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, 2009 Commission file number: 1-16735 
 Penn Virginia Resource Partners, L.P. (Exact name of registrant as specified in its charter)  Delaware

          

          23-3087517(State or other jurisdiction of incorporation or organization)

          

          (I.R.S. Employer Identification Number)
 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:  Title of each class

          

          Name of exchange on which registeredCommon Units

          

          New York Stock Exchange
 Securities registered pursuant to Section 12(g) of the Act: None 
 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yes x No o 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 (Exchange Act). Yes o 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 o 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. o Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check One)  Large accelerated filer o

          

          Accelerated filer x

          

          Non-accelerated filer o

          

          Smaller reporting company o
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes o No x The aggregate market value of common units held by non-affiliates of the registrant was $432,356,579 as of June 30, 2009 (the last business day of its most recently completed second fiscal quarter), based on the last sale price of such units as quoted on the New York Stock Exchange. For purposes of making this calculation only, the registrant has defined affiliates as including the registrants general partner, all affiliates of the registrants general partner and all directors and executive officers of the registrants general partner. This determination of affiliate status is not necessarily a conclusive determination for other
purposes. As of February 22, 2010, 51,798,895 common units representing limited partner interests of the registrant were outstanding. DOCUMENTS INCORPORATED BY REFERENCE None
     TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES Table of Contents  PageForward-Looking Statements





ii
  ItemPart I1.Business





11A.Risk Factors





211B.Unresolved Staff Comments





382.Properties





393.Legal Proceedings





464.Reserved





46Part II5.Market for the Registrants Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities





476.Selected Financial Data





487.Managements Discussion and Analysis of Financial Condition and Results of Operations





49Overview of Business





49Liquidity and Capital Resources





51Contractual Obligations





55Off-Balance Sheet Arrangements





55Results of Operations





56Environmental Matters





66Critical Accounting Estimates





66New Accounting Standards





687A.Quantitative and Qualitative Disclosures About Market Risk





698.Financial Statements and Supplementary Data





729.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure





1109A.Controls and Procedures





1109B.Other Information





110Part III10.Directors, Executive Officers and Corporate Governance





11111.Executive Compensation





11512.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters





13313.Certain Relationships and Related Transactions, and Director Independence





13414.Principal Accounting Fees and Services





136Part IV15.Exhibits and Financial Statement Schedules





137
 i    TABLE OF CONTENTS Forward-Looking Statements Certain statements contained herein that are not descriptions of historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or Exchange Act. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: 

          the volatility of commodity prices for natural gas, NGLs and coal; 

          our ability to access external sources of capital; 

          any impairment writedowns of our assets; 

          the relationship between natural gas, NGL and coal prices; 

          the projected demand for and supply of natural gas, NGLs and coal; 

          competition among producers in the coal industry generally and among natural gas midstream companies; 

          the extent to which the amount and quality of actual production of our coal differs from estimated recoverable coal reserves; 

          our ability to generate sufficient cash from our businesses to maintain and pay the quarterly distribution to our general partner and our unitholders; 

          the experience and financial condition of our coal lessees and natural gas midstream customers, including our lessees ability to satisfy their royalty, environmental, reclamation and other obligations to us and others; 

          operating risks, including unanticipated geological problems, incidental to our coal and natural resource management or natural gas midstream business; 

          our ability to acquire new coal reserves or natural gas midstream assets and new sources of natural gas supply and connections to third-party pipelines on satisfactory terms; 

          our ability to retain existing or acquire new natural gas midstream customers and coal lessees; 

          the ability of our lessees to produce sufficient quantities of coal on an economic basis from our reserves and obtain favorable contracts for such production; 

          the occurrence of unusual weather or operating conditions including force majeure events; 

          delays in anticipated start-up dates of our lessees mining operations and related coal infrastructure projects and new processing plants in our natural gas midstream business; 

          environmental risks affecting the mining of coal reserves or the production, gathering and processing of natural gas; 

          the timing of receipt of necessary governmental permits by us or our lessees; 

          hedging results; 

          accidents; 

          changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with respect to emissions levels applicable to coal-burning power generators; 

          uncertainties relating to the outcome of current and future litigation regarding mine permitting;
 ii    TABLE OF CONTENTS 

          risks and uncertainties relating to general domestic and international economic (including inflation, interest rates and financial and credit markets) and political conditions (including the impact of potential terrorist attacks); and 

          other risks set forth in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2009. Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect managements views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.
 iii    TABLE OF CONTENTS Part I Item 1 Business General Penn Virginia Resource Partners, L.P. (NYSE: PVR) is a publicly traded Delaware limited partnership formed by Penn Virginia Corporation (NYSE: PVA), or Penn Virginia, in 2001 that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. Both in our current limited partnership form and in our previous corporate form, we have managed coal properties since 1882. We currently conduct operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream. Our operating income was $108.3 million in 2009, compared to $115.2 million in 2008 and $117.7 million in 2007. In 2009, our coal and natural resource management segment contributed $87.5 million, or 81%, to operating income, and our natural gas midstream segment contributed $20.8 million, or 19%, to operating income. Unless the context requires otherwise, references to the Partnership, we, us or our in this Annual Report on Form 10-K refer to Penn Virginia Resource Partners, L.P. and its subsidiaries. Coal and Natural Resource Management Segment Overview Our coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees. As of December 31, 2009, we owned or controlled approximately 829 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. We enter into long-term leases with experienced, third-party mine operators, providing them the right to mine our coal reserves in exchange for royalty payments. We actively work with our lessees to develop efficient methods to exploit our reserves and to maximize production from our properties. We do not operate any mines. In 2009, our lessees produced 34.3 million tons of coal from our properties and paid us coal royalties revenues of $120.4 million, for an
average royalty per ton of $3.51. Approximately 82% of our coal royalties revenues in 2009 were derived from coal mined on our 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 our coal royalties revenues for the respective periods was derived from coal mined on our properties under leases containing fixed royalty rates that escalate annually. See  Contracts  Coal and Natural Resource Management Segment for a description of our coal leases. Natural Gas Midstream Segment Overview Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of December 31, 2009, we owned and operated natural gas midstream assets located in Oklahoma and Texas, including six natural gas processing facilities having 400 MMcfd of total capacity and approximately 4,118 miles of natural gas gathering pipelines. Our natural gas midstream business earns revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In addition, we own a 25% member interest in Thunder Creek Gas
Services, LLC, or Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyomings Powder River Basin. We also own 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. In 2009, system throughput volumes at our gas processing plants and gathering systems, including gathering-only volumes, were 121.3 Bcf, or approximately 332 MMcfd.
 1    TABLE OF CONTENTS Business Strategy Our primary business objective is to create sustainable, capital-efficient growth in cash available for distribution to our unitholders while maintaining a strong credit profile and financial flexibility. Our growth objective is largely dependent on the availability of open and reasonably priced capital markets. Subject to the availability of the capital markets, we are pursuing the following business strategies: 

          Continue to grow coal reserve holdings through acquisitions and investments in our existing market areas.  We expect to continue to add to our coal reserve holdings in Central Appalachia and the Illinois Basin in the future, but may consider the acquisition of reserves outside of these basins if the market and quality of the reserves satisfy our criteria. We have historically operated in Central Appalachia, our largest area of coal reserves, but we view the Illinois Basin as a growth area, both because of its proximity to power plants and because we expect future environmental regulations will require the scrubbing of most coals, and not just the higher sulfur coal that is typically found in this basin. We will consider acquisitions of coal reserves that are long-lived and that are of sufficient size to yield significant production or serve as a platform for complementary acquisitions. 

          Expand in areas that complement our coal royalty business. Timber and coal infrastructure projects typically involve long-lived, fee-based assets that generally produce predictable cash flows. We own or control approximately 243,000 acres of forestlands in Appalachia, which primarily produce various hardwoods, and we own a number of coal infrastructure facilities. We also have an equity interest in a coal handling joint venture, which is expected to provide development opportunities for coal-related infrastructure projects. 

          Expand our natural gas midstream operations by adding new production to existing systems and acquiring or building new gathering and processing assets. We continually seek new supplies of natural gas both to offset the natural declines in production from the wells currently connected to our systems and to increase system throughput volumes. New natural gas supplies are obtained for all of our systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and by contracting for natural gas that has been released from competitors systems. During 2009, we acquired a 60 MMcfd processing plant and residue pipeline facilities in western Oklahoma. Additionally, we completed a 40 MMcfd processing plant expansion in our Beaver/Spearman complex, or the Panhandle system. 

          Mitigate commodity price exposure in our natural gas midstream segment.  Our natural gas midstream operations consist of a mix of fee-based and margin-based services that, together with our hedging activities, are expected to generate relatively stable cash flows. During the quarter ended December 31, 2009, approximately 19% of the system throughput volumes in our natural gas midstream segment were gathered or processed under fee-based contracts. Under fee-based contracts, we are not exposed directly to commodity price risk. The remainder of our system throughput volumes were gathered or processed under gas purchase/keep-whole arrangements and percentage-of-proceeds arrangements that are subject to commodity price risk. However, we expect to manage our exposure to commodity price risk by entering into hedging transactions. Based upon current volumes, we have entered into hedging agreements covering approximately 58% and 37% of
our commodity-sensitive volumes in 2010 and 2011. We generally target hedging 50 to 60% of our commodity-sensitive volumes covering a two-year period. Contracts Coal and Natural Resource Management Segment We earn most of our coal royalties revenues under long-term leases that generally require our lessees to make royalty payments to us 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 our coal royalties revenues is earned under long-term leases that require the lessees to make royalty payments to us based on fixed royalty rates that escalate annually. A typical lease either expires upon exhaustion of the leased reserves 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 our leases require the lessee to pay minimum rental payments to us in monthly or annual installments,
 2    TABLE OF CONTENTS 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 us once coal production commences. Substantially all of our leases impose obligations on the lessees to diligently mine the leased coal using modern mining techniques, indemnify us for any damages we incur in connection with the lessees mining operations, including any damages we 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 our written consent prior to assigning the lease and maintain commercially reasonable amounts of general liability and other insurance. Substantially all of the leases grant us 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 us the right to terminate the lease and take possession of the leased premises. In addition, we earn revenues under coal services contracts, timber contracts and oil and gas leases. Our coal services contracts generally provide that the users of our coal services pay us a fixed fee per ton of coal processed at our facilities. All of our coal services contracts are with lessees of our coal reserves and these contracts generally have terms that run concurrently with the related coal lease. Our timber contracts generally provide that the timber companies pay us a fixed price per thousand board feet of timber harvested from our property. We receive royalties under our oil and gas leases based on a percentage of the revenues the
producers receive for the oil and gas they sell. Natural Gas Midstream Segment Our natural gas 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, 2009, our 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 NGLs: (i) gas purchase/keep-whole and (ii) percentage-of-proceeds. For the fourth quarter of 2009, approximately 28% of our system throughput volumes were gathered or processed
under gas purchase/keep-whole contracts, 53% were gathered or processed under percentage-of-proceeds contracts and 19% were gathered or processed under fee-based gathering contracts. A majority of the gas purchase/keep-whole and percentage-of-proceeds contracts include fee-based components such as gathering and compression charges. In 2009, 21%, 15% and 10% of our natural gas midstream segment revenues and 17%, 11% and 8% of our total consolidated revenues resulted from three of our natural gas midstream customers, Conoco, Inc., Tenaska Marketing Ventures and ONEOK Energy Marketing. Gas Purchase/Keep-Whole Arrangements.  Under gas purchase/keep-whole arrangements, we generally purchase 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). We then gather the natural gas to one of our plants where it is processed to extract the entrained NGLs, which are then sold to third parties at market prices. We resell 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 BTU content of the natural gas, we retain a reduced volume of gas to sell after processing. Accordingly, under these arrangements, our revenues and gross margins increase as the price of NGLs increases relative to the price of natural gas, and our revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. We have generally been able to mitigate our exposure in the latter case by requiring the payment under many of our gas purchase/keep-whole arrangements of minimum processing charges which ensure that we receive a minimum amount of processing revenues. The gross margins that we realize 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.  Under percentage-of-proceeds arrangements, we generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed-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, our
 3    TABLE OF CONTENTS revenues and gross margins increase as natural gas prices and NGL prices increase, and our revenues and gross margins decrease as natural gas prices and NGL prices decrease. Fee-Based Arrangements.  Under fee-based arrangements, we receive fees for gathering, compressing and/or processing natural gas. The revenues we earn from these arrangements are directly dependent on the volume of natural gas that flows through our systems and are independent of commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues from these arrangements would be reduced due to the related reduction in drilling and development of new supply. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our 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. Natural Gas Marketing Contracts.  We are 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 Panhandle Eastern Pipeline and at market hubs accessed by various interstate pipelines. Connect Energy Services, LLC, or Connect Energy, our wholly owned subsidiary, has earned fees from Penn Virginia Oil & Gas, L.P., or PVOG LP, a wholly owned subsidiary of Penn Virginia, since September 1, 2006, for marketing a portion of PVOG LPs natural gas production. Revenues from this business do not generate qualifying income for
a publicly traded limited partnership, but we do not expect it to have an impact on our tax status, as it does not represent a significant percentage of our operating income. For the years ended December 31, 2009 and 2008, natural gas marketing activities generated $1.8 million and $5.8 million in net revenues. Commodity Derivative Contracts.  We utilize collar derivative contracts to hedge against the variability in our frac spread. Our frac spread is the spread between the purchase price for the natural gas we purchase from producers and the sale price for NGLs that we sell after processing. We hedge against the variability in our frac spread by entering into costless collar and swap derivative contracts to sell NGLs forward at a predetermined commodity 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, such use may also
limit future revenues or cost savings from favorable price movements. See Note 6 to the Consolidated Financial Statements for a further description of our derivatives program. Partnership Structure Penn Virginia, a publicly held energy company has been engaged in the coal royalty business since 1882 and is also engaged in the exploration, development and production of natural gas and oil. Penn Virginia formed us as a Delaware limited partnership in July 2001 to own and operate substantially all of the assets of and assume the liabilities relating to Penn Virginias coal land management business. We completed our initial public offering in October 2001. Penn Virginia continues to hold a significant interest in us through its indirect controlling interest in Penn Virginia GP Holdings, L.P. (NYSE: PVG), or PVG, a publicly traded Delaware
limited partnership.
 4    TABLE OF CONTENTS Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own our subsidiaries through a wholly owned subsidiary, PVR Finco LLC, which is the sole member of the operating company for the coal and natural resource management segment, Penn Virginia Operating Co., LLC, or PVR Coal, and the operating company for the natural gas midstream segment, PVR Midstream LLC, or PVR Midstream. The following diagram depicts our and our affiliates simplified organizational and ownership structure as of December 31, 2009: [GRAPHIC MISSING] Relationship with Penn Virginia Corporation Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Under an omnibus agreement between us, Penn Virginia and our general partner, Penn Virginia and its affiliates, including PVG and our general partner, are restricted in their ability to engage in any coal-related business. See Item 13, Certain Relationships and Related Transactions, and Director Independence  Transactions with Related Persons. Partnership Distributions Cash Distributions We paid cash distributions of $1.88 per common unit during the year ended December 31, 2009. In the first quarter of 2010, we paid a cash distribution of $0.47 ($1.88 on an annualized basis) per common unit with respect to the fourth quarter of 2009. This distribution was unchanged from the previous distribution paid on November 13, 2009. For the remainder of 2010, we expect to pay quarterly cash distributions of at least $0.47 ($1.88 on an annualized basis) per common unit.
 5    TABLE OF CONTENTS The following table reflects the allocation of total cash distributions paid by us during the years ended December 31, 2009, 2008 and 2007 (in thousands, except per unit information):  Year Ended December 31,2009

          

          2008

          

          2007Limited partner units

          

          $

          97,382

          

          

          $

          89,207

          

          

          $

          76,536General partner interest (2%)

          

          

          1,988

          

          

          

          1,820

          

          

          

          1,562Incentive distribution rights

          

          

          24,140

          

          

          

          20,049

          

          

          

          11,551Phantom units

          

          

          499

          

          

          

          

          

          

          

          Total cash distributions paid

          

          $

          124,009

          

          

          $

          111,076

          

          

          $

          89,649Total cash distributions paid per limited partner unit

          

          $

          1.88

          

          

          $

          1.82

          

          

          $

          1.66
 Incentive Distribution Rights In accordance with our partnership agreement, incentive distribution rights, or IDRs, represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. The minimum quarterly distribution is $0.25 ($1.00 on an annualized basis) per unit. Our general partner currently holds 100% of the IDRs, but may transfer these rights separately from its general partner interest to an affiliate (other than an individual) or to another entity as part of the merger or consolidation of our general partner with or into
such entity or the transfer of all or substantially all of our general partners assets to another entity without the prior approval of our unitholders if the transferee agrees to be bound by the provisions of our partnership agreement. Prior to September 30, 2011, other transfers of the IDRs will require the affirmative vote of holders of a majority of the outstanding common units. On or after September 30, 2011, the IDRs will be freely transferable. The IDRs are payable as follows: If for any quarter: 

          we have distributed available cash from operating surplus to our common unitholders in an amount equal to the minimum quarterly distribution; and 

          we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution; then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner: 

          First, 98% to all unitholders, and 2% to our general partner, until each unitholder has received a total of $0.275 per unit for that quarter; 

          Second, 85% to all unitholders, and 15% to our general partner, until each unitholder has received a total of $0.325 per unit for that quarter; 

          Third, 75% to all unitholders, and 25% to our general partner, until each unitholder has received a total of $0.375 per unit for that quarter; and 

          Thereafter, 50% to all unitholders and 50% to our general partner. Since 2001, we have increased our quarterly cash distribution from $0.25 ($1.00 on an annualized basis) per unit to $0.47 ($1.88 on an annualized basis) per unit, which is our most recently declared distribution. These increased cash distributions have placed our general partner at the maximum target cash distribution level as described above and, as a consequence, since reaching such level, our general partner has received 50% of available cash in excess of $0.375 per unit.
 6    TABLE OF CONTENTS Subordinated Units Until May 22, 2007, we had Class B units, a separate class of subordinated units representing limited partner interests in us that were issued to PVG in connection with PVGs initial public offering. On May 22, 2007, all of our Class B units automatically converted into common units on a one-for-one basis and no Class B units remain outstanding. Limited Call Right If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner has the right, which it may assign in whole or in part to any of its affiliates or us, but not the obligation, to acquire all of the remaining common units held by unaffiliated persons as of a record date to be selected by our general partner, on at least ten but not more than 60 days notice, at a price equal to the greater of (i) the average of the daily closing prices of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the
highest price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result of this right of our general partner, a holder of common units may have his or her common units purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his or her units in the market. As of February 22, 2010, PVG and its affiliates owned 19,587,049 common units, representing approximately 37% of our outstanding common units. Certain Conflicts of Interest Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Penn Virginia and PVG), on the one hand, and us and our unitholders, on the other hand. Our general partner is controlled by PVG, which is in turn controlled by Penn Virginia. Accordingly, PVG (and Penn Virginia indirectly) has the ability to elect, remove and replace the directors and officers of our general partner. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners, Penn Virginia and PVG. At the same time, our
general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders. Certain of the executive officers and non-independent directors of our general partner also serve as executive officers and directors of Penn Virginia or the general partner of PVG. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to Penn Virginia or PVG, on the one hand, and us, on the other hand, are in conflict. Limits on Fiduciary Responsibilities Our partnership agreement limits the liability and reduces the fiduciary duties owed by our general partner to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partners fiduciary duty. Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement permits our general partner to make a number of decisions in its sole discretion. This entitles our general partner to consider only the interests and factors that it desires and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Other provisions of the partnership agreement provide that our general partners
actions must be made in its reasonable discretion. These standards reduce the obligations to which our general partner would otherwise be held. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be fair and reasonable to us under the factors previously set forth. In determining whether a transaction or resolution is fair and reasonable our general partner may consider the interests of all parties involved, including its own. Unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty. These standards reduce the obligations to which our general partner would otherwise be
held.
 7    TABLE OF CONTENTS In order to become a limited partner of our partnership, a common unitholder is required to agree to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Revised Uniform Limited Partnership Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person. In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions if our general partner and those other persons acted in good faith. We are required by our partnership agreement to indemnify our general partner and its officers, directors, employees, affiliates, partners, members, agents and trustees to the fullest extent permitted by law against liabilities, costs and expenses incurred by our general partner or these other persons. This indemnification is required if our general partner or any of these persons acted in good faith and in a manner they reasonably believed to be in, or (in the case of a person other than our general partner) not opposed to, our best interests. Indemnification is required for criminal proceedings if our general partner or these other persons had no
reasonable cause to believe their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met these requirements concerning good faith and our best interests. Competition Coal and Natural Resource Management Segment The coal industry is intensely competitive primarily as a result of the existence of numerous producers. Our lessees compete with both large and small coal producers in various regions of the United States for domestic sales. The industry has undergone significant consolidation which has led to some of the competitors of our lessees having significantly larger financial and operating resources than most of our lessees. Our lessees compete on the basis of coal price at the mine, coal quality (including sulfur content), transportation cost from the mine to the customer and the reliability of supply. Continued demand for our coal and the prices that our
lessees obtain are also affected by demand for electricity, demand for metallurgical coal, access to transportation, environmental and government regulations, technological developments and the availability and price of alternative fuel supplies, including nuclear, natural gas, oil and hydroelectric power. Demand for our low sulfur coal and the prices our lessees will be able to obtain for it will also be affected by the price and availability of high sulfur coal, which can be marketed in tandem with emissions allowances which permit the high sulfur coal to meet federal Clean Air Act, or CAA, requirements. Natural Gas Midstream Segment We experience competition in all of our natural gas midstream markets. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, process, transport and market natural gas. Many of our competitors have greater financial resources and access to larger natural gas supplies than we do. The ability to offer natural gas producers competitive gathering and processing arrangements and subsequent reliable service is fundamental to obtaining and keeping gas supplies for our gathering systems. The primary concerns of the producer are: 

          the pressure maintained on the system at the point of receipt; 

          the relative volumes of gas consumed as fuel and lost; 

          the gathering/processing fees charged; 

          the timeliness of well connects; 

          the customer service orientation of the gatherer/processor; and 

          the reliability of the field services provided.
 8    TABLE OF CONTENTS Government Regulation and Environmental Matters The operations of our coal and natural resource management business and natural gas midstream business are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. Coal and Natural Resource Management Segment General Regulation Applicable to Coal Lessees.  Our 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. These extensive and comprehensive regulatory requirements are closely enforced, our lessees regularly have on-site inspections and violations during mining operations are not unusual in the industry, notwithstanding compliance efforts by our lessees. However, none of the violations to date, or the monetary penalties assessed, have been material to us or, to our knowledge, to our lessees. Although many new safety requirements have been instituted recently, we do not currently expect that future compliance will have a material adverse effect on us. While it is not possible to quantify the costs of compliance by our 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 our lessees are contractually liable for all costs relating to their mining operations, including the costs of reclamation and mine closure. However, we do 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 our lessees. The possibility exists that new legislation or regulations may be adopted which have a significant impact on the mining operations of our lessees or their customers ability to use coal and may require us, our lessees or their customers to change operations significantly or incur substantial costs. Air Emissions.  The CAA and corresponding state and local laws and regulations affect all aspects of our business, both directly and indirectly. The CAA directly impacts our 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 CAA 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 Environmental Protection Agency, or 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 our lessees ability to sell coal, which could have a material effect on our coal royalties revenues. The EPAs Acid Rain Program, provided in Title IV of the 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
 9    TABLE OF CONTENTS 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, which would have permanently capped nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. beginning in 2009 and 2010. CAIR required those 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 have required 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 have resulted in decreased demand for lower sulfur coal, which may have potentially driven down prices for lower sulfur coal. On July 11, 2008, the D.C. Circuit Court of Appeals vacated CAIR in its entirety. The EPA subsequently filed a petition for rehearing or, in the alternative, for a remand of the case without vacatur. On December 23, 2008, the Court issued an opinion to remand without vacating CAIR. Therefore, CAIR will remain in effect while the EPA conducts rulemaking to modify CAIR to comply with the Courts July 2008 opinion. The Court
declined to impose a schedule by which the EPA must complete the rulemaking, but reminded the EPA that the Court does ...not intend to grant an indefinite stay of the effectiveness of this Courts decision. The EPA is considering its options on how to proceed. In March 2005, the EPA finalized the Clean Air Mercury Rule, or CAMR, which was to establish a two-part, nationwide cap on mercury emissions from coal-fired power plants beginning in 2010. It 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. The EPA appealed the decision to the U.S. Supreme Court in October 2008, but withdrew its petition for certiorari on February 6, 2009. However, a utility group continues to seek certiorari, challenging the court of appeals decision to overturn CAMR. In the meantime, the EPA plans to develop standards
consistent with the court of appeals ruling, intending to propose air toxics standards for coal- and oil-fired electric generating units by March 10, 2011, and finalize a rule by November 16, 2011. In conjunction with these efforts, on December 24, 2009, the EPA approved an Information Collection Request (ICR) requiring all U.S. power plants with coal-or oil-fired electric generating units to submit emissions information for use in developing air toxics emissions standards. In addition, various states have promulgated or are considering more stringent emission limits on mercury 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. In March 2007, the EPA published final rules addressing how states would implement plans to bring regions designated as non-attainment for fine particulate matter into compliance with the new air quality standard. Under the EPAs final rule, states had 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, our lessees mining operations and their customers could be affected when the new standards are implemented by the applicable states. Likewise, the EPAs regional haze program to improve visibility in national parks and wilderness areas required affected states to 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.
 10    TABLE OF CONTENTS 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 CAA. The EPA has alleged that certain modifications have been made to these facilities without first obtaining permits required under the new source review program. Several of these lawsuits have settled, but others remain pending. On April 2, 2007, the U.S. Supreme Court ruled in one such case, Environmental Defense v. Duke Energy Corp. The Court held that the 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 our coal could be affected, which could have an adverse effect on our coal royalties revenues. Carbon Dioxide 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, 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. In addition, on April 2, 2007 the U.S. Supreme Court held in Massachusetts 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 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 U.S. Court of Appeals for the District of Columbia Circuit, involving a challenge to the EPAs decision not to regulate 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 the EPA for further consideration in light of the ruling in Massachusetts v. EPA. On July 11, 2008, the EPA released an advanced notice of proposed rulemaking to regulate greenhouse gases under the CAA in response to the ruling in Massachusetts v. EPA. The notice did not contain a definitive proposal of what a greenhouse gas regulatory program would look like, but it presented the EPAs analyses and policy alternatives for consideration. The EPA stated that promulgating a program under the CAA would take years to issue. In 2009, EPA took further steps toward greenhouse gas regulation under the CAA, issuing a final rule declaring that six greenhouse gases, including carbon dioxide and methane, endanger both the public health and the public welfare of current and future generations. The issuance of this endangerment finding allows the EPA to begin regulating greenhouse gas emissions under
existing provisions of CAA. In late September and early October of 2009, in anticipation of the issuance of the endangerment finding, the EPA officially proposed two sets of rules regarding possible future regulation of greenhouse gas emissions under the CAA, one that would regulate greenhouse gas emissions from motor vehicles and the other greenhouse gas emissions from large stationary sources such as power plants or industrial facilities. Any decision in this case or any regulatory action by the EPA limiting greenhouse gas emissions from power plants could impact the demand for our coal, which could have an adverse effect on our coal royalties revenues. The permitting of a number of proposed new coal-fired power plants has also recently been contested by environmental organizations for concerns related to greenhouse gas emissions from new plants. For instance, 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.
 11    TABLE OF CONTENTS 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 EPAs Environmental Appeals Board, or EAB, and other judicial forums under the CAA. For example, in June 2008, a Georgia court voided a CAA permit and halted the construction of a coal-fired power plant for failure to address carbon dioxide emissions. Likewise, in November 2008, in another case, In re Deseret Power Electric Cooperative, the EAB remanded the permitting decision back to the Region to reopen the record and reconsider whether carbon dioxide is a
pollutant subject to regulation under the CAA with instructions to consider its nationwide implications. In December 2008, the EPA Administrator issued an interpretive rule determining that the phrase in the CAA not subject to regulation does not include pollutants for which only monitoring and reporting is required. Because carbon dioxide is such a pollutant, this interpretive rule has the effect of precluding any consideration of carbon dioxide emissions in connection with federal permitting under the CAA. Environmental groups filed a Petition for Reconsideration of the interpretive rule. On February 17, 2009, the EPA stated that it would grant the Petition for Reconsideration and allow public comment, but it declined to stay the effectiveness of the interpretive rule at that time. A number of 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, ten northeastern and mid-Atlantic states have agreed to implement a regional cap-and-trade program, referred to as the Regional Greenhouse Gas Initiative, or 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. 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. Auctions for carbon dioxide allowances under the program began in September 2008. Following the RGGI model, seven Western states and four Canadian provinces 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, including fossil-fuel fired power plants, in participating states through trading of emissions credits beginning in 2012. Similarly, in 2007, six Midwestern states and one Canadian province signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions, including developing a market-based,
multi-sector cap. Some states have passed laws individually. For example, 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 25% by 2020 with mandatory caps beginning in 2012 for significant sources. In 2007, New Jersey passed a greenhouse gas reduction that would be economy wide, requiring emissions to drop to 1990 levels by 2020 and that emissions be capped at 80% of 2006 levels by 2050. At the federal level, legislation was introduced in Congress in 2007, 2008 and 2009 to reduce greenhouse gas emissions in the United States. Such or similar federal legislation, which generally seeks to place an economy-wide cap on emissions of greenhouse gases and would require most sources of greenhouse gas emissions to obtain greenhouse gas emission allowances corresponding to their annual emissions of greenhouse gases, could be taken up in 2010 or later years. It is possible that future federal and state initiatives to control and put a price on carbon dioxide emissions, or otherwise regulate greenhouse gas 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 our lessees coal sales, and thereby have an adverse effect on our coal royalties revenues. Surface Mining Control and Reclamation Act of 1977.  The Surface Mining Control and Reclamation Act of 1977, or SMCRA, and similar state statutes establish 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
 12    TABLE OF CONTENTS result of mining operations, and requires mine operators to post performance bonds to ensure compliance with any reclamation obligations. Moreover, regulatory authorities may attempt to assign the liabilities of our coal lessees to another entity such as us if any of our lessees are not financially capable of fulfilling those obligations on the theory that we owned or controlled the mine operator in such a way for liability to attach. To our knowledge, no such claims have been asserted against us to date. In conjunction with mining the property, our 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 our lessees ability to produce coal, which could affect our coal royalties revenues. Hazardous Materials and Wastes.  The Federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, or the Superfund 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. We could become liable under federal and state Superfund and waste management statutes if our 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 Act.  Our coal lessees operations are regulated under the Clean Water Act, or the CWA, with respect to discharges of pollutants, including dredged or fill material into waters of the United States. Individual or general permits under Section 404 of the CWA are required to conduct dredge or fill activities in jurisdictional 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 our 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 in Rapanos v. United States, the EPA and the U.S. Army Corps of Engineers, or the Corps, issued joint
 13    TABLE OF CONTENTS 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. 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 in Ohio Valley Environmental Coalition v. Bulen enjoined the Huntington District of the Corps from issuing further permits pursuant to Nationwide Permit 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 the 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 Corps. In the event similar lawsuits prove to be successful in adjoining jurisdictions, our lessees may be required to apply for individual discharge permits pursuant to Section 404 of the CWA in areas where they would have otherwise utilized Nationwide Permit 21. Such a change could result in delays in our lessees obtaining the required mining permits to conduct their operations, which could in turn have an adverse effect on our coal royalties revenues. Individual CWA Section 404 permits for valley fills associated with surface mining activities are also subject to certain legal challenges and uncertainty. On September 22, 2005, in the case Ohio 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 ours that operates the Republic No. 2 Mine in Kanawha County, West Virginia, intervened as a
defendant in this litigation when the plaintiffs amended their complaint to add the December 22, 2005 individual CWA Section 404 permit for 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 the OVEC 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. The Corps, Alex Energy, other impacted mining companies and mining associations appealed the March 23, 2007 ruling to the U.S. Court of Appeals for the Fourth Circuit. On February 13, 2009, the Fourth Circuit reversed and vacated the District Courts March 23, 2007 opinion and order that had rescinded the challenged permits and vacated the District Courts injunction of activity under those permits and reversed a related order by the District Court that would have required yet additional permits under the CWA. One of the three judges dissented in part from this decision and would have upheld the decision rescinding the permits and enjoining
future activity but agreed with the other two judges on the other parts of the decision. This decision may be subject to further appellate review including by the Fourth Circuit itself. We are unable to predict the outcome of any further appellate review that may be obtained.
 14    TABLE OF CONTENTS 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 the U.S. District Court for the Eastern District of Kentucky, alleging identical violations. The Corps has voluntarily suspended its consideration of the permit application in that case for agency re-evaluation. While the final outcome of these cases remains uncertain, if lawsuits challenging the use of valley fills ultimately limits or prohibits the mining methods or operations of our lessees, it could have an adverse effect on our coal royalties 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 our lessees could adversely impact our coal royalties revenues. In December 2008, the Department of Interior published the Excess Spoil, Coal Mine Waste and Buffers for Perennial and Intermittent Streams rule under SMCRA in part to clarify when valley fills are permitted. The rule would require a 100-foot buffer around all waters, including streams, lakes, ponds and wetlands. However, the rule would exempt certain activities, such as permanent spoil fills and coal waste disposal facilities, and allow mining that changes a waterways flow, providing the mining company repairs damage later. Companies could also receive a permit to dispose of waste within the buffer zone if they explain why an alternative is
not reasonably possible or is not necessary to meet environmental requirements. Environmental groups have brought lawsuits challenging the rule. It is unclear what impact the rule will have on the previously discussed lawsuits related to valley fills or any mining operations undertaken by our lessees in the future. 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 allocations for these stream segments. The adoption of new TMDL-related allocations for streams to which our
lessees coal mining operations discharge could require more costly water treatment and could adversely affect our lessees coal production. The CWA also requires states to develop anti-degradation policies to ensure non-impaired water bodies in the state do not fall below applicable water quality standards. These and other regulatory developments may restrict our lessees ability to develop new mines or could require our lessees to modify existing operations, which could have an adverse effect on our coal business. The Safe Drinking Water Act, or the 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 our 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 our 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 our 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 our lessees ability to mine coal from our properties in accordance with current mining plans. Mine Health and Safety Laws.  The operations of our 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. 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
 15    TABLE OF CONTENTS 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 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. Pursuant to the Miner Act, the Mine Safety Health Administration, or MSHA, has promulgated new emergency rules on mine safety and revised MSHAs civil penalty assessment regulations, which resulted in an across-the-board increase in penalties from the existing regulations. These requirements may
add significant costs to our lessees operations, particularly for underground mines, and could affect the financial performance of our lessees operations. Implementing and complying with these new laws and regulations could adversely affect our lessees coal production and could therefore have an adverse effect on our coal royalties revenues. Mining Permits and Approvals.  Numerous governmental permits or approvals are required for mining operations. In connection with obtaining these permits and approvals, our 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, our 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 our 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, our lessees submit the necessary permit applications between 12 and 24 months before they plan to begin mining a new area. In our experience, permits generally are approved within 12 months after a completed application is submitted. In the past, our lessees have generally obtained their mining permits without significant delay. Our 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. Our 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  Coal and Natural Resource Management Segment  Clean Water Act.
 16    TABLE OF CONTENTS OSHA.  Our lessees and our own business are subject to the Occupational Safety and Health Act, 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 citizens. Natural Gas Midstream Segment General Regulation.  Our natural gas gathering facilities generally are exempt from the Federal Energy Regulatory Commissions, or the FERC, jurisdiction under the Natural Gas Act of 1938, or the NGA, but FERC regulation nevertheless could significantly affect our gathering business and the market for our services. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines into which our 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. 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. Our 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. Our 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 our 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, our 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. Our operations in Oklahoma are regulated by the Oklahoma Corporation Commission, which prohibits us from charging any unduly discriminatory fees for our gathering services. We cannot predict whether our gathering rates will be found to be unjust, unreasonable or unduly discriminatory. We are 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 our right as an owner of gathering facilities to decide with whom we contract 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, or the NGPSA, which requires certain natural gas pipelines to comply with safety standards in constructing and operating the pipelines, and subjects pipelines to regular inspections. We also operate a NGL pipeline that is subject to regulation by the U.S. Department of Transportation under the Hazardous Liquids Pipeline Safety Act of 1979, as amended, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. In response to recent pipeline
accidents, Congress and the U.S. Department of Transportation have instituted heightened pipeline safety requirements. Certain of our gathering facilities are exempt from these federal pipeline safety requirements under the rural gathering exemption. We cannot assure you that the rural gathering exemption
 17    TABLE OF CONTENTS 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.  Our natural gas midstream operations are subject to the CAA and comparable state laws and regulations. See  Coal and Natural Resource Management Segment  Air Emissions. These laws and regulations govern emissions of pollutants into the air resulting from the activities of our processing plants and compressor stations and also impose procedural requirements on how we conduct our natural gas midstream operations. Such laws and regulations may include requirements that we 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 we are required to obtain or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We 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.  Our 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 we own or operate, regardless of whether such disposal or release occurred during or prior to our acquisition of such properties. See  Coal and Natural Resource Management Segment  Hazardous Materials and Wastes. Although petroleum, including natural gas and NGLs are generally excluded from CERCLAs definition of hazardous substance, our natural gas
midstream operations do generate wastes in the course of ordinary operations that may fall within the definition of a CERCLA hazardous substance, or be subject to regulation under state laws. Our natural gas midstream operations generate wastes, including some hazardous wastes, which are subject to 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 we believe 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 our facilities. We currently own or lease numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas and NGLs. Although we believe 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, we 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. We have ongoing remediation projects underway at several sites, but we do not believe that the costs associated with such cleanups will have a material adverse impact on our operations or revenues. Water Discharges.  Our natural gas midstream operations are subject to the CWA. See  Coal and Natural Resource Management Segment  Clean Water Act. Any unpermitted release of pollutants, including NGLs or condensates, from our systems or facilities could result in fines or penalties as well as significant remedial obligations. OSHA.  Our natural gas midstream operations are subject to OSHA. See  Coal and Natural Resource Management Segment  OSHA.
 18    TABLE OF CONTENTS Employees and Labor Relations We do not have employees. To carry out our operations, our general partner and its affiliates employed 167 employees who directly supported our operations at December 31, 2009. Our general partner considers current employee relations to be favorable. Available Information Our internet address is http://www.pvresource.com. We make available free of charge on or through our website our Corporate Governance Principles, Code of Business Conduct and Ethics, Executive and Financial Officer Code of Ethics and Audit Committee Charter, and we will provide copies of such documents to any unitholder 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 Exchange Act as soon as reasonably practicable after we
electronically file such material with, or furnish it to, the Securities and Exchange Commission. All references in this Annual Report on Form 10-K to the NYSE refer to the New York Stock Exchange, and all references to the SEC refer to the Securities and Exchange Commission.
 19    TABLE OF CONTENTS Common Abbreviations and Definitions The following are abbreviations and definitions commonly used in the coal and oil and gas industries that are used in this Annual Report on Form 10-K.  Bbl

          

          a standard barrel of 42 U.S. gallons liquid volumeBcf

          

          one billion cubic feetBcfe

          

          one billion 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 contentBTU

          

          British thermal unitMBbl

          

          one thousand barrelsMbf

          

          one thousand board feetMcf

          

          one thousand cubic feetMcfe

          

          one thousand cubic feet equivalentMMBbl

          

          one million barrelsMMbf

          

          one million board feetMMBtu

          

          one million British thermal unitsMMcf

          

          one million cubic feetMMcfd

          

          one million cubic feet per dayMMcfe

          

          one million cubic feet equivalentNGL

          

          natural gas liquidNYMEX

          

          New York Mercantile ExchangeProbable coal 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 more widely spaced 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 observationProved oil and gas 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 yearsProven coal reserves

          

          those 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
 20    TABLE OF CONTENTS 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 Inherent in an Investment in Us The amount of cash that we will be able to distribute on our common units principally depends upon the amount of cash we generate from our coal and natural resource management and natural gas midstream businesses. Under the terms of our partnership agreement, we must pay our general partners expenses and set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash that we will be able to distribute each quarter to our partners principally depends upon the amount of cash we can generate from our coal and natural resource management and natural gas midstream businesses. The amount of cash we will generate will fluctuate from quarter to quarter based on, among other things: 

          the amount of coal our lessees are able to produce; 

          the price at which our lessees are able to sell the coal; 

          our lessees timely receipt of payment from their customers; 

          our timely receipt of payments from our lessees; 

          the amount of natural gas transported in our gathering systems; 

          the amount of throughput in our processing plants; 

          the price of and demand for natural gas; 

          the price of and demand for NGLs; 

          the relationship between natural gas and NGL prices; 

          the fees we charge and the margins we realize for our natural gas midstream services; and 

          our hedging activities. In addition, the actual amount of cash that we will have available for distribution will depend on other factors including: 

          the level of capital expenditures we make; 

          the cost of acquisitions, if any; 

          our debt service requirements; 

          fluctuations in our working capital needs; 

          restrictions on distributions contained in our debt agreements; 

          prevailing economic conditions; and 

          the amount of cash reserves established by our general partner in its sole discretion for the proper conduct of our business. Because of these factors, we may not have sufficient available cash each quarter to continue paying distributions at their current level or at all. The amount of cash that we have available for distribution depends primarily upon our 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, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record profits.
 21    TABLE OF CONTENTS While we may incur debt to pay distributions to our unitholders, the agreements governing such debt are secured and they may restrict or limit the distributions we can pay to our unitholders. While we are permitted by our partnership agreements to incur debt to pay distributions to our unitholders, our payment of principal and interest on such indebtedness will reduce our cash available for distribution to our unitholders. Furthermore, our debt agreement, which currently consists solely of the revolving credit facility, or Revolver, contains covenants limiting our ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to our partners. The Revolver also contains covenants requiring us not to exceed certain specified financial ratios. We are prohibited from making any distribution to our
partners if such distribution would cause an event of default or otherwise violate a covenant under the Revolver. Additionally, the Revolver is secured by substantially all of our assets, and if we are unable to satisfy our obligations thereunder, the lenders could seek to foreclose on our assets. The lenders may also sell substantially all of our assets under such foreclosure or other realization upon those encumbrances without prior approval of our unitholders, which would adversely affect the price of our common units. See Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations  Liquidity and Capital Resources  Long-Term Debt, for more information about the Revolver. Our unitholders do not elect our general partner or vote on our general partners directors. The owner of our general partner owns a sufficient number of common units to allow it to prevent the removal of our general partner. Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence managements decisions regarding our business. Our unitholders do not have the ability to elect our general partner or the directors of our general partner and will have no right to elect our general partner or the directors of our general partner on an annual or other continuing basis in the future. The board of directors of our general partner, including our independent directors, is chosen by PVG, its sole member. Furthermore, if our public unitholders are
dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Our general partner may not be removed except upon the vote of the holders of at least two-thirds of the outstanding common units. Because PVG owns more than one-third of our outstanding units, our general partner currently cannot be removed without its consent. As a result of these provisions, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price. Our general partner may cause us to issue additional common units or other equity securities without the approval of our unitholders, which would dilute their ownership interests and may increase the risk that we will not have sufficient available cash to maintain or increase our cash distributions. Our general partner may cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval. The issuance of additional common units or other equity securities of equal rank will have the following effects: 

          our unitholders proportionate ownership interest in us will decrease; 

          the amount of cash available for distribution on each common unit may decrease; 

          the relative voting strength of each previously outstanding common unit may be diminished; 

          the ratio of taxable income to distributions may increase; and 

          the market price of our common units may decline. The control of our general partner may be transferred to a third party who could replace our current management team, in either case, without unitholder consent. Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, PVG, the owner of our general partner, may transfer its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner and to control the decisions taken by the board of directors and officers.
 22    TABLE OF CONTENTS Our unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business. Under Delaware law, our unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders as a group to remove or replace our general partner, to approve some amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in the control of our business. Additionally, the limitations on the liability of holders of limited partner interests for the liabilities of a limited partnership have not been clearly established in many jurisdictions. Furthermore, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution. Our partnership agreement restricts the rights of unitholders owning 20% or more of our units. Our unitholders voting rights are restricted by the provision in our partnership agreement generally providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of the general partner, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders ability to
influence the manner or direction of our management. As a result of these provisions, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price. If Penn Virginia sells all or a part of its remaining partner interests in PVG, our strategic and operational objectives may change. In September 2009, Penn Virginia sold approximately one-third of its limited partner interest in PVG, constituting approximately 26% of PVGs common units. Following such sale, Penn Virginia owned the general partner interest in PVG and approximately 51% of PVGs common units. Penn Virginia may sell all or part of its remaining partner interests in PVG without our or PVGs consent or the consent of our or PVGs unitholders. Several of the members of our and PVGs management team, including the Chief Executive Officer and Chief Financial Officer of our general partner and PVGs general partner, are also members of Penn Virginias management team. If Penn Virginia sells all or a significant part of its remaining partner interests in PVG, our general partner and PVGs general partner may replace some or all of those officers with new members of a management team that may have different strategic or operational objectives for us or PVG. A change in strategic or operational objectives could affect our results of operations and cash available for
distribution. Risks Related to Conflicts of Interest Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner has limited fiduciary duties to us and our unitholders, which may permit it to favor its own interests to the detriment of us and our unitholders. Penn Virginia and its affiliates, including PVG, own an approximately 37% limited partner interest in us and own and control our general partner. Conflicts of interest may arise between our general partner and its affiliates (including Penn Virginia and PVG), on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations: 

          Our general partner is allowed to take into account the interests of parties other than us, such as Penn Virginia and PVG, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders. 

          Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available to be distributed to our unitholders.
 23    TABLE OF CONTENTS 

          Our general partner controls the enforcement of obligations owed to us by it and its affiliates. 

          Our general partner determines which costs incurred by it and its affiliates are reimbursable by us. 

          Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf. 

          Our general partner decides whether to retain separate counsel, accountants or others to perform services for us. The fiduciary duties of our general partners officers and directors may conflict with those of PVGs general partner, and our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to us. Our general partners officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our unitholders and the owner of our general partner, PVG. However, three of our general partners eight directors and three of its five officers are also directors or officers of PVGs general partner, which has fiduciary duties to manage the business of PVG in a manner beneficial to PVG and its unitholders, including Penn Virginia. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to us on the one hand, and PVG, on the other hand, are in conflict. The
resolution of these conflicts may not always be in our best interest or that of our unitholders. In addition, our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute a breach of our general partners fiduciary duties owed to unitholders. By purchasing our units, our unitholders are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law. We may face conflicts of interest in the allocation of administrative time among Penn Virginias business, PVGs business and our business. Our general partner shares administrative personnel with Penn Virginia and PVGs general partner to operate Penn Virginias business, PVGs business and our business. Our general partners officers, who are also the officers of PVGs general partner and/or Penn Virginia, will have responsibility for overseeing the allocation of time spent by administrative personnel on our behalf and on behalf of PVG and/or Penn Virginia. These officers face conflicts regarding these time allocations that may adversely affect our results of operations, cash flows and financial condition. It is unlikely that these allocations will be the
result of arms-length negotiations among Penn Virginia, PVGs general partner and our general partner. Our general partner has a call right that may require our unitholders to sell their common units at an undesirable time or price. If at any time more than 80% of our outstanding common units are owned by our general partner and its affiliates, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or us, but not the obligation, to acquire all, but not less than all, of the remaining units held by unaffiliated persons at a price equal to the greater of (i) the average of the daily closing prices of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest price paid by our general partner or any of its affiliates for common units
during the 90-day period preceding the date such notice is first mailed. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his or her units in the market. Affiliates of our general partner currently own approximately 37% of our outstanding common units.
 24    TABLE OF CONTENTS Risks Related to Our Coal and Natural Resource Management Business If our lessees do not manage their operations well or experience financial difficulties, their production volumes and our coal royalties revenues could decrease. We depend on our lessees to effectively manage their operations on our properties. Our lessees make their own business decisions with respect to their operations, including decisions relating to: 

          the method of mining; 

          credit review of their customers; 

          marketing of the coal mined; 

          coal transportation arrangements; 

          negotiations with unions; 

          employee hiring and firing; 

          employee wages, benefits and other compensation; 

          permitting; 

          surety bonding; and 

          mine closure and reclamation. If our lessees do not manage their operations well, or if they experience financial difficulties, their production could be reduced, which would result in lower coal royalties revenues to us and could have a material adverse effect on our business, results of operations or financial condition. The coal mining operations of our lessees are subject to numerous operational risks that could result in lower coal royalties revenues. Our coal royalties revenues are largely dependent on the level of production from our coal reserves achieved by our lessees. The level of our lessees production is subject to operating conditions or events that may increase our lessees cost of mining and delay or halt production at particular mines for varying lengths of time and that are beyond their or our control, including: 

          the inability to acquire necessary permits; 

          changes or variations in geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit; 

          changes in governmental regulation of the coal industry; 

          mining and processing equipment failures and unexpected maintenance problems; 

          adverse claims to title or existing defects of title; 

          interruptions due to power outages; 

          adverse weather and natural disasters, such as heavy rains and flooding; 

          labor-related interruptions; 

          employee injuries or fatalities; and 

          fires and explosions. Any interruptions to the production of coal from our reserves could reduce our coal royalties revenues and could have a material adverse effect on our business, results of operations or financial condition. In addition, our coal royalties revenues are based upon sales of coal by our lessees to their customers. If our 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 our cash flow to be adversely affected and could have a material adverse effect on our business, results of operations or financial condition.
 25    TABLE OF CONTENTS A substantial or extended decline in coal prices could reduce our coal royalties revenues and the value of our coal reserves. A substantial or extended decline in coal prices from recent levels could have a material adverse effect on our lessees operations (including mine closures) and on the quantities of coal that may be economically produced from our properties. In addition, because a majority of our coal royalties are derived from coal mined on our properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price, our coal royalties revenues could be reduced by such a decline. Such a decline could also reduce our coal services revenues and the value of our coal reserves. Additionally, volatility in
coal prices could make it difficult to estimate with precision the value of our coal reserves and any coal reserves that we may consider for acquisition. The future state of the global economy, including financial and credit markets on coal production levels and prices is uncertain. Depending on the longevity and ultimate severity of this downturn, demand for coal may decline, which could adversely effect production and pricing for coal mined by our lessees, and, consequently, adversely effect the royalty income received by us. We depend on a limited number of primary operators for a significant portion of our coal royalties revenues and the loss of or reduction in production from any of our major lessees would reduce our coal royalties revenues. We depend on a limited number of primary operators for a significant portion of our coal royalties revenues. In the year ended December 31, 2009, five primary operators, each with multiple leases, accounted for 61% of our coal royalties revenues and 11% of our total consolidated revenues. If any of these operators enters bankruptcy or decides to cease operations or significantly reduces its production, our coal royalties revenues would be reduced. A failure on the part of our lessees to make coal royalty payments could give us the right to terminate the lease, repossess the property or obtain liquidation damages and/or enforce payment obligations under the lease. If we repossessed any of our properties, we would seek to find a replacement lessee. We may not be able to find a replacement lessee and, if we find a replacement lessee, we 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 we enter 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 us 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. Our coal business will be adversely affected if we are unable to replace or increase our coal reserves through acquisitions. Because our reserves decline as our lessees mine our coal, our future success and growth depends, in part, upon our ability to acquire additional coal reserves that are economically recoverable. The current state of the global economy, including financial markets, and the consequential adverse effect on credit availability is adversely impacting our access to new capital and credit availability. Depending on the longevity and ultimate severity of this downturn, our ability to make acquisitions may be significantly adversely affected. If we are unable to negotiate purchase contracts to replace or increase our coal reserves on acceptable terms, our
coal royalties revenues will decline as our coal reserves are depleted and we could, therefore, experience a material adverse effect on our business, results of operations or financial condition. If we are able to acquire additional coal reserves, there is a possibility that any acquisition could be dilutive to earnings and reduce our ability to make distributions to unitholders or to pay interest on, or the principal of, our debt obligations. Any debt we incur to finance an acquisition may similarly affect our ability to make distributions to unitholders or to pay interest on, or the principal of, our debt obligations. Our ability to make acquisitions in the future also could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.
 26    TABLE OF CONTENTS Our lessees could satisfy obligations to their customers with coal from properties other than ours, depriving us of the ability to receive amounts in excess of the minimum coal royalties payments. We do not control our lessees business operations. Our lessees customer supply contracts do not generally require our lessees to satisfy their obligations to their customers with coal mined from our reserves. Several factors may influence a lessees decision to supply its customers with coal mined from properties we do not own or lease, including the royalty rates under the lessees lease with us, mining conditions, transportation costs and availability and customer coal quality specifications. If a lessee satisfies its obligations to its customers with coal from properties we do not own or lease, production under our lease will
decrease, and we will receive lower coal royalties revenues. Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal mined from our properties. Transportation costs represent a significant portion of the total cost of coal for the customers of our lessees. Increases in transportation costs could make coal a less competitive source of energy or could make coal produced by some or all of our lessees less competitive than coal produced from other sources. On the other hand, significant decreases in transportation costs could result in increased competition for our lessees from coal producers in other parts of the country or increased imports from offshore producers. Our 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 our lessees to supply coal to their customers. Our lessees transportation providers may face difficulties in the future and impair the ability of our lessees to supply coal to their customers, thereby resulting in decreased coal royalties revenues to us. Our lessees workforces could become increasingly unionized in the future, which could adversely affect their productivity and thereby reduce our coal royalties revenues. One of our lessees has one mine operated by unionized employees. This mine was our third largest mine on the basis of coal production for the year ended December 31, 2009. All of our lessees could become increasingly unionized in the future. If some or all of our lessees non-unionized operations were to become unionized, it could adversely affect their productivity and increase the risk of work stoppages. In addition, our lessees operations may be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our lessees operations. Any further unionization of our
lessees employees could adversely affect the stability of production from our coal reserves and reduce our coal royalties revenues. Our coal reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of our coal reserves. Our estimates of our coal reserves may vary substantially from the actual amounts of coal our lessees may be able to economically recover. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our 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: 

          geological and mining conditions, which may not be fully identified by available exploration data; 

          the amount of ultimately recoverable coal in the ground; 

          the effects of regulation by governmental agencies; and 

          future coal prices, operating costs, capital expenditures, severance and excise taxes and development and reclamation costs. Actual production, revenues and expenditures with respect to our 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 us.
 27    TABLE OF CONTENTS Any change in fuel consumption patterns by electric power generators away from the use of coal could affect the ability of our lessees to sell the coal they produce and thereby reduce our coal royalties revenues. According to the U.S. Department of Energy, domestic electric power generation accounted for approximately 89% of domestic coal consumption in 2008. 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. We believe 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 CAA 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  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 our lessees to sell the coal they produce and thereby reduce our coal royalties 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 our 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. 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 our lessees produce and thereby reducing our coal royalties revenues. See Item 1, Business  Government Regulation and Environmental Matters  Coal and Natural Resource Management Segment  Air Emissions. Concerns about the environmental impacts of fossil-fuel emissions, including perceived impacts on global climate change, are resulting in increased regulation of emissions of greenhouse gases in many jurisdictions and increased interest in and the likelihood of further regulation, which could significantly affect our coal royalties revenues. Global climate change continues to attract considerable public and scientific attention. Several widely publicized scientific reports have engendered widespread concern about the impacts of human activity, especially fossil fuel combustion, on global climate change. Legislative attention in the United States is being paid to global climate change and to reducing greenhouse gas emissions, particularly from coal combustion by power plants. Such legislation was introduced in Congress in the last several years to reduce greenhouse gas emissions in the United States and further proposals or amendments are likely to be offered in the future. In
anticipation of EPAs endangerment finding regarding greenhouse gas emissions (which was finalized in December 2009), the agency proposed two sets of rules regarding possible future regulation of greenhouse gas emissions under the CAA. While the first proposes to regulate greenhouse gas emissions from motor vehicles, the other targets greenhouse gas emissions from large stationary sources such as power plants or industrial facilities. 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 power plants. See Item 1, Business  Governmental Regulation and Environmental Matters  Coal and Natural Resource Management Segment  Air Emissions. Enactment of laws, passage of regulations regarding greenhouse gas emissions by the United
States or some of its states, or other actions to limit carbon dioxide emissions could result in electric generators switching from coal to other fuel sources. This may adversely affect the use of and demand for fossil fuels, particularly coal. Delays in our lessees obtaining mining permits and approvals, or the inability to obtain required permits and approvals, could have an adverse effect on our coal royalties revenues. Mine operators, including our lessees, must obtain numerous permits and approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal
 28    TABLE OF CONTENTS 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 our lessees to conduct operations may not be issued, maintained or renewed, may not be issued or renewed in a timely fashion, or may involve requirements that restrict our lessees ability to economically conduct their mining operations. Limitations on our 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 our coal royalties revenues. See Item 1, Business  Government Regulation and Environmental Matters  Coal and Natural Resource Management Segment  Mining Permits and Approvals. Uncertainty over the precise parameters of the CWAs regulatory scope and a recent federal district court decision may adversely impact our 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, our lessees often need to obtain government approvals, including CWA Section 404 permits to construct valley fills and sediment control ponds. Ongoing uncertainty over which waters are subject to the CWA may adversely impact our lessees ability to secure these necessary permits. In addition, a 2007 decision by a U.S. District Court in West Virginia invalidated a permit issued to one of our lessees for the Republic No. 2 Mine and enjoined our lessee, Alex Energy, Inc., from taking any further actions under this permit. This ruling was appealed and the appellate court
reversed and vacated the district courts order. It is unclear if this ruling will be appealed or if the permits will be challenged on other grounds. 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 that could ultimately have an adverse effect on our coal royalties revenues. See Item 1, Business  Government Regulation and Environmental Matters  Coal and Natural Resource Management Segment  Clean Water Act, for more information about the litigation described above. Our lessees mining operations are subject to extensive and costly laws and regulations, which could increase operating costs and limit our lessees ability to produce coal, which could have an adverse effect on our coal royalties revenues. Our 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. Our 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 our lessees mining operations, either through direct impacts such as new requirements impacting our 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 our coal royalties revenues. See Item 1, Business  Government Regulation and
Environmental Matters  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, we do not believe violations by our 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. Our lessees may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from their
operations. If our lessees are required to pay these costs and liabilities and if their financial viability is
 29    TABLE OF CONTENTS affected by doing so, then their mining operations and, as a result, our coal royalties revenues and our ability to make distributions, could be adversely affected. Risks Related to Our Natural Gas Midstream Business The success of our natural gas midstream business depends upon our ability to find and contract for new sources of natural gas supply. In order to maintain or increase system throughput levels on our gathering systems and asset utilization rates at our processing plants, we must contract for new natural gas supplies. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include the level of drilling activity creating new gas supply near our gathering systems, our success in contracting for existing natural gas supplies that are not committed to other systems and our ability to expand and increase the capacity of our systems. We 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. We have no control over the level of drilling activity in our areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, we have 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. Our natural gas midstream assets, including our gathering systems and processing plants, are connected to natural gas reserves and wells for which the production will naturally decline over time. Our cash flows associated with these systems will decline unless we are able to secure new supplies of natural gas by connecting additional production to these systems. A material decrease in natural gas production in our areas of operation, as a result of depressed commodity prices or otherwise, would result in a decline in the volume of natural gas we handle, which would reduce our revenues and operating income. In addition, our future growth will depend,
in part, upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our currently connected supplies. We typically do not obtain independent evaluations of natural gas reserves dedicated to our gathering systems; therefore, volumes of natural gas on our systems in the future could be less than we anticipate. We typically do not obtain independent evaluations of natural gas reserves connected to our gathering systems due to the unwillingness of producers to provide reserve information, as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves dedicated to our gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas gathered on our gathering systems in the future could be less than we
anticipate. A decline in the volumes of natural gas on our systems could have a material adverse effect on our business, results of operations or financial condition. A reduction in demand for NGL products by the petrochemical, refining or heating industries could materially adversely affect our business, results of operations and financial condition. The NGL products we produce, including ethane, propane, normal butane, isobutane and natural gasoline, have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general economic conditions, new government regulations, reduced demand by consumers for products made with NGL products, increased competition from petroleum-based products due to pricing differences, mild winter weather or other reasons, could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services. Any reduced demand for our NGL
products could adversely affect demand for the services we provide as well as NGL prices, which would negatively impact our results of operations and financial condition.
 30    TABLE OF CONTENTS The profitability of our natural gas midstream business is dependent upon prices and market demand for natural gas and NGLs, which are beyond our control and have been volatile. We are subject to significant risks due to fluctuations in natural gas commodity prices. During 2009, we generated a majority of our gross margin from two types of contractual arrangements under which our margin is exposed to increases and decreases in the price of natural gas and NGLs  gas purchase/keep-whole and percentage-of-proceeds arrangements. See Item 1, Business  Contracts  Natural Gas Midstream Segment. Virtually all of the system throughput volumes in our Crescent System and Hamlin System are processed under percentage-of-proceeds arrangements. The system throughput volumes in our Panhandle System are processed primarily under either percentage-of proceeds or gas purchase/keep-whole arrangements. Under both types of arrangements, we provide gathering and processing services for natural gas received. Under percentage-of-proceeds arrangements, we generally sell the NGLs produced from the processing operations and the remaining residue gas at market prices and remit to the producers an agreed upon percentage of the proceeds based on either an index
price or the price actually received for the gas and NGLs. Under these 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 our business, results of operations or financial condition. Under gas purchase/keep-whole arrangements, we generally buy natural gas from producers based upon an index price and then sell 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 our business, results of operations or financial condition. In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. The markets and prices for residue gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuates with changes in market and economic conditions, and other factors, including: 

          the state of the global economy, including financial and credit markets on worldwide demand for oil and domestic demand for natural gas and NGLs; 

          the impact of weather on the demand for oil and natural gas; 

          the level of domestic oil and natural gas production; 

          the availability of imported oil and natural gas; 

          actions taken by foreign oil and gas producing nations; 

          the availability of local, intrastate and interstate transportation systems; 

          the availability and marketing of competitive fuels; 

          the impact of energy conservation efforts; and 

          the extent of governmental regulation and taxation. Acquisitions and expansions may affect our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing the risks of being unable to effectively integrate these new operations. From time to time, we evaluate and acquire assets and businesses that we believe complement our existing operations. Readily available access to debt and equity capital and credit availability has been and continues to be critical factors in our ability to grow. The current state of the global economy, including financial markets, and the consequential adverse effect on credit availability is adversely impacting our access to new capital and credit availability. Depending on the longevity and ultimate severity of this downturn, our ability to make acquisitions may be significantly adversely affected. In the event we complete acquisitions, we
 31    TABLE OF CONTENTS may encounter difficulties integrating these acquisitions with our 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, we may not be able to realize the operating efficiencies, competitive advantages, cost savings or other benefits expected from these acquisitions. Future acquisitions might not generate increases in our cash distributions to our unitholders, and because of the capital used to complete such acquisitions, or the debt incurred, our results of operations may change significantly. Expanding our natural gas midstream business by constructing new gathering systems, pipelines and processing facilities subjects us to construction risks. One of the ways we may grow our 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 our control and require the expenditure of significant amounts of capital. Our access to such capital is currently adversely impacted by the state of the global economy, including financial and credit markets. If we do
undertake these projects, they may not be completed on schedule, or at all, or at the anticipated cost. Moreover, our 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 our estimates. Generally, we may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, we 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 our expected investment return, which could have a material adverse effect on our business, results of operations or financial condition. If we are unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then we may be unable to fully execute our growth strategy and our cash flows could be reduced. The construction of additions to our existing gathering assets may require us to obtain new rights-of-way before constructing new pipelines. We may be unable to obtain rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us 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 our cash flows could be reduced. We are exposed to the credit risk of our natural gas midstream customers, and nonpayment or nonperformance by our customers would reduce our cash flows. We are subject to risk of loss resulting from nonpayment or nonperformance by our natural gas midstream customers. We depend on a limited number of customers for a significant portion of our natural gas midstream revenues. In 2009, 21%, 15% and 10% of our natural gas midstream segment revenues and 17%, 11% and 8% of our total consolidated revenues resulted from three of our natural gas midstream customers, Conoco, Inc., Tenaska Marketing Ventures and ONEOK Energy Marketing. Any nonpayment or nonperformance by our natural gas midstream segment customers would reduce our cash flows. Any reduction in the capacity of, or the allocations to, us in interconnecting third-party pipelines could cause a reduction of volumes processed, which could adversely affect our revenues and cash flows. We are 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 our natural gas midstream facilities. Similarly, if additional shippers begin transporting volumes of residue gas and NGLs on interconnecting pipelines, our allocations in these pipelines could be reduced. Any reduction in volumes gathered and processed in our facilities could adversely affect our revenues and cash flows. Natural gas derivative transactions may limit our potential gains and involve other risks. In order to manage our exposure to price risks in the marketing of our natural gas and NGLs, we periodically enter into condensate, natural gas and NGL price hedging arrangements with respect to a portion
 32    TABLE OF CONTENTS of our expected production. Our hedges are limited in duration, usually for periods of two years or less. However, in connection with acquisitions, sometimes our hedges are for longer periods. These hedging transactions may limit our potential gains if natural gas or NGL prices were to rise (or decline with respect to natural gas hedges entered into to lock the frac spread) over the price established by the hedging arrangements. Moreover, we have entered into derivative transactions related to only a portion of our condensate, natural gas and NGL volumes. As a result, we will continue to have direct commodity price risk with respect to the unhedged
portion of these volumes. In trying to maintain an appropriate balance, we may end up hedging too much or too little, depending upon how natural gas or NGL prices fluctuate in the future. In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which: 

          our production is less than expected; 

          there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; 

          the counterparties to our futures contracts fail to perform under the contracts; or 

          a sudden, unexpected event materially impacts natural gas or NGL prices. In addition, derivative instruments involve basis risk. Basis risk in a derivative 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. The accounting standards regarding hedge accounting are complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our Consolidated Financial Statements may reflect volatility due to these derivatives, even when there is no underlying economic impact at that point. In addition, it is not always possible for us to engage in a derivative transaction that completely mitigates our exposure to commodity prices. Our Consolidated Financial Statements may reflect a gain or loss arising from an exposure to commodity prices for which we are
unable to enter into a completely effective hedge transaction. Our natural gas midstream business involves many hazards and operational risks, some of which may not be fully covered by insurance. Our 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: 

          damage to pipelines, related equipment and surrounding properties caused by hurricanes, tornadoes, floods and other natural disasters and acts of terrorism; 

          inadvertent damage from construction and farm equipment; 

          leaks of natural gas, NGLs and other hydrocarbons; and 

          fires and explosions. 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 our related operations. Our 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 our business, results of operations or financial condition. We are not fully insured against all risks incident to our natural gas midstream business. We do not have property insurance on all of our underground pipeline
systems that would cover damage to the pipelines. We are 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 our business, results of operations or financial condition.
 33    TABLE OF CONTENTS Federal, state or local regulatory measures could adversely affect our natural gas midstream business. We own and operate an 11-mile interstate natural gas pipeline that, pursuant to the NGA, is subject to the jurisdiction of the FERC. The FERC has granted us 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 we will have to comply with the filing requirements if our natural gas midstream segment 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. Our 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 our gathering business and the market for our services. For a more detailed discussion of how regulatory measures affect our natural gas gathering business, see Item 1, Business  Government Regulation and Environmental Matters  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. Our natural gas midstream business is subject to extensive environmental regulation. Many of the operations and activities of our 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 our facilities and the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or the prior owners of our natural gas midstream business or locations to which we or they have sent wastes for disposal. These laws and regulations can restrict or impact our business activities in many
ways, including restricting the manner in which we dispose 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 our natural gas midstream business due to our handling of natural gas and other petroleum products, air emissions related to our natural gas midstream operations, historical industry operations, waste disposal practices and the use by the prior owners of our natural gas midstream business of natural gas flow meters containing mercury. For example, an accidental release from one of our pipelines or processing facilities could subject us 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 our compliance costs and the cost of any remediation that may become necessary. We 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  Natural Gas Midstream Segment. The natural gas midstream segment may record impairment losses on its long-lived assets. The natural gas midstream segment has completed a number of acquisitions in recent years, including the North Texas System (Lone Star Gathering, L.P., or Lone Star). See Note 3 to the Consolidated Financial Statements for a description of our natural gas midstream segments material acquisitions. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the
 34    TABLE OF CONTENTS ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, and the resulting amount of goodwill, if any. Unforeseen changes in operations, the business environment or market conditions could substantially alter managements assumptions and could result in lower estimates of values of acquired assets or of future cash flows. This could result in impairment charges being recorded in our Consolidated Statements of Income. Tax Risks to Our Common Unitholders Our tax treatment depends on our status as a partnership for federal income tax purposes as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced. The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or IRS, on this or any other matter affecting us. Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, if our view is incorrect, or if there is a change in our business (or a change in current law), we could be treated as a corporation for federal income tax purposes or otherwise subject to taxation as an entity. If we were treated as a corporation for federal income tax purposes for any taxable year for which the statute of limitations remains open or for any future taxable year, we would pay federal income tax on our taxable income for such years at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders
would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in our anticipated cash flow and likely cause a substantial reduction in the value of our common units. Moreover, treatment of us as a corporation would materially and adversely affect our ability to make payments on our debt. The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis. Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. Specifically, the present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, at the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner
that does apply to us. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we are subject to an entity-level tax on the portion of our income that is generated in Texas. Specifically, the Texas margin tax is imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of such a tax on us by Texas and other states will reduce the cash available for distribution to our unitholders. Our partnership agreement provides
that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to
 35    TABLE OF CONTENTS taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us. If the IRS contests the federal income tax positions that we take, it may adversely affect the market for our common units, and the costs of any contest will reduce cash available for distribution to our unitholders. We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter that affects us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may disagree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest between us and the IRS will result in a reduction in cash available for
distribution to our unitholders and thus will be borne indirectly by our unitholders. Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us. Because our unitholders are treated as partners to whom we allocate taxable income which could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability that results from the taxation of their share of our taxable income. Tax gain or loss on disposition of our common units could be more or less than expected. If a unitholder sells his or her common units, he or she will recognize a gain or loss equal to the difference between the amount realized and the adjusted tax basis in those common units. Prior distributions to such unitholder in excess of the total net taxable income allocated to him or her, which decreased his or her tax basis in his or her common units, will, in effect, become taxable income to such unitholder if the common units are sold at a price greater than such unitholders tax basis in those common units, even if the price he or she receives is less than that unitholders original cost. A substantial portion of the amount
realized, whether or not representing gain, may be taxed as ordinary income to the unitholder due to recapture items, including depreciation recapture. In addition, if a unitholder sells his or her common units, he or she may incur a tax liability in excess of the amount of cash such unitholder received from the sale because the amount realized from the sale includes a unitholders share of our nonrecourse liabilities. Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them. Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, a significant amount of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our
taxable income. Tax-exempt entities and non-U.S. persons should consult their tax advisor before investing in our common units. We are registered as a tax shelter. This may increase the risk of an IRS audit of us or a unitholder. We are registered with the IRS as a tax shelter. Our tax shelter registration number is 01309000001. The IRS requires that some types of entities, including some partnerships, register as tax shelters in response to the perception that they claim tax benefits that the IRS may believe to be unwarranted. As a result, we may be audited by the IRS and tax adjustments could be made. Any unitholder owning less than a 1% profits interest in us has very limited rights to participate in the income tax audit process. Further, any
 36    TABLE OF CONTENTS adjustments in our tax returns will lead to adjustments in our unitholders tax returns and may lead to audits of unitholders tax returns and adjustments of items unrelated to us. A unitholder will bear the cost of any expense incurred in connection with an examination of his or her personal tax return. We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units. Due to a number of factors, including our inability to match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholders sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders tax returns. We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders. We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and if the IRS were to challenge this method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor
pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Although existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. A unitholder whose common units are loaned to a short seller to cover a short sale of common units may be considered as having disposed of those common units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition. Because a unitholder whose common units are loaned to a short seller to cover a short sale of units may be considered as having disposed of the loaned common units, such unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common
units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units. We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units. When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourself using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. Our methodology may be viewed as understating the
 37    TABLE OF CONTENTS value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our
general partner and certain of our unitholders. A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders tax returns without the benefit of additional deductions. The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the technical termination of our partnership for federal income tax purposes. We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A sale or exchange would occur, for example, if we sold our business or merged with another company, or if any of our unitholders, including Penn Virginia, PVG or any of their affiliates, sold or transferred their partner interests in us. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result
in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination would not effect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical
termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Our unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units. In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. It is the
responsibility of our unitholders to file all U.S. federal, state and local tax returns that may be required of each of them. Item 1B Unresolved Staff Comments We have received no written SEC staff comments regarding our periodic or current reports under the Exchange Act which were issued 180 days or more preceding the end of our 2009 fiscal year that remain unresolved.
 38    TABLE OF CONTENTS Item 2 Properties Title to Properties The following map shows the general locations of our coal reserves and related infrastructure investments and our natural gas gathering and processing systems as of December 31, 2009: [GRAPHIC MISSING] We believe that we have satisfactory title to all of our properties and the associated coal reserves in accordance with standards generally accepted in the coal and natural resource management and natural gas midstream industries. Facilities We currently lease our office space in Radnor, Pennsylvania, Dallas and Houston, Texas as well as Kingsport, Tennessee. We own the field office in Charleston, West Virginia. We believe that our properties are adequate for our current needs. Coal Reserves and Production As of December 31, 2009, we owned or controlled approximately 829 million tons of proven and probable coal reserves located on approximately 497,000 acres (including fee and leased acreage) in Illinois, Kentucky, New Mexico, Virginia and West Virginia. Our coal reserves are in various surface and underground mine seams located on the following properties: 

          Central Appalachia Basin: properties located in eastern Kentucky, southwestern Virginia and southern West Virginia; 

          Northern Appalachia Basin: properties located in northern West Virginia; 

          Illinois Basin: properties located in southern Illinois and western Kentucky; and 

          San Juan Basin: properties located in the four corners area of New Mexico. 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 our coal reserves are classified as proven and probable reserves. Proven and probable coal reserves are defined as follows:
 39    TABLE OF CONTENTS Proven Coal Reserves.  Proven coal reserves are 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.  Probable coal reserves are 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 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, we perform 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 our coal reserves are high in energy content, low in sulfur and suitable for either the steam or to a lesser extent 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. Our lessees mine coal using both underground and surface methods. As of December 31, 2009, our lessees operated 34 surface mines and 41 underground mines. Approximately 52% of the coal produced from our properties in 2009 came from underground mines and 48% came from surface mines. Most of our lessees use the continuous mining method in their underground mines located on our properties. In continuous mining, main airways and transportation entries are developed and remote-controlled continuous miners extract coal from rooms, leaving pillars to support the roof. Shuttle cars transport coal to a conveyor belt for transportation
to the surface. In several underground mines, our lessees use two continuous miners running at the same time, also known as a supersection, to improve productivity and reduce unit costs. One of our lessees uses the longwall mining method at two different mines to mine underground reserves. Longwall mining uses hydraulic jacks or shields, varying from four feet to twelve feet in height, to support the roof of the mine while a mobile cutting shearer advances through the coal. Chain conveyors then move the coal to a standard deep mine conveyor belt system for delivery to the surface. Continuous mining is used to develop access to long rectangular panels of coal that are mined with longwall equipment, allowing controlled caving behind the advancing machinery. Longwall mining is typically highly productive when used for large blocks of
medium to thick coal seams. Surface mining methods used by our lessees include auger and highwall mining to enhance production, improve reserve recovery and reduce unit costs. On our San Juan Basin property, a combination of the dragline and truck-and-shovel surface mining methods is used to mine the coal. Dragline and truck-and-shovel mining uses large capacity machines to remove overburden to expose the coal seams. Wheel loaders then load the coal in haul trucks for transportation to a loading facility. Our lessees customers are primarily electric utilities, also referred to as steam markets. Coal produced from our properties is transported by rail, barge and truck, or a combination of these means of transportation. Coal from the Virginia portion of the Wise property and the Buchanan property is primarily shipped to electric utilities in the Southeast by the Norfolk Southern railroad. Coal from the Kentucky portion of the Wise property is primarily shipped to electric utilities in the Southeast by the CSX railroad. Coal from the Coal River and Spruce Laurel properties in West Virginia is shipped to steam and metallurgical customers
by the CSX railroad, by barge along the Kanawha River and by truck or by a combination thereof. Coal from the Northern Appalachia properties is shipped by barge on the Monongahela River, by truck and by the CSX and Norfolk Southern railroads. Coal from the Illinois Basin properties is shipped by barge on the Green River
 40    TABLE OF CONTENTS and by truck. Coal from the San Juan Basin property is shipped to steam markets in New Mexico and Arizona by the Burlington Northern Santa Fe railroad. All of our properties contain and have access to numerous roads and state or interstate highways. The following table shows our most important coal producing seams by property at December 31, 2009:  Area

          

          Property

          

          State

          

          Producing Mine Types

          

          Seam Name

          

          Height Range (ft.)Central Appalachia

          

          Wise

          

          VA, KY

          

          Surface, Underground

          

          Parsons

          

          1.00  6.00Phillips

          

          1.50  6.00Low Splint

          

          1.00  5.50Taggart/Marker

          

          1.50  9.00U. Wilson

          

          1.50  5.50Kelly/Imboden

          

          1.00  7.50Buchanan

          

          VA

          

          Underground

          

          Hagy

          

          2.50  3.50Wayland

          

          KY

          

          Underground

          

          U. Elkhorn No. 2

          

          2.33  4.00Coal River, Fields Creek

          

          WV

          

          Surface, Underground

          

          Coalburg

          

          1.00  11.00Winifrede

          

          1.00  6.50Cedar Grove

          

          1.00  5.50No. 2 Gas

          

          1.50  8.00Alloy

          

          WV

          

          Underground

          

          Powellton

          

          2.50  4.50Coal River, Cabin Creek

          

          WV

          

          Surface

          

          Coalburg

          

          1.00  5.00Buffalo Creek

          

          1.00  5.50Winifrede

          

          1.00  10.00Coal River, West Coal River

          

          WV

          

          Surface, Underground

          

          Stockton

          

          4.00  12.00No. 2 Gas

          

          2.50  4.00Huff Creek/Toney Fork

          

          WV

          

          Surface

          

          Coalburg

          

          5.00  16.00Underground

          

          Chilton

          

          3.00  4.00Underground

          

          U. Alma

          

          3.00  4.00Powell Mountain

          

          VA, KY

          

          Surface, Underground

          

          Splint Seams

          

          2.00  2.75Underground

          

          Darby

          

          2.50  3.00Northern Appalachia

          

          Federal No 2

          

          WV

          

          Underground

          

          Pittsburgh

          

          6.50  9.50Upshur

          

          

          

          Surface

          

          Pittsburgh

          

          3.00  6.50Illinois Basin

          

          Green River

          

          KY

          

          Surface, Underground

          

          KY No. 9

          

          3.00  5.00Allied

          

          KY

          

          Underground

          

          KY No. 9

          

          3.00  5.00San Juan Basin

          

          Lee Ranch

          

          NM

          

          Surface

          

          Cleary Seams

          

          8.00  16.00
 The following tables set forth production data for the periods presented and reserve information with respect to each of our properties for the period presented (tons in millions):  Production for Year Ended December 31,Property

          

          2009

          

          2008

          

          2007Central Appalachia

          

          

          18.3

          

          

          

          19.6

          

          

          

          18.8Northern Appalachia

          

          

          3.8

          

          

          

          3.6

          

          

          

          4.2Illinois Basin

          

          

          4.7

          

          

          

          4.6

          

          

          

          3.8San Juan Basin

          

          

          7.5

          

          

          

          5.9

          

          

          

          5.7Total

          

          

          34.3

          

          

          

          33.7

          

          

          

          32.5
  Proven and Probable Reserves as of December 31, 2009Property

          

          Underground

          

          Surface

          

          Total

          

          Steam

          

          Metallurgical

          

          TotalCentral Appalachia

          

          

          443.6

          

          

          

          160.3

          

          

          

          603.9

          

          

          

          514.7

          

          

          

          89.2

          

          

          

          603.9Northern Appalachia

          

          

          23.4

          

          

          

          

          

          

          

          23.4

          

          

          

          23.4

          

          

          

          

          

          

          

          23.4Illinois Basin

          

          

          154.2

          

          

          

          9.7

          

          

          

          163.9

          

          

          

          163.9

          

          

          

          

          

          

          

          163.9San Juan Basin

          

          

          

          

          

          

          37.4

          

          

          

          37.4

          

          

          

          37.4

          

          

          

          

          

          

          

          37.4Total

          

          

          621.2

          

          

          

          207.4

          

          

          

          828.6

          

          

          

          739.4

          

          

          

          89.2

          

          

          

          828.6
 41    TABLE OF CONTENTS Of the approximately 829 million tons of proven and probable coal reserves to which we had rights as of December 31, 2009, we owned the mineral interests and the related surface rights to 454.2 million tons, or 53%, and we owned only the mineral interests to 189.6 million tons, or 24%. We leased the mineral rights to the remaining 184.8 million tons, or 23%, from unaffiliated third parties and, in turn, subleased these reserves to our lessees. For the reserves we lease from third parties, we pay royalties to the owner based on the amount of coal produced from the leased reserves. Additionally, in some instances, we purchase surface rights or
otherwise compensate surface right owners for mining activities on their properties. In 2009, our aggregate expenses to third-party surface and mineral owners were $5.8 million. The following table sets forth the coal reserves we owned and leased with respect to each of our coal properties as of December 31, 2009 (tons in millions):  Property

          

          Owned

          

          Leased

          

          Total ControlledCentral Appalachia

          

          

          452.9

          

          

          

          151.0

          

          

          

          603.9Northern Appalachia

          

          

          23.4

          

          

          

          

          

          

          

          23.4Illinois Basin

          

          

          133.9

          

          

          

          30.0

          

          

          

          163.9San Juan Basin

          

          

          33.6

          

          

          

          3.8

          

          

          

          37.4Total

          

          

          643.8

          

          

          

          184.8

          

          

          

          828.6
 The following table sets forth our coal reserve activity for the periods presented and ended (tons in millions):  2009

          

          2008

          

          2007Reserves  beginning of year

          

          

          826.8

          

          

          

          818.4

          

          

          

          765.4Purchase of coal reserves

          

          

          2.4

          

          

          

          34.6

          

          

          

          60.0Tons mined by lessees

          

          

          (34.3

          )

          

          

          (33.7

          )

          

          

          (32.5

          )Revisions of estimates and other

          

          

          33.7

          

          

          

          7.5

          

          

          

          25.5Reserves  end of year

          

          

          828.6

          

          

          

          826.8

          

          

          

          818.4
 Our coal reserve estimates are prepared from geological data assembled and analyzed by our general partners or its affiliates 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.
 42    TABLE OF CONTENTS We classify low sulfur coal as coal with a sulfur content of less than 1.0%, medium sulfur coal as coal with a sulfur content between 1.0% and 1.5% and high sulfur coal as coal with a sulfur content of greater than 1.5%. Compliance coal is that portion of low sulfur coal that meets compliance standards for the CAA. As of December 31, 2009, approximately 25% of our reserves met compliance standards for the CAA and 37% were low sulfur. The following table sets forth our estimate of the sulfur content and the typical clean coal quality of our recoverable coal reserves for the period presented (tons in millions):  Sulfur Content

          

          Typical Clean Coal QualityReserves as of December 31, 2009

          

          Heat ContentProperty

          

          Compliance(1)

          

          LowSulfur(2)

          

          MediumSulfur

          

          HighSulfur

          

          Sulfur Unclassified

          

          Total

          

          BTU perPound(3)

          

          Sulfur (%)

          

          Ash (%)Central Appalachia

          

          

          203.1

          

          

          

          283.0

          

          

          

          205.4

          

          

          

          106.9

          

          

          

          8.6

          

          

          

          603.9

          

          

          

          14,041

          

          

          

          1.04

          

          

          

          6.50Northern Appalachia

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          23.4

          

          

          

          

          

          

          

          23.4

          

          

          

          12,900

          

          

          

          2.58

          

          

          

          8.80Illinois Basin

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          163.9

          

          

          

          

          

          

          

          163.9

          

          

          

          11,034

          

          

          

          2.39

          

          

          

          8.32San Juan Basin

          

          

          

          

          

          

          22.1

          

          

          

          11.5

          

          

          

          3.8

          

          

          

          

          

          

          

          37.4

          

          

          

          9,200

          

          

          

          0.89

          

          

          

          17.80Total

          

          

          203.1

          

          

          

          305.1

          

          

          

          216.9

          

          

          

          298.0

          

          

          

          8.6

          

          

          

          828.6
  (1)

          Compliance coal is low sulfur coal which, when burned, emits less than 1.2 pounds of sulfur dioxide per million BTU. Compliance coal meets the sulfur dioxide emission standards imposed by Phase II of the CAA without blending in other coals or using sulfur dioxide reduction technologies. Compliance coal is a subset of low sulfur coal and is, therefore, also reported within the amounts for low sulfur coal. (2)

          Includes compliance coal. (3)

          As-received BTU per pound includes the weight of moisture in the coal on an as sold basis. The following table shows the proven and probable coal reserves we leased to mine operators by property for the period presented (tons in millions):  Proven and Probable Reserves As of December 31, 2009Property

          

          Total Controlled

          

          Leasedto Operators

          

          PercentageLeasedCentral Appalachia

          

          

          603.9

          

          

          

          540.2

          

          

          

          89

          %Northern Appalachia

          

          

          23.4

          

          

          

          23.0

          

          

          

          98

          %Illinois Basin

          

          

          163.9

          

          

          

          111.5

          

          

          

          68

          %San Juan Basin

          

          

          37.4

          

          

          

          37.4

          

          

          

          100

          %Total

          

          

          828.6

          

          

          

          712.1

          

          

          

