Edgar Filing: Penn Virginia GP Holdings, L.P.

February 24, 2011

/s/ Forrest W. McNair

Forrest W. McNair

Vice President and Controller

Penn Virginai GP Holdings, L.P. - Form 10-K

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, 2010

Commission file number: 1-33171

Penn Virginia GP Holdings, L.P.

(Exact name of registrant as specified in its charter)


Delaware		20-5116532
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

Five Radnor Corporate Center, Suite 500

100 Matsonford Road

Radnor, Pennsylvania 19087

(Address of principal executive offices)

Registrant’s telephone number, including area code: (610) 975-8200

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


Title of each class		Name of exchange on which registered
Common 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 ¨ No x

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 ¨ No x

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

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

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

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

The aggregate market value of common units held by non-affiliates of the registrant was $618,389,569 as of June 30, 2010 (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, 2011 39,074,500 common units representing limited partner interests of the registrant were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

PENN VIRGINIA GP HOLDINGS, L.P. AND SUBSIDIARIES

Table of Contents


		Page
Forward-Looking Statements			1

Item

	Part I
1.	Business		2
1A.	Risk Factors		21
1B.	Unresolved Staff Comments		40
2.	Properties		41
3.	Legal Proceedings		46
4.	Reserved		47

	Part II
5.	Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		48
6.	Selected Financial Data		50
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		51
	Overview of Business		51
	Liquidity and Capital Resources		55
	Contractual Obligations		58
	Off-Balance Sheet Arrangements		59
	Results of Operations		60
	Environmental Matters		69
	Critical Accounting Estimates		69
	New Accounting Standards		71
7A.	Quantitative and Qualitative Disclosures About Market Risk		72
8.	Financial Statements and Supplementary Data		75
9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		106
9A.	Controls and Procedures		106
9B.	Other Information		106

	Part III
10.	Directors, Executive Officers and Corporate Governance		107
11.	Executive Compensation		107
12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		107
13.	Certain Relationships and Related Transactions, and Director Independence		107
14.	Principal Accounting Fees and Services		107

	Part IV
15.	Exhibits and Financial Statement Schedules		108

Forward-Looking Statements

Certain statements contained in this Annual Report on Form 10-K include “forward-looking statements.” All statements that express belief, expectation, estimates or intentions, as well as those that are not statements of historical fact, are forward-looking statements. Words such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” and similar expressions are intended to identify such forward-looking statements. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following:

•

the volatility of commodity prices for natural gas, natural gas liquids, or 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;

•

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);

•

our ability to complete our previously announced merger; and

•

other risks set forth in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2010.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the 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.

Part I

Item 1 Business

General

Penn Virginia GP Holdings, L.P. (NYSE: PVG) is a publicly traded Delaware limited partnership that currently owns three types of equity interests in Penn Virginia Resource Partners, L.P. (NYSE: PVR), or PVR, a publicly traded Delaware limited partnership that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas. 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 GP Holdings, L.P. and its subsidiaries.

Our Interest in PVR

Our only cash generating assets consist of our interests in PVR, which consist of the following:

•

a 2% general partner interest in PVR, which we hold through our 100% ownership interest in Penn Virginia Resource GP, LLC, PVR’s general partner;

•

all of the incentive distribution rights, or IDRs, in PVR, which we hold through our 100% ownership interest in PVR’s general partner; and

•

19,638,745 common units of PVR, representing an approximately 37% limited partner interest in PVR.

All of our cash flows are generated from the cash distributions we receive with respect to the PVR equity interests we own. PVR is required by its partnership agreement to distribute, and it has historically distributed within 45 days of the end of each quarter, all of its cash on hand at the end of each quarter, less cash reserves established by its general partner in its sole discretion to provide for the proper conduct of PVR’s business or to provide for future distributions. While we, like PVR, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of PVR. Most notably, our general partner does not have an economic interest in us and is therefore not entitled to receive any distributions from us and our capital structure does not include IDRs. Accordingly, our distributions are allocated exclusively to our common units, which is our only class of security currently outstanding.

PVR IDRs

In accordance with PVR’s partnership agreement, IDRs represent the right to receive an increasing percentage of quarterly distributions of PVR’s 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. We currently hold 100% of the IDRs through our ownership of PVR’s general partner, but may transfer these rights to an affiliate (other than an individual) or to another entity as part of the merger or consolidation of PVR’s general partner with or into such entity or the transfer of all or substantially all of PVR’s general partner’s assets to another entity without the prior approval of PVR’s unitholders if the transferee agrees to be bound by the provisions of PVR’s 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 PVR common units. On or after September 30, 2011, the IDRs will be freely transferable. The IDRs are payable as follows:

If for any quarter:

•

PVR has distributed available cash from operating surplus to its common unitholders in an amount equal to the minimum quarterly distribution; and

•

PVR has 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, PVR will distribute any additional available cash from operating surplus for that quarter among the unitholders and us, as the owner of PVR’s general partner, in the following manner:

•

First, 98% to all unitholders, and 2% to us, as the owner of PVR’s 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 us, as the owner of PVR’s 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 us, as the owner of PVR’s 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 us, as the owner of PVR’s general partner.

Since 2001, PVR has increased its 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 its most recently declared distribution. These increased cash distributions by PVR have placed us at the maximum target cash distribution level as described above and, as a consequence, since reaching such level, we have received 50% of available cash in excess of $0.375 per unit.

PVR’s Business

PVR is a publicly traded Delaware limited partnership 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. PVR currently conducts operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream. We consolidate PVR’s results into our financial statements because we control PVR’s general partner. In 2010, we had a 2% general partner interest in PVR and all of the IDRs, which we hold through our 100% ownership interest in Penn Virginia Resource GP, LLC, PVR’s general partner, and an approximately 37% limited partner interest in PVR.

Our operating income was $121.6 million in 2010, compared to $105.9 million in 2009 and $113.2 million in 2008. In 2010, the PVR coal and natural resource management segment contributed $93.1 million, or 77%, to our operating income, and the PVR natural gas midstream segment contributed $32.8 million, or 27%, to our operating income. These contributions were partially offset by operating expenses from the corporate and other functions, which resulted in $4.3 million of expenses, or 4%.

PVR Coal and Natural Resource Management Segment Overview

The PVR coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. PVR also earns 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, 2010, PVR owned or controlled approximately 804 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. PVR enters into long-term leases with experienced, third-party mine operators, providing them the right to mine PVR’s coal reserves in exchange for royalty payments. PVR actively works with its lessees to develop efficient methods to exploit its reserves and to maximize production from PVR’s properties. PVR does not operate any mines. In 2010, PVR’s lessees produced 34.5 million tons of coal from its properties and paid PVR coal royalties revenues of $130.3 million, for an average royalty per ton of $3.78. Approximately 80% of PVR’s coal royalties revenues in 2010 were derived from coal mined on PVR’s properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of PVR’s coal royalties revenues for the respective periods was derived from coal mined on PVR’s properties under leases containing fixed royalty rates that escalate annually. See “— PVR’s Contracts — PVR Coal and Natural Resource Management Segment” for a description of PVR’s coal leases.

In December, 2010, PVR announced a definitive agreement to purchase certain mineral rights and associated oil and gas royalty interests in Kentucky and Tennessee for approximately $97.3 million, subject to closing adjustments. The mineral rights include approximately 102.0 million tons of coal reserves and resources, and royalty interests from approximately 158 oil and gas wells. There are currently 14 active producing underground and surface mines on the approximately 126,000 acres of mineral estates being acquired, with 10 principal coal lessees operating the mines. The coal is primarily steam coal that is consumed by major electric utilities and other industrial customers in the southeastern United States. On January 25, 2011 PVR completed the purchase of these assets, which was funded by borrowings under the PVR revolving credit facility (“PVR Revolver”).

PVR Natural Gas Midstream Segment Overview

PVR’s natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of December 31, 2010, PVR owned and operated natural gas midstream assets located in Oklahoma, Pennsylvania and Texas, including six natural gas processing facilities having 400 MMcfd of total capacity and approximately 4,263 miles of natural gas gathering pipelines. PVR’s 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, PVR owns member interests in joint ventures that gather and transport natural gas. PVR owns 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. PVR owns a 50% member interest in Crosspoint Pipeline, LLC (“Crosspoint”), a joint venture that gathers residue gas from PVR’s Crossroads Plant and transports it to market. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

In 2010, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 129.7 Bcf, or approximately 355 MMcfd.

During 2010 PVR began construction of gathering systems in Wyoming and Lycoming Counties in Pennsylvania. We have completed construction of three miles of 12-inch gas gathering pipelines in Wyoming County and began gathering natural gas in June, 2010. Construction and development to provide gathering, compression and related services in Lycoming County continues and the first segment of the system began operations in February 2011. These gathering and

transportation infrastructures will capture expected volumes in the Marcellus Shale area. This has been and will continue to be where a significant portion of our growth capital will be spent over the next year.

Changes in Our Management

In connection with Penn Virginia’s (Penn Virginia Corporation NYSE: PVA) reduction of its limited partner interest in us, we implemented certain changes in management, as described below.

On March 8, 2010, A. James Dearlove resigned from his position as Chief Executive Officer of Penn Virginia Resource GP, LLC, or PVR GP, PVR’s general partner, and on March 9, 2010, he resigned from his position as President and Chief Executive Officer of PVG GP, LLC, or PVG GP, our general partner. On March 8, 2010, the board of directors of PVR GP appointed William H. Shea, Jr. to the position of Chief Executive Officer of PVR GP, and on March 9, 2010 the board of directors of PVG GP appointed Mr. Shea to the positions of President and Chief Executive Officer of PVG GP.

On March 23, 2010, Frank A. Pici resigned from his position as Vice President and Chief Financial Officer of PVR GP, and his position as Vice President and Chief Financial Officer of PVG GP. On March 23, 2010, the board of directors of PVR GP appointed Robert B. Wallace to the position of Executive Vice President and Chief Financial Officer of PVR GP, and the board of directors of PVG GP appointed Mr. Wallace to the position of Executive Vice President and Chief Financial Officer of PVG GP.

On March 31, 2010, A. James Dearlove, Frank A. Pici and Nancy M. Snyder each resigned from their positions as directors on the board of directors of PVR GP. On March 31, 2010, Mr. Shea was appointed as a director on the board of directors of PVR GP and on the board of directors of PVG GP.

On June 7, 2010, Frank A. Pici and Nancy M. Snyder each resigned from their positions as directors on the board of directors of PVG GP. On June 7, 2010, Ms. Snyder also resigned from her position as Vice President, Chief Administrative Officer, General Counsel and Assistant Secretary of each of PVR GP and PVG GP. On June 29, 2010 the board of directors of PVR GP appointed Bruce D. Davis, Jr. as Executive Vice President, General Counsel and Secretary of PVR GP and the board of directors of PVG GP appointed Mr. Davis as Executive Vice President, General Counsel and Secretary of PVG GP.

Proposed Merger

On September 21, 2010, we announced that we entered into an Agreement and Plan of Merger (the “Merger Agreement”) by and among PVR, PVR GP, PVG GP and PVR Radnor, LLC (“Merger Sub”), a wholly owned subsidiary of PVR, pursuant to which we and PVG GP, our general partner, will be merged into Merger Sub, with Merger Sub as the surviving entity (the “Merger”). Merger Sub will subsequently be merged into PVRGP, with PVR GP being the surviving entity. In the transaction, our unitholders will receive consideration of 0.98 common units in PVR for each common unit in PVG, representing aggregate consideration of approximately 38.3 million common units in PVR. Pursuant to the Merger Agreement and the Fourth Amended and Restated Agreement of Limited Partnership of PVR, the incentive distribution rights held by PVR’s general partner will be extinguished, the 2.0% general partner interest in PVR held by PVR’s general partner will be converted into a noneconomic interest and approximately 19.6 million common units in PVR owned by PVG will be cancelled.

The terms of the Merger Agreement were unanimously approved by our conflicts committee, comprised of independent directors, of the board of directors of our general partner, by the board of directors of our general partner, by the PVG conflicts committee, comprised of independent directors, of the board of directors of PVR’s general partner, and by the board of directors of PVR’s general partner (in each case with the chief executive officer of each general partner recusing himself from the board of directors approvals).

Pursuant to the Merger Agreement, we agreed to support the Merger by, among other things, voting our PVR common units in favor of the Merger and against any transaction that, among other things, would materially delay or prevent the consummation of the Merger. The agreement to support automatically terminates if the conflicts committee of the board of directors or the board of directors of our general partner changes its recommendation to our unitholders with respect to the Merger or the conflicts committee of the board of directors or the board of directors of PVR’s general partner changes its recommendation to PVR’s unitholders with respect to the Merger.

After the Merger, the board of directors of PVR’s general partner, PVR GP, is expected to consist of nine members, six of whom are expected to be the existing members of the PVR board and three of whom are expected to be the three existing members of the conflicts committee of the board of directors of our general partner.

approvals, (iv) the effectiveness of a registration statement on Form S-4 with respect to the issuance of our common units in connection with the Merger, (v) receipt of certain tax opinions, (vi) approval for listing PVR’s common units to be issued in connection with the Merger on the New York Stock Exchange and (vii) the execution of PVR’s Fourth Amended and Restated Agreement of Limited Partnership.

We will be considered the surviving consolidated entity for accounting purposes, while PVR will be the surviving consolidated entity for legal and reporting purposes. The Merger will be accounted for as an equity transaction. Therefore, the changes in our ownership interest as a result of the Merger will not result in gain or loss recognition.

On February 16, 2011, PVR held a special meeting to consider the vote upon the approval and adoption of the Merger and the other transactions contemplated by the Merger Agreement. At the special meeting, two matters were voted on and approved by a majority of the PVR’s unitholders. The first matter voted upon was the approval of the Merger Agreement and the transactions contemplated thereby. 67.52% or 35,308,687 of the PVR’s units outstanding and entitled to vote, voted in favor of this matter. The second matter voted upon was the approval of the Fourth Amended and Restated Partnership Agreement. 67.54% or 35,322,534 of the PVR’s units outstanding and entitled to vote, voted in favor of this matter.

On February 16, 2011, we announced that we had adjourned the special meeting of PVG unitholders originally scheduled for February 16, 2011 until March 9, 2011. Prior to the adjournment of the PVG special meeting, 20,688,419 units, or 52.94% of the PVG units outstanding and entitled to vote, voted in favor of the proposal to adjourn the special meeting to a later date to allow further time to solicit additional proxies from PVG unitholders. At the commencement of the PVG special meeting, the proxies received from unitholders totaled 25,353,727 million units, or 64.88% of all PVG units outstanding and entitled to vote. Of the total PVG units outstanding and entitled to vote, proxies representing 39.77% of the PVG units were in favor of the merger proposal. The approval of the Merger Agreement and related transactions requires the affirmative vote of holders of a majority of all units outstanding and entitled to vote. The reconvened PVG special meeting will be held at The Villanova University Conference Center, 601 County Line Road, Radnor, Pennsylvania 19087 on March 9, 2011 at 10:00 AM local time.

Business Strategy

Our primary business strategy is to increase our cash distributions to our unitholders. We intend to monitor the implementation of PVR’s business strategies. Our business strategy includes supporting the growth of PVR by purchasing PVR units or lending funds to PVR to provide funding for acquisitions or for internal growth projects. We may also provide PVR with other forms of credit support, such as guarantees related to financing a project.

PVR’s primary business objective is to create sustainable, capital-efficient growth in distributable cash flow to maximize its cash distributions to its unitholders by expanding its coal property management and natural gas gathering and processing businesses through both internal growth and acquisitions. PVR has successfully grown its business through organic growth projects and acquisitions of coal and natural resource properties and natural gas midstream assets. For a more detailed discussion of PVR’s acquisitions, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Acquisitions and Investments.” We and PVR intend to continue to pursue the following business strategies:

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Continue to grow coal reserve holdings through acquisitions and investments in PVR’s existing market areas . PVR continually seeks new reserves of coal both to offset the depletion from production and to increase future production. PVR expects to continue to add to its 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 its criteria. PVR has historically operated in Central Appalachia, its largest area of coal reserves, but views the Illinois Basin as a growth area, both because of its proximity to power plants and because PVR expects future environmental regulations will require the scrubbing of most coals, and not just the higher sulfur coal that is typically found in this basin. PVR 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 PVR’s coal royalty business. Timber and coal infrastructure projects typically involve long-lived assets that generally produce predictable cash flows. PVR owns or controls approximately 243,000 acres of forestlands in Appalachia, which primarily produce various hardwoods and PVR owns a number of coal infrastructure facilities. PVR also has an equity interest in a coal handling joint venture, which is expected to provide development opportunities for coal-related infrastructure projects.

•

Expand PVR’s natural gas midstream operations by adding new production to existing systems and acquiring or building new gathering and processing assets. PVR continually seeks new supplies of natural gas both to offset the natural declines in production from the wells currently connected to its systems and to increase system throughput volumes. New natural gas supplies are obtained for all of PVR’s 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.

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Mitigate commodity price exposure in the PVR natural gas midstream segment . PVR’s natural gas midstream operations consist of a mix of fee-based and margin-based services that, together with its hedging activities, are expected to generate relatively stable cash flows. During the quarter ended December 31, 2010 approximately 22% of the system throughput volumes in the PVR natural gas midstream segment were gathered or processed under fee-based contracts. Under fee-based contracts, PVR is not exposed directly to commodity price risk. The remainder of PVR’s 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, PVR expects to manage its exposure to commodity price risk by entering into hedging transactions. Based upon PVR’s current volumes, it has entered into hedging agreements covering approximately 55% and 32% of its commodity-sensitive volumes in 2011 and 2012. Historically, PVR has generally targeted hedging 50% to 60% of its commodity-sensitive volumes covering a two-year period.

PVR’s Contracts

PVR Coal and Natural Resource Management Segment

PVR earns most of its coal royalties revenues under long-term leases that generally require its lessees to make royalty payments to it based on the higher of a percentage of the gross sales price or a fixed price per ton of coal they sell. The balance of PVR’s coal royalties revenues is earned under long-term leases that require the lessees to make royalty payments to PVR 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 PVR’s leases require the lessee to pay minimum rental payments to PVR in monthly or annual installments, even if no mining activities are ongoing. These minimum rentals are recoupable, usually over a period from one to three years from the time of payment, against the production royalties owed to PVR once coal production commences.

Substantially all of PVR’s leases impose obligations on the lessees to diligently mine the leased coal using modern mining techniques, indemnify PVR for any damages it incurs in connection with the lessee’s mining operations, including any damages PVR 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 its written consent prior to assigning the lease and maintain commercially reasonable amounts of general liability and other insurance. Substantially all of the leases grant PVR the right to review all lessee mining plans and maps, enter the leased premises to examine mine workings and conduct audits of lessees’ compliance with lease terms. In the event of a default by a lessee, substantially all of the leases give PVR the right to terminate the lease and take possession of the leased premises.

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

PVR Natural Gas Midstream Segment

PVR’s natural gas midstream 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, 2010, PVR’s natural gas midstream business generated a majority of its gross margin from two types of contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and NGLs: (i) gas purchase/keep-whole and (ii) percentage-of-proceeds. For the fourth quarter of 2010, approximately 16% of PVR’s system throughput volumes were gathered or processed under gas purchase/keep-whole contracts, 62% were gathered or processed under percentage-of-proceeds contracts and 22% 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 2010, 17%, 14%, 11% and 10% of the PVR natural gas midstream segment’s revenues and 14%, 11%, 9% and 8% of our total consolidated revenues resulted from four of PVR’s natural gas midstream customers, Conoco Phillips Company, Tenaska Marketing Ventures, Targa Liquids Marketing and Trade and Williams NGL Marketing, LLC.

Gas Purchase/Keep-Whole Arrangements Under gas purchase/keep-whole arrangements, PVR generally buys natural gas from producers based upon an index price and then sells the NGLs and the remaining residue gas to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the volume of natural

gas available for sale, profitability is dependent on the value of those NGLs being higher than the value of the volume of gas reduction or “shrink.” Under these arrangements, revenues and gross margins decrease when the price of natural gas increases relative to the price of NGLs. Accordingly, a change in the relationship between the price of natural gas and the price of NGLs could have a material adverse effect on PVR’s business, results of operations or financial condition.

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

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

In many cases, PVR provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of PVR’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts were signed and customer requirements. The contract mix and, accordingly, exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.

Natural Gas Marketing Contracts PVR is also engaged in natural gas marketing by aggregating third-party volumes and selling those volumes into interstate and intrastate pipeline systems such as Enogex and Panhandle Eastern Pipeline and at market hubs accessed by various interstate pipelines. Revenues from this business do not generate qualifying income for a publicly traded limited partnership, but PVR does not expect it to have an impact on its tax status, as it does not represent a significant percentage of PVR’s operating income. For the years ended December 31, 2010 , PVR’s natural gas marketing activities generated $2.8 million, $1.8 million and $5.8 million in net revenues.

PVR Natural Gas Midstream Segment Commodity Derivatives PVR utilizes derivative contracts to hedge against the variability in its frac spread. PVR’s frac spread is the spread between the purchase price for the natural gas PVR purchases from producers and the sale price for NGLs that PVR sells after processing. PVR hedges against the variability in its 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 8 to the Consolidated Financial Statements for a further description of PVR’s derivatives program.

Partnership Structure

PVR completed its initial public offering in October 2001. PVR’s operations are conducted through, and its operating assets are owned by, its subsidiaries. PVR owns its 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, 2010:

LOGO

Relationship with PVR

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. In addition, under a non-compete agreement between us, our general partner, and PVR and its general partner, we must offer the right of first refusal to PVR on any potential acquisition of assets relating to any coal or natural gas businesses. We are not otherwise prohibited from engaging in activities that directly compete with PVR, even if we would have a conflict of interest with PVR with respect to such business opportunity.

Partnership Distributions

Cash Distributions

Our only cash generating assets consist of our interests in PVR. We paid cash distributions of $1.55 per common unit during the year ended December 31, 2010. In the first quarter of 2011, we paid a cash distribution of $0.39 ($1.56 on an

annualized basis) per common unit with respect to the fourth quarter of 2010. This distribution was unchanged from the previous distribution paid on November 19, 2010.

PVR Cash Distributions

In conjunction with our IPO, Penn Virginia contributed its general partner interest, including its IDRs, and most of its limited partner interest in PVR to us in exchange for the general partner interest and a limited partner interest in us. We received total distributions from PVR of $63.1 million, $63.0 million and $57.5 million for the periods presented, allocated among our limited partner interest, general partner interest and IDRs in PVR as shown in the following table:


	Year Ended December 31,
	2010		2009		2008
Limited partner units	$	36,872	$	36,824	$	35,648
General partner interest (2%)		1,999		1,988		1,820
IDRs		24,267		24,140		20,049

Total cash distributions paid	$	63,138	$	62,952	$	57,517

PVR paid cash distributions of $1.88 per common unit during the year ended December 31, 2010. In the first quarter of 2011, PVR paid a cash distribution of $0.47 ($1.88 on an annualized basis) per common unit with respect to the fourth quarter of 2010. This distribution was unchanged from the previous distribution paid on November 12, 2010.

Limited Call Right

If at any time our general partner and its affiliates own more than 90% 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.

Certain Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships among PVR and its general partner and affiliates, on the one hand, and us and our unitholders, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owner. At the same time, our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders.

All of our general partner’s executive officers are also officers of PVR’s general partner and one of our general partner’s directors is also a director of PVR’s general partner. Consequently, this director and all of the officers may encounter situations in which their fiduciary obligations to PVR, 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 provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

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 unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct, or in the case of a criminal matter, acted with the knowledge that such conduct was unlawful.

Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

We are required by our partnership agreement to indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above.

Competition

PVR Coal and Natural Resource Management Segment

The coal industry is intensely competitive primarily as a result of the existence of numerous producers. PVR’s 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 PVR’s lessees having significantly larger financial and operating resources than most of PVR’s lessees. PVR’s 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 PVR’s coal and the prices that PVR’s 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 PVR’s low sulfur coal and the prices PVR’s 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.

PVR Natural Gas Midstream Segment

PVR experiences competition in all of its natural gas midstream markets. PVR’s competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, process, transport and market natural gas. Many of PVR’s competitors have greater financial resources and access to larger natural gas supplies than PVR does.

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 PVR’s gathering systems. The primary concerns of the producer are:

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

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the relative volumes of gas consumed as fuel and lost;

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the gathering/processing fees charged;

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the timeliness of well connects;

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the customer service orientation of the gatherer/processor; and

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the reliability of the field services provided.

Government Regulation and Environmental Matters

The operations of PVR’s 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.

PVR Coal and Natural Resource Management Segment

General Regulation Applicable to Coal Lessees PVR’s lessees are obligated to conduct mining operations in compliance with all applicable federal, state and local laws and regulations. These laws and regulations include matters involving the discharge of materials into the environment, employee health and safety, mine permits and other licensing requirements, reclamation and restoration of mining properties after mining is completed, management of materials generated by mining operations, surface subsidence from underground mining, water pollution, legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, plant and wildlife protection, limitations on land use, storage of petroleum products and substances which are regarded as hazardous under applicable laws and management of electrical equipment containing polychlorinated biphenyls, or PCBs. These extensive and comprehensive regulatory requirements are closely enforced, PVR’s lessees regularly have on-site inspections and violations during mining operations are not unusual in the industry, notwithstanding compliance efforts by PVR’s lessees. However, none of the violations to date, or the monetary penalties assessed, have been material to us or, to PVR’s knowledge, to PVR’s 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 PVR’s lessees with all applicable federal, state and local laws and regulations, those costs have been and are expected to continue to be significant. The lessees post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. We do not accrue for such costs because PVR’s lessees are contractually liable for all costs relating to their mining operations, including the costs of reclamation and mine closure. However, 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 PVR’s lessees. The possibility exists that new legislation or regulations, or new interpretations of existing laws or regulations, may be adopted which have a significant impact on the mining operations of PVR’s lessees or their customers’ ability to use coal and may require us, PVR’s lessees or their customers to change operations significantly or incur substantial costs.

Air Emissions The federal Clean Air Act (“CAA”) and corresponding state and local laws and regulations affect all aspects of coal mining operations, both directly and indirectly. The CAA directly impacts PVR’s lessees’ coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The 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 (“SIPs”), could make coal a less attractive fuel alternative in the planning and building of power plants in the future. Any reduction in coal’s share of power generating capacity could negatively impact PVR’s lessees’ ability to sell coal, which could have a material effect on PVR’s coal royalties revenues.

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

The EPA has promulgated rules, referred to as the “NOx SIP Call,” that require coal-fired power plants and other large stationary sources in 21 eastern states and Washington, D.C. to make substantial reductions in nitrogen oxide emissions in an effort to reduce the impacts of ozone transport between states. Additionally, in March 2005, the EPA issued the final

Clean Air Interstate Rule, or CAIR, which would have permanently capped nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. In 2008, the D.C. Circuit Court of Appeals after initially vacating CAIR, issued an opinion to remand without vacating CAIR. Therefore, CAIR has remained in effect while the EPA conducts rulemaking to modify CAIR to comply with the Court’s July 2008 opinion. In lieu of CAIR, in July 2010, the EPA proposed the Transport Rule which sets a pollution limit on nitrogen oxide and sulfur dioxide emissions in 31 states and the District of Columbia. The public comment period has ended and the EPA expects to issue a final rule in Spring 2011. Under the Transport Rule, some coal-fired power plants might be required to install additional pollution control equipment which could lead to decreased demand for low-sulfur coal.

