessees for small or isolated coal reserves, since industry trends toward consolidation favor larger-scale, higher technology mining operations to increase productivity rates.

PVR’s coal business will be adversely affected if PVR is unable to replace or increase its coal reserves through acquisitions.

Because its reserves decline as its lessees mine its coal, PVR’s future success and growth depends, in part, upon its ability to acquire additional coal reserves that are economically recoverable. If PVR is unable to negotiate purchase contracts to replace or increase its coal reserves on acceptable terms, its coal royaltyroyalties revenues will decline as its coal reserves are depleted. In addition, if PVR is unable to successfully integrate the companies, businesses or properties it is able to acquire, its coal royaltyroyalties revenues may decline and PVR could, therefore, experience a material adverse effect on its business, financial condition or results of operations. If PVR acquires additional coal reserves, there is a possibility that any acquisition could be dilutive to earnings and reduce its ability to make distributions to unitholders including us, or to pay interest on, or the principal of, its debt obligations. Any debt PVR incurs to finance an acquisition may similarly affect its ability to make distributions to unitholders including us, or to pay interest on, or the principal of, its debt obligations. PVR’s ability to make acquisitions in the future also could be limited by restrictions under its existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.

PVR’s lessees could satisfy obligations to their customers with coal from properties other than PVR’s, depriving PVR of the ability to receive amounts in excess of the minimum coal royalty payments.

PVR does not control its lessees’ business operations. ItsPVR’s lessees’ customer supply contracts do not generally require its lessees to satisfy their obligations to their customers with coal mined from PVR’s reserves. Several factors may influence a lessee’s decision to supply its customers with coal mined from properties PVR does not own or lease, including the royalty rates under the lessee’s lease with PVR, mining conditions, transportation costs and availability and customer coal quality specifications. If a lessee satisfies its obligations to its customers with coal from properties PVR does not own or lease, production under its lease will decrease, and PVR will receive lower coal royaltyroyalties revenues.

Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal mined from PVR’s properties.

Transportation costs represent a significant portion of the total cost of coal for the customers of PVR’s lessees. Increases in transportation costs could make coal a less competitive source of energy or could make coal produced by some or all of PVR’s lessees less competitive than coal produced from other sources. On the other hand, significant decreases in transportation costs could result in increased competition for PVR’s lessees from coal producers in other parts of the country.country or increased imports from offshore producers.

PVR’s lessees depend upon rail, barge, trucking, overland conveyor and other systems to deliver coal to their customers. Disruption of these transportation services due to weather-related problems, strikes, lockouts, bottlenecks, mechanical failures and other events could temporarily impair the ability of PVR’s lessees to supply coal to their customers. PVR’s lessees’ transportation providers may face difficulties in the future and impair the ability of its lessees to supply coal to their customers, thereby resulting in decreased coal royaltyroyalties revenues to PVR.

PVR’s lessees could experience labor disruptions, and PVR’s lessees’ workforces could become increasingly unionized in the future.

Two of PVR’s lessees each havehas one mine operated by unionized employees. One of thesethe mines operated by unionized employees was PVR’s second largest mine on the basis of coal production as of December 31, 2006.2007. All of PVR’s lessees could become increasingly unionized in the future. If some or all of PVR’s lessees’ non-unionized operations were to become unionized, it could adversely affect their productivity and increase the risk of work stoppages. In addition, PVR’s lessees’ operations may be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against its lessees’ operations. Any further unionization of PVR’s lessees’ employees could adversely affect the stability of production from its coal reserves and reduce its coal royaltyroyalties revenues.

PVR’s coal reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of PVR’s coal reserves.

PVR’s estimates of its coal reserves may vary substantially from the actual amounts of coal its lessees may be able to economically recover. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond PVR’s control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions relate to:

Actual production, revenues and expenditures with respect to PVR’s coal reserves will likely vary from estimates, and these variations may be material. As a result, you should not place undue reliance on the coal reserve data provided by PVR.

Any change in fuel consumption patterns by electric power generators away from the use of coal could affect the ability of PVR’s lessees to sell the coal they produce and thereby reduce PVR’s coal royaltyroyalties revenues.