          86

          %
 Other Natural Resource Management Assets Coal Preparation and Loading Facilities We generate coal services revenues from fees we charge to our lessees for the use of our coal preparation and loading facilities, which are located in Virginia, West Virginia and Kentucky. The facilities provide efficient methods to enhance lessee production levels and exploit our reserves. Timber and Oil and Gas Royalty Interests We own approximately 243,000 acres of forestland in Kentucky, Virginia and West Virginia. The majority of our forestland is located on properties that also contain our coal reserves. We own royalty interests in approximately 7.2 Bcfe of proved oil and gas reserves located in Kentucky, Virginia and West Virginia. Approximately 86% of our oil and gas royalty interests in these reserves are associated with properties acquired from Penn Virginia in 2007. Natural Gas Midstream Systems Our 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.
 43    TABLE OF CONTENTS We own, lease or have rights-of-way to the properties where the majority of our natural gas midstream facilities are located. We also own 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. We owned six natural gas processing facilities having 400 MMcfd of total capacity as of December 31, 2009. Our natural gas midstream operations currently include four natural gas gathering and processing systems and two stand-alone natural gas gathering systems, including: (i) the Panhandle gathering and processing facilities in the Texas/Oklahoma panhandle area; (ii) the Crossroads gathering and processing facilities in East Texas; (iii) the Crescent gathering and processing facilities in central Oklahoma; (iv) the Arkoma gathering system in eastern Oklahoma; (v) the North Texas gathering and pipeline facilities in the Fort Worth Basin; and (vi) the
Hamlin gathering and processing facilities in west-central Texas. These assets included approximately 4,118 miles of natural gas gathering pipelines as of December 31, 2009. In addition, we own a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyomings Powder River Basin. Panhandle System General.  The Panhandle System is a natural gas gathering system stretching over ten counties in the Anadarko Basin of the panhandle of Texas and Oklahoma. The system consists of approximately 1,681 miles of natural gas gathering pipelines, ranging in size from two to 16 inches in diameter, and the Beaver, Spearman and Sweetwater natural gas processing plants. Included in the system is an 11-mile, 10-inch diameter, FERC-jurisdictional residue line. In July 2009, we completed an acquisition of a natural gas processing and residue pipeline facilities in western Oklahoma for approximately $22.6 million in cash. The acquired assets included a 60 MMcfd gas processing plant located near Sweetwater, Oklahoma (the Sweetwater plant). Additionally, we completed a 40 MMcfd processing plant expansion in our Spearman complex that was put into service on July 31, 2009. The acquired and expanded processing facilities increased our processing capacity in the Panhandle System to 260 MMcfd. The increased processing capacity has allowed us to process gas volumes that were being bypassed due to
processing capacity constraints in the Panhandle System and has alleviated pipeline pressure-related volume constraints in the eastern portion of the Panhandle System. The Panhandle System is comprised of a number of major gathering systems and 26 related compressor stations that gather natural gas, directly or indirectly, to the Beaver, Spearman and Sweetwater plants. These include the Beaver, Perryton, Spearman, Wolf Creek/Kiowa Creek and Ellis systems. These gathering systems are located in Beaver, Ellis, Harper and Roger Mills Counties in Oklahoma and Hansford, Hemphill, Hutchinson, Lipscomb, Ochiltree and Roberts Counties in Texas. The Beaver plant has 100 MMcfd of inlet gas capacity. The plant is capable of operating in high ethane recovery mode or in ethane rejection mode and has instrumentation allowing for unattended operation of up to 16 hours per day. The Spearman plant has 100 MMcfd of inlet capacity. The plant is capable of operating in high ethane recovery mode or in ethane rejection mode and has instrumentation allowing for unattended operation of up to 16 hours per day. The Sweetwater plant is capable of operating in high ethane recovery mode or in ethane rejection mode and has instrumentation allowing for unattended operation of up to 16 hours per day. In conjunction with the acquisition of the Sweetwater plant, two new gas compressor stations were installed; one is located on the east end of the North Canadian pipeline and the other on the east end of the Hemphill pipeline.
 44    TABLE OF CONTENTS Natural Gas Supply and Markets for Sale of Natural Gas and NGLs.  The supply in the Panhandle System comes from approximately 203 producers pursuant to 332 contracts. The residue gas from the Beaver plant can be delivered into the Northern Natural Gas, Southern Star Central Gas or ANR Pipeline Company pipelines for sale or transportation to market. The NGLs produced at the Beaver plant are delivered into ONEOK Hydrocarbons pipeline system for transportation to and fractionation at ONEOKs Conway fractionator. The residue gas from the Spearman plant is delivered into Northern Natural Gas pipelines for sale or transportation to market. The NGLs produced at the Spearman plant are delivered into MAPCOs (Mid-America Pipeline Company) pipeline system. MAPCOs pipeline system has the flexibility of delivering the NGLs to either Mont Belvieu or Conway for fractionation. The residue gas from the Sweetwater plant is delivered into Northern Natural Gas pipelines for sale or transportation to market. The NGLs produced at the Sweetwater plant are delivered into ONEOK Hydrocarbons pipeline system for transportation to and fractionation at ONEOKs Conway fractionator. Crossroads System General.  The Crossroads System is a natural gas gathering system located in the southeast portion of Harrison County, Texas. The Crossroads System consists of approximately eight miles of natural gas gathering pipelines, ranging in size from eight to twelve inches in diameter, and the Crossroads plant. The Crossroads System also includes approximately 20 miles of six-inch NGL pipeline that transport the NGLs produced at the Crossroads plant to the Panola Pipeline. The Crossroads plant has 80 MMcfd of inlet capacity. The plant is capable of operating in high ethane recovery mode or in ethane rejection mode and has instrumentation allowing for unattended operation of up to 16 hours per day. Natural Gas Supply and Markets for Sale of Natural Gas and NGLs.  The natural gas on the Crossroads System originates from the Bethany Field from where we have contracted with five producers. The Crossroads System delivers the residue gas from the Crossroads plant into the CenterPoint Energy pipeline for sale or transportation to market. The NGLs produced at the Crossroads plant are delivered into the Panola Pipeline for transportation to Mont Belvieu, Texas for fractionation. Crescent System General.  The Crescent System is a natural gas gathering system stretching over seven counties within central Oklahomas Sooner Trend. The system consists of approximately 1,701 miles of natural gas gathering pipelines, ranging in size from two to 10 inches in diameter, and the Crescent natural gas processing plant located in Logan County, Oklahoma. Fifteen compressor stations are operating across the Crescent System. The Crescent plant is a NGL recovery plant with current capacity of approximately 40 MMcfd. The Crescent facility also includes a gas engine-driven generator which is routinely operated, making the plant self-sufficient with respect to electric power. The cost of fuel (residue gas) for the generator is borne by the producers under the terms of their respective gas contracts. Natural Gas Supply and Markets for Sale of Natural Gas and NGLs.  The gas supply on the Crescent System is primarily gas associated with the production of oil or casinghead gas from the mature Sooner Trend. Wells in this region producing casinghead gas are generally characterized as low volume, long-lived producers of gas with large quantities of NGLs. The supply in the Crescent System comes from approximately 256 producers pursuant to 411 contracts. The Crescent plants connection to the Enogex and ONEOK Gas Transportation pipelines for residue gas and the ONEOK Hydrocarbon pipeline for NGLs gives the Crescent
System access to a variety of market outlets. Hamlin System General.  The Hamlin System is a natural gas gathering system stretching over eight counties in West Central Texas. The system consists of approximately 516 miles of natural gas gathering pipelines, ranging in size from two to 12 inches in diameter and with current capacity of approximately 20 MMcfd, and the Hamlin natural gas processing plant located in Fisher County, Texas. Eight compressor stations are operating across the system.
 45    TABLE OF CONTENTS Natural Gas Supply and Markets for Sale of Natural Gas and NGLs.  The gas on the Hamlin System is primarily gas associated with the production of oil or casinghead gas. The supply on the Hamlin System comes from approximately 143 producers pursuant to 114 contracts. The Hamlin System delivers the residue gas from the Hamlin plant into the Enbridge or Atmos pipelines. The NGLs produced at the Hamlin plant are delivered into TEPPCOs pipeline system. North Texas System General.  The North Texas assets are located in the southern portion of the Fort Worth Basin of North Texas and include approximately 134 miles of gas gathering pipelines and approximately 240,000 acres dedicated by active producers. This expands the geographic scope of the natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin. Natural Gas Supply.  The gathering and transportation infrastructure captures current and expected volumes in Johnson, Hill, Bosque, Somervell, Hamilton and Erath counties. Since the acquisition, we have averaged 18 MMcfd in gathered volumes during 2009. Item 3 Legal Proceedings 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. Item 4 Reserved
 46    TABLE OF CONTENTS Part II Item 5

          Market for the Registrants Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities Market Information Our common units are traded on the NYSE under the symbol PVR. The high and low sales prices (composite transactions) and distributions declared related to each fiscal quarter in 2009 and 2008 were as follows:  Quarter Ended

          

          High

          

          Low

          

          CashDistributionDeclaredDecember 31, 2009

          

          $

          22.30

          

          

          $

          16.57

          

          

          $

          0.47September 30, 2009

          

          $

          17.98

          

          

          $

          12.35

          

          

          $

          0.47June 30, 2009

          

          $

          15.99

          

          

          $

          10.96

          

          

          $

          0.47March 31, 2009

          

          $

          16.51

          

          

          $

          9.10

          

          

          $

          0.47December 31, 2008

          

          $

          19.85

          

          

          $

          8.34

          

          

          $

          0.47September 30, 2008

          

          $

          27.38

          

          

          $

          15.08

          

          

          $

          0.47June 30, 2008

          

          $

          30.15

          

          

          $

          24.69

          

          

          $

          0.46March 31, 2008

          

          $

          29.00

          

          

          $

          18.00

          

          

          $

          0.45
 Equity Holders As of February 22, 2010, there were 227 record holders and approximately 21,360 beneficial owners (held in street name) of our common units.
 47    TABLE OF CONTENTS Item 6

          Selected Financial Data The following selected historical financial information was derived from our Consolidated Financial Statements as of December 31, 2009, 2008, 2007, 2006 and 2005, and for each of the years then ended. The selected financial data should be read in conjunction with our Consolidated Financial Statements and the accompanying Notes and Supplementary Data in Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations, and Item 8, Financial Statements and Supplementary Data:  2009

          

          2008

          

          2007

          

          2006

          

          2005(1)(in thousands, except per unit data)Statement of Income Data:Revenues(2)

          

          $

          656,704

          

          

          $

          881,580

          

          

          $

          549,445

          

          

          $

          517,891

          

          

          $

          446,348Expenses(2)

          

          $

          548,402

          

          

          $

          766,338

          

          

          $

          431,720

          

          

          $

          415,071

          

          

          $

          368,258Operating income

          

          $

          108,302

          

          

          $

          115,242

          

          

          $

          117,725

          

          

          $

          102,820

          

          

          $

          78,090Net income

          

          $

          65,215

          

          

          $

          104,500

          

          

          $

          56,623

          

          

          $

          73,928

          

          

          $

          51,161Common Unit Data:Net income per limited partner unit, basic and diluted

          

          $

          0.76

          

          

          $

          1.63

          

          

          $

          0.92

          

          

          $

          1.59

          

          

          $

          1.21Distributions paid

          

          $

          124,009

          

          

          $

          111,076

          

          

          $

          89,649

          

          

          $

          66,954

          

          

          $

          51,949Distributions paid per unit

          

          $

          1.88

          

          

          $

          1.82

          

          

          $

          1.66

          

          

          $

          1.48

          

          

          $

          1.24Balance Sheet and Other Financial Data:Property, plant and equipment, net

          

          $

          900,844

          

          

          $

          895,119

          

          

          $

          731,282

          

          

          $

          556,513

          

          

          $

          458,782Total assets(3)

          

          $

          1,208,060

          

          

          $

          1,218,819

          

          

          $

          931,279

          

          

          $

          714,023

          

          

          $

          657,879Long-term debt

          

          $

          620,100

          

          

          $

          568,100

          

          

          $

          399,153

          

          

          $

          207,214

          

          

          $

          246,846Cash flows provided by operating activities

          

          $

          159,972

          

          

          $

          139,176

          

          

          $

          127,824

          

          

          $

          107,344

          

          

          $

          93,172Cash acquisitions and additions

          

          $

          80,677

          

          

          $

          332,028

          

          

          $

          225,040

          

          

          $

          129,712

          

          

          $

          303,673Other Statistical Data:Coal royalty tons (in thousands)

          

          

          34,330

          

          

          

          33,690

          

          

          

          32,528

          

          

          

          32,778

          

          

          

          30,227System throughput volumes (MMcf)

          

          

          121,335

          

          

          

          98,683

          

          

          

          67,810

          

          

          

          55,991

          

          

          

          38,875
  (1)

          The 2005 column includes the results of operations of our natural gas midstream segment since March 3, 2005, the closing date of the acquisition of Cantera Gas Resources, LLC. (2)

          In 2009 and 2008, we recorded $72.5 million and $127.9 million of natural gas midstream revenue and $72.5 and $127.9 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG LP and the subsequent sale of that gas to third parties. We take title to the gas prior to transporting it to third parties. These transactions do not impact the gross margin, nor do they impact operating income. (3)

          Total assets for the year ended December 31, 2008 include the effects of the Lone Star acquisition. See Note 3 to the Consolidated Financial Statements for a more detailed description of this acquisition, including pro forma results.
 48    TABLE OF CONTENTS Item 7

          Managements Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of the financial condition and results of operations of Penn Virginia Resource Partners, L.P. and its subsidiaries (the Partnership, we, us or our) should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Item 8. All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated. Overview of Business We are a publicly traded Delaware limited partnership formed by Penn Virginia in 2001 that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. Both in our current limited partnership form and in our previous corporate form, we have managed coal properties since 1882. We currently conduct operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream. In 2009, our coal and natural resource management segment contributed $87.5 million, or 81%, to operating income, and our natural gas midstream segment
contributed $20.8 million, or 19%, to operating income. As of December 31, 2009, we owned or controlled approximately 829 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. We enter into long-term leases with experienced, third-party mine operators, providing them the right to mine our coal reserves in exchange for royalty payments. We actively work with our lessees to develop efficient methods to exploit our reserves and to maximize production from our properties. We do not operate any mines. In 2009, our lessees produced 34.3 million tons of coal from our properties and paid us coal royalties revenues of $120.4 million, for an
average royalty per ton of $3.51. Approximately 82% of our coal royalties revenues in 2009 were derived from coal mined on our 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 our coal royalties revenues for the respective periods was derived from coal mined on our properties under leases containing fixed royalty rates that escalate annually. Coal royalties are impacted by several factors that we generally cannot control. The number of tons mined annually is determined by an operators mining efficiency, labor availability, geologic conditions, access to capital, ability to market coal and ability to arrange reliable transportation to the end-user. New legislation or regulations have been or may be adopted which may have a significant impact on the mining operations of our lessees or their customers ability to use coal and which may require us, our lessees or our lessees customers to change operations significantly or incur substantial costs. See Item 1A, Risk
Factors. To a lesser extent, coal prices also impact coal royalties revenues. Generally, as coal prices change over an extended period of time, our average royalty per ton may change as the majority of our lessees pay royalties based on the gross sales prices of the coal mined. However, most of our lessees coal is sold under contracts with a duration of one year or more; therefore, the underlying prices for our royalties are less susceptible to short-term volatility in coal prices and prices change primarily as our lessees long-term contracts are renegotiated. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees. Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of December 31, 2009, we owned and operated natural gas midstream assets located in Oklahoma and Texas, including six natural gas processing facilities having 400 MMcfd of total capacity and approximately 4,118 miles of natural gas gathering pipelines. Our natural gas midstream business earns revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In addition, we own a 25% member interest in Thunder Creek, a joint
venture that gathers and transports coalbed methane in Wyomings Powder River Basin. We also own 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.
 49    TABLE OF CONTENTS In 2009, system throughput volumes at our gas processing plants and gathering systems, including gathering-only volumes, were 121.3 Bcf, or approximately 332 MMcfd. In 2009, 21%, 15% and 10% of our natural gas midstream segment revenues and 17%, 11% and 8% of our total consolidated revenues related to three of our natural gas midstream customers, Conoco, Inc., Tenaska Marketing Ventures and ONEOK Energy Marketing. We continually seek new supplies of natural gas to both offset the natural declines in production from the wells currently connected to our systems and to increase system throughput volumes. New natural gas supplies are obtained for all of our systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and contracting for natural gas that has been released from competitors systems. In 2009, our natural gas midstream segment made aggregate capital expenditures of $72.8 million, primarily related to our acquisition of the Sweetwater plant, expansion of the Spearman plant and other expansion related
projects in the panhandle of Texas and Oklahoma. For a more detailed discussion of our acquisitions and investments, see  Acquisitions and Investments. Key Developments 2009 Commodity Prices The 2009 average commodity prices for coal, timber, natural gas, crude oil and NGLs declined from 2008 levels. NGLs refer to ethane, propane, iso butane, normal butane and pentane. The pricing of these commodities directly and indirectly drive our earnings. Coal royalties, which accounted for 83% of the 2009 coal and natural resource management segment revenues, were slightly lower as compared 2008. We continue to benefit from long-term contract prices our lessees previously negotiated with their customers. However, the state of the global economy, including financial and credit markets, has reduced worldwide demand for coal with resultant price declines. Depending on the longevity and ultimate severity of the deterioration, demand for coal may continue to decline, which could adversely affect production and pricing for coal mined by our lessees. Revenues, profitability and the future rate of growth of our natural gas midstream segment are highly dependent on market demand and prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market demand. As part of our risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. Our derivative financial instruments
include costless collars and swaps. Based upon current volumes, we have entered into hedging arrangements covering approximately 58% and 37% of our commodity-sensitive volumes in 2010 and 2011. We generally target hedging 50% to 60% of our commodity-sensitive volumes covering a two-year period. Acquisitions and Investments In July 2009, we completed an acquisition of gas processing and residue pipeline facilities in western Oklahoma from Atlas Pipeline Partners, L.P. for approximately $22.6 million in cash. Funding for the acquisition was provided by borrowings under the Revolver. The acquired assets included a 60 MMcfd processing plant within Atlas 180 MMcfd Sweetwater facility. Additionally, we completed a 40 MMcfd processing plant expansion in our Spearman complex that was put into service on July 31, 2009. The acquired and expanded processing facilities increased our processing capacity in the Panhandle System to 260 MMcfd and overall processing capacity to
400 MMcfd. The increased processing capacity has allowed the natural gas midstream segment to process gas volumes that were being bypassed due to processing capacity constraints in the Panhandle System and has alleviated pipeline pressure-related volume constraints in the eastern portion of the Panhandle System.
 50    TABLE OF CONTENTS In July 2008, we completed the Lone Star acquisition. Lone Stars assets are located in the southern portion of the Fort Worth Basin of North Texas and include approximately 129 miles of gas gathering pipelines and approximately 240,000 acres dedicated by active producers. The Lone Star acquisition expanded the geographic scope of the natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin. We acquired this business for approximately $164.3 million and a liability of $4.7 million, which represents the fair value of a $5.0 million guaranteed payment, plus contingent payments of $30.0 million and $25.0 million. Funding
for the acquisition was provided by $80.7 million of borrowings under the Revolver, 2,009,995 PVG common units (which we purchased from two subsidiaries of Penn Virginia for $61.8 million) and 542,610 of our newly issued common units. The contingent payments will be triggered if revenues from certain assets located in a defined geographic area reach certain targets by or before June 30, 2013 and will be funded in cash or common units, at our election. In April 2008, we acquired a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyomings Powder River Basin. The purchase price was $51.6 million in cash, after customary closing adjustments, and was funded with long-term debt under the Revolver. In May 2008, we acquired fee ownership of approximately 29 million tons of coal reserves and approximately 56 MMbf of hardwood timber in western Virginia and eastern Kentucky. The purchase price was $24.5 million in cash and was funded with long-term debt under the Revolver. Liquidity and Capital Resources Cash Flows On an ongoing basis, we generally satisfy our working capital requirements and fund our capital expenditures using cash generated from our operations, borrowings under the Revolver and proceeds from equity offerings. We satisfy our debt service obligations and distributions to unitholders solely using cash generated from our operations. We believe that the cash generated from our operations and our borrowing capacity will be sufficient to meet our 2010 working capital requirements, anticipated capital expenditures (other than major capital improvements or acquisitions), scheduled debt payments and distributions. However, our ability to meet these
requirements in the future will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and natural gas midstream market, some of which are beyond our control. The following table summarizes our statements of cash flows for the periods presented:  For the Year Ended December 31,2009

          

          2008

          

          2007Cash flows from operating activities:Net income contribution

          

          $

          65,215

          

          

          $

          104,500

          

          

          $

          56,623Adjustments to reconcile net income to net cash provided by operating activities (summarized)

          

          

          100,065

          

          

          

          41,205

          

          

          

          73,444Net changes in operating assets and liabilities

          

          

          (5,308

          )

          

          

          (6,529

          )

          

          

          (2,243

          )Net cash provided by operating activities

          

          

          159,972

          

          

          

          139,176

          

          

          

          127,824Net cash used in investing activities

          

          

          (79,530

          )

          

          

          (331,030

          )

          

          

          (224,182

          )Net cash provided by (used in) financing activities

          

          

          (81,267

          )

          

          

          181,808

          

          

          

          104,448Net increase (decrease) in cash and cash equivalents

          

          $

          (825

          )

          

          $

          (10,046

          )

          

          $

          8,090
 51    TABLE OF CONTENTS Cash Flows From Operating Activities The overall increase in net cash provided by operating activities in 2009 as compared to 2008 was driven by an increase in the natural gas midstream segments gross margin, adjusted for the cash impact of midstream derivatives and impairments. We received a net $10.6 million in midstream derivative settlements in 2009 compared to paying a net $37.2 million in 2008. The difference in net derivative settlements relates to decreased commodity pricing and the expiration of older commodity derivatives. This increase was partially offset by a decrease in operating income, before DD&A expense and impairments from the coal and natural resource
management segment primarily due to decreases in coal royalties, oil and gas royalties and other revenue. The overall increase in net cash provided by operating activities in 2008 as compared to 2007 was primarily attributable to increased cash received from the sales of residue gas and NGLs, which was primarily due to increased system throughput volume; increased coal royalties received, which was primarily due to increased production and sales prices of coal in the Central Appalachian and Illinois Basin regions; and increased cash received from the sale of standing timber, which was due primarily to increased harvesting from our September 2007 forestland acquisition. These increases were partially offset by increased cash outflows from our natural gas
midstream commodity derivative settlements. Cash Flows From Investing Activities Net cash used in investing activities were primarily for capital expenditures. The following table sets forth our capital expenditures programs, by segment, for the periods presented:  Year Ended December 31,2009

          

          2008Coal and natural resource managementAcquisitions

          

          $

          2,067

          

          

          $

          27,075Expansion capital expenditures

          

          

          

          

          

          

          Other property and equipment expenditures

          

          

          185

          

          

          

          195Total

          

          

          2,252

          

          

          

          27,270Natural gas midstreamAcquisitions

          

          

          27,514

          

          

          

          259,417Expansion capital expenditures

          

          

          36,863

          

          

          

          59,385Other property and equipment expenditures

          

          

          8,399

          

          

          

          14,505Total

          

          

          72,776

          

          

          

          333,307Total capital expenditures

          

          $

          75,028

          

          

          $

          360,577
 Our 2009 capital expenditures consisted primarily of a natural gas midstream plant acquisition, and expansion capital used to increase our natural gas processing capacity and operational footprint in our Panhandle System. Our 2008 capital expenditures were primarily discretionary in nature and included our 25% member interest acquisition in Thunder Creek, the Lone Star acquisition, pipeline assets in the Anadarko Basin of Oklahoma and Texas, expansion capital expenditures related to the Spearman and Crossroads plants and the acquisition of approximately 29 million tons of coal reserves and an estimated 56 MMbf of hardwood timber in western Virginia and eastern Kentucky. Our natural gas midstream segment also incurred approximately $14.5 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas.
 52    TABLE OF CONTENTS Cash Flows From Financing Activities During 2009, we had net borrowings of $52.0 million under the Revolver. These borrowings were used to fund our capital expenditure program. During 2008, we had net borrowings of $156.0 million primarily attributable to the Revolver offset by the repayments of $63.3 million under the Senior Unsecured Notes due 2013. In 2008 we also received net proceeds of $141.1 million from the sale of our common units in a public offering, which was comprised of net proceeds of $138.2 million from the sale of the common units to the public and $2.9 million in contributions from our general partner to maintain its 2% general partner interest. This increase in
outstanding common units also increased distributions paid to our partners. In January 2010 we declared a $0.47 ($1.88 on an annualized basis) per unit quarterly distribution for the three months ended December 31, 2009 paid on February 12, 2010 to unitholders of record at the close of business on February 2, 2010. Sources of Liquidity Long-Term Debt Revolver.  As of December 31, 2009, net of outstanding borrowings of $620.1 million and letters of credit of $1.6 million, we had remaining borrowing capacity of $178.3 million on the Revolver. In March 2009, we increased the size of our Revolver from $700.0 million to $800.0 million and secured the Revolver with substantially all of our assets. The Revolver matures in December 2011 and is available to us for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10.0 million sublimit for the issuance of letters of credit. In 2009, we incurred commitment fees of $0.5 million on the unused
portion of the Revolver. The interest rate under the Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 1.25% if we select the base rate borrowing option under the Revolver or at a rate derived from the London Interbank Offered Rate, or LIBOR, plus an applicable margin ranging from 1.75% to 2.75% if we select the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under the Revolver during 2009 was approximately 2.7%. We do not have a public credit rating for the Revolver. A discussion of the applicable covenants and related compliance with respect to the Revolver is provided in the discussion of Financial Condition that follows. Interest Rate Swaps.  We have entered into interest rate swaps, or Interest Rate Swaps, to establish fixed rates on a portion of the outstanding borrowings under the Revolver. The following table sets forth the Interest Rate Swap positions at December 31, 2009 (in millions):  Dates

          

          Notional Amounts

          

          Weighted-Average Fixed RateUntil March 2010

          

          $

          310.0

          

          

          

          3.54

          %March 2010  December 2011

          

          $

          250.0

          

          

          

          3.37

          %December 2011  December 2012

          

          $

          100.0

          

          

          

          2.09

          %
 The Interest Rate Swaps extend one year past the maturity of the current Revolver. After considering the applicable margin of 2.25% in effect as of December 31, 2009 the total interest rate on the $310 million portion of the Revolver borrowings covered by the Interest Rate Swaps was 5.79% as of December 31, 2009. Unit Offering In 2008, we completed the sale of 5.15 million common units representing limited partner interests in a registered public offering and received $138.2 million in net proceeds. We received total contributions of $2.9 million from our general partner to maintain its 2% general partner interest in us. The net sales proceeds were used to repay a portion of our borrowings under the Revolver.
 53    TABLE OF CONTENTS Financial Condition Covenant Compliance The terms of the Revolver require us to maintain financial covenants. These covenants are as follows: 

          Total debt to consolidated EBITDA may not exceed 5.25 to 1.0. EBITDA, which is a non-GAAP measure, is generally defined in the PVR Revolver as PVRs net income plus interest expense (net of interest income), depreciation, depletion and amortization expenses, and non-cash hedging activity and impairments. 

          Consolidated EBITDA to interest expense may not be less than 2.5 to 1.0. As of December 31, 2009, we were in compliance with all of the Revolvers covenants. The following table summarizes the actual results of our covenant compliance for the period ended December 31, 2009:  Description of Covenant

          

          Covenant

          

          ActualResultsDebt to EBITDA

          

          

          5.25

          

          

          

          3.36EBITDA to interest expense

          

          

          2.50

          

          

          

          7.50
 In the event that we would be in default of our covenants under the Revolver, we could appeal to the banks for a waiver of the covenant default. Should the banks deny our appeal to waive the covenant default, the outstanding borrowings under the Revolver would become payable upon demand and would be reclassified to the current liabilities section of our Consolidated Balance Sheet. The Revolver prohibits us from making distributions to our partners if any potential default, or event of default, as defined in the Revolver, occurs or would result from the distributions. In addition, the Revolver contains various covenants that limit our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business or enter into a merger or sale of our assets, including the sale or transfer of interests in our subsidiaries. Future Capital Needs and Commitments We believe that our remaining borrowing capacity of $178.3 million will be sufficient for our 2010 capital needs and commitments. Our short-term cash requirements for operating expenses and quarterly distributions to PVG, as the owner of our general partner, and unitholders are expected to be funded through operating cash flows. In 2010, we anticipate making capital expenditures, excluding acquisitions, of approximately $60.0 million. The majority of the 2010 capital expenditures are expected to be incurred in the natural gas midstream segment. We intend to fund these capital expenditures with a combination of operating cash flows and borrowings
under the Revolver. Long-term cash requirements for acquisitions and other capital expenditures are expected to be funded by operating cash flows, borrowings under the Revolver and the issuances of additional debt and equity securities if available under commercially acceptable terms. Part of our long-term strategy is to increase cash available for distribution to our unitholders by making acquisitions and other capital expenditures. Our ability to make these acquisitions and other capital expenditures in the future will depend largely on the availability of debt financing and on our ability to periodically use equity financing through the issuance of new common units. Future financing will depend on various factors, including prevailing market conditions, interest rates and our financial condition and credit rating.
 54    TABLE OF CONTENTS Contractual Obligations The following table summarizes our contractual obligations as of December 31, 2009 (in thousands):  Payments Due by PeriodTotal

          

          Less Than 1 Year

          

          1  3 Years

          

          3  5 Years

          

          More Than 5 yearsRevolver

          

          $

          620,100

          

          

          $

          

          

          

          $

          620,100

          

          

          $

          

          

          

          $

          Asset retirement obligations(1)

          

          

          2,014

          

          

          

          

          

          

          

          369

          

          

          

          

          

          

          

          1,645Interest expense(2)

          

          

          30,034

          

          

          

          15,440

          

          

          

          14,594

          

          

          

          

          

          

          

          Derivatives(3)

          

          

          15,536

          

          

          

          11,251

          

          

          

          4,285

          

          

          

          

          

          

          

          Natural gas midstream activities(4)

          

          

          32,320

          

          

          

          13,103

          

          

          

          10,202

          

          

          

          7,354

          

          

          

          1,661Rental commitments(5)

          

          

          24,480

          

          

          

          4,243

          

          

          

          6,430

          

          

          

          5,864

          

          

          

          7,943Total contractual obligations(6)

          

          $

          724,484

          

          

          $

          44,037

          

          

          $

          655,980

          

          

          $

          13,218

          

          

          $

          11,249
  (1)

          The undiscounted balance was approximately $7.7 million at December 31, 2009. (2)

          Represents estimated interest payments that will be due under the Revolver. (3)

          Represents estimated payments we will make resulting from our commodity derivatives as well as the Interest Rate Swaps. (4)

          Commitments for natural gas midstream activities relate to firm transportation agreements. (5)

          Primarily relates to equipment and building leases and leases of coal reserve-based properties which we sublease, or intend to sublease, to third parties. (6)

          Total contractual obligations do not include anticipated 2010 capital expenditures. Part of the purchase price for the Lone Star acquisition includes contingent payments of approximately $55.0 million. These contingency payments will be made by us if certain revenue targets are met before June 30, 2013. Because the outcome of these contingent payments is not determinable beyond a reasonable doubt, we have not accrued them as a liability. Rather, once the revenue targets are met, the contingent payments will be recorded as an additional cost of the Lone Star acquisition. We do not have employment agreements with our executive officers and do not have any other employees. Our compensation obligations with respect to our executive officers can be significantly different from one year to another and are based on variables such as our performance for the given year. For a more detailed discussion on our executive compensation, see Item 11, Executive Compensation. Off-Balance Sheet Arrangements We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2009, the material off-balance sheet arrangements and transactions that we have entered into included operating lease arrangements, firm transportation agreements, and letters of credit, all of which are customary in our business. See Contractual Obligations summarized above for more detail related to the value of off-balance sheet arrangements. We did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special
purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We are, therefore, not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships.
 55    TABLE OF CONTENTS Results of Operations Consolidated Review The following table presents summary consolidated operating results for the periods presented:  Year Ended December 31,2009

          

          2008

          

          2007Revenues

          

          $

          656,704

          

          

          $

          881,580

          

          

          $

          549,445Expenses

          

          

          548,402

          

          

          

          766,338

          

          

          

          431,720Operating income

          

          

          108,302

          

          

          

          115,242

          

          

          

          117,725Other income (expense)

          

          

          (43,087

          )

          

          

          (10,742

          )

          

          

          (61,102

          )Net income

          

          $

          65,215

          

          

          $

          104,500

          

          

          $

          56,623
 The following table presents certain summary financial information relating to our segments for the periods presented:  Coal and Natural Resource Management

          

          Natural Gas Midstream

          

          ConsolidatedFor the Year Ended December 31, 2009:Revenues

          

          $

          144,600

          

          

          $

          512,104

          

          

          $

          656,704Cost of midstream gas purchased

          

          

          

          

          

          

          406,583

          

          

          

          406,583Operating costs and expenses

          

          

          24,231

          

          

          

          45,842

          

          

          

          70,073Impairments

          

          

          1,511

          

          

          

          

          

          

          

          1,511Depreciation, depletion and amortization

          

          

          31,330

          

          

          

          38,905

          

          

          

          70,235Operating income

          

          $

          87,528

          

          

          $

          20,774

          

          

          $

          108,302For the Year Ended December 31, 2008:Revenues

          

          $

          153,327

          

          

          $

          728,253

          

          

          $

          881,580Cost of midstream gas purchased

          

          

          

          

          

          

          612,530

          

          

          

          612,530Operating costs and expenses

          

          

          26,226

          

          

          

          37,615

          

          

          

          63,841Impairments

          

          

          

          

          

          

          31,801

          

          

          

          31,801Depreciation, depletion and amortization

          

          

          30,805

          

          

          

          27,361

          

          

          

          58,166Operating income

          

          $

          96,296

          

          

          $

          18,946

          

          

          $

          115,242For the Year Ended December 31, 2007:Revenues

          

          $

          111,639

          

          

          $

          437,806

          

          

          $

          549,445Cost of midstream gas purchased

          

          

          

          

          

          

          343,293

          

          

          

          343,293Operating costs and expenses

          

          

          20,138

          

          

          

          26,777

          

          

          

          46,915Depreciation, depletion and amortization

          

          

          22,690

          

          

          

          18,822

          

          

          

          41,512Operating income

          

          $

          68,811

          

          

          $

          48,914

          

          

          $

          117,725
 56    TABLE OF CONTENTS Coal and Natural Resource Management Segment Year Ended December 31, 2009 Compared With Year Ended December 31, 2008 The following table sets forth a summary of certain financial and other data for our coal and natural resource management segment and the percentage change for the periods presented:  Year Ended December 31,

          

          Favorable (Unfavorable)

          

          %Change2009

          

          2008Financial HighlightsRevenuesCoal royalties

          

          $

          120,435

          

          

          $

          122,834

          

          

          $

          (2,399

          )

          

          

          (2%)Coal services

          

          

          7,332

          

          

          

          7,355

          

          

          

          (23

          )

          

          

          (0%)Timber

          

          

          5,726

          

          

          

          6,943

          

          

          

          (1,217

          )

          

          

          (18%)Oil and gas royalty

          

          

          2,471

          

          

          

          5,989

          

          

          

          (3,518

          )

          

          

          (59%)Other

          

          

          8,636

          

          

          

          10,206

          

          

          

          (1,570

          )

          

          

          (15%)Total revenues

          

          

          144,600

          

          

          

          153,327

          

          

          

          (8,727

          )

          

          

          (6%)ExpensesCoal royalties

          

          

          5,768

          

          

          

          9,534

          

          

          

          3,766

          

          

          

          40%Other operating

          

          

          2,892

          

          

          

          2,406

          

          

          

          (486

          )

          

          

          (20%)Taxes other than income

          

          

          1,704

          

          

          

          1,680

          

          

          

          (24

          )

          

          

          (1%)General and administrative

          

          

          13,867

          

          

          

          12,606

          

          

          

          (1,261

          )

          

          

          (10%)Impairments

          

          

          1,511

          

          

          

          

          

          

          

          (1,511

          )

          

          

          Depreciation, depletion and amortization

          

          

          31,330

          

          

          

          30,805

          

          

          

          (525

          )

          

          

          (2%)Total expenses

          

          

          57,072

          

          

          

          57,031

          

          

          

          (41

          )

          

          

          (0%)Operating income

          

          $

          87,528

          

          

          $

          96,296

          

          

          $

          (8,768

          )

          

          

          (9%)Other dataCoal royalty tons by regionCentral Appalachia

          

          

          18,319

          

          

          

          19,587

          

          

          

          (1,268

          )

          

          

          (6%)Northern Appalachia

          

          

          3,786

          

          

          

          3,578

          

          

          

          208

          

          

          

          6%Illinois Basin

          

          

          4,724

          

          

          

          4,584

          

          

          

          140

          

          

          

          3%San Juan Basin

          

          

          7,501

          

          

          

          5,941

          

          

          

          1,560

          

          

          

          26%Total

          

          

          34,330

          

          

          

          33,690

          

          

          

          640

          

          

          

          2%Coal royalties revenues by regionCentral Appalachia

          

          $

          85,183

          

          

          $

          93,577

          

          

          $

          (8,394

          )

          

          

          (9%)Northern Appalachia

          

          

          6,931

          

          

          

          6,568

          

          

          

          363

          

          

          

          6%Illinois Basin

          

          

          12,420

          

          

          

          10,451

          

          

          

          1,969

          

          

          

          19%San Juan Basin

          

          

          15,901

          

          

          

          12,238

          

          

          

          3,663

          

          

          

          30%$

          120,435

          

          

          $

          122,834

          

          

          $

          (2,399

          )

          

          

          (2%)Less coal royalties expenses(1)

          

          

          (5,768

          )

          

          

          (9,534

          )

          

          

          3,766

          

          

          

          (40%)Net coal royalties revenues

          

          $

          114,667

          

          

          $

          113,300

          

          

          $

          1,367

          

          

          

          1%Coal royalties per ton by region ($/ton)Central Appalachia

          

          $

          4.65

          

          

          $

          4.78

          

          

          $

          (0.13

          )

          

          

          (3%)Northern Appalachia

          

          

          1.83

          

          

          

          1.84

          

          

          

          (0.01

          )

          

          

          (1%)Illinois Basin

          

          

          2.63

          

          

          

          2.28

          

          

          

          0.35

          

          

          

          15%San Juan Basin

          

          

          2.12

          

          

          

          2.06

          

          

          

          0.06

          

          

          

          3%$

          3.51

          

          

          $

          3.65

          

          

          $

          (0.14

          )

          

          

          (4%)Less coal royalties expenses(1)

          

          

          (0.17

          )

          

          

          (0.28

          )

          

          

          0.11

          

          

          

          (39%)Net coal royalties revenues

          

          $

          3.34

          

          

          $

          3.37

          

          

          $

          (0.03

          )

          

          

          (1%)
  (1)

          Our coal royalties expense is incurred primarily in the Central Appalachian region.
 57    TABLE OF CONTENTS Revenues Coal royalties revenues decreased slightly due to the decrease in the average coal royalty received per ton. This decrease was due to an overall shift in production mix to lower royalty lessees, primarily to fixed rate leases in the San Juan Basin from the higher royalty Central Appalachian region. Coal production by our lessees increased slightly due to higher production in the San Juan Basin resulting from the start up of a second mine and improved mining conditions. This increase was partially offset by a decline in production in the Central Appalachian region which was due to a reduction in longwall mining activity and a depressed coal market. Timber revenues decreased due to lower sales prices resulting from weakened market conditions for furniture-grade wood products. The average price received for timber decreased 27% from $287 per Mbf in 2008 to $209 per Mbf in 2009. The oil and gas royalty revenues decrease was primarily attributable to lower natural gas prices in 2009. Realized prices received for natural gas decreased 57% from $10.63 per Mcf in 2008 to $4.55 per Mcf in 2009. Other revenues, which consisted primarily of wheelage fees, forfeiture income and management fees, decreased due to lower wheelage income from a decline in coal production in certain areas. In addition, in 2008, a $0.8 million gain on the settlement of unmined coal was recognized. Expenses Coal royalties expenses decreased due to a decline in mining activity by our lessees from subleased properties in the Central Appalachian region where our coal royalties expense is primarily incurred. Mining activity on our subleased property fluctuates between periods due to the proximity of our property boundaries and other mineral owners. General and administrative expenses increased as a result of an uncollectible account receivable resulting from a lessee bankruptcy and increased staffing and related benefit costs. The $1.5 million impairment expense in 2009 was the result of a reduction in the value of an intangible asset. We test long-lived assets for impairment if a triggering event occurs and the impairment was triggered by a wheelage contract being rejected in bankruptcy. As a result of the impairment, the fair value of the contract has been reduced to zero. DD&A expenses increased slightly due to higher depletion expense resulting from the increase in coal mined from our properties by our lessees. On a per ton basis, DD&A remained constant at $0.91 per ton for both periods.
 58    TABLE OF CONTENTS Year Ended December 31, 2008 Compared With Year Ended December 31, 2007  The following table sets forth a summary of certain financial and other data for our coal and natural resource management segment and the percentage change for the periods presented:  Year Ended December 31,

          

          Favorable (Unfavorable)

          

          %Change2008

          

          2007Financial HighlightsRevenuesCoal royalties

          

          $

          122,834

          

          

          $

          94,140

          

          

          $

          28,694

          

          

          

          30%Coal services

          

          

          7,355

          

          

          

          7,252

          

          

          

          103

          

          

          

          1%Timber

          

          

          6,943

          

          

          

          1,711

          

          

          

          5,232

          

          

          

          306%Oil and gas royalty

          

          

          5,989

          

          

          

          1,864

          

          

          

          4,125

          

          

          

          221%Other

          

          

          10,206

          

          

          

          6,672

          

          

          

          3,534

          

          

          

          53%Total revenues

          

          

          153,327

          

          

          

          111,639

          

          

          

          41,688

          

          

          

          37%ExpensesCoal royalties

          

          

          9,534

          

          

          

          5,540

          

          

          

          (3,994

          )

          

          

          (72%)Other operating

          

          

          2,406

          

          

          

          2,531

          

          

          

          125

          

          

          

          5%Taxes other than income

          

          

          1,680

          

          

          

          1,110

          

          

          

          (570

          )

          

          

          (51%)General and administrative

          

          

          12,606

          

          

          

          10,957

          

          

          

          (1,649

          )

          

          

          (15%)Depreciation, depletion and amortization

          

          

          30,805

          

          

          

          22,690

          

          

          

          (8,115

          )

          

          

          (36%)Total expenses

          

          

          57,031

          

          

          

          42,828

          

          

          

          (14,203

          )

          

          

          (33%)Operating income

          

          $

          96,296

          

          

          $

          68,811

          

          

          $

          27,485

          

          

          

          40%Other dataCoal royalty tons by regionCentral Appalachia

          

          

          19,587

          

          

          

          18,827

          

          

          

          760

          

          

          

          4%Northern Appalachia

          

          

          3,578

          

          

          

          4,194

          

          

          

          (616

          )

          

          

          (15%)Illinois Basin

          

          

          4,584

          

          

          

          3,779

          

          

          

          805

          

          

          

          21%San Juan Basin

          

          

          5,941

          

          

          

          5,728

          

          

          

          213

          

          

          

          4%Total

          

          

          33,690

          

          

          

          32,528

          

          

          

          1,162

          

          

          

          4%Coal royalties revenues by regionCentral Appalachia

          

          $

          93,577

          

          

          $

          68,815

          

          

          $

          24,762

          

          

          

          36%Northern Appalachia

          

          

          6,568

          

          

          

          6,434

          

          

          

          134

          

          

          

          2%Illinois Basin

          

          

          10,451

          

          

          

          7,432

          

          

          

          3,019

          

          

          

          41%San Juan Basin

          

          

          12,238

          

          

          

          11,459

          

          

          

          779

          

          

          

          7%$

          122,834

          

          

          $

          94,140

          

          

          $

          28,694

          

          

          

          30%Less coal royalties expenses(1)

          

          

          (9,534

          )

          

          

          (5,540

          )

          

          

          (3,994

          )

          

          

          72%Net coal royalties revenues

          

          $

          113,300

          

          

          $

          88,600

          

          

          $

          24,700

          

          

          

          28%Coal royalties per ton by region ($/ton)Central Appalachia

          

          $

          4.78

          

          

          $

          3.66

          

          

          $

          1.12

          

          

          

          31%Northern Appalachia

          

          

          1.84

          

          

          

          1.53

          

          

          

          0.31

          

          

          

          20%Illinois Basin

          

          

          2.28

          

          

          

          1.97

          

          

          

          0.31

          

          

          

          16%San Juan Basin

          

          

          2.06

          

          

          

          2.00

          

          

          

          0.06

          

          

          

          3%$

          3.65

          

          

          $

          2.89

          

          

          $

          0.76

          

          

          

          26%Less coal royalties expenses(1)

          

          

          (0.28

          )

          

          

          (0.17

          )

          

          

          (0.11

          )

          

          

          65%Net coal royalties revenues

          

          $

          3.37

          

          

          $

          2.72

          

          

          $

          0.65

          

          

          

          24%
  (1)