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. Moreover, on April 29, 2010, EPA proposed new Maximum Achievable Control Technology for several classes of boilers and process heaters, including large coal-fired boilers and process heaters, which would require significant reductions in the emission of particulate matter, carbon monoxide, hydrogen chloride, dioxins and mercury. In addition, various states have promulgated or proposed 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 SIPs 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 revised ozone National Ambient Air Quality Standards (“NAAQS”), significant additional emissions control expenditures may be required at coal-fired power plants. Attainment dates for the new standards range between 2013 and 2030, depending on the severity of the non-attainment. In July 2009, the U.S. Court of Appeals for the District of Columbia vacated part of a rule implementing the ozone NAAQs and remanded certain other aspects of the rule to the EPA for further consideration. Notwithstanding the decision, we expect that additional emissions control requirements may be imposed on new and expanded coal-fired power plants and industrial boilers in the years ahead. Because coal mining operations and coal-fired electric generating facilities emit particulate matter, PVR’s lessees’ mining operations and their customers could be affected when the new standards are implemented by the applicable states.

Likewise, the EPA’s regional haze program to improve visibility in national parks and wilderness areas required affected states to develop SIPs 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. Demand for PVR’s steam coal could be affected when these standards are implemented by the applicable states.

On June 3, 2010, EPA issued a final rule setting forth a more stringent primary NAAQS applicable to sulfur dioxide. The rule also modifies the monitoring increment for the sulfur dioxide standard, establishing a 1-hour standard, and expands the sulfur dioxide monitoring network. Attainment designations will be made pursuant to the modified standards by June 2012. States with non-attainment areas will have until 2014 to submit SIP revisions which must meet the modified standard by August 1, 2017; for all other areas, states will be required to submit “maintenance” SIPs by 2013. EPA also plans to address the secondary sulfur dioxide standard, which is currently under review. As a result, coal-fired power plants, which are the largest end users of PVR’s coal, may be required to install additional emissions control equipment or take other steps to lower sulfur emissions.

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. Depending on the ultimate resolution of these cases, demand for PVR’s coal could be affected, which could have an adverse effect on PVR’s coal royalties revenues.

Climate Change In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for greenhouse gases, went into effect for those nations that ratified it.

The United States is not participating in this treaty. However, the United States is actively participating in international discussions that are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration, with a goal of reaching a consensus on a replacement treaty. Any replacement treaty or other international arrangement requiring additional reductions in greenhouse gas emissions could have a global impact on the demand for coal.

Future regulation of greenhouse gases in the United States could occur pursuant to future U.S. treaty commitments, new domestic legislation that may impose a carbon emissions tax or establish a cap-and-trade program or regulation by the EPA. The Obama Administration has indicated its support for a mandatory cap and trade program to reduce greenhouse gas emissions and the U.S. Congress is considering various proposals to reduce greenhouse gas emissions, mandate electricity suppliers to use renewable energy sources to generate a certain percentage of power, and require energy efficiency measures. Passage of such comprehensive climate change and energy legislation could impact the demand for coal. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of coal that PVR’s lessees mine and sell, thereby reducing PVR’s royalties revenues.

Even in the absence of new federal legislation, greenhouse gas emissions have begun to be regulated by the EPA pursuant to the CAA. In response to the April 2, 2007 U.S. Supreme Court ruling in Massachusetts, et al. v. EPA that the EPA has authority to regulate greenhouse gas emissions under the CAA the EPA has taken several steps towards implementing regulations regarding the emission of greenhouse gases. In 2009, EPA issued 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” , allowing the EPA to begin regulating greenhouse gas emissions under existing provisions of CAA. In May 2010, the EPA issued a final “tailoring rule” that phases in various greenhouse-gas-related permitting requirements beginning in January 2011. Until June 30, 2011, only sources currently subject to CAA prevention of significant deterioration or operating permit programs will be subject to greenhouse gas permitting requirements. Beginning July 1, 2011, these permitting programs will extend to newly built sources emitting more than 100,000 tons of greenhouse gases per year and modified facilities increasing their emissions by at least 75,000 tons of greenhouse gases per year. EPA’s rule clarifies that “smaller sources,” those with emissions of less than 50,000 tons of greenhouse gases per year, will not be regulated until at least April 30, 2016, and may in fact be permanently excluded from the permitting requirements. In December 2010, the EPA issued its plan to update pollution standards for fossil fuel power plants and petroleum refineries. Under that agreement, EPA intends to propose standards for power plants in July 2011 and for refineries in December 2011 and will issue final standards in May 2012 and November 2012, respectively.

The permitting of a number of proposed new coal-fired power plants has also 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. Other state regulatory authorities have also rejected the construction of new coal-fired power plants based on the uncertainty surrounding the potential costs associated with greenhouse gas emissions from these plants under future laws limiting the emission of carbon dioxide.

In addition, permits for several new coal-fired power plants without limits imposed on their greenhouse gas emissions have been appealed by environmental organizations to the 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. Also, a federal appeals court has allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of carbon dioxide, while a second federal appeals court dismissed a similar case on procedural grounds. The U.S. Supreme Court has agreed to hear the appeal of the lower court’s decision.

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. The members of RGGI have established in statute and/or regulation a carbon dioxide trading program. 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.

It is possible that future international, federal and state initiatives to control carbon dioxide emissions could result in increased costs associated with coal consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for coal consumption could result in some of PVR’s lessees’ customers switching to alternative sources of fuel, or otherwise adversely affect PVR’s lessee’s operations and demand for PVR’s coal, which could have a material adverse effect on PVR’s royalties revenues.

Surface Mining Control and Reclamation Act 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 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 PVR’s coal lessees to another entity such as us if any of PVR’s 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 PVR’s knowledge, no such claims have been asserted against us to date. In conjunction with mining the property, PVR’s coal lessees are contractually obligated under the terms of their leases to comply with all state and local laws, including SMCRA, with obligations including the reclamation and restoration of the mined areas by grading, shaping and reseeding the soil. Upon completion of the mining, reclamation generally is completed by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan. Additionally, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is 31.5 cents per ton on surface-mined coal and 13.5 cents per ton on underground-mined coal. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation of orphaned mine sites and abandoned mine drainage control on a statewide basis.

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

Hazardous Materials and Wastes 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 PVR’s 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 PVR’s coal lessees’ operations are regulated under the Clean Water Act, or the CWA, with respect to discharges of pollutants and also require dredge and fill permits under Section 404 for the construction of slurry ponds, stream impoundments, sediment control ponds and valley fills. The EPA issues permits for the discharge of pollutants into navigable waters while the Army Corps of Engineers, or Army Corps, issues dredge and fill permits under Section 404 of the CWA.

Although the CWA has long authorized EPA to review 404 permits issued by the Army Corps, EPA has only recently begun reviewing 404 permits issued by the Army Corps for coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by EPA regarding these permits.

For instance, even though the State of West Virginia has been delegated the authority to issue permits for coal mines in that state, the EPA is taking a more active role in its review of NPDES permit applications for coal mining operations in Appalachia. EPA has stated that it plans to review all applications for NPDES permits. Indeed, interim final guidance issued by the EPA on April 1, 2010, encourages EPA Regions 3, 4 and 5 to (1) object to the issuance of state program NPDES permits where the Region does not believe that the proposed permit satisfies the requirements of the CWA, and (2) exercise a greater degree of oversight with regard to state issued general Section 404 permits.

In addition, the April 1, 2010, interim final guidance also addresses the Regions’ involvement in Section 404 permitting decisions. This guidance follows up on the June 11, 2009 Enhanced Coordination Process Memoranda for the issuance of 404 permits whereby EPA undertook a new level of review of 404 permits than it had previously undertaken. Ultimately, EPA identified 79 coal-related applications for 404 permits that would need to go through that process. EPA’s actions in issuing the Enhanced Coordination Process Memoranda and the guidance are being challenged in a lawsuit pending before the United States District Court for the District of Columbia in a case captioned National Mining Assoc. v. U.S. Environmental Protection Agency. In a ruling issued on January 18, 2011, the District Court held that these measures “are legislative rules that were adopted in violation of the APA’s notice and comment requirements.” The court would not grant the motion for a preliminary injunction to enjoin further use of these measures but also refused to dismiss the Complaint as the EPA had sought.

Not only is EPA reviewing new permits before they are issued, EPA has recently exercised its “veto” power on January 14, 2011 to withdraw or restrict the use of previously issued permits in connection with the Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action is the first time that such power was exercised with regard to a previously permitted coal mining project. More frequent use of the EPA’s Section 404 “veto” power as well as the increased risk of application of this power to previously permitted projects could create uncertainly with regard to PVR’s lessees’ continued use of their current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting PVR’s coal royalties revenues.

These initiatives have extended the time required to obtain permits for coal mining and we anticipate further delays in obtaining permits and that the costs associated with obtaining and complying with those permits will increase substantially. In addition, uncertainty over what legally constitutes a navigable water of the United States within the CWA’s regulatory scope may adversely impact the ability of PVR’s coal lessees to secure the necessary permits for their mining activities. It is possible that some of PVR’s lessees’ projects may not be able to obtain these permits because of the manner in which these rules are being interpreted and applied. It is also possible that PVR’s lessees may be unable to obtain or may experience delays in securing, utilizing or renewing additional Section 404 individual permits for surface mining operations due to agency or court decisions stemming from the above developments.

PVR’s lessess may no longer seek general permits under Nationwide Permit 21 (“NWP 21”) adopted by the Army Corps under its authority in Section 404 of the CWA because on June 17, 2010, the Army Corps suspended the use of NWP 21 in the Appalachian states where PVR’s lessees operate, but NWP 21 authorizations already granted remain in effect. While the suspension is in effect, PVR’s lessees must seek 404 permits on an individual basis subject to the EPA measures discussed above with the uncertainties and delays attendant to that process for now.

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 brought lawsuits challenging the rule and in a March 2010 settlement with litigation parties, the OSM agreed to use best efforts to sign a proposed rule by February 28, 2011 and a final rule by June 29, 2012. In addition, Congress has proposed, and may in the future propose, legislation to restrict the placement of mining material in streams.

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 PVR’s lessees’ coal mining operations discharge could require more costly water treatment and could adversely affect PVR’s lessees’ coal production.

The CWA also requires states to develop anti-degradation policies to ensure non-impaired water bodies in the state do not fall below applicable water quality standards. These and other regulatory developments may restrict PVR’s lessees’ ability to develop new mines or could require PVR’s lessees to modify existing operations, which could have an adverse effect on PVR’s 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 PVR’s lessees’ reclamation operations where subsidence or other mining-related problems require the provision of drinking water to affected adjacent homeowners.

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

Mine Health and Safety Laws The operations of PVR’s coal lessees are subject to stringent health and safety standards that have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposes comprehensive health and safety standards on all mining operations. In addition, as part of the Mine Health and Safety Acts of 1969 and 1977, the Black Lung Acts require payments of benefits by all businesses conducting current mining operations to coal miners with black lung or pneumoconiosis and to some beneficiaries of miners who have died from this disease.

Mining accidents in the last several years in West Virginia, Utah, 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. More stringent mine safety laws and regulations promulgated by these states and the federal government have included increased sanctions for non-compliance. Other states have proposed or passed similar bills, resolutions or regulations addressing mine safety practices. Moreover, workplace accidents, such as the April 5, 2010, Upper Big Branch Mine incident, are likely to result in more stringent enforcement and possibly the passage of new laws and regulations.

In 2006, the Mine Improvement and New Emergency Response Act (“Miner Act”) was enacted 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. Since passage of the Miner Act, enforcement scrutiny has also increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and the severity of enforcement actions and related penalties. Various states also have enacted their own new laws and regulations addressing many of these same subjects. The Dodd Frank Bill that was enacted by Congress in 2010 now requires mining companies including coal companies to include various safety statistics regarding citations, penalties, notices of violation and pending legal actions in periodic reports that are required by the securities laws. These disclosures may lead to the enactment of yet further legislation regarding mine safety.

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

Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws. Regulations also provide that a mining permit can be refused or revoked if the permit

applicant or permittee owns or controls, directly or indirectly through other entities, mining operations which have outstanding environmental violations. Although, like other coal companies, PVR’s lessees have been cited for violations in the ordinary course of business, to PVR’s 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.

PVR’s lessees have obtained or applied for permits to mine a majority of the reserves that are currently planned to be mined over the next five years. PVR’s lessees are also in the planning phase for obtaining permits for the additional reserves planned to be mined over the following five years. However, there are no assurances that they will not experience difficulty in obtaining mining permits in the future. See “— Coal and Natural Resource Management Segment — Clean Water Act.”

OSHA PVR’s lessees and PVR’s 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 PVR’s operations and that this information be provided to employees, state and local government authorities and citizens.

PVR Natural Gas Midstream Segment

General Regulation PVR’s 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 PVR’s gathering business and the market for PVR’s services. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines into which PVR’s gathering pipelines deliver. However, we cannot assure you that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

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

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

PVR is subject to ratable take and common purchaser statutes in Texas and Oklahoma. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting PVR’s right as an owner of gathering facilities to decide with whom 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 PVR’s gathering facilities are exempt from these federal pipeline safety requirements under the rural gathering exemption. We cannot assure you that the rural

gathering exemption will be retained in its current form in the future. Failure to comply with applicable regulations under the NGA, the NGPSA and certain state laws can result in the imposition of administrative, civil and criminal remedies.

Air Emissions PVR’s 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 PVR’s processing plants and compressor stations and also impose procedural requirements on how we conduct PVR’s 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. PVR’s failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. PVR will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

Hazardous Materials and Wastes PVR’s natural gas midstream operations could incur liability under CERCLA and comparable state laws resulting from the disposal or other release of hazardous substances or wastes originating from properties we own or operate, regardless of whether such disposal or release occurred during or prior to PVR’s 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,” PVR’s 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.

PVR’s 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 PVR believes that it is unlikely that the RCRA exemption will be repealed in the near future, repeal would increase costs for waste disposal and environmental remediation at PVR’s facilities.

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

Water Discharges PVR’s 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 PVR’s systems or facilities could result in fines or penalties as well as significant remedial obligations.

OSHA PVR’s natural gas midstream operations are subject to OSHA. See “— Coal and Natural Resource Management Segment — OSHA.”

Employees and Labor Relations

Neither we nor PVR have employees. To carry out PVR’s operations, our affiliates employed 210 employees who directly supported PVR’s operations at December 31, 2010. Our general partner considers current employee relations to be favorable.

Available Information

Our internet address is http://www.pvgpholdings.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, Compensation and Benefits Committee Charter 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. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with, or furnish to, the SEC.

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 volume
Bcf		one billion cubic feet
Bcfe		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 content
BTU		British thermal unit
MBbl		one thousand barrels
Mbf		one thousand board feet
Mcf		one thousand cubic feet
Mcfe		one thousand cubic feet equivalent
MMBbl		one million barrels
MMbf		one million board feet
MMBtu		one million British thermal units
MMcf		one million cubic feet
MMcfd		one million cubic feet per day
MMcfe		one million cubic feet equivalent
NGL		natural gas liquid
NYMEX		New York Mercantile Exchange
Probable coal reserves		those coal 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 observation
Proven coal reserves		those coal reserves for which: (i) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; (ii) grade and/or quality are computed from the results of detailed sampling; and (iii) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well defined, that the size, shape, depth and mineral content of reserves are well-established
Proved 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 years

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, results of operations, as well as any related benefits of owning our securities could be materially and adversely affected.

Risks Inherent in an Investment in Us

Our cash flow is entirely dependent on the ability of PVR to make cash distributions to us.

Our earnings and cash flow consist exclusively of cash distributions from PVR. Consequently, a significant decline in PVR’s earnings or cash distributions would have a negative impact on us. The amount of cash that PVR will be able to distribute to its partners, including us, each quarter principally depends upon the amount of cash it can generate from its coal and natural resource management and natural gas midstream businesses. The amount of cash that PVR will generate will fluctuate from quarter to quarter based on, among other things:

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the amount of coal its lessees are able to produce;

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the price at which its lessees are able to sell the coal;

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its lessees’ timely receipt of payment from their customers;

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its timely receipt of payments from its lessees;

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the amount of natural gas transported in its gathering systems;

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the amount of throughput in its processing plants;

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the price of and demand for natural gas;

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its timely receipt of payments from its natural gas and NGL customers;

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the price of and demand for NGLs;

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the relationship between natural gas and NGL prices, which impacts the effectiveness of its hedging program; and

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the fees it charges and the margins it realizes for its natural gas midstream services.

In addition, the actual amount of cash that PVR will have available for distribution will depend on other factors including:

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the level of capital expenditures it makes;

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the cost of acquisitions, if any;

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its debt service requirements;

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fluctuations in its working capital needs;

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restrictions on distributions contained in its debt agreements;

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prevailing economic conditions; and

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the amount of cash reserves established by its general partner in its sole discretion for the proper conduct of its business.

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

Since PVR’s inception as a publicly traded partnership, it has grown principally by making acquisitions in both of its business segments and, to a lesser extent, by organic growth on its properties. Readily available access to debt and equity capital and credit availability have been and continue to be critical factors in PVR’s ability to grow. The recent global economic downturn, coupled with the global financial and credit market disruptions, and the consequential adverse effect on credit availability, may adversely impact PVR’s access to new capital and credit availability. Depending on the longevity and ultimate severity of this downturn, PVR’s ability to make acquisitions may be significantly adversely affected, as may PVR’s ability to make cash distributions to its unitholders and, in turn, would affect our ability to make cash distributions to our unitholders.

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

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restrictions on distributions contained in any future debt agreements;

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our estimated general and administrative expenses as well as other operating expenses;

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expenses of PVR’s general partner and PVR;

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reserves necessary for us to make the necessary capital contributions to maintain our 2% general partner interest in PVR, as required by PVR’s partnership agreement upon the issuance of additional partnership securities by PVR; and

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reserves our general partner believes prudent for us to maintain the proper conduct of our business or to provide for future distributions by us.

In addition, prior to making any distributions to our unitholders, we will reimburse our general partner and its affiliates for all direct and indirect expenses incurred by them on our behalf. Our general partner will determine the amount of these reimbursed expenses. In addition, our general partner and its affiliates may perform other services for us for which we will be charged fees as determined by our general partner. The reimbursement of these expenses, in addition to the other factors listed above, could adversely affect the amount of distributions we make to our unitholders. The actual amount of cash that is available for distribution to our unitholders will depend on numerous factors, many of which are beyond our control or the control of our general partner.

Our rate of growth may be reduced to the extent we purchase additional units from PVR, which will reduce the percentage of the cash we receive from the IDRs.

Our business strategy includes supporting the growth of PVR by purchasing PVR units or lending funds to PVR to provide funding for the acquisition of a business or asset or for an internal growth project. To the extent we purchase common units or securities not entitled to a current distribution from PVR, the rate of our distribution growth may be reduced, at least in the short term, as less of our cash distributions will come from our ownership of PVR IDRs, whose distributions increase at a faster rate than those of our other securities.

Our ability to meet our financial needs may be adversely affected by our cash distribution policy and our lack of operational assets.

Our cash distribution policy, which is consistent with our partnership agreement, requires us to distribute all of our available cash quarterly. Our only cash generating assets are interests in PVR, and we currently have no independent operations separate from those of PVR. Moreover, as discussed in these risk factors, a reduction in PVR’s distributions will disproportionately affect the amount of cash distributions we receive. Given that our cash distribution policy is to distribute available cash and not retain it and that our only cash generating assets are interests in PVR, we may not have enough cash to meet our needs if there is an increase in our operating expenses, general and administrative expenses, working capital requirements or the cash needs of PVR or its subsidiaries that reduces PVR’s distributions.

PVR’s general partner, with our consent but without the consent of our unitholders, may limit or modify the incentive distributions we are entitled to receive, which may reduce cash distributions to our unitholders.

We own PVR’s general partner, which owns the IDRs in PVR that entitle us to receive increasing percentages, up to a maximum of 50% of any cash distributed by PVR as certain target distribution levels are reached in excess of $0.375 per PVR unit in any quarter. A substantial portion of the cash flow we receive from PVR is provided by these IDRs. Because of the high percentage of PVR’s incremental cash flow that is distributed to the IDRs, certain potential acquisitions might not increase cash available for distribution per PVR unit. In order to facilitate acquisitions by PVR, the board of directors of the general partner of PVR may elect to reduce the IDRs payable to us with our consent, which we may provide without the approval of our unitholders if our general partner determines that such reduction does not adversely affect our limited partners in any material respect. These reductions may be permanent reductions in the IDRs or may be reductions with respect to cash flows from the potential acquisition. If distributions on the IDRs were reduced for the benefit of the PVR units, the total amount of cash distributions we would receive from PVR, and therefore the amount of cash distributions we could pay to our unitholders, would be reduced.

A reduction in PVR’s distributions will disproportionately affect the amount of cash distributions to which we are currently entitled.

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

Our IDRs entitle us to receive increasing percentages, up to 50%, of all incremental cash distributions above $0.375 per unit distributed by PVR for any quarter. Because we are at the maximum target cash distribution level on the IDRs, future growth in distributions we receive from PVR will not result from an increase in the target cash distribution level associated with the IDRs. Furthermore, a decrease in the amount of distributions by PVR to less than $0.375 per unit per quarter would reduce our percentage of the incremental cash distributions above $0.325 per common unit per quarter from 50% to 25%. As a result, any such reduction in quarterly cash distributions from PVR would have the effect of disproportionately reducing the amount of distributions that we receive from PVR based on our ownership interest in the IDRs as compared to distributions we receive from PVR with respect to our 2% general partner and limited partner interest in PVR.

If distributions on our common units are not paid with respect to any fiscal quarter our unitholders will not be entitled to receive such payments in the future.

Our distributions to our unitholders will not be cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, our unitholders will not be entitled to receive such payments in the future.

Our cash distribution policy limits our ability to grow.

Because we distribute almost all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. In fact, our growth is completely dependent upon PVR’s ability to increase its quarterly distribution per unit because currently our only cash-generating assets are our interests in PVR. If we issue additional units or incur debt to fund acquisitions and growth capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level.

Consistent with the terms of its partnership agreement, PVR distributes to its partners its available cash each quarter. In determining the amount of cash available for distribution, PVR sets aside cash reserves, which it uses to fund its growth capital expenditures. Additionally, PVR has relied upon external financing sources, including commercial borrowings and other debt and equity issuances, to fund its acquisition capital expenditures. Accordingly, to the extent PVR does not have sufficient cash reserves or is unable to finance growth externally, its cash distribution policy will significantly impair its ability to grow. In addition, to the extent PVR issues additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that PVR will be unable to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to distribute to our unitholders. The incurrence of additional debt to finance its growth strategy would result in increased interest expense to PVR, which in turn may reduce the available cash that we have to distribute to our unitholders.

While we or PVR may incur debt to pay distributions to our and its unitholders, the agreements governing such debt are secured and they may restrict or limit the distributions we can pay to our unitholders.

While we or PVR are permitted by our partnership agreements to incur debt to pay distributions to our unitholders, our or PVR’s payment of principal and interest on such indebtedness will reduce our cash available for distribution to our unitholders. We are not currently a party to any debt agreements, but anticipate that any credit facility we may enter into will limit our ability to pay distributions to our unitholders during an event of default or if an event of default would result from the distributions. In addition, any future levels of indebtedness may adversely affect our ability to obtain additional financing for future operations or capital needs, limit our ability to pursue acquisitions and other business opportunities or make our results of operations more susceptible to adverse economic or operating conditions.

Furthermore, the restrictive covenants in the agreements governing PVR’s indebtedness under its revolving credit facility (“PVR Revolver”), and the indenture governing PVR’s outstanding senior notes (“PVR Senior Notes”) contains covenants limiting its ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to us. These restrictions could limit PVR’s ability to obtain future financings, make needed capital expenditures, withstand a future downturn in its business or the economy in general, conduct operations, or otherwise take advantage of business opportunities that may arise. The PVR Revolver contains covenants requiring PVR to maintain specified financial ratios and satisfy other financial conditions and it may be unable to meet those ratios and conditions. Any future breach of these covenants and PVR’s failure to meet any of those ratios and conditions could result in a default under the terms of the PVR Revolver, which could result in the acceleration of its debt and other financial obligations. Additionally, the PVR Revolver is secured by substantially all of PVR’s assets, and if PVR is unable to satisfy its obligations thereunder, the lenders could seek to foreclose on PVR’s assets. The lenders may also sell substantially all of PVR’s assets under such foreclosure or other realization upon those encumbrances without prior approval of our unitholders, which would adversely affect the price of PVR’s and 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 PVR Revolver.

Our unitholders do not elect 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 and will have no right to elect our general partner on an annual or other continuing basis in the future. 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.

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:

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our unitholders’ proportionate ownership interest in us will decrease;

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

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

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the ratio of taxable income to distributions may increase; and

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the market price of our common units may decline.

If the Merger is not consummated, 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.

If the Merger is not consummated, 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. The new owner of our general partner would then be in a position to replace all of the officers of our general partners with individuals it chooses.

If PVR’s unitholders remove PVR’s general partner, we would lose our general partner interest and IDRs in PVR and the ability to manage PVR.

We currently manage PVR through Penn Virginia Resource GP, LLC, PVR’s general partner and our wholly owned subsidiary. PVR’s partnership agreement, however, gives unitholders of PVR the right to remove the general partner of PVR upon the affirmative vote of holders of two-thirds of PVR’s outstanding units. If Penn Virginia Resource GP, LLC were removed as general partner of PVR, it would receive cash or common units in exchange for its 2% general partner interest and the IDRs and would lose its ability to manage PVR. While the common units or cash we would receive are intended under the terms of PVR’s partnership agreement to fully compensate us in the event such an exchange is required, the value of these common units or investments we make with the cash over time may not be equivalent to the value of the general partner interest and the IDRs had we retained them.

In addition, if Penn Virginia Resource GP, LLC is removed as general partner of PVR, we would face an increased risk of being deemed an investment company. See “— If in the future we cease to manage and control PVR, we may be deemed to be an investment company under the Investment Company Act of 1940.”

Our ability to sell our partner interests in PVR may be limited by securities law restrictions and liquidity constraints.

As of December 31, 2010, we owned 19,587,049 common units of PVR, all of which are unregistered and restricted securities within the meaning of Rule 144 under the Securities Act of 1933, or the Securities Act. Unless we were to register these units, we are limited to selling into the market in any three-month period an amount of PVR common units that does not exceed the greater of 1% of the total number of common units outstanding or the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale. In addition, we face contractual limitations on our ability to sell our general partner interest and IDRs and the market for such interests is illiquid.

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.

If in the future we cease to manage and control PVR, we may be deemed to be an investment company under the Investment Company Act of 1940.

If we cease to manage and control PVR and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contractual rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us and our affiliates, and adversely affect the price of our common units.

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.

PVR may issue additional limited partner interests or other equity securities, which may increase the risk that PVR will not have sufficient available cash to maintain or increase its cash distribution level.

PVR has wide latitude to issue additional limited partner interests on the terms and conditions established by its general partner. We receive cash distributions from PVR on the general partner interest, IDRs and limited partner interest that we hold. Because a majority of the cash we receive from PVR is attributable to our ownership of the IDRs, payment of distributions on additional PVR limited partner interests may increase the risk that PVR will be unable to maintain or increase its quarterly cash distribution per unit, which in turn may reduce the amount of incentive distributions we receive and the available cash that we have to distribute to our unitholders.