According to the U.S. Department of Energy, domestic electric power generation accounts for approximately 90% of domestic coal consumption. The amount of coal consumed for domestic electric power generation is affected primarily by the overall demand for electricity, the price and availability of competing fuels for power plants such as nuclear, natural gas, fuel oil and hydroelectric power and environmental and other governmental regulations. PVR believes that most new power plants will be built to produce electricity during peak periods of demand. Many of these new power plants will likely be fired by natural gas because of lower construction costs compared to coal-fired plants and because natural gas is a cleaner burning fuel. The increasingly stringent requirements of the Clean Air ActCAA may result in more electric power generators shifting from coal to natural gas-fired power plants. See Item 1, “Business—Government Regulation and Environmental Matters—PVR Coal and Natural Resource Management Segment—Air Emissions.”

Extensive environmental laws and regulations affecting electric power generators could have corresponding effects on the ability of PVR’s lessees to sell the coal they produce and thereby reduce PVR’s coal royaltyroyalties revenues.

Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants, which are the ultimate consumers of the coal PVR’s lessees produce. These laws and regulations can require significant emission control expenditures for many coal-fired power plants, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. There is also continuing pressure on state and federal regulators to impose limits on carbon dioxide emissions from electric power plants, particularly coal-fired power plants. As a result of these current and proposed laws, regulations and trends, electricity generators may elect to switch to other fuels that generate less of these emissions, possibly further reducing demand for the coal that PVR’s lessees produce and thereby reducing its coal royaltyroyalties revenues. See Item 1, “Business—Government Regulation and Environmental Matters—PVR Coal and Natural Resource Management Segment—Air Emissions.”

Delays in PVR’s lessees obtaining mining permits and approvals, or the inability to obtain required permits and approvals, could have an adverse effect on PVR’s coal royaltyroyalties revenues.

Mine operators, including PVR’s lessees, must obtain numerous permits and approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining. The permitting rules are complex and can change over time. The public has the right to comment on many permit applications and otherwise participate in the permitting process, including through court intervention. Accordingly, permits required by PVR’s lessees to conduct operations may not be issued, maintained or renewed, or may not be issued or renewed in a timely fashion, or may involve requirements that restrict itsPVR’s lessees’ ability to economically conduct their mining operations. Limitations on PVR’s lessees’ ability to conduct their mining operations due to the inability to obtain or renew necessary permits, or due to uncertainty, litigation or delays associated with the eventual issuance of these permits, could have an adverse effect on its coal royaltyroyalties revenues. See Item 1, “Business—Government Regulation and Environmental Matters—PVR Coal and Natural Resource Management Segment—Mining Permits and Approvals.”

Uncertainty over the precise parameters of the Clean Water Act’s regulatory scope and a recent federal district court decision may adversely impact PVR’s coal lessees’ ability to secure the necessary permits for their valley fill surface mining activities.

To dispose of mining overburden generated from surface mining activities, PVR’s lessees often need to obtain government approvals, including Clean Water Act Section 404 permits to construct valley fills and sediment control ponds. Ongoing uncertainty over which waters are subject to the Clean Water Act may adversely impact PVR’s lessees’ ability to secure these necessary permits. In addition, a recent decision by a United States District Court in West Virginia invalidated a permit issued to one of PVR’s lessees for the Republic No. 2 Mine and enjoined its lessee, Alex Energy, Inc., from taking any further actions under this permit. Although this ruling has been appealed, uncertainty over the correct legal standard for issuing Section 404 permits may lead to rulings invalidating other permits, additional challenges to various permits and additional delays and costs in applying for and obtaining new permits. Unless this decision is overturned or further limited in subsequent proceedings, the ruling and its collateral consequences could ultimately have an adverse effect on PVR’s coal royalties revenues. See Item 1, “Business—Government Regulation and Environmental Matters—PVR Coal and Natural Resource Management Segment—Clean Water Act,” for more information about the litigation described above.

PVR’s lessees’ mining operations are subject to extensive and costly laws and regulations, which could increase operating costs and limit its lessees’ ability to produce coal, which could have an adverse effect on PVR’s coal royaltyroyalties revenues.

PVR’s lessees are subject to numerous and detailed federal, state and local laws and regulations affecting coal mining operations, including laws and regulations pertaining to employee health and safety, permitting and

licensing requirements, air quality standards, water pollution, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Numerous governmental permits and approvals are required for mining operations. PVR’s lessees are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be significant and time-consuming and may delay commencement or continuation of exploration or production operations. The possibility exists that new laws or regulations (or judicial interpretations of existing laws and regulations) may be adopted in the future that could materially affect PVR’s lessees’ mining operations, either through direct impacts such as new requirements impacting its lessees’ existing mining operations, or indirect impacts such as new laws and regulations that discourage or limit coal consumers’ use of coal. Any of these direct or indirect impacts could have an adverse effect on PVR’s coal royaltyroyalties revenues. See Item 1, “Business—Government Regulation and Environmental Matters—Mattes—PVR Coal and Natural Resource Management Segment.”