          Our coal royalties expense is incurred primarily in the Central Appalachian region.
 59    TABLE OF CONTENTS Revenues Coal royalties revenues increased as a result of higher coal prices and additional tons being mined by our lessees. Coal royalty tons increased primarily due to higher production in the Central Appalachia and Illinois Basin regions, partially offset by a production decline in the Northern Appalachian region. The Central Appalachian region increase was the result of longwall mining and the timing of additional mining equipment added to our properties during 2008. The Illinois Basin region increase was primarily due to a full year of production in 2008 on coal reserves which were acquired in June 2007. The Northern Appalachian region decrease was a
result of adverse longwall mining conditions. Coal prices were higher on average due to international coal shortages on both the metallurgical and steam markets, which not only drove increases in export metallurgical pricing, but also allowed some higher thermal capacity steam coal to crossover into the metallurgical market; consequently, this caused the domestic steam coal markets to tighten and resulted in higher domestic pricing. Our coal royalties revenues are dependent on the prevailing coal prices received by our lessees, which are affected by numerous factors that are generally beyond our control. Coal prices are generally determined by national and regional supply and demand. Timber revenues increased due to increased harvesting from our September 2007 forestland acquisition. The average price received for timber increased 20% from $240 per Mbf in 2007 to $287 per Mbf in 2008. The oil and gas royalty revenues increase was primarily due to the increased royalties resulting from our October 2007 oil and gas royalty interest acquisition. Realized prices received for natural gas increased 31% from $8.11 per Mcf in 2007 to $10.63 per Mcf in 2008. Other revenues increased primarily due to increased coal transportation, or wheelage, fees attributable to greater production, increased forfeiture income and the recognition of a $0.8 million gain on the settlement of unmined coal. Expenses Coal royalties expenses increased due to additional mining by our lessees from subleased properties in the Central Appalachian region. Taxes other than income increased primarily due to increased severance taxes resulting from our September 2007 forestland acquisition and October 2007 oil and gas royalty interest acquisition. General and administrative expenses increased primarily due to increased staffing and related benefit costs. DD&A expenses increased due to increased depletion resulting from our September 2007 forestland acquisition, October 2007 oil and gas royalty interest acquisition and May 2008 coal reserves and forestland acquisition. A discussion of our DD&A methodologies is provided in the Critical Accounting Estimates that follows.
 60    TABLE OF CONTENTS Natural Gas Midstream Segment Year Ended December 31, 2009 Compared With Year Ended December 31, 2008 The following table sets forth a summary of certain financial and other data for our natural gas midstream segment and the percentage change for the periods presented:  Year Ended December 31,

          

          Favorable (Unfavorable)

          

          %Change2009

          

          2008Financial HighlightsRevenuesResidue gas

          

          $

          289,427

          

          

          $

          452,535

          

          

          $

          (163,108

          )

          

          

          (36%)Natural gas liquids

          

          

          182,794

          

          

          

          229,765

          

          

          

          (46,971

          )

          

          

          (20%)Condensate

          

          

          17,010

          

          

          

          26,009

          

          

          

          (8,999

          )

          

          

          (35%)Gathering, processing and transportation fees

          

          

          15,558

          

          

          

          11,693

          

          

          

          3,865

          

          

          

          33%Total natural gas midstream revenues(1)

          

          

          504,789

          

          

          

          720,002

          

          

          

          (215,213

          )

          

          

          (30%)Equity earnings in equity investment

          

          

          5,548

          

          

          

          2,408

          

          

          

          3,140

          

          

          

          130%Producer services

          

          

          1,767

          

          

          

          5,843

          

          

          

          (4,076

          )

          

          

          (70%)Total revenues

          

          

          512,104

          

          

          

          728,253

          

          

          

          (216,149

          )

          

          

          (30%)ExpensesCost of midstream gas purchased(1)

          

          

          406,583

          

          

          

          612,530

          

          

          

          205,947

          

          

          

          34%Operating

          

          

          26,451

          

          

          

          20,737

          

          

          

          (5,714

          )

          

          

          (28%)Taxes other than income

          

          

          3,090

          

          

          

          2,578

          

          

          

          (512

          )

          

          

          (20%)General and administrative

          

          

          16,301

          

          

          

          14,300

          

          

          

          (2,001

          )

          

          

          (14%)Impairments

          

          

          

          

          

          

          31,801

          

          

          

          31,801

          

          

          

          100%Depreciation and amortization

          

          

          38,905

          

          

          

          27,361

          

          

          

          (11,544

          )

          

          

          (42%)Total operating expenses

          

          

          491,330

          

          

          

          709,307

          

          

          

          217,977

          

          

          

          31%Operating income

          

          $

          20,774

          

          

          $

          18,946

          

          

          $

          1,828

          

          

          

          10%Operating StatisticsSystem throughput volumes (MMcf)

          

          

          121,335

          

          

          

          98,683

          

          

          

          22,652

          

          

          

          23%Daily throughput volumes (MMcfd)

          

          

          332

          

          

          

          270

          

          

          

          62

          

          

          

          23%Gross margin

          

          $

          98,206

          

          

          $

          107,472

          

          

          $

          (9,266

          )

          

          

          (9%)Cash impact of derivatives

          

          

          10,566

          

          

          

          (31,709

          )

          

          

          42,275

          

          

          

          133%Gross margin, adjusted for impact of derivatives

          

          $

          108,772

          

          

          $

          75,763

          

          

          $

          33,009

          

          

          

          44%Gross margin ($/Mcf)

          

          $

          0.81

          

          

          $

          1.09

          

          

          $

          (0.28

          )

          

          

          (26%)Cash impact of derivatives ($/Mcf)

          

          

          0.09

          

          

          

          (0.32

          )

          

          

          0.41

          

          

          

          128%Gross margin, adjusted for impact of derivatives ($/Mcf)

          

          $

          0.90

          

          

          $

          0.77

          

          

          $

          0.13

          

          

          

          17%
  (1)

          In 2009 and 2008, we recorded $72.5 million and $127.9 million of natural gas midstream revenue and $72.5 million and $127.9 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG LP and the subsequent sale of that gas to third parties. We take title to the gas prior to transporting it to third parties. These transactions do not impact the gross margin.
 61    TABLE OF CONTENTS Gross Margin Gross margin is the difference between our natural gas midstream revenues and our cost of midstream gas purchased. Natural gas midstream revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to our gas processing plants. Cost of midstream gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts. The gross margin decrease was a result of lower commodity pricing and lower fractionation, or frac spreads, partially offset by increased system throughput volumes and increased natural gas processing capacity. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis. Drilling activities by producers central to our natural gas gathering and processing plants were at reduced levels from the previous year due to lower natural gas prices. However, the 2009 system throughput volumes benefited from the results of drilling activity in 2008 and the first part of 2009. The expansion and acquisition activity, especially in the Panhandle System, has alleviated pipeline pressures and allowed us to move all of our gas in this region to our processing plants. As noted above, in July 2009 we completed an acquisition of gas processing and residue pipeline facilities in western Oklahoma. The acquired assets included the 60 MMcfd
Sweetwater plant. Additionally, we completed a 40 MMcfd processing plant expansion in our Spearman complex that was put into service on July 31, 2009. The acquired and expanded processing facilities increased our processing capacity in the Panhandle System to 260 MMcfd and overall processing capacity to 400 MMcfd. The increased processing capacity has allowed us to process natural gas volumes that were being bypassed due to processing capacity constraints in the Panhandle System and has alleviated pipeline pressure-related volume constraints in the eastern portion of the Panhandle. During 2009, we generated a majority of the gross margin from contractual arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. See Item 1, Business  Contracts  Natural Gas Midstream Segment, for discussion of the types of contracts utilized by the natural gas midstream segment. As part of our risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. See Note 6 to the Consolidated Financial Statements for a description of our derivatives program. On a per Mcf basis, adjusted for
the impact of our commodity derivative instruments, our gross margin increased in 2009 by $0.13, or 17%. This favorable impact of commodity derivatives is a result of overall lower commodity prices during 2009 and the expiration of older derivative instruments. Revenues Other Than Gross Margin Equity earnings in equity investment increased due to a full year of results in 2009 compared with a partial year in 2008. In April 2008, we acquired a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyomings Powder River Basin. In addition, revenues from the joint venture have grown in 2009 due to mainline volume increases in the Powder River Basin. Producer services revenues decreased due to a negative relative change in the natural gas indices on which our purchases and sales of natural gas are based and a decrease in marketing fees resulting from lower commodity prices. Expenses Operating expenses increased due to prior and current years acquisitions, expansion projects, compressor rentals and labor costs. Increased costs for compressor rentals and labor costs were incurred due to expanding our footprint in the Panhandle System. Taxes other than income increased due to higher property taxes. The increase in property taxes was a result of acquisitions and plant expansions. General and administrative expenses increased due to increased staffing and related benefit costs. The increase was primarily attributable to labor costs resulting from the 2008 acquisitions and plant expansions. We incurred a full year of salaries and benefits in 2009 compared with a partial year in 2008.
 62    TABLE OF CONTENTS Impairment expense in 2008 was the result of a reduction in the value of goodwill. We test goodwill for impairment on an annual basis, at a minimum, and more frequently if a triggering event occurs. The goodwill testing during the fourth quarter of 2008 identified a goodwill impairment loss of $31.8 million. The impairment charge, which was triggered by fourth quarter declines in oil and gas spot and futures prices and a decline in our market capitalization, reduced to zero all goodwill recorded in conjunction with acquisitions made by our natural gas midstream segment in 2008 and prior years. Depreciation and amortization expenses increased primarily due to acquisitions, capital expansions on the Spearman and Sweetwater plants and new well connections in existing areas of operation. Year Ended December 31, 2008 Compared With Year Ended December 31, 2007 The following table sets forth a summary of certain financial and other data for our natural gas midstream segment and the percentage change for the periods presented:  Year Ended December 31,

          

          Favorable (Unfavorable)

          

          %Change2008

          

          2007Financial HighlightsRevenuesResidue gas

          

          $

          452,535

          

          

          $

          242,129

          

          

          $

          210,406

          

          

          

          87%Natural gas liquids

          

          

          229,765

          

          

          

          172,144

          

          

          

          57,621

          

          

          

          33%Condensate

          

          

          26,009

          

          

          

          13,889

          

          

          

          12,120

          

          

          

          87%Gathering, processing and transportation fees

          

          

          11,693

          

          

          

          5,012

          

          

          

          6,681

          

          

          

          133%Total natural gas midstream revenues(1)

          

          

          720,002

          

          

          

          433,174

          

          

          

          286,828

          

          

          

          66%Equity earnings in equity investment

          

          

          2,408

          

          

          

          

          

          

          

          2,408

          

          

          

          Producer services

          

          

          5,843

          

          

          

          4,632

          

          

          

          1,211

          

          

          

          26%Total revenues

          

          

          728,253

          

          

          

          437,806

          

          

          

          290,447

          

          

          

          66%ExpensesCost of midstream gas purchased(1)

          

          

          612,530

          

          

          

          343,293

          

          

          

          (269,237

          )

          

          

          (78%)Operating

          

          

          20,737

          

          

          

          12,893

          

          

          

          (7,844

          )

          

          

          (61%)Taxes other than income

          

          

          2,578

          

          

          

          1,926

          

          

          

          (652

          )

          

          

          (34%)General and administrative

          

          

          14,300

          

          

          

          11,958

          

          

          

          (2,342

          )

          

          

          (20%)Impairments

          

          

          31,801

          

          

          

          

          

          

          

          (31,801

          )

          

          

          Depreciation and amortization

          

          

          27,361

          

          

          

          18,822

          

          

          

          (8,539

          )

          

          

          (45%)Total operating expenses

          

          

          709,307

          

          

          

          388,892

          

          

          

          (320,415

          )

          

          

          (82%)Operating income

          

          $

          18,946

          

          

          $

          48,914

          

          

          $

          (29,968

          )

          

          

          (61%)Operating StatisticsSystem throughput volumes (MMcf)

          

          

          98,683

          

          

          

          67,810

          

          

          

          30,873

          

          

          

          46%Daily throughput volumes (MMcfd)

          

          

          270

          

          

          

          186

          

          

          

          84

          

          

          

          45%Gross margin

          

          $

          107,472

          

          

          $

          89,881

          

          

          $

          17,591

          

          

          

          20%Cash impact of derivatives

          

          

          (31,709

          )

          

          

          (13,184

          )

          

          

          (18,525

          )

          

          

          (141%)Gross margin, adjusted for impact of derivatives

          

          $

          75,763

          

          

          $

          76,697

          

          

          $

          (934

          )

          

          

          (1%)Gross margin ($/Mcf)

          

          $

          1.09

          

          

          $

          1.33

          

          

          $

          (0.24

          )

          

          

          (18%)Cash impact of derivatives ($/Mcf)

          

          

          (0.32

          )

          

          

          (0.19

          )

          

          

          (0.13

          )

          

          

          (68%)Gross margin, adjusted for impact of derivatives ($/Mcf)

          

          $

          0.77

          

          

          $

          1.14

          

          

          $

          (0.37

          )

          

          

          (32%)
  (1)

          In 2008, we recorded $127.9 million of natural gas midstream revenue and $127.9 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG LP and the subsequent sale of that gas to third parties. We take title to the gas prior to transporting it to third parties. These transactions do not impact the gross margin.
 63    TABLE OF CONTENTS Gross Margin Gross margin is the difference between our natural gas midstream revenues and our cost of midstream gas purchased. Natural gas midstream revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to our gas processing plants. Cost of midstream gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts. The gross margin increase was a result of higher commodity pricing, increased system throughput volume production and higher frac spreads during 2008 compared to 2007. The system throughput volumes increase is due primarily to the Crossroads plant in East Texas, which became fully operational in 2008, and to the Lone Star acquisition, which was consummated in the third quarter of 2008. Also, the continued development by producers operating in the vicinity of the Panhandle System, as well as our success in contracting and connecting new supply contributed to the increase in throughput volume. During 2008, we generated a majority of the gross margin from contractual arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. See Item 1, Business  Contracts  Natural Gas Midstream Segment, for discussion of the types of contracts utilized by the natural gas midstream segment. As part of our risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. See Note 6 to the Consolidated Financial Statements for a description of our derivatives program. On a per Mcf basis, adjusted for
the impact of our commodity derivative instruments for which we discontinued hedge accounting in 2006, our gross margin decreased by $0.37, or 32%. Gross margins during the first part of 2008 continued to increase given the favorable pricing environment, such as higher commodity prices and frac spreads, and increased system throughput volumes. However, margins decreased towards the end of 2008 due to a significant decrease in the prices of NGLs as a result of reduced industrial demand in a weakening economy. The gross margin on a per Mcf basis decreased in 2008 due to an increase in fee-based system throughput volumes. These increased volumes are associated with our 2008 expansions and acquisitions. Revenues Other Than Gross Margin Equity earnings in equity investment increased due to our April 2008 acquisition of a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyomings Powder River Basin. We acquired the member interest in April 2008. Producer services revenues increased due to an increase in agent fees for the marketing of Penn Virginias and third parties natural gas production. Agent fees increased primarily due to increases in Penn Virginias natural gas production as well as increases in the price of natural gas. Expenses Operating expenses increased due to expenses related to our expanding footprint in areas of operation, including acquisitions and the addition of the Spearman and Crossroads plants. These expenses include increased repairs and maintenance expenses, increased compressor rentals, chemical and treating expenses and increased labor costs. Taxes other than income decreased due to higher property taxes. The increase in property taxes was a result of acquisitions and plant expansions. General and administrative expenses increased due to increased staffing and related benefit costs. The increase in personnel was primarily attributable to acquisitions, plant expansions and well connects in established areas of operation.
 64    TABLE OF CONTENTS Impairment expense in 2008 was the result of a reduction in the value of goodwill. We test goodwill for impairment on an annual basis, at a minimum, and more frequently if a triggering event occurs. The goodwill testing during the fourth quarter of 2008 identified a goodwill impairment loss of $31.8 million. The impairment loss, which was triggered by fourth quarter declines in oil and gas spot and futures prices and a decline in our market capitalization, reduced to zero all goodwill recorded in conjunction with acquisitions made by our natural gas midstream segment in 2008 and prior years. Depreciation and amortization expenses increased primarily due to capital expansions on the Spearman and Crossroads plants and acquisitions. Other Our other results consist of interest expense and derivative gains and losses. The following table sets forth a summary of certain financial data for our other results for the periods presented:  Year Ended December 31,2009

          

          2008

          

          2007Operating income

          

          $

          108,302

          

          

          $

          115,242

          

          

          $

          117,725Other income (expense)Interest expense

          

          

          (24,653

          )

          

          

          (24,672

          )

          

          

          (17,338

          )Other

          

          

          1,280

          

          

          

          (2,907

          )

          

          

          1,804Derivatives

          

          

          (19,714

          )

          

          

          16,837

          

          

          

          (45,568

          )Net income

          

          $

          65,215

          

          

          $

          104,500

          

          

          $

          56,623
 Interest Expense.  Our consolidated interest expense for the periods presented is comprised of the following:  Year Ended December 31,Source

          

          2009

          

          2008

          

          2007Interest on borrowings

          

          $

          21,523

          

          

          $

          23,641

          

          

          $

          18,861Capitalized interest(1)

          

          

          (226

          )

          

          

          (675

          )

          

          

          (786

          )Interest rate swaps

          

          

          3,356

          

          

          

          1,706

          

          

          

          (737

          )Total interest expense

          

          $

          24,653

          

          

          $

          24,672

          

          

          $

          17,338
  (1)

          Capitalized interest was primarily related to the construction of our natural gas gathering facilities. Our consolidated interest expense remained relatively constant at $24.7 million for the years ended December 31, 2009 and 2008. Even though interest rates decreased during 2009, this decrease was offset in part by the higher level of outstanding borrowings during 2009 as compared to 2008. There were also higher levels of debt issuance costs expensed in 2009 related to the March 2009 increase in the size of our Revolver from $700.0 million to $800.0 million. The increase in interest expense in 2008 compared to 2007 is primarily due to the increase in our average debt balance. The interest capitalized in all three years related to construction of the Spearman and Crossroads plants. In connection with the Interest Rate Swaps, we recognized $3.4 million in net hedging losses in interest expense in 2009. The increase over prior years relates to the decrease in LIBOR rates during 2009 relative to the fixed interest rates of the Interest Rate Swaps. Derivatives.  Our results of operations and operating cash flows were impacted by changes in market prices for NGLs, crude oil and natural gas prices, as well as the Interest Rate Swaps.
 65    TABLE OF CONTENTS Commodity markets are volatile, and as a result, our hedging activity results can vary significantly. Our results of operations are affected by the volatility of changes in fair value, which fluctuate with changes in NGL, crude oil and natural gas prices. We determine the fair values of our commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties for derivatives in an asset position, and our own credit risk derivatives in a liability position. During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps are recognized in the derivatives line item on our Consolidated Statements of Income. Our derivative activity for the periods presented is summarized below:  Year Ended December 31,2009

          

          2008

          

          2007Interest Rate Swap unrealized derivative gain

          

          $

          3,260

          

          

          $

          

          

          

          $

          Interest Rate Swap realized derivative loss

          

          

          (7,566

          )

          

          

          

          

          

          

          Natural gas midstream commodity unrealized derivative gain (loss)

          

          

          (25,974

          )

          

          

          55,303

          

          

          

          (27,789

          )Natural gas midstream commodity realized derivative gain (loss)

          

          

          10,566

          

          

          

          (38,466

          )

          

          

          (17,779

          )Total derivative gain (loss)

          

          $

          (19,714

          )

          

          $

          16,837

          

          

          $

          (45,568

          )
 Environmental Matters Our operations and those of our lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of our coal property leases impose liability on the relevant lessees for all environmental and reclamation liabilities arising under those laws and regulations. The lessees are bonded and have indemnified us against any and all future environmental liabilities. We regularly visit our coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. Our management believes that our operations and
those of our lessees comply with existing laws and regulations and does not expect any material impact on our financial condition or results of operations. As of December 31, 2009 and 2008, our environmental liabilities were $1.0 million and $1.2 million, which represents our best estimate of the liabilities as of those dates related to our coal and natural resource management and natural gas midstream businesses. We have reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future. For a summary of the environmental laws and regulations applicable to our operations, see Item 1, Business  Government Regulation and
Environmental Matters. Critical Accounting Estimates The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. We consider the following to be the most critical accounting policies which involve the judgment of our management. Coal Royalties Revenues We recognize coal royalties revenues on the basis of tons of coal sold by our lessees and the corresponding revenues from those sales. Since we do not operate any coal mines, we do not have access to actual production and revenues information until approximately 30 days following the month of production. Therefore, our financial results include estimated revenues and accounts receivable for the month of production. We record any differences, which historically have not been significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized.
 66    TABLE OF CONTENTS Natural Gas Midstream Gross Margin Our gross margin is the difference between our natural gas midstream revenues and our cost of midstream gas purchased. Natural gas midstream revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to our gas processing plants. We recognize revenues from the sale of NGLs and residue gas when we sell the NGLs and residue gas produced at our gas processing plants. We recognize gathering and transportation revenues based upon actual volumes delivered. Cost
of midstream gas purchased consists of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts. Due to the time needed to gather information from various purchasers and measurement locations and then calculate volumes delivered, the collection of natural gas midstream revenues and the calculation of the cost of midstream gas purchased may take up to 30 days following the month of production. Therefore, we make accruals for revenues and accounts receivable and the related cost of midstream gas purchased and accounts payable based on estimates of natural gas purchased and NGLs and residue gas sold. We record any differences, which historically have not been significant, between the actual amounts ultimately received or paid and the original
estimates in the period they become finalized. Depreciation, Depletion and Amortization We compute depreciation and amortization of property, plant and equipment using the straight-line balance method over the estimated useful life of each asset. Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by our own geologists and outside consultants. Our estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. From time to time, we carry out core-hole drilling activities on our coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling
activities are expensed as incurred. We deplete timber using a methodology consistent with the units-of-production method, but that is based on the quantity of timber harvested. We determine depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves. When we retire or sell an asset, we remove its cost and related accumulated depreciation and amortization from our Consolidated Balance Sheets. Upon sale, we record the difference between the net book value, net of any assumed asset retirement obligation, and proceeds from disposition as a gain or loss. Intangible assets are primarily associated with assumed contracts, customer relationships and rights-of-way. These intangible assets are amortized over periods of up to 20 years, the period in which benefits are derived from the contracts, customer relationships and rights-of-way, and are combined with property, plant and equipment and are reviewed for impairment. See Note 10 to the Consolidated Financial Statements for a more detailed description of our intangible assets. Derivative Activities From time to time, we enter into derivative financial instruments to mitigate our exposure to natural gas, crude oil and NGL price volatility. The derivative financial instruments, which are placed with financial institutions that we believe are of acceptable credit risks, take the form of collars and swaps. All derivative financial instruments are recognized in our Consolidated Financial Statements at fair value. The fair values of our derivative instruments are determined based on discounted cash flows derived from quoted forward prices. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by
the board of directors of our general partner. During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps are recognized in the derivatives line item on our Consolidated Statements of Income. At December 31, 2009, a $1.4 million loss
 67    TABLE OF CONTENTS remained in accumulated other comprehensive income related to the Interest Rate Swaps. The $1.4 million loss will be recognized in interest expense as the Interest Rate Swaps settle. We recognize changes in fair value in earnings currently in the derivatives line on the Consolidated Statements of Income. We have experienced and could continue to experience significant changes in the estimate of unrealized derivative gains or losses recognized due to fluctuations in the value of these commodity derivative contracts. The discontinuation of hedge accounting has no impact on our reported cash flows, although our results of operations are affected by the volatility of mark-to-market gains and losses and changes in fair value, which fluctuate with changes in natural gas, crude oil and NGL prices. These fluctuations could be significant
in a volatile pricing environment. See Note 6 to the Consolidated Financial Statements for a further description of our derivatives program. Impairment of Goodwill Goodwill has been allocated to our natural gas midstream segment and recorded in connection with acquisitions and business combinations. This goodwill is not amortized, but tested for impairment at least annually. Goodwill impairment is determined using a two-step test. The first step of the impairment test is used to identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value of a reporting unit exceeds its book value, goodwill of the reporting unit is not considered impaired, and the second step of the impairment test is not required. If the book value of a reporting unit
exceeds its fair value, the second step of the impairment test is performed to measure the amount of impairment loss, if any. The second step of the impairment test compares the implied fair value of the reporting units goodwill with the book value of that goodwill. If the book value of the reporting units goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. We tested goodwill for impairment during the fourth quarter of 2008 and recorded a goodwill impairment loss of $31.8 million. The impairment loss, which was triggered by fourth quarter declines in oil and gas spot and futures prices and a decline in our market capitalization, reduced to zero all goodwill recorded in conjunction with acquisitions made by the natural gas midstream segment in 2008 and prior years. This loss was recorded in the impairment line on our Consolidated Statements of Income. Our goodwill balance remained at zero at December 31, 2009. See Note 9 to the Consolidated Financial Statements for a description of goodwill and the
related impairment loss. Equity Investments We use the equity method of accounting to account for our 25% member interest in Thunder Creek, as well as our investment in a 50% member interest in a coal handling joint venture, recording the initial investment at cost. Subsequently, the carrying amount of the investment is increased to reflect our share of income of the investee and capital contributions, and is reduced to reflect our share of losses of the investee or distributions received from the investee as the joint ventures report them. Our share of earnings or losses from Thunder Creek is included in other revenues on the Consolidated Statements of Income, and our share of earnings and
losses from the coal handling joint venture is included in coal services on the Consolidated Statements of Income. Other revenues and coal services revenues also include amortization of the amount of the equity investments that exceed our portion of the underlying equity in net assets (the inside/outside basis). We record this amortization over the life of the contracts acquired in the Thunder Creek acquisition and the life of the coal services contracts acquired in the acquisition of the coal handling joint venture. New Accounting Standards See Note 2 to the Consolidated Financial Statements for a description of recent accounting standards.
 68    TABLE OF CONTENTS Item 7A

          Quantitative and Qualitative Disclosures About Market Risk Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are as follows: 

          Price Risk 

          Interest Rate Risk 

          Customer Credit Risk As a result of our risk management activities as discussed below, we are also exposed to counterparty risk with financial institutions with whom we enter into these risk management positions. Sensitivity to these risks has heightened due to the state of the global economy, including financial and credit markets. We have completed a number of acquisitions in recent years. See Note 3 to the Consolidated Financial Statements for a description of our material acquisitions. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, and the resulting amount of goodwill, if any. Changes in operations, further decreases in commodity prices, changes in the business environment or
further deteriorations of market conditions could substantially alter managements assumptions and could result in lower estimates of values of acquired assets or of future cash flows. If these events occur, it is reasonably possible that we could record a significant impairment loss on our Consolidated Statements of Income. Price Risk Our price risk management program permits the utilization of derivative financial instruments (such as futures, forwards, option contracts and swaps) to seek to mitigate the price risks associated with fluctuations in natural gas, NGL and crude oil prices as they relate to our natural gas midstream business. The derivative financial instruments are placed with major financial institutions that we believe are of acceptable credit risk. The fair values of our price risk management activities are significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil. At December 31, 2009, we reported a net commodity derivative liability related to the natural gas midstream segment of $3.2 million that is with six counterparties and is substantially concentrated with three of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We neither paid nor received collateral with respect to our derivative positions. No significant uncertainties related to the collectability of amounts owed to us exist with regard to these counterparties. In 2009, we reported a net derivative loss of $19.7 million. Some of our commodity derivative financial instruments initially qualified as cash flow hedges, and changes in the effective portion of fair value from these contracts were deferred in accumulated comprehensive income until the hedged transactions settled. When we discontinued hedge accounting for commodity derivatives in 2006, a net loss remained in accumulated other comprehensive income. As the hedged transactions settled in 2007 and 2008, we recognized these deferred changes in fair value in revenues and cost of gas purchased in our Consolidated Statements of Income. As of December 31,
2008, no net losses remained in accumulated other comprehensive income related to our natural gas midstream commodity derivatives. Because we no longer use hedge accounting for our commodity derivatives, we recognize changes in fair value in earnings currently in the derivatives line on the Consolidated Statements of Income. We have experienced and could continue to experience significant changes in the estimate of unrealized derivative gains or losses recognized due to fluctuations in the value of these commodity derivative contracts. The discontinuation of hedge accounting has no impact on our reported cash flows, although our results of operations are affected by the volatility of mark-to-market gains and losses and changes in fair value, which fluctuate with changes in
natural gas crude oil and NGL prices. These fluctuations could be significant in a volatile pricing environment.
 69    TABLE OF CONTENTS The following table lists our commodity derivative agreements and their fair values as of December 31, 2009:  Average Volume Per Day

          

          Swap Price

          

          Weighted Average Price

          

          Fair Value at December 31, 2009Put

          

          Call(In Thousands)Crude Oil Collar

          

          

          (barrels)

          

          

          

          

          

          

          

          ($ per barrel)First Quarter 2010 through Fourth Quarter 2010

          

          

          750

          

          

          

          

          

          

          $

          70.00

          

          

          $

          81.25

          

          

          $

          (1,329

          )First Quarter 2010 through Fourth Quarter 2010

          

          

          1,000

          

          

          

          

          

          

          $

          68.00

          

          

          $

          80.00

          

          

          

          (2,171

          )First Quarter 2011 through Fourth Quarter 2011

          

          

          400

          

          

          

          

          

          

          $

          75.00

          

          

          $

          98.50

          

          

          

          18Natural Gas Purchase Swap

          

          

          (MMBtu)

          

          

          

          ($ per MMBtu)First Quarter 2010 through Fourth Quarter 2010

          

          

          5,000

          

          

          $

          5.815

          

          

          

          

          

          

          

          

          

          

          

          (41

          )First Quarter 2011 through Fourth Quarter 2011

          

          

          3,000

          

          

          $

          6.430

          

          

          

          

          

          

          

          

          

          

          

          (99

          )NGL  Natural Gasoline Collar

          

          

          (gallons)

          

          

          

          

          

          

          

          ($ per gallon)First Quarter 2011 through Fourth Quarter 2011

          

          

          60,000

          

          

          

          

          

          

          $

          1.55

          

          

          $

          1.92

          

          

          

          (945

          )Settlements to be received in subsequent period

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          1,331$

          (3,236

          )
 We estimate that a $5.00 per barrel increase in the crude oil price would decrease the fair value of our crude oil collars by $3.1 million. We estimate that a $5.00 per barrel decrease in the crude oil price would increase the fair value of our crude oil collars by $2.8 million. We estimate that a $1.00 per MMBtu increase in the natural gas price would increase the fair value of our natural gas purchase swaps by $2.7 million. We estimate that a $1.00 per MMBtu decrease in the natural gas price would decrease the fair value of our natural gas purchase swaps by $2.7 million. We estimate that a $0.11 per gallon increase in the natural gasoline (a
natural gas liquid, NGL) price would decrease the fair value of our natural gasoline collar by $1.8 million. We estimate that a $0.11 per gallon decrease in the natural gasoline price would increase the fair value of our natural gasoline collar by $1.7 million. We estimate that, excluding the effects of derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, our natural gas midstream gross margin and operating income in 2010 would increase or decrease by $6.9 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, our natural gas midstream gross margin and operating income in 2010 would increase or decrease by $11.5 million. This assumes that natural gas prices, crude oil prices and inlet volumes remain constant at anticipated levels. These estimated changes in our gross margin and operating income
exclude potential cash receipts or payments in settling these derivative positions. Interest Rate Risk As of December 31, 2009, we had $620.1 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We entered into the Interest Rate Swaps to establish fixed interest rates on a portion of the outstanding indebtedness under the Revolver. Until March 2010, the notional amounts of the Interest Rate Swaps total $310.0 million, or 50.0% of our outstanding indebtedness under the Revolver as of December 31, 2009, with us paying a weighted average fixed rate of 3.54% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From March 2010 to December 2011,
the notional amounts of the Interest Rate Swaps total $250.0 million, or 40.3% of our outstanding indebtedness under the Revolver as of December 31, 2009, with us paying a weighted average fixed rate of 3.37% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From December 2011 to December 2012, the notional amounts of the Interest Rate Swaps
 70    TABLE OF CONTENTS total $100.0 million, or 16.1% of our outstanding indebtedness under the Revolver as of December 31, 2009,with us paying a weighted average fixed rate of 2.09% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. The Interest Rate Swaps extend one year past the current maturity of the Revolver. A 1% increase in short-term interest rates on the floating rate debt outstanding under the Revolver (net of amounts fixed through the Interest Rate Swaps) as of December 31, 2009 would cost us approximately $3.1 million in additional interest expense per year. During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps are recognized in earnings currently. Therefore, our results of operations are affected by the volatility of changes in fair value, which fluctuates with changes in interest rates. These fluctuations could be significant. See Note 6 to the Consolidated Financial Statements for a further description of our derivatives program. Customer Credit Risk We are exposed to the credit risk of our customers and lessees. Approximately 84%, or $69.3 million, of our consolidated accounts receivable at December 31, 2009 resulted from our natural gas midstream segment and approximately 16%, or $13.0 million, resulted from our coal and natural resource management segment. Approximately $11.6 million of the natural gas midstream segments receivables at December 31, 2009 related to one customer, Tenaska Marketing Ventures. At December 31, 2009, 17% of our natural gas midstream segment accounts receivable and 14% of our consolidated accounts receivable related to this natural gas midstream customer. No
significant uncertainties related to the collectability of amounts owed to us exist in regard to this natural gas midstream customer. This customer concentration increases our exposure to credit risk on our receivables, since the financial insolvency of this customer could have a significant impact on our results of operations. If our customers or lessees become financially insolvent, they may not be able to continue to operate or meet their payment obligations. Any material losses as a result of customer defaults could harm and have an adverse effect on our business, financial condition or results of operations. Substantially all of our trade accounts receivable are unsecured. To mitigate the risks of nonperformance by our customers, we perform ongoing credit evaluations of our existing customers. We monitor individual customer payment capability in granting credit arrangements to new customers by performing credit evaluations, seek to limit credit to amounts we believe the customers can pay, and maintain reserves we believe are adequate to cover exposure for uncollectable accounts. As of December 31, 2009, no receivables were collateralized, and we had recorded a $1.2 million allowance for doubtful accounts in the natural gas midstream segment.
 71    TABLE OF CONTENTS Item 8 Financial Statements and Supplementary Data PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS  PageReport of Independent Registered Public Accounting Firm





73Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting





74Consolidated Financial Statements





75Notes to the Consolidated Financial Statements and Supplementary Data





79
 72    TABLE OF CONTENTS REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Partners of Penn Virginia Resource Partners, L.P.: We have audited the accompanying consolidated balance sheets of Penn Virginia Resource Partners, L.P., and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income, partners capital and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2009. These consolidated financial statements are the responsibility of the Partnerships management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Penn Virginia Resource Partners, L.P. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Penn Virginia Resource Partners, L.P.s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control  Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 1, 2010, expressed an unqualified opinion on the effectiveness of the Partnerships internal control over financial reporting. /s/ KPMG LLP Houston, Texas March 1, 2010
 73    TABLE OF CONTENTS REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Partners of Penn Virginia Resource Partners, L.P.: We have audited Penn Virginia Resource Partners, L.P.s internal control over financial reporting as of December 31, 2009, based on criteria established inInternal Control  Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Penn Virginia Resource Partners, L.P.s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Managements Annual Report on Internal Control Over Financial Reporting (Item 9A(b) herein).
Our responsibility is to express an opinion on the Partnerships internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, Penn Virginia Resource Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control  Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Penn Virginia Resource Partners, L.P. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income, partners capital and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated March 1, 2010 expressed an unqualified opinion on those consolidated financial statements. /s/ KPMG LLP Houston, TexasMarch 1, 2010
 74    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   CONSOLIDATED STATEMENTS OF INCOME (in thousands, except per unit amounts)  Year Ended December 31,2009

          

          2008

          

          2007RevenuesNatural gas midstream

          

          $

          504,789

          

          

          $

          720,002

          

          

          $

          433,174Coal royalties

          

          

          120,435

          

          

          

          122,834

          

          

          

          94,140Coal services

          

          

          7,332

          

          

          

          7,355

          

          

          

          7,252Other

          

          

          24,148

          

          

          

          31,389

          

          

          

          14,879Total revenues

          

          

          656,704

          

          

          

          881,580

          

          

          

          549,445ExpensesCost of midstream gas purchased

          

          

          406,583

          

          

          

          612,530

          

          

          

          343,293Operating

          

          

          35,111

          

          

          

          32,677

          

          

          

          20,964Taxes other than income

          

          

          4,794

          

          

          

          4,258

          

          

          

          3,036General and administrative

          

          

          30,168

          

          

          

          26,906

          

          

          

          22,915Impairments

          

          

          1,511

          

          

          

          31,801

          

          

          

          Depreciation, depletion and amortization

          

          

          70,235

          

          

          

          58,166

          

          

          

          41,512Total expenses

          

          

          548,402

          

          

          

          766,338

          

          

          

          431,720Operating income

          

          

          108,302

          

          

          

          115,242

          

          

          

          117,725Other income (expense)Interest expense

          

          

          (24,653

          )

          

          

          (24,672

          )

          

          

          (17,338

          )Other

          

          

          1,280

          

          

          

          (2,907

          )

          

          

          1,804Derivatives

          

          

          (19,714

          )

          

          

          16,837

          

          

          

          (45,568

          )Net income

          

          $

          65,215

          

          

          $

          104,500

          

          

          $

          56,623General partners interest in net income

          

          $

          24,962

          

          

          $

          23,715

          

          

          $

          14,224Limited partners interest in net income

          

          $

          40,253

          

          

          $

          80,785

          

          

          $

          42,399Basic and diluted net income per limited partner unit (see Note 14)

          

          $

          0.76

          

          

          $

          1.63

          

          

          $

          0.92Weighted average number of units outstanding, basic and diluted

          

          

          51,799

          

          

          

          49,495

          

          

          

          46,103
 See accompanying notes to consolidated financial statements.
 75    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   CONSOLIDATED BALANCE SHEETS (in thousands, except unit amounts)  December 31,2009

          

          December 31, 2008AssetsCurrent assetsCash and cash equivalents

          

          $

          8,659

          

          

          $

          9,484Accounts receivable, net of allowance for doubtful accounts

          

          

          82,321

          

          

          

          73,267Derivative assets

          

          

          1,331

          

          

          

          30,431Other current assets

          

          

          4,468

          

          

          

          4,263Total current assets

          

          

          96,779

          

          

          

          117,445Property, plant and equipment

          

          

          1,162,070

          

          

          

          1,093,526Accumulated depreciation, depletion and amortization

          

          

          (261,226

          )

          

          

          (198,407

          )Net property, plant and equipment

          

          

          900,844

          

          

          

          895,119Equity investments

          

          

          87,601

          

          

          

          78,442Intangible assets, net

          

          

          83,741

          

          

          

          92,672Derivative assets

          

          

          1,284

          

          

          

          Other long-term assets

          

          

          37,811

          

          

          

          35,141Total assets

          

          $

          1,208,060

          

          

          $

          1,218,819Liabilities and Partners CapitalCurrent liabilitiesAccounts payable

          

          $

          60,679

          

          

          $

          60,390Accrued liabilities

          

          

          9,726

          

          

          

          10,796Deferred income

          

          

          3,839

          

          

          

          4,842Derivative liabilities

          

          

          11,251

          

          

          

          13,585Total current liabilities

          

          

          85,495

          

          

          

          89,613Deferred income

          

          

          5,482

          

          

          

          6,150Other liabilities

          

          

          16,191

          

          

          

          17,359Derivative liabilities

          

          

          4,285

          

          

          

          6,915Long-term debt

          

          

          620,100

          

          

          

          568,100Commitments and contingencies (see Note 17)Partners capitalCommon units (51,798,895 at December 31, 2009 and 2008)

          

          

          471,068

          

          

          

          526,927General partner interest

          

          

          6,834

          

          

          

          8,000Accumulated other comprehensive income

          

          

          (1,395

          )

          

          

          (4,245

          )Total partners' capital

          

          

          476,507

          

          

          

          530,682Total liabilities and partners capital

          

          $

          1,208,060

          

          

          $

          1,218,819
 See accompanying notes to consolidated financial statements.
 76    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)  Year Ended December 31,2009

          

          2008

          

          2007Cash flows from operating activitiesNet income

          

          $

          65,215

          

          

          $

          104,500

          

          

          $

          56,623Adjustments to reconcile net income to net cash provided by operating activities:Depreciation, depletion and amortization

          

          

          70,235

          

          

          

          58,166

          

          

          

          41,512Impairments

          

          

          1,511

          

          

          

          31,801

          

          

          

          Commodity derivative contracts:Total derivative losses (gains)

          

          

          22,700

          

          

          

          (11,357

          )

          

          

          50,163Cash settlements of derivatives

          

          

          3,000

          

          

          

          (38,466

          )

          

          

          (17,779

          )Non-cash interest expense

          

          

          4,391

          

          

          

          2,693

          

          

          

          678Equity earnings, net of distributions received

          

          

          (2,537

          )

          

          

          (224

          )

          

          

          (285

          )Other

          

          

          765

          

          

          

          (1,408

          )

          

          

          (845

          )Changes in operating assets and liabilities:Accounts receivable

          

          

          (8,387

          )

          

          

          5,607

          

          

          

          (12,701

          )Accounts payable

          

          

          1,121

          

          

          

          (4,615

          )

          

          

          13,435Accrued liabilities

          

          

          3,440

          

          

          

          (3,613

          )

          

          

          (1,415

          )Deferred income

          

          

          (1,671

          )

          

          

          1,145

          

          

          

          (1,799

          )Other asset and liabilities

          

          

          189

          

          

          

          (5,053

          )

          

          

          237Net cash provided by operating activities

          

          

          159,972

          

          

          

          139,176

          

          

          

          127,824Cash flows from investing activitiesAcquisitions

          

          

          (29,580

          )

          

          

          (260,376

          )

          

          

          (176,917

          )Additions to property, plant and equipment

          

          

          (51,097

          )

          

          

          (71,652

          )

          

          

          (48,123

          )Other

          

          

          1,147

          

          

          

          998

          

          

          

          858Net cash used in investing activities

          

          

          (79,530

          )

          

          

          (331,030

          )

          

          

          (224,182

          )Cash flows from financing activitiesDistributions to partners

          

          

          (124,009

          )

          

          

          (111,076

          )

          

          

          (89,649

          )Proceeds from borrowings

          

          

          132,000

          

          

          

          453,800

          

          

          

          220,500Repayments of borrowings

          

          

          (80,000

          )

          

          

          (297,800

          )

          

          

          (27,000

          )Net proceeds from issuance of partners capital

          

          

          

          

          

          

          141,084

          

          

          

          860Debt issuance costs

          

          

          (9,258

          )

          

          

          (4,200

          )

          

          

          (263

          )Net cash provided by (used in) activities

          

          

          (81,267

          )

          

          

          181,808

          

          

          

          104,448Net increase (decrease) in cash and cash equivalents

          

          

          (825

          )

          

          

          (10,046

          )

          

          

          8,090Cash and cash equivalents  beginning of period

          

          

          9,484

          

          

          

          19,530

          

          

          

          11,440Cash and cash equivalents  end of period

          

          $

          8,659

          

          

          $

          9,484

          

          

          $

          19,530Supplemental disclosure:Cash paid for interest

          

          $

          25,271

          

          

          $

          23,282

          

          

          $

          15,880Noncash investing activities:Issuance of PVR units for acquisition

          

          $

          

          

          

          $

          15,171

          

          

          $

          PVG units given as consideration for acquisition

          

          $

          

          

          

          $

          68,021

          

          

          $

          Other liabilities

          

          $

          

          

          

          $

          4,673

          

          