If PVR’s general partner is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of PVR, its value, and, therefore, the value of our common units, could decline.

The general partner of PVR may make expenditures on behalf of PVR for which it will seek reimbursement from PVR. Under Delaware partnership law, the general partner, in its capacity as the general partner of PVR, has unlimited liability for the obligations of PVR, such as its debts and environmental liabilities, except for those contractual obligations of PVR that are expressly made without recourse to the general partner. To the extent its general partner incurs obligations on behalf of PVR, it is entitled to be reimbursed or indemnified by PVR. If PVR is unable or unwilling to reimburse or indemnify its general partner, PVR’s general partner may not be able to satisfy those liabilities or obligations, which would reduce its cash flows to us.

Risks Related to Conflicts of Interest

PVR’s general partner owes fiduciary duties to PVR’s unitholders that may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including PVR’s general partner, on one hand, and PVR and its unitholders, on the other hand. The directors and officers of PVR’s general partner have fiduciary duties to manage PVR in a manner beneficial to us, the owner of PVR’s general partner. At the same time, PVR’s general partner has a fiduciary duty to manage PVR in a manner beneficial to PVR and its unitholders. The board of directors of PVR’s general partner or its conflicts committee will resolve any such conflict and they have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders. For example, conflicts of interest may arise in the following situations:

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the terms and conditions of any contractual agreements between us and our affiliates, on the one hand, and PVR, on the other hand;

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the interpretation and enforcement of contractual obligations between us and our affiliates, on one hand, and PVR, on the other hand;

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the determination of the amount of cash to be distributed to PVR’s partners and the amount of cash to be reserved

for the future conduct of PVR’s business;

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the determination of whether PVR should make acquisitions and on what terms;

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the determination of whether PVR should use cash on hand, borrow or issue equity to raise cash to finance acquisitions or expansion capital projects, repay indebtedness, meet working capital needs, pay distributions or otherwise;

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any decision we make in the future to engage in business activities independent of PVR; and

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the allocation of shared overhead expenses to PVR and us.

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.

Conflicts of interest may arise between our general partner and its affiliates 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:

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

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Our general partner determines whether or not we incur debt and that decision may affect our or PVR’s credit ratings.

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Our general partner may limit its liability and reduce its fiduciary duties under our partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations and reductions, might constitute breaches of fiduciary duty. As a result of purchasing units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

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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.

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

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Our partnership agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution.

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

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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.

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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 PVR’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. However, all of our general partner’s executive officers are also officers of PVR’s general partner and one of our general partner’s directors is also a director of PVR’s general partner, and each has fiduciary duties to manage the business of PVR in a manner beneficial to PVR and its unitholders. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to us on the one hand, and PVR, 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.

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 90% 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.

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

If PVR’s lessees do not manage their operations well or experience financial difficulties, their production volumes and PVR’s coal royalties revenues could decrease.

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

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the method of mining;

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credit review of their customers;

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marketing of the coal mined;

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coal transportation arrangements;

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negotiations with unions;

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employee hiring and firing;

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employee wages, benefits and other compensation;

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permitting;

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surety bonding; and

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mine closure and reclamation.

If PVR’s 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 PVR and could have a material adverse effect on PVR’s business, results of operations or financial condition.

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

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

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the inability to acquire necessary permits;

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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;

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changes in governmental regulation of the coal industry;

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mining and processing equipment failures and unexpected maintenance problems;

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adverse claims to title or existing defects of title;

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interruptions due to power outages;

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

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labor-related interruptions;

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employee injuries or fatalities; and

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fires and explosions.

Any interruptions to the production of coal from PVR’s reserves could reduce its coal royalties revenues and could have a material adverse effect on PVR’s business, results of operations or financial condition. In addition, PVR’s coal royalties revenues are based upon sales of coal by its lessees to their customers. If PVR’s lessees do not receive payments for delivered coal on a timely basis from their customers, their cash flow would be adversely affected, which could cause PVR’s cash flow to be adversely affected and could have a material adverse effect on PVR’s business, results of operations or financial condition.

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

A substantial or extended decline in coal prices from recent levels could have a material adverse effect on PVR’s lessees’ operations (including mine closures) and on the quantities of coal that may be economically produced from its properties. In addition, because a majority of PVR’s coal royalties are derived from coal mined on PVR’s properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price, PVR’s coal royalties revenues could be reduced by such a decline. Such a decline could also reduce PVR’s coal services revenues and the value of its coal reserves. Additionally, volatility in coal prices could make it difficult to estimate with precision

the value of PVR’s coal reserves and any coal reserves that PVR may consider for acquisition. 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 PVR’s lessees, and, consequently, adversely effect the royalty income received by PVR.

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

PVR depends on a limited number of primary operators for a significant portion of its coal royalties revenues. In the year ended December 31, 2010, five primary operators, each with multiple leases, accounted for 73% of PVR’s 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, PVR’s coal royalties revenues would be reduced.

A failure on the part of PVR’s lessees to make coal royalty payments could give PVR the right to terminate the lease, repossess the property or obtain liquidation damages and/or enforce payment obligations under the lease. If PVR repossessed any of its properties, PVR would seek to find a replacement lessee. PVR may not be able to find a replacement lessee and, if it finds a replacement lessee, PVR may not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If PVR enters into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as the lessee it replaced.

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

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

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

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

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

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

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

PVR’s lessees’ workforces could become increasingly unionized in the future, which could adversely affect their productivity and thereby reduce PVR’s coal royalties revenues.

One of PVR’s lessees has one mine operated by unionized employees. This mine was PVR’s second largest mine on the basis of coal production for the year ended December 31, 2010. All of PVR’s lessees could become increasingly unionized in the future. If some or all of PVR’s lessees’ non-unionized operations were to become unionized, it could adversely affect their productivity and increase the risk of work stoppages. In addition, PVR’s lessees’ operations may be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against its lessees’ operations. Any further unionization of PVR’s lessees’ employees could adversely affect the stability of production from its coal reserves and reduce its coal royalties revenues.

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

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

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

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the amount of ultimately recoverable coal in the ground;

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the effects of regulation by governmental agencies; and

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future coal prices, operating costs, capital expenditures, severance and excise taxes and development and reclamation costs.

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

PVR could be negatively impacted by any decline in the market demand for coal.

The domestic demand for, and price of PVR’s coal primarily depend on coal consumption patterns of the domestic electric utility industry. Consumption by the domestic electric utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments and the price of competing coal and alternative fuel sources, such as natural gas, nuclear, hydroelectric power and other renewable energy sources. During the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. Increased competition by coal producers or producers of alternate fuels could decrease the demand for, or pricing of, or both, for PVR’s coal, adversely impacting demand for the coal that PVR’s lessees produce and thereby reducing our coal royalties revenues.

In addition, 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 PVR’s coal royalties revenues. See Item 1, “Business — Government Regulation and Environmental Matters — Coal and Natural Resource Management Segment — Air Emissions.”

Federal and state laws restricting the emissions of greenhouse gases in many jurisdictions could adversely affect PVR’s coal royalties revenues.

Global climate change continues to attract considerable public and scientific attention. Several scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases”, or GHG’s, including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. Legislative attention in the United States is being paid to reducing GHG emissions. Many states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the development of regional greenhouse gas cap-and-trade programs.

There are many regulatory approaches currently in effect or being considered to address greenhouse gases, including possible future U.S. treaty commitments, new federal or state legislation that may impose a carbon emissions tax or

establish a cap-and-trade program and regulation by the EPA. EPA rules require extensive regulation of GHG emissions from mobile sources and stationary sources, including imposing permitting requirements and obligations to use best available control technology for the reduction of GHG emissions whenever certain stationary sources, such as power plants, are built or significantly modified. Moreover, the EPA plans to update pollution standards for fossil fuel power plants and petroleum refineries.

The permitting of new coal-fired power plants has also been contested by state regulators and environmental organizations for concerns related to greenhouse gas emissions from the new plants. Other state regulatory authorities 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 emissions of carbon dioxide. In addition, several permits issued to new coal-fired power plants without limits on greenhouse gas emissions have been appealed to EPA’s Environmental Appeals Board. The regulation of emissions of GHGs associated with the use of coal may lead PVR’s lessees’ customers to curtail their operations, switch to other fuels or other alternatives which may, individually and collectively, reduce demand for our lessees’ coal and thereby decrease revenues. See Item 1, “Business — Governmental Regulation and Environmental Matters — Coal and Natural Resource Management Segment — Air Emissions.” As a result of current laws and proposed laws, regulations and trends, electric generators may switch from coal to other fuels that generate less greenhouse gas emissions, possibly reducing demand for coal.

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

PVR’s lessees are subject to 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. PVR’s lessees are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be significant and time-consuming and may delay commencement or continuation of exploration or production operations. The possibility exists that new laws or regulations (or judicial interpretations of existing laws and regulations) may be adopted in the future that could materially affect PVR’s lessees’ mining operations, either through direct impacts such as new requirements impacting PVR’s lessees’ existing mining operations, or indirect impacts such as new laws and regulations that discourage or limit coal consumers’ use of coal. Any of these direct or indirect impacts could have an adverse effect on PVR’s coal 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, PVR does not believe violations by its lessees can be eliminated completely. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens and, to a lesser extent, the issuance of injunctions to limit or cease operations. PVR’s lessees may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from their operations. If PVR’s lessees are required to pay these costs and liabilities and if their financial viability is affected by doing so, then their mining operations and, as a result, PVR’s coal royalties revenues and its ability to make distributions to us, could be adversely affected.

Risks Related to PVR’s Natural Gas Midstream Business

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

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

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. PVR has no control over the level of drilling activity in its areas of operations, the amount of reserves underlying the wells and the rate

at which production from a well will decline. In addition, PVR has no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital.

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

PVR typically does not obtain independent evaluations of natural gas reserves dedicated to its gathering systems; therefore, volumes of natural gas on PVR’s systems in the future could be less than it anticipates.

PVR typically does not obtain independent evaluations of natural gas reserves connected to its gathering systems due to the unwillingness of producers to provide reserve information, as well as the cost of such evaluations. Accordingly, PVR does not have independent estimates of total reserves dedicated to its gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to PVR’s gathering systems is less than it anticipates and PVR’s is unable to secure additional sources of natural gas, then the volumes of natural gas gathered on PVR’s gathering systems in the future could be less than PVR anticipates. A decline in the volumes of natural gas on PVR’s systems could have a material adverse effect on PVR’s 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 PVR’s business, results of operations and financial condition.

The NGL products PVR produces, 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 PVR handles or reduce the fees PVR charges for its services. Any reduced demand for PVR’s NGL products could adversely affect demand for the services PVR provides as well as NGL prices, which would negatively impact PVR’s results of operations and financial condition.

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

PVR is subject to significant risks due to fluctuations in natural gas commodity prices. During 2010, PVR 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 — gas purchase/keep-whole and percentage-of-proceeds arrangements. See Item 1, “Business — PVR’s Contracts — PVR Natural Gas Midstream Segment.”

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

In the past, the prices of natural gas and NGLs have been extremely volatile, and PVR expects this volatility to continue. The markets and prices for residue gas and NGLs depend upon factors beyond PVR’s control. These factors

include demand for oil, natural gas and NGLs, which fluctuates with changes in market and economic conditions, and other factors, including:

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

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

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the level of domestic oil and natural gas production;

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the availability of imported oil and natural gas;

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actions taken by foreign oil and gas producing nations;

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the availability of local, intrastate and interstate transportation systems;

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the availability and marketing of competitive fuels;

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the impact of energy conservation efforts; and

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the extent of governmental regulation and taxation.

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

From time to time, PVR evaluates and acquires assets and businesses that it believes complement its existing operations. Readily available access to debt and equity capital and credit availability have been and continue to be critical factors in PVR’s ability to grow. While global financial markets and economic conditions have been disrupted in the past, these conditions have improved more recently. The cost of raising money in the debt and equity capital markets has increased while the availability of funds from these markets generally has diminished. Depending on the longevity and ultimate severity of a downturn, PVR’s ability to make acquisitions may be significantly adversely affected. In the event PVR completes acquisitions, PVR may encounter difficulties integrating these acquisitions with its existing businesses without a loss of employees or customers, a loss of revenues, an increase in operating or other costs or other difficulties. In addition, PVR may not be able to realize the operating efficiencies, competitive advantages, cost savings or other benefits expected from these acquisitions. Future acquisitions might not generate increases in PVR’s cash distributions to its unitholders, and because of the capital used to complete such acquisitions, or the debt incurred, PVR’s and our results of operations may change significantly.

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

One of the ways PVR may grow its natural gas midstream business is through the construction of additions to existing gathering, compression and processing systems. The construction of a new gathering system or pipeline, the expansion of an existing pipeline through the addition of new pipe or compression and the construction of new processing facilities involve numerous regulatory, environmental, political and legal uncertainties beyond PVR’s control and require the expenditure of significant amounts of capital. While global financial markets and economic conditions have been disrupted in the past, these conditions have improved more recently. Depending on the longevity and ultimate severity of this downturn, PVR’s ability to access new capital to fund new projects in a cost-effective manner may be significantly adversely impacted. If PVR does undertake these projects, they may not be completed on schedule, or at all, or at the anticipated cost. Moreover, PVR’s revenues may not increase immediately upon the expenditure of funds on a particular project. For example, the construction of gathering facilities requires the expenditure of significant amounts of capital, which may exceed PVR’s estimates. Generally, PVR may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, PVR may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. As a result, there is the risk that new facilities may not be able to attract enough natural gas to achieve PVR’s expected investment return, which could have a material adverse effect on PVR’s business, results of operations or financial condition.

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

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

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

PVR is subject to risk of loss resulting from nonpayment or nonperformance by its natural gas midstream customers. PVR depends on a limited number of customers for a significant portion of its natural gas midstream revenues. In 2010,

17%, 14%, 11% and 10% of PVR’s natural gas midstream segment revenues and 14%, 11%, 9% and 8% of our total consolidated revenues resulted from four of PVR’s natural gas midstream customers Conoco Phillips Company, Tenaska Marketing Ventures, Targa Liquids Marketing and Trade and Williams NGL Marketing, LLC. Any nonpayment or nonperformance by PVR’s natural gas midstream customers would reduce its cash flows.

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

PVR is dependent upon connections to third-party pipelines to receive and deliver residue gas and NGLs. Any reduction of capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures or other causes could result in reduced volumes gathered and processed in PVR’s natural gas midstream facilities. Similarly, if additional shippers begin transporting volumes of residue gas and NGLs on interconnecting pipelines, PVR’s allocations in these pipelines could be reduced. Any reduction in volumes gathered and processed in PVR’s facilities could adversely affect its revenues and cash flows.

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

In order to manage PVR’s exposure to price risks in the marketing of its natural gas and NGLs, PVR periodically enters into condensate, natural gas and NGL price hedging arrangements with respect to a portion of its expected production. PVR’s hedges are limited in duration, usually for periods of two years or less. However, in connection with acquisitions, sometimes PVR’s hedges are for longer periods. These hedging transactions may limit PVR’s potential gains if NGL prices were to rise (or prices decline with respect to natural gas hedges entered into to lock the frac spread) over the price established by the hedging arrangements. Moreover, PVR has entered into derivative transactions related to only a portion of its condensate, natural gas and NGL volumes. As a result, PVR will continue to have direct commodity price risk with respect to the unhedged portion of these volumes. In trying to maintain an appropriate balance, PVR may end up hedging too much or too little, depending upon how natural gas or NGL prices fluctuate in the future.

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

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PVR’s production is less than expected;

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

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the counterparties to PVR’s futures contracts fail to perform under the contracts; or

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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 PVR engages 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 PVR to engage in a derivative transaction that completely mitigates its exposure to commodity prices. Our Consolidated Financial Statements may reflect a gain or loss arising from an exposure to commodity prices for which PVR is unable to enter into a completely effective hedge transaction.

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

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

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

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inadvertent damage from construction and farm equipment;

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leaks of natural gas, NGLs and other hydrocarbons; and

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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 PVR’s related operations. PVR’s natural gas midstream operations are concentrated in Texas and Oklahoma, and a natural disaster or other hazard affecting these areas could have a material adverse effect on its business, results of operations or

financial condition. PVR is not fully insured against all risks incident to its natural gas midstream business. PVR does not have property insurance on all of its underground pipeline systems that would cover damage to the pipelines. PVR is not insured against all environmental accidents that might occur, other than those considered to be sudden and accidental. If a significant accident or event occurs that is not fully insured, it could adversely affect PVR’s business, results of operations or financial condition.

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

PVR owns and operates an 11-mile interstate natural gas pipeline that, pursuant to the NGA, is subject to the jurisdiction of the FERC. The FERC has granted PVR waivers of various requirements otherwise applicable to conventional FERC-jurisdictional pipelines, including the obligation to file a tariff governing rates, terms and conditions of open access transportation service. The FERC has determined that PVR will have to comply with the filing requirements if the PVR 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.

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

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

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

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

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

The PVR natural gas midstream segment may record impairment losses on its long-lived assets.

The PVR 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 5 to the Consolidated Financial Statements for a description of the PVR 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. 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, IRS, were to treat us or PVR as a corporation for federal income tax purposes or we or PVR 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 value of our investment in PVR depends largely on PVR being treated as a partnership for federal income tax purposes, which requires that 90% or more of PVR’s gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code. PVR may not meet this requirement or current law may change so as to cause, in either event, PVR to be treated as a corporation for federal income tax purposes or otherwise subject to federal income tax. Moreover, 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.

If PVR were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35% Distributions to us would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to us. As a result, there would be a material reduction in our anticipated cash flow and distributions to unitholders, including us, likely causing a substantial reduction in the value of PVR units.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate. 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. As a result, there would be a material reduction in our anticipated cash flow and distributions to unitholders, likely causing a substantial reduction in the value of our common units.

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 or PVR to be treated as a corporation for federal income tax purposes or otherwise subjecting us or PVR 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 recently been considered that would have eliminated partnership tax treatment for certain publicly traded partnerships and recharacterize certain types of income received from partnerships. 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 similar changes 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, PVR is 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 PVR’s gross income apportioned to Texas in the prior year. Imposition of such a tax on us or PVR 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 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.

PVR’s partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects PVR to taxation as a corporation or otherwise subjects PVR 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 PVR. Likewise, our cash distributions to our unitholders will be reduced if we or PVR is subjected to any form of such entity-level taxation.

If the IRS contests the federal income tax positions that we or PVR take, it may adversely affect the market for our common units or PVR’s 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. Moreover, PVR has not requested any ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes or any other matter that affects it. The IRS may adopt positions that differ from the positions we or PVR take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we or PVR take. A court may disagree with some or all of the positions we or PVR

take. Any contest with the IRS may materially and adversely impact the market for our common units or PVR’s common units and the price at which they trade. In addition, the cost of any contest between PVR and the IRS will result in a reduction in cash available for distribution to PVR unitholders and thus will be borne indirectly by us, as a unitholder and as the owner of the general partner of PVR. Moreover, 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, virtually all 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 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.

To maintain the uniformity of the economic and tax characteristics of our common units, we have adopted 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 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, the U.S. Treasury Department 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. Nonetheless, the proposed regulations do not specifically authorize the use of the protection method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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.

PVR has adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and the public unitholders of PVR. The IRS may challenge this treatment, which could adversely affect the value of our common units.

When we or PVR issue additional units or engage in certain other transactions, PVR determines the fair market value of its assets and allocates any unrealized gain or loss attributable to such assets to the capital accounts of PVR’s unitholders and us. Although PVR may from time to time consult with professional appraisers regarding valuation matters, including the valuation of its assets, PVR makes many of the fair market value estimates of its assets itself using a methodology based on the market value of its common units as a means to measure the fair market value of its assets. PVR’s methodology may be viewed as understating the value of PVR’s assets. In that case, there may be a shift of income, gain, loss and deduction between certain PVR unitholders and us, which may be unfavorable to such PVR 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 PVR’s intangible assets and a lesser portion allocated to PVR’s tangible assets. The IRS may challenge PVR’s valuation methods, or our or PVR’s allocation of the Section 743(b) adjustment attributable to PVR’s tangible and intangible assets, and allocations of income, gain, loss and deduction between us and certain of PVR’s 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 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 ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in PVR.

Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in PVR. Other holders of common units in PVR will receive remedial allocations of deductions from PVR. Remedial allocations of deductions to us will be very limited. In addition, our ownership of PVR IDRs will cause more taxable income to be allocated to us from PVR than will be allocated to holders who hold only common units in PVR. If PVR is

successful in increasing its distributions over time, our income allocations from our PVR IDRs will increase, and, therefore, our ratio of taxable income to cash distributions will increase. Because our ratio of taxable income to cash distributions will be greater than the ratio applicable to holders of common units in PVR, our unitholder’s allocable taxable income will be significantly greater than that of a holder of common units in PVR who receives cash distributions from PVR equal to the cash distributions such unitholder receives from us.

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 or PVR conduct business or own property now or in the future, even if those 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.

Risks Related to the Potential Merger

The market value of the stated consideration to our unitholders will be determined by the price of PVR’s common units, the value of which will decrease if the market value of PVR’s common units decreases, and our unitholders cannot be sure of the market value of PVR common units that will be issued.

Pursuant to the Merger Agreement, our unitholders will receive approximately 38.3 million PVR common units as a result of the Merger. The aggregate market value of PVR’s common units that our unitholders will receive in the Merger will fluctuate with any changes in the trading price of PVR’s common units. This means there is no “price protection” mechanism contained in the Merger Agreement that would adjust the number of PVR common units that our unitholders will receive based on any decreases in the trading price of PVR common units. If PVR’s common unit price decreases, the market value of the stated consideration received by our unitholders will also decrease. Consider the following example:

Example: Pursuant to the Merger Agreement, our unitholders will receive 0.98 PVR common units for each PVG common unit, subject to receipt of cash in lieu of any fractional PVR common units. Based on the closing sales price of PVR common units on September 20, 2010 of $24.98 per unit, the market value of all PVR common units to be received by our unitholders would be approximately $956.6 million. If the trading price for PVR common units decreased 10% from $24.98 to $22.48 per unit, then the market value of all PVR common units to be received by our unitholders would be approximately $860.9 million. Accordingly, there is a risk that the premium that existed on September 20, 2010, the last trading day before the public announcement of the Merger, will not be realized by our unitholders at the time the Merger is completed. PVR common unit price changes may result from a variety of factors, including general market and economic conditions, changes in its business, operations and prospects, and regulatory considerations. Many of these factors are beyond the PVR’s control.

The right of our unitholders to distributions will be changed following the Merger.

Under PVR’s existing partnership agreement, we are entitled to receive approximately 2.0% of all distributions made by PVR and increasing percentages, up to a maximum of 48%, of the amount of incremental cash distributed by PVR in respect of the PVR common units as certain target distribution levels are reached in excess of $0.275 per PVR common unit in any quarter. After the Merger, the former unitholders of PVG common units as a group will be entitled to receive approximately 54% of all distributions made by PVR. As a result of this change, the distributions received by the former unitholders of PVG could be significantly different. If distributions from PVR were to increase significantly, the distributions to the former PVG unitholders could be significantly less than they would be if the current structure was not changed.

While the Merger Agreement is in effect, our opportunities to enter into different business combination transactions with other parties on more favorable terms may be limited, and we may be limited in our ability to pursue other attractive business opportunities.

While the Merger Agreement is in effect, we are prohibited from knowingly initiating, soliciting or encouraging the submission of any acquisition proposal or from participating in any discussions or negotiations regarding any acquisition proposal, subject to certain exceptions. As a result of these provisions in the Merger Agreement, our opportunities to enter into more favorable transactions may be limited. Likewise, if we were to sell directly to a third party, we might have received more value with respect to the general partner interest in us and the incentive distribution rights in PVR based on the value of PVR’s business at such time.

Moreover, the Merger Agreement provides for the payment of up to $18.0 million in termination fees under specified circumstances, which may discourage other parties from proposing alternative transactions that could be more favorable to our unitholders.

We have also agreed to refrain from taking certain actions with respect to our businesses and financial affairs pending the consummation of the Merger or termination of the Merger Agreement. These restrictions could be in effect for an extended period of time if the consummation of the Merger is delayed. These limitations do not preclude us from conducting our business in the ordinary or usual course or from acquiring assets or businesses so long as such activity does not have a “material adverse effect” as such term is defined in the Merger Agreement or materially affect our ability to complete the transactions contemplated by the Merger Agreement.

In addition to the economic costs associated with pursuing the Merger, the management of our general partner will continue to devote substantial time and other human resources to the proposed Merger which could limit our ability to pursue other attractive business opportunities, including potential joint ventures, stand-alone projects and other transactions. If we are unable to pursue such other attractive business opportunities, then our growth prospects and the long-term strategic position of our businesses following the Merger could be adversely affected

Failure to complete the Merger or delays in completing the Merger could negatively impact our common unit price.

If the Merger is not completed for any reason, we may be subject to a number of material risks, including the following:

•

the price of our common units may decline to the extent that the current market price of these securities reflects a market assumption that the Merger will be completed; and

•

some costs relating to the Merger, such as certain investment banking fees and legal and accounting fees, must be paid even if the Merger is not completed.

The costs of the Merger could adversely affect PVR’s operations and cash flows available for distribution to its unitholders.

We and PVR estimate the total costs of the Merger to be approximately $10.5 million, primarily consisting of investment banking, legal counsel, and accounting fees, and financial printing and other related costs. These costs could adversely affect PVR’s operations and cash flows available for distributions to PVR’s unitholders. The foregoing estimate is preliminary and is subject to change.

If the Merger Agreement were terminated, we may be obligated to pay PVR for costs incurred related to the Merger. These costs could require us to seek loans or use our available cash that would have otherwise been available for distributions.

Upon termination of the Merger Agreement, and depending upon the circumstances leading to that termination, we could be responsible for reimbursing PVR for Merger related expenses that PVR has paid.

If the Merger Agreement is terminated, the expense reimbursements required by us under the Merger Agreement may require us to seek loans or use cash received from our distributions from PVR to reimburse these expenses. In either case, reimbursement of these costs could reduce the cash we have available to make quarterly distributions.

Tax Risks Related to the Potential Merger

No ruling has been obtained with respect to the U.S. federal income tax consequences of the Merger.

No ruling has been or will be requested from the IRS with respect to the U.S. federal income tax consequences of the Merger. Instead, we are relying on the opinion of counsel to our Conflicts Committee, and PVR is relying on the opinion of its counsel, as to the U.S. federal income tax consequences of the Merger to our unitholders and PVR’s unitholders, respectively. These opinions and positions may not be sustained if challenged by the IRS, which could result in a material change to the expected tax consequences of the Merger.

The intended U.S. federal income tax consequences of the Merger are dependent upon each of us and PVR being treated as a partnership for U.S. federal income tax purposes.

The treatment of the Merger as nontaxable to our unitholders and to PVR unitholders is dependent upon each of us and PVR being treated as a partnership for U.S. federal income tax purposes. If either we or PVR were treated as a corporation for U.S. federal income tax purposes, the consequences of the Merger would be materially different and the Merger would be treated as a taxable exchange in which gain or loss would be recognized by our unitholders.