Because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry and, notwithstanding compliance efforts, PVR does not believe violations by its lessees can be eliminated completely. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens and, to a lesser extent, the issuance of injunctions to limit or cease operations. PVR’s lessees may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from their operations. If PVR’s lessees are required to pay these costs and liabilities and if their financial viability is affected by doing so, then their mining operations and, as a result, PVR’s coal royaltyroyalties revenues and its ability to make distributions, could be adversely affected.

Recent mining accidents in West Virginia and Kentucky have received national attention and instigated responses at the state and national level that are likely to resulthave resulted in increased scrutiny of current safety practices and procedures at all mining

operations, particularly underground mining operations. See Item 1, “Business—Government Regulation and Environmental Matters—PVR Coal and Natural Resource Management Segment—Mine Health and Safety Laws,” for a more detailed discussion of recently enacted legislation that addresses mine safety equipment, training and emergency reporting requirements. Implementing and complying with these new laws and regulations could adversely affect PVR’s lessees’ coal production and could therefore have an adverse affecteffect on PVR’s coal royaltyroyalties revenues and its ability to make distributions.

Risks Related to PVR’s Natural Gas Midstream Business

The success of PVR’s natural gas midstream business depends upon its ability to find and contract for new sources of natural gas supply.

In order to maintain or increase system throughput levels on PVR’s gathering systems and asset utilization rates at its processing plants, PVR must contract for new natural gas supplies. The primary factors affecting PVR’s ability to connect new supplies of natural gas to its gathering systems include the level of drilling activity creating new gas supply near its gathering systems, PVR’s success in contracting for existing natural gas supplies that are not committed to other systems and PVR’s ability to expand and increase the capacity of its systems. PVR may not be able to obtain additional contracts for natural gas supplies.

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. PVR has no control over the level of drilling activity in its areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, PVR has no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital.

PVR’s natural gas midstream assets, including its gathering systems and processing plants, are connected to natural gas reserves and wells for which the production will naturally decline over time. PVR’s cash flows associated with these systems will decline unless it is able to accesssecure new supplies of natural gas by connecting additional production to these systems. A material decrease in natural gas production in PVR’s areas of operation, as a result of depressed commodity prices or otherwise, would result in a decline in the volume of natural gas PVR handles, which would reduce its revenues and operating income. In addition, PVR’s future growth will depend, in part, upon whether it can contract for additional supplies at a greater rate than the rate of natural decline in PVR’s currently connected supplies.

The profitability of PVR’s natural gas midstream business is dependent upon prices and market demand for natural gas and NGLs, which are beyond PVR’s control and have been volatile.

PVR is subject to significant risks due to fluctuations in natural gas commodity prices. During 2006,2007, PVR generated a majority of its gross processing margin from two types of contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and NGLs—percentage-of-proceeds and gas purchase/keep-whole arrangements. See Item 1, “Business—Contracts—PVR Natural Gas Midstream Segment.”

Virtually all of the natural gas gathered on PVR’s Crescent System and Hamlin System is contracted under percentage-of-proceeds arrangements. The natural gas gathered on PVR’s Beaver System is contracted primarily under either percentage-of proceeds or gas purchase/keep-whole arrangements. Under both types of arrangements, PVR provides gathering and processing services for natural gas received. Under percentage-of-proceeds arrangements, PVR generally sells the NGLs produced from the processing operations and the remaining residue gas at market prices and remits to the producers an agreed upon percentage of the proceeds based upon an index price for the gas and the price received for the NGLs. Under these percentage-of-proceeds arrangements, revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have a material adverse effect on PVR’s results of operations. Under gas purchase/keep-whole arrangements, PVR generally buys natural gas from producers based upon an index price and then sells the NGLs and the remaining residue gas to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the volume of natural gas available for sale, profitability is dependent on the value of those NGLs being higher than the value of the volume of gas reduction or “shrink.” Under these arrangements, revenues and gross margins decrease when the price of natural gas increases relative to the price of NGLs. Accordingly, a change in the relationship between the price of natural gas and the price of NGLs could have a material adverse effect on PVR’s results of operations.