          $

          
 See accompanying notes to consolidated financial statements.
 77    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   CONSOLIDATED STATEMENT OF PARTNERS CAPITAL AND COMPREHENSIVE INCOME(in thousands)  Common Units

          

          Class B Units

          

          General Partner

          

          Accumulated Other Comprehensive Income (Loss)

          

          Total

          

          Comprehensive Income (Loss)Units

          

          Amount

          

          Units

          

          AmountBalance at December 31, 2006

          

          

          42,060

          

          

          $

          302,938

          

          

          

          4,012

          

          

          $

          102,500

          

          

          $

          5,394

          

          

          $

          (8,652

          )

          

          $

          402,180

          

          

          $

          70,167Capital contributions

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          19

          

          

          

          

          

          

          

          19Issuance of units

          

          

          

          

          

          

          

          

          

          

          34

          

          

          

          843

          

          

          

          

          

          

          

          

          

          

          

          843Conversion of class B units

          

          

          4,046

          

          

          

          99,675

          

          

          

          (4,046

          )

          

          

          (99,675

          )

          

          

          

          

          

          

          

          

          

          

          Distributions ($1.66 per unit)

          

          

          

          

          

          

          (73,260

          )

          

          

          

          

          

          

          (3,277

          )

          

          

          (13,112

          )

          

          

          

          

          

          

          (89,649

          )Net income allocation

          

          

          

          

          

          

          44,562

          

          

          

          

          

          

          

          (391

          )

          

          

          12,452

          

          

          

          

          

          

          

          56,623

          

          

          $

          56,623Other comprehensive income

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          1,260

          

          

          

          1,260

          

          

          

          1,260Balance at December 31, 2007

          

          

          46,106

          

          

          $

          373,915

          

          

          

          

          

          

          $

          

          

          

          $

          4,753

          

          

          $

          (7,392

          )

          

          $

          371,276

          

          

          $

          57,883Public unit offering (See Note 4)

          

          

          5,150

          

          

          

          138,141

          

          

          

          

          

          

          

          

          

          

          

          2,943

          

          

          

          

          

          

          

          141,084Issuance of units for acquisition (See Note 3)

          

          

          543

          

          

          

          21,316

          

          

          

          

          

          

          

          

          

          

          

          435

          

          

          

          

          

          

          

          21,751Distributions ($1.82 per unit)

          

          

          

          

          

          

          (89,207

          )

          

          

          

          

          

          

          

          

          

          

          (21,869

          )

          

          

          

          

          

          

          (111,076

          )Net income allocation

          

          

          

          

          

          

          82,762

          

          

          

          

          

          

          

          

          

          

          

          21,738

          

          

          

          

          

          

          

          104,500

          

          

          $

          104,500Other comprehensive income

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          3,147

          

          

          

          3,147

          

          

          

          3,147Balance at December 31, 2008

          

          

          51,799

          

          

          $

          526,927

          

          

          

          

          

          

          $

          

          

          

          $

          8,000

          

          

          $

          (4,245

          )

          

          $

          530,682

          

          

          $

          107,647Unit based compensation

          

          

          

          

          

          

          1,769

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          1,769Distributions ($1.88 per unit)

          

          

          

          

          

          

          (97,881

          )

          

          

          

          

          

          

          

          

          

          

          (26,128

          )

          

          

          

          

          

          

          (124,009

          )Net income allocation

          

          

          

          

          

          

          40,253

          

          

          

          

          

          

          

          

          

          

          

          24,962

          

          

          

          

          

          

          

          65,215

          

          

          $

          65,215Other comprehensive income

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          2,850

          

          

          

          2,850

          

          

          

          2,850Balance at December 31, 2009

          

          

          51,799

          

          

          $

          471,068

          

          

          

          

          

          

          $

          

          

          

          $

          6,834

          

          

          $

          (1,395

          )

          

          $

          476,507

          

          

          $

          68,065
 See accompanying notes to consolidated financial statements.
 78    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Organization Penn Virginia Resource Partners, L.P. (the Partnership, we, us or our) is a publicly traded Delaware limited partnership formed by Penn Virginia Corporation (Penn Virginia) in 2001 that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. We currently conduct operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream. Our coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. Our coal reserves are primarily located in Kentucky, Virginia, West Virginia, Illinois and New Mexico. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees. Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. We own and operate natural gas midstream assets located in Oklahoma and Texas. Our 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. In addition, we own a 25% member interest in Thunder Creek Gas Services, LLC (Thunder Creek), a joint venture that gathers and transports coalbed methane in Wyomings Powder River Basin. We also own 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. Our general partner is Penn Virginia Resource GP, LLC, which is a wholly owned subsidiary of Penn Virginia GP Holdings, L.P. (PVG), a publicly traded Delaware limited partnership. At December 31, 2009, Penn Virginia owned an approximately 51% limited partner interest in PVG, as well as the non-economic general partner interest in PVG. At December 31, 2009, PVG owned an approximately 37% limited partner interest in us as well as 100% of our general partner, which owns a 2% general partner interest in us. 2. Summary of Significant Accounting Policies Basis of Presentation Our consolidated financial statements include the accounts of the Partnership and all of our wholly owned subsidiaries. Intercompany balances and transactions have been eliminated in consolidation. We own a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyomings Powder River Basin and a 50% member interest in a coal handling joint venture. Earnings from our 25% member interest in Thunder Creek are recorded in the other revenues line on the consolidated statements of income, and earnings from our 50% member interest in a coal handling venture are recorded in the coal services line on the
consolidated statements of income. Our investments in these equity affiliates are recorded on the equity investments line on the consolidated balance sheets. Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. Certain reclassifications have been made to conform to the current periods presentation. Management has evaluated all activities of the Partnership through the date upon which the Consolidated Financial Statements were issued, and concluded that no subsequent events have occurred that would require recognition in the Consolidated Financial Statements or disclosure in the Notes to the Consolidated Financial Statements. Use of Estimates Preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 79    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. Summary of Significant Accounting Policies   (continued) Cash and Cash Equivalents We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Property, Plant and Equipment Property, plant and equipment consist of our ownership in coal fee mineral interests, our royalty interest in oil and natural gas wells, forestlands, processing facilities, gathering systems, compressor stations and related equipment. Property, plant and equipment are carried at cost and include expenditures for additions and improvements, such as roads and land improvements, which increase the productive lives of existing assets. Maintenance and repair costs are charged to expense as incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. We compute depreciation and amortization of property, plant and
equipment using the straight-line balance method over the estimated useful life of each asset as follows:  Useful LifeGathering systems

          

          

          15  20  yearsCompressor stations

          

          

          5  15 yearsProcessing plants

          

          

          15 yearsOther property and equipment

          

          

          3  20 years
 Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by our own geologists and outside consultants. Our estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. From time to time, we carry out core-hole drilling activities on our coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling
activities are expensed as incurred. We deplete timber using a methodology consistent with the units-of-production method, but that is based on the quantity of timber harvested. We determine depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves. When we retire or sell an asset, we remove its cost and related accumulated depreciation and amortization from our consolidated balance sheets. Upon sale, we record the difference between the net book value, net of any assumed asset retirement obligation (ARO), and proceeds from disposition as a gain or loss. Intangible assets are primarily associated with assumed contracts, customer relationships and rights-of-way. These intangible assets are amortized over periods of up to 20 years, the period in which benefits are derived from the contracts, customer relationships and rights-of-way, and are reviewed for impairment along with their associated property, plant and equipment whenever events or changes in circumstances indicated that the carrying amounts may not be recoverable. See Note 10, Intangible Assets, net, for a more detailed description of our intangible assets. Asset Retirement Obligations We recognize the fair value of a liability for an ARO in the period in which it is incurred. The determination of fair value is based upon regional market and specific facility type information. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. See Note 12, Asset Retirement Obligations. The long-lived assets for which our AROs are recorded include compressor stations, gathering systems and coal processing plants. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed
inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed rate, and the additional
 80    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. Summary of Significant Accounting Policies   (continued) capitalized costs are depreciated over the productive life of the assets. Both the accretion and the depreciation are included in depreciation, depletion and amortization (DD&A) expense on our consolidated statements of income. In connection with our natural gas midstream assets, we are obligated under federal regulations to perform limited procedures around the abandonment of pipelines. In some cases, we are unable to reasonably determine the fair value of such ARO because the settlement dates, or ranges thereof, are indeterminable. An ARO will be recorded in the period in which we can reasonably determine the settlement dates. Impairment of Long-Lived Assets We review long-lived assets to be held and used, including related intangible assets, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. We recognize an impairment loss when the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flows. In this circumstance, we recognize an impairment loss equal to the difference between the carrying value and the fair value of the asset. Fair value is estimated to be the present value of future net cash flows from the asset, discounted using a rate commensurate with the risk and remaining life of the asset. The natural gas midstream segment has completed a number of acquisitions in recent years. See Note 3, Acquisitions, for a description of our natural gas midstream segments material acquisitions. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, and the resulting amount of goodwill, if any. Changes in operations, further decreases in commodity
prices, changes in the business environment or further deteriorations of market conditions could substantially alter managements assumptions and could result in lower estimates of values of acquired assets or of future cash flows. If these events occur, it is reasonably possible that we could incur a significant impairment loss on our consolidated statements of income. Impairment of Goodwill Goodwill recorded in connection with a business combination is not amortized, but tested for impairment at least annually. Goodwill impairment is determined using a two-step test. The first step of the impairment test is used to identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value of a reporting unit exceeds its book value, goodwill of the reporting unit is not considered impaired, and the second step of the impairment test is not required. If the book value of a reporting unit exceeds its fair value, the second step of the impairment test is performed to measure the
amount of impairment loss, if any. The second step of the impairment test compares the implied fair value of the reporting units goodwill with the book value of that goodwill. If the book value of the reporting units goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. The annual impairment testing is performed in the fourth quarter. Management uses a number of different criteria when evaluating goodwill for possible impairment. Indicators such as significant decreases in a reporting units book value, decreases in cash flows, sustained operating losses, a sustained decrease in market capitalization, adverse changes in the business climate, legal matters, losses of significant customers and new technologies which could accelerate obsolescence of business products are used by management when performing evaluations. We tested goodwill for impairment during the fourth quarter of 2008 and recorded an impairment loss of $31.8 million. As a result of this impairment loss, we did
not have a balance in goodwill at December 31, 2008. We had a $7.7 million balance in goodwill at December 31, 2007. See Note 9, Goodwill for a description of goodwill and the related impairment loss.
 81    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. Summary of Significant Accounting Policies   (continued) Equity Investments We use the equity method of accounting to account for our 25% member interest in Thunder Creek, as well as our 50% member interest investment in a coal handling joint venture, recording the initial investment at cost. Subsequently, the carrying amount of the investment is increased to reflect our share of income of the investees and capital contributions, and is reduced to reflect our share of losses of the investees or distributions received from the investees as the joint ventures report them. Our share of earnings or losses from Thunder Creek is included in other revenues on the consolidated statements of income, and our share of earnings and
losses from the coal handling joint venture is included in coal services on the consolidated statements of income. Other revenues and coal services revenues also include amortization of the amount of the equity investments that exceed our portion of the underlying equity in net assets. We record this amortization over the life of the contracts acquired in the Thunder Creek acquisition, which is 12 years, and the life of the coal services contracts entered into in connection with the coal handling joint venture, which is 15 years. Debt Issuance Costs Debt issuance costs relating to long-term debt have been capitalized and are being amortized and recorded as interest expense over the term of the related debt instrument. Long-Term Prepaid Minimums We lease a portion of our reserves from third parties that require monthly or annual minimum rental payments. The prepaid minimums are recoupable from future production and are deferred and charged to coal royalties expense as the coal is subsequently produced. We evaluate the recoverability of the prepaid minimums on a periodic basis; consequently, any prepaid minimums that cannot be recouped are charged to coal royalties expense. Environmental Liabilities Other liabilities include accruals for environmental liabilities that we either assumed in connection with certain acquisitions or recorded in operating expenses when it became probable that a liability had been incurred and the amount of that liability could be reasonably estimated. Concentration of Credit Risk Approximately 84% of our consolidated accounts receivable at December 31, 2009 resulted from our natural gas midstream segment and approximately 16% resulted from our coal and natural resource management segment. Approximately 17% of our natural gas midstream segment accounts receivables and 14% of our consolidated accounts receivable at December 31, 2009 related to one natural gas midstream customer. As of December 31, 2009, no receivables were collateralized, and we had recorded a $1.2 million allowance for doubtful accounts in the natural gas midstream segment. No significant uncertainties related to the collectability of amounts owed to us exist
in regard to this natural gas midstream customer. This customer concentration increases our exposure to credit risk on our receivables, since the financial insolvency of this customer could have a significant impact on our results of operations. Revenues Natural Gas Midstream Revenues.  We recognize revenues from the sale of natural gas liquids (NGLs) and residue gas when we sell the NGLs and residue gas produced at our gas processing plants. We recognize gathering and transportation revenues based upon actual volumes delivered. Due to the time needed to gather information from various purchasers and measurement locations and then calculate volumes delivered, the collection of natural gas midstream revenues may take up to 30 days following the month of production. Therefore, we make accruals for revenues and accounts receivable and the related cost of
 82    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. Summary of Significant Accounting Policies   (continued) midstream gas purchased and accounts payable based on estimates of natural gas purchased and NGLs and residue gas sold. We record any differences, which historically have not been significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized. Coal Royalties Revenues and Deferred Income.  We recognize coal royalties revenues on the basis of tons of coal sold by our lessees and the corresponding revenues from those sales. Since we do not operate any coal mines, we do not have access to actual production and revenues information until approximately 30 days following the month of production. Therefore, our financial results include estimated revenues and accounts receivable for the month of production. We record any differences, which historically have not been significant, between the actual amounts ultimately received or paid and the original estimates in the period they
become finalized. Most of our lessees must make minimum monthly or annual payments that are generally recoupable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recoups a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of income. Deferred income also includes unearned income from a coal services facility lease, which is recognized as interest income as it is earned. Coal Services Revenues.  We recognize coal services revenues when lessees use our facilities for the processing, loading and/or transportation of coal. Coal services revenues consist of fees collected from lessees for the use of our loadout facility, coal preparation plants and dock loading facility. We also include equity earnings of our coal handling joint venture in coal services revenues. We recognize our share of income or losses from our investment in a coal handling joint venture as the joint venture reports them to us. Oil and Gas Royalty Revenues.  We recognize oil and gas royalty revenues in connection with royalty interests owned by us. Royalties are recognized as revenue when natural gas, crude oil and NGLs are removed from the respective underground mineral reserve locations. Royalty payments are generally received two months after the products are removed. An accrual is included in accounts receivables for amounts not received during the month removed based on historical trends. Timber Revenues.  We recognize timber revenues based on the volume of timber harvested and sold from our properties. Producer Services Revenues.  We recognize producer services revenues in connection with agent fees for the marketing of Penn Virginias and other third parties natural gas production. We aggregate third-party volumes and sell those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines. Derivative Instruments From time to time, we enter into derivative financial instruments to mitigate our exposure to natural gas, crude oil and NGL price volatility. The derivative financial instruments, which are placed with financial institutions that we believe are acceptable credit risks, take the form of collars and swaps. All derivative financial instruments are recognized in our consolidated financial statements at fair value. The fair values of our derivative instruments are determined based on discounted cash flows derived from quoted forward prices. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by the
board of directors of our general partner. During 2006 we discontinued hedge accounting for commodity derivatives. Because we no longer apply hedge accounting for our commodity derivatives, we recognize changes in fair value in earnings currently in the derivatives line on the consolidated statements of income. We have experienced and could continue to experience significant changes in the estimate of unrealized derivative gains or losses recognized due to fluctuations in the value of these commodity derivative contracts. The
 83    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. Summary of Significant Accounting Policies   (continued) discontinuation of hedge accounting has no impact on our reported cash flows, although our results of operations are affected by the volatility of mark-to-market gains and losses and changes in fair value, which fluctuate with changes in natural gas, crude oil and NGL prices. These fluctuations could be significant in a volatile pricing environment. We have also entered into interest rate swaps agreements (the Interest Rate Swaps) to mitigate our exposure to debt interest expense. During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps are recognized in the derivatives line item on our consolidated statements of income. During the year ended December 31, 2009, we reclassified a total of $3.4 million from accumulated other comprehensive income (AOCI) to earnings related the Interest Rate Swaps. At December 31, 2009, a $1.4 million loss remained in
AOCI and will be recognized in interest expense as the Interest Rate Swaps settle. See Note 6, Derivative Instruments, for a description of our derivative program. Income Taxes As a partnership, we are not a taxable entity and have no federal income tax liability. The taxable income and losses of the Partnership are includable in the federal and state income tax returns of our partners. Net income for financial statement purposes may differ significantly from taxable income reportable to partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under our partnership agreement. Net Income per Limited Partner Unit Effective January 1, 2009, we adopted the new accounting standard addressing the computation of earnings per unit for master limited partnerships that issue multiple classes of securities that participate in partnerships distribtutions. Our securities consist of publicly traded common units held by limited partners, a general partner interest and separately transferable incentive distribution rights (IDRs). This standard requires earnings or losses for a reporting period to be allocated to our limited partners, our general partner and holders of IDRs using the two-class method to compute earnings per unit. Under this method, our net
income (or loss) for a reporting period is reduced (or increased) by the amount that has been or will be distributed to our participating security holders. In the event that our net income exceeds our distributions (or our distributions exceed our net income), such excess undistributed net income (or loss) is allocated to our limited partners and our general partner in the ratio of 98% and 2%, as provided in our partnership agreement. Also, on January 1, 2009, we adopted the new accounting standard which determines whether instruments granted in share-based payments transactions are participating securities. Under this standard, unvested unit-based payment awards that contain non-forfeitable rights to distributions or distribution equivalents are participating securities and, therefore, are included in the computation of net income allocable to limited partners pursuant to the two-class method of computing earnings per unit. During 2009, our general partner granted phantom units to employees of our general partner or its affiliates. See Note 16, Unit-Based Payments. We
have determined that our unvested phantom unit awards contain non-forfeitable rights to distributions and, therefore, are participating securities for purposes of this standard. Basic and diluted net income per limited partner unit is computed by dividing net income allocable to limited partners by the weighted average number of limited partner units outstanding during the period. Diluted net income per limited partner unit is computed by dividing net income allocable to limited partners by the weighted average number of limited partner units outstanding during the period and, when dilutive, phantom units. Unit-Based Compensation Our general partner has a long-term incentive plan that permits the grant of awards to directors and employees of our general partner and employees of its affiliates who perform services for us. Awards under our long-term incentive plan can be in the form of common units, restricted units, unit options, phantom units
 84    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. Summary of Significant Accounting Policies   (continued) and deferred common units. Our long-term incentive plan is administered by the compensation and benefits committee of our general partners board of directors. We reimburse our general partner for payments made pursuant to our long-term incentive plan and recognize compensation expense over the vesting period of the awards. Authoritative accounting literature establishes standards for transactions in which an entity exchanges its equity instruments for goods and services. This standard requires us to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. See Note 16, Unit-Based Payments, for a more detailed description of our long-term incentive plan. New Accounting Standards In April 2008, an amendment to accounting standards related to the determination of the useful life of intangible assets was issued. This amendment addresses the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible. This amendment is effective for fiscal years beginning after December 15, 2008 and did not have a material impact on our financial statements. In April 2009, an amendment to business combination standards was issued related to accounting for assets acquired and liabilities assumed in a business combination that arise from contingencies. This amendment addresses application issues raised by preparers, auditors and members of the legal profession on initial recognition and measurement, subsequent measurement and accounting and disclosure of assets and liabilities arising from contingencies in a business combination. The amendment is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first
annual reporting period beginning on or after December 15, 2008. This amendment will have an impact on our accounting for any future acquisitions and our financial statements. In May 2009, an accounting standard related to Subsequent Events was issued and established principles and requirements for evaluating and reporting subsequent. Disclosures are required as of the date through which subsequent events are evaluated by management and were effective for interim periods ending after June 15, 2009 and apply prospectively. Because these are disclosure requirements only, and do not affect the accounting treatment for subsequent events, the adoption of this accounting standard did not impact our financial statements. Effective July 1, 2009, we adopted the Financial Accounting Standards Board (FASB) accounting standards codification for generally accepted accounting. These standards establish the FASBs accounting standards codification (the Codification) as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with United States generally accepted accounting principles (U.S. GAAP). Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal
securities laws are also sources of authoritative U.S. GAAP for SEC registrants. All guidance contained in the Codification carries an equal level of authority. The Codification superseded all existing non-SEC accounting and reporting standards. All other non-grandfathered, non-SEC accounting literature not included in the Codification is non-authoritative. The FASB will not issue new standards in the form of Statements, FASB Staff Positions or Emerging Issues Task Force Abstracts. Instead, it will issue Accounting Standards Updates (ASUs). The FASB will not consider ASUs as authoritative in their own right. ASUs will serve only to update the Codification, provide background information about the guidance and provide the bases for conclusions on the change(s) in the Codification. References made to FASB guidance throughout these financials have been updated for the Codification. In August 2009, the FASB issued guidance on how companies should measure liabilities at fair value. The guidance clarifies that the quoted price for an identical liability should be used. However, if such information is not available, an entity may use the quoted price of an identical liability when traded as an
 85    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. Summary of Significant Accounting Policies   (continued) asset, quoted prices for similar liabilities or similar liabilities traded as assets, or another valuation technique (such as the market or income approach). The guidance also indicates that the fair value of a liability is not adjusted to reflect the impact of contractual restrictions that prevent its transfer and indicates circumstances in which quoted prices for an identical liability or quoted price for an identical liability traded as an asset may be considered level 1 fair value measurements. This guidance was effective October 1, 2009. The adoption of this guidance did not have a material impact on our financial statements. 3. Acquisitions In the following paragraphs, all references to coal, crude oil and natural gas reserves and acreage acquired are unaudited. The factors we used to determine the fair market value of acquisitions include, but are not limited to, discounted future net cash flows on a risked-adjusted basis, geographic location, quality of resources, potential marketability and financial condition of lessees. Business Combination Lone Star Gathering, L.P. (Lone Star) On July 17, 2008, we completed an acquisition of substantially all of the assets of Lone Star. Lone Stars assets are located in the southern portion of the Fort Worth Basin of North Texas and include approximately 129 miles of gas gathering pipelines and approximately 240,000 acres dedicated by active producers. The Lone Star acquisition expanded the geographic scope of the natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin. We acquired this business for approximately $164.3 million and a liability of $4.7 million, which represents the fair value of a $5.0 million guaranteed payment, plus contingent payments of $30.0 million and $25.0 million. Funding for the acquisition was provided by $80.7 million of borrowings under our revolving credit facility (the Revolver), 2,009,995 PVG common units (which we purchased from two subsidiaries of Penn Virginia for $61.8 million) and 542,610 of our newly issued common units. The contingent payments will be triggered if revenues from certain assets located in a defined geographic area reach certain targets by or before June 30, 2013 and will be funded in cash or common units, at our election. The Lone Star acquisition has been accounted for using the purchase method of accounting. Under the purchase method of accounting, the total purchase price has been allocated to the net tangible and intangible assets acquired from Lone Star based on their estimated fair values. The total purchase price was allocated to the assets purchased based upon fair values on the date of the Lone Star acquisition as follows (in thousands):  Cash consideration paid for Lone Star

          

          $

          81,125Fair value of PVG common units given as consideration for Lone Star

          

          

          68,021Fair value of PVR common units issued and given as consideration for Lone Star

          

          

          15,171Payment guaranteed December 31, 2009

          

          

          4,673Total purchase price

          

          $

          168,990Fair value of assets acquired:Property and equipment

          

          $

          88,596Intangible assets

          

          

          69,200Goodwill

          

          

          11,194Fair value of assets acquired

          

          $

          168,990
 The purchase price included approximately $11.2 million of goodwill, all of which was allocated to the natural gas midstream segment. A significant factor that contributed to the recognition of goodwill was the ability to acquire an established business on the western border of the expanding Barnett Shale play in the
 86    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. Acquisitions   (continued) Fort Worth Basin. In accordance with goodwill and other intangible assets accounting standards, goodwill recorded in connection with a business combination is not amortized, but is tested for impairment at least annually. Accordingly, the accompanying pro forma combined income statement does not include amortization of the goodwill recorded in the acquisition. As a result of testing goodwill for impairment in the fourth quarter of 2008, we recognized a loss on impairment of goodwill. See Note 9, Goodwill for a description of our goodwill impairment. The purchase price includes approximately $69.2 million of intangible assets that are associated with assumed contracts and customer relationships. These intangible assets will be amortized over the period in which benefits are derived from the contracts and relationships assumed and will be reviewed for impairment along with the related tangible assets. Based on when the estimated economic benefit will be earned, we estimate the useful lives of these intangible assets to be 20 years. See Note 10, Intangible Assets, net. The following pro forma financial information reflects the consolidated results of our operations as if the Lone Star acquisition had occurred on January 1, 2007. The pro forma information includes adjustments primarily for depreciation of acquired property and equipment, the amortization of intangible assets, interest expense for acquisition debt and the change in weighted average common units resulting from the issuance of 542,610 of our newly issued common units given as consideration in the Lone Star acquisition. The pro forma financial information is not necessarily indicative of the results of operations as it would have been had these
transactions been effected on the assumed date (in thousands, except per unit data):  Year Ended December 31,2008

          

          2007(Unaudited)Revenues

          

          $

          885,147

          

          

          $

          552,439Net income

          

          $

          93,363

          

          

          $

          38,778Net income per limited partner unit, basic & diluted

          

          $

          1.41

          

          

          $

          0.54
 Other Business Combinations In July 2009, we completed an acquisition of the gas processing and residue pipeline facilities in western Oklahoma for approximately $22.6 million in cash. Funding of the acquisition was provided by long-term debt under the Revolver. The acquired assets included a 60 MMcfd processing plant. The purchase price has been allocated as follows: $13.1 million to processing plant and related equipment and $9.5 million to pipelines and compressor stations. In April 2008, we acquired a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyomings Powder River Basin. The purchase price was $51.6 million in cash, after customary closing adjustments and was funded with long-term debt under the Revolver. The entire member interest is recorded in equity investments on the consolidated balance sheets. This investment includes $37.3 million of fair value for the net assets acquired and $14.3 million of fair value paid in excess of our portion of the underlying equity in the net assets acquired related to customer contracts and related customer relations.
This excess is being amortized to equity earnings over the life of the underlying contracts, which is 12 years. See Note 8, Equity Investments. The earnings are recorded in other revenues on the consolidated statements of income. In October 2007, we purchased from Penn Virginia oil and gas royalty interests associated with leases of property in eastern Kentucky and southwestern Virginia and with estimated proved oil and gas reserves of 8.7 Bcfe at January 1, 2007. The purchase price for this asset acquisition was $31.0 million in cash and was funded with long-term debt under the Revolver.
 87    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. Acquisitions   (continued) In September 2007, we acquired fee ownership of approximately 62,000 acres of forestland in northern West Virginia. The purchase price was $93.3 million in cash and was funded with long-term debt under the Revolver. The purchase price has been allocated as follows: $86.1 million to timber, $6.6 million to land and $0.6 million to oil and gas royalty interests. In June 2007, we acquired a combination of fee ownership and lease rights to approximately 51 million tons of coal reserves, along with a preparation plant and coal handling facilities. The property is located on approximately 17,000 acres in western Kentucky. The purchase price was $42.0 million in cash and was funded with long-term debt under the Revolver. The purchase price has been allocated as follows: $30.2 million to coal properties, $11.3 million to the coal processing plant and related facilities and $0.5 million to land. We also recorded a $28.1 million lease receivable and $16.6 million to deferred rent relating to a coal services facility
lease. The pro forma results for these business combinations for the years ended December 31, 2008 and 2007 do not materially change the net income for these periods. 4. Unit Offering In 2008, we issued 5.15 million common units to the public representing limited partner interests and received $138.2 million in net proceeds. We received total contributions of $2.9 million from our general partner to maintain its indirect 2% general partner interest. We used net proceeds to repay a portion of our borrowings under the Revolver. 5. Fair Value Measurement of Financial Instruments Effective January 1, 2009, we present fair value measurements and disclosures applicable to both our financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis. Our financial instruments that are subject to fair value disclosures consist of cash and cash equivalents, accounts receivable, accounts payable, derivative instruments and long-term debt. At December 31, 2009, the carrying values of all these financial instruments approximated their fair value. Authoritative accounting literature requires fair value measurements to be classified and disclosed in one of the following three categories: 

          Level 1:  Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 1 inputs generally provide the most reliable evidence of fair value. 

          Level 2:  Quoted prices in markets that are not active or inputs, which are observable, either directly or indirectly, for substantially the full term of the asset or liability. 

          Level 3:  Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Nonrecurring Fair Value Measurements We have completed a number of acquisitions in recent years. See Note 3, Acquisitions, for a description of our natural gas midstream segments material acquisitions. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, AROs and the resulting amount of goodwill, if any. The Sweetwater plant acquisition included nonfinancial assets and liabilities
that were measured at fair value during 2009. The cost approach was used to develop the fair values of the Sweetwater plant assets. The cost approach is a technique that uses the reproduction or replacement cost as an initial basis for value. The cost to reproduce or replace the subject asset with a new asset, either
 88    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 5. Fair Value Measurement of Financial Instruments   (continued) identical (reproduction) or having the same utility (replacement), establishes the highest amount a prudent investor is likely to pay. A series of models were used to value the Sweetwater plant and related pipelines. Salient data points for the model included capacities of the processing plant, processing technology, and size and length of pipeline. To the extent that the asset being valued provides less utility than a new one, due to physical deterioration, functional obsolescence, and/or economic obsolescence, the value of the subject asset is adjusted for those reductions in value. Adjustments may be made for age, physical wear and tear,
technological inefficiencies, changes in price levels, and reduced demand, among other factors. Related to the Sweetwater plant assets, an ARO liability was recognized. See Note 2, Summary of Significant Accounting Policies for a description of the inputs and techniques used to derive ARO fair values. Unrelated to the Sweetwater plant acquisition, there was a fair value measurement of an intangible asset. During 2009 an intangible asset was impaired related to a bankruptcy courts decision to reject a wheelage agreement associated with a lessee of PVRs coal and natural resource segment. The following table summarizes the initial fair value estimates for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis by category during 2009 (in thousands):  Fair Value Measurements, UsingDescription

          

          Fair Value Measurements at December 31, 2009

          

          Quoted Prices in Active Markets for Identical Assets(Level 1)

          

          Significant Other Observable Inputs (Level 2)

          

          Significant Unobservable Inputs (Level 3)Sweetwater plant PP&E-noncurrent assets

          

          $

          22,772

          

          

          $

          

          

          

          $

          

          

          

          $

          22,772Sweetwater plant ARO-noncurrent liabilities

          

          

          (208

          )

          

          

          

          

          

          

          

          

          

          

          (208

          )Total

          

          $

          22,564

          

          

          $

          

          

          

          $

          

          

          

          $

          22,564
 Recurring Fair Value Measurements The following table summarizes the assets and liabilities measured at fair value on a recurring basis and included our derivative financial instruments by categories as of December 31, 2009 (in thousands):  Fair Value Measurements at December 31, 2009, UsingDescription

          

          Fair Value Measurements at December 31, 2009

          

          Quoted Prices in Active Markets for Identical Assets(Level 1)

          

          Significant Other Observable Inputs(Level 2)

          

          Significant Unobservable Inputs(Level 3)Interest rate swap assets  noncurrent

          

          $

          1,266

          

          

          $

          

          

          

          $

          1,266

          

          

          $

          Interest rate swap liabilities  current

          

          

          (7,710

          )

          

          

          

          

          

          

          (7,710

          )

          

          

          Interest rate swap liabilities  noncurrent

          

          

          (3,241

          )

          

          

          

          

          

          

          (3,241

          )

          

          

          Commodity derivative assets  current

          

          

          1,331

          

          

          

          

          

          

          

          1,331

          

          

          

          Commodity derivative assets  noncurrent

          

          

          18

          

          

          

          

          

          

          

          18

          

          

          

          Commodity derivative liabilities  current

          

          

          (3,541

          )

          

          

          

          

          

          

          (3,541

          )

          

          

          Commodity derivative liabilities  noncurrent

          

          

          (1,044

          )

          

          

          

          

          

          

          (1,044

          )

          

          

          Total

          

          $

          (12,921

          )

          

          $

          

          

          

          $

          (12,921

          )

          

          $

          
 89    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 5. Fair Value Measurement of Financial Instruments   (continued) The values of both the Interest Rate Swap and commodity derivatives are presented in the derivative assets and derivative liabilities line items on the consolidated balance sheets. See Note 6, Derivative Instruments, for the effects of these instruments on our consolidated statements of income. We use the following methods and assumptions to estimate the fair values in the above table: 

          Commodity derivative instruments:  We utilize collar derivative contracts to hedge against the variability in the frac spread. We determine the fair values of our commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities. This is a level 2 input. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. See Note 6, Derivative Instruments. 

          Interest rate swaps:  We have entered into the Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver. We use an income approach using valuation techniques that connect future cash flows to a single discounted value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. This is a level 2 input. See Note 6, Derivative Instruments. 6. Derivative Instruments Natural Gas Midstream Segment Commodity Derivatives We utilize costless collars and swap derivative contracts to hedge against the variability in cash flows associated with anticipated natural gas midstream revenues and cost of midstream gas purchased. We also utilize collar derivative contracts to hedge against the variability in our frac spread. Our frac spread is the spread between the purchase price for the natural gas we purchase from producers and the sale price for NGLs that we sell after processing. We hedge against the variability in our frac spread by entering into costless collar and swap derivative contracts to sell NGLs forward at a predetermined commodity 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, such use may also 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 Put (or floor) price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the Call (or 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. With respect to a swap contract for the purchase of a commodity, the
counterparty is required to make a payment to us if the settlement price for any settlement period is greater than the swap price for such contract, and we are required to make a payment to the counterparty if the settlement price is less than the swap price for such contract.
 90    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. Derivative Instruments   (continued) We determine the fair values of our derivative agreements by discounting the cash flows based on quoted forward prices for the respective commodities as of December 31, 2009, using discount rates adjusted for the credit risk of the counterparties if the derivative is in an asset position and our own credit risk for derivatives in a liability position. The following table sets forth our positions as of December 31, 2009 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:  Average Volume Per Day

          

          Swap Price

          

          Weighted Average Price

          

          Fair Value at December 31, 2009Put

          

          Call(in thousands)Crude Oil Collar

          

          

          (barrels)

          

          

          

          

          

          

          

          ($ per barrel)First Quarter 2010 through Fourth Quarter 2010

          

          

          750

          

          

          

          

          

          

          $

          70.00

          

          

          $

          81.25

          

          

          $

          (1,329

          )First Quarter 2010 through Fourth Quarter 2010

          

          

          1,000

          

          

          

          

          

          

          $

          68.00

          

          

          $

          80.00

          

          

          

          (2,171

          )First Quarter 2011 through Fourth Quarter 2011

          

          

          400

          

          

          

          

          

          

          $

          75.00

          

          

          $

          98.50

          

          

          

          18Natural Gas Purchase Swap

          

          

          (MMBtu)

          

          

          

          ($ per MMBtu)First Quarter 2010 through Fourth Quarter 2010

          

          

          5,000

          

          

          $

          5.815

          

          

          

          

          

          

          

          

          

          

          

          (41

          )First Quarter 2011 through Fourth Quarter 2011

          

          

          3,000

          

          

          $

          6.430

          

          

          

          

          

          

          

          

          

          

          

          (99

          )NGL  Natural Gasoline Collar

          

          

          (gallons)

          

          

          

          

          

          

          

          ($ per gallon)First Quarter 2011 through Fourth Quarter 2011

          

          

          60,000

          

          

          

          

          

          

          $

          1.55

          

          

          $

          1.92

          

          

          

          (945

          )Settlements to be received in subsequent period

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          1,331
 At December 31, 2009, we reported a net derivative liability related to the natural gas midstream segment of $3.2 million. No amounts remain in AOCI as of December 31, 2008 related to derivatives in the natural gas midstream segment for which we discontinued hedge accounting in 2006, and no amounts have been recorded to AOCI related to the derivative positions as of December 31, 2009.
 91    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. Derivative Instruments   (continued) Interest Rate Swaps We have entered into the Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver. Until March 2010, the notional amounts of the Interest Rate Swaps total $310.0 million, or approximately 50% of our total long-term debt outstanding as of December 31, 2009, with us paying a weighted average fixed rate of 3.54% on the notional amount, and the counterparties paying a variable rate equal to the three-month London Interbank Offered Rate (LIBOR). From March 2010 to December 2011, the notional amounts of the Interest Rate Swaps total $250.0 million with us paying a weighted average fixed rate of
3.37% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From December 2011 to December 2012, the notional amounts of the Interest Rate Swaps total $100.0 million, with us paying a weighted average fixed rate of 2.09% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. The Interest Rate Swaps extend one year past the maturity of the current Revolver. The Interest Rate Swaps have been entered into with seven financial institution counterparties, with no counterparty having more than 24% of the open positions. The following table sets forth our positions as of December 31, 2009 for the Interest Rate Swaps:  Dates

          

          Notional Amounts

          

          Weighted-Average Fixed Rate

          

          Fair Value at December 31, 2009(in thousands)Until March 2010

          

          $

          310.0

          

          

          

          3.54

          %

          

          $

          (2,479

          )March 2010  December 2011

          

          $

          250.0

          

          

          

          3.37

          %

          

          

          (8,456

          )December 2011  December 2012

          

          $

          100.0

          

          

          

          2.09

          %

          

          

          1,252
 During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps have been recognized in the derivatives line item on our consolidated statements of income. At December 31, 2009, a $1.4 million loss remained in AOCI related to the Interest Rate Swaps. The $1.4 million loss will be recognized in interest expense as the original forecasted interest payments occur. We reported a (i) net derivative liability of $9.7 million at December 31, 2009 and (ii) loss in AOCI of $1.4 million at December 31, 2009 related to the Interest Rate Swaps. In connection with periodic settlements, we recognized $3.4 million of net hedging losses in interest expense in the year ended December 31, 2009. Based upon future interest rate curves at December 31, 2009, we expect to realize $7.7 million of hedging losses within the next 12 months. The amounts that we ultimately realize will vary due to changes in the fair value of open derivative agreements prior to settlement.
 92    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. Derivative Instruments   (continued) Financial Statement Impact of Derivatives The following table summarizes the effects of our derivative activities, as well as the location of the gains and losses, on our consolidated statements of income for the periods presented (in thousands):  Location of gain (loss) on derivatives recognized in income

          

          Year Ended December 31,2009

          

          2008Derivatives not designated as hedging instruments:Commodity contracts(1)

          

          

          Natural gas midstream revenues

          

          

          $

          

          

          

          $

          (8,219

          )Commodity contracts(1)

          

          

          Cost of midstream gas purchased

          

          

          

          

          

          

          

          2,739Interest rate contracts(2)

          

          

          Interest expense

          

          

          

          (3,356

          )

          

          

          (1,706

          )Interest rate contracts

          

          

          Derivatives

          

          

          

          (4,306

          )

          

          

          (8,635

          )Commodity contracts

          

          

          Derivatives

          

          

          

          (15,408

          )

          

          

          25,472Total increase (decrease) in net income resulting from derivatives

          

          

          

          

          

          $

          (23,070

          )

          

          $

          9,651Realized and unrealized derivative impact:Cash received (paid) for commodity and interest rate

          

          

          Derivatives

          

          

          

          3,000

          

          

          

          (38,466

          )Cash paid for interest rate contract settlements

          

          

          Interest expense

          

          

          

          (370

          )

          

          

          (503

          )Unrealized derivative gain (loss)(3)

          

          

          

          

          

          

          (25,700

          )

          

          

          48,620Total increase (decrease) in net income resulting from derivatives

          

          

          

          

          

          $

          (23,070

          )

          

          $

          9,651
  (1)

          This represents commodity derivative amounts reclassified out of AOCI and into earnings. Subsequent to the discontinuation of hedge accounting for commodity derivatives in 2006, amounts remaining in AOCI have been reclassified into earnings in the same period or periods during which the original hedge forecasted transaction affects earnings. No losses remain in AOCI related to commodity derivatives for which we discontinued hedge accounting in 2006. (2)

          This represents Interest Rate Swap amounts reclassified out of AOCI and into earnings. During 2008 and 2009 we discontinued hedge accounting for various Interest Rate Swaps at different times. By the first quarter of 2009 we discontinued hedge accounting for the remaining Interest Rate Swaps. During 2009 and 2008 we reclassified $0.4 million and $0.5 million out of AOCI relating to actual hedge settlements accounted for under hedge accounting. During 2009 and 2008 we reclassified $3.0 million and $1.2 million for remaining AOCI that have been reclassified into earnings in the same period or periods relating to Interest Rate Swaps not designated for hedge accounting. (3)

          This activity represents unrealized gains in the natural gas midstream, cost of midstream gas purchased, interest expense and derivatives lines on our consolidated statements of income.
 93    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. Derivative Instruments   (continued) The following table summarizes the fair value of our derivative instruments, as well as the locations of these instruments on our consolidated balance sheets as of December 31, 2009 and 2008 (in thousands):  Fair values as of December 31, 2009

          

          Fair values as of December 31, 2008Balance Sheet Location

          

          Derivative Assets

          

          Derivative Liabilities

          

          Derivative Assets

          

          Derivative LiabilitiesDerivatives not designated as hedging instruments:Interest rate contracts(1)

          

          

          Derivative assets/liabilities  current

          

          

          $

          

          

          

          $

          7,710

          

          

          $

          

          

          

          $

          5,891Interest rate contracts(1)

          

          

          Derivative assets/liabilities  noncurrent

          

          

          

          1,266

          

          

          

          3,241

          

          

          

          

          

          

          

          6,915Commodity contracts

          

          

          Derivative assets/liabilities  current

          

          

          

          1,331

          

          

          

          3,541

          

          

          

          30,431

          

          

          

          7,694Commodity contracts

          

          

          Derivative assets/liabilities  noncurrent

          

          

          

          18

          

          

          

          1,044

          

          

          

          

          

          

          

          Total derivatives not designated as hedging instruments

          

          

          

          

          

          $

          2,615

          

          

          $

          15,536

          

          

          $

          30,431

          

          

          $

          20,500Total fair value of derivative instruments

          

          

          

          

          

          $

          2,615

          

          

          $

          15,536

          

          

          $

          30,431

          

          

          $

          20,500
  (1)

          During 2009 and 2008 we discontinued hedge accounting for various Interest Rate Swaps at different times. By the first quarter of 2009 we discontinued hedge accounting for the remaining Interest Rate Swaps. For presentational purposes all Interest Rate Swaps are shown as not designated as hedging instruments for both periods presented, 2009 and 2008, reflecting their accounting status as of December 31, 2009. See Note 5, Fair Value Measurement of Financial Instruments for a description of how the above financial instruments are valued. The following table summarizes the effect of the Interest Rate Swaps on our total interest expense for the periods presented (in thousands):  Year Ended December 31,Source

          

          2009

          

          2008

          

          2007Interest on borrowings

          

          $

          21,523

          

          

          $

          23,641

          

          

          $

          18,861Capitalized interest(1)

          

          

          (226

          )

          

          

          (675

          )

          

          

          (786

          )Interest rate swaps

          

          

          3,356

          

          

          

          1,706

          

          

          

          (737

          )Total interest expense

          

          $

          24,653

          

          

          $

          24,672

          

          

          $

          17,338
  (1)

          Capitalized interest was primarily related to the construction of our natural gas gathering facilities. The effects of derivative gains (losses), cash settlements of our natural gas midstream commodity derivatives and cash settlements of the Interest Rate Swaps that do not follow hedge accounting are reported as adjustments to reconcile net income to net cash provided by operating activities on our consolidated statements of cash flows. These items are recorded in the Total derivative losses (gains) and Cash settlements of derivatives lines on the consolidated statements of cash flows. The above hedging activity represents cash flow hedges. As of December 31, 2009, we did not own derivative instruments that were classified as fair value hedges or trading securities. In addition, as of December 31, 2009, we did not own derivative instruments containing credit risk contingencies.
 94    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. Property and Equipment The following table summarizes our property and equipment as of December 31, 2009 and 2008 (in thousands):  As of December 31,2009