The U.S. federal income tax treatment of the Merger is subject to potential legislative changes and differing judicial or administrative interpretations.

The U.S. federal income tax consequences of the Merger depend on determinations of fact and interpretations of complex provisions of U.S. federal income tax law. The U.S. federal income tax rules are constantly under review by persons involved in the legislative process, the IRS and the U.S. Treasury Department, frequently resulting in revised interpretations of established concepts, statutory changes, revisions to Treasury Regulations and other modifications and interpretations. Any modification to the U.S. federal income tax laws or interpretations thereof may or may not be applied retroactively and could change the U.S. federal income tax treatment of the Merger to our unitholders and PVR’s unitholders. For example, the U.S. House of Representatives has passed legislation relating to the taxation of “carried interests” that may treat transactions, such as the Merger, occurring on or after an effective date of January 1, 2011, as a taxable exchange to a unitholder of a partnership such as PVG. The U.S. Senate has considered legislation that may have a similar effect. We and PVR are unable to predict whether this proposed legislation or any other proposals will ultimately be enacted, and if so, whether any such proposed legislation would be applied retroactively.

Our unitholders may recognize taxable income or gain for U.S. federal income tax purposes as a result of the Merger.

It is not anticipated that gain or loss will be recognized for U.S. federal income tax purposes by our unitholders as a result of the Merger, except that a unitholder may recognize a gain due to (i) any decrease in our unitholder’s share of partnership liabilities pursuant to Section 752 of the Code, (ii) cash or property distributions to us or our unitholders, and (iii) amounts paid by one person to or on behalf of another person pursuant to the Merger Agreement.

We estimate that the Merger will result in an increase in the amount of net income (or decrease in the amount of net loss) allocable to all of our unitholders that receive PVR common units in the Merger.

We estimate that the closing of the Merger will result in an increase in the amount of net income (or decrease in the amount of net loss) allocable to all of our unitholders that receive PVR common units in the Merger. Although we have projected specific ranges of such an impact for our unitholders, the actual amount and effect of such increase in net income (or decrease in net loss) for any of our unitholders may be more than anticipated because it will depend upon the unitholder’s particular situation, including when, and at what prices, the unitholder purchased our common units and the ability of the unitholder to utilize any suspended passive losses. In addition, the projections are based upon numerous assumptions, and the federal income tax liability of such unitholders could be further increased if PVR makes a future offering of PVR common units and uses the proceeds of the offering in a manner that does not produce substantial additional deductions, such as to repay indebtedness currently outstanding or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate currently applicable to PVR’s assets.

Item 1B Unresolved Staff Comments

None.

Item 2 Properties

Title to Properties Owned or Controlled by PVR

The following map shows the general locations of PVR’s coal reserves and related infrastructure investments and PVR’s natural gas gathering and processing systems as of December 31, 2010:

LOGO

PVR believes that it has satisfactory title to all of its 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

PVR currently leases its office space in Radnor, Pennsylvania, Dallas and Houston, Texas as well as Kingsport, Tennessee. PVR owns the field office in Charleston, West Virginia. PVR believes that its properties are adequate for its current needs.

Coal Reserves and Production

As of December 31, 2010, PVR owned or controlled approximately 804 million tons of proven and probable coal reserves located in Illinois, Kentucky, New Mexico, Virginia and West Virginia. PVR’s coal reserves are in various surface and underground mine seams located on the following properties:

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

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Northern Appalachia Basin : properties located in northern West Virginia;

•

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

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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 PVR’s coal reserves are classified as proven and probable reserves. Proven and probable coal reserves are defined as follows:

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

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

PVR’s lessees mine coal using both underground and surface methods. As of December 31, 2010, PVR’s lessees operated 28 surface mines and 39 underground mines. Approximately 46% of the coal produced from PVR’s properties in 2010 came from underground mines and 54% came from surface mines. Most of PVR’s lessees use the continuous mining method in all of their underground mines located on PVR’s 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, PVR’s lessees use two continuous miners running at the same time, also known as a supersection, to improve productivity and reduce unit costs.

One of PVR’s 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 PVR’s lessees include auger and highwall mining to enhance production, improve reserve recovery and reduce unit costs. On PVR’s 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.

PVR’s lessees’ customers are primarily electric utilities, also referred to as “steam” markets. Coal produced from PVR’s 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 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 PVR’s properties contain and have access to numerous roads and state or interstate highways.

The following tables set forth production data for the periods presented and reserve information with respect to each of PVR’s properties for the period presented (tons in millions):


	Production for Year Ended December 31,
Property	2010		2009		2008
Central Appalachia		18.2		18.3		19.6
Northern Appalachia		4.0		3.8		3.6
Illinois Basin		4.2		4.7		4.6
San Juan Basin		8.1		7.5		5.9

Total		34.5		34.3		33.7


	Proven and Probable Reserves as of December 31, 2010
Property	Underground		Surface		Total		Steam		Metallurgical		Total
Central Appalachia		429.2		154.3		583.5		500.1		83.4		583.5
Northern Appalachia		29.7		-		29.7		29.7		-		29.7
Illinois Basin		152.7		8.5		161.2		161.2		-		161.2
San Juan Basin		-		29.3		29.3		29.3		-		29.3

Total		611.6		192.1		803.7		720.3		83.4		803.7

Of the approximately 804 million tons of proven and probable coal reserves to which PVR had rights as of December 31, 2010, PVR owned the mineral interests and the related surface rights to 432 million tons, or 54%, and PVR owned only the mineral interests to 190 million tons, or 23%. PVR leased the mineral rights to the remaining 182 million tons, or 23%, from unaffiliated third parties and, in turn, subleased these reserves to PVR’s lessees. For the reserves PVR leases from third parties, PVR pays royalties to the owner based on the amount of coal produced from the leased reserves. Additionally, in some instances, PVR purchases surface rights or otherwise compensate surface right owners for mining activities on their properties. In 2010, PVR’s aggregate expenses to third-party surface and mineral owners were $7.7 million.

The following table sets forth the coal reserves PVR owned and leased with respect to each of its coal properties as of December 31, 2010 (tons in millions):


Property	Owned		Leased		Total Controlled
Central Appalachia		435.7		147.8		583.5
Northern Appalachia		29.7		-		29.7
Illinois Basin		130.8		30.4		161.2
San Juan Basin		25.4		3.9		29.3

Total		621.6		182.1		803.7

The following table sets forth PVR’s coal reserve activity for the periods presented and ended (tons in millions):


	2010		2009		2008
Reserves - beginning of year		828.6		826.8		818.4
Purchase of coal reserves		11.4		2.4		34.6
Tons mined by lessees		(34.5)		(34.3)		(33.7)
Revisions of estimates and other		(1.8)		33.7		7.5

Reserves - end of year (1)		803.7		828.6		826.8

(1)	See Item 8, “Financial Statements and Supplementary Data — Note 20. Subsequent Event” for a discussion of a recent purchase of coal reserves.

PVR’s coal reserve estimates are prepared from geological data assembled and analyzed by PVR’s 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.

PVR classifies 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, 2010, approximately 24% of PVR’s reserves met compliance standards for the CAA and 36% were low sulfur. The following table sets forth

PVR’s estimate of the sulfur content and the typical clean coal quality of its recoverable coal reserves for the period presented (tons in millions):


													Typical Clean
			Sulfur Content										Coal Quality
			Reserves as of December 31, 2010										Heat Content
Property	Compliance (1)		Low Sulfur (2)		Medium Sulfur		High Sulfur		Sulfur Unclassified		Total		BTU per Pound (3)		Sulfur (%)		Ash (%)
Central Appalachia		193.3		265.6		205.6		104.8		7.5		583.5		14,041		1.04		6.50
Northern Appalachia		-		-		-		29.7		-		29.7		12,900		2.58		8.80
Illinois Basin		-		-		-		161.2		-		161.2		11,034		2.39		8.32
San Juan Basin		-		20.0		7.6		1.7		-		29.3		9,200		0.89		17.80

Total		193.3		285.6		213.2		297.4		7.5		803.7

(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 PVR leased to mine operators by property for the period presented (tons in millions):


	Proven and Probable Reserves As of December 31, 2010
Property	Total Controlled		Leased to Operators		Percentage Leased
Central Appalachia		583.5		504.5		86%
Northern Appalachia		29.7		19.3		65%
Illinois Basin		161.2		104.4		65%
San Juan Basin		29.3		29.3		100%

Total		803.7		657.5		82%

Other Natural Resource Management Assets

Coal Preparation and Loading Facilities

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

Timber and Oil and Gas Royalty Interests

PVR owns approximately 243,000 acres of forestland in Kentucky, Virginia and West Virginia. The majority of PVR’s forestland is located on properties that also contain its coal reserves.

PVR owns royalty interests in approximately 6.3 Bcfe of proved oil and gas reserves located in Kentucky, Virginia and West Virginia.

Natural Gas Midstream Systems

PVR’s natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. PVR owns, leases or has rights-of-way to the properties where the majority of its natural gas midstream facilities are located. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

PVR owned six natural gas processing facilities having 400 MMcfd of total capacity as of December 31, 2010. PVR’s natural gas midstream operations currently include four natural gas gathering and processing systems and three 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; (vii) the Marcellus gathering system located in northern Pennsylvania. These assets included approximately 4,263 miles of natural gas gathering pipelines as of December 31, 2010. In addition, PVR owns a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. PVR also own a 50% member interest in Crosspoint, a joint venture that gathers residue gas from our Crossroads Plant and transports it to market.

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 1,817 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, PVR 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, PVR completed a 40 MMcfd processing plant expansion in its Spearman complex that was put into service on July 31, 2009. The acquired and expanded processing facilities increased PVR’s processing capacity in the Panhandle System to 260 MMcfd. The increased processing capacity has allowed PVR to process gas volumes that were previously 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 30 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, Roberts and Wheeler 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.

Natural Gas Supply and Markets for Sale of Natural Gas and NGLs. 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 ONG, Natural Gas Pipeline and or ANR 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 east 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 transports 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 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 1,705 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. Fourteen 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 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 517 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.

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 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 136 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.

Marcellus System

General. The Marcellus assets are located in Wyoming and Lycoming Counties in Pennsylvania. PVR has currently completed construction of three miles of 12-inch gas gathering pipelines in Wyoming County and began gathering natural gas in June 2010. Construction and development to provide gathering, compression and related services in Lycoming County continues and the first segment of the system began operations in February 2011.

Natural Gas Supply. The gathering and transportation infrastructure captures current and expected volumes in the Marcellus Shale area. The Marcellus System delivers the natural gas to local customers as well providing avenues for local producers to major pipeline systems such as Transco.

Item 3 Legal Proceedings

As previously disclosed in the joint proxy statement/prospectus of PVG and PVR filed with the Securities and Exchange Commission on December 23, 2010 (the “Joint Proxy Statement/Prospectus”), Kevin Epoch, Sanjay Israni and Anita Scheifele, purported PVG unitholders, (collectively, “Plaintiffs”) filed various putative class action complaints, subsequently amended, against PVR, PVR GP, PVG, PVG GP, and certain of PVG GP’s directors and officers (collectively, “Defendants”) in the Court of Common Pleas of Delaware County, Pennsylvania under the captions Epoch v. Penn Virginia GP Holdings, L.P., et al. and Scheifele v. Shea, et al. relating to the Merger Agreement and the related Merger transactions.

On February 1, 2011, the parties to the above-described Epoch and Scheifele actions entered into the Memorandum of Understanding (“MOU”) to settle the litigation in its entirety. The MOU provides that the parties will seek dismissal with prejudice of the litigation and a release of the Defendants from all present and future claims asserted in the litigation in exchange for a supplemental disclosure to the Joint Proxy Statement/Prospectus. The supplemental disclosure is set forth in a Joint Proxy Statement/Prospectus supplement filed with the Securities and Exchange Commission on February 3, 2011.

The MOU is subject to a number of conditions, including, without limitation, completion of certain discovery by the plaintiffs, the drafting and execution of a formal Stipulation of Settlement, the consummation of the merger and court approval of the proposed settlement. There is no assurance that these conditions will be satisfied.

Other than the merger-related litigation described above, neither we nor PVR are currently a party to any material legal proceedings. In addition, neither we nor PVR are aware of any material legal or governmental proceedings against us or PVR, or contemplated to be brought against us or PVR, under the various environmental protection statutes to which we or PVR are subject. See Item 1, “Business — Government Regulation and Environmental Matters,” for a more detailed discussion of PVR’s material environmental obligations.

Item 4 Reserved

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 “PVG.” The high and low sales prices (composite transactions) and distributions declared related to each fiscal quarter in 2010 and 2009 were as follows:


Quarter Ended	High	Low	Cash Distribution Declared
December 31, 2010	$27.37	$22.91	$0.39
September 30, 2010	$23.80	$17.45	$0.39
June 30, 2010	$19.06	$15.11	$0.39
March 31, 2010	$20.63	$15.18	$0.39
December 31, 2009	$17.40	$12.27	$0.38
September 30, 2009	$17.42	$11.56	$0.38
June 30, 2009	$13.83	$10.75	$0.38
March 31, 2009	$13.86	$8.08	$0.38

Equity Holders

As of December 31, 2010, there were 40 record holders and approximately 14,500 beneficial owners of our common units.

Common Unitholder Return Performance Presentation

The performance graph below compares the cumulative total unitholder return on our common units with the cumulative total returns on the Standard & Poor’s 500 Index (the “S&P 500 Index”) and the Alerian MLP Total Return Index (the “Alerian Total Return Index”). The Alerian Total Return Index is a composite of the 50 most prominent energy master limited partnerships and limited liability companies, as determined by Standard & Poor’s using a float-adjusted market capitalization methodology. The graph assumes an investment of $100 in our common units, and in each of the S&P 500 Index and the Alerian Total Return Index on December 5, 2006 (the day our units began trading on the NYSE) and reinvestment of all dividends and distributions. The results shown in the graph are based on historical data and should not be considered indicative of future performance.

LOGO

Notwithstanding anything to the contrary set forth in any of our previous or future filings under the Securities Act of 1933 or the Securities Exchange Act of 1934 that might incorporate this report or future filings with the SEC, in whole or in part, the preceding performance information shall not be deemed to be “soliciting material” or to be “filed” with the SEC or incorporated by reference into any filing except to the extent this performance presentation is specifically incorporated by reference therein.

Item 6 Selected Financial Data

On December 8, 2006, we completed our IPO whereby we became the successor to Penn Virginia Resource GP, LLC on a combined basis (predecessor). For the purposes of this selected financial data, we refer to the predecessor for the periods prior to December 8, 2006 and to us for the periods beginning on December 8, 2006. The financial data present our results of operations and financial position as if we had existed as a single entity, separate from Penn Virginia, for the periods prior to December 8, 2006.

Because we own and control the general partner of PVR, we reflect our ownership interest in PVR on a consolidated basis, which means that our financial results are combined with PVR’s financial results. We have no separate operating activities apart from those conducted by PVR, and our cash flows consist primarily of distributions from PVR on the partner interests, including IDRs, that we own in PVR. Accordingly, the selected historical financial data set forth in the following table primarily reflect the operating activities and results of operations of PVR. The limited partner interests in PVR not owned by our affiliates are reflected as noncontrolling interests on our balance sheet and the non-affiliated partners’ share of income from PVR is reflected as an expense in our results of operations.

The following selected historical financial information was derived from our Consolidated Financial Statements as of December 31, 2010, 2009, 2008, 2007 and 2006, 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”:


	2010		2009		2008		2007		2006
	(in thousands, except per unit data)
Statement of Income Data:
Revenues (1)	$	864,136	$	656,704	$	881,580	$	549,445	$	517,891
Expenses (1)	$	742,551	$	550,779	$	768,408	$	434,202	$	415,468

Operating income	$	121,585	$	105,925	$	113,172	$	115,243	$	102,423
Net income	$	64,187	$	62,911	$	102,598	$	54,576	$	74,701
Net income attributable to Penn Virginia GP Holdings, LP	$	37,144	$	37,879	$	52,686	$	29,169	$	32,048
Common Unit Data:
Net income per limited partner unit, basic and diluted	$	0.95	$	0.97	$	1.35	$	0.75	$	0.98
Distributions paid	$	60,595	$	59,393	$	54,704	$	35,558	$	-
Distributions paid per unit (2)	$	1.55	$	1.52	$	1.40	$	0.91	$	-
Balance Sheet and Other Financial Data:
Property, plant and equipment, net	$	971,046	$	900,844	$	895,119	$	731,282	$	556,513
Total assets (3)	$	1,304,205	$	1,219,063	$	1,227,674	$	942,251	$	716,269
Long-term debt of PVR	$	708,000	$	620,100	$	568,100	$	399,153	$	207,214
Cash flows provided by operating activities	$	178,450	$	158,214	$	137,187	$	126,480	$	100,683
Additions to property, plant and equipment	$	124,116	$	80,677	$	332,028	$	225,040	$	129,712
Other Statistical Data:
Coal royalty tons (in thousands)		34,512		34,330		33,690		32,528		32,778
System throughput volumes (MMcf)		129,703		121,335		98,683		67,810		55,991

(1)

In 2010, 2009 and 2008, PVR recorded $27.8 million, $72.5 million and $127.9 million of natural gas midstream revenue and $27.8 million, $72.5million and $127.9 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG LP, a subsidiary of Penn Virginia Corporation and considered a related party company up to June 7, 2010, and the subsequent sale of that gas to third parties. PVR took 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.

(2)	We paid a pro rata quarterly distribution of $0.07 per unit in February 2007, which covered the period from December 5, 2006 to December 31, 2006.

(3)

Total assets for the year ended December 31, 2008 include PVR’s Lone Star acquisition, which expanded the geographic scope of the PVR natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin. See Note 5 to the Consolidated Financial Statements for a more detailed description of this acquisition, including pro forma results.

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 GP Holdings, L.P. and its subsidiaries (“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 Our Business

General

We are a publicly traded Delaware limited partnership. Our only cash generating assets consist of our interests in PVR, which consist of the following:

•

a 2% general partner interest in PVR, which we hold through our 100% ownership interest in Penn Virginia Resource GP, LLC, PVR’s general partner;

•

all of the IDRs in PVR, which we hold through our 100% ownership interest in PVR’s general partner; and

•

19,638,745 common units of PVR, representing an approximately 37% limited partner interest in PVR.

PVR IDRs

In accordance with PVR’s partnership agreement, IDRs represent the right to receive an increasing percentage of quarterly distributions of PVR’s 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 per unit ($1.00 per unit on an annualized basis). We currently hold 100% of the IDRs through our ownership of PVR’s general partner, but may transfer these rights separately to an affiliate (other than an individual) or to another entity as part of PVR’s general partner’s merger or consolidation of PVR’s general partner with or into such entity or the transfer of all or substantially all of PVR’s general partner’s assets to another entity without the prior approval of PVR’s unitholders if the transferee agrees to be bound by the provisions of PVR’s 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 PVR common units. On or after September 30, 2011, the IDRs will be freely transferable. The IDRs are payable as follows:

If for any quarter:

•

PVR has distributed available cash from operating surplus to its common unitholders in an amount equal to the minimum quarterly distribution; and

•

PVR has 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, PVR will distribute any additional available cash from operating surplus for that quarter among the unitholders and us, as the owner of PVR’s general partner, in the following manner:

•

First , 98% to all unitholders, and 2% to us, as the owner of PVR’s 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 us, as the owner of PVR’s 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 us, as the owner of PVR’s 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 us, as the owner of PVR’s general partner.

Since 2001, PVR has increased its quarterly cash distribution from $0.25 per unit ($1.00 on an annualized basis) to $0.47 per unit ($1.88 on an annualized basis), which is its most recently declared distribution. These increased cash distributions by PVR have placed us at the maximum target cash distribution level as described above and as a consequence, since reaching such level, we have received 50% of available cash in excess of $0.375 per unit.

Financial Presentation

We reflect our ownership interest in PVR on a consolidated basis, which means that our financial results are combined with PVR’s financial results. The approximately 61% limited partner interest in PVR that we do not own, after the effect

of IDRs, is reflected as noncontrolling interests in our results of operations. We have no separate operating activities apart from those conducted by PVR, and our cash flows currently consist of distributions from PVR on the partner interests, including the IDRs, that we own. Accordingly, the discussion and analysis of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects the operating activities and results of operations of PVR.

Overview of PVR’s Business

PVR is a publicly traded Delaware limited partnership 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 its current limited partnership form and in its previous corporate form, PVR has managed coal properties since 1882. PVR currently conducts operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream. In 2010, PVR’s coal and natural resource management segment contributed $93.1 million, or 74%, to operating income, and PVR’s natural gas midstream segment contributed $32.8 million, or 26%, to operating income.

Coal and Natural Resource Segment

As of December 31, 2010, PVR owned or controlled approximately 804 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. PVR enters into long-term leases with experienced, third-party mine operators, providing them the right to mine PVR’s coal reserves in exchange for royalty payments. PVR actively works with its lessees to develop efficient methods to exploit its reserves and to maximize production from PVR’s properties. PVR does not operate any mines. In 2010, PVR’s lessees produced 34.5 million tons of coal from its properties and paid PVR coal royalties revenues of $130.3 million, for an average royalty per ton of $3.78. Approximately 80% of PVR’s coal royalties revenues in 2010 were derived from coal mined on its properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of PVR’s coal royalties revenues for the respective periods was derived from coal mined on PVR’s properties under leases containing fixed royalty rates that escalate annually.

Coal royalties are impacted by several factors that PVR 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 PVR’s lessees or their customers’ ability to use coal and which may require PVR, its lessees or its 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, PVR’s average royalty per ton may change as the majority of PVR’s lessees pay royalties based on the gross sales prices of the coal mined. However, most of PVR’s lessees’ coal is sold under contracts with a duration of one year or more; therefore, the underlying prices for PVR’s royalties are less susceptible to short-term volatility in coal prices and prices change primarily as PVR’s lessees’ long-term contracts are renegotiated.

PVR also earns 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 Segment

PVR’s natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of December 31, 2010, PVR owned and operated natural gas midstream assets located in Oklahoma, Pennsylvania and Texas, including six natural gas processing facilities having 400 MMcfd of total capacity and approximately 4,263 miles of natural gas gathering pipelines. PVR’s 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, PVR owns a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. PVR owns a 50% member interest in Crosspoint, a joint venture that gathers residue gas from our Crossroads Plant and transports it to market. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

In 2010, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 129.7 Bcf, or approximately 355 MMcfd. In 2010, 17%, 14%, 11% and 10% of PVR’s natural gas midstream segment revenues and 14%, 11%, 9% and 8% of our total consolidated revenues related to four of PVR’s natural gas midstream customers, Conoco Phillips Company, Tenaska Marketing Ventures, Targa Liquids Marketing and Trade and Williams NGL Marketing, LLC.

PVR continually seeks new supplies of natural gas to both offset the natural declines in production from the wells currently connected to its systems and to increase system throughput volumes. New natural gas supplies are obtained for all of PVR’s 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 2010, PVR’s natural gas midstream segment made aggregate capital expenditures of $104.5 million, primarily related to PVR’s expansion of the Panhandle System and Marcellus System due to growth opportunities in those areas. For a more detailed discussion of PVR’s acquisitions and investments, see “— Acquisitions and Investments.”

Key Developments

2010 Commodity Prices

The 2010 average commodity prices for coal, timber, natural gas, crude oil and NGLs increased from 2009 levels. NGLs refer to ethane, propane, iso butane, normal butane and pentane. The pricing of these commodities directly and indirectly drive PVR’s earnings.

Coal royalties, which accounted for 85% of the 2010 coal and natural resource management segment revenues, were eight percent higher as compared 2009. The increase was attributed to higher realized coal royalties per ton by region. Coal prices received by our lessees increased during 2010 as compared to 2009. Due to global demands and production issues, the most noticeable increase related to the sales price of metallurgical coal. Coal operators in the Appalachian Basin realized higher prices for metallurgical coal and sought ways to increase production.

Revenues, profitability and the future rate of growth of PVR’s natural gas midstream segment are highly dependent on market demand and prevailing NGL and natural gas prices. 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 PVR’s risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased. PVR’s derivative financial instruments include costless collars and swaps. Based upon current volumes, PVR has entered into hedging arrangements covering approximately 55% and 32% of its commodity-sensitive volumes in 2011 and 2012. Historically, PVR has targeted hedging 50% to 60% of its commodity-sensitive volumes covering a two-year period.

Acquisitions and Investments

In June 2010, PVR completed and began operating a natural gas gathering pipeline and compression facilities servicing a private firm’s Marcellus Shale natural gas production in Wyoming County, Pennsylvania. Construction and development of other gathering and compression facilities in other areas of the Marcellus Shale play are in progress. The facilities will provide gathering, compression and related services in Lycoming County and the first segment of the system began operations in February 2011.

PVR had two coal mineral acquisitions during 2010. PVR acquired approximately 10 million tons of Pittsburgh Seam coal reserves for $17.7 million in cash. This transaction supplements 40 million tons that PVR previously acquired in December 2002. In addition to the acquisition of the reserves, PVR received an increase in royalty of $1.00 per ton for the approximate 10 million tons of coal reserves remaining on the original transaction, plus a royalty on the newly-acquired reserves. In December, PVR purchased coal reserves in a greenfield project in Northern Appalachia. Their initial investment is $7 million in cash with contingency payments to be made as permitting and production progress.

In December 2010, PVR announced a definitive agreement to purchase certain mineral rights and associated oil and gas royalty interests in Kentucky and Tennessee for approximately $97.3 million, subject to closing adjustments. The mineral rights include approximately 102 million tons of coal reserves and resources, and royalty interest from approximately 158 oil and gas wells. There are currently 14 active producing underground and surface mines on the approximately 126,000 acres of mineral estates being acquired, with 10 principal coal lessees operating the mines. The coal is primarily steam coal that is consumed by major electric utilities and other industrial customers in the southeastern United States. On January 25, 2011 PVR completed the purchase of these assets.

Changes in Our Management

In connection with Penn Virginia’s (Penn Virginia Corporation NYSE: PVA) reduction of its limited partner interest in us, we implemented certain changes in management, as described below.

PVR Senior Notes Offering

In April 2010, PVR sold $300.0 million of unsecured senior notes due on April 15, 2018 (“PVR Senior Notes”), with an annual interest rate of 8.25% payable semi-annually in arrears on April 15 and October 15 of each year. The PVR Senior Notes were sold at par, equating to an effective yield to maturity of 8.25%.

Proposed Merger

The Merger Agreement is subject to customary closing conditions including, among other things, (i) approval by the affirmative vote of the holders of a majority of our common units outstanding and entitled to vote at a meeting of the holders of our common units, (ii) approval by the affirmative vote of the holders of a majority of PVR’s common units outstanding and entitled to vote at a meeting of the holders of PVR’s common units, (iii) receipt of applicable regulatory approvals, (iv) the effectiveness of a registration statement on Form S-4 with respect to the issuance of our common units in connection with the Merger, (v) receipt of certain tax opinions, (vi) approval for listing PVR’s common units to be issued in connection with the Merger on the New York Stock Exchange and (vii) the execution of PVR’s Fourth Amended and Restated Agreement of Limited Partnership.