In the past, the prices of natural gas and NGLs have been extremely volatile, and PVR expects this volatility to continue. The markets and prices for residue gas and NGLs depend upon factors beyond PVR’s control. These factors include demand for oil, natural gas and NGLs, which fluctuates with changes in market and economic conditions, and other factors, including:

Acquisitions and expansions may affect PVR’s business by substantially increasing the level of its indebtedness and contingent liabilities and increasing the risks of being unable to effectively integrate these new operations.

From time to time, PVR evaluates and acquires assets and businesses that it believes complimentcomplement its existing operations. PVR may encounter difficulties integrating these acquisitions with its existing businesses without a loss of employees or customers, a loss of revenues, an increase in operating or other costs or other difficulties. In addition, PVR may not be able to realize the operating efficiencies, competitive advantages, cost savings or other benefits expected from these acquisitions. Future acquisitions may require substantial capital or the incurrence of substantial indebtedness. As a result, PVR’s capitalization and results of operations may change significantly following an acquisition, and you will not have the opportunity to evaluate the economic, financial and other relevant information that PVR will consider in determining the application of these funds and other resources.acquisition. Future PVR acquisitions might not generate increases in PVR’s pro forma available cash per unit, and may not increase cash distributions to PVR’sits unitholders.

Expanding PVR’s natural gas midstream business by constructing new gathering systems, pipelines and processing facilities subjects itPVR to construction risks.

One of the ways PVR may grow its natural gas midstream business is through the construction of additions to existing gathering, compression and processing systems. The construction of a new gathering system or pipeline, the expansion of an existing pipeline through the addition of new pipe or compression and the construction of new processing facilities involve numerous regulatory, environmental, political and legal uncertainties beyond PVR’s control and require the expenditure of significant amounts of capital. If PVR undertakes these projects, they may not be completed on schedule, or at all, or at the budgeted cost. Moreover, PVR’s revenues may not increase immediately upon the expenditure of funds on a particular project. For example, the construction of gathering facilities requires the expenditure of significant amounts of capital, which may exceed PVR’s estimates. Generally, PVR may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, PVR may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. As a result, there is the risk that new facilities may not be able to attract enough natural gas to achieve PVR’s expected investment return, which could adversely affect its financial position or results of operations and its ability to make distributions.distributions to us.

If PVR is unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then itPVR may be unable to fully execute its growth strategy and its cash flows could be reduced.

The construction of additions to PVR’s existing gathering assets may require itPVR to obtain new rights-of-way before constructing new pipelines. PVR may be unable to obtain rights-of-way to connect new natural gas supplies to its existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for PVR to obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, then PVR’s cash flows could be reduced.

PVR is exposed to the credit risk of its natural gas midstream customers, and nonpayment or nonperformance by PVR’s customers couldwould reduce its cash flows.

PVR is subject to risk of loss resulting from nonpayment or nonperformance by its natural gas midstream customers. PVR depends on a limited number of customers for a significant portion of its natural gas midstream revenue. For 2006, tworevenues. In 2007, three of PVR’s natural gas midstream customers represented 49%accounted for 53% of totalPVR’s natural gas midstream revenues and 26%27% of our total

consolidated revenues. Any nonpayment or nonperformance by ourPVR’s natural gas midstream customers couldwould reduce ourits cash flows.

Any reduction in the capacity of, or the allocations to, PVR in interconnecting third-party pipelines could cause a reduction of volumes processed, which wouldcould adversely affect itsPVR’s revenues and cash flow.flows.

PVR is dependent upon connections to third-party pipelines to receive and deliver residue gas and NGLs. Any reduction of capacities of these interconnecting pipelines due to testing, line repair, reduced operating

pressures or other causes could result in reduced volumes gathered and processed in itsPVR’s natural gas midstream facilities. Similarly, if additional shippers begin transporting volumes of residue gas and NGLs on interconnecting pipelines, PVR’s allocations in these pipelines wouldcould be reduced. Any reduction in volumes gathered and processed in PVR’s facilities wouldcould adversely affect its revenues and cash flow.flows.

Natural gas hedgingderivative transactions may limit PVR’s potential gains and involve other risks.

In order to manage PVR’s exposure to price risks in the marketing of its natural gas and NGLs, PVR periodically enters into natural gas and NGL price hedging arrangements with respect to a portion of its expected production. PVR’s hedges are limited in duration, usually for periods of two years or less. However, in connection with acquisitions, sometimes PVR’s hedges are for longer periods. These hedging transactions may limit PVR’s potential gains if natural gas or NGL prices were to rise over the price established by the hedging arrangements. In trying to maintain an appropriate balance, PVR may end up hedging too much or too little, depending upon how natural gas or NGL prices fluctuate in the future. PVR’s hedging transactions may not reduce the risk or minimize the effect of any decline in natural gas or NGL prices.