          

          2008Coal properties

          

          $

          478,803

          

          

          $

          476,787Compressor stations

          

          

          62,701

          

          

          

          53,392Gathering systems

          

          

          372,550

          

          

          

          334,522Coal services equipment

          

          

          38,474

          

          

          

          38,474Processing plants

          

          

          55,948

          

          

          

          38,150Land

          

          

          20,743

          

          

          

          20,985Oil and gas royalties

          

          

          36,937

          

          

          

          36,937Timber

          

          

          87,869

          

          

          

          87,869Other property, plant and equipment

          

          

          8,045

          

          

          

          6,410Total property, plant and equipment

          

          

          1,162,070

          

          

          

          1,093,526Accumulated depreciation, depletion and amortization

          

          

          (261,226

          )

          

          

          (198,407

          )Net property, plant and equipment

          

          $

          900,844

          

          

          $

          895,119
 8. Equity Investments In 2004, we acquired a 50% interest in Coal Handling Solutions LLC, a joint venture formed to own and operate end-user coal handling facilities. In 2008, we acquired a 25% member interest in Thunder Creek Gas Services LLC, a joint venture that gathers and transports coalbed methane gas in Wyomings Powder River Basin for $51.6 million in cash, after customary closing adjustments. See Note 3, Acquisitions. We account for these investments under the equity method of accounting. As of December 31, 2009 and 2008, our equity investment totaled $87.6 million and $78.4 million, which exceeded our portion of the underlying equity in net
assets by $18.4 million and $20.2 million. The difference is being amortized to equity earnings over the estimated life of the intangible assets at the time of the acquisition. The intangible assets relate to contracts and customer relationships acquired, which are estimated to be from 12 years to 15 years. In accordance with the equity method, we recognized equity earnings of $7.3 million in 2009, $4.2 million in 2008 and $1.8 million in 2007, with a corresponding increase in the investment. The joint ventures generally pay to us quarterly distributions of our portion of the joint ventures cash flows. We received cash distributions from the joint ventures of $4.7 million in 2009, $4.0 million in 2008 and $1.5 million in 2007. Equity earnings related to the 50% interest in Coal Handling Solutions LLC are included in coal services revenues on our consolidated statements of income, and equity earnings related to the 25% member interest in Thunder
Creek are recorded in other revenues on our consolidated statements of income. The equity investments for both joint ventures are included in the equity investments line on our consolidated balance sheets.
 95    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. Equity Investments   (continued) Summarized financial data for equity investments is as follows (in thousands):  As of December 31,2009

          

          2008Current assets

          

          $

          32,996

          

          

          $

          27,772Noncurrent assets

          

          $

          214,463

          

          

          $

          191,438Current liabilities

          

          $

          4,898

          

          

          $

          14,152Noncurrent liabilities

          

          $

          5,392

          

          

          $

          3,356
  Year Ended December 31,2009

          

          2008

          

          2007Revenues

          

          $

          68,106

          

          

          $

          43,687

          

          

          $

          11,347Expenses

          

          $

          34,916

          

          

          $

          25,204

          

          

          $

          5,637Net income

          

          $

          33,190

          

          

          $

          18,483

          

          

          $

          5,710
 9. Goodwill Goodwill is tested for impairment on an annual basis, at a minimum, and more frequently if a triggering event occurs. Our 2008 annual impairment testing of goodwill and other intangible assets resulted in an impairment to goodwill of approximately $31.8 million in the fourth quarter of 2008. The impairment loss, which was triggered by fourth quarter declines in oil and gas spot and futures prices and a decline in our market capitalization, reduces to zero all goodwill recorded in conjunction with acquisitions made by the natural gas midstream segment in 2008 and prior years. In determining the fair value of the natural gas midstream segment (reporting unit), we used an income approach. Under the income approach, the fair value of the reporting unit is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, appropriate discount rates and a market derived earnings multiple terminal value (the value of the reporting unit at the end of the estimation period). Key assumptions used in the discounted cash flows model described above include estimates of future commodity prices based on the December 31, 2008 commodity price strips and estimates of operating, administrative and capital costs. We discounted the resulting future cash flows using a peer company based weighted average cost of capital of 12%. This loss is recorded in the impairment line on our consolidated statements of income. The goodwill impairment loss reflects the negative impact of certain factors which resulted in a reduction in the anticipated cash flows used to estimate fair value. The business and marketplace environments in which we currently operate differs from the historical environments that drove the factors used to value and record the acquisition of these business units. There is no goodwill balance as of December 31, 2009 and 2008.
 96    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 10. Intangible Assets, net The following table summarizes our net intangible assets as of December 31, 2009 and 2008 (in thousands):  As of December 31,2009

          

          2008Contracts and customer relationships

          

          $

          104,700

          

          

          $

          106,900Rights-of-way

          

          

          4,552

          

          

          

          4,552Total intangible assets

          

          

          109,252

          

          

          

          111,452Accumulated amortization

          

          

          (25,511

          )

          

          

          (18,780

          )Intangible assets, net

          

          $

          83,741

          

          

          $

          92,672
 The contracts and customer relationships and rights-of-way were primarily acquired in the Lone Star acquisition. See Note 3, Acquisitions. Contracts and customer relationships are amortized on a straight-line basis over the expected useful lives of the individual contracts and relationships, up to 20 years. Total intangible amortization expense for the years ended December 31, 2009, 2008 and 2007 was approximately $7.4 million, $5.5 million and $4.1 million. As of December 31, 2009 and 2008, accumulated amortization of intangible assets was $25.5 million and $18.8 million. The following table sets forth our estimated aggregate
amortization expense for the next five years and thereafter (in thousands):  Year

          

          Amortization Expense2010

          

          $

          6,7912011

          

          

          6,2852012

          

          

          5,7182013

          

          

          5,4992014

          

          

          5,346Thereafter

          

          

          54,102Total

          

          $

          83,741
 11. Allowance for Prepaid Minimums We establish provisions for losses on long-term prepaid minimums if we determine that we will not recoup all or part of the outstanding balance. Collectability is reviewed periodically and an allowance is established or adjusted, as necessary, using the specific identification method. The allowance is netted against long-term prepaid minimums on our consolidated balance sheets. The following table presents the activity of our allowance for prepaid minimums for the years ended December 31, 2009, 2008 and 2007 (in thousands):  Year Ended December 31,2009

          

          2008

          

          2007Balance at beginning of period

          

          $

          1,972

          

          

          $

          1,646

          

          

          $

          1,737Charges to expense

          

          

          138

          

          

          

          326

          

          

          

          (91

          )Forfeiture of prepaid minimum

          

          

          

          

          

          

          

          

          

          

          Balance at end of period

          

          $

          2,110

          

          

          $

          1,972

          

          

          $

          1,646
 97    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 12. Asset Retirement Obligations The following table reconciles the beginning and ending aggregate carrying amount of our asset retirement obligations for the years ended December 31, 2009 and 2008, which are recorded in other liabilities on our consolidated balance sheets (in thousands):  Year Ended December 31,2009

          

          2008Balance at beginning of period

          

          $

          1,814

          

          

          $

          2,028Liabilities incurred

          

          

          208

          

          

          

          Accretion expense

          

          

          (8

          )

          

          

          291Revision of estimate

          

          

          

          

          

          

          (505

          )Balance at end of period

          

          $

          2,014

          

          

          $

          1,814
 The accretion expense is recorded in the depreciation, depletion and amortization expense line on the consolidated statements of income. 13. Long-Term Debt The following table summarizes our long-term debt as of December 31, 2009 and 2008 (in thousands):  As of December 31,2009

          

          2008Revolver  variable rate of 2.5% and 4.4% at December 31, 2009 and 2008

          

          $

          620,100

          

          

          $

          568,100Total debt

          

          

          620,100

          

          

          

          568,100Less: Current maturities

          

          

          

          

          

          

          Total long-term debt

          

          $

          620,100

          

          

          $

          568,100
 We capitalized interest costs amounting to $0.2 million and $0.7 million in the years ended December 31, 2009 and 2008 related to the construction of natural gas processing plants. Revolver As of December 31, 2009, net of outstanding indebtedness of $620.1 million and letters of credit of $1.6 million, we had remaining borrowing capacity of $178.3 million on the Revolver. In March 2009, we increased the size of our Revolver from $700.0 million to $800.0 million and secured the Revolver with substantially all of our assets. The Revolver matures in December 2011 and is available to us for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10.0 million sublimit for the issuance of letters of credit. In 2009, we incurred commitment fees of $0.5 million on the unused portion of the Revolver.
The interest rate under the Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 1.25% if we select the base rate indebtedness option under the Revolver or at a rate derived from LIBOR plus an applicable margin ranging from 1.75% to 2.75% if we select the LIBOR-based indebtedness option. The weighted average interest rate on indebtedness outstanding under the Revolver during 2009 was approximately 2.7%. We do not have a public credit rating for the Revolver. The financial covenants under the Revolver require us not to exceed specified ratios. The Revolver prohibits us from making distributions to our partners if any potential default, or event of default, as defined in the Revolver, occurs or would result from the distributions. In addition, the Revolver contains various covenants that limit our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business, or enter into a merger or sale of our assets, including the sale or transfer of interests in our subsidiaries. As of December 31, 2009, we were in compliance with
all of our covenants under the Revolver.
 98    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. Long-Term Debt   (continued) Notes In July 2008, we paid an aggregate of $63.3 million to the holders of the Senior Unsecured Notes due 2013 (the Notes) to prepay 100% of the aggregate principal amount of the Notes. This amount consisted of approximately $58.4 million aggregate principal amount outstanding on the Notes, $1.1 million in accrued and unpaid interest on the Notes through the prepayment date and $3.8 million in make-whole amounts due in connection with the prepayment. The $3.8 million of make-whole payments were recorded in interest expense on our consolidated statements of income. The Notes were repaid with long-term debt under the Revolver. While the Notes
were outstanding, we had a public credit rating. However, due to the repayment of the Notes, we have elected not to renew this rating. As of December 31, 2007, we owed $64.0 million under the Notes, the current portion of which was $12.6 million. The Notes bore interest at a fixed rate of 6.02%. Debt Maturities The following table sets forth the aggregate maturities of the principal amounts of long-term debt for the next five years and thereafter (in thousands):  Year

          

          Aggregate Maturities of Principal Amounts2010

          

          $

          2011

          

          

          620,1002012

          

          

          2013

          

          

          2014

          

          

          Thereafter

          

          

          Total debt, including current maturities

          

          $

          620,100
 14. Partners Capital and Distributions As of December 31, 2009, partners capital consisted of 51.8 million common units, representing a 98% limited partner interest and a 2% general partner interest. As of December 31, 2009, affiliates of Penn Virginia, in the aggregate, owned a 39% interest in us, consisting of 19.6 million common units and a 2% general partner interest. Net Income per Limited Partner Unit Effective January 1, 2009, we adopted the new accounting standard addressing the computation of earnings per share for master limited partnerships that issue multiple classes of securities that participate in partnerships distribtutions. Our securities consist of publicly traded common units held by limited partners, a general partner interest and separately transferable incentive distribution rights (IDRs). This standard requires earnings or losses for a reporting period to be allocated to our limited partners, our general partner and holders of IDRs using the two-class method to compute earnings per unit. Under this method, our net
income (or loss) for a reporting period is reduced (or increased) by the amount that has been or will be distributed to our participating security holders. In the event that our net income exceeds our distributions (or our distributions exceed our net income), such excess undistributed net income (or loss) is allocated to our limited partners and our general partner in the ratio of 98% and 2%, as provided in our partnership agreement. Also on January 1, 2009, we adopted the new accounting standard which determines whether instruments granted in share-based payments transactions are participating securities. Under this standard, unvested unit-based payment awards that contain non-forfeitable rights to distributions or distribution equivalents are participating securities and, therefore, are included in the computation of net income allocable to limited
 99    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. Partners Capital and Distributions   (continued) partners pursuant to the two-class method of computing earnings per unit. During the year ended December 31, 2009, our general partner granted phantom units to employees of our general partner or its affiliates. We have determined that our unvested phantom unit awards contain non-forfeitable rights to distributions and, therefore, are participating securities for purposes of this standard. Basic and diluted net income per limited partner unit is computed by dividing net income allocable to limited partners by the weighted average number of limited partner units outstanding during the period. Diluted net income per limited partner unit is computed by dividing net income allocable to limited partners by the weighted average number of limited partner units outstanding during the period and, when dilutive, phantom units. For the year ended December 31, 2009 the average awards of 151,000 phantom units were excluded from the diluted net income per limited partner unit calculation because the inclusion of these phantom units would have had an
antidilutive effect. The following table reconciles net income and weighted average units used in computing basic and diluted net income per limited partner unit (in thousands, except per unit data):  Year Ended December 31,2009

          

          2008

          

          2007As Adjusted

          

          As AdjustedNet income

          

          $

          65,215

          

          

          $

          104,500

          

          

          $

          56,623Less:Distributions payable on account of incentive distribution rights

          

          

          (24,140

          )

          

          

          (22,067

          )

          

          

          (13,358

          )Distributions payable on account of general partner interest

          

          

          (1,988

          )

          

          

          (1,903

          )

          

          

          (1,600

          )General partner interest in excess of distributions over earnings allocable to the general partner interest

          

          

          1,166

          

          

          

          255

          

          

          

          734Net income allocable to limited partners and participating securities

          

          $

          40,253

          

          

          $

          80,785

          

          

          $

          42,399Less:Distributions to participating securities

          

          

          (664

          )

          

          

          

          

          

          

          Participating securities allocable share of net income

          

          

          (210

          )

          

          

          

          

          

          

          Net income allocable to limited partners

          

          $

          39,379

          

          

          $

          80,785

          

          

          $

          42,399Weighted average limited partner units, basic and diluted

          

          

          51,799

          

          

          

          49,495

          

          

          

          46,103Net income per limited partner unit, basic and diluted

          

          $

          0.76

          

          

          $

          1.63

          

          

          $

          0.92
 The foregoing amounts reflect the retroactive application of the two new accounting standards described above on certain previously reported items for the years ended 2008 and 2007. Subordinated Units Until May 22, 2007, we had Class B units, a separate class of subordinated units representing limited partner interests in us, which were issued to PVG in connection with PVGs initial public offering. On May 22, 2007, all of our Class B units automatically converted into common units on a one-for-one basis and no Class B units remain outstanding.
 100    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. Partners Capital and Distributions   (continued) Cash Distributions We distribute 100% of Available Cash (as defined in our partnership agreement) within 45 days after the end of each quarter to unitholders of record and to our general partner. Available Cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established by our general partner for future requirements. Our general partner has the discretion to establish cash reserves that are necessary or appropriate to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any of our debt instruments or other agreements or (iii) provide funds for distributions to unitholders and
our general partner for any one or more of the next four quarters. According to our partnership agreement, our general partner receives incremental incentive cash distributions if cash distributions exceed certain target thresholds as follows:  Unitholders

          

          GeneralPartnerQuarterly cash distribution per unit:First target  up to $0.275 per unit

          

          

          98

          %

          

          

          2

          %Second target  above $0.275 per unit up to $0.325 per unit

          

          

          85

          %

          

          

          15

          %Third target  above $0.325 per unit up to $0.375 per unit

          

          

          75

          %

          

          

          25

          %Thereafter  above $0.375 per unit

          

          

          50

          %

          

          

          50

          %
 The following table reflects the allocation of total cash distributions paid by us during the years ended December 31, 2009, 2008 and 2007 (in thousands, except per unit data):  Year Ended December 31,2009

          

          2008

          

          2007Limited partner units

          

          $

          97,382

          

          

          $

          89,207

          

          

          $

          76,536General partner interest (2%)

          

          

          1,988

          

          

          

          1,820

          

          

          

          1,562Incentive distribution rights

          

          

          24,140

          

          

          

          20,049

          

          

          

          11,551Phantom units

          

          

          499

          

          

          

          

          

          

          

          Total cash distributions paid

          

          $

          124,009

          

          

          $

          111,076

          

          

          $

          89,649Total cash distributions paid per limited partner unit

          

          $

          1.88

          

          

          $

          1.82

          

          

          $

          1.66
 On February 12, 2010, we paid a $0.47 quarterly distribution per unit to unitholders of record on February 2, 2010. This distribution was unchanged from the previous distribution paid on November 13, 2009. Limited Call Right If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to acquire all of the remaining common units held by unaffiliated persons as of a record date to be selected by our general partner, on at least ten but not more than 60 days notice, at a price equal to the greater of (i) the average of the daily closing prices of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest price paid by our general partner or any of its affiliates for common
units during the 90-day period preceding the date such notice is first mailed. 15. Related Party Transactions General and Administrative Penn Virginia charges us for certain corporate administrative expenses which are allocable to us and our subsidiaries. When allocating general corporate expenses, consideration is given to property and equipment, payroll and general corporate overhead. Any direct costs are paid by us. Total corporate administrative
 101    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 15. Related Party Transactions   (continued) expenses charged to us and our subsidiaries totaled $5.3 million, $5.1 million and $4.2 million for the years ended December 31, 2009, 2008 and 2007. These costs are reflected in general and administrative expenses in our consolidated statements of income. At least annually, our management performs an analysis of general corporate expenses based on time allocations of shared employees and other pertinent factors. Based on this analysis, our management believes that the allocation methodologies used are reasonable. Accounts Payable  Affiliate Amounts payable to related parties totaled $7.2 million and $8.0 million as of December 31, 2009 and 2008. The balance primarily relates to amounts due to a wholly owned subsidiary of Penn Virginia, Penn Virginia Oil & Gas, L.P. (PVOG LP), related to the natural gas gathering and processing agreement between PVR East Texas Gas Processing, LLC (PVR East Texas) and PVOG LP. See  Gathering and Processing Revenues. These balances are included in accounts payable on our consolidated balance sheets. Marketing Revenues PVOG LP and Connect Energy Services, LLC (Connect Energy), our wholly owned subsidiary, are parties to a Master Services Agreement effective September 1, 2006. Pursuant to the Master Services Agreement, PVOG LP and Connect Energy have agreed that Connect Energy will market all of PVOG LPs oil and gas production in Arkansas, Louisiana, Oklahoma and Texas for a fee equal to 1% of the net sales price (subject to specified limitations) received by PVOG LP for such production. The Master Services Agreement has a primary term of five years and automatically renews for additional one-year terms until terminated by either party. Under the
Master Services Agreement, PVOG LP paid fees to Connect Energy of $1.4 million, $3.0 million and $2.2 million for the years ended December 31, 2009, 2008 and 2007. Marketing revenues are included in other revenues on our consolidated statements of income. Gathering and Processing Revenues PVR East Texas and PVOG LP are parties to a natural Gas Gathering and Processing Agreement effective April 1, 2007. Pursuant to the Gas Gathering and Processing Agreement, PVOG LP and PVR East Texas have agreed that PVR East Texas will gather and process all of PVOG LPs current and future gas production in certain areas of the Bethany Field in East Texas and redeliver the NGLs to PVOG LP for a $0.3115/MMBtu service fee (with an annual CPI adjustment). The Gas Gathering and Processing Agreement has a primary term of 15 years and automatically renews for additional one year terms until terminated by either party. PVR East Texas began gathering
and processing PVOG LPs gas in June 2008. For the years ended December 31, 2009 and 2008, PVOG LP paid PVR East Texas $4.0 million and $2.3 million in fees pursuant to the Gas Gathering and Processing Agreement. These gathering and processing revenues are recorded in the natural gas midstream line on our consolidated statements of income. In addition to the gathering and processing by PVR East Texas, PVOG LP sells the processed natural gas and NGLs to Connect Energy at PVRs Crossroads Plant, Connect Energy transports them to the marketing location, and then Connect Energy resells such gas or NGLs to third parties. The sales price received by PVOG LP from Connect Energy for such gas or NGLs equals the sales price received by Connect Energy for such gas or NGLs from the third parties. For the years ended December 31, 2009 and 2008, PVOG LP received and recognized revenue of $ 72.5 million and $127.9 million from Connect Energy in connection with such sales. For the years ended
December 31, 2009 and 2008, PVR recorded $72.5 million and $127.9 million of natural gas midstream revenue and $72.5 million and $127.9 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG LP and the subsequent sale of that gas to third parties. We take title to the gas prior to transporting it to third parties.
 102    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 16. Unit-Based Payments Long-Term Incentive Plan Authoritative accounting literature establishes standards for transactions in which an entity exchanges its equity instruments for goods and services. These standards requires us to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. As of December 31, 2009, the Partnership had the Penn Virginia Resource GP, LLC Fifth Amended and Restated Long-Term Incentive Plan (LTIP) which is administered by the Compensation and Benefits Committee (the Committee) of our general partner, Penn Virginia Resource GP, LLC, and is intended to promote the interest of the Partnership. The LTIP permitted the grant of awards to employees and directors of our general partner and employees of its affiliates who perform services for us. In January 2009, the LTIP was amended to permit the granting of awards covering an aggregate of 3,000,000 common units to employees and directors of
our general partner and employees of its affiliates who perform services for us. Awards under the LTIP can be in the form of common units, restricted units, unit options, phantom units and deferred common units. We reimburse our general partner for payments made pursuant to the LTIP and recognize compensation cost based on the fair value of the awards over the vesting period. We recognized a total of $4.8 million, $3.2 million and $2.4 million in the years ended December 31, 2009, 2008 and 2007 of compensation expense related to the granting of common units and deferred common units and the vesting of restricted and phantom units granted under the LTIP. These expenses are recorded on the general and administrative expense line on our consolidated statements of income. Common Units.  Our general partner granted 1,871 common units at a weighted average grant-date fair value of $15.46 per unit to non-employee directors in 2009. Our general partner granted 1,525 common units at a weighted average grant-date fair value of $20.27 per unit to non-employee directors in 2008. Our general partner granted 1,183 common units at a weighted average grant-date fair value of $27.09 per unit to non-employee directors in 2007. Deferred Common Units.  A portion of the compensation to the non-employee directors of our general partner is paid in deferred common units. Each deferred common unit represents one common unit, which vests immediately upon issuance and is available to the holder upon termination or retirement from the board of directors of our general partner.  Number ofDeferredCommon Units

          

          Weighted Average Grant-Date Fair ValueBalance at January 1, 2007

          

          

          38,907

          

          

          $

          25.26Granted and vested

          

          

          22,311

          

          

          

          26.42Balance at December 31, 2007

          

          

          61,218

          

          

          

          25.68Granted and vested

          

          

          30,951

          

          

          

          20.36Converted to common units

          

          

          (28,600

          )

          

          

          23.70Balance at December 31, 2008

          

          

          63,569

          

          

          

          23.98Granted and vested

          

          

          35,819

          

          

          

          15.62Balance at December 31, 2009

          

          

          99,388

          

          

          

          20.97
 In 2008, 28,600 deferred common units converted to common units. The aggregate intrinsic value of deferred common units converted to common units in 2008 and 2006 was $0.7 million and $0.2 million. The fair value of the deferred common units is calculated based on the grant-date unit price. Restricted Units.  Restricted units vest upon terms established by the Committee. In addition, all restricted units will vest upon a change of control of our general partner or Penn Virginia. If a grantees
 103    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 16. Unit-Based Payments   (continued) employment with, or membership on the board of directors of, our general partner terminates for any reason, the grantees unvested restricted units will be automatically forfeited unless, and to the extent that, the Committee provides otherwise. Distributions payable with respect to restricted units may, in the Committees discretion, be paid directly to the grantee or held by our general partner and made subject to a risk of forfeiture during the applicable restriction period. Restricted units generally vest over a three-year period, with one-third vesting in each year. The following table summarizes the status of our nonvested restricted units as of December 31, 2009 and changes during the year then ended:  Nonvested Restricted Units

          

          WeightedAverageGrant-DateFair ValueNonvested at January 1, 2009

          

          

          221,855

          

          

          $

          26.93Granted

          

          

          

          

          

          

          Vested

          

          

          (128,106

          )

          

          

          27.19Forfeit

          

          

          (940

          )

          

          

          26.36Nonvested at December 31, 2009

          

          

          92,809

          

          

          $

          26.57
 At December 31, 2009, we had $1.2 million of total unrecognized compensation cost related to nonvested restricted units. We expect to reimburse our general partner for that cost over a weighted-average period of 0.3 years. The total grant-date fair value of restricted units that vested in 2009, 2008 and 2007 was $3.5 million, $1.9 million and $1.2 million. Phantom Units.  A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of the Committee, the cash equivalent of the value of a common unit. The Committee determines the time period over which phantom units granted to employees and directors will vest. In addition, all phantom units will vest upon a change of control of our general partner or Penn Virginia. If a directors membership on the board of directors of our general partner terminates for any reason, or an employees employment with our general partner and its affiliates terminates for any reason other
than retirement after reaching age 62 and completing 10 years of consecutive service, the grantees phantom units will be automatically forfeited unless, and to the extent, the Committee provides otherwise. In 2009, 354,792 phantom unit grants were made under our LTIP. This was the first year for phantom unit grants and 2,379 phantom units were forfeited in 2009. Phantom units generally vest over a three-year period, with one-third vesting in each year. The Committee, in its discretion, may grant tandem distribution equivalent rights with respect to phantom units. A distribution equivalent right is a right to receive an amount in cash equal to, and 30 days after, the cash distributions made with respect to a common unit during the period such phantom unit is outstanding. Payments of distribution equivalent rights associated with units that are expected to vest are recorded as capital distributions; however, payments associated with units that are not expected to vest are recorded
as compensation expense.
 104    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 16. Unit-Based Payments   (continued) The following table summarizes the status of our nonvested phantom units as of December 31, 2009 and changes during the year then ended:  Nonvested Phantom Units

          

          WeightedAverageGrant-DateFair ValueNonvested at January 1, 2009

          

          

          

          

          

          $

          Granted

          

          

          354,792

          

          

          

          11.59Vested

          

          

          (75,410

          )

          

          

          11.59Forfeit

          

          

          (2,379

          )

          

          

          11.59Nonvested at December 31, 2009

          

          

          277,003

          

          

          $

          11.59
 At December 31, 2009, we had $2.3 million of total unrecognized compensation cost related to nonvested phantom units. The total grant-date fair value of restricted units that vested in 2009 was $0.9 million. 17. Commitments and Contingencies Rental Commitments Operating lease rental expense in the years ended December 31, 2009, 2008 and 2007 was $7.5 million, $4.5 million and $2.6 million. The following table sets forth our minimum rental commitments for the next five years under all non-cancelable operating leases in effect at December 31, 2009 (in thousands):  Year

          

          Minimum RentalCommitments2010

          

          $

          4,2432011

          

          

          3,4132012

          

          

          3,0172013

          

          

          2,9712014

          

          

          2,893Thereafter

          

          

          7,943Total minimum payments

          

          $

          24,480
 Our rental commitments primarily relate to equipment and building leases and leases of coal reserve-based properties which we sublease, or intend to sublease, to third parties. The obligation with respect to leased properties which we sublease expires when the property has been mined to exhaustion or the lease has been canceled. The timing of mining by third party operators is difficult to estimate due to numerous factors. We believe that the future rental commitments with regard to this subleased property cannot be estimated with certainty.
 105    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 17. Commitments and Contingencies   (continued) Firm Transportation Commitments As of December 31, 2009, we had contracts for firm transportation capacity rights for specified volumes per day on a pipeline system with terms that ranged from one to seven 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. The following table sets forth our obligation for firm transportation commitments in effect at December 31, 2009 for the next five years and thereafter (in thousands):  Year

          

          Firm TransportationCommitments2010

          

          $

          13,1032011

          

          

          5,6942012

          

          

          4,5082013

          

          

          4,0332014

          

          

          3,321Thereafter

          

          

          1,661Total firm transportation commitments

          

          $

          32,320
 Legal We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position or results of operations. Environmental Compliance Our operations and those of our lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of our coal property leases impose liability on the relevant lessees for all environmental and reclamation liabilities arising under those laws and regulations. The lessees are bonded and have indemnified us against any and all future environmental liabilities. We regularly visit our coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. Our management believes that our operations and
those of our lessees comply with existing laws and regulations and does not expect any material impact on our financial condition or results of operations. As of December 31, 2009 and 2008, our environmental liabilities were $1.0 million and $1.2 million, which represents our best estimate of the liabilities as of those dates related to our coal and natural resource management and natural gas midstream businesses. We have reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future. Mine Health and Safety Laws There are numerous mine health and safety laws and regulations applicable to the coal mining industry. However, since we do not operate any mines and do not employ any coal miners, we are not subject to such laws and regulations. Accordingly, we have not accrued any related liabilities.
 106    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 18. Comprehensive Income Comprehensive income represents changes in partners capital during the reporting period, including net income and charges directly to partners capital which are excluded from net income. The following table sets forth the components of comprehensive income for the periods presented (in thousands):  Year Ended December 31,2009

          

          2008

          

          2007Net income

          

          $

          65,215

          

          

          $

          104,500

          

          

          $

          56,623Unrealized holding losses on derivative activities

          

          

          (506

          )

          

          

          (4,039

          )

          

          

          (2,599

          )Reclassification adjustment for derivative activities

          

          

          3,356

          

          

          

          7,186

          

          

          

          3,859Comprehensive income

          

          $

          68,065

          

          

          $

          107,647

          

          

          $

          57,883
 Included in the comprehensive income balance at December 31, 2009 is $1.4 million of losses relating to Interest Rate Swaps on which we discontinued hedge accounting. The $1.4 million loss will be recognized in earnings through the end of 2011 as the hedged transactions settle. See Note 6, Derivative Instruments. 19. Segment Information Our operating segments represent components of our business about which separate financial information is available and is evaluated regularly by the chief operating decision maker, or decision-making group, in assessing performance. Our decision-making group consists of our Chief Executive Officer and other senior officers. This group routinely reviews and makes operating and resource allocation decisions among our coal and natural resource management operations and our natural gas midstream operations. Accordingly, our reportable segments are as follows: 

          Coal and Natural Resource Management   Our coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. Our coal reserves are primarily located in Kentucky, Virginia, West Virginia, Illinois and New Mexico. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees. 

          Natural Gas Midstream   Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. We own and operate natural gas midstream assets located in Oklahoma and Texas. Our 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. In addition, we own a 25% member interest in Thunder Creek Gas Services, LLC (Thunder Creek), a joint venture that gathers and transports coalbed methane in Wyomings Powder River Basin. We also own 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.
 107    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 19. Segment Information   (continued) The following table presents a summary of certain financial information relating to our segments as of and for the years ended December 31, 2009, 2008 and 2007 (in thousands):  Revenues

          

          Operating income2009

          

          2008

          

          2007

          

          2009

          

          2008

          

          2007Coal and natural resource management(1)

          

          $

          144,600

          

          

          $

          153,327

          

          

          $

          111,639

          

          

          $

          87,528

          

          

          $

          96,296

          

          

          $

          68,811Natural gas midstream(2)

          

          

          512,104

          

          

          

          728,253

          

          

          

          437,806

          

          

          

          20,774

          

          

          

          18,946

          

          

          

          48,914Consolidated totals

          

          $

          656,704

          

          

          $

          881,580

          

          

          $

          549,445

          

          

          $

          108,302

          

          

          $

          115,242

          

          

          $

          117,725Interest expense

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          (24,653

          )

          

          

          (24,672

          )

          

          

          (17,338

          )Other

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          1,280

          

          

          

          (2,907

          )

          

          

          1,804Derivatives

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          (19,714

          )

          

          

          16,837

          

          

          

          (45,568

          )Consolidated net income

          

          

          

          

          

          

          

          

          

          

          

          

          

          $

          65,215

          

          

          $

          104,500

          

          

          $

          56,623
  Additions to property and equipment

          

          DD&A expenses2009

          

          2008

          

          2007

          

          2009

          

          2008

          

          2007Coal and natural resource management

          

          $

          2,252

          

          

          $

          27,270

          

          

          $

          177,960

          

          

          $

          31,330

          

          

          $

          30,805

          

          

          $

          22,690Natural gas midstream

          

          

          78,425

          

          

          

          304,758

          

          

          

          47,080

          

          

          

          38,905

          

          

          

          27,361

          

          

          

          18,822Consolidated totals

          

          $

          80,677

          

          

          $

          332,028

          

          

          $

          225,040

          

          

          $

          70,235

          

          

          $

          58,166

          

          

          $

          41,512
  Total assets at December 31,2009

          

          2008

          

          2007Coal and natural resource management(3)

          

          $

          574,258

          

          

          $

          600,418

          

          

          $

          610,866Natural gas midstream(4)

          

          

          633,802

          

          

          

          618,402

          

          

          

          320,413Consolidated totals

          

          $

          1,208,060

          

          

          $

          1,218,820

          

          

          $

          931,279
  (1)

          Our coal and natural resource management segments revenues for the years ended December 31, 2009, 2008 and 2007 include $1.7 million, $1.8 million and $1.8 million of equity earnings related to our 50% interest in Coal Handling Solutions LLC. See Note 8, Equity Investments for a further description. (2)

          Our natural gas midstream segments revenues for the year ended December 31, 2009 and 2008 include $5.3 million and $2.4 million of equity earnings related to our 25% member interest in Thunder Creek that we acquired in 2008 for $51.6 million. See Note 3, Acquisitions for a further description of this acquisition and Note 8, Equity Investments for a further description of this segments equity investment. Operating income for the year ended December 31, 2008 included a noncash impairment charge of $31.8 million related to the reduction in the value of natural gas midstream goodwill. See Note 9, Goodwill for further discussion of this impairment. (3)

          Total assets at December 31, 2009, 2008 and 2007 for the coal and natural resource management segment included equity investment of $21.0 million, $23.4 million and $25.6 million related to our 50% interest in Coal Handling Solutions LLC. See Note 8, Equity Investments for a further description. (4)

          Total assets at December 31, 2009 and 2008 for the natural gas midstream segment included equity investment of $59.8 million and $55.0 million related to our 25% member interest in Thunder Creek that we acquired in 2008. Total assets for the year ended December 31, 2008 include the effects of the Lone Star acquisition. See Note 3, Acquisitions and Note 8, Equity Investments for a further description. Total assets at December 31, 2007 for the natural gas midstream segment included goodwill of $7.7 million.
 108    TABLE OF CONTENTS PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 19. Segment Information   (continued) Operating income is equal to total revenues less cost of midstream gas purchased, operating costs and expenses and DD&A expense. Operating income does not include interest expense, certain other income items and derivatives. Identifiable assets are those assets used in our operations in each segment. For the year ended December 31, 2009, two customers of our natural gas midstream segment accounted for $109.5 million and $75.4 million, or 17% and 11%, of our total consolidated net revenues. These customer concentrations may impact our results of operations, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We are not aware of any financial difficulties experienced by these customers. For the year ended December 31, 2008, two of our natural gas midstream segment customers accounted for $194.9 million and $93.8 million, or 22% and 11%, of our total consolidated net revenues. For the year ended December 31, 2007, three customers of our natural gas midstream segment accounted for approximately $109.2 million, $61.0 million and $60.5 million, or 20%, 11% and 11%, of our total consolidated net revenues. Supplemental Quarterly Financial Information (Unaudited, in thousands except unit data)  FirstQuarter

          

          SecondQuarter

          

          ThirdQuarter

          

          FourthQuarter2009Revenues

          

          $

          156,759

          

          

          $

          149,419

          

          

          $

          155,625

          

          

          $

          194,901Operating income

          

          $

          21,927

          

          

          $

          21,393

          

          

          $

          27,816

          

          

          $

          37,166Net income

          

          $

          9,468

          

          

          $

          13,322

          

          

          $

          18,824

          

          

          $

          23,601Basic and diluted net income per limited partner unit(1)

          

          $

          0.06

          

          

          $

          0.13

          

          

          $

          0.24

          

          

          $

          0.33Weighted average number of units outstanding, basic and diluted

          

          

          51,799

          

          

          

          51,799

          

          

          

          51,799

          

          

          

          51,7992008Revenues

          

          $

          156,814

          

          

          $

          276,505

          

          

          $

          285,276

          

          

          $

          162,985Operating income (loss)(2)

          

          $

          31,234

          

          

          $

          44,329

          

          

          $

          40,023

          

          

          $

          (344

          )Net income

          

          $

          34,540

          

          

          $

          9,471

          

          

          $

          44,552

          

          

          $

          15,937Basic and diluted net income per limited partner unit(1)

          

          $

          0.64

          

          

          $

          0.08

          

          

          $

          0.73

          

          

          $

          0.19Weighted average number of units outstanding, basic and diluted

          

          

          46,106

          

          

          

          48,581

          

          

          

          51,663

          

          

          

          51,799
  (1)

          The sum of the quarters may not equal the total of the respective years net income per limited partner unit due to applying the two-class method of calculating net income per limited partner unit. The 2008 basic and diluted net income per limited partner unit amounts have been recast give application of new accounting standards. See Note 2, Summary of Significant Accounting Policies. (2)

          Operating income in 2008 included a loss on the impairment of goodwill of $31.8 million that we recorded in the fourth quarter of 2008. See Note 9, Goodwill.
 109    TABLE OF CONTENTS Item 9 Changes in and Disagreements With Accountants on Accounting and Financial Disclosure None. Item 9A Controls and Procedures (a) Disclosure Controls and Procedures Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of December 31, 2009. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded
that, as of December 31, 2009, such disclosure controls and procedures were effective. (b) Managements Annual Report on Internal Control Over Financial Reporting Our management, including our Chief Executive Officer and our Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over our financial reporting. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2009. This evaluation was completed based on the framework established in Internal Control  Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Our management has concluded that, as of December 31, 2009, our internal control over financial reporting was effective. (c) Attestation Report of the Registered Public Accounting Firm KPMG LLP, an independent registered public accounting firm, or KPMG, has issued an attestation report on our internal control over financial reporting as of December 31, 2009, which is included in Item 8 of this Annual Report on Form 10-K. (d) Changes in Internal Control Over Financial Reporting No changes were made in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Item 9B Other Information There was no information that was required to be disclosed by us on a Current Report on Form 8-K during the fourth quarter of 2009 which we did not disclose.
 110    TABLE OF CONTENTS Part III Item 10 Directors, Executive Officers and Corporate Governance Directors and Executive Officers The following table sets forth information concerning the directors and executive officers of our general partner. All directors of our general partner are elected, and may be removed, by PVG, its sole member and a majority-owned subsidiary of Penn Virginia.  Name

          

          Age

          

          Position with Our General PartnerA. James Dearlove

          

          62

          

          Chairman of the Board of Directors and Chief Executive OfficerEdward B. Cloues, II

          

          62

          

          DirectorJames L. Gardner

          

          58

          

          DirectorThomas W. Hofmann

          

          58

          

          DirectorJames R. Montague

          

          62

          

          DirectorMarsha R. Perelman

          

          59

          

          DirectorFrank A. Pici

          

          54

          

          Director and Vice President and Chief Financial OfficerNancy M. Snyder

          

          56

          

          Director and Vice President, Chief Administrative Officer and General CounselKeith D. Horton

          

          56

          

          Co-President and Chief Operating Officer  CoalRonald K. Page

          

          59

          