Liquidity and Capital Resources

We rely exclusively on distributions from PVR to fund our general and administrative costs of being a public company. On an ongoing basis, PVR generally satisfies its working capital requirements and funds its capital expenditures using cash generated from its operations, borrowings under the PVR Revolver and proceeds from PVR debt and equity offerings. PVR funds its debt service obligations and distributions to unitholders solely using cash generated from its operations. PVR believes that the cash generated from its operations and its borrowing capacity will be sufficient to meet its working capital requirements and anticipated capital expenditures (other than major capital improvements or acquisitions). PVR believes that the cash generated from its operations will be sufficient to meet its scheduled debt payments under the PVR Revolver and its distribution payments. See Note 3 to the Consolidated Financial Statements for a tabular presentation of PVR’s distribution thresholds.

PVR’s ability to satisfy its obligations and planned expenditures will depend upon its 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 PVR’s control. If PVR’s plans or assumptions change or are inaccurate, or we make acquisition, PVR may need to raise additional capital. While global financial markets and economic conditions have been disrupted in the past, these conditions have improved more recently. However, PVR can give no assurance that it can raise additional capital in a cost-effective manner to meet these needs.

Cash Flows

The following table summarizes our statements of cash flows for the periods presented:


	Year Ended December 31,
	2010		2009		2008
Cash flows from operating activities:
Net income	$	64,187	$	62,911	$	102,598
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		103,257		100,066		41,565
Net changes in operating assets and liabilities		11,006		(4,763)		(6,976)

Net cash provided by operating activities		178,450		158,214		137,187
Net cash used in investing activities		(122,787)		(79,530)		(331,030)
Net cash provided by (used) in financing activities		(59,013)		(77,708)		181,678

Net increase (decrease) in cash and cash equivalents	$	(3,350)	$	976	$	(12,165)

Cash Flows From Operating Activities

Changes to our working capital and to our current ratio are largely affected by net cash provided by PVR’s operating activities. Net cash provided by PVR’s operating activities primarily came from the following sources:

PVR coal and natural resource management segment:

•

the collection of coal royalties;

•

the sale of standing timber;

•

the collection of coal transportation, or wheelage, fees;

•

distributions received from PVR’s equity investees; and

•

settlements from PVR’s interest rate swaps.

PVR natural gas midstream segment:

•

the collection of revenues from natural gas processing contracts with natural gas producers;

•

the collection of revenues from PVR’s natural gas marketing business; and

•

settlements from PVR’s natural gas midstream commodity derivatives.

PVR uses the cash provided by operating activities in the PVR coal and natural resource management segment and the PVR natural gas midstream segment in the following ways:

•

operating expenses, such as core-hole drilling costs and repairs and maintenance costs;

•

taxes other than income, such as severance and property taxes;

•

general and administrative expenses, such as office rentals, staffing costs and legal fees;

•

interest on debt service obligations;

•

capital expenditures;

•

repayments of borrowings; and

•

distributions to PVR’s partners.

On a stand-alone basis, our working capital and current ratio are primarily affected by cash distributions that we pay to our partners.

The overall increase in net cash provided by operating activities in 2010 as compared to 2009 was primarily driven by an increase in PVR’s natural gas midstream segment’s gross margin and higher coal royalties revenue. These increases were offset by cash derivative settlements, and higher operating and general and administrative costs, which were incurred as result of expanding operations and change in management structure.

The overall increase in net cash provided by operating activities in 2009 as compared to 2008 was driven by an increase in the PVR 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 in cash flows 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.

Cash Flows From Investing Activities

We do not own any property, plant and equipment on a stand-alone basis, nor did we have investing activities on a stand-alone basis for the years ended December 31, 2010, 2009 or 2008. Net cash used by PVR in investing activities were primarily for capital expenditures. The following table sets forth PVR’s capital expenditures programs, by segment, for the periods presented:


	Year Ended December 31,
	2010		2009		2008
Coal and natural resource management
Acquisitions	$	27,641	$	2,067	$	27,075
Other property and equipment expenditures		1,170		185		195

Total		28,811		2,252		27,270

Natural gas midstream
Acquisitions		-		27,514		259,417
Expansion capital expenditures		96,334		36,863		59,385
Other property and equipment expenditures		14,126		8,399		14,505

Total		110,460		72,776		333,307


Total capital expenditures	$	139,271	$	75,028	$	360,577

PVR’s 2010 capital expenditures consisted primarily of natural gas midstream expansion capital used to increase its natural gas gathering and operational footprint in its Panhandle and Marcellus Systems. PVR’s coal and natural resource management added to their reserve base in Northern Appalachia by amending an existing coal mineral lease and from a coal mineral acquisition. During 2011, PVR expects to invest approximately $140.0 million in internal growth capital.

PVR’s 2009 capital expenditures consisted primarily of a natural gas midstream plant acquisition, and expansion capital used to increase its natural gas processing capacity and operational footprint in its Panhandle System.

PVR’s 2008 capital expenditures were primarily discretionary in nature and included PVR’s 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. The PVR natural gas midstream segment also incurred approximately $14.5 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas.

Cash Flows From Financing Activities

During 2010, PVR amended its revolving credit facility, the PVR Revolver, to extend the maturity date and increase its borrowing capacity to $850 million. PVR also issued $300 million of PVR Senior Notes. The net proceeds from the sale of the PVR Senior Notes were used to repay borrowings under the PVR Revolver. Offsetting the repayment were funds drawn to finance our expansion growth capital. During 2009, PVR had net borrowings of $52.0 million under the PVR Revolver. These borrowings were used to fund its capital expenditure program. During 2008, PVR had net borrowings of $156.0 million primarily attributable to the PVR Revolver offset by the repayments of $63.3 million under the PVR Senior Unsecured Notes due 2013. In 2008, PVR also received net proceeds of $141.1 million from the sale of PVR’s common units in a public offering, which was comprised of net proceeds of $138.2 million from the sale of PVR common units to the public and $2.9 million in contributions from us to maintain its 2% general partner interest. This increase in outstanding common units also increased distributions paid to PVR’s partners.

In January 2011, PVR declared a $0.47 ($1.88 on an annualized basis) per unit quarterly distribution for the three months ended December 31, 2010 paid on February 14, 2011 to unitholders of record at the close of business on February 7, 2011.

Certain Non-GAAP Financial Measures

We use non-GAAP (Generally Accepted Accounting Principles) measures to evaluate our business and performance. None of these measures should be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP, or as indicators of our operating performance or liquidity.

The following tables present the calculation of distributable cash to PVG and reconciliation of net income attributable to PVG with respect to the periods presented:


Calculation of Non-GAAP “Distributable cash”	Year Ended December 31,
Distributable cash (a):	2010		2009		2008
Cash distributions to be received from PVR associated with:
2% general partner interest	$	2,004	$	1,988	$	1,903
General partner incentive distribution rights		24,325		24,140		22,067
PVR common units		36,896		36,824		36,236

Total cash to be received from PVR	$	63,225	$	62,952	$	60,206

Deduct: Net expenses of PVG on a stand-alone basis (b)		(4,271)		(2,304)		(1,902)
Cash reserve for working capital		2,002		(1,256)		(1,256)


Distributable cash (c)	$	60,956	$	59,392	$	57,048


Cash distributions to be paid to partners of PVG
To Penn Virginia Corporation		3,443		38,116		44,595
To public unitholders		57,513		21,276		12,453


Total cash distributions to be paid	$	60,956	$	59,392	$	57,048


Distribution per limited partner unit (paid in subsequent period)	$	1.56	$	1.52	$	1.46

Weighted-average units outstanding, basic and diluted		39,075		39,075		39,075

(a)	The distributable cash is presented on basis as to what is expected to be received from PVR cash distributions paid in the subsequent periods, for the respective years.

(b)	Net expenses of PVG, which represent general and administrative expenses, partially offset by interest income.

(c)

Distributable cash represents cash distributions received from PVR, minus our net expenses, minus cash reserve for working capital, or plus a use of cash reserves. Distributable cash is presented because we believe it is a useful adjunct to net income under GAAP. Distributable cash is a significant liquidity metric which is an indicator of our ability to pay quarterly cash distributions to our limited partners. Distributable cash is also the quantitative standard used throughout the investment community with respect to publicly traded partnerships. Distributable cash is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities, as an indicator of cash flows, as a measure of liquidity or as an alternative to net income.

Sources of Liquidity

Long-Term Debt

As of December 31, 2010, we had no outstanding borrowings other than the borrowings of PVR discussed below, which are included in our Consolidated Financial Statements.

PVR Revolver. On August 13, 2010, PVR entered into an amended and restated secured credit agreement increasing its borrowing capacity under the PVR Revolver to $850.0 million. As of December 31, 2010, net of outstanding indebtedness of $408.0 million and letters of credit of $1.6 million, PVR had remaining borrowing capacity of $440.4 million on the PVR Revolver. The PVR Revolver matures August 13, 2015. The PVR Revolver includes a $10 million sublimit for the issuance of letters of credit and a $25 million sublimit for swingline borrowings. PVR has an option, subject to the acceptance by the bank group, to increase the commitments under the PVR Revolver by up to an additional $200 million, to a total of $1.05 billion. The PVR Revolver is available to provide funds for general partnership purposes, including working capital, capital expenditures, acquisitions and quarterly distributions. In 2010, PVR incurred commitment fees of $1.2 million on the unused portion of the PVR Revolver. The interest rate under the PVR Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at base rate plus an applicable margin ranging from 1.25% to 2.25% if it selects the base rate indebtedness option under the PVR Revolver or at a rate derived from LIBOR plus an applicable margin ranging from 2.25% to 3.25% if it selects the LIBOR-based indebtedness option. The weighted average interest rate on borrowings outstanding under the PVR Revolver during 2010 was approximately 2.5%. PVR does not have a public rating for the PVR Revolver. As of December 31, 2010, PVR was in compliance with all of its covenants under the PVR Revolver.

PVR Senior Notes. In April 2010, PVR sold $300.0 million of PVR Senior Notes due on April 15, 2018 with an annual interest rate of 8.25%, which is payable semi-annually in arrears on April 15 and October 15 of each year. The PVR Senior Notes were sold at par, equating to an effective yield to maturity of approximately 8.25%. The net proceeds from the sale of the PVR Senior Notes of approximately $292.6 million, after deducting fees and expenses of approximately $7.4 million, were used to repay borrowings under the PVR Revolver. The PVR Senior Notes are senior to any subordinated indebtedness, and are effectively subordinated to all of PVR’s secured indebtedness including the PVR Revolver to the extent of the collateral securing that indebtedness. The obligations under the PVR Senior Notes are fully and unconditionally guaranteed by PVR’s current and future subsidiaries, which are also guarantors under the PVR Revolver.

PVR Interest Rate Swaps. PVR has entered into interest rate swaps, or PVR Interest Rate Swaps, to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver. The following table sets forth the PVR Interest Rate Swap positions at December 31, 2010 (in millions):


	Notional Amounts	Swap Interest Rates
Term	(in millions)	Pay	Receive
March 2010 - December 2011	$250.0	3.37%	LIBOR
December 2011 - December 2012	$100.0	2.09%	LIBOR

After considering the applicable margin of 2.50% in effect as of December 31, 2010 the total interest rate on the $250.0 million portion of the PVR Revolver borrowings covered by the PVR Interest Rate Swaps was 5.87% as of December 31, 2010.

Contractual Obligations

We did not have any contractual obligations as of December 31, 2010. The following table summarizes PVR’s contractual obligations as of December 31, 2010 (in thousands):


	Payments Due by Period
	Total		Less than 1 Year		1-3 Years		3-5 Years		More Than 5 years
Revolver	$	408,000	$	-	$	-	$	408,000	$	-
Senior notes		300,000		-		-		-		300,000
Asset retirement obligations (1)		2,172		-		369		-		1,803
Interest expense (2)		235,654		36,704		73,408		68,823		56,719
Derivatives (3)		24,623		19,516		5,107		-		-
Natural gas midstream activities (4)		26,151		12,628		8,541		4,982		-
Rental commitments (5)		27,436		4,094		8,148		7,853		7,341
Contingency payments (6)		2,765		-		837		1,017		911

Total contractual obligations (7)	$	1,026,801	$	72,942	$	96,410	$	490,675	$	366,774

(1)	The undiscounted balance was approximately $7.7 million at December 31, 2010.

(2)	Represents estimated interest payments that will be due under the PVR Revolver (which matures August 13, 2015) and PVR Senior Notes (which mature April 15, 2018).

(3)	Represents estimated payments PVR will make resulting from its commodity derivatives as well as the PVR 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 PVR subleases, or intends to sublease, to third parties.

(6)	Part of the purchase price for coal reserves in Northern Applachia includes undiscounted contingency payments of $5.2 million.

(7)	Total contractual obligations do not include anticipated 2011 PVR capital expenditures.

Part of the purchase price for the PVR Lone Star acquisition includes contingent payments of approximately $55.0 million. These contingency payments will be made by PVR if certain revenue targets are met before June 30, 2013. Because the outcome of these contingent payments is not determinable beyond a reasonable doubt, PVR did not accrue these contingent payments as a liability during the year ended December 31, 2010. Rather, once the revenue targets are met, the contingent payments will be recorded as an additional cost of the Lone Star acquisition.

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, 2010, the material off-balance sheet arrangements and transactions that PVR has 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. Neither we nor PVR had 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.

Results of Operations

Consolidated Review

The following table presents summary consolidated results for the periods presented:


	Year Ended December 31,
	2010		2009		2008
Revenues	$	864,136	$	656,704	$	881,580
Expenses		742,551		550,779		768,408

Operating income		121,585		105,925		113,172
Other income (expense) (1)		(57,398)		(43,014)		(10,574)

Net income	$	64,187	$	62,911	$	102,598
Net income attributable to noncontrolling interests		(27,043)		(25,032)		(49,912)

Net income attributable to Penn Virginia GP Holdings, L.P.	$	37,144	$	37,879	$	52,686

(1)	Other income (expense) includes interest expense, interest income and derivatives.

The following table presents certain summary financial information relating to our segments for the periods presented:


	PVR Coal and Natural Resource Management		PVR Natural Gas Midstream		Corporate and Other		Consolidated
For the Year Ended December 31, 2010:
Revenues	$	152,488	$	711,648	$	-	$	864,136
Cost of gas purchased		-		(577,813)		-		(577,813)
Operating costs and expenses		(28,483)		(56,041)		(4,314)		(88,838)
Depreciation, depletion and amortization		(30,873)		(45,027)		-		(75,900)

Operating income (loss)	$	93,132	$	32,767	$	(4,314)	$	121,585


For the Year Ended December 31, 2009:
Revenues	$	144,600	$	512,104	$	-	$	656,704
Cost of gas purchased		-		(406,583)		-		(406,583)
Operating costs and expenses		(24,231)		(45,842)		(2,377)		(72,450)
Impairment		(1,511)		-		-		(1,511)
Depreciation, depletion and amortization		(31,330)		(38,905)		-		(70,235)

Operating income (loss)	$	87,528	$	20,774	$	(2,377)	$	105,925


For the Year Ended December 31, 2008:
Revenues	$	153,327	$	728,253	$	-	$	881,580
Cost of gas purchased		-		(612,530)		-		(612,530)
Operating costs and expenses		(26,226)		(37,615)		(2,070)		(65,911)
Impairment		-		(31,801)		-		(31,801)
Depreciation, depletion and amortization		(30,805)		(27,361)		-		(58,166)

Operating income (loss)	$	96,296	$	18,946	$	(2,070)	$	113,172

PVR Coal and Natural Resource Management Segment

Year Ended December 31, 2010 Compared With Year Ended December 31, 2009

The following table sets forth a summary of certain financial and other data for the PVR coal and natural resource management segment and the percentage change for the periods presented:


	Year Ended December 31,				Favorable		%
	2010		2009		(Unfavorable)		Change
Financial Highlights
Revenues
Coal royalties	$	130,349	$	120,435		9,914		8%
Coal services		7,830		7,332		498		7%
Timber		6,261		5,726		535		9%
Oil and gas royalty		2,651		2,471		180		7%
Other		5,397		8,636		(3,239)		(38%)

Total revenues		152,488		144,600		7,888		5%


Expenses
Operating		11,437		9,692		(1,745)		(18%)
General and administrative		17,046		14,539		(2,507)		(17%)
Impairments		-		1,511		1,511		-
Depreciation, depletion and amortization		30,873		31,330		457		1%

Total expenses		59,356		57,072		(2,284)		(4%)


Operating income		93,132		87,528		5,604		6%


Other data

Coal royalty tons by region
Central Appalachia		18,207		18,319		(112)		(1%)
Northern Appalachia		3,965		3,786		179		5%
Illinois Basin		4,182		4,724		(542)		(11%)
San Juan Basin		8,158		7,501		657		9%

Total tons		34,512		34,330		182		1%


Coal royalties revenues by region
Central Appalachia		92,827		85,183		7,644		9%
Northern Appalachia		8,449		6,931		1,518		22%
Illinois Basin		11,208		12,420		(1,212)		(10%)
San Juan Basin		17,865		15,901		1,964		12%

Total royalties		130,349		120,435		9,914		8%


Coal royalties per ton by region ($/ton)
Central Appalachia	$	5.10	$	4.65	$	0.45		10%
Northern Appalachia		2.13		1.83		0.30		16%
Illinois Basin		2.68		2.63		0.05		2%
San Juan Basin		2.19		2.12		0.07		3%

Average royalties per ton	$	3.78	$	3.51	$	0.27		8%

Revenues

Coal royalties revenues increased due to the increase in the average coal royalty received per ton and a slight increase in tons produced. The coal markets improved in 2010 and remain fairly strong as the metallurgical coal markets continue to lead the way.

Coal production by PVR’s lessees increased slightly due to higher production in the San Juan Basin resulting from the startup of a second mine in 2009 and the addition of new equipment in 2010. Longwall mining activity increased production in the Northern Appalachia region. These increases were partially offset by a decline in production in the Illinois Basin region, which was due poor mining conditions at certain mines. Central Appalachia production remained relatively consistent with increased production in West Virginia as certain mines increased production was offset by decreased production in Virginia due to normal depletion and timing of when operators were mining on or off PVR’s properties.

Coal services revenues have increased due to the operating results of PVR’s joint venture providing fee-based coal-related infrastructure facilities to certain lessees.

Timber revenues increased due to higher sales prices received for harvested timber, partially offset by a lower harvest in 2010 resulting from weakened market conditions for furniture-grade wood and construction products. The average price received for timber increased 30% from $209 per Mbf in 2009 to $271 per Mbf in 2010.

The oil and gas royalty revenue increase was primarily attributable to higher natural gas prices in 2010. Realized prices received for natural gas increased 11% from $4.55 per Mcf in 2009 to $5.07 per Mcf in 2010.

Other revenues, which consisted primarily of wheelage fees, forfeiture income and management fees, decreased due to lower forfeiture income in 2010.

Expenses

Operating expenses increased due to increased coal royalties and timber related costs. Increased mining activity by PVR lessees from subleased properties in the Central Appalachia region increased coal royalties expenses. Mining activity on PVR subleased property fluctuates between periods due to the proximity of PVR property boundaries and other mineral owners. Weather and its effects on timber harvesting activities increased timber costs in 2010.

General and administrative expenses increased as a result of PVR’s change in management structure. Some shared costs with Penn Virginia have been replaced with direct costs and the change in ownership accelerated the vesting of equity compensation. Penn Virginia divested its interest in PVG during 2009 and 2010 and no longer owns any limited or general partner interest in PVR. Because the divestiture was considered a change of control under the long-term incentive plan, all unvested restricted and phantom units granted to employees performing services for the benefit of PVR were considered vested on the date the last PVG units were sold, June 7, 2010. Approximately $2.1 million was expensed related to the accelerated vesting for the Coal and Natural Resource Management segment. In addition to the change in management structure, costs related to acquisitions and due diligence have increased.

The $1.5 million impairment expense in 2009 was the result of a reduction in the value of an intangible asset. PVR tests 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 was reduced to zero.

DD&A expenses decreased slightly due to decreased timber depletion expense resulting from the lower harvest in 2010. The decrease is partially offset by an increase in coal depletion due to a shift in production mix of coal mined from our properties by our lessees. On a per ton basis, DD&A decreased from $0.91 per ton in 2009 to $0.89 per ton in 2010.

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 the PVR coal and natural resource management segment and the percentage change for the periods presented:


	Year Ended December 31,				Favorable		%
	2009		2008		(Unfavorable)		Change
Financial Highlights
Revenues
Coal 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%)


Expenses
Operating		9,692		12,940		3,248		25%
General and administrative		14,539		13,286		(1,253)		(9%)
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 data

Coal royalty tons by region
Central 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 tons		34,330		33,690		640		2%


Coal royalties revenues by region
Central 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%

Total royalties		120,435		122,834		(2,399)		(2%)


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%

Average royalties per ton	$	3.51	$	3.65	$	(0.14)		(4%)

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 PVR lessees increased slightly due to higher production in the San Juan Basin resulting from the startup 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 PVR lessees from subleased properties in the Central Appalachian region where PVR’s coal royalties expense is primarily incurred. Mining activity on PVR subleased property fluctuates between periods due to the proximity of PVR’s 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.

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.

PVR Natural Gas Midstream Segment

Year Ended December 31, 2010 Compared With Year Ended December 31, 2009

The following table sets forth a summary of certain financial and other data for the PVR natural gas midstream segment and the percentage change for the periods presented:


	Year Ended December 31,				Favorable
	2010		2009		(Unfavorable)		% Change
Financial Highlights
Revenues
Residue gas (1)	$	359,745	$	289,427	$	70,318		24%
Natural gas liquids		297,885		182,794		115,091		63%
Condensate		26,425		17,010		9,415		55%
Gathering, processing and transportation fees		18,109		15,558		2,551		16%

Total natural gas midstream revenues		702,164		504,789		197,375		39%
Equity earnings in equity investment		6,664		5,548		1,116		20%
Producer services		2,820		1,767		1,053		60%

Total revenues		711,648		512,104		199,544		39%


Expenses
Cost of gas purchased (1)		577,813		406,583		(171,230)		(42%)
Operating		32,806		29,096		(3,710)		(13%)
General and administrative		23,235		16,746		(6,489)		(39%)
Depreciation and amortization		45,027		38,905		(6,122)		(16%)

Total operating expenses		678,881		491,330		(187,551)		(38%)


Operating income	$	32,767	$	20,774	$	11,993		58%


Operating Statistics
System throughput volumes (MMcf)		129,703		121,335		8,368		7%
Daily throughput volumes (MMcfd)		355		332		23		7%

Gross margin	$	124,351	$	98,206	$	26,145		27%
Cash impact of derivatives		(1,860)		10,566		(12,426)		(118%)

Gross margin, adjusted for impact of derivatives	$	122,491	$	108,772	$	13,719		13%


Gross margin ($/Mcf)	$	0.96	$	0.81	$	0.15		19%
Cash impact of derivatives ($/Mcf)		(0.02)		0.09		(0.11)		(122%)

Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.94	$	0.90	$	0.04		4%

(1)

For the period of January 1 through June 7, 2010 and for the year ended December 31, 2009, PVR recorded $27.8 million and $72.5 million of natural gas midstream revenue and $27.8 million and $72.5 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG LP, a subsidiary of Penn Virginia Corporation and considered a related party up to June 7, 2010, and the subsequent sale of that gas to third parties. PVR took title to the gas prior to transporting it to third parties. These transactions do not impact the gross margin.

Gross Margin

Gross margin is the difference between PVR natural gas midstream revenues and PVR cost of midstream gas purchased. PVR 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. PVR 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 and higher fractionation, or frac spreads. System volumes also increased during 2010, but primarily on systems not entirely exposed to commodity pricing. These systems include a newly constructed system in the Marcellus region of Northeastern Pennsylvania (a fee-based gathering system) and Crossroads (a primarily fee-based gathering and processing system, which does have some exposure to percentage of proceeds contracts). The volumes at PVR’s Panhandle and Crossroads processing plants (inlet volumes) also increased

during 2010. Processing contracts on PVR’s Panhandle system are primarily gas purchase and percentage of proceeds contracts. Thus, PVR experienced a growth in our gross margin due higher commodity pricing and frac spreads.

Drilling activity during 2010 increased in areas which produce rich gas (natural gas containing significant NGLs). As a result, the number of wells drilled and connected to its Panhandle System increased. PVR’s expansion and acquisition activities throughout 2010 and 2009, especially in the Panhandle System, have alleviated pipeline pressure problems and allowed them to move more gas in this region to their processing plants. PVR has also increased its capital spending in growth areas, such as the Marcellus region. PVR’s new Marcellus Systems are primarily fee-based systems in a very active drilling area.

During 2010, PVR 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 PVR’s risk management strategy, they use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. See Note 8 to the Consolidated Financial Statements for a description of PVR derivatives program. On a per Mcf basis, adjusted for the impact of commodity derivative instruments, PVR’s gross margin increased in 2010 by $0.04, or 4%. The unfavorable impact of commodity derivatives is a result of changing commodity prices during 2010 and the expiration of older derivative instruments.

Revenues Other Than Gross Margin

Equity earnings in PVR equity investments increased as they continue to see increased volumes on the systems managed by these joint ventures. The increase at Crosspoint is directly related to the increased volumes at the Crossroads plant. Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin, also saw increased earnings due to mainline volume increases in the Powder River Basin.

Producer services revenues increased due to increased natural gas pricing and volumes moved by producers.

Expenses

Operating expenses increased due to PVR’s expanding footprint on existing and newly constructed systems. Increased costs include compressor rentals and labor costs.

General and administrative expenses increased as a result of our change in management structure. Some shared costs with Penn Virginia have been replaced with direct costs and the change in ownership accelerated the vesting of equity compensation. Penn Virginia divested its interest in PVG during 2009 and 2010 and no longer owns any limited or general partner interest in PVR. Because the divestiture was considered a change of control under the long-term incentive plan, all unvested restricted and phantom units granted to employees performing services for the benefit of PVR were considered vested on the date the last PVG units were sold, June 7, 2010. Approximately $3.5 million was expensed related to the accelerated vesting for the Natural Gas Midstream segment.

Depreciation and amortization expenses increased primarily due to capital expansions on the Panhandle and Marcellus Systems.

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 the PVR natural gas midstream segment and the percentage change for the periods presented:


	Year Ended December 31,				Favorable
	2009		2008		(Unfavorable)		% Change
Financial Highlights
Revenues
Residue gas (1)	$	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		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%)


Expenses
Cost of gas purchased (1)		406,583		612,530		205,947		34%
Operating		29,096		23,009		(6,087)		(26%)
General and administrative		16,746		14,606		(2,140)		(15%)
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 Statistics
System 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, 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. PVR took title to the gas prior to transporting it to third parties. These transactions do not impact the gross margin.

Gross Margin

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.

Drilling activities by producers central to PVR’s 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. PVR’s expansion and acquisition activity, especially in the Panhandle System, has alleviated pipeline pressures and allowed PVR to move all of its gas in this region to its processing plants. As noted above, in July 2009 PVR completed an acquisition of gas processing and residue pipeline facilities in western Oklahoma. The acquired assets included the 60 MMcfd Sweetwater plant. Additionally, PVR completed a 40 MMcfd processing plant expansion in its Spearman complex that was put into service on July 31, 2009. The acquired and expanded processing facilities increased PVR’s processing capacity in the Panhandle System to 260 MMcfd and overall processing capacity to 400 MMcfd. The increased processing capacity has allowed PVR 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, PVR 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 — PVR’s Contracts — PVR Natural Gas Midstream Segment,” for discussion of the types of contracts utilized by the PVR natural gas midstream segment. As part of PVR’s risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased. See Note 8 to the Consolidated Financial Statements for a description of PVR’s derivatives program. On a per Mcf basis, adjusted for the impact of PVR’s commodity derivative instruments, PVR’s 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, PVR 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 PVR’s 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 PVR’s 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 PVR’s 2008 acquisitions and plant expansions. PVR incurred a full year of salaries and benefits in 2009 compared with a partial year in 2008.