In addition, hedgingderivative transactions may expose PVR to the risk of financial loss in certain circumstances, including instances in which:

In addition, hedging transactions using derivative instruments involve basis risk. Basis risk in a hedgingderivative contract occurs when the index upon which the contract is based is more or less variable than the index upon which the hedged asset is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of production may have more or less variability than the regional price index used for the sale of that production.

PVR’s natural gas midstream business involves many hazards and operational risks, some of which may not be fully covered by insurance.

PVR’s natural gas midstream operations are subject to the many hazards inherent in the gathering, compression, treating, processing and transportation of natural gas and NGLs, including:

These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of PVR’s related operations. PVR’s natural gas midstream operations are concentrated in Texas and Oklahoma, and a natural disaster or other hazard affecting these areas could have a material adverse effect on its operations. PVR is not fully insured against all risks incident to its natural gas midstream business. PVR does not have property insurance on all of its underground pipeline systems that would cover damage to the pipelines. PVR is not insured against all environmental accidents that might occur, other than those considered to be sudden and accidental. If a significant accident or event occurs that is not fully insured, it could adversely affect PVR’s operations and financial condition.

Federal, state or local regulatory measures could adversely affect PVR’s natural gas midstream business.

PVR owns and operates an 11-mile interstate natural gas pipeline that, pursuant to the NGA,, is subject to the jurisdiction of the FERC. The FERC has granted PVR waivers of various requirements otherwise applicable to conventional FERC-jurisdictional pipelines, including the obligation to file a tariff governing rates, terms and conditions of open access transportation service. The FERC has determined that PVR will have to comply with the filing requirements if the natural gas company ever desires to apply for blanket transportation authority to transport third-party gas on the 11-mile pipeline. The FERC may revoke these waivers at any time.

PVR’s natural gas gathering facilities generally are exempt from the FERC’s jurisdiction under the NGA, but the FERC regulation nevertheless could change and significantly affect PVR’s gathering business and the market for its services. For a more detailed discussion of how regulatory measures affect PVR’s natural gas gathering systems, see Item 1, “Business—Government Regulation and Environmental Matters—PVR Natural Gas Midstream Segment.”

Failure to comply with applicable federal and state laws and regulations can result in the imposition of administrative, civil and criminal remedies.

PVR’s natural gas midstream business is subject to extensive environmental regulation.

Many of the operations and activities of PVR’s gathering systems, plants and other facilities are subject to significant federal, state and local environmental laws and regulations. These include, for example, laws and regulations that impose obligations related to air emissions and discharge of wastes from PVR’s facilities and the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by CanteraPVR or the prior owners of its natural

gas midstream business or locations to which it hasor they have sent wastes for disposal. These laws and regulations can restrict or impact PVR’s business activities in many ways, including restricting the manner in which it disposes of substances, requiring pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with control requirements. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances and wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.

There is inherent risk of the incurrence of environmental costs and liabilities in PVR’s natural gas midstream business due to its handling of natural gas and other petroleum products, air emissions related to its natural gas midstream operations, historical industry operations, waste disposal practices and Cantera’sthe use by the prior useowners of its natural gas midstream business of natural gas flow meters containing mercury. For example, an accidental release from one of PVR’s pipelines or processing facilities could subject it to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase PVR’s compliance costs and the cost of any remediation that may become necessary. PVR may incur material environmental costs and liabilities. Insurance may not provide sufficient coverage in the event an environmental claim is made. See Item 1, “Business—Government Regulation and Environmental Matters—PVR Natural Gas Midstream Segment.”

We received no written comments from the SEC staff regarding our periodic or current reports under the Exchange Act within 180 days before the end of our fiscal year ended December 31, 2006.

Title to Properties

The following map shows the general locations of our oil and gas production and exploration, PVR’s coal reserves and related infrastructure investments and PVR’s natural gas gathering and processing systems:systems as of December 31, 2007:

We believe that we have satisfactory title to all of our properties and the associated oil, natural gas and coal reserves in accordance with standards generally accepted in the oil and natural gas, coal and natural resource management and natural gas midstream industries.

Facilities

We are headquartered in Radnor, Pennsylvania, with additional offices in Oklahoma, Tennessee, Texas and West Virginia. All of our office facilities are leased, except for PVR’s West Virginia office, which it owns. We believe that our properties are adequate for our current needs.