          Co-President and Chief Operating Officer  Midstream
 A. James Dearlove has served as Chairman of the Board of Directors and Chief Executive Officer of our general partner since December 2002 and July 2001 and as Chairman of the Board of Directors and President and Chief Executive Officer of PVGs general partner since September 2006. Mr. Dearlove has also served in various capacities with Penn Virginia since 1977, including as President and Chief Executive Officer since May 1996, as President and Chief Operating Officer from 1994 to May 1996, as Senior Vice President from 1992 to 1994 and as Vice President from 1986 to 1992. Mr. Dearlove also serves as a director of Penn Virginia and
as a director of the National Council of Coal Lessors. Mr. Dearlove has served in numerous capacities with Penn Virginia and its affiliates, including us, for over 30 years, during which time Penn Virginia grew from a very small company primarily engaged in the coal land management business to a much larger company primarily engaged in the oil and gas exploration and production business with controlling interests in affiliates engaged in the coal and natural resource management and natural gas midstream businesses. Mr. Dearloves broad experience and detailed knowledge of our operations lends critical support to the decision making process of the board of directors of our general partner. Edward B. Cloues, II has served as a director of our general partner since January 2003. Since January 1998, Mr. Cloues has served as Chairman of the Board and Chief Executive Officer of K-Tron International, Inc., a provider of material handling equipment and systems. From October 1979 to January 1998, Mr. Cloues was a partner of Morgan, Lewis & Bockius LLP, a global law firm. Mr. Cloues also serves as a director of Penn Virginia and is the non-executive Chairman of the Board of AMREP Corporation. As a CEO and a former law firm partner specializing in business law matters, Mr. Cloues has extensive leadership experience and familiarity with complex mergers and acquisitions and other transactions. In addition, as a result of his multiple public company directorships and other business experience, Mr. Cloues has considerable background in financial, corporate governance and executive compensation matters. James L. Gardner has served as a director of our general partner since January 2006. Since 2005, Mr. Gardner has been an Associate Professor of Philosophy at Freed-Hardeman University. From 2002 to 2004, Mr. Gardner served as Executive Vice President and Chief Administrative Officer of Massey Energy Company, or Massey, a coal mining company. From 2000 to 2002, Mr. Gardner was in the private practice of law, principally representing Massey. He also served as a director of Massey from 2000 to 2002. Mr. Gardner served as Senior Vice President of Massey from 1994 to 2000 and as General Counsel from 1993 to 2000. From 1991 to 1993, Mr.
Gardner was an attorney at the law firm of Hunton & Williams LLP.
 111    TABLE OF CONTENTS As a result of his position as a director and executive at Massey and his representation of coal clients as a lawyer, Mr. Gardner has extensive operational, strategic and legal experience related to the coal industry. With this experience, Mr. Gardner offers keen insight to the board of directors of our general partner as it oversees our coal and natural resource management operations. Thomas W. Hofmann has served as a director of our general partner since May 2009. Since December 2008, Mr. Hofmann has been retired. Mr. Hofmann served as Senior Vice President and Chief Financial Officer of Sunoco, Inc., an oil refining and marketing company, from January 2002 to December 2008 and as Vice President and Chief Financial Officer of Sunoco from July 1998 to January 2002. Mr. Hofmann also serves as a director of West Pharmaceuticals Services, Inc. In the last five years, he has also served on the board of directors of the general partner of Sunoco Logistics Partners, L.P. and VIASYS Healthcare Inc. As the former CFO of Sunoco, Inc., Mr. Hofmann has experience and knowledge regarding financial issues related to energy companies and the energy industry. Mr. Hofmann utilizes this experience as the chairman of the audit committee of the board of directors of our general partner. James R. Montague has served as a director of our general partner since July 2001. Since 2003, Mr. Montague has been retired. From 2001 to 2002, Mr. Montague served as President of EnCana Gulf of Mexico LLC, a subsidiary of EnCana Corporation, which is in the business of oil and gas exploration and production. From 1996 to June 2001, Mr. Montague served as President of two subsidiaries of International Paper Company, IP Petroleum Company, an exploration and production oil and gas company, and GCO Minerals Company, a company that manages International Paper Companys mineral holdings. Mr. Montague also serves as a director of Atwood
Oceanics, Inc. and as a director of the general partner of Magellan Midstream Partners, L.P. In the last five years, Mr. Montague has served on the board of directors of The Meridian Resource Corporation. Mr. Montague has detailed knowledge of our operations, having served as a director of our general partner since our initial public offering in 2001. In addition, Mr. Montagues substantial experience as an executive in the energy industry and as a director of another publicly traded partnership has helped him provide guidance to the board of directors of our general partner in connection with financial, strategic and other transactions. Marsha R. Perelman has served as a director of our general partner since May 2005. In 1993, Ms. Perelman founded, and since then has been the Chief Executive Officer of, Woodforde Management, Inc., a holding company. In 1983, she co-founded, and from 1983 to 1990 served as the President of, Clearfield Ohio Holdings, Inc., a gas gathering and distribution company. In 1983, she also co-founded, and from 1983 to 1990 served as Vice President of, Clearfield Energy, Inc., a crude oil gathering and distribution company. Ms. Perelman also serves as a director of Penn Virginia. Ms. Perelman has detailed knowledge of our operations, having served as a director of our general partner since 2005 and as a director of Penn Virginia since 1998. Ms. Perelmans professional and personal contacts have helped her, as the chairperson of Penn Virginias nominating and governance committee, identify and recruit director candidates for the board of directors of our general partner. In addition, Ms. Perelmans background in the energy and other industries has enabled her to contribute significantly to our strategic direction. Frank A. Pici has served as Vice President and Chief Financial Officer of our general partner since September 2001 and as a director since October 2002 and as Vice President and Chief Financial Officer and as a director of PVGs general partner since September 2006. Mr. Pici has also served as Executive Vice President and Chief Financial Officer of Penn Virginia since September 2001. 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, an oil and gas exploration and production company.
 112    TABLE OF CONTENTS During his career, Mr. Pici has gained substantial experience with managing a broad range of financial aspects of energy companies and publicly traded partnerships, including during his eight-year tenure as our CFO and Penn Virginias CFO and in connection with his service as the CFO of PVGs general partner since 2006. The board of directors of our general partner draws on this experience when it considers financial and economic analyses related to financing and other transactions. Nancy M. Snyder has served as Vice President and General Counsel and as a director of our general partner since July 2001 and as Chief Administrative Officer since May 2008 and as Vice President and General Counsel and as a director of PVGs general partner since September 2006 and as Chief Administrative Officer since May 2008. Ms. Snyder has also served in various capacities with Penn Virginia since 1997, including as Executive Vice President since May 2006, as Chief Administrative Officer since May 2008, as Senior Vice President from February 2003 to May 2006, as Vice President from December 2000 to February 2003 and as General
Counsel and Corporate Secretary since 1997. Ms. Snyder has served in numerous capacities with Penn Virginia and its affiliates, including us, for over 12 years, during which time she has overseen all legal matters, including those related to acquisitions, financings and other transactions, and has gained substantial knowledge of our operations. In addition, as chief administrative officer in charge of our human resources department, Ms. Snyder has substantial experience with corporate governance and executive compensation matters affecting us. Her experience in these areas helps her to effectively assist the board of directors of our general partner when it evaluates matters related to these
areas. Keith D. Horton has served as Co-President and Chief Operating Officer  Coal of our general partner since June 2006 and as President of PVR Coal since September 2001. From July 2001 to June 2006, Mr. Horton served as President and Chief Operating Officer of our general partner. Mr. Horton has also served in various capacities with Penn Virginia since 1981, including as Executive Vice President since December 2000, as Vice President  Eastern Operations from February 1999 to December 2000 and as Vice President from February 1996 to February 1999. Mr. Horton also serves as a director of Penn Virginia and as
director of the Virginia Mining Association, the Powell River Project and the Eastern Coal Council. Ronald K. Page has served as Co-President and Chief Operating Officer  Midstream of our general partner since June 2006 and as President of PVR Midstream since January 2005. From July 2003 to June 2006, Mr. Page served as Vice President, Corporate Development of our general partner. Mr. Page has also served in various capacities with Penn Virginia since July 2003, including as Vice President since May 2005 and as Vice President, Corporate Development from July 2003 to May 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. Role of the Board of Directors of our General Partner Our business is managed under the direction of the board of directors of our general partner. The board of directors of our general partner has adopted Corporate Governance Principles outlining its duties. A current copy of our general partners Corporate Governance Principles is available at the Governance section of our website, http://www.pvresource.com. The board of directors of our general partner meets regularly to review significant developments affecting us and to act on matters requiring its approval. Code of Business Conduct and Ethics The board of directors of our general partner has adopted a Code of Business Conduct and Ethics as its code of ethics as defined in Item 406 of Regulation S-K, which applies to all directors, officers and employees of our general partner, including its Chief Executive Officer, Chief Financial Officer, principal accounting officer or controller or persons performing similar functions, and all employees of any affiliate of our general partner who provide services to us. A current copy of our general partners Code of Business Conduct and Ethics is available at the Governance section of our website, http://www.pvresource.com. Our general partner intends to satisfy the disclosure requirement for any future amendments to, or waivers of, its Code of Business Conduct and Ethics by posting such information on our website.
 113    TABLE OF CONTENTS Executive Sessions and Meetings of Independent Directors; Communications with the Board Our general partners Independent Directors, as such term is defined in Item 13, Certain Relationships and Related Transactions, and Director Independence  Director Independence, meet in executive sessions without management during regularly scheduled meetings of the board of directors of our general partner and may do so, if appropriate, during board meetings which are scheduled on an as needed basis. James L. Gardner, an Independent Director, presides over executive sessions. Unitholders and other interested parties may communicate any concerns they have regarding us by contacting Mr. Gardner in writing c/o
Secretary, Penn Virginia Resource GP, LLC, Three Radnor Corporate Center, Suite 300, 100 Matsonford Road, Radnor, Pennsylvania 19087. Committees of the Board of Directors of our General Partner The board of directors of our general partner has an audit committee, a conflicts committee and a compensation and benefits committee. Audit Committee.  Messrs. Gardner, Hofmann and Montague are the members of the audit committee of our general partner, and each is an Independent Director. Mr. Hofmann is an audit committee financial expert as defined in Item 407(d)(5) of Regulation S-K. The audit committee of our general partner is responsible for the appointment, compensation, evaluation and termination of our independent registered public accounting firm, and oversees the work, internal quality-control procedures and independence of our independent registered public accounting firm. The committee discusses with management and our independent registered
public accounting firm our annual audited and quarterly unaudited financial statements and recommends to the board of directors of our general partner that our annual audited financial statements be included in our Annual Report on Form 10-K. The committee also discusses with management earnings press releases and guidance provided to analysts. The committee also provides oversight with respect to business risk matters, compliance with ethics policies, compliance with legal and regulatory requirements and performance of our internal audit function. The committee has established procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls, auditing and other matters and the confidential anonymous submission by employees of concerns regarding questionable accounting, auditing and other matters. The committee may obtain advice and assistance from outside legal, accounting or other advisors as it deems necessary to carry out its
duties. Conflicts Committee.  Messrs. Gardner, Hofmann and Montague are the members of the conflicts committee of our general partner, and each is an Independent Director. The conflicts committee of our general partner reviews transactions between or among us and Penn Virginia or PVG, or any of their affiliates, and any other transactions involving us or our affiliates that the board of directors of our general partner believes may involve conflicts of interest. The conflicts committee then determines whether such transactions are fair and reasonable to us, and whether our general partner has upheld the fiduciary or other duties it owes to
us. The committee may obtain advice and assistance from outside legal, financial or other advisors as it deems necessary to carry out its duties. Compensation and Benefits Committee.  Messrs. Cloues, Gardner, Hofmann and Montague are the members of the compensation and benefits committee of our general partner, and each is an Independent Director. The compensation and benefits committee of our general partner assists the compensation and benefits committee of Penn Virginia when the Penn Virginia committee determines the compensation for the executive officers of our general partner. See Item 11, Executive Compensation  Compensation Discussion and Analysis  How Compensation Is Determined  Committee Process. The
committee reviews and discusses with management the information contained in Item 11, Executive Compensation  Compensation Discussion and Analysis, and recommends that such information be included herein. The committee periodically reviews and makes recommendations or decisions regarding our general partners incentive compensation and equity-based plans, provides oversight with respect to our general partners other employee benefit plans and reports its recommendations to the board of directors of our general partner. The committee also reviews and makes recommendations to the board of directors of our general partner regarding director compensation policy. The committee may obtain advice and assistance from outside compensation consultants or other advisors as it deems necessary to carry out its duties.
 114    TABLE OF CONTENTS Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Exchange Act requires officers and directors of our general partner and beneficial owners of more than 10% of our common units to file, by a specified date, reports of beneficial ownership and changes in beneficial ownership with the SEC and to furnish copies of such reports to us. We believe that all such filings were made on a timely basis in 2009, except that we inadvertently filed one late Form 4 on behalf of Penn Virginia with respect to one transaction. Item 11 Executive Compensation Compensation Discussion and Analysis Under the rules established by the SEC, we are required to provide a discussion and analysis of information necessary to an understanding of our compensation policies and decisions regarding our Chief Executive Officer, or our CEO, Chief Financial Officer, or our CFO, and the other executive officers of our general partner named in the Summary Compensation Table included in this Annual Report on Form 10-K. The required disclosure includes the use of specified tables and a report of the compensation and benefits committee of our general partner. Unless otherwise indicated, all references in this Annual Report on Form 10-K to our NEOs refer
to the executive officers named in the Summary Compensation Table, all references to our Committee or the Committee refer to the compensation and benefits committee of our general partner, all references to the Penn Virginia Committee refer to the compensation and benefits committee of Penn Virginia and all references to the PVG Committee refer to the compensation and benefits committee of PVGs general partner. Compensation Structure Penn Virginia indirectly controls our general partner and indirectly owns a significant limited partner interest in us. Because of this relationship, and since all of our NEOs are also executives of Penn Virginia and three of our NEOs, including our CEO, devote a majority of their professional time to Penn Virginia, the Penn Virginia Committee sets compensation for our NEOs. A. James Dearlove, our CEO, Frank A. Pici, our Vice President and CFO, and Nancy M. Snyder, our Vice President, Chief Administrative Officer and General Counsel, who are referred to in this Annual Report on Form 10-K as the Shared Executives, are employees of Penn
Virginia and rendered services not only to us, but also to Penn Virginia and PVG, during 2009. We are responsible for reimbursing to Penn Virginia that portion of the Shared Executives compensation related to the services they perform for us. The specific portions of compensation reimbursed to Penn Virginia by us are determined based on the portion of professional time devoted by each Shared Executive to us. The Shared Executives are required to document the amount of professional time they spend rendering services to us. See How Compensation Is Determined  Committee Process for a discussion of our Committees review of such allocations. Two of our NEOs, Keith D. Horton, Co-President and Chief Operating Officer  Coal of our general partner, and Ronald K. Page, Co-President and Chief Operating Officer  Midstream of our general partner, who are referred to in this Annual Report on Form 10-K as the Partnership
Executives, render their services solely to us so we pay all of their compensation. Objectives of the Compensation Program The compensation program is based on the following objectives: 

          Executives should be accountable for our performance as well as their own individual performance, so compensation should be tied to both partnership financial measures and individual performance measures. 

          Executive compensation should balance and align the short-term and long-term interests of our executives with those of our unitholders, so executive compensation packages should include a mix of cash and equity-based compensation. 

          Executive compensation should be industry-competitive so that we can attract, retain and motivate talented executives with appropriate experience and skill sets. Elements of Compensation We and Penn Virginia pay our NEOs a base salary and provide them an opportunity to earn an annual cash bonus and an annual long-term compensation award. In determining these three elements of
 115    TABLE OF CONTENTS compensation, the Penn Virginia Committee, with the assistance of our Committee and the PVG Committee, takes into account certain peer group information obtained by our Committee, the Penn Virginia Committee, each such committees independent compensation consultants and management. The Penn Virginia Committee typically focuses on approximately the 50th percentile of the peer benchmarks described below under How Compensation Is Determined  Peer Benchmarks for the Partnership and How Compensation Is Determined  Peer Benchmarks for Penn Virginia, but it also applies its independent
judgment to these matters and considers such other factors as it deems relevant when determining our NEOs compensation. 

          Base Salary  We and Penn Virginia pay each of our NEOs an industry-competitive salary so that we can attract and retain talented executives. The base salaries also reflect the capabilities, levels of experience, tenure, positions and responsibilities of our NEOs. 

          Annual Cash Bonus  We and Penn Virginia provide each of our NEOs the opportunity to earn an industry-competitive annual cash bonus. This opportunity creates a strong financial incentive for our NEOs to achieve or exceed a combination of partnership and individual goals. The performance criteria by which each NEO is measured and other factors affecting the compensation of our NEOs are described below under the headings How Compensation Is Determined  Peer Benchmarks for the Partnership, How Compensation Is Determined  Peer Benchmarks for Penn Virginia, How Compensation Is Determined  Partnership, Company and Individual Performance Criteria and How Compensation Is Determined  2009 Performance Criteria. In addition to the performance criteria, our Committee and the Penn Virginia Committee may consider any other
factors they deem appropriate when awarding annual cash bonuses to our NEOs. 

          Long-Term Compensation Awards  We and Penn Virginia provide each of our NEOs the opportunity to earn an industry-competitive annual long-term compensation award. This opportunity creates a strong financial incentive for our NEOs to promote the long-term financial and operational success of the Partnership and to encourage a significant equity stake in the Partnership. See Executive Stock Ownership Guidelines below. Long-term compensation awards are expressed in dollar values, and we pay those awards in the form of restricted units or phantom units. Penn Virginia pays those awards in the form of stock options, restricted stock or restricted stock units. The actual numbers of restricted units and shares of restricted stock awarded are based on the NYSE closing prices of our common units and Penn Virginias common stock on the dates of grant. The actual number of stock options awarded is based on a
weighted-average value of all options granted to all classes of Penn Virginias employees on the date of grant using the Black-Scholes-Merton option-pricing formula. The Shared Executives long-term compensation awards are split between restricted units or phantom units of us, on the one hand, and stock options, restricted stock or restricted stock units of Penn Virginia, on the other hand. For each Shared Executive, the ratio of the split between Partnership-related long-term compensation and Penn Virginia-related long-term compensation is determined based on the amount of time such Shared Executive devotes to us, on the one hand, and Penn Virginia and PVG, on the other hand. Time devoted to PVG is included with time devoted to Penn Virginia for the purpose of splitting the type of long-term compensation awards because PVG is a majority-owned subsidiary of Penn Virginia. Executives who render services wholly or predominately to us may receive only restricted units or phantom
units, and executives who render services wholly or predominantly to Penn Virginia may receive only stock options, restricted stock or restricted stock units. Executives who receive Penn Virginia awards are given the opportunity to elect whether to receive those awards in stock options, restricted stock, restricted stock units or a combination of the three, but it is the Penn Virginia Committees policy that the awards paid in stock options must comprise at least 50% of the value of the awards.
 116    TABLE OF CONTENTS How Compensation Is Determined Committee Process.  Because of our relationship with Penn Virginia, as discussed above, the Penn Virginia Committee sets compensation for our NEOs. Our Committee and the PVG Committee assist the Penn Virginia Committee in determining executive compensation for our NEOs in the manner described below. Each of our Committee, the Penn Virginia Committee and the PVG Committee is comprised entirely of independent directors. With respect to Messrs. Horton and Page, who manage our coal and natural resource management-related and natural gas midstream-related operations, respectively, and devote substantially all of their business time to us, our Committee has the primary responsibility to assess all factors relevant to their compensation. Based on that assessment and after discussing such assessment with the PVG Committee, our Committee recommends to the Penn Virginia Committee salary, annual cash bonus and long-term compensation for them, and the Penn Virginia Committee determines their compensation. With respect to the Shared Executives, including our CEO, the Penn
Virginia Committee assesses the factors relevant to their compensation and, after discussing such assessment with our Committee and the PVG Committee, sets the salary, annual cash bonus and long-term compensation for each Shared Executive. Since all of our NEOs other than our CEO report directly to, and work on a daily basis with, our CEO, our Committee and the Penn Virginia Committee review and discuss with our CEO his evaluation of the performance of each of our other NEOs, as appropriate. The Penn Virginia Committee gives considerable weight to our CEOs evaluations when assessing our other NEOs performance and determining their compensation, and our Committee gives our CEOs evaluation considerable weight when assessing the Shared Executives performance and the amount of compensation to recommend to the Penn Virginia Committee for the Partnership Executives.
The Penn Virginia Committee bases its evaluation of our CEO, and our CEO bases his evaluation of each of our other NEOs, primarily on whether we or Penn Virginia met or exceeded certain partnership or corporate performance criteria and whether the NEO met or exceeded certain specifically tailored job-related individual performance criteria. These performance criteria and other factors relevant to our NEOs compensation are described in detail below under the headings Peer Benchmarks for the Partnership, Peer Benchmarks for Penn Virginia, Partnership, Company and Individual Performance Criteria and 2009 Performance Criteria. The Penn Virginia Committee set the 2010, 2009 and 2008 base salaries and 2009-related, 2008-related and 2007-related bonus and long-term compensation awards for each of the Partnership Executives in the amounts our Committee recommended. Since we reimburse Penn Virginia for a portion of the Shared
Executives compensation based on the amount of time they devote to us, our Committee reviews the amount of the Shared Executives time allocable to us each year and determines whether such time allocations are reasonable in light of the business conducted by us during such year. Peer Benchmarks for the Partnership.  In 2009, our Committee engaged BDO Seidman LLP, or BDO, for the third consecutive year as its independent compensation consultant to assist it in a general review of the compensation packages for our NEOs. In 2007, BDO provided our Committee with information and advice regarding overall program design and compensation trends. In 2008, BDO analyzed the base salaries, target bonuses and long-term compensation opportunities of the following peer group comprised of 16 publicly traded limited partnerships, referred to as our Peer Group, comparable to us based on market capitalization and
type and geographic location of operations:  Alliance Resource Partners, L.P.

          

          Hiland Partners, LPAtlas Pipeline Partners, L.P.

          

          Magellan Midstream Partners, L.P.Boardwalk Pipeline Partners, LP

          

          Natural Resource Partners L.P.Copano Energy, L.L.C.

          

          NuStar Energy L.P.Crosstex Energy, L.P.

          

          ONEOK Partners, L.P.DCP Midstream Partners, LP

          

          Regency Energy Partners LPEnbridge Energy Partners, L.P.

          

          Sunoco Logistics Partners L.P.Energy Transfer Partners, L.P.

          

          TEPPCO Partners, L.P.
 117    TABLE OF CONTENTS BDOs analysis showed that the total compensation of the Partnership Executives fell between the 50th and 75th percentiles of executive officers in our Peer Group with comparable responsibilities, but that our overall cost of management was significantly lower than that of our Peer Group because we reimburse Penn Virginia for only a portion of the Shared Executives compensation. In 2009, BDO provided a general outlook of compensation trends and suggested that, in the existing economic environment, there had been little movement in the value of total compensation packages of the our Peer Group. On that basis, our
Committee concluded that a full review of total compensation programs of our Peer Group was not warranted and that the data provided in the 2008 study provided sufficient guidance for compensation decisions in 2009. During 2009, Penn Virginia also performed an internal analysis of our Peer Groups compensation practices as described in proxy statements and other periodic reports, and Penn Virginias conclusions were generally consistent with those of BDO. See How Compensation Is Determined  Partnership, Company and Individual Performance Criteria for information regarding the competitive compensation positioning of individual NEOs. Peer Benchmarks for Penn Virginia.  In 2009, the Penn Virginia Committee engaged Hewitt Associates LLC, or Hewitt, for the third consecutive year as its independent compensation consultant to assist it in a general review of the compensation packages for the Shared Executives and the president of Penn Virginias oil and gas subsidiary. Hewitt studied a peer group which was comprised of the following 15 publicly traded oil and gas companies, referred to as the Penn Virginia Peer Group, similar to Penn Virginia based on revenues, assets, capitalization and scope of operations:  Berry Petroleum Company

          

          Petrohawk Energy CorporationBill Barrett Corporation

          

          Petroleum Development CorporationCabot Oil & Gas Corporation

          

          PetroQuest Energy, Inc.Carrizo Oil & Gas, Inc.

          

          Quicksilver Resources Inc.CNX Gas Corporation

          

          Range Resources CorporationDelta Petroleum Corporation

          

          Southwestern Energy CompanyEXCO Resources, Inc.

          

          St. Mary Land & Exploration CompanyGoodrich Petroleum Corporation
 Based on Hewitts analysis of base salaries, target bonuses and long-term compensation opportunities of the Penn Virginia Peer Group as described in survey data and proxy statements and other periodic reports filed by companies in the Penn Virginia Peer Group, Hewitt concluded that total 2009 compensation opportunities for the Shared Executives and the president of Penn Virginias oil and gas subsidiary, as a group, were generally near the 50th percentile of executive officers in the Penn Virginia Peer Group with comparable responsibilities. During 2009, Penn Virginia also performed an internal analysis of the Penn Virginia Peer
Groups compensation practices as described in proxy statements and other periodic reports, and its conclusions were generally consistent with those of Hewitt. See How Compensation Is Determined  Partnership, Company and Individual Performance Criteria for information regarding the competitive compensation positioning of individual NEOs. Partnership, Company and Individual Performance Criteria.  The Penn Virginia Committee, with the assistance of our Committee and the PVG Committee, targets the amount of salary, cash bonus and long-term compensation awards for each NEO at approximately the 50th percentile of executive officers of our peers with comparable responsibilities, in the case of the Partnership Executives, or executive officers of Penn Virginias peers with comparable responsibilities, in the case of the Shared Executives. However, given the importance of executive accountability for our and Penn Virginias performance as well as for individual
performance, our Committee, the Penn Virginia Committee and the PVG Committee recognize that compensation for any NEO could exceed such 50th percentile targets, reflecting a reward for exceptional Partnership, Penn Virginia or individual performance, or be lower than such 50th percentile targets, reflecting Partnership, Penn Virginia or individual underperformance. To measure specific performance, the Penn Virginia Committee, with the assistance of our Committee and the PVG Committee, uses certain Partnership and Penn Virginia performance criteria and certain individual performance criteria which measure achievement and contribution to us or Penn Virginia. Our Committee, the Penn Virginia Committee and the PVG Committee believe that these performance criteria for each NEO are
 118    TABLE OF CONTENTS focused on factors over which such NEO has some control and which should have a positive effect on our and Penn Virginias operations and on the price of our common units or Penn Virginias common stock or PVGs common units. The weight given any one criterion and the mix of criteria included in determining amounts of compensation vary among our NEOs depending on their positions and principal areas of responsibility. The relevance and the relative importance of any of these criteria change from time to time, even within the same year, depending on our and Penn Virginias strategic objectives, operational needs and general business
and regulatory environments. For this reason, the Penn Virginia Committee, with the assistance of our Committee and the PVG Committee, uses broad discretion and may change these performance criteria from year to year or within a given year, may assign an aggregate weight to several performance criteria applicable to a NEO, may consider adding criteria which were not known at the time the original criteria were established or deleting criteria which became obsolete or unimportant, or may consider all criteria collectively. 2009 Performance Criteria.  Flexibility with respect to performance criteria was particularly relevant in 2009. At the beginning of 2009, the global financial and credit markets had collapsed, commodity prices had plummeted and we and Penn Virginia were concerned about liquidity. Penn Virginia, like many of its industry peers, was faced with the likelihood of a negative redetermination of the borrowing base under its revolving credit facility, and neither we nor Penn Virginia, like our respective industry peers, were certain of when or whether we would be able to raise public debt or equity. Our CEO recommended, and the Penn Virginia
Committee agreed, that, under these circumstances, the quantitative performance criteria that the Penn Virginia Committee has used historically, while still relevant, were difficult to quantify with reasonable certainty and were, in fact, not the most important goals for us or Penn Virginia at that time. Rather, our CEO recommended, and the Penn Virginia Committee and our Committee agreed, that our NEOs should first work to increase our and Penn Virginias liquidity and conserve our and Penn Virginias capital so that we and Penn Virginia could maintain stable operations during the economic crisis and be in a position to grow once markets and commodity prices recovered. Compensation of Our NEOs A. James Dearlove, CEO.  In February 2010, the Penn Virginia Committee, with the assistance of our Committee and the PVG Committee, set Mr. Dearloves 2010 base salary at $500,000, representing an 11% increase over his 2009 base salary. The Penn Virginia Committee, with the assistance of our Committee and the PVG Committee, also awarded to Mr. Dearlove a 2009-related cash bonus of $500,000, or approximately 111% of his 2009 base salary, and a 2009-related long-term compensation award valued at $1,500,000, or approximately 333% of his 2009 base salary. The increase in Mr. Dearloves base salary, along with the amount
of his bonus, was intended to bring Mr. Dearloves cash compensation in line with the median cash compensation of CEOs in the Penn Virginia Peer Group. We reimbursed Penn Virginia for 30% of Mr. Dearloves 2009-related bonus and long-term compensation awards, or $150,000 and $450,000. Mr. Dearloves 2009-related bonus and 2009-related long-term compensation were based on the 2009-related performance considerations: 

          Promoted transactions which, among other things, increased our liquidity (defined as cash and cash equivalents plus available borrowing capacity under our revolving credit facility) from $139.8 million at December 31, 2008 to $187.0 million at December 31, 2009 through a credit facility adjustment and strategic but conservative capital spending 

          Promoted transactions which, among other things, increased Penn Virginias liquidity (defined as cash and cash equivalents plus available borrowing capacity under Penn Virginias revolving credit facility) from $139.2 million at December 31, 2008 to $378.3 million at December 31, 2009 (or $498.3 million including uncommitted borrowing base amounts) through public financings, credit facility adjustments, sales of non-core assets and strategic but conservative capital spending 

          Recommended and oversaw modifications and redirections throughout 2009, a particularly difficult year, in our, Penn Virginias and PVGs strategies to react appropriately to changing global financial and credit conditions 

          Promoted our strategy to expand natural gas midstream operations by overseeing an acquisition by our natural gas midstream division, or PVRM, of $22.6 million of midstream assets and an expansion of PVRMs Beaver/Spearman plant, both of which increased PVRMs processing capacity
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          Focused the use of Penn Virginias available capital on core oil and gas areas 

          Worked with the board of directors of Penn Virginia to update the succession plan for the CEO position and reviewed internal candidate assessments with the board of directors of Penn Virginia 

          Oversaw active investor relations program, including eight quarterly public teleconferences and 13 investor conferences, with more than 125 one-on-one investor meetings, six sales force presentations and 17 road shows held during 2009 

          Provided strong leadership for us, Penn Virginia and PVG by effectively managing three separate publicly traded entities engaged in multiple businesses and maintaining our, Penn Virginias and PVGs excellent regulatory and ethical track records The Penn Virginia Committee believes, and Hewitts data confirms, that the amounts of 2009-related bonus and long-term compensation awarded to Mr. Dearlove, when combined with his base salary, comprise an industry-competitive compensation package that falls at approximately the 50th percentile of CEOs in the Penn Virginia Peer Group. Further, the Penn Virginia Committee believes that this compensation appropriately reflects our, Penn Virginias and Mr. Dearloves 2009 performances. Our Committee reviewed Mr. Dearloves time allocated to us during 2009 and concluded that such allocation was reasonable given the business
conducted by us during 2009. Frank A. Pici, Vice President and CFO.  In February 2010, the Penn Virginia Committee, with the assistance of our Committee and the PVG Committee, set Mr. Picis 2010 base salary at $300,000, representing a 9% increase over his 2009 base salary. This increase was intended to bring Mr. Picis base salary closer to the median base salary of CFOs in the Penn Virginia Peer Group. The Penn Virginia Committee, with the assistance of our Committee and the PVG Committee, also awarded to Mr. Pici a 2009-related cash bonus of $220,000, or approximately 80% of his 2009 base salary, and a 2009-related long-term compensation
award valued at $650,000, or approximately 236% of his 2009 base salary. We reimbursed Penn Virginia for 23% of Mr. Picis 2009-related cash bonus and long-term compensation awards, or $50,600 and $149,500. Mr. Picis 2009-related bonus and 2009-related long-term compensation were based on the following 2009-related performance considerations: 

          Oversaw the following significant liquidity and capital raising transactions: o

          Our $100 million revolving credit facility expansion o

          Penn Virginias $65 million equity offering in May 2009 o

          Penn Virginias $300 million high yield debt offering in June 2009 o

          Penn Virginias $118 million secondary offering of PVG common units in September 2009 

          Contributed to the direction of our, Penn Virginias and PVGs strategies 

          Oversaw the amendment and extension of Penn Virginias revolving credit facility with a limited reduction in the borrowing base 

          Oversaw the reorganization of our and Penn Virginias accounting and finance departments 

          Oversaw the financial planning, modeling and evaluation of our and Penn Virginias contemplated acquisitions, dispositions and investments 

          Monitored the hedging policies for our natural gas midstream and Penn Virginias oil and gas businesses 

          Set and implemented a successful SOX compliance program that has resulted in us, Penn Virginia and PVG having had no significant SOX-related regulatory compliance issues 

          Maintained an excellent relationship with our and Penn Virginias bank groups comprised of 17 banks and 12 banks 

          Oversaw an active investor relations function
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          Effectively managed the finance, tax, accounting, treasury, investor relations and information technology-related aspects of three separate publicly traded entities engaged in multiple businesses The Penn Virginia Committee believes, and Hewitts data confirms, that the amounts of 2009-related bonus and long-term compensation awarded to Mr. Pici, when combined with his base salary, comprise an industry-competitive compensation package that falls between the 25th and 50th percentiles of CFOs in the Penn Virginia Peer Group. Further, the Penn Virginia Committee believes that this compensation appropriately reflects our, Penn Virginias and Mr. Picis 2009 performances. Our Committee reviewed Mr. Picis time allocated to us during 2009 and concluded that such allocation was reasonable given the business
conducted by us during 2009. Nancy M. Snyder, Vice President, Chief Administrative Officer and General Counsel.  In February 2010, the Penn Virginia Committee, with the assistance of our Committee and the PVG Committee, set Ms. Snyders 2010 base salary at $300,000, representing a 13% increase over her 2009 base salary. The Penn Virginia Committee, with the assistance of our Committee and the PVG Committee, also awarded to Ms. Snyder a 2009-related cash bonus of $240,000, or approximately 91% of her 2009 base salary, and a 2009-related long-term compensation award valued at $750,000, or approximately 283% of her 2009 base salary. We reimbursed Penn
Virginia for 35% of Ms. Snyders 2009-related cash bonus and long-term compensation awards, or $84,000 and $262,500. Ms. Snyders 2009-related bonus and 2009-related long-term compensation were based on the following 2009-related performance considerations: 

          Oversaw the negotiation of, and directed outside counsel with respect to, the following significant liquidity and capital raising transactions: o

          Our $100 million revolving credit facility expansion o

          Penn Virginias $65 million equity offering in May 2009 o

          Penn Virginias $300 million high yield debt offering in June 2009 o

          Penn Virginias $118 million secondary offering of PVG common units in September 2009 

          Contributed to the direction of our, Penn Virginias and PVGs strategies 

          Oversaw the negotiation of the amendment and extension of Penn Virginias revolving credit facility 

          Oversaw the in-house completion of PVRMs $22.6 million acquisition of midstream assets and Penn Virginias $38 million sale of its non-core Gulf Coast assets 

          Oversaw the in-house completion of several credit agreement amendments for us and Penn Virginia, numerous acquisition bids, joint operating agreements, joint exploration agreements, master service agreements, gas processing and transportation agreements, leases, easements and other day-to-day transactions and renewal of our, Penn Virginias and PVGs insurance policies 

          Oversaw Penn Virginias in-house legal staff, which, in addition to transactional work and day-to-day contractual matters, reviewed or prepared our, Penn Virginias and PVGs periodic filings and governance documents, including more than 42 Form 8-Ks, 74 sets of board and committee minutes and 184 Form 4s 

          Oversaw all of our and Penn Virginias litigation and dispute-related work 

          Maintained our, Penn Virginias and PVGs excellent legal compliance track record 

          Reviewed and suggested amendment, as necessary, of all governance and other documents, including committee charters, codes of conduct, whistleblower policies, trading policies and equity plans for us, Penn Virginia and PVG 

          Effectively managed the legal, human resource and corporate secretary functions of three separate publicly traded entities engaged in multiple businesses
 121    TABLE OF CONTENTS The Penn Virginia Committee believes, and Hewitts data confirms, that the amounts of 2009-related bonus and long-term compensation awarded to Ms. Snyder, when combined with her base salary, comprise an industry-competitive compensation package that falls between the 50th and 75th percentiles of general counsels in the Penn Virginia Peer Group. The Penn Virginia Committee decided to target Ms. Snyders total compensation between these percentiles rather than at the median salary for general counsels in the Penn Virginia Peer Group because Ms. Snyders responsibilities are significantly broader than those of a general counsel. Further,
the Penn Virginia Committee believes that this compensation appropriately reflects our, Penn Virginias and Ms. Snyders 2009 performances. Our Committee reviewed Ms. Snyders time allocated to us during 2009 and concluded that such allocation was reasonable given the business conducted by us during 2009. Keith D. Horton, Chief Operating Officer  Coal.  In February 2010, our Committee, with the assistance of the PVG Committee, recommended and the Penn Virginia Committee decided not to increase Mr. Hortons base salary for 2010, maintaining it at $280,000. Our Committee, with the assistance of the PVG Committee, also recommended and the Penn Virginia Committee, with the concurrence of our Committee, awarded to Mr. Horton a 2009-related cash bonus of $161,000, or approximately 58% of his 2009 base salary, and a 2009-related long-term compensation award valued at $420,000, or approximately 150% of his 2009
base salary. We paid all of Mr. Hortons 2009-related bonus and long-term compensation awards. Mr. Hortons 2009-related bonus and 2009-related long-term compensation were based on the following 2009-related performance considerations: 

          Maintained stable operational performance by our coal and natural resource management division despite challenging industry conditions 

          Oversaw the re-leasing of a significant amount of coal reserves to a new operator following the bankruptcy of the then-existing operator 

          Our total coal production increased by 2% in the year ended December 31, 2009 compared to the year ended the December 31, 2008 

          Our Central Appalachian coal production, which accounted for 53% of our total coal production in 2009, decreased by only 6% in the year ended December 31, 2009 compared to the year ended the December 31, 2008, while Central Appalachian coal production decreased by 14% industry-wide Our Committee and the Penn Virginia Committee believe, and BDOs most recent review and interpretation of market data confirms, that the amounts of 2009-related bonus and long-term compensation awarded to Mr. Horton, when combined with his base salary, comprise an industry-competitive compensation package that falls between the 50th and 75th percentiles of chief operating officers in our Peer Group. Further, our Committee and the Penn Virginia Committee believe that this compensation appropriately reflects our and Mr. Hortons 2009 performances. These amounts also reflect Mr. Hortons strong leadership abilities,
significant industry experience, tenure at the Partnership and our desire to retain his services, as well as our Committees and the Penn Virginia Committees desire to facilitate, to the extent reasonable and appropriate, the opportunity for all of our NEOs to earn reasonably comparable compensation notwithstanding that they work in different industries that have different compensation practices. Ronald K. Page, Chief Operating Officer  Midstream.  In February 2010, our Committee, with the assistance of the PVG Committee, recommended and the Penn Virginia Committee decided not to increase Mr. Pages base salary for 2010, maintaining it at $260,000. Our Committee, with the assistance of the PVG Committee, also recommended and the Penn Virginia Committee, with the concurrence of our Committee, awarded to Mr. Page a 2009-related cash bonus of $160,000, or approximately 62% of his 2009 base salary, and a 2009-related long-term compensation award valued at $440,000, or approximately 169% of his 2009
base salary. We paid all of Mr. Pages 2009-related bonus and long-term compensation awards. Mr. Pages 2009-related bonus and 2009-related long-term compensation were based on the following 2009-related performance considerations:
 122    TABLE OF CONTENTS 

          Oversaw our acquisition of $22.6 million of midstream assets, which increased our processing capacity by 60 MMcfd 

          Oversaw the expansion of our Beaver/Spearman plant, which increased our processing capacity by 40 MMcfd 

          Our system throughput volumes increased by 23% in the year ended December 31, 2009 compared to the year ended December 31, 2008 Our Committee and the Penn Virginia Committee believe, and BDOs most recent review and interpretation of market data confirms, that the amounts of 2009-related bonus and long-term compensation awarded to Mr. Page, when combined with his base salary, comprise an industry-competitive compensation package that falls between the 50th and 75th percentiles of chief operating officers in our Peer Group. Further, our Committee and the Penn Virginia Committee believe that this compensation appropriately reflects our and Mr. Pages 2009 performances. These amounts also reflect Mr. Pages strong leadership abilities,
significant industry experience and our desire to retain his services, as well as our Committees and the Penn Virginia Committees desire to facilitate, to the extent reasonable and appropriate, the opportunity for all of our NEOs to earn reasonably comparable compensation notwithstanding that they work in different industries that have different compensation practices. Compensation Committee Report Under the rules established by the SEC, we are required to discuss the compensation and benefits of the executive officers of our general partner, including our CEO, our CFO and our other NEOs. The Compensation and Benefits Committee is furnishing the following report in fulfillment of the SECs requirements. The Compensation and Benefits Committee has reviewed the information contained above under the heading Compensation Discussion and Analysis and has discussed the Compensation Discussion and Analysis with management. Based upon its review and discussions with management, the Compensation and Benefits Committee recommended to the board of directors of the Partnerships general partner that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K. Compensation and Benefits Committee James L. Gardner (Chairman) Edward B. Cloues, II Thomas W. Hofmann James R. Montague
 123    TABLE OF CONTENTS Summary Compensation Table The following table sets forth the compensation paid by us, during or with respect to the years ended December 31, 2009, 2008 and 2007, to our CEO, our CFO and our general partners three other most highly compensated executive officers for services rendered to us and our subsidiaries: Summary Compensation Table  Name and Principal Position

          

          Year

          

          Salary($)

          

          Bonus($)

          

          Stock Awards($)(1)

          

          All Other Compensation($)(2)

          

          Total($)A. James DearloveChief Executive Officer

          

          

          2009

          

          

          

          135,000

          

          

          

          150,000

          

          

          

          800,000

          

          

          

          11,925

          

          

          

          1,096,9252008

          

          

          

          180,000

          

          

          

          198,000

          

          

          

          759,992

          

          

          

          15,152

          

          

          

          1,153,1442007

          

          

          

          144,400

          

          

          

          209,000

          

          

          

          312,507

          

          

          

          13,709

          

          

          

          679,616Frank A. PiciVice President and Chief Financial Officer

          

          

          2009

          

          

          

          63,250

          

          

          

          50,600

          

          

          

          181,499

          

          

          

          9,143

          

          

          

          304,4922008

          

          

          

          90,750

          

          

          

          69,300

          

          

          

          223,999

          

          

          

          12,060

          

          

          

          396,1092007

          

          

          

          73,640

          

          

          

          61,600

          

          

          

          121,604

          

          

          

          9,296

          

          

          

          266,140Keith D. HortonCo-President and Chief Operating Officer  Coal

          

          

          2009

          

          

          

          280,000

          

          

          

          161,000

          

          

          

          419,998

          

          

          

          37,750

          

          

          

          898,7482008

          

          

          

          280,000

          

          

          

          160,000

          

          

          

          399,990

          

          

          

          35,415

          

          

          

          875,4052007

          

          

          

          270,000

          

          

          

          185,000

          

          

          

          315,004

          

          

          

          31,800

          

          

          

          801,804Ronald K. PageCo-President and Chief Operating Officer  Midstream

          

          

          2009

          

          

          

          260,000

          

          

          

          160,000

          

          

          

          440,003

          

          

          

          37,750

          

          

          

          897,7532008

          

          

          

          260,000

          

          

          

          160,000

          

          

          

          399,990

          

          

          

          35,200

          

          

          

          855,3402007

          

          

          

          235,000

          

          

          

          170,000

          

          

          

          265,010

          

          

          

          31,800

          

          

          

          701,810Nancy M. SnyderVice President, Chief Administrative Officer and General Counsel

          

          

          2009

          

          

          

          92,750

          

          

          

          84,000

          

          

          

          297,504

          

          

          

          13,913

          

          

          

          488,1662008

          

          

          

          92,750

          

          

          

          82,250

          

          

          

          263,987

          

          

          

          12,694

          

          

          

          451,6812007

          

          

          

          75,900

          

          

          

          70,950

          

          

          

          138,600

          

          

          

          10,494

          

          

          

          295,944
  (1)

          Represents the aggregate grant date fair value of restricted units and phantom units granted by our Committee to our NEOs in consideration for services rendered to us. These amounts were computed in accordance with FASB ASC Topic 718 and were based on the NYSE closing prices of our common units on the dates of grant. See Note 16 in the Notes to Consolidated Financial Statements. (2)

          Reflects amounts paid or reimbursed by us for (i) automobile allowances, executive health exams and gym memberships and (ii) matching and other contributions to our NEOs 401(k) Plan accounts. The cash components of our executive compensation consist of a base salary and the opportunity to earn an annual cash bonus. See Compensation Discussion and Analysis  Elements of Compensation. The amounts of salary and bonus reflected in the Summary Compensation Table above include only amounts paid or reimbursed by us in consideration for services rendered to us by our NEOs and do not include any amounts paid by Penn Virginia to any of our NEOs in consideration for services rendered to Penn Virginia. The specific portions of salary and bonus paid, or reimbursed to Penn Virginia, by us depend on the portion of professional
time devoted by each NEO to us. See Compensation and Discussion Analysis  Compensation Structure for a description of the manner in which our NEOs are compensated. The following table shows the portion of professional time devoted to us by each Shared Executive in 2009, 2008 and 2007 and the portion of such Shared Executives salary and bonus we reimbursed Penn Virginia with respect to those years:  PVR PortionShared Executive

          

          2009

          

          2008

          

          2007A. James Dearlove

          

          

          30

          %

          

          

          40

          %

          

          

          38

          %Frank A. Pici

          

          

          23

          %

          

          

          33

          %

          

          

          28

          %Nancy M. Snyder

          

          

          35

          %

          

          

          35

          %

          

          

          33

          %
 124    TABLE OF CONTENTS Because each of the Partnership Executives devoted all of his professional time to us in 2009, 2008 and 2007, we paid all of his 2009, 2008 and 2007 salaries and 2009-related, 2008-related and 2007-related bonuses. For a discussion of the salaries and bonuses paid to the Shared Executives by Penn Virginia, see the Penn Virginia Proxy Statement relating to its 2010 Annual Meeting of Shareholders. The equity components of our executive compensation program consist of the opportunity to earn awards of restricted units or phantom units from us and awards of stock options, restricted stock and restricted stock units from Penn Virginia. Like the cash component of executive compensation, that portion of the value of each NEOs equity-based compensation paid or reimbursed by us depends on the portion of professional time that each NEO devotes to us. The values of the stock awards reflected in the Summary Compensation Table above include only the values of restricted unit and phantom unit awards granted by our Committee. Our Committee did not
grant any restricted units in 2009 and did not grant any phantom units in 2008 or 2007. Grants of Plan-Based Awards The following table sets forth the grant date and number of all phantom units granted to our NEOs in 2009 by our Committee with respect to services rendered to us in 2008: 2009 Grants of Plan-Based Awards  Name

          

          Grant Date

          

          All Other Stock Awards: Number of Shares of Stock or Units(#)

          

          Grant Date Fair Value of Stock and Option Awards($)A. James Dearlove

          

          

          February 25, 2009

          

          

          

          69,025

          

          

          

          800,000Frank A. Pici

          

          

          February 25, 2009

          

          

          

          15,660

          

          

          

          181,499Keith D. Horton

          

          

          February 25, 2009

          

          

          

          36,238

          

          

          

          419,998Ronald K. Page

          

          

          February 25, 2009

          

          

          

          37,964

          

          

          

          440,003Nancy M. Snyder

          

          

          February 25, 2009

          

          

          

          25,669

          

          

          