Impairment expense in 2008 was the result of a reduction in the value of goodwill. PVR tests 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 PVR’s market capitalization, reduced to zero all goodwill recorded in conjunction with acquisitions made by the PVR natural gas midstream segment in 2008 and prior years.

Depreciation and amortization expenses increased primarily due to PVR’s acquisitions, capital expansions on the Spearman and Sweetwater plants and new well connections in existing areas of operation.

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,
	2010		2009		2008
Operating income	$	121,585	$	105,925	$	113,172
Other income (expense)
Interest expense		(35,591)		(24,653)		(24,672)
Other		686		1,353		(2,739)
Derivatives		(22,493)		(19,714)		16,837

Net income	$	64,187	$	62,911	$	102,598

Interest Expense. PVR consolidated interest expense increased during 2010 due to the issuance of the PVR Senior Notes. The PVR Senior Notes bear an 8.25% interest rate, whereas the PVR Revolver’s annualized interest rates have been 2.5%, 2.7% and 4.2% for the years ended December 31, 2010, 2009 and 2008. The PVR Senior Notes were issued to pay down borrowing on the PVR Revolver and to increase the availability of funds under the PVR Revolver for acquisitions and growth capital needs. Non-cash interest expense has also increased over the three year period due to the issuance of the PVR Senior Notes and amendment fees on the PVR Revolver.

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 PVR Interest Rate Swaps.

Commodity markets are volatile, and as a result, PVR’s hedging activity results can vary significantly. PVR’s 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. PVR determines the fair values of its 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 PVR’s counterparties for derivatives in an asset position, and PVR’s own credit risk for derivatives in a liability position.

PVR’s derivative activity for the periods presented is summarized below:


	Year Ended December 31,
	2010		2009		2008
Interest Rate Swap unrealized derivative gain	$	1,000	$	3,260		-
Interest Rate Swap realized derivative loss		(8,215)		(7,566)		-
Interest Rate Swap other comprehensive income reclass		(715)		-		-
Natural gas midstream commodity unrealized derivative gain (loss)		(12,703)		(25,974)		55,303
Natural gas midstream commodity realized derivative gain (loss)		(1,860)		10,566		(38,466)

Total derivative gain (loss)	$	(22,493)	$	(19,714)	$	16,837

Noncontrolling Interests . Noncontrolling interests represents net income allocated to PVR’s limited partner units owned by the public. In 2010, 2009 and 2008, noncontrolling interests reduced our consolidated income from operations by $27.0 million, $25.0 million and $49.9 million.

Environmental Matters

PVR’s operations and those of its 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 PVR’s 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 PVR against any and all future environmental liabilities. PVR regularly visits its coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. PVR’s management believes that its operations and those of its lessees comply with existing laws and regulations and does not expect any material impact on its financial condition or results of operations.

As of December 31, 2010 and 2009, PVR’s environmental liabilities were $0.9 million and $1.0 million, which represents PVR’s best estimate of the liabilities as of those dates related to its coal and natural resource management and natural gas midstream businesses. PVR has 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 PVR’s 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 PVR’s lessees and the corresponding revenues from those sales. Since PVR does not operate any coal mines, it does not have access to actual production and revenues information until after the month of production. Therefore, PVR’s 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.

Natural Gas Midstream Gross Margin

PVR’s gross margin is the difference between its natural gas midstream revenues and its 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 PVR’s gas processing plants. We recognize revenues from the sale of NGLs and residue gas when PVR sells the NGLs and residue gas produced at its 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, PVR makes 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 PVR’s own geologists and outside consultants. PVR’s 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, PVR carries out core-hole drilling activities on its 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. PVR depletes timber using a methodology consistent with the units-of-production method, but that is based on the quantity of timber harvested. PVR determines 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 PVR retires or sells 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 12 to the Consolidated Financial Statements for a more detailed description of PVR’s intangible assets.

Derivative Activities

From time to time, PVR enters into derivative financial instruments to mitigate its exposure to natural gas, crude oil and NGL price volatility. The derivative financial instruments, which are placed with financial institutions that PVR believes 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 PVR’s derivative instruments are determined based on discounted cash flows derived from quoted forward prices. All derivative transactions are subject to PVR’s risk management policy, which has been reviewed and approved by the board of directors of PVR’s general partner.

During the first quarter of 2009, PVR discontinued hedge accounting for all of the PVR Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the PVR Interest Rate Swaps are recognized in the derivatives line item on our Consolidated Statements of Income. At December 31, 2009, a $0.4 million gain remained in accumulated other comprehensive income related to the PVR Interest Rate Swaps. The $0.4 million gain will be recognized in the derivatives line item as the PVR Interest Rate Swaps settle.

PVR recognizes changes in fair value in earnings in the derivatives line on the Consolidated Statements of Income. PVR has 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 8 to the Consolidated Financial Statements for a further description of PVR’s derivatives programs.

Impairment of Goodwill

Goodwill has been allocated to the PVR 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.

PVR 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 PVR’s market capitalization, reduced to zero all goodwill recorded in conjunction with acquisitions made by the PVR natural gas midstream segment in 2008 and prior years. This loss was recorded in the impairment line on our Consolidated Statements of Income. PVR’s goodwill balance remained at zero at December 31, 2009. See Note 11 to the Consolidated Financial Statements for a description of goodwill and the related impairment loss.

Equity Investments

PVR uses the equity method of accounting to account for its 25% member interest in Thunder Creek, as well as its investment in a 50% member interest in a coal handling joint venture and 50% member interest in Crosspoint, recording the initial investment at cost. Subsequently, the carrying amount of the investment is increased to reflect PVR’s share of income of the investee and capital contributions and is reduced to reflect its share of losses of the investee or distributions received from the investee as the joint ventures report them. PVR’s share of earnings or losses from Thunder Creek and is included in other revenues on our Consolidated Statements of Income. PVR’s share of earning or losses from the coal handling joint venture is included in coal services on our 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). PVR records this amortization over the life of the contracts acquired in the Thunder Creek acquisition and the life of the coal services contracts acquired in PVR’s acquisition of the coal handling joint venture.

Gain or Loss on Sale or Issuance of Subsidiary Units

We account for PVR equity issuances as sales of noncontrolling interests. For each PVR equity issuance, we have calculated a gain or loss in accordance with accounting standards for sales of stock by a subsidiary. These standards provide guidance on accounting for the effect of issuances of a subsidiary’s stock on the parent’s investment in that subsidiary. In some situations, these standards allow registrants to elect an accounting policy of recording gains or losses on issuances of stock by a subsidiary either in income or as a capital transaction. Accordingly, we have adopted a policy to record these gains and losses directly to partners’ capital.

New Accounting Standards

See Note 4 to the Consolidated Financial Statements for a description of recent accounting standards.

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

PVR is also indirectly exposed to the credit risk of its customers and lessees. If PVR’s customers or lessees become financially insolvent, they may not be able to continue to operate or meet their payment obligations.

As a result of PVR’s risk management activities as discussed below, we are also exposed to counterparty risk with financial institutions with whom PVR enters into these risk management positions. Sensitivity to these risks has heightened due to the state of the global economy, including financial and credit markets.

PVR has completed a number of acquisitions in recent years. See Note 5 to the Consolidated Financial Statements for a description of PVR’s material acquisitions. In conjunction with PVR’s accounting for these acquisitions, it was necessary for PVR 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 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

PVR’s 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 PVR’s natural gas midstream business. The derivative financial instruments are placed with major financial institutions that PVR believes are of acceptable credit risk. The fair values of PVR’s price risk management activities are significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

At December 31, 2010, PVR reported a net commodity derivative liability related to the PVR natural gas midstream segment of $15.9 million that is with five counterparties and is substantially concentrated with three of those counterparties. This concentration may impact PVR’s overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. PVR neither paid nor received collateral with respect to its derivative positions. No significant uncertainties related to the collectability of amounts owed to PVR exist with regard to these counterparties.

In 2010, PVR reported a net derivative loss of $22.5 million. Some of PVR’s 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 PVR 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, PVR recognized these deferred changes in fair value in revenues and cost of gas purchased in its Consolidated Statements of Income. As of December 31, 2008, no net losses remained in accumulated other comprehensive income related to PVR’s natural gas midstream commodity derivatives.

Because PVR no longer uses hedge accounting for its commodity derivatives, PVR recognizes changes in fair value in earnings currently in the derivatives line on the Consolidated Statements of Income. PVR has 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 PVR’s reported cash flows, although PVR’s 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.

The following table lists PVR’s commodity derivative agreements and their fair values as of December 31, 2010:


	Average Volume Per Day						Fair Value at December 31, 2010
					Weighted Average Price
			Swap Price		Put	Call
							(in thousands)
NGL - natural gasoline collar		(gallons)			(per gallon)
First quarter 2011 through fourth quarter 2011		95,000			$1.57	$1.94	$	(7,924)

Crude oil collar		(barrels)			(per barrel)
First quarter 2011 through fourth quarter 2011		400			$75.00	$98.50		(475)

Natural gas purchase swap		(MMBtu)		(MMBtu)
First quarter 2011 through fourth quarter 2011		6,500		$5.80				(2,909)

NGL - natural gasoline collar		(gallons)			(per gallon)
First quarter 2012 through fourth quarter 2012		54,000			$1.75	$2.02		(2,802)

Crude oil swap		(barrels)		(per barrel)
First quarter 2012 through fourth quarter 2012		600		$88.62				(1,106)

Natural gas purchase swap		(MMBtu)		(MMBtu)
First quarter 2012 through fourth quarter 2012		4,000		$5.195				(162)

Settlements to be paid in subsequent period								(561)

							$	(15,939)

PVR estimates that a $5.00 per barrel increase in the crude oil price would decrease the fair value of PVR’s crude oil collars by $1.5 million. PVR estimates that a $5.00 per barrel decrease in the crude oil price would increase the fair value of PVR’s crude oil collars by $1.4 million. PVR estimates that a $1.00 per MMBtu increase in the natural gas price would increase the fair value of PVR’s natural gas purchase swaps by $3.6 million. PVR estimates that a $1.00 per MMBtu decrease in the natural gas price would decrease the fair value of PVR’s natural gas purchase swaps by $3.6 million. PVR estimates that a $0.11 per gallon increase in the natural gasoline (a natural gas liquid, NGL) price would decrease the fair value of PVR’s natural gasoline collar by $4.6 million. PVR estimates that a $0.11 per gallon decrease in the natural gasoline price would increase the fair value of PVR’s natural gasoline collar by $4.4 million.

PVR estimates that, excluding the effects of derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, PVR’s natural gas midstream gross margin and operating income in 2011 would increase or decrease by $0.9 million. In addition, PVR estimates that for every $5.00 per barrel increase or decrease in the crude oil price, PVR’s natural gas midstream gross margin and operating income in 2011 would increase or decrease by $5.9 million. This assumes that natural gas prices, crude oil prices and inlet volumes remain constant at anticipated levels. These estimated changes in PVR’s gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk

As of December 31, 2010, PVR had $408.0 million of outstanding indebtedness under the PVR Revolver, which carries a variable interest rate throughout its term. PVR entered into the PVR Interest Rate Swaps to establish fixed interest rates on a portion of the outstanding indebtedness under the PVR Revolver. From March 2010 to December 2011, the notional amounts of the PVR Interest Rate Swaps total $250.0 million, or 61% of PVR’s outstanding indebtedness under the PVR Revolver as of December 31, 2010, with PVR 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 PVR Interest Rate Swaps total $100.0 million, or 25% of PVR’s outstanding indebtedness under the PVR Revolver as of December 31, 2010, with PVR 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. A 1% increase in short-term interest rates on the floating rate debt outstanding under the PVR Revolver (net of amounts fixed through the PVR Interest Rate Swaps) as of December 31, 2010 would cost PVR approximately $2.5 million in additional interest expense per year.

During the first quarter of 2009, PVR discontinued hedge accounting for all of the PVR Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the PVR Interest Rate Swaps are recognized in earnings currently. Therefore, PVR’s 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 8 to the Consolidated Financial Statements for a further description of PVR’s derivatives program.

Customer Credit Risk

PVR is exposed to the credit risk of its customers and lessees. Approximately 87%, or $84.7 million, of our consolidated accounts receivable at December 31, 2010 resulted from the PVR natural gas midstream segment and approximately 13%, or $13.1 million, resulted from the PVR coal and natural resource management segment. Approximately $38.0 million of the PVR natural gas midstream segment’s receivables at December 31, 2010 related to four customers, Conoco Phillips Company, Tenaska Marketing Ventures, Targa Liquids Marketing and Trade and Williams NGL Marketing, LLC. At December 31, 2010, 46% of the PVR natural gas midstream segment’s accounts receivable and 38% of our consolidated accounts receivable related to this PVR natural gas midstream customer. No significant uncertainties related to the collectability of amounts owed to PVR exist in regard to this natural gas midstream customer.

This customer concentration increases our exposure to credit risk on PVR’s receivables, since the financial insolvency of this customer could have a significant impact on PVR’s results of operations. If PVR’s 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 PVR’s trade accounts receivable are unsecured.

To mitigate the risks of nonperformance by its customers, PVR performs ongoing credit evaluations of its existing customers. PVR monitors individual customer payment capability in granting credit arrangements to new customers by performing credit evaluations, seeking to limit credit to amounts PVR believes the customers can pay, and maintaining reserves PVR believes are adequate to cover exposure for uncollectable accounts. As of December 31, 2010, no receivables were collateralized, and PVR had recorded a $0.2 million allowance for doubtful accounts in the PVR natural gas midstream segment.

Future Accounting Pronouncements

A consensus was reached regarding business combinations and the related disclosure of supplementary pro forma information. The consensus specifies that if a public entity presents comparative financial statements, the entity (acquirer) should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. It also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. This accounting standard is effective prospectively for 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, 2010.

Item 8 Financial Statements and Supplementary Data

PENN VIRGINIA GP HOLDINGS, L.P. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


		Page
Report of Independent Registered Public Accounting Firm		76
Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting		77
Consolidated Financial Statements		78
Notes to the Consolidated Financial Statements and Supplementary Data		82

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Penn Virginia GP Holdings, L.P.:

We have audited the accompanying consolidated balance sheets of Penn Virginia GP Holdings, L.P., and subsidiaries as of December 31, 2010 and 2009, 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, 2010. 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 GP Holdings, L.P. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, 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 GP Holdings, L.P.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 24, 2011, expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 24, 2011

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Penn Virginia GP Holdings L.P.:

We have audited Penn Virginia GP Holdings, L.P.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Penn Virginia GP Holdings, 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 GP Holdings, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, 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 GP Holdings, L.P. and subsidiaries as of December 31, 2010 and 2009, 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, 2010, and our report dated February 24, 2011 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

February 24, 2011

PENN VIRGINIA GP HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per unit amounts)


	Year Ended December 31,
	2010		2009		2008
Revenues
Natural gas midstream	$	702,164	$	504,789	$	720,002
Coal royalties		130,349		120,435		122,834
Coal services		7,830		7,332		7,355
Other		23,793		24,148		31,389

Total revenues		864,136		656,704		881,580


Expenses
Cost of gas purchased		577,813		406,583		612,530
Operating		44,243		38,788		35,949
General and administrative		44,595		33,662		29,962
Impairments		-		1,511		31,801
Depreciation, depletion and amortization		75,900		70,235		58,166

Total expenses		742,551		550,779		768,408


Operating income		121,585		105,925		113,172

Other income (expense)
Interest expense		(35,591)		(24,653)		(24,672)
Other		686		1,353		(2,739)
Derivatives		(22,493)		(19,714)		16,837


Net income		64,187		62,911		102,598
Less net income attributable to noncontrolling interests		(27,043)		(25,032)		(49,912)

Net income attributable to Penn Virginia GP Holdings, L.P.	$	37,144	$	37,879	$	52,686


Net income per unit attributable to Penn Virginia GP Holdings, L.P., basic and diluted	$	0.95	$	0.97	$	1.35

Weighted average number of units outstanding, basic and diluted		39,075		39,075		39,075

See accompanying notes to consolidated financial statements.

PENN VIRGINIA GP HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit amounts)


	December 31,		December 31,
	2010		2009
Assets
Current assets
Cash and cash equivalents	$	15,964	$	19,314
Accounts receivable, net of allowance for doubtful accounts		97,787		82,321
Derivative assets		-		1,331
Other current assets		5,900		4,816

Total current assets		119,651		107,782


Property, plant and equipment		1,295,227		1,162,070
Accumulated depreciation, depletion and amortization		(324,181)		(261,226)

Net property, plant and equipment		971,046		900,844


Equity investments		84,327		87,601
Intangible assets, net		76,950		83,741
Derivative assets		-		1,284
Other long-term assets		52,231		37,811


Total assets	$	1,304,205	$	1,219,063


Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities	$	103,845	$	71,233
Deferred income		4,360		3,839
Derivative liabilities		19,516		11,251

Total current liabilities		127,721		86,323


Deferred income		7,874		5,482
Other liabilities		20,853		17,270
Derivative liabilities		5,107		4,285
PVR senior notes		300,000		-
PVR revolving credit facility		408,000		620,100
Commitments and contingencies (see Note 18)
Partners’ capital
Penn Virginia GP Holdings, L.P. partners’ capital		213,805		249,696
Noncontrolling interests of subsidiaries		220,845		235,907

Total partners’ capital		434,650		485,603

Total liabilities and partners’ capital	$	1,304,205	$	1,219,063

See accompanying notes to consolidated financial statements.

Penn Virginia GP Holdings, L.P. and Subsidiaries

Consolidated Statements of Cash Flows

(in thousands)


	Twelve Months Ended December 31,
	2010		2009		2008
Cash flows from operating activities	$	64,187	$	62,911	$	102,598
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		75,900		70,235		58,166
Impairments		-		1,511		31,801
Commodity derivative contracts:
Total derivative losses (gains)		23,583		22,700		(11,357)
Cash receipts (payments) to settle derivatives		(10,075)		3,000		(38,466)
Non-cash interest expense		5,278		4,391		2,693
Non-cash unit-based compensation		6,172		1,769		-
Equity earnings, net of distributions received		3,274		(2,537)		(224)
Other		(875)		(1,003)		(1,048)
Changes in operating assets and liabilities
Accounts receivable		(15,462)		(8,387)		5,607
Accounts payable and accrued liabilities		20,600		4,614		(8,673)
Deferred income		2,913		(1,671)		1,145
Other asset and liabilities		2,955		681		(5,055)

Net cash provided by operating activities		178,450		158,214		137,187


Cash flows from investing activities		(24,876)		(29,580)		(260,376)
Acquisitions		(99,240)		(51,097)		(71,652)
Additions to property, plant and equipment		1,329		1,147		998

Other		(122,787)		(79,530)		(331,030)

Net cash used in investing activities

Cash flows from financing activities
Distributions to partners		(122,024)		(120,450)		(108,263)
Proceeds from issuance of senior notes		300,000		-		-
Proceeds from borrowings		158,000		132,000		453,800
Repayments of borrowings		(370,100)		(80,000)		(297,800)
Purchase of PVR limited partner units		(1,092)		-		-
Net proceeds from issuance of partners’ capital		-		-		138,141
Debt issuance costs and other		(23,797)		(9,258)		(4,200)

Net cash provided by (used in) financing activities		(59,013)		(77,708)		181,678


Net increase (decrease) in cash and cash equivalents		(3,350)		976		(12,165)
Cash and cash equivalents – beginning of period		19,314		18,338		30,503

Cash and cash equivalents – end of period	$	15,964	$	19,314	$	18,338


Supplemental disclosure:
Cash paid for interest	$	31,833	$	25,271	$	23,282

Noncash investing activities:
Issuance of PVR units for acquisition	$	-	$	-	$	15,171
PVG units given as consideration for acquisition	$	-	$	-	$	6,021
Other liabilities related to acquisitions	$	2,765	$	-	$	4,673

See accompanying notes to consolidated financial statements.

PENN VIRGINIA GP HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL AND COMPREHENSIVE INCOME

(in thousands)


					Accumulated Other Comprehensive Income (Loss)		Noncontrolling interests of subsidiaries
	Common Units				Accumulated Other Comprehensive Income (Loss)		Noncontrolling interests of subsidiaries		Total		Comprehensive Income (Loss)
Balance at December 31, 2007		39,075	$	227,776	$	(3,274)	$	156,957	$	381,459

Unit price adj for PVG units (1)		-		2,474		-		-		2,474
Gain on sale of subsidiary units		-		43,522		-		(43,522)		-
PVR issuance of units		-		-		-		157,108		157,108
Distributions paid		-		(54,704)		-		(53,559)		(108,263)
Net income		-		52,686		-		49,912		102,598		102,598
Other comprehensive income		-		-		1,062		2,085		3,147		3,147

Balance at December 31, 2008		39,075	$	271,754	$	(2,212)	$	268,981	$	538,523	$	105,745


Unit-based compensation		-		-		-		1,769		1,769
Distributions paid		-		(59,393)		-		(61,057)		(120,450)
Net income		-		37,879		-		25,032		62,911		62,911
Other comprehensive income		-		-		1,668		1,182		2,850		2,850

Balance at December 31, 2009		39,075	$	250,240	$	(544)	$	235,907	$	485,603	$	65,761


Unit-based compensation		-		-		-		6,172		6,172
Loss on issuance of subsidiary units		-		(1,508)		-		1,508		-
Purchase of subsidiary units				(11,665)		-		10,573		(1,092)
Distributions paid		-		(60,565)		-		(61,459)		(122,024)
Net income		-		37,144		-		27,043		64,187		64,187
Other comprehensive income		-		-		703		1,101		1,804		1,804


Balance at December 31, 2010		39,075	$	213,646	$	159	$	220,845	$	434,650	$	65,991

(1)	Represents the unit price adjustment for the PVG units purchased by PVR from Penn Virginia Corporation (“Penn Virginia”) and subsequently given as consideration in the acquisition of Lone Star Gathering, L.P. (“Lone Star”). See Note 5, “Acquisitions” for a description of this acquisition.

See accompanying notes to consolidated financial statements.

PENN VIRGINIA GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

Penn Virginia GP Holdings, L.P. (the “Partnership,” “we,” “us” or “our”) is a publicly traded Delaware limited partnership that owns three types of equity interests in Penn Virginia Resource Partners, L.P. (“PVR”), a publicly traded Delaware limited partnership. As of December 31, 2009, the equity interests are (1) a 2% general partner interest in PVR, which we hold through our 100% ownership interest in Penn Virginia Resource GP, LLC, PVR’s general partner, (2) all of the incentive distribution rights (“IDRs”) in PVR, which we hold through our 100% ownership interest in PVR’s general partner and (3) an approximately 37% limited partner interest in PVR. With the IDRs, we receive an increasing percentage of PVR’s quarterly distributions of available cash from operating surplus after certain levels of cash distributions have been achieved. Our only cash generating assets consist of our equity interests in PVR. Due to our control of the general partner of PVR, the financial results of PVR are included in our consolidated financial statements. However, PVR functions with a capital structure that is independent of ours, consisting of its own debt instruments and publicly traded common units.

2. Business of Penn Virginia Resource Partners, L.P.

PVR currently conducts operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream.

The PVR coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. PVR’s coal reserves are primarily located in Kentucky, Virginia, West Virginia, Illinois and New Mexico. PVR also earns 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. PVR also own a member interest in a joint venture providing end-user coal handling facilties.

The PVR natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. PVR owns and operates natural gas midstream assets located in Oklahoma and Texas. PVR’s natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In addition, PVR owns member interests in two midstream joint ventures that gather and transport natural gas. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

We, through our ownership of the general partner of PVR, manage the operations and activities of PVR. PVR’s general partner is liable for all of PVR’s debts (to the extent not paid from PVR’s assets), except for indebtedness or other obligations that are made specifically non-recourse to us.

We do not receive any management fee or other compensation for the management of PVR. We and our affiliates are reimbursed for expenses incurred on PVR’s behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to PVR and all other expenses necessary or appropriate to conduct the business of, and allocable to, PVR. PVR’s partnership agreement provides that PVR’s general partner will determine the expenses that are allocable to PVR in any reasonable manner determined by PVR in its sole discretion.

In connection with Penn Virginia’s (Penn Virginia Corporation NYSE: PVA) reduction of its limited partner interest in us, we implemented certain changes in management, as described below.

the PVG special meeting, the proxies received from unitholders totaled 25,353,727 million units, or 64.88% of all PVG units outstanding and entitled to vote. Of the total PVG units outstanding and entitled to vote, proxies representing 39.77% of the PVG units were in favor of the merger proposal. The approval of the Merger Agreement and related transactions requires the affirmative vote of holders of a majority of all units outstanding and entitled to vote. The reconvened PVG special meeting will be held at The Villanova University Conference Center, 601 County Line Road, Radnor, Pennsylvania 19087 on March 9, 2011 at 10:00 AM local time.

3. Unit Ownership Interests in Penn Virginia Resource Partners, L.P.

PVR makes quarterly cash distributions of its available cash, generally defined as all of PVR’s cash and cash equivalents on hand at the end of each quarter less cash reserves established by the general partner at its sole discretion. According to PVR’s partnership agreement, PVR’s general partner receives incremental incentive cash distributions if cash distributions exceed certain target thresholds as follows:


	Unitholders		General Partner
Quarterly 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 PVR during the years ended December 31, 2010, 2009 and 2008:


	Year Ended December 31,
	2010		2009		2008
Limited partner units	$	97,889	$	97,382	$	89,207
General partner interest (2%)		1,999		1,988		1,820
Incentive distribution rights		24,267		24,140		20,049
Phantom units		440		499		-

Total cash distributions paid	$	124,595	$	124,009	$	111,076


Total cash distributions paid per limited partner unit	$	1.88	$	1.88	$	1.82

On February 14, 2011, PVR paid a $0.47 per unit quarterly distribution to unitholders of record on February 7, 2010. This distribution was unchanged from the previous distribution paid on November 12, 2010.

In conjunction with our initial public offering in December 2006, Penn Virginia contributed its general partner interest, including its IDRs, and most of its limited partner interest in PVR to us in exchange for the general partner interest and a limited partner interest in us. We also purchased additional common units and Class B units of PVR with the proceeds of our initial public offering. We received total distributions from PVR of $63.1 million, $63.0 million and $57.5 million in 2010, 2009 and 2008, allocated among our limited partner interest, general partner interest and IDRs in PVR as shown in the following table:


	Year Ended December 31,
	2010		2009		2008
Limited partner units	$	36,872	$	36,824	$	35,648
General partner interest (2%)		1,999		1,988		1,820
IDRs		24,267		24,140		20,049

Total cash distributions paid	$	63,138	$	62,952	$	57,517

4. Summary of Significant Accounting Policies

Basis of Presentation

Unless otherwise indicated, for the purposes of our consolidated financial statements, the “Partnership,” “we,” “us” or “our” refers to Penn Virginia GP Holdings, L.P. and subsidiaries. References to the “parent company” are intended to mean Penn Virginia GP Holdings, L.P. individually as the parent company and not on a consolidated basis.

In accordance with generally accepted accounting principles, the distribution of net assets from the parent company to affiliates of Penn Virginia in December 2006 was accounted for as a reorganization of entities under common control in a

manner similar to a pooling of interests. As a result, our historical consolidated financial information presented in this Annual Report on Form 10-K for periods prior to our receipt of contributions from Penn Virginia has been presented using the consolidated financial information of Penn Virginia Resource GP, LLC and subsidiaries, which was our predecessor company.

The presentation of such predecessor consolidated financial information assumes that the historical ownership interests in PVR held by affiliates of Penn Virginia (prior to the contribution of net assets in December 2006) were owned by the parent company. This method of presentation is substantially on the same basis that our consolidated results of operations and financial position have been presented since the contribution of net assets from affiliates of Penn Virginia.

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 member interests in three joint ventures that are accounting for under the equity method of accounting and more fully described in Note 10 to the Consolidated Financial Statements. Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. These statements involve the use of estimates and judgments where appropriate. Certain reclassifications have been made to conform to the current period’s presentation.

Certain reclassifications have been made to conform to the current period’s presentation of taxes other than income. Historically, we reported taxes other than income as a separate component of expenses. We have reclassified the components of taxes other than income, which primarily related to property taxes and payroll taxes, to operating expense and general and administrative expense for all periods presented.

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, but disclosure is required in the Notes to Consolidated Financial Statements. See Note 21 to the Consolidated Financial Statements.

All dollar amounts presented in the tables to these Notes are in thousands unless otherwise indicated.

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.

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 PVR’s ownership in coal fee mineral interests, PVR’s 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 Life
Gathering systems		15 – 20 years
Compressor stations		5 – 15 years
Processing plants		15 years
Other property and equipment		3 – 20 years

timber harvested. PVR determines 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 PVR retires or sells an asset, we remove its cost and related accumulated depreciation and amortization from our consolidated balance sheet. 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 on an accelerated or straight-line basis 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 indicate that the carrying amounts may not be recoverable. See Note 12, “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 asset retirement obligation (“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 13, “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 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 PVR’s 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 PVR coal and natural resource management and PVR natural gas midstream segments have completed a number of acquisitions in recent years. See Note 5, “Acquisitions,” for a description of the 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.

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 its 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. See Note 11, “Goodwill” for a description of goodwill and the related impairment loss.

Equity Investments

PVR uses the equity method of accounting to account for its 25% member interest in Thunder Creek, as well as its investment in a 50% member interest investment in a coal handling joint venture and the Crosspoint gas gathering line, recording the initial investment at cost. Subsequently, the carrying amounts of the investment are increased to reflect PVR’s share of income of the investees and capital contributions and are reduced to reflect its share of losses of the investees or distributions received from the investees as the joint ventures report them. PVR’s share of earnings or losses from Thunder Creek and Crosspoint is included in other revenues on the consolidated statements of income, and our share of earnings and losses from the coal handling 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 PVR’s portion of the underlying equity in net assets. PVR records 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

PVR leases a portion of its 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. PVR evaluates 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 PVR 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 87% of our consolidated accounts receivable at December 31, 2010 resulted from the PVR natural gas midstream segment and approximately 13% resulted from the PVR coal and natural resource management segment. Approximately 46% of the PVR natural gas midstream segment’s accounts receivables and 38% of our consolidated accounts receivable at December 31, 2010 related to four natural gas midstream customers. As of December 31, 2010, no receivables were collateralized, and we had recorded a $0.2 million allowance for doubtful accounts in the PVR natural gas midstream segment. No significant uncertainties related to the collectability of amounts owed to PVR exist in regard to these PVR natural gas midstream customers. These customer concentrations increase our exposure to credit risk on PVR’s receivables, since the financial insolvency of any of these customers 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 PVR sells the NGLs and residue gas produced at its 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 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 PVR’s lessees and the corresponding revenues from those sales. Since PVR does not operate any coal mines, PVR does 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 PVR’s 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. Other liabilities on the balance sheet also include deferred unearned income from a coal services facility lease, which is recognized as other income as it is earned.

Coal Services Revenues . We recognize coal services revenues when lessees use PVR’s facilities for the processing, loading and/or transportation of coal. Coal services revenues consist of fees collected from lessees for the use of PVR’s loadout facility, coal preparation plants and dock loading facility. We also include equity earnings of PVR’s coal handling joint venture in coal services revenues. We recognize our share of income or losses from PVR’s investment in a coal handling joint venture as the joint venture reports them to PVR.

Derivative Instruments

From time to time, PVR enters into derivative financial instruments to mitigate its exposure to natural gas, crude oil and NGL price volatility. The derivative financial instruments, which are placed with financial institutions that PVR 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 PVR’s 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 PVR’s general partner. PVR does not use hedge accounting for commodity derivatives; thus, the open positions are recorded at fair value with the change in value recorded to earnings.

Because PVR no longer applies 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.

PVR has also entered into interest rate swaps agreements (the “PVR Interest Rate Swaps”) to mitigate its exposure to debt interest expense. During the first quarter of 2009, PVR discontinued hedge accounting for all of the PVR Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the PVR Interest Rate Swaps are recognized in the derivatives line item on the consolidated statements of income. During the year ended December 31, 2010, PVR reclassified a total of $1.8 million from accumulated other comprehensive income (“AOCI”) to earnings related the PVR Interest Rate Swaps. At December 31, 2010, a $0.4 million gain remained in AOCI and will be recognized in the derivatives line as the PVR Interest Rate Swaps settle. See Note 8, “Derivative Instruments,” for a description of PVR’s derivative program.

Income Taxes

As a partnership, we are not a taxable entity and have no federal income tax liability. Penn Virginia Resource GP, LLC is a limited liability company which is treated as a partnership for federal income tax purposes. Therefore, Penn Virginia Resource GP, LLC is not a taxable entity and generally incurs no federal income tax liability. PVR is a partnership and is also not a taxable entity and has no federal income tax liability. The taxable income or losses of the Partnership and PVR are includable in the federal and state income tax returns of our and their 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 and PVR’s partnership agreements.

Net Income per Limited Partner Unit

Basic and diluted net income per limited partner unit is determined by dividing net income by the weighted average number of outstanding common units. At December 31, 2010, there were no dilutive units.

Noncontrolling Interests

Effective January 1, 2009, we adopted the new accounting standard on noncontrolling interests. This standard requires that the noncontrolling interests in PVR be reported on our consolidated balance sheets as a separate item within partners’

capital. Net income attributable to the noncontrolling interests in PVR is separately presented on the face of our consolidated statements of income. Our consolidated financial statements have been retroactively adjusted to reflect the adoption of this standard. Comprehensive income attributable to the noncontrolling interests in PVR is separately presented in our schedule of comprehensive income; see Note 19, “Comprehensive Income”. This standard also requires that gains from the sales of subsidiary units be recorded directly to partners’ capital. If we sell sufficient controlling interests in our subsidiaries to require deconsolidation of those subsidiaries, then we expect to record a gain or loss on our consolidated statements of income.

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 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 recognize compensation expense over the vesting period of the awards.

The general partner of PVR has a long-term incentive plan that permits the grant of awards to directors and employees of PVR’s general partner and employees of its affiliates who perform services for PVR. Awards under the PVR long-term incentive plan can be in the form of PVR common units, restricted PVR units, PVR unit options, phantom PVR units and deferred PVR common units. The PVR long-term incentive plan is administered by the compensation and benefits committee of the board of directors of PVR’s general partner. PVR reimburses its general partner for payments made pursuant to the PVR long-term incentive plan.

We and PVR account for unit-based compensation in accordance with authoritative accounting literature related to share-based payments, which establishes standards for transactions in which an entity exchanges its equity instruments for goods and services. This standard requires us and PVR 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 17, “Unit-Based Payments.”

Gain or Loss on Sale or Issuance of Subsidiary Units

New Accounting Standards

In January 2010, an accounting standards update (“ASU”) was issued that amends certain disclosure requirements. This ASU provides for additional financial instrument fair value disclosures for transfers in and out of Levels I and II and for activity in Level III. This ASU also clarifies certain other existing disclosure requirements including level of desegregation and disclosures around inputs and valuation techniques. This ASU is effective for annual or interim reporting periods beginning after December 15, 2009, except for the requirement to provide the Level III activity for purchases, sales, issuances, and settlements on a gross basis. That requirement is effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The amendments do not require disclosures for earlier periods presented for comparative purposes at initial adoption. The adoption of this amendment did not impact on our financial statements, but may cause us to enhance future disclosures around derivative fair value disclosures.

5. Acquisitions

In the following paragraphs, all references to coal, crude oil and natural gas reserves and acreage acquired are unaudited. The factors PVR 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, PVR 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 PVR natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin.

PVR 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 PVR’s revolving credit facility (the “PVR Revolver”), 2,009,995 of our common units (which PVR purchased from two subsidiaries of Penn Virginia for $61.8 million) and 542,610 newly issued PVR 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 PVR’s 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:


Cash consideration paid for Lone Star	$	81,125
Fair value of PVG common units given as consideration for Lone Star		68,021
Fair value of PVR common units issued and given as consideration for Lone Star		15,171
Contingency payment		4,673

Total purchase price	$	168,990


Fair value of assets acquired:
Property and equipment	$	88,596
Intangible assets		69,200
Goodwill		11,194

Fair value of assets acquired	$	168,990

The purchase price included approximately $11.2 million of goodwill, all of which was allocated to the PVR natural gas midstream segment. A significant factor that contributed to the recognition of goodwill includes the ability to acquire an established business on the western border of the expanding Barnett Shale play in the 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 11, “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 12, “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 PVR’s 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):


	December 31,
	2008
Revenues	$	885,147
Net income	$	93,363
Net income per limited partner unit, basic & diluted	$	1.41

Other Miscellaneous Acquisitions

In 2010 PVR completed two acquisitions of coal mineral reserves for approximately $24.7 million. In 2009 PVR completed two natural gas midstream acquisitions for approximately $27.5 million. Funding for all these transactions was provided by borrowing under the PVR Revolver. The pro forma result for the years ended December 31, 2010 and 2009 for the above acquisitions did not materially change the historical results for those periods.

6. PVR Unit Offering

In May 2008, PVR issued 5.15 million common units representing limited partner interests in PVR in a registered public offering and received $138.2 million in net proceeds. We made contributions to PVR of $2.9 million to maintain

our indirect 2% general partner interest. PVR used the net proceeds to repay a portion of its borrowings under the PVR Revolver.

7. Fair Value Measurement of Financial Instruments

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, 2010, the carrying values of all these financial instruments, except PVR’s long-term debt with fixed interest rates, approximated their fair value. The fair value of PVR’s floating-rate debt approximates the carrying amount because the interest rates paid are based on short-term maturities. The fair value of PVR’s fixed-rate debt is estimated based on the published market prices for the same or similar issues. As of December 31, 2010, the fair value of PVR’s fixed-rate debt was $310.5 million.

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

PVR has completed a number of acquisitions in recent years. See Note 5, “Acquisitions,” for a description of our coal and natural resource management and natural gas midstream segment’s material acquisitions. In conjunction with PVR’s 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 in 2010, and the ones requiring the most judgment, involved the estimated fair values of coal minerals and the timing of permitting and production activities. The coal mineral acquisitions included nonfinancial assets that were measured at fair value during 2010. The total purchase price allocation was $9.8 million. Regarding the coal mineral acquisition, which included contingency payments, the contingent purchase consideration was recorded at its anticipated fair value on the date of acquisition. Any difference between the actual contingent purchase consideration and the original fair value estimate is recorded in earning when the contingency is eventually resolved. There are three triggering events that can impact contingent purchase consideration. Outside appraisers conducted due diligence with PVR’s Manager of Development for West Virginia Properties, as well as outside parties, to assess the prospects of the various trigger events of permitting, and thereafter milestones of slope and shaft completion and eventually tonnage production rates being realized. Based on discussions with management, and considering that this is a deep mining permit and not the more currently troubled permitting process of mountaintop mining, a success factor of 80% probability was assigned to the permitted phase of purchase consideration. Given that the other two triggering events are clearly linked to the successful permitting event, an 80% factor was applied as well.

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 2010:


			Fair Value Measurements Using
Description	Fair Value Measurements at December 31, 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Northern Appalachia coal reserves	$	9,765	$	-	$	-	$	9,765

Total	$	9,765	$	-	$	-	$	9,765

In conjunction with PVR’s 2009 accounting for acquisitions, it was necessary for it 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 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 4, “Summary of Significant Accounting Policies” for a description of the inputs and techniques used to derive ARO fair values. 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:


			Fair Value Measurements, Using
Description	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	$	-	$	-	$	22,772
Sweetwater 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 include PVR’s derivative financial instruments by categories as of December 31, 2010:


			Fair Value Measurements at December 31, 2010, Using
Description	Fair Value Measurements at December 31, 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Interest rate swap liabilities - current	$	(7,647)		-	$	(7,647)		-
Interest rate swap liabilities - noncurrent		(1,037)		-		(1,037)		-
Commodity derivative liabilities - current		(11,869)		-		(11,869)		-
Commodity derivative liabilities - noncurrent		(4,070)		-		(4,070)		-

Total	$	(24,623)	$	-	$	(24,623)	$	-


			Fair Value Measurements at December 31, 2009, Using
Description	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)	$	-

The values of both the PVR Interest Rate Swap and commodity derivatives are presented in the derivative assets and derivative liabilities line items on the consolidated balance sheets.

See Note 8, “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: PVR’s natural gas midstream segment utilizes collar and swap derivative contracts to hedge against the variability in the frac spread. PVR determines the fair values of its commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities. This is a level 2 input. PVR generally uses the income approach, using valuation techniques that convert future cash flows to a single discounted value. See Note 8, “Derivative Instruments.”

•

Interest rate swaps: PVR has entered into the PVR Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver. PVR uses an income approach using valuation techniques that connect future cash flows to a single discounted value. PVR estimates 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 8, “Derivative Instruments.”

8. Derivative Instruments

PVR Natural Gas Midstream Segment Commodity Derivatives

PVR utilizes costless collars and swap derivative contracts to hedge against the variability in cash flows associated with its anticipated natural gas midstream revenues and cost of midstream gas purchased. PVR also utilizes collar derivative contracts to hedge against the variability in its frac spread. PVR’s frac spread is the spread between the purchase price for the natural gas purchase from producers and the sale price for NGLs that is sold after processing. PVR hedges against the variability in its 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. PVR is 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 PVR is required to make a payment to the counterparty if the settlement price is less than the swap price for such contract.

PVR determines the fair values of its derivative agreements by discounting the cash flows based on quoted forward prices for the respective commodities as of December 31, 2010, using discount rates adjusted for the credit risk of the counterparties if the derivative is in an asset position and its own credit risk for derivatives in a liability position. The following table sets forth our positions as of December 31, 2010 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:


	Average Volume Per Day								Fair Value at December 31, 2010
					Weighted Average Price
			Swap Price		Put		Call
									(in thousands)
NGL - natural gasoline collar		(gallons)				(per gallon)
First quarter 2011 through fourth quarter 2011		95,000				$1.57		$1.94	$	(7,924)

Crude oil collar		(barrels)				(per barrel)
First quarter 2011 through fourth quarter 2011		400				$75.00		$98.50		(475)

Natural gas purchase swap		(MMBtu)		(MMBtu)
First quarter 2011 through fourth quarter 2011		6,500		$5.80						(2,909)

NGL - natural gasoline collar		(gallons)				(per gallon)
First quarter 2012 through fourth quarter 2012		54,000				$1.75		$2.02		(2,802)

Crude oil swap		(barrels)		(per barrel)
First quarter 2012 through fourth quarter 2012		600		$88.62						(1,106)

Natural gas purchase swap		(MMBtu)		(MMBtu)
First quarter 2012 through fourth quarter 2012		4,000		$5.195						(162)

Settlements to be paid in subsequent period										(561)

At December 31, 2010, PVR reported a net derivative liability related to the natural gas midstream segment of $15.9 million. No amounts remain in AOCI related to derivatives in the natural gas midstream segment for which PVR discontinued hedge accounting in 2006, and no amounts have been recorded to AOCI related to the derivative positions as of December 31, 2010.

PVR Interest Rate Swaps

PVR has entered into the PVR Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver. From March 2010 to December 2011, the notional amounts of the PVR Interest Rate Swaps total $250.0 million with PVR 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 London Interbank Offered Rate (“LIBOR”). From December 2011 to December 2012, the notional amounts of the PVR Interest Rate Swaps total $100.0 million, with PVR 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 PVR Interest Rate Swaps have been entered into with seven financial institution counterparties, with no

counterparty having more than 30% of the open positions. The following table sets forth the positions as of December 31, 2010 for the PVR Interest Rate Swaps:


	Notional Amounts	Swap Interest Rates		Fair Value at
Term	(in millions)	Pay	Receive	December 31, 2010
March 2010 - December 2011	$250.0	3.37%	LIBOR	$	(7,647)
December 2011 - December 2012	$100.0	2.09%	LIBOR	$	(1,037)

During the first quarter of 2009, PVR discontinued hedge accounting for all of the PVR Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the PVR Interest Rate Swaps have been recognized in the derivatives line item on our consolidated statements of income. At December 31, 2009, a $0.4 million gain remained in AOCI related to the PVR Interest Rate Swaps. The $0.4 million loss will be recognized in the derivatives line as the original forecasted interest payments occur.

PVR reported a (i) net derivative liability of $8.7 million at December 31, 2010 and (ii) gain in AOCI of $0.4 million at December 31, 2010 related to the PVR Interest Rate Swaps. In connection with periodic settlements, PVR recognized $1.8 million of net hedging losses in interest expense and the derivatives line in the year ended December 31, 2010. Based upon future interest rate curves at December 31, 2010, PVR expects to realize $7.6 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.

Financial Statement Impact of Derivatives

The following table summarizes the effects of PVR’s derivative activities, as well as the location of the gains and losses, on our consolidated statements of income for the periods presented:


	Location of gain (loss)
	on derivatives recognized	Year Ended December 31,
	in income	2010		2009		2008
Derivatives not designated as hedging instruments:
Commodity contracts (1)	Natural gas midstream revenues	$	-	$	-	$	(8,219)
Commodity contracts (1)	Cost of midstream gas purchased		-		-		2,739
Interest rate contracts (2)	Interest expense		(1,090)		(3,356)		(1,706)
Interest rate contracts	Derivatives		(7,930)		(4,306)		(8,635)
Commodity contracts	Derivatives		(14,563)		(15,408)		25,472

Total decrease in net income resulting from derivatives		$	(23,583)	$	(23,070)	$	9,651

Realized and unrealized derivative impact:
Cash received (paid) for commodity and interest rate contract settlements	Derivatives	$	(10,075)	$	3,000	$	(38,466)
Cash paid for interest rate contract settlements	Interest expense		-		(370)		(503)
Unrealized derivative losses (3)			(13,508)		(25,700)		48,620

Total decrease in net income resulting from derivatives		$	(23,583)	$	(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 PVR Interest Rate Swap amounts reclassified out of AOCI and into earnings. During 2008 and 2009 PVR discontinued hedge accounting for various PVR Interest Rate Swaps at different times. By the first quarter of 2009 PVR discontinued hedge accounting for the remaining PVR Interest Rate Swaps. During 2009 and 2008 PVR reclassified $0.4 million and $0.5 million out of AOCI relating to actual hedge settlements accounted for under hedge accounting. During 2010, 2009 and 2008 we reclassified $1.8 million, $ 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.

The following table summarizes the fair value of PVR’s derivative instruments, as well as the locations of these instruments on our consolidated balance sheets as for the periods presented:


		Fair values as of December 31, 2010				Fair values as of December 31, 2009
	Balance Sheet Location	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Derivatives not designated as hedging instruments:
Interest rate contracts (1)	Derivative assets/liabilities - current	$	-	$	7,647	$	-	$	7,710
Interest rate contracts (1)	Derivative assets/liabilities - noncurrent		-		1,037		1,266		3,241
Commodity contracts	Derivative assets/liabilities - current		-		11,869		1,331		3,541
Commodity contracts	Derivative assets/liabilities - noncurrent		-		4,070		18		1,044

Total derivatives not designated as hedging instruments		$	-	$	24,623	$	2,615	$	15,536

Total fair value of derivative instruments		$	-	$	24,623	$	2,615	$	15,536

(1)

During 2009 and 2008 PVR discontinued hedge accounting for various PVR Interest Rate Swaps at different times. By the first quarter of 2009 PVR discontinued hedge accounting for the remaining PVR Interest Rate Swaps. For presentation purposes all PVR Interest Rate Swaps are shown as not designated as hedging instruments for periods presented, 2010 and 2009, reflecting their accounting status as of December 31, 2010.

See Note 7, “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 PVR Interest Rate Swaps on PVR’s total interest expense for the periods presented:


	Year Ended December 31,
Source	2010		2009		2008
Interest on Borrowings	$	34,892	$	21,523	$	23,641
Interest rate swaps		1,090		3,356		1,706
Capitalized interest (1)		(391)		(226)		(675)

Total interest expense	$	35,591	$	24,653	$	24,672

(1)	Capitalized interest was primarily related to the construction of PVR’s natural gas gathering facilities.

The effects of derivative gains (losses), cash settlements of PVR’s natural gas midstream commodity derivatives and cash settlements of the PVR Interest Rate Swaps are reported as adjustments to reconcile net income to net cash provided by operating activities on our consolidated statements of cash flows. PVR no longer utilizes hedge accounting treatment for commodity or interest rate swap derivatives. These items are recorded in the “Total derivative losses (gains)” and “Cash receipts (payments) to settlement derivatives” lines on the consolidated statements of cash flows.

The above hedging activity represents cash flow hedges. As of December 31, 2010, neither PVR nor we owned derivative instruments that were classified as fair value hedges or trading securities. In addition, as of December 31, 2010, neither PVR nor we owned derivative instruments containing credit risk contingencies.

9. Property and Equipment

The following table summarizes property and equipment as of December 31, 2010 and 2009:


	As of December 31,
	2010		2009
Coal properties	$	506,235	$	478,803
Timber		87,699		87,869
Oil and gas royalties		36,937		36,937
Coal services equipment		35,310		38,474
Gathering systems		458,999		372,550
Compressor stations		77,909		62,701
Processing plants		61,665		55,948
Land		20,743		20,743
Other property, plant and equipment		9,730		8,045

Total property, plant and equipment		1,295,227		1,162,070
Accumulated depreciation, depletion and amortization		(324,181)		(261,226)

Net property, plant and equipment	$	971,046	$	900,844

10. Equity Investments

PVR owns 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 5, “Acquisitions.” We also own a 50% member interest in Crosspoint Pipeline LLC, a joint venture that gathers residue gas from our Crossroads Plant and transports it to market. We account for these investments under the equity method of accounting. As of December 31, 2010 and 2009, PVR’s equity investment totaled $84.3 million and $87.6 million, which exceeded PVR’s portion of the underlying equity in net assets by $16.0 million and $18.4 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, PVR recognized equity earnings of $8.7 million in 2010, $7.3 million in 2009 and $4.2 million in 2008, with a corresponding increase in the investment. The joint ventures generally pay PVR quarterly distributions of its portion of the joint ventures’ cash flows. PVR received cash distributions from the joint ventures of $12.0 million in 2010, $4.7 million in 2009 and $4.0 million in 2008. Equity earnings related to the 50% interest in Coal Handling Solutions LLC are included in coal services revenues on the consolidated statements of income, and equity earnings related to the 25% member interest in Thunder Creek and Crosspoint are recorded in other revenues on the consolidated statements of income. The equity investments for both joint ventures are included in the equity investments line on the consolidated balance sheets.

Summarized financial data for equity investments is as follows:


	As of December 31,
	2010		2009
Current assets	$	43,367	$	32,996
Noncurrent assets	$	203,595	$	214,463
Current liabilities	$	6,890	$	4,898
Noncurrent liabilities	$	5,147	$	5,392

	Year Ended December 31,
	2010		2009		2008
Revenues	$	69,302	$	68,106	$	43,687
Expenses	$	33,782	$	34,916	$	25,204
Net income	$	35,520	$	33,190	$	18,483

11. Goodwill

Goodwill is tested for impairment on an annual basis, at a minimum, and more frequently if a triggering event occurs. PVR’s 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 PVR’s market capitalization, reduced to zero all goodwill recorded in conjunction with acquisitions made by the PVR natural gas midstream segment in 2008 and prior years.

In determining the fair value of the PVR natural gas midstream segment (reporting unit), PVR 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. PVR discounted the resulting future cash flows using a peer company based weighted average cost of capital of 12%.

This loss was recorded in the impairment line on the 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, 2010 and 2009.

12. Intangible Assets, Net

The following table summarizes PVR’s net intangible assets as of December 31, 2010 and 2009:


	As of December 31,
	2010		2009
Contracts and customer relationships	$	104,700	$	104,700
Rights-of-way		4,552		4,552

Total intangible assets		109,252		109,252
Accumulated amortization		(32,302)		(25,511)

Intangible assets, net	$	76,950	$	83,741

The contracts and customer relationships and rights-of-way were primarily acquired by PVR in the Lone Star acquisition. See Note 5, “Acquisitions.” Contracts and customer relationships are amortized on both a straight-line basis and an accelerated basis, based on the period and timing of the benefit to us, 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, 2010, 2009 and 2008 was approximately $6.7 million, $7.4 million and $5.5 million. The following table sets forth PVR’s estimated aggregate amortization expense for the next five years and thereafter:


Year	Amortization Expense
2011		6,285
2012		5,718
2013		5,499
2014		5,346
2015		5,233
Thereafter		48,869

Total	$	76,950

13. 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, 2010 and 2009, which are included in other liabilities on the consolidated balance sheets:


	Year Ended December 31,
	2010		2009
Balance at beginning of period	$	2,014	$	1,814
Liabilities incurred		-		208
Accretion expense		158		(8)
Revision of estimate		-		-

Balance at end of period	$	2,172	$	2,014

The accretion expense is recorded in the depreciation, depletion and amortization expense line on the consolidated statements of income.

14. Long-Term Debt

We have no long-term debt. The following table summarizes PVR’s long-term debt as of December 31, 2010 and 2009:


	As of December 31,
	2010		2009
PVR Revolver – variable rate of 2.9% and 2.5% at December 31, 2010 and 2009	$	408,000	$	620,100
PVR Senior notes - fixed rate of 8.25%		300,000		-

Total PVR debt		708,000		620,100
Less: Current maturities		-		-

Total PVR long-term debt	$	708,000	$	620,100

PVR capitalized interest costs amounting to $0.4 million and $0.2 million in the years ended December 31, 2010 and 2009 related to the construction of natural gas processing plants.

PVR Revolver

On August 13, 2010, PVR entered into an amended and restated secured credit agreement increasing our borrowing capacity under the PVR Revolver to $850 million. As of December 31, 2010, net of outstanding indebtedness of $408.0

million and letters of credit of $1.6 million, PVR had remaining borrowing capacity of $440.4 million on the PVR Revolver. The PVR Revolver matures August 13, 2015. The PVR Revolver includes a $10 million sublimit for the issuance of letters of credit and a $25 million sublimit for swingline borrowings. PVR has an option, subject to the acceptance by the bank group, to increase the commitments under the PVR Revolver by up to an additional $200 million, to a total of $1.05 billion. The PVR Revolver is available to provide funds for general partnership purposes, including working capital, capital expenditures, acquisitions and quarterly distributions. In 2010, PVR incurred commitment fees of $1.2 million on the unused portion of the PVR Revolver. The interest rate under the PVR Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at base rate plus an applicable margin ranging from 1.25% to 2.25% if they select the base rate indebtedness option under the PVR Revolver or at a rate derived from LIBOR plus and applicable margin ranging from 2.25% to 3.25% if they select the LIBOR-based indebtedness option. The weighted average interest rate on borrowings outstanding under the PVR Revolver during 2010 was approximately 2.5%. We do not have a public rating for the PVR Revolver. As of December 31, 2010, PVR was in compliance with all of our covenants under the PVR Revolver.

PVR Senior Notes

In April 2010, PVR sold $300.0 million of senior notes due on April 15, 2018 (“PVR Senior Notes”) with an annual interest rate of 8.25%, which is payable semi-annually in arrears on April 15 and October 15 of each year. The PVR Senior Notes were sold at par, equating to an effective yield to maturity of approximately 8.25%. The net proceeds from the sale of the PVR Senior Notes of approximately $292.6 million, after deducting fees and expenses of approximately $7.4 million, were used to repay borrowings under the PVR Revolver. The PVR Senior Notes are senior to any subordinated indebtedness, and are effectively subordinated to all of our secured indebtedness including the PVR Revolver to the extent of the collateral securing that indebtedness. The obligations under the PVR Senior Notes are fully and unconditionally guaranteed by our current and future subsidiaries, which are also guarantors under the PVR Revolver.

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:


Year	Aggregate Maturities Principal Amounts
2011	$	-
2012		-
2013		-
2014		-
2015		408,000
Thereafter		300,000

Total debt, including current maturities	$	708,000

15. Partners’ Capital and Distributions

As of December 31, 2010, partners’ capital consisted of 39.1 million common units.

Cash Distributions

We distribute 100% of Available Cash (as defined in our partnership agreement) within 55 days after the end of each quarter to unitholders of record. 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, (iii) provide funds for distributions to unitholders and our general partner for any one or more of the next four quarters or (iv) permit Penn Virginia Resource GP, LLC to make capital contributions to PVR to maintain its 2% general partner interest upon the issuance of additional partnership securities by PVR.

The following table reflects the allocation of total cash distributions paid by us for the periods presented (in thousands, except per unit data):


	Year Ended December 31,
Unitholders	2010		2009		2008
Public unitholders	$	49,493	$	17,477	$	11,269
Penn Virginia Corporation		11,072		41,916		43,435

Total cash distributions paid	$	60,565	$	59,393	$	54,704


Total cash distributions paid per unit	$	1.55	$	1.52	$	1.40

On February 22, 2011, we paid a $0.39 quarterly distribution per unit to unitholders of record on February 15, 2011. This distribution was unchanged from the previous distribution paid on November 19, 2010.

Limited Call Right

Gain or Loss on Sale or Issuance of Subsidiary Units

In 2010, we recognized losses of $1.5 million upon the issuance of PVR common units to satisfy the vesting of phantom units. See Note 17, “Unit-Based Payments.”

As a result of PVR’s unit offering in May 2008, we recognized gains in partners’ capital of $39.5 million. See Note 6, “PVR Unit Offering.” As a result of the issuance of PVR units in the acquisition of Lone Star, we recognized gains in partners’ capital of $4.0 million. See Note 5, “Acquisitions.” These gains in partners’ capital resulted in a $43.5 million decrease in our noncontrolling interests in PVR.

Noncontrolling Interests

The following schedule summarizes the effects of changes in our ownership interest in PVR on our partners’ capital.


	2010		2009		2008
Net income attributable to Penn Virginia GP Holdings, L.P.	$	37,144	$	37,879	$	52,686

Transfers (to) from the noncontrolling interest:
Increase in Penn Virginia GP Holdings, L.P. partners’ capital for sale of 5.2 PVR common units		-		-		39,495
Increase in Penn Virginia GP Holdings, L.P. partners’ capital for issuance of 0.5 million PVR common units in connection with acquisition		-		-		4,027
Decrease in Penn Virginia GP Holdings, L.P. partners’ capital for issuance of 0.5 million PVR common units for vesting of phantom units		(1,508)		-		-
Decrease in Penn Virginia GP Holdings, L.P. partners’ capital for purchase of 0.1 million PVR common units		(11,665)		-		-

Net transfers (to) from noncontrolling interest		(13,173)		-		43,522

Change from net income attributable to Penn Virginia GP Holdings, L.P. and transfers (to) from noncontrolling interest	$	23,971	$	37,879	$	96,208

16. Related Party Transactions

In June 2010, PVA sold its remaining interest in PVG and as a result, PVA no longer owns any limited or general partner interests in us or PVR. As a result of the divestiture, the related party transactions noted below are now considered arm’s-length and no longer require separate disclosures. PVA and PVG executed a transition agreement covering the services of certain shared employees, aiding the transition of corporate and accounting functions that could continue until March 2011. Related party transactions included charges from PVA for certain corporate administrative expenses which are allocable to us and our subsidiaries. Other transactions involved subsidiaries of PVA related to the marketing of natural gas, gathering and processing of natural gas, and the purchase and sale of natural gas and NGLs in which we took

title to the products. The Consolidated Statements of Income and Consolidated Balance Sheet amounts noted below represent related party transactions through June 7, 2010 (date of divestiture).


	Year Ended December 31,
	2010		2009		2008
Consolidated Statements of Income:
Natural gas midstream revenues	$	29,002	$	76,573	$	130,220
Other income	$	787	$	1,418	$	3,014
Cost of gas purchased	$	27,780	$	72,529	$	127,907
General and administrative	$	1,906	$	5,747	$	5,536

	December 31, 2010		December 31, 2009
Consolidated Balance Sheets:
Accounts receivable	$	-	$	674
Accounts payable	$	-	$	1,816

17. Unit-Based Payments

Long-Term Incentive Plan

Our general partner has adopted a long-term incentive plan. Our long-term incentive plan permits the grant of awards covering an aggregate of 300,000 common units to employees and directors 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 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 recognize compensation expense evenly over the vesting period of the awards.

We recognized compensation expense related to our long-term incentive plan of $0.6 million, $0.4 million and $0.4 million for the years ended December 31, 2010, 2009 and 2008. Compensation expense is recorded on the general and administrative expense line on the consolidated statements of income.

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.

The following is a summary of deferred common unit activity for the periods presented:


	Number of Deferred Common Units		Weighted Average Grant-Date Fair Value
Balance at December 31, 2007		13,396	$27.30
Granted and vested		18,732	$20.61

Balance at December 31, 2008		32,128	$23.40
Granted and vested		32,172	$13.28

Balance at December 31, 2009		64,300	$18.34
Granted and vested		26,043	$20.47
Converted to common units		(19,470)	$18.00

Balance at December 31, 2010		70,873	$19.21

In 2010, 19,470 deferred common units converted to common units. We purchased units on the open market to satisfy this unit payment. The aggregate intrinsic value of deferred common units converted to common units in 2010 was $0.4 million. The aggregate intrinsic value of vested deferred common units at December 31, 2010, was $1.4 million.

PVR Long-Term Incentive Plan

PVR’s general partner has adopted a long-term incentive plan. PVR’s long-term incentive plan permits the grant of awards covering an aggregate of 3,000,000 PVR common units to employees and directors of PVR’s general partner and employees of its affiliates who perform services for PVR. Awards under the PVR long-term incentive plan can be in the form of PVR common units, restricted PVR units, PVR unit options, phantom PVR units and deferred PVR common units. The PVR long-term incentive plan is administered by the compensation and benefits committee of the board of directors of PVR’s general partner (“Committee”). PVR reimburses its general partner for payments made pursuant to the

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PVR long-term incentive plan. PVR recognizes compensation cost based on the fair value of the awards over the vesting period.

PVR recognized a total of $8.0 million, $4.8 million and $3.2 million in the years ended December 31, 2010, 2009 and 2008 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 long-term incentive plan. Compensation expense is recorded on the general and administrative expense line on the consolidated statements of income.

PVR Common Units. PVR’s common units, which are granted to non-employee directors, vest immediately upon issuance. PVR’s general partner granted 1,448 common units at a weighted average grant-date fair value of $23.41 per unit to non-employee directors in 2010. PVR’s 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. PVR’s 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. The fair value of the PVR common units is calculated based on the grant-date unit price.

Deferred PVR Common Units. A portion of the compensation to the non-employee directors of PVR’s general partner is paid in deferred PVR common units. Each deferred PVR common unit represents one PVR common unit, which vests immediately upon issuance and is available to the holder upon termination or retirement from the board of directors of PVR’s general partner.

The following is a summary of deferred common PVR unit activity for the periods presented:


	Number of Deferred Common Units		Weighted Average Grant-Date Fair Value
Balance at January 1, 2008		61,218	$25.68
Granted and vested		30,951	$20.36
Converted to common units		(28,600)	$23.70

Balance at December 31, 2008		63,569	$23.98
Granted and vested		35,819	$15.62

Balance at December 31, 2009		99,388	$20.97
Granted and vested		27,194	$24.00

Balance at December 31, 2010		126,582	$21.62

In 2008, 28,600 deferred PVR common units converted to PVR common units. The aggregate intrinsic value of deferred PVR common units converted to PVR common units in 2008 was $0.7 million. The aggregate intrinsic value of vested deferred PVR common units at December 31, 2010, was $2.8 million. The fair value of the deferred PVR common units is calculated based on the grant-date unit price.

Restricted PVR Units. Restricted PVR units vest upon terms established by the Committee. In addition, all restricted PVR units will vest upon a change of control of PVR’s general partner or Penn Virginia. If a grantee’s employment with, or membership on the board of directors of, PVR’s general partner terminates for any reason, the grantee’s unvested restricted PVR units will be automatically forfeited unless, and to the extent that, the Committee provides otherwise. Distributions payable with respect to restricted PVR units may, in the Committee’s discretion, be paid directly to the grantee or held by PVR’s general partner and made subject to a risk of forfeiture during the applicable restriction period. Restricted PVR units generally vest over a three-year period, with one-third vesting in each year. The fair value of the restricted PVR units is calculated based on the grant-date unit price.

Because PVA’s divestiture of PVG was considered a change of control under the PVR LTIP, all unvested restricted units granted to employees performing services for the benefit of us were considered vested on the date of the divestiture. In total, approximately 36,000 restricted PVR units vested and the restrictions were lifted.

The following table summarizes the status of nonvested restricted PVR units as of December 31, 2010 and changes during the year then ended:


	Nonvested Restricted Units		Weighted Average Grant-Date Fair Value
Nonvested at January 1, 2010		92,809	$26.57
Vested		(90,550)	$26.89
Forfeited		(2,259)	$26.91

Nonvested at December 31, 2010		-	$ -

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The total grant-date fair value of restricted PVR units that vested in 2010, 2009 and 2008 was $2.4 million, $3.5 million and $1.9 million.

Phantom PVR Units. A phantom PVR unit entitles the grantee to receive a common PVR unit upon the vesting of the phantom PVR unit, or in the discretion of the Committee, the cash equivalent of the value of a common PVR unit. The Committee determines the time period over which phantom units granted to employees and directors will vest. In addition, all phantom PVR units will vest upon a change of control of its general partner. If a director’s membership on the board of directors of its general partner terminates for any reason, or an employee’s employment with its 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. Phantom PVR units were first granted in 2009. Phantom PVR units generally vest over a three-year period, with one-third vesting in each year. The fair value of the phantom PVR units is calculated based on the grant-date unit price. Generally, we pay distribution for all of our unvested phantom units. Payments of distribution associated with phantom units that are expected to vest are recorded as capital distributions; however, payments associated with phantom units that are not expected to vest are recorded as compensation expense.

The following table summarizes the status of nonvested phantom PVR units as of December 31, 2010 and changes during the year then ended:


	Nonvested Phantom Units		Weighted Average Grant-Date Fair Value
Nonvested at January 1, 2010		277,003	$11.59
Granted		261,262	$23.41
Vested		(419,076)	$15.87
Forfeit		(21,456)	$15.88

Nonvested at December 31, 2010		97,733	$23.91

At December 31, 2010, PVR had $1.9 million of total unrecognized compensation cost related to nonvested phantom PVR units. PVR expects to reimburse its general partner for that cost over a weighted-average period of 2.6 years. The total grant-date fair value of phantom PVR units that vested in 2010 and 2009 was $6.6 million and $0.9 million. The aggregate intrinsic value at December 31, 2010, of phantom PVR units expected to vest was $2.3 million.

18. Commitments and Contingencies

Rental Commitments

Operating lease rental expense in the years ended December 31, 2010, 2009 and 2008 was $9.6 million, $7.5 million and $4.5 million. The following table sets forth PVR’s minimum rental commitments for the next five years under all non-cancelable operating leases in effect at December 31, 2010:


Year	Minimum Rental Commitments
2011	$	4,094
2012		4,096
2013		4,052
2014		3,955
2015		3,898
Thereafter		7,341

Total minimum payments	$	27,436

PVR’s rental commitments primarily relate to equipment and building leases and leases of coal reserve-based properties which PVR subleases, or intends to sublease, to third parties. The obligation with respect to leased properties which PVR subleases 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. PVR believes that the future rental commitments with regard to this subleased property cannot be estimated with certainty.

Firm Transportation Commitments

As of December 31, 2010, PVR had contracts for firm transportation capacity rights for specified volumes per day on a pipeline system with terms that ranged from one to five years. The contracts require PVR to pay transportation demand

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charges regardless of the amount of pipeline capacity PVR uses. PVR may sell excess capacity to third parties at its discretion. The following table sets forth PVR’s obligation for firm transportation commitments in effect at December 31, 2010 for the next five years and thereafter:


Year	Firm Transportation Commitments
2011	$	12,628
2012		4,508
2013		4,033
2014		3,321
2015		1,661
Thereafter		-

Total firm transportation commitments	$	26,151

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

Mine Health and Safety Laws

There are numerous mine health and safety laws and regulations applicable to the coal mining industry. However, since PVR does not operate any mines and does not employ any coal miners, PVR is not subject to such laws and regulations. Accordingly, we have not accrued any related liabilities.

19. 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:


	Year Ended December 31,
	2010		2009		2008
Net income	$	64,187	$	62,911	$	102,598
Unrealized holding losses on derivative activities		-		(506)		(4,039)
Reclassification adjustment for derivative activities		1,804		3,356		7,186

Comprehensive income	$	65,991	$	65,761	$	105,745

Included in the comprehensive income balance at December 31, 2010 is $0.4 million of gains relating to the PVR Interest Rate Swaps on which PVR discontinued hedge accounting. The $0.4 million gain will be recognized in earnings through the end of 2011 as the hedged transactions settle. See Note 8, “Derivative Instruments.”

20. 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 PVR’s Chief Executive Officer and other senior officers. This group routinely reviews

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and makes operating and resource allocation decisions among PVR’s coal and natural resource management operations and PVR’s natural gas midstream operations. Accordingly, our reportable segments are as follows:

•

PVR Coal and Natural Resource Management — The PVR coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. PVR’s coal reserves are primarily located in Kentucky, Virginia, West Virginia, Illinois and New Mexico. PVR also earns 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.

•

PVR Natural Gas Midstream — The PVR natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. PVR owns and operates natural gas midstream assets located in Oklahoma and Texas. PVR’s natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services.

The following table presents a summary of certain financial information relating to our segments as of and for the years ended December 31, 2010, 2009 and 2008:


	Revenues						Operating income
	2010		2009		2008		2010		2009		2008
Coal and natural resource management(1)	$	152,488	$	144,600	$	153,327	$	93,132	$	87,528	$	96,296
Natural gas midstream(2)		711,648		512,104		728,253		32,767		20,774		18,946
Corporate and other		-		-		-		(4,314)		(2,377)		(2,070)

Consolidated totals	$	864,136	$	656,704	$	881,580	$	121,585	$	105,925	$	113,172

Interest expense								(35,591)		(24,653)		(24,672)
Other								686		1,353		(2,739)
Derivatives								(22,493)		(19,714)		16,837

Consolidated net income							$	64,187	$	62,911	$	102,598


	Additions to property and equipment						Depreciation, depletion & amortization
	2010		2009		2008		2010		2009		2008
Coal and natural resource management	$	25,751	$	2,252	$	27,270	$	30,873	$	31,330	$	30,805
Natural gas midstream		98,365		78,425		304,758		45,027		38,905		27,361

Consolidated totals	$	124,116	$	80,677	$	332,028	$	75,900	$	70,235	$	58,166


	Total assets at December 31,
	2010		2009		2008
Coal and natural resource management(3)	$	585,559	$	574,258	$	600,418
Natural gas midstream(4)		711,942		633,802		618,402
Corporate and other		6,704		11,003		8,854

Consolidated totals	$	1,304,205	$	1,219,063	$	1,227,674

(1)

The PVR coal and natural resource management segment’s revenues for the years ended December 31, 2010, 2009 and 2008 include $2.0 million, $1.7 million and $1.8 million of equity earnings related to PVR’s 50% interest in Coal Handling Solutions LLC. See Note 10, “Equity Investments” for a further description.

(2)

The PVR natural gas midstream segment’s revenues for the years ended December 31, 2010, 2009 and 2008 include $6.0 million, $5.3 million and $2.4 million of equity earnings related to PVR’s 25% member interest in Thunder Creek that PVR acquired in 2008 for $51.6 million. See Note 5, “Acquisitions” for a further description of this acquisition and Note 10, “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 the PVR natural gas midstream goodwill. See Note 11, “Goodwill” for further discussion of this impairment.

(3)

Total assets at December 31, 2010, 2009 and 2008 for the PVR coal and natural resource management segment included equity investment of $19.0 million, $21.0 million and $23.4 million related to PVR’s 50% interest in Coal Handling Solutions LLC. See Note 10, “Equity Investments” for a further description.

(4)

Total assets at December 31, 2010, 2009 and 2008 for the PVR natural gas midstream segment included equity investment of $58.8 million, $59.8 million and $55.0 million related to PVR’s 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 5, “Acquisitions” and Note 10, “Equity Investments” for a further description.

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.

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For the year ended December 31, 2010, two customers of PVR’s natural gas midstream segment accounted for $122.6 million and $97.0 million, or 14% 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, 2009, two customers of PVR’s 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.

Supplemental Quarterly Financial Information (Unaudited, in thousands except unit data)


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2010
Revenues	$	206,478	$	189,432	$	222,829	$	245,397
Operating income (1)	$	26,758	$	23,710	$	31,693	$	39,424
Net income	$	13,682	$	22,106	$	10,145	$	18,254
Basic and diluted net income (loss) per limited partner unit, common and subordinated (2)	$	0.22	$	0.30	$	0.19	$	0.25
Weighted average number of units outstanding, basic and diluted		39,075		39,075		39,075		39,075

2009
Revenues	$	156,759	$	149,419	$	155,625	$	194,901
Operating income (1)	$	21,390	$	20,831	$	26,937	$	36,767
Net income	$	8,942	$	12,779	$	17,966	$	23,224
Basic and diluted net income (loss) per limited partner unit, common and subordinated (2)	$	0.18	$	0.21	$	0.26	$	0.32
Weighted average number of units outstanding, basic and diluted		39,075		39,075		39,075		39,075

(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.

(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 11, “Goodwill.”

21. Subsequent Event

In December, 2010, PVR announced a definitive agreement to purchase certain mineral rights and associated oil and gas royalty interest in Kentucky and Tennessee for approximately $97.3 million, subject to closing adjustments. The mineral rights include approximately 102.0 million tons of coal reserves and resources, and royalty interest from approximately 158 oil and gas wells. There are currently 14 active producing underground and surface mines on the approximately 126,000 acres of mineral estates being acquired, with 10 principal coal lessees operating the mines. The coal is primarily steam coal that is consumed by major electric utilities and other industrial customers in the southeastern United States. On January 25, 2011 PVR completed the purchase of these assets, which was funded by borrowings under the PVR Revolver.

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Item 9 Changes in and Disagreements With Accountants on Accounting and Financial DisclosureNone.

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, 2010. 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, 2010, 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, 2010. 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, 2010, our internal control over financial reporting was effective.

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, 2010, 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

None.

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Part III

ITEM 10.

Directors, Executive Officers and Corporate Governance

Information required to be set forth in Item 10. Directors, Executive Officers and Corporate Governance, has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2011 Annual Meeting of Unitholders expected to be filed no later than April 30, 2011.

ITEM 11.

Executive Compensation

Information required to be set forth in Item 11. Executive Compensation, has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2011 Annual Meeting of Unitholders expected to be filed no later than April 30, 2011.

ITEM 12.

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

Information required to be set forth in Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters, has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2010 Annual Meeting of Unitholders expected to be filed no later than April 30, 2011.

ITEM 13.

Certain Relationships and Related Transactions, and Director Independence

Information required to be set forth in Item 13. Certain Relationships and Related Transactions, and Director Independence, has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2011 Annual Meeting of Unitholders expected to be filed no later than April 30, 2011.

ITEM 14.

Principal Accountant Fees and Services

Information required to be set forth in Item 14. Principal Accountant Fees and Services, has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2011 Annual Meeting of Unitholders expected to be filed no later than April 30, 2011.

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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 79 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 Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on July 22, 2008).
(2.2)		Agreement and Plan of Merger, dated September 21, 2010, by and among Penn Virginia Resource Partners, L.P., Penn Virginia Resource GP, LLC, PVR Radnor, LLC, Penn Virginia GP Holdings, L.P. and PVG GP, LLC (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed on September 22, 2010).
(3.1)		Certificate of Limited Partnership of Penn Virginia GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to Registrant’s Registration Statement on Form S-1 filed on July 11, 2006).
(3.1.1)		Amendment dated June 19, 2006 to the Certificate of Limited Partnership of Penn Virginia GP Holdings, L.P. (incorporated by reference to Exhibit 3.2 to Registrant’s Registration Statement on Form S-1 filed on July 11, 2006).
(3.1.2)		Amendment dated September 6, 2006 to the Certificate of Limited Partnership of Penn Virginia GP Holdings, L.P. (incorporated by reference to Exhibit 3.15 to Amendment No. 2 to Registrant’s Registration Statement on Form S-1 filed on October 6, 2006).
(3.2)		Second Amended and Restated Agreement of Limited Partnership of Penn Virginia GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on October 26, 2007).
(3.2.1)		Amendment No.1 to Second Amended and Restated Agreement of Limited Partnership of Penn Virginia GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on February 24, 2009).
(3.2.2)		Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Penn Virginia GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on March 31, 2010).
(3.2.3)		Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Penn Virginia GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on June 7, 2010).
(3.3)		Certificate of Formation of PVG GP, LLC (incorporated by reference to Exhibit 3.12 to Amendment No. 1 to Registrant’s Registration Statement on Form S-1 filed on September 7, 2006).
(3.4)		Second Amended and Restated Limited Liability Company Agreement of PVG GP, LLC (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed on June 7, 2010).
(3.5)		Certificate of Limited Partnership of Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 3.1 to Penn Virginia Resource Partners, L.P.’s Registration Statement on Form S-1 filed on July 19, 2001).
(3.6)		Third Amended and Restated Agreement of Limited Partnership of Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 3.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on August 7, 2008).
(3.6.1)		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 Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on February 24, 2009).

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(3.6.2)		Amendment No. 2 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 March 31, 2010).
(3.7)		Certificate of Formation of Penn Virginia Resource GP, LLC (incorporated by reference to Exhibit 3.5 to Amendment No. 1 to Penn Virginia Resource Partners, L.P.’s Registration Statement Form S-1 filed on September 7, 2001).
(3.8)		Fifth Amended and Restated Limited Liability Company Agreement of Penn Virginia Resource GP, LLC (incorporated by reference to Exhibit 3.2 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on March 31, 2010).
(10.1)		Amended and Restated Credit Agreement, dated as of August 13, 2010 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 Current Report on Form 8-K filed on August 19, 2010).
(10.2)		Contribution Agreement dated as of December 8, 2006 among Penn Virginia Resource LP Corp., Penn Virginia Resource GP, LLC, Kanawha Rail Corp., Penn Virginia GP Holdings, L.P. and Penn Virginia Resource GP Corp. (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on December 13, 2006).
(10.3)		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 Penn Virginia Resource Partners, L.P.’s Registration Statement on Form S-1 filed on October 4, 2001).
(10.3.1)		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 Penn Virginia Resource Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2002).
(10.4)		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 Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on December 13, 2006).
(10.5)		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 Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on July 22, 2008).
(10.6)		PVG GP, LLC 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 October 29, 2007).*
(10.7)		Form of Agreement for Deferred Common Unit Grants under the PVG GP, LLC Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.12 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007).*
(10.8)		Form of Agreement for Restricted Unit Awards under the PVG GP, LLC Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.13 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007).*
(10.9)		PVG 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).*
(10.10)		Penn Virginia Resource GP, LLC Fifth Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on January 15, 2009).*
(10.11)		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 Penn Virginia Resource Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2007).*
(10.12)		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 Penn Virginia Resource Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2007).*
(10.13)		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 Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on February 24, 2009).*

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(10.14)		Penn Virginia Resource GP, LLC Amended and Restated Non-Employee Directors Deferred Compensation Plan (incorporated by reference to Exhibit 10.4 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on October 29, 2007).*
(10.15)		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 Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on October 22, 2008).*
(10.16)		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 Penn Virginia Resource Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2008).*
(10.17)		Employment Agreement between Robert B. Wallace and Penn Virginia Resource GP, LLC dated March 23, 2010 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on March 24, 2010).*
(10.18)		Amended and Restated Employment Agreement between William H. Shea, Jr. and Penn Virginia Resource GP, LLC dated March 23, 2010 (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on March 24, 2010).*
(10.19)		PVG GP, LLC Non-Employee Director Compensation Summary Sheet for 2011 *
(10.20)		Contribution Agreement dated as of June 7, 2010 among Penn Virginia Resource GP Corp., Penn Virginia GP Holdings, L.P. and PVG GP, LLC (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on June 7, 2010).
(10.21)		Memorandum of Understanding, dated February 1, 2011, among Penn Virginia Resource Partners, L.P., Penn Virginia Resource GP, LLC, PVR Radnor LLC, Penn Virginia GP Holdings, L.P., PVG GP, LLC the individual directors of Holdings GP, and Kevin Epoch, Sanjay Israni and Anita Scheifele (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on February 7, 2011).
(14.1)		PVG GP, LLC Code of Business Conduct and Ethics (incorporated by reference to Registrant’s Current Report on Form 8-K filed on July 24, 2009).
(12.1)		Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.
(21.1)		Subsidiaries of Penn Virginia GP Holdings, 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.

110

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 GP HOLDINGS, L.P.
	By: PVG GP, LLC
February 24, 2011	By:
		/s/ Robert B. Wallace
		Robert B. Wallace
		Executive Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by or on the behalf of the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


/s/ A. James Dearlove A. James Dearlove	Chairman of the Board	February 24, 2011
/s/ William H. Shea, Jr. William H. Shea, Jr.	President, Chief Executive Officer and Director	February 24, 2011
/s/ Robert J. Hall Robert J. Hall	Director	February 24, 2011
/s/ John C. van Roden, Jr. John C. van Roden, Jr.	Director	February 24, 2011
/s/ Jonathan B. Weller Jonathan B. Weller	Director	February 24, 2011

111