Oil and Gas Properties

As is customary in the oil and gas industry, we make only a cursory review of title to farmout acreage and to undeveloped oil and gas leases upon execution of any contracts. Prior to the commencement of drilling operations, a thorough title examination is conducted and curative work is performed with respect to significant defects. To the extent title opinions or other investigations reflect defects, we cure such title defects. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on a property, we could suffer a loss of our investment in the property. Prior to completing an acquisition of producing oil and gas assets, we obtain title opinions on all material leases. Our oil and gas properties are subject to customary royalty interests, liens for current taxes and other burdens that we believe do not materially interfere with the use or materially affect the value of such properties.

Production and Pricing

The following table sets forth production, average sales prices and production costs with respect to our oil and gas properties for the years ended December 31, 2007, 2006 2005 and 2004:2005:

		2007				2006				2005
Production
Oil and condensate (Mbbls)			461				382				302
Natural gas (MMcf)			37,802				28,968				25,550
Total production (MMcfe)			40,569				31,260				27,362
Average realized prices
Natural gas ($/Mcf):
Natural gas revenues, as reported		$	6.94			$	7.35			$	8.31
Derivatives (gains) losses included in natural gas revenues			(0.01	)			(0.02	)			0.55
Natural gas revenues before impact of derivatives			6.93				7.33				8.86
Cash settlements on natural gas derivatives			0.39				0.37				(0.55	)
Natural gas revenues, adjusted for derivatives		$	7.32			$	7.70			$	8.31
Oil and condensate ($/Bbl):
Oil and condensate revenues, as reported		$	60.97			$	55.59			$	45.67
Derivatives (gains) losses included in oil and condensate revenues			1.09				1.20				2.84
Oil and condensate revenues before impact of derivatives			62.06				56.79				48.51
Cash settlements on crude oil derivatives			(1.59	)			(0.58	)			(2.84	)
Oil and condensate revenues, adjusted for derivatives		$	60.47			$	56.21			$	45.67
Production expenses ($/Mcfe)
Lease operating		$	1.15			$	0.88			$	0.63
Taxes other than income			0.44				0.38				0.48
General and administrative			0.40				0.41				0.34
Total production expenses		$	1.99			$	1.66			$	1.45

Proved Reserves

The following table presents certain information regarding our proved reserves as of December 31, 2007, 2006 2005 and 2004.2005. The proved reserve estimates presented below were prepared by Wright and Company, Inc., independent petroleum engineers. For additional information regarding estimates of proved reserves, the preparation of such estimates by Wright and Company, Inc. and other information about our oil and gas reserves, see Note 23 in the Notes to Consolidated Financial Statements.Supplemental Information on Oil and Gas Producing Activities (Unaudited). Our estimates of proved reserves in the following table below are consistent with those filed by us with other federal agencies.

that fiscal year end. For information on the changes in the standardized measure of discounted future net cash flows, see Note 23the Supplemental Information on Oil and Gas Producing Activities (unaudited).

(2)	Natural gas and oil prices were based on sales prices per Mcf and Bbl in effect at year end, with the Notesrepresentative price of natural gas adjusted for basis premium and BTU content to Consolidated Financial Statements.arrive at the appropriate net price.

In accordance with the SEC’s guidelines, the engineers’ estimates of future net revenues from our properties and the standardized measure thereof are based on oil and natural gas sales prices in effect as of December 31, 2006,2007, and estimated future costs as of December 31, 2006.2007. The prices are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. Prices for oil and gas are subject to substantial seasonal fluctuations as well as fluctuations resulting from numerous other factors. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Proved reserves are the estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. Therefore, the standardized measure amounts shown above should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. The information set forth

in the foregoing tables includes revisions of certain volumetric reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in production prices.

Production and Reserves by Region

The following table sets forth by region the estimated quantities of proved reserves as of December 31, 2007:

The following table sets forth by region the average daily production and total production for the years ended December 31, 2007, 2006 and 2005:

		Average Daily Production for the Year Ended December 31,						Total Production for the Year Ended December 31,
Region		2007		2006		2005		2007		2006		2005
		(MMcfe)						(MMcf)
Appalachia		34.0		35.0		37.8		12,424		12,759		13,812
Mississippi		20.7		17.6		14.2		7,551		6,411		5,185
East Texas		21.9		12.5		15.5		7,986		4,546		5,648
Mid-Continent		11.3		3.4		7.4		4,131		1,248		2,717
Gulf Coast		23.2		17.3		—		8,477		6,296		—
Total		111.1		85.8		74.9		40,569		31,260		27,362

Acreage

The following table sets forth our developed and undeveloped acreage at December 31, 2006.2007. The acreage is located primarily in the Appalachian, Mississippi, East Texas, Mid-Continent and Gulf Coast onshore areasregions of the United States.