          297,504
 Narrative Discussion of Equity Awards In 2009, we granted phantom units to our NEOs. In 2008 and 2007, we granted restricted units to our NEOs. The values of our restricted units and phantom units reflected in the Summary Compensation Table and the Grants of Plan-Based Awards Table were based on the NYSE closing prices of our common units on the dates of grant. Restricted units are issued and outstanding common units which are subject to a vesting period as described below. Phantom units are rights to receive one common unit upon the termination of the vesting period described below. The vesting periods for restricted units and phantom units will terminate as determined by our Committee
and specified in an award agreement. All restricted units granted to our NEOs since 2005 and all phantom units ever granted to our NEOs vest over a three-year period, with one-third of each award vesting on the first, second and third anniversaries of the grant date unless (i) the grantees employment terminates for any reason other than death or disability, in which event any unvested restricted units or unvested phantom units are forfeited unless otherwise determined by our Committee, or (ii) the grantee dies, becomes disabled or becomes retirement eligible, which is defined as reaching age 62 and completing 10 years of consecutive service with our general partner or its affiliate, or there occurs a change of control, in which events all restrictions lapse. All phantom units ever granted to our NEOs provide that payments on such phantom units will be made in common units (or, at the request of the phantom unitholder and upon the approval of our Committee, an amount of cash equal
to the fair market value of our common units) at the time of vesting, unless vesting occurs early on account of becoming retirement eligible, in which event payments will be made when such phantom units would have originally vested, even if that is after retirement. Our Committee has granted distribution equivalent rights in tandem with all phantom unit awards it has ever granted to our NEOs. Our Committee grants annual compensation-based restricted units or phantom units during the first quarter of each year after the Penn Virginia Committee, with our Committees and the PVG Committees assistance, has concluded its analysis of executive compensation with respect to the preceding year. Our Committee generally grants restricted units from time to time in connection with the hiring, promotion or
 125    TABLE OF CONTENTS retention of Partnership-related employees and, while it has not done so in the past, it may consider granting phantom units in connection with such events. Our Committee may also consider grants at such other times as it may deem appropriate. During 2009, we paid quarterly distributions of $0.47 on each restricted unit and each phantom unit. The distributions were paid at the same times and in the same amounts as distributions paid to the other holders of our common units and were taken into consideration when determining the values of the restricted units and phantom units shown previously in the Summary Compensation Table and in the Grants of Plan-Based Awards Table. Outstanding Equity Awards at Fiscal Year-End The following table sets forth certain information regarding the numbers and values of restricted units and phantom units not vested as of December 31, 2009 held by our NEOs on December 31, 2009. The market value of non-vested restricted units or phantom units is based on the NYSE closing price of our common units on December 31, 2009. Outstanding Equity Awards at Fiscal Year-End 2009  Stock AwardsName

          

          Number of Shares or Units of Stock That Have Not Vested(#)

          

          Market Value of Shares or Units of Stock That Have Not Vested($)A. James Dearlove

          

          

          0

          

          

          

          0Frank A. Pici

          

          

          7,058

          (1)

          

          

          152,17015,660

          (2)

          

          

          337,630Keith D. Horton

          

          

          13,819

          (3)

          

          

          297,93836,238

          (4)

          

          

          781,291Ronald K. Page

          

          

          13,199

          (5)

          

          

          284,57037,964

          (6)

          

          

          818,504Nancy M. Snyder

          

          

          8,260

          (7)

          

          

          178,08625,669

          (8)

          

          

          553,424
  (1)

          Of these restricted units, 2,775 vested on February 22, 2010, 1,509 will vest on February 27, 2010 and 2,774 will vest on February 22, 2011. (2)

          Of these phantom units, 5,220 vested on February 25, 2010, 5,220 will vest on February 25, 2011 and 5,220 will vest on February 25, 2012. (3)

          Of these restricted units, 4,955 vested on February 22, 2010, 3,910 will vest on February 27, 2010 and 4,954 will vest on February 22, 2011. (4)

          Of these phantom units, 12,080 vested on February 25, 2010, 12,079 will vest on February 25, 2011 and 12,079 will vest on February 25, 2012. (5)

          Of these restricted units, 4,955 vested on February 22, 2010, 3,290 will vest on February 27, 2010 and 4,954 will vest on February 22, 2011. (6)

          Of these phantom units, 12,655 vested on February 25, 2010, 12,655 will vest on February 25, 2011 and 12,654 will vest on February 25, 2012. (7)

          Of these restricted units, 3,270 vested on February 22, 2010, 1,720 will vest on February 27, 2010 and 3,270 will vest on February 22, 2011. (8)

          Of these phantom units, 8,557 vested on February 25, 2010, 8,556 will vest on February 25, 2011 and 8,556 will vest on February 25, 2012.
 126    TABLE OF CONTENTS Vesting of Restricted Units and Phantom Units The following table sets forth the number of common units acquired, and the values realized, by our NEOs upon the vesting of restricted units and phantom units during 2009: Option Exercises and Stock Vested in 2009  Stock AwardsName

          

          Number of Shares Acquired on Vesting(#)

          

          Value Realized on Vesting($)A. James Dearlove

          

          

          108,382

          (1)

          

          

          1,731,072Frank A. Pici

          

          

          6,315

          (2)

          

          

          74,014Keith D. Horton

          

          

          12,902

          (2)

          

          

          151,101Ronald K. Page

          

          

          11,359

          (2)

          

          

          133,125Nancy M. Snyder

          

          

          6,685

          (2)

          

          

          78,403
  (1)

          Represents common units acquired upon the vesting of 39,357 restricted units and 69,025 phantom units. (2)

          Represents common units acquired upon the vesting of restricted units. Executive Stock Ownership Guidelines We and Penn Virginia require our CEO and the other Shared Executives to own common units and shares of Penn Virginias common stock valued at an aggregate amount equal to four times base salary, in the case of our CEO, and two times base salary, in the case of the other Shared Executives, with the proportion of units and stock being reflective of the amount of time they devote to us and Penn Virginia. We require each Partnership Executive to own common units valued at two times his base salary. As of December 31, 2009, all of our NEOs were in compliance with these requirements. Nonqualified Deferred Compensation The following table sets forth certain information regarding compensation paid by both our general partner and Penn Virginia and deferred by our NEOs under Penn Virginias Supplemental Employee Retirement Plan: 2009 Nonqualified Deferred Compensation  Name

          

          Executive Contributions in Last FY($)(1)

          

          Registrant Contributions in Last FY($)

          

          Aggregate Earnings (Loss) in Last FY($)

          

          Aggregate Withdrawals/Distributions($)

          

          Aggregate Balance at Last FYE($)(2)A. James Dearlove

          

          

          247,500

          

          

          

          0

          

          

          

          91,810

          

          

          

          260,512

          

          

          

          842,333Frank A. Pici

          

          

          0

          

          

          

          0

          

          

          

          389,426

          

          

          

          0

          

          

          

          1,559,330Keith D. Horton

          

          

          0

          

          

          

          0

          

          

          

          4,470

          

          

          

          0

          

          

          

          15,553Ronald K. Page

          

          

          32,000

          

          

          

          0

          

          

          

          30,247

          

          

          

          0

          

          

          

          122,722Nancy M. Snyder

          

          

          185,000

          

          

          

          0

          

          

          

          219,044

          

          

          

          0

          

          

          

          1,285,032
  (1)

          All of these amounts are included in the amounts of salary and bonus for 2009 reported by us or Penn Virginia in the Summary Compensation Tables included in this Annual Report on Form 10-K and Penn Virginias Proxy Statement relating to its 2010 Annual Meeting of Shareholders. (2)

          Except with respect to aggregate contributions by Penn Virginia of $21,910 on behalf of Mr. Pici in 2001 and 2002, these amounts reflect only salaries and bonuses paid to our NEOs and earnings on those salaries and bonuses. All such salary and bonus amounts were previously reported by us or Penn Virginia as compensation to our NEOs in the Summary Compensation Tables included in our Annual Reports on Form 10-K and Penn Virginias Proxy Statements.
 127    TABLE OF CONTENTS The Penn Virginia Corporation Supplemental Employee Retirement Plan, or the SERP, allows all of Penn Virginias and its affiliates employees, including employees of our general partner, whose salaries exceeded $145,000 in 2009 to defer receipt of up to 100% of their salary, net of their salary deferrals under Penn Virginias 401(k) Plan, and up to 100% of their annual cash bonuses. The amounts reported in the Nonqualified Deferred Compensation Table above include not only contributions and earnings thereon related to deferred salaries and bonuses paid for services rendered to us, but also contributions and earnings thereon related to
deferred salaries and bonuses paid for services rendered to Penn Virginia. All deferrals under the SERP are credited to an account maintained by Penn Virginia and are invested by Penn Virginia, at the employees election, in Penn Virginias common stock or in certain mutual funds made available by Penn Virginia and selected by the employee. Since all amounts deferred under the SERP consist of previously earned salary or bonus, all SERP participants are fully vested at all times in all amounts credited to their accounts. Amounts held in a participants account will be distributed to the participant on the earlier of the date on which such participants employment terminates or there occurs a change of control of Penn Virginia. Neither we nor Penn Virginia are required to make any contributions to the SERP. Since Penn Virginia established the SERP in 1996, it has contributed an aggregate of $43,816 in 2001 and 2002 to the SERP in connection with offers of employment
to Mr. Pici and another executive of Penn Virginia, but has made no other contributions to the SERP. Penn Virginia has established a rabbi trust to fund the benefits payable under the SERP. Other than the $43,816 of Penn Virginia contributions described above, the assets of the rabbi trust consist of the cash amounts of salary and bonus already earned and deferred by our NEOs and other employees under the SERP and the securities in which those amounts have been invested. Assets held in the rabbi trust are designated for the payment of benefits under the SERP and are not available for Penn Virginias general use. However, the assets held in the rabbi trust are subject to the claims of Penn Virginias general creditors, and SERP participants
may not be paid in the event of Penn Virginias insolvency. Long-Term Incentive Plan Our general partner has adopted the Penn Virginia Resource GP, LLC Fifth Amended and Restated Long-Term Incentive Plan, or our LTIP. Our LTIP permits the grant of awards covering an aggregate of 3,000,000 common units to employees and directors of our general partner and employees of its affiliates who perform services for us. Awards under our LTIP can be in the form of common units, restricted units, unit options, phantom units and deferred common units. Our LTIP is administered by our Committee. Our general partners board of directors in its discretion may terminate or amend our LTIP at any time with respect to any units for which a grant has not yet been made. Our general partners board of directors also has the right to alter or amend our LTIP or any part of the plan from time to time, including increasing the number of units that may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant. Common Units.  Our LTIP permits the grant of common units to employees and directors. Our general partner granted 1,871 common units to a director of our general partner in 2009. Restricted Units.  Our LTIP permits the grant of restricted units to employees and directors. No grants of restricted units were made under our LTIP in 2009. 940 restricted units were forfeited in 2009. Restricted units vest upon terms established by our Committee. In addition, all restricted units will vest upon a change of control. If a directors membership on the board of directors of our general partner terminates for any reason, or an employees employment with our general partner and its affiliates terminates for any reason other than retirement after reaching age 62 and completing 10 years of consecutive service,
the grantees unvested restricted units will be automatically forfeited unless, and to the extent, that our Committee provides otherwise. Distributions payable with respect to restricted units may, in our Committees discretion, be paid directly to the grantee or held by our general partner and made subject to a risk of forfeiture during the applicable restriction period.
 128    TABLE OF CONTENTS Unit Options.  Our LTIP permits the grant of options covering common units to employees and directors. No grants of unit options have been made under our LTIP. Unit options will have an exercise price that is determined by our Committee, but may not be less than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by our Committee. In addition, all unit options will become exercisable upon a change of control. If a directors membership on the board of directors of our general partner terminates for any reason, or an employees employment
with our general partner and its affiliates terminates for any reason other than retirement after reaching age 62 and completing 10 years of consecutive service, the grantees unit options will be automatically forfeited unless, and to the extent, that our Committee provides otherwise. Upon exercise of a unit option, our general partner will acquire common units in the open market or directly from us or any other person or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring these common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. Phantom Units.  Our LTIP permits the grant of phantom units to employees and directors. Our general partner granted 354,792 phantom units to officers and employees of our general partner in 2009. 2,379 phantom units were forfeited in 2009. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of our Committee, the cash equivalent of the value of a common unit. Our Committee will determine the time period over which phantom units granted to employees and directors will vest. In addition, all phantom units will vest upon a change of control. If a directors
membership on the board of directors of our general partner terminates for any reason, or an employees employment with our general partner and its affiliates terminates for any reason other than retirement after reaching age 62 and completing 10 years of consecutive service, the grantees phantom units will be automatically forfeited unless, and to the extent, our Committee provides otherwise. Common units delivered upon the vesting of phantom units may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. Our Committee, in its discretion, may grant tandem distribution equivalent rights with respect to phantom units. Deferred Common Units.  Our LTIP permits the grant of deferred common units to directors. Our general partner granted 42,955 deferred common units to directors of our general partner in 2009. Each deferred common unit represents one common unit, which vests immediately upon issuance and is available to the holder upon termination or retirement from the board of directors of our general partner. Common units delivered in connection with deferred common units may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly
from us or any other person, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. Deferred common units awarded to directors receive additional deferred common units equal in value to all cash or other distributions paid by us on account of our common units. Change-in-Control Arrangements Our Committee, the Penn Virginia Committee, we and Penn Virginia believe that the Partnership Executives, together with our other senior management and key employees, are a primary reason for our success and that it is important for us to protect them in the event that they lose their jobs under certain circumstances upon a change of control. Four of our five NEOs are age 55 or older, and our NEOs have served the Partnership or Penn Virginia for an average of more than 15 years, with Messrs. Dearlove and Horton and Ms. Snyder having served in various capacities for 32, 28 and 12 years. We and Penn Virginia also believe that, by providing change of
control protection, our NEOs will be able to evaluate every Partnership or Penn Virginia opportunity, including a change of control, that may likely result in the termination of their employment, without the distraction of personal considerations. For these reasons, our general partner has entered into change of control severance agreements with the Partnership Executives, which entitle them to the benefits described below and which are substantially the same as the change of control severance agreements entered into between Penn Virginia and each of the Shared Executives. As noted
 129    TABLE OF CONTENTS below, our change in control severance benefits are not triggered unless employment is terminated or adversely changed in a significant manner and our general partner does not pay tax gross ups in the event of a change of control. General Partner Executive Change of Control Severance Agreements On October 17, 2008, our general partner entered into an Amended and Restated Executive Change of Control Severance Agreement, or a General Partner Severance Agreement, with each of Messrs. Horton and Page containing the terms and conditions described below. Term.  Each General Partner Severance Agreement has a two-year term which is automatically extended for consecutive one-day periods until terminated by notice from our general partner. If such notice is given, the General Partner Severance Agreement will terminate two years after the date of such notice. Triggering Events.  Each General Partner Severance Agreement provides severance benefits to the Partnership Executive upon the occurrence of two events, or the GP Dual Triggering Events. Specifically, if a change of control occurs and, within two years after the date of such change of control, either (a) our general partner terminates the Partnership Executives employment for any reason other than for cause or the Partnership Executives inability to perform his duties for at least 180 days due to mental or physical impairment or (b) the Partnership Executive terminates his employment due to a material reduction in his
authority, duties, title, status or responsibility, a greater than 5% reduction in his base salary, a discontinuation of a material incentive compensation plan in which he participated, the failure of our general partner to obtain an agreement from its successor to assume his General Partner Severance Agreement or his relocation by more than 100 miles of the office of our general partner at which he was working at the time of the change of control, then the Partnership Executive may elect to receive the change of control severance payments and other benefits described below. Change of Control Severance Benefits.  Upon the occurrence of the GP Dual Triggering Events, the Partnership Executive may elect to receive a lump sum, in cash, of an amount equal to three times the sum of his annual base salary plus the highest cash bonus paid to him during the two-year period prior to termination, subject to reduction as described below under Excise Taxes. In addition, all options to purchase shares of Penn Virginia common stock then held by the Partnership Executive will immediately vest and will remain exercisable for the shorter of three years or the remainder of the options respective terms
and all restricted stock and restricted stock units of Penn Virginia and all restricted units and phantom units of PVR and PVG then held by the Partnership Executive will immediately vest and all restrictions will lapse. Our general partner will also provide certain health and dental benefit-related payments to the Partnership Executive as well as certain outplacement services. Excise Taxes.  The General Partner Severance Agreements do not include gross up benefits to cover excise taxes. If the independent registered public accounting firm of our general partner determines that any payments to be made or benefits to be provided to the Partnership Executive under his General Partner Severance Agreement would result in him being subject to the excise tax imposed by Section 4999 of the Internal Revenue Code, such payments or benefits will be reduced to the extent necessary to prevent him from being subject to such excise tax. Restrictive Covenants and Releases.  Each General Partner Severance Agreement prohibits the Partnership Executive from (a) disclosing, either during or after his term of employment, confidential information regarding our general partner or its affiliates and (b) until two years after his employment has ended, soliciting or diverting business from our general partner or its affiliates. The General Partner Severance Agreement also requires that, upon payment of the severance benefits to the Partnership Executive, the Partnership Executive and our general partner release each other from all claims relating to the Partnership
Executives employment or the termination of such employment.
 130    TABLE OF CONTENTS Estimated Payments The following table sets forth the estimated aggregate payments to Messrs. Horton and Page under their respective General Partner Severance Agreements assuming that the GP Dual Triggering Events occurred on December 31, 2009:  Name of Executive Officer

          

          Salary and Bonus($)

          

          Accelerated Vesting of Restricted Stock and Units($)

          

          Other Benefits($)(1)

          

          Total Estimated Severance Payment($)Keith D. Horton

          

          

          1,395,000

          

          

          

          1,079,224

          

          

          

          88,800

          

          

          

          2,563,024Ronald K. Page

          

          

          1,290,000

          

          

          

          1,103,074

          

          

          

          88,800

          

          

          

          2,481,874
  (1)

          Other benefits include medical and dental insurance-related payments and the value of outplacement services. Penn Virginia Executive Change of Control Severance Agreements On October 17, 2008, Penn Virginia entered into an Amended and Restated Executive Change of Control Severance Agreement, or a Penn Virginia Severance Agreement, with each of the Shared Executives containing terms and conditions substantially similar to those of the General Partner Severance Agreements. For a discussion of the terms and conditions of, and the estimated payments under, the Penn Virginia Severance Agreements, see the Penn Virginia Proxy Statement relating to its 2010 Annual Meeting of Shareholders. Any payments required to be made to the Shared Executives under the Penn Virginia Severance Agreements will be the sole responsibility of
Penn Virginia. Compensation of Directors The following table sets forth the aggregate compensation paid by us to the non-employee directors of our general partner during 2009: 2009 Director Compensation  Name

          

          Fees Earned or Paid in Cash($)

          

          Stock Awards($)(1)

          

          Total($)Edward B. Cloues, II

          

          

          31,000

          

          

          

          90,000 (2)

          

          

          

          121,000James L. Gardner

          

          

          53,500

          

          

          

          90,000 (3)

          

          

          

          143,500Thomas W. Hofmann

          

          

          31,830

          

          

          

          58,846 (4)

          

          

          

          90,676James R. Montague

          

          

          56,285

          

          

          

          90,000 (5)

          

          

          

          146,285Marsha R. Perelman

          

          

          0

          (6)

          

          

          119,000 (7)

          

          

          

          119,000
  (1)

          Represents the aggregate grant date fair value of common units and deferred common units granted to the non-employee directors of our general partner. These amounts were computed in accordance with FASB ASC Topic 718 and were based on the NYSE closing prices of our common units on the dates of grant. See Note 16 in the Notes to Consolidated Financial Statements. (2)

          As of December 31, 2009, Mr. Cloues had 25,080 deferred common units outstanding. (3)

          As of December 31, 2009, Mr. Gardner had 20,063 deferred common units outstanding. (4)

          As of December 31, 2009, Mr. Hofmann had 3,757 deferred common units outstanding. (5)

          As of December 31, 2009, Mr. Montague had 27,080 deferred common units outstanding. (6)

          Ms. Perelman elected to receive all cash compensation in common units. (7)

          As of December 31, 2009, Ms. Perelman had 23,408 deferred common units outstanding.
 131    TABLE OF CONTENTS Each non-employee director of our general partner receives an annual retainer of $110,000, consisting of $20,000 of cash and $90,000 worth of deferred common units. The actual number of deferred common units awarded in any given year is based upon the NYSE closing price of our common units on the dates on which such awards are granted. Each deferred common unit represents one common unit representing a limited partner interest in us, which vests immediately upon issuance and is available to the holder upon termination or retirement from the board of directors of our general partner. Directors are restricted from selling such common units until six
months after such termination or retirement. The Chairman of the audit committee of the board of directors of our general partner receives an annual cash retainer of $15,000, and each audit committee member receives an annual cash retainer of $10,000. The Chairmen of all other committees of the board of directors of our general partner receive annual cash retainers of $2,500. All annual retainers are payable on a quarterly basis. In addition to annual retainers, each non-employee director receives $1,000 cash for each board of directors and committee meeting he or she attends. Directors appointed during a year, or who cease to be directors during a year, receive a pro rata portion of cash and deferred common units. Directors may elect to receive any cash payments in common units or deferred common units, and may elect to defer the receipt of any cash or common units they receive under our general partners Amended and Restated Non-Employee Directors Deferred Compensation Plan. Our general partner does not have any unit ownership requirement for its directors. Non-Employee Directors Deferred Compensation Plan Our general partner has adopted the Penn Virginia Resource GP, LLC Amended and Restated Non-Employee Directors Deferred Compensation Plan. This plan permits the non-employee directors of our general partner to defer the receipt of any or all cash, common units and restricted units they receive as compensation. All deferrals, and any distributions with respect to deferred common units or deferred restricted units, are credited to a deferred compensation account, the cash portion of which is credited quarterly with interest calculated at the prime rate. Non-employee directors of our general partner are fully vested at all times in any cash or deferred
common units credited to their deferred compensation accounts. Any restricted unit awards credited to a deferred compensation account are subject to the same vesting and forfeiture restrictions that apply to the underlying award. Amounts held in a non-employee directors deferred compensation account will be distributed to the director on the January 1st following the earlier to occur of the director reaching age 70 or the resignation or removal of the director from the board of directors of our general partner. Upon the death of a non-employee director, all vested amounts held in the deferred compensation account of the non-employee director will be distributed to the directors estate. Compensation Committee Interlocks and Insider Participation During 2009, Messrs. Cloues, Gardner, Hoffman and Montague served on the compensation and benefits committee of our general partner. None of these members is a former or current officer or employee of us or any of our subsidiaries or had any relationship requiring disclosure under Item 404 of Regulation S-K, Transactions with Related Persons, Promoters and Certain Control Persons. In 2009, none of the executive officers of our general partner served as a member of the board of directors or compensation committee of any entity that has one or more executive officers serving on the board of directors or the compensation and benefits
committee of our general partner.
 132    TABLE OF CONTENTS Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters Beneficial Ownership of Units The following table sets forth, as of February 22, 2010, the amount and percentage of our outstanding common units beneficially owned by (i) each person known by us to own beneficially more than 5% of our common units, (ii) each director of our general partner, (iii) each executive officer of our general partner and (iv) all directors and executive officers of our general partner as a group:  Name of Beneficial Owner

          

          Common Units(1)

          

          Percent ofCommon Units(2)Penn Virginia GP Holdings, L.P.(3)

          

          

          19,587,049

          

          

          

          37.8

          %Penn Virginia Resource GP Corp.(3)

          

          

          50,736

          

          

          

          *Edward B. Cloues, II

          

          

          40,529

          (4)

          

          

          *A. James Dearlove

          

          

          166,930

          (5)

          

          

          *James L. Gardner

          

          

          21,485

          (6)

          

          

          *Thomas W. Hofmann

          

          

          4,837

          (7)

          

          

          *Keith D. Horton

          

          

          47,288

          (8)

          

          

          *James R. Montague

          

          

          41,607

          (9)

          

          

          *Ronald K. Page

          

          

          41,213

          (10)

          

          

          *Marsha R. Perelman

          

          

          42,907

          (11)

          

          

          *Frank A. Pici

          

          

          45,313

          (12)

          

          

          *Nancy M. Snyder

          

          

          47,499

          (13)

          

          

          *All directors and executive officers as a group (10 persons)

          

          

          494,608

          (14)

          

          

          1.0

          %
  *

          Less than 1%. (1)

          Unless otherwise indicated, all common units are owned directly by the named holder and such holder has sole power to vote and dispose of such units. (2)

          Based on 51,798,895 common units issued and outstanding on February 22, 2010. On February 22, 2010, there were approximately 21,400 holders of our common units. (3)

          Penn Virginia is the ultimate parent company of Penn Virginia GP Holdings, L.P. and Penn Virginia Resource GP Corp. As such, Penn Virginia may be deemed to beneficially own the common units held by Penn Virginia GP Holdings, L.P. and Penn Virginia Resource GP Corp., which together own 37.9% of our common units. The address for each of Penn Virginia GP Holdings, L.P. and Penn Virginia Resource GP Corp. is c/o Penn Virginia Corporation, Three Radnor Corporate Center, Suite 300, 100 Matsonford Road, Radnor, Pennsylvania 19087. (4)

          Includes 26,607 deferred common units. (5)

          Includes 69,025 phantom units. (6)

          Reflects 21,485 deferred common units. (7)

          Reflects 4,837 deferred common units. (8)

          Includes 8,864 restricted units, 12,080 phantom units and 1,000 common units held by Mr. Hortons spouse. (9)

          Includes 2,000 common units deferred pursuant to our general partners non-employee directors deferred compensation plan and 26,607 deferred common units. (10)

          Includes 8,244 restricted units and 12,655 phantom units. (11)

          Includes 24,900 deferred common units and 5,000 common units held by a trust of which Ms. Perelman is a trustee and a beneficiary. (12)

          Includes 4,283 restricted units and 5,220 phantom units. (13)

          Includes 4,990 restricted units, 8,557 phantom units and 470 common units held by Ms. Snyder for the benefit of a minor child. (14)

          Includes 26,381 restricted units, 107,537 phantom units, 2,000 common units deferred pursuant to our general partners non-employee directors deferred compensation plan, 104,436 deferred common units, 5,000 common units held by a trust of which Ms. Perelman is a trustee and a beneficiary, 1,000 common units held by Mr. Hortons spouse and 470 common units held by Ms. Snyder for the benefit of a minor child.
 133    TABLE OF CONTENTS Equity Compensation Plan Information The following table sets forth certain information as of December 31, 2009 regarding the options outstanding and securities issued and to be issued under our general partners equity compensation plans not approved by our unitholders. Our general partner does not have any equity compensation plans which were approved by our unitholders. See Item 11, Executive Compensation  Long-Term Incentive Plan, for a description of our LTIP, our only equity compensation plan.  Plan Category

          

          Number of Securities To Be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)

          

          Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)

          

          Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c)Equity compensation plans approved by unitholders

          

          

          N/A

          

          

          

          N/A

          

          

          

          N/AEquity compensation plans not approved by unitholders

          

          

          0

          

          

          

          N/A

          

          

          

          2,002,084
 Item 13 Certain Relationships and Related Transactions, and Director Independence Transactions with Related Persons Management and Administrative Services We are managed and controlled by our general partner pursuant to our partnership agreement. Under our partnership agreement, our general partner is reimbursed for all direct and indirect expenses it incurs or payments it makes on our behalf. These expenses include salaries, fees and other compensation and benefit expenses of employees, officers and directors, insurance, other administrative or overhead expenses and all other expenses necessary or appropriate to conduct our business. The costs allocated to us by our general partner for administrative services and overhead totaled $5.3 million, $5.1 million and $4.2 million for the years ended December
31, 2009, 2008 and 2007. Incentive Distributions Our partnership agreement provides for incentive distributions payable to our general partner out of our Available Cash (as defined in our partnership agreement) in the event quarterly distributions to unitholders exceed certain specified targets. In general, subject to certain limitations, if a quarterly distribution exceeds a target of $0.275 per common unit, our general partner will receive incentive distributions equal to (i) 15% of that portion of the distribution per common unit which exceeds but is not more than $0.325, plus (ii) 25% of that portion of the quarterly distribution per common unit which exceeds $0.325 but is not more than $0.375,
plus (iii) 50% of that portion of the quarterly distribution per common unit which exceeds $0.375. In 2009, our general partner received total distributions, including incentive distributions, of $63.0 million from us. See also Item 1, Business  Partnership Distributions. Oil and Gas Marketing Agreement Connect Energy, our wholly owned subsidiary, and PVOG LP, Penn Virginias wholly owned subsidiary, are parties to a Master Services Agreement effective September 1, 2006. Pursuant to the Master Services Agreement, Connect Energy and PVOG LP have agreed that Connect Energy will market all of PVOG LPs oil and gas production in Arkansas, Louisiana, Oklahoma and Texas for a fee equal to 1% of the net sales price (subject to specified limitations) received by PVOG LP for such production. The Master Services Agreement has a primary term of five years and automatically renews for additional one year terms until terminated by either party. In
2009, PVOG LP paid Connect Energy $1.4 million in fees pursuant to the Master Services Agreement.
 134    TABLE OF CONTENTS Gas Gathering and Processing Agreement PVR East Texas Gas Processing LLC, or PVR East Texas, our wholly owned subsidiary, and PVOG LP are parties to a Gas Gathering and Processing Agreement effective May 1, 2007. Pursuant to the Gas Gathering and Processing Agreement, PVR East Texas and PVOG LP have agreed that PVR East Texas will gather and process all of PVOG LPs current and future gas production in certain areas of the Bethany Field in East Texas and redeliver the NGLs to PVOG LP for a current service fee of $0.3115/MMBtu (with an annual CPI adjustment). The Gas Gathering and Processing Agreement has a primary term of 15 years and automatically renews for additional one year
terms until terminated by either party. In 2009, PVOG LP paid PVR East Texas $4.0 million in fees pursuant to the Gas Gathering and Processing Agreement. Gas Purchase Arrangement From time to time, Connect Energy purchases gas or NGLs from PVOG LP at our Crossroads Plant and resells such gas or NGLs to third parties. The purchase price paid by Connect Energy to PVOG LP for such gas or NGLs equals the sales price received by Connect Energy for such gas or NGLs from the third parties. In 2009, Connect Energy paid PVOG LP $72.5 million in connection with such purchases. Omnibus Agreement Penn Virginia, we, our general partner and PVR Coal are parties to an Omnibus Agreement that governs potential competition among us. The Omnibus Agreement was entered into in connection with our initial public offering in October 2001. Upon completion of PVGs initial public offering in December 2006, PVG became subject to the Omnibus Agreement as an affiliate of Penn Virginia. For purposes of the Omnibus Agreement, any restrictions that apply to Penn Virginia also apply to PVG. Under the Omnibus Agreement, Penn Virginia and its affiliates are not permitted to engage in the businesses of: (i) owning, mining, processing, marketing or transporting coal, (ii) owning, acquiring or leasing coal reserves or (iii) growing, harvesting or selling timber, unless it or they first offers us the opportunity to acquire these businesses or assets and the board of directors of our general partner, with the concurrence of its conflicts committee, elects to cause us not to pursue such opportunity or acquisition. In addition, Penn Virginia and its affiliates will be able to purchase any business which includes the purchase of coal reserves,
timber or infrastructure relating to the production or transportation of coal if the majority value of such business is not derived from owning, mining, processing, marketing or transporting coal or growing, harvesting or selling timber. If Penn Virginia or its affiliates make any such acquisition, it or they must offer us the opportunity to purchase the coal reserves, timber or related infrastructure following the acquisition and the conflicts committee of the board of directors of our general partner will determine whether we should pursue the opportunity. The restriction will terminate upon a change of control of Penn Virginia or our general partner. Non-Compete Agreement We and PVG are parties to a Non-Compete Agreement that governs potential competition among us. The Non-Compete Agreement was entered into in connection with PVGs initial public offering in December 2006, but is not effective until PVG is no longer subject to the Omnibus Agreement. Pursuant to the Non-Compete Agreement, PVG will have a right of first refusal with respect to the potential acquisition of any general partner interest, and any other equity interests under common ownership with such general partner, in a publicly traded partnership, other than any partnerships engaged in the coal or timber businesses described above or the business
of gathering or processing natural gas or other hydrocarbons. We will have a right of first refusal with respect to the potential acquisition of assets that relate to the business of (i) owning, mining, processing, marketing or transporting coal, (ii) owning, acquiring or leasing coal reserves, (iii) growing, harvesting or selling timber or (iv) the gathering or processing of natural gas or other hydrocarbons. Policies and Procedures Regarding Transactions with Related Persons Under our Corporate Governance Principles, all directors must recuse themselves from any decision affecting their personal, business or professional interests. In addition, as a general matter, our practice is that any proposed transaction between us (or any of our subsidiaries) and Penn Virginia or PVG (or any of their respective subsidiaries) is approved by the conflicts committee of our general partner. For a discussion of the
 135    TABLE OF CONTENTS conflicts committee of our general partner, see Item 10, Directors, Executive Officers and Corporate Governance  Committees of the Board of Directors of our General Partner  Conflicts Committee. With respect to any proposed transaction with any other related person, as a general matter, our practice is that such transactions are approved by disinterested directors. The General Counsel of our general partner advises the board of directors of our general partner as to which transactions involve related persons, which transactions require the approval of the conflicts committee of our general partner and which
directors are prohibited from voting on a particular transaction. All of the related transactions described above were approved in accordance with the foregoing policies and procedures. Director Independence Messrs. Cloues, Gardner, Hofmann and Montague and Ms. Perelman are independent directors, as defined by NYSE Listing Standards and SEC rules and regulations. We refer to those directors as Independent Directors. The board of directors of our general partner has determined that none of the Independent Directors have any relationship with us other than as a director of our general partner or its affiliates, Penn Virginia or PVGs general partner. Item 14 Principal Accounting Fees and Services In connection with the audits of our consolidated financial statements and our internal control over financial reporting, or ICFR, for 2009, we entered into an agreement with KPMG which sets forth the terms by which KPMG will perform audit services for us. That agreement provides for alternative dispute resolution procedures and an exclusion of the right to collect punitive damages. The following table shows fees for professional audit services rendered by KPMG for the audits of our consolidated financial statements for 2009 and 2008 and the audits of our ICFR for 2009 and 2008 and fees billed for other services rendered by KPMG:  2009

          

          2008Audit Fees(1)

          

          $

          732,000

          

          

          $

          1,020,000Audit-Related Fees(2)

          

          

          5,000

          

          

          

          5,000Tax Fees

          

          

          

          

          

          

          All Other Fees

          

          

          

          

          

          

          Total Fees

          

          $

          737,000

          

          

          $

          1,025,000
  (1)

          Audit fees consist of fees for the audit of our consolidated financial statements, the audit of our ICFR, consents for registration statements and comfort letters related to public offerings. Also included in audit fees are reimbursements of travel-related expenses. (2)

          Audit-related fees consist of fees pertaining to debt compliance letters issued by KPMG for the Notes. Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Registered Public Accounting Firm The policy of the audit committee of our general partner is to pre-approve all audit, audit-related and non-audit services provided by our independent registered public accounting firm. These services may include audit services, audit-related services, tax services and other services. The audit committee may also pre-approve particular services on a case-by-case basis. Our independent registered public accounting firm is required to periodically report to the audit committee regarding the extent of services provided by our independent registered public accounting firm in accordance with such pre-approval. The audit committee may also delegate
pre-approval authority to one or more of its members. Such member(s) must report any decisions to the audit committee at the next scheduled meeting.
 136    TABLE OF CONTENTS Part IV Item 15 Exhibits and Financial Statement Schedules The following documents are filed as exhibits to this Annual Report on Form 10-K:  (1)

          

          Financial Statements  The financial statements filed herewith are listed in the Index to Consolidated Financial Statements on page 72 of this Annual Report on Form 10-K.(2)

          

          All schedules are omitted because they are not required, inapplicable or the information is included in the Consolidated Financial Statements or the notes thereto.(3)

          

          Exhibits(2.1)

          

          Purchase and Sale Agreement dated June 17, 2008 between Lone Star Gathering, L.P. and Penn Virginia Resource Partners, L.P., as amended by First Amendment to Purchase and Sale Agreement dated as of July 17, 2008 (incorporated by reference to Exhibit 2.1 to Registrants Current Report on Form 8-K filed on July 22, 2008).(3.1)

          

          Certificate of Limited Partnership of Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 3.1 to Registrants Registration Statement on Form S-1 filed on July 19, 2001).(3.2)

          

          Third Amended and Restated Agreement of Limited Partnership of Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 3.1 to Registrants Current Report on Form 8-K filed on August 7, 2008).(3.2.1)

          

          Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 3.1 to Registrants Current Report on Form 8-K filed on February 24, 2009).(3.3)

          

          Limited Liability Company Agreement of PVR Finco LLC (incorporated by reference to Exhibit 3.2 to Registrants Current Report on Form 8-K filed on August 7, 2008).(3.4)

          

          Certificate of Formation of Penn Virginia Resource GP, LLC (incorporated by reference to Exhibit 3.5 to Amendment No. 1 to Registrants Registration Statement Form S-1 filed on September 7, 2001).(3.5)

          

          Fourth Amended and Restated Limited Liability Company Agreement of Penn Virginia Resource GP, LLC (incorporated by reference to Exhibit 3.2 to Registrants Current Report on Form 8-K filed on December 13, 2006).(10.1)

          

          Amended and Restated Credit Agreement, dated August 5, 2008, by and among PVR Finco LLC, the guarantors party thereto, PNC Bank, National Association, as Administrative Agent, and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to Registrants Quarterly Report on Form 10-Q for the quarter ended September 30, 2008).(10.2)

          

          First Amendment to Amended and Restated Credit Agreement, dated March 27, 2009, among PVR Finco LLC, the guarantors party thereto, PNC Bank, National Association, as Administrative Agent, and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to Registrants Current Report on Form 8-K filed on March 31, 2009).(10.3)

          

          Consolidated Commitment Increase Agreement, dated March 27, 2009 (incorporated by reference to Exhibit 10.2 to Registrants Current Report on Form 8-K filed on March 31, 2009).(10.4)

          

          Contribution and Conveyance Agreement dated September 13, 2001 among Penn Virginia Operating Co., LLC, Penn Virginia Holding Corp., Penn Virginia Resource Holdings Corp., Penn Virginia Resource LP Corp., Penn Virginia Resource GP Corp. and the other parties named therein (incorporated by reference to Exhibit 10.2 to Amendment No. 2 to Registrants Registration Statement on Form S-1 filed on October 4, 2001).
 137    TABLE OF CONTENTS (10.5)

          

          Contribution, Conveyance and Assumption Agreement dated September 14, 2001 among Penn Virginia Resource GP, LLC, Penn Virginia Resource Partners, L.P., Penn Virginia Operating Co., LLC and the other parties named therein (incorporated by reference to Exhibit 10.3 to Amendment No. 2 to Registrants Registration Statement on Form S-1 filed on October 4, 2001).(10.6)

          

          Closing Contribution, Conveyance and Assumption Agreement dated October 30, 2001 among Penn Virginia Operating Co., LLC, Penn Virginia Corporation, Penn Virginia Resource Partners, L.P., Penn Virginia Resource GP, LLC, Penn Virginia Resource L.P. Corp., Wise LLC, Loadout LLC, PVR Concord LLC, PVR Lexington LLC, PVR Savannah LLC, Kanawha Rail Corp. (incorporated by reference to Exhibit 10.7 to Amendment No. 2 to Registrants Registration Statement on Form S-1 filed on October 4, 2001).(10.7)

          

          Omnibus Agreement dated October 30, 2001 among the Penn Virginia Corporation, Penn Virginia Resource GP, LLC, Penn Virginia Operating Co., LLC and Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 10.6 to Amendment No. 2 to Registrants Registration Statement on Form S-1 filed on October 4, 2001).(10.8)

          

          Amendment No. 1 to Omnibus Agreement dated December 19, 2002 among the Penn Virginia Corporation, Penn Virginia Resource GP, LLC, Penn Virginia Operating Co., LLC and Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 10.7 to Registrants Annual Report on Form 10-K for the year ended December 31, 2002).(10.9)

          

          Non-Compete Agreement dated December 8, 2006 among Penn Virginia GP Holdings, L.P., Penn Virginia Resource Partners, L.P. and Penn Virginia Resource GP, LLC (incorporated by reference to Exhibit 10.2 to Registrants Current Report on Form 8-K filed on December 13, 2006).(10.10)

          

          Units Purchase Agreement dated June 17, 2008 by and among Penn Virginia Resource LP Corp., Kanawha Rail Corp. and Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 10.1 to Registrants Current Report on Form 8-K filed on July 22, 2008).(10.11)

          

          Penn Virginia Resource GP, LLC Fifth Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Registrants Current Report on Form 8-K filed on January 15, 2009).*(10.12)

          

          Form of Agreement for Deferred Common Unit Grants under the Penn Virginia Resource GP, LLC Fifth Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.14 to Registrants Annual Report on Form 10-K for the year ended December 31, 2007).*(10.13)

          

          Form of Agreement for Restricted Unit Awards under the Penn Virginia Resource GP, LLC Fifth Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.15 to Registrants Annual Report on Form 10-K for the year ended December 31, 2007).*(10.14)

          

          Form of Agreement for Phantom Unit Awards under the Penn Virginia Resource GP, LLC Fifth Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Registrants Current Report on Form 8-K filed on February 24, 2009).*(10.15)

          

          Penn Virginia Resource GP, LLC Amended and Restated Non-Employee Directors Deferred Compensation Plan (incorporated by reference to Exhibit 10.4 to Registrants Current Report on Form 8-K filed on October 29, 2007).*(10.16)

          

          Amended and Restated Executive Change of Control Severance Agreement dated October 17, 2008 between Penn Virginia Resource GP, LLC and Keith D. Horton (incorporated by reference to Exhibit 10.1 to Registrants Current Report on Form 8-K filed on October 22, 2008).*
 138    TABLE OF CONTENTS (10.17)

          

          Amended and Restated Executive Change of Control Severance Agreement dated October 17, 2008 between Penn Virginia Resource GP, LLC and Ronald K. Page (incorporated by reference to Exhibit 10.15 to Registrants Annual Report on Form 10-K for the year ended December 31, 2008).*(12.1)

          

          Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.(14.1)

          

          Penn Virginia Resource GP, LLC Code of Business Conduct and Ethics (incorporated by reference to Exhibit 14.1 to Registrants Current Report on Form 8-K filed on July 24, 2009).(21.1)

          

          Subsidiaries of Penn Virginia Resource Partners, L.P.(23.1)

          

          Consent of KPMG LLP.(31.1)

          

          Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(31.2)

          

          Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(32.1)

          

          Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(32.2)

          

          Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
  *

          Management contract or compensatory plan or arrangement.
 139    TABLE OF CONTENTS SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  PENN VIRGINIA RESOURCE PARTNERS, L.P.By: PENN VIRGINIA RESOURCE GP, LLCMarch 1, 2010

          

          By:/s/ Frank A. PiciFrank A. PiciVice President and Chief Financial OfficerMarch 1, 2010

          

          By:/s/ Forrest W. McNairForrest W. McNairVice President and Controller
 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.  /s/ A. James DearloveA. James Dearlove

          

          Chairman of the Board and Chief Executive Officer

          

          March 1, 2010/s/ Edward B. Cloues, IIEdward B. Cloues, II

          

          Director

          

          March 1, 2010/s/ James L. GardnerJames L. Gardner

          

          Director

          

          March 1, 2010/s/ Thomas W. HofmannThomas W. Hofmann

          

          Director

          

          March 1, 2010/s/ James R. MontagueJames R. Montague

          

          Director

          

          March 1, 2010/s/ Marsha R. PerelmanMarsha R. Perelman

          

          Director

          

          March 1, 2010/s/ Frank A. PiciFrank A. Pici

          

          Director and Vice President and Chief Financial Officer

          

          March 1, 2010/s/ Nancy M. SnyderNancy M. Snyder

          

          Director and Vice President, Chief Administrative Officer and General Counsel

          

          March 1, 2010
 140