Wells Drilled

The following table sets forth the gross and net numbers of exploratory and development wells that we drilled during the last three years.years ended December 31, 2007, 2006 and 2005. The number of wells drilled refers to the number of wells reaching total depth at any time during the respective year. Net wells equals the number of gross wells multiplied by our working interest in each of the gross wells. Productive wells represent either wells which were producing or which were capable of commercial production.

The four exploratory wells under evaluation at the end of 2007 included two Devonian Shale wells in West Virginia, one New Albany Shale well in Illinois and one horizontal coalbed methane well in West Virginia. We expect to determine the commercial viability of these wells in 2008. At December 31, 2007, we had capitalized costs of $4.3 million related to these wells.

The exploratory well under evaluation at the end of 2006 was a Cotton Valley well in Texas. We expect to determine the commercial viability ofIn 2007, we determined that this well during 2007.was commercially viable and reclassified $1.1 million to wells, equipment and facilities based on the determination of proved reserves. At December 31, 2006, we had capitalized costs of $1.1 million related to this well.

The three exploratory wells under evaluation at the end of 2005 included two New Albany Shale wells in Illinois and a Bakken Dolomite horizontal oil well in Montana. In 2006, we determined that these wells were not commercially viable, resulting in a $3.8 million write-off.

The three exploratory wells under evaluation at the end of 2004 included a horizontal Devonian shale well in West Virginia, a CBM well in Mississippi and an horizontal CBM well in Virginia. In 2005, we determined that these wells were not commercially viable, resulting in a $3.3 million write-off.

Productive Wells

The following table sets forth the number of productive oil and gas wells in which we had a working interest at December 31, 2006 is set forth below.2007. Productive wells are producing wells or wells capable of commercial production.

In addition to the above working interest wells, we own royalty interests in 2,8762,429 gross wells.

Coal Reserves and Production

As of December 31, 2006,2007, PVR owned or controlled approximately 765818 million tons of proven and probable coal reserves located on approximately 379,000397,000 acres (including fee and leased acreage) in Illinois, Kentucky, New Mexico, Virginia and West Virginia. PVR’s coal reserves are in various surface and underground mine seams located on the following properties:

Coal reserves are coal tons that can be economically extracted or produced at the time of determination considering legal, economic and technical limitations. All of the estimates of PVR’s coal reserves are classified as proven and probable reserves. Proven and probable reserves are defined as follows:

Proven Coal Reserves.Reserves. Proven coal reserves are coal reserves for which: (i) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; (ii) grade and/or quality are computed from the results of detailed sampling; and (iii) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well defined, that the size, shape, depth and mineral content of reserves are well-established.

Probable Coal Reserves.Reserves. Probable coal reserves are coal reserves for which quantity and grade and/or quality are computed from information similar to that used for proven coal reserves, but the sites for inspection, sampling and measurement are more widely spaced or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven coal reserves, is high enough to assume continuity between points of observation.

In areas where geologic conditions indicate potential inconsistencies related to coal reserves, PVR performs additional exploration to ensure the continuity and mineability of the coal reserves. Consequently, sampling in those areas involves drill holes or channel samples that are spaced closer together than those distances cited above.

Coal reserve estimates are adjusted annually for production, unmineable areas, acquisitions and sales of coal in place. The majority of PVR’s coal reserves are high in energy content, low in sulfur and suitable for either the steam or metallurgical market.

The amount of coal that a lessee can profitably mine at any given time is subject to several factors and may be substantially different from “proven and probable coal reserves.” Included among the factors that influence profitability are the existing market price, coal quality and operating costs.

The following tables set forth production data and reserve information with respect to each of PVR’s properties:

		Production for the Year Ended December 31,
Property		2007		2006		2005
		(tons in millions)
Central Appalachia		18.8		20.2		19.0
Northern Appalachia		4.2		5.0		5.0
Illinois Basin		3.8		2.5		1.4
San Juan Basin		5.7		5.1		4.8
Total		32.5		32.8		30.2

The following table sets forth the coal reserves PVR owns and leases with respect to each of its coal properties as of December 31, 2006:2007:

The following table sets forth PVR’s coal reserve estimates were prepared from geological data assembledactivity for each of its coal properties for the years ended December 2007, 2006 and analyzed by PVR’s general partner’s geologists and engineers. These estimates are compiled using geological data taken from thousands of drill holes, geophysical logs, adjacent mine workings, outcrop prospect openings and other sources. These estimates also take into account legal, qualitative, technical and economic limitations that may keep coal from being mined. Coal reserve estimates will change from time to time due to mining activities, analysis of new engineering and geological data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods and other factors.2005:

Other Natural Resource Management Assets

Coal Preparation and Loading Facilities

PVR generates coal services revenues from fees it charges to its lessees for the use of its coal preparation and loading facilities.facilities, which are located in Virginia, West Virginia and Kentucky. The facilities provide efficient methods to enhance lessee production levels and exploit PVR’s coal reserves. Historically, the majority

Timber and Oil and Gas Royalty Interests

PVR owns approximately 220,000 acres of these fees have been generated by PVR’s unit train loadout facility on its Central Appalachia property, which accommodates 108 car unit trains that can be loadedforestland in approximately four hours. SomeKentucky, Virginia and West Virginia. Approximately 28% of PVR’s lessees utilizeforestland is located on the unit train loadout facility to reduce the delivery costs incurred by their customers. The coal service facility PVR purchased in November 2002 on its Coal River property62,000 acres in West Virginia began operations late in the third quarter of 2003. In the first quarter of 2004,that PVR placed into service a newly constructed coal loadout facility for another lessee in West Virginia for $4.4 million. In September 2006, PVR completed construction of a new preparation and loading facility on property it acquired in 2005September 2007. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Acquisitions and Investments,” for a discussion of PVR’s forestland acquisition. The balance of PVR’s forestland is located on properties that also contain its coal reserves.

PVR owns royalty interests in approximately 11.2 Bcfe of proved oil and gas reserves located on approximately 165,000 acres in Kentucky, Virginia and West Virginia. Approximately 40% of PVR’s oil and gas royalty interests are associated with the leases of property in eastern Kentucky.Kentucky and southwestern Virginia that PVR acquired in October 2007. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Acquisitions, Dispositions and Investments,” for a discussion of PVR’s oil and gas royalty interest acquisition.

Natural Gas Midstream Systems

PVR’s natural gas midstream operations currently include three natural gas gathering and processing systems and a standalonestand-alone natural gas gathering system, including: (i) the Beaver/Perryton gathering and processing facilities in the Texas/Oklahoma panhandle area, (ii) the Crescent gathering and processing facilities in central Oklahoma, (iii) the Hamlin gathering and processing facilities in west-central Texas and (iv) the Arkoma gathering system in eastern Oklahoma. These systems include approximately 3,6313,682 miles of natural gas gathering pipelines and three natural gas processing facilities, which have 160 MMcfd of total capacity. PVR’s natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. PVR owns, leases or has rights-of-way to the properties where the majority of its natural gas midstream facilities are located.

The following table sets forth information regarding PVR’s natural gas midstream assets:

PVR expects to place a new Spearman natural gas processing plant in service by April 2008. The Spearman natural gas processing plant will have 60 MMcfd of inlet capacity. The Spearman natural gas processing plant will process gas gathered on the Spearman system. The new Spearman plant will create space in the Beaver natural gas processing plant for the gas that is currently bypassing the Beaver plant.

General. PVR is currently constructing a new natural gas gathering system located in the southeast portion of Harrison County, Texas (the Crossroads System). The Crossroads natural gas processing plant will have 80 MMcfd of inlet capacity. The Crossroads System will consist of approximately eight miles of natural gas gathering pipelines, ranging in size from eight to twelve inches in diameter, and the Crossroads natural gas processing plant. The Crossroads System will also include approximately 19 miles of six-inch NGL pipeline to transport the NGLs produced at the Crossroads plant to Panola Pipeline. The Crossroads System is expected to begin operations by April 2008.

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. See Item 1, “Business—Government Regulation and Environmental Matters,” for a more detailed discussion of our material environmental obligations.

There were no matters submitted to a vote of security holders during the fourth quarter of 2006.2007.

PARTPart II

Market Information

Our common stock is traded on the New York Stock ExchangeNYSE under the symbol “PVA.” The high and low sales prices (composite transactions) and dividends paid for each fiscal quarter in 20062007 and 20052006 were as follows: