UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

FORM 10-K

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

Commission file number: 1-16735

 

Penn Virginia Resource Partners, L.P.

(Exact name of registrant as specified in its charter)

Delaware		23-3087517
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

Three Radnor Corporate Center, Suite 300
100 Matsonford Road
Radnor, Pennsylvania 19087

(Address of principal executive offices)

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

 

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

Title of each class		Name of exchange on which 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 x No o

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

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

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

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

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

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

The aggregate market value of common units held by non-affiliates of the registrant was $432,356,579 as of June 30, 2009 (the last business day of its most recently completed second fiscal quarter), based on the last sale price of such units as quoted on the New York Stock Exchange. For purposes of making this calculation only, the registrant has defined affiliates as including the registrant’s general partner, all affiliates of the registrant’s general partner and all directors and executive officers of the registrant’s general partner. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of February 22, 2010, 51,798,895 common units representing limited partner interests of the registrant were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

Table of Contents

		Page
Forward-Looking Statements			ii

Item
Part I
1. Business			1
1A. Risk Factors			21
1B. Unresolved Staff Comments			38
2. Properties			39
3. Legal Proceedings			46
4. Reserved			46
Part II
5. Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities			47
6. Selected Financial Data			48
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			49
Overview of Business			49
Liquidity and Capital Resources			51
Contractual Obligations			55
Off-Balance Sheet Arrangements			55
Results of Operations			56
Environmental Matters			66
Critical Accounting Estimates			66
New Accounting Standards			68
7A. Quantitative and Qualitative Disclosures About Market Risk			69
8. Financial Statements and Supplementary Data			72
9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			110
9A. Controls and Procedures			110
9B. Other Information			110
Part III
10. Directors, Executive Officers and Corporate Governance			111
11. Executive Compensation			115
12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters			133
13. Certain Relationships and Related Transactions, and Director Independence			134
14. Principal Accounting Fees and Services			136
Part IV
15. Exhibits and Financial Statement Schedules			137

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Forward-Looking Statements

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

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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.

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Part I

Item 1 Business

General

Penn Virginia Resource Partners, L.P. (NYSE: PVR) is a publicly traded Delaware limited partnership formed by Penn Virginia Corporation (NYSE: PVA), or Penn Virginia, in 2001 that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. Both in our current limited partnership form and in our previous corporate form, we have managed coal properties since 1882. We currently conduct operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream.

Our operating income was $108.3 million in 2009, compared to $115.2 million in 2008 and $117.7 million in 2007. In 2009, our coal and natural resource management segment contributed $87.5 million, or 81%, to operating income, and our natural gas midstream segment contributed $20.8 million, or 19%, to operating income. Unless the context requires otherwise, references to the “Partnership,” “we,” “us” or “our” in this Annual Report on Form 10-K refer to Penn Virginia Resource Partners, L.P. and its subsidiaries.

Coal and Natural Resource Management Segment Overview

Our coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees.

As of December 31, 2009, we owned or controlled approximately 829 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. We enter into long-term leases with experienced, third-party mine operators, providing them the right to mine our coal reserves in exchange for royalty payments. We actively work with our lessees to develop efficient methods to exploit our reserves and to maximize production from our properties. We do not operate any mines. In 2009, our lessees produced 34.3 million tons of coal from our properties and paid us coal royalties revenues of $120.4 million, for an average royalty per ton of $3.51. Approximately 82% of our coal royalties revenues in 2009 were derived from coal mined on our properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of our coal royalties revenues for the respective periods was derived from coal mined on our properties under leases containing fixed royalty rates that escalate annually. See “— Contracts — Coal and Natural Resource Management Segment” for a description of our coal leases.

Natural Gas Midstream Segment Overview

Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of December 31, 2009, we owned and operated natural gas midstream assets located in Oklahoma and Texas, including six natural gas processing facilities having 400 MMcfd of total capacity and approximately 4,118 miles of natural gas gathering pipelines. Our natural gas midstream business earns revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In addition, we own a 25% member interest in Thunder Creek Gas Services, LLC, or Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. We also own a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

In 2009, system throughput volumes at our gas processing plants and gathering systems, including gathering-only volumes, were 121.3 Bcf, or approximately 332 MMcfd.

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Business Strategy

Our primary business objective is to create sustainable, capital-efficient growth in cash available for distribution to our unitholders while maintaining a strong credit profile and financial flexibility. Our growth objective is largely dependent on the availability of open and reasonably priced capital markets. Subject to the availability of the capital markets, we are pursuing the following business strategies:

Contracts

Coal and Natural Resource Management Segment

We earn most of our coal royalties revenues under long-term leases that generally require our lessees to make royalty payments to us based on the higher of a percentage of the gross sales price or a fixed price per ton of coal they sell. The balance of our coal royalties revenues is earned under long-term leases that require the lessees to make royalty payments to us based on fixed royalty rates that escalate annually. A typical lease either expires upon exhaustion of the leased reserves or has a five to ten-year base term, with the lessee having an option to extend the lease for at least five years after the expiration of the base term. Substantially all of our leases require the lessee to pay minimum rental payments to us in monthly or annual installments,

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even if no mining activities are ongoing. These minimum rentals are recoupable, usually over a period from one to three years from the time of payment, against the production royalties owed to us once coal production commences.

Substantially all of our leases impose obligations on the lessees to diligently mine the leased coal using modern mining techniques, indemnify us for any damages we incur in connection with the lessee’s mining operations, including any damages we may incur due to the lessee’s failure to fulfill reclamation or other environmental obligations, conduct mining operations in compliance with all applicable laws, obtain our written consent prior to assigning the lease and maintain commercially reasonable amounts of general liability and other insurance. Substantially all of the leases grant us the right to review all lessee mining plans and maps, enter the leased premises to examine mine workings and conduct audits of lessees’ compliance with lease terms. In the event of a default by a lessee, substantially all of the leases give us the right to terminate the lease and take possession of the leased premises.

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

Natural Gas Midstream Segment

Our natural gas midstream business generates revenues primarily from gas purchase and processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. During the year ended December 31, 2009, our natural gas midstream business generated a majority of its gross margin from two types of contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and NGLs: (i) gas purchase/keep-whole and (ii) percentage-of-proceeds. For the fourth quarter of 2009, approximately 28% of our system throughput volumes were gathered or processed under gas purchase/keep-whole contracts, 53% were gathered or processed under percentage-of-proceeds contracts and 19% were gathered or processed under fee-based gathering contracts. A majority of the gas purchase/keep-whole and percentage-of-proceeds contracts include fee-based components such as gathering and compression charges.

In 2009, 21%, 15% and 10% of our natural gas midstream segment revenues and 17%, 11% and 8% of our total consolidated revenues resulted from three of our natural gas midstream customers, Conoco, Inc., Tenaska Marketing Ventures and ONEOK Energy Marketing.

Gas Purchase/Keep-Whole Arrangements.  Under gas purchase/keep-whole arrangements, we generally purchase natural gas at the wellhead at either (i) a percentage discount to a specified index price, (ii) a specified index price less a fixed amount or (iii) a combination of (i) and (ii). We then gather the natural gas to one of our plants where it is processed to extract the entrained NGLs, which are then sold to third parties at market prices. We resell the remaining natural gas to third parties at an index price which typically corresponds to the specified purchase index. Because the extraction of the NGLs from the natural gas during processing reduces the BTU content of the natural gas, we retain a reduced volume of gas to sell after processing. Accordingly, under these arrangements, our revenues and gross margins increase as the price of NGLs increases relative to the price of natural gas, and our revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. We have generally been able to mitigate our exposure in the latter case by requiring the payment under many of our gas purchase/keep-whole arrangements of minimum processing charges which ensure that we receive a minimum amount of processing revenues. The gross margins that we realize under the arrangements described in clauses (i) and (iii) above also decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price.

Percentage-of-Proceeds Arrangements.  Under percentage-of-proceeds arrangements, we generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed-upon percentage of the proceeds of those sales based on either an index price or the price actually received for the gas and NGLs. Under these types of arrangements, our

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revenues and gross margins increase as natural gas prices and NGL prices increase, and our revenues and gross margins decrease as natural gas prices and NGL prices decrease.

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

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

Natural Gas Marketing Contracts.  We are also engaged in natural gas marketing by aggregating third-party volumes and selling those volumes into interstate and intrastate pipeline systems such as Enogex and Panhandle Eastern Pipeline and at market hubs accessed by various interstate pipelines. Connect Energy Services, LLC, or Connect Energy, our wholly owned subsidiary, has earned fees from Penn Virginia Oil & Gas, L.P., or PVOG LP, a wholly owned subsidiary of Penn Virginia, since September 1, 2006, for marketing a portion of PVOG LP’s natural gas production. Revenues from this business do not generate qualifying income for a publicly traded limited partnership, but we do not expect it to have an impact on our tax status, as it does not represent a significant percentage of our operating income. For the years ended December 31, 2009 and 2008, natural gas marketing activities generated $1.8 million and $5.8 million in net revenues.

Commodity Derivative Contracts.  We utilize collar derivative contracts to hedge against the variability in our frac spread. Our frac spread is the spread between the purchase price for the natural gas we purchase from producers and the sale price for NGLs that we sell after processing. We hedge against the variability in our frac spread by entering into costless collar and swap derivative contracts to sell NGLs forward at a predetermined commodity price and to purchase an equivalent volume of natural gas forward on an MMBtu basis. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues or cost savings from favorable price movements.

See Note 6 to the Consolidated Financial Statements for a further description of our derivatives program.

Partnership Structure

Penn Virginia, a publicly held energy company has been engaged in the coal royalty business since 1882 and is also engaged in the exploration, development and production of natural gas and oil. Penn Virginia formed us as a Delaware limited partnership in July 2001 to own and operate substantially all of the assets of and assume the liabilities relating to Penn Virginia’s coal land management business. We completed our initial public offering in October 2001. Penn Virginia continues to hold a significant interest in us through its indirect controlling interest in Penn Virginia GP Holdings, L.P. (NYSE: PVG), or PVG, a publicly traded Delaware limited partnership.

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Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own our subsidiaries through a wholly owned subsidiary, PVR Finco LLC, which is the sole member of the operating company for the coal and natural resource management segment, Penn Virginia Operating Co., LLC, or PVR Coal, and the operating company for the natural gas midstream segment, PVR Midstream LLC, or PVR Midstream. The following diagram depicts our and our affiliates’ simplified organizational and ownership structure as of December 31, 2009:

Relationship with Penn Virginia Corporation

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Under an omnibus agreement between us, Penn Virginia and our general partner, Penn Virginia and its affiliates, including PVG and our general partner, are restricted in their ability to engage in any coal-related business. See Item 13, “Certain Relationships and Related Transactions, and Director Independence — Transactions with Related Persons.”

Partnership Distributions

Cash Distributions

We paid cash distributions of $1.88 per common unit during the year ended December 31, 2009. In the first quarter of 2010, we paid a cash distribution of $0.47 ($1.88 on an annualized basis) per common unit with respect to the fourth quarter of 2009. This distribution was unchanged from the previous distribution paid on November 13, 2009. For the remainder of 2010, we expect to pay quarterly cash distributions of at least $0.47 ($1.88 on an annualized basis) per common unit.

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

		Year Ended December 31,
		2009				2008				2007
Limited partner units		$	97,382			$	89,207			$	76,536
General partner interest (2%)			1,988				1,820				1,562
Incentive distribution rights			24,140				20,049				11,551
Phantom units			499				—				—
Total cash distributions paid		$	124,009			$	111,076			$	89,649
Total cash distributions paid per limited partner unit		$	1.88			$	1.82			$	1.66

Incentive Distribution Rights

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

If for any quarter:

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

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

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Subordinated Units

Until May 22, 2007, we had Class B units, a separate class of subordinated units representing limited partner interests in us that were issued to PVG in connection with PVG’s initial public offering. On May 22, 2007, all of our Class B units automatically converted into common units on a one-for-one basis and no Class B units remain outstanding.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner has the right, which it may assign in whole or in part to any of its affiliates or us, but not the obligation, to acquire all of the remaining common units held by unaffiliated persons as of a record date to be selected by our general partner, on at least ten but not more than 60 days’ notice, at a price equal to the greater of (i) the average of the daily closing prices of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed.

As a result of this right of our general partner, a holder of common units may have his or her common units purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his or her units in the market.

As of February 22, 2010, PVG and its affiliates owned 19,587,049 common units, representing approximately 37% of our outstanding common units.

Certain Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Penn Virginia and PVG), on the one hand, and us and our unitholders, on the other hand. Our general partner is controlled by PVG, which is in turn controlled by Penn Virginia. Accordingly, PVG (and Penn Virginia indirectly) has the ability to elect, remove and replace the directors and officers of our general partner. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners, Penn Virginia and PVG. At the same time, our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders.

Certain of the executive officers and non-independent directors of our general partner also serve as executive officers and directors of Penn Virginia or the general partner of PVG. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to Penn Virginia or PVG, on the one hand, and us, on the other hand, are in conflict.

Limits on Fiduciary Responsibilities

Our partnership agreement limits the liability and reduces the fiduciary duties owed by our general partner to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duty.

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement permits our general partner to make a number of decisions in its sole discretion. This entitles our general partner to consider only the interests and factors that it desires and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Other provisions of the partnership agreement provide that our general partner’s actions must be made in its reasonable discretion. These standards reduce the obligations to which our general partner would otherwise be held.

Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be “fair and reasonable” to us under the factors previously set forth. In determining whether a transaction or resolution is “fair and reasonable” our general partner may consider the interests of all parties involved, including its own. Unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty. These standards reduce the obligations to which our general partner would otherwise be held.

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In order to become a limited partner of our partnership, a common unitholder is required to agree to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Revised Uniform Limited Partnership Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions if our general partner and those other persons acted in good faith.

We are required by our partnership agreement to indemnify our general partner and its officers, directors, employees, affiliates, partners, members, agents and trustees to the fullest extent permitted by law against liabilities, costs and expenses incurred by our general partner or these other persons. This indemnification is required if our general partner or any of these persons acted in good faith and in a manner they reasonably believed to be in, or (in the case of a person other than our general partner) not opposed to, our best interests. Indemnification is required for criminal proceedings if our general partner or these other persons had no reasonable cause to believe their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met these requirements concerning good faith and our best interests.

Competition

Coal and Natural Resource Management Segment

The coal industry is intensely competitive primarily as a result of the existence of numerous producers. Our lessees compete with both large and small coal producers in various regions of the United States for domestic sales. The industry has undergone significant consolidation which has led to some of the competitors of our lessees having significantly larger financial and operating resources than most of our lessees. Our lessees compete on the basis of coal price at the mine, coal quality (including sulfur content), transportation cost from the mine to the customer and the reliability of supply. Continued demand for our coal and the prices that our lessees obtain are also affected by demand for electricity, demand for metallurgical coal, access to transportation, environmental and government regulations, technological developments and the availability and price of alternative fuel supplies, including nuclear, natural gas, oil and hydroelectric power. Demand for our low sulfur coal and the prices our lessees will be able to obtain for it will also be affected by the price and availability of high sulfur coal, which can be marketed in tandem with emissions allowances which permit the high sulfur coal to meet federal Clean Air Act, or CAA, requirements.

Natural Gas Midstream Segment

We experience competition in all of our natural gas midstream markets. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, process, transport and market natural gas. Many of our competitors have greater financial resources and access to larger natural gas supplies than we do.

The ability to offer natural gas producers competitive gathering and processing arrangements and subsequent reliable service is fundamental to obtaining and keeping gas supplies for our gathering systems. The primary concerns of the producer are:

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Government Regulation and Environmental Matters

The operations of our coal and natural resource management business and natural gas midstream business are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted.

Coal and Natural Resource Management Segment

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

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

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

Air Emissions.  The CAA and corresponding state and local laws and regulations affect all aspects of our business, both directly and indirectly. The CAA directly impacts our lessees’ coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants. There have been a series of recent federal rulemakings that are focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and additional measures required under Environmental Protection Agency, or EPA, laws and regulations will make it more costly to build and operate coal-fired power plants and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel alternative in the planning and building of power plants in the future. Any reduction in coal’s share of power generating capacity could negatively impact our lessees’ ability to sell coal, which could have a material effect on our coal royalties revenues.

The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade

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excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels.

The EPA has promulgated rules, referred to as the “NOx SIP Call,” that require coal-fired power plants and other large stationary sources in 21 eastern states and Washington, D.C. to make substantial reductions in nitrogen oxide emissions in an effort to reduce the impacts of ozone transport between states. Additionally, in March 2005, the EPA issued the final Clean Air Interstate Rule, or CAIR, which would have permanently capped nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. beginning in 2009 and 2010. CAIR required those states to achieve the required emission reductions by requiring power plants to either participate in an EPA-administered “cap-and-trade” program that caps emission in two phases, or by meeting an individual state emissions budget through measures established by the state. The stringency of the caps under CAIR may have required many coal-fired sources to install additional pollution control equipment, such as wet scrubbers, to comply. This increased sulfur emission removal capability required by CAIR could have resulted in decreased demand for lower sulfur coal, which may have potentially driven down prices for lower sulfur coal. On July 11, 2008, the D.C. Circuit Court of Appeals vacated CAIR in its entirety. The EPA subsequently filed a petition for rehearing or, in the alternative, for a remand of the case without vacatur. On December 23, 2008, the Court issued an opinion to remand without vacating CAIR. Therefore, CAIR will remain in effect while the EPA conducts rulemaking to modify CAIR to comply with the Court’s July 2008 opinion. The Court declined to impose a schedule by which the EPA must complete the rulemaking, but reminded the EPA that the Court does “...not intend to grant an indefinite stay of the effectiveness of this Court’s decision.” The EPA is considering its options on how to proceed.

In March 2005, the EPA finalized the Clean Air Mercury Rule, or CAMR, which was to establish a two-part, nationwide cap on mercury emissions from coal-fired power plants beginning in 2010. It was the subject of extensive controversy and litigation and, in February 2008, the U.S. Circuit Court of Appeals for the District of Columbia vacated CAMR. The EPA appealed the decision to the U.S. Supreme Court in October 2008, but withdrew its petition for certiorari on February 6, 2009. However, a utility group continues to seek certiorari, challenging the court of appeals decision to overturn CAMR. In the meantime, the EPA plans to develop standards consistent with the court of appeal’s ruling, intending to propose air toxics standards for coal- and oil-fired electric generating units by March 10, 2011, and finalize a rule by November 16, 2011. In conjunction with these efforts, on December 24, 2009, the EPA approved an Information Collection Request (ICR) requiring all U.S. power plants with coal-or oil-fired electric generating units to submit emissions information for use in developing air toxics emissions standards. In addition, various states have promulgated or are considering more stringent emission limits on mercury emissions from coal-fired electric generating units.

The EPA has adopted new, more stringent national air quality standards for ozone and fine particulate matter. As a result, some states will be required to amend their existing state implementation plans to attain and maintain compliance with the new air quality standards. In March 2007, the EPA published final rules addressing how states would implement plans to bring regions designated as non-attainment for fine particulate matter into compliance with the new air quality standard. Under the EPA’s final rule, states had until April 2008 to submit their implementation plans to the EPA for approval. Because coal mining operations and coal-fired electric generating facilities emit particulate matter, our lessees’ mining operations and their customers could be affected when the new standards are implemented by the applicable states.

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

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

Carbon Dioxide Emissions.  The Kyoto Protocol to the United Nations Framework Convention on Climate Change calls for developed nations to reduce their emissions of greenhouse gases to 5% below 1990 levels by 2012. Carbon dioxide, which is a major byproduct of the combustion of coal and other fossil fuels, is subject to the Kyoto Protocol. The Kyoto Protocol went into effect on February 16, 2005 for those nations that ratified the treaty. In 2002, the United States withdrew its support for the Kyoto Protocol, and the United States is not participating in this treaty. Since the Kyoto Protocol became effective, there has been increasing international pressure on the United States to adopt mandatory restrictions on carbon dioxide emissions. In addition, on April 2, 2007 the U.S. Supreme Court held in Massachusetts v. EPA that unless the EPA affirmatively concludes that greenhouse gases are not causing climate change, the EPA must regulate greenhouse gas emissions from new automobiles under the CAA. The Court remanded the matter to the EPA for further consideration. This litigation did not directly concern the EPA’s authority to regulate greenhouse gas emissions from stationary sources, such as coal mining operations or coal-fired power plants. However, the Court’s decision is likely to influence another lawsuit currently pending in the U.S. Court of Appeals for the District of Columbia Circuit, involving a challenge to the EPA’s decision not to regulate carbon dioxide from power plants and other stationary sources under a CAA new source performance standard rule, which specifies emissions limits for new facilities. The court remanded that question to the EPA for further consideration in light of the ruling in Massachusetts v. EPA. On July 11, 2008, the EPA released an advanced notice of proposed rulemaking to regulate greenhouse gases under the CAA in response to the ruling in Massachusetts v. EPA. The notice did not contain a definitive proposal of what a greenhouse gas regulatory program would look like, but it presented the EPA’s analyses and policy alternatives for consideration. The EPA stated that promulgating a program under the CAA would take years to issue. In 2009, EPA took further steps toward greenhouse gas regulation under the CAA, issuing a final rule declaring that six greenhouse gases, including carbon dioxide and methane, “endanger both the public health and the public welfare of current and future generations.” The issuance of this “endangerment finding” allows the EPA to begin regulating greenhouse gas emissions under existing provisions of CAA. In late September and early October of 2009, in anticipation of the issuance of the endangerment finding, the EPA officially proposed two sets of rules regarding possible future regulation of greenhouse gas emissions under the CAA, one that would regulate greenhouse gas emissions from motor vehicles and the other greenhouse gas emissions from large stationary sources such as power plants or industrial facilities. Any decision in this case or any regulatory action by the EPA limiting greenhouse gas emissions from power plants could impact the demand for our coal, which could have an adverse effect on our coal royalties revenues.

The permitting of a number of proposed new coal-fired power plants has also recently been contested by environmental organizations for concerns related to greenhouse gas emissions from new plants. For instance, in October 2007, state regulators in Kansas became the first to deny an air emissions construction permit for a new coal-fired power plant based on the plant’s projected emissions of carbon dioxide. State regulatory authorities in Florida and North Carolina have also rejected the construction of new coal-fired power plants based on the uncertainty surrounding the potential costs associated with greenhouse gas emissions from these plants under future laws limiting the emission of carbon dioxide.

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In addition, permits for several new coal-fired power plants without limits imposed on their greenhouse gas emissions have been appealed by environmental organizations to the EPA’s Environmental Appeals Board, or EAB, and other judicial forums under the CAA. For example, in June 2008, a Georgia court voided a CAA permit and halted the construction of a coal-fired power plant for failure to address carbon dioxide emissions. Likewise, in November 2008, in another case, In re Deseret Power Electric Cooperative, the EAB remanded the permitting decision back to the Region to reopen the record and reconsider whether carbon dioxide is a pollutant subject to regulation under the CAA with instructions to consider its nationwide implications. In December 2008, the EPA Administrator issued an interpretive rule determining that the phrase in the CAA “not subject to regulation” does not include pollutants for which only monitoring and reporting is required. Because carbon dioxide is such a pollutant, this interpretive rule has the effect of precluding any consideration of carbon dioxide emissions in connection with federal permitting under the CAA. Environmental groups filed a Petition for Reconsideration of the interpretive rule. On February 17, 2009, the EPA stated that it would grant the Petition for Reconsideration and allow public comment, but it declined to stay the effectiveness of the interpretive rule at that time.

A number of states have also either passed legislation or announced initiatives focused on decreasing or stabilizing carbon dioxide emissions associated with the combustion of fossil fuels, and many of these measures have focused on emissions from coal-fired electric generating facilities. For example, ten northeastern and mid-Atlantic states have agreed to implement a regional cap-and-trade program, referred to as the Regional Greenhouse Gas Initiative, or RGGI, to stabilize carbon dioxide emissions from regional power plants beginning in 2009. This initiative aims to reduce emissions of carbon dioxide to levels roughly corresponding to average annual emissions between 2000 and 2004. The members of RGGI agreed to seek to establish in statute and/or regulation a carbon dioxide trading program and have each state’s component of the regional program effective no later than December 31, 2008. Auctions for carbon dioxide allowances under the program began in September 2008. Following the RGGI model, seven Western states and four Canadian provinces have also formed a regional greenhouse gas reduction initiative known as the Western Regional Climate Action Initiative, which calls for an overall reduction of regional greenhouse gas emissions from major industrial and commercial sources, including fossil-fuel fired power plants, in participating states through trading of emissions credits beginning in 2012. Similarly, in 2007, six Midwestern states and one Canadian province signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions, including developing a market-based, multi-sector cap. Some states have passed laws individually. For example, in 2006, the governor of California signed Assembly Bill 32 into law, requiring the California Air Resources Board to develop regulations and market mechanisms to reduce California’s greenhouse gas emissions by 25% by 2020 with mandatory caps beginning in 2012 for significant sources. In 2007, New Jersey passed a greenhouse gas reduction that would be economy wide, requiring emissions to drop to 1990 levels by 2020 and that emissions be capped at 80% of 2006 levels by 2050.

At the federal level, legislation was introduced in Congress in 2007, 2008 and 2009 to reduce greenhouse gas emissions in the United States. Such or similar federal legislation, which generally seeks to place an economy-wide cap on emissions of greenhouse gases and would require most sources of greenhouse gas emissions to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases, could be taken up in 2010 or later years. It is possible that future federal and state initiatives to control and put a price on carbon dioxide emissions, or otherwise regulate greenhouse gas emissions, could result in increased costs associated with coal consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for coal consumption could result in some customers switching to alternative sources of fuel, which could negatively impact our lessees’ coal sales, and thereby have an adverse effect on our coal royalties revenues.

Surface Mining Control and Reclamation Act of 1977.  The Surface Mining Control and Reclamation Act of 1977, or SMCRA, and similar state statutes establish minimum national operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of mining activities. SMCRA also imposes on mine operators the responsibility of restoring the land to its original state and compensating the landowner for types of damages occurring as a

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result of mining operations, and requires mine operators to post performance bonds to ensure compliance with any reclamation obligations. Moreover, regulatory authorities may attempt to assign the liabilities of our coal lessees to another entity such as us if any of our lessees are not financially capable of fulfilling those obligations on the theory that we “owned” or “controlled” the mine operator in such a way for liability to attach. To our knowledge, no such claims have been asserted against us to date. In conjunction with mining the property, our coal lessees are contractually obligated under the terms of their leases to comply with all state and local laws, including SMCRA, with obligations including the reclamation and restoration of the mined areas by grading, shaping and reseeding the soil. Upon completion of the mining, reclamation generally is completed by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan. Additionally, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is 31.5 cents per ton on surface-mined coal and 13.5 cents per ton on underground-mined coal. This tax was set to expire on June 30, 2006, but the program was extended until September 30, 2021.

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

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

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

Clean Water Act.  Our coal lessees’ operations are regulated under the Clean Water Act, or the CWA, with respect to discharges of pollutants, including dredged or fill material into waters of the United States. Individual or general permits under Section 404 of the CWA are required to conduct dredge or fill activities in jurisdictional waters of the United States. Surface coal mining operators obtain these permits to authorize such activities as the creation of slurry ponds, stream impoundments and valley fills. Uncertainty over what legally constitutes a navigable water of the United States within the CWA’s regulatory scope may adversely impact the ability of our coal lessees to secure the necessary permits for their mining activities. Some surface mining activities require a CWA Section 404 “dredge and fill” permit under the CWA for valley fills and the associated sediment control ponds. On June 5, 2007, in response to the U.S. Supreme Court’s divided opinion in Rapanos v. United States, the EPA and the U.S. Army Corps of Engineers, or the Corps, issued joint

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guidance to EPA regions and Corps districts interpreting the geographic extent of regulatory jurisdiction under Section 404 of the CWA. Specifically, the guidance places jurisdictional water bodies into two groups: waters where the agencies will assert regulatory jurisdiction “categorically” and waters where the agencies will assert jurisdiction on a case-by-case basis following a “significant nexus analysis.” It remains to be seen how this guidance will affect the permitting process for obtaining additional permits for valley fills and sediment ponds although it is likely to add uncertainty and delays in the issuance of new permits. Some valley fill surface mining activities have the potential to impact headwater streams that are not relatively permanent, which could therefore trigger a detailed “significant nexus analysis” to determine whether a Section 404 permit would be required. Such analyses could require the extensive collection of additional field data and could lead to delays in the issuance of CWA Section 404 permits for valley fill surface mining operations.

Recent federal district court decisions in West Virginia, and related litigation filed in federal district court in Kentucky, have created additional uncertainty regarding the future ability to obtain certain general permits authorizing the construction of valley fills for the disposal of overburden from mining operations. The Corps is authorized by Section 404 of the CWA to issue “nationwide” permits for specific categories of dredging and filling activities that are similar in nature and that are determined to have minimal adverse environmental effects. Nationwide Permit 21 authorizes the disposal of dredged or fill material from surface coal mining activities into the waters of the United States. A July 2004 decision by the Southern District of West Virginia in Ohio Valley Environmental Coalition v. Bulen enjoined the Huntington District of the Corps from issuing further permits pursuant to Nationwide Permit 21. While the decision was vacated by the Fourth Circuit Court of Appeals in November 2005, it has been remanded to the District Court for the Southern District of West Virginia for further proceedings. Moreover, a similar lawsuit has been filed in the U.S. District Court for the Eastern District of Kentucky that seeks to enjoin the issuance of permits pursuant to Nationwide Permit 21 by the Louisville District of the Corps.

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

Individual CWA Section 404 permits for valley fills associated with surface mining activities are also subject to certain legal challenges and uncertainty. On September 22, 2005, in the case Ohio Valley Environmental Coalition (“OVEC”) v. United States Army Corps of Engineers, environmental group plaintiffs filed suit in the U.S. District Court for the Southern District of West Virginia challenging the Corps’ decision to issue individual CWA Section 404 permits for certain mining projects. Alex Energy, Inc., or Alex Energy, a lessee of ours that operates the Republic No. 2 Mine in Kanawha County, West Virginia, intervened as a defendant in this litigation when the plaintiffs’ amended their complaint to add the December 22, 2005 individual CWA Section 404 permit for the Republic No. 2 Mine, or the Republic No. 2 Permit. On March 23, 2007, the district court rescinded several challenged CWA Section 404 permits, including the Republic No. 2 Permit, and remanded the permit applications to the Corps for further proceedings. In addition, the district court enjoined the permit holders, including Alex Energy, from all activities authorized under the rescinded permits. As part of the OVEC litigation, the environmental groups have also challenged the CWA Section 404 permit issued to Alex Energy for the Republic No. 1 Mine, also located in Kanawha County, West Virginia.

The Corps, Alex Energy, other impacted mining companies and mining associations appealed the March 23, 2007 ruling to the U.S. Court of Appeals for the Fourth Circuit. On February 13, 2009, the Fourth Circuit reversed and vacated the District Court’s March 23, 2007 opinion and order that had rescinded the challenged permits and vacated the District Court’s injunction of activity under those permits and reversed a related order by the District Court that would have required yet additional permits under the CWA. One of the three judges dissented in part from this decision and would have upheld the decision rescinding the permits and enjoining future activity but agreed with the other two judges on the other parts of the decision. This decision may be subject to further appellate review including by the Fourth Circuit itself. We are unable to predict the outcome of any further appellate review that may be obtained.

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In December 2007, plaintiff environmental groups brought a similar suit against the issuance of a CWA Section 404 permit for a surface coal mine in the U.S. District Court for the Eastern District of Kentucky, alleging identical violations. The Corps has voluntarily suspended its consideration of the permit application in that case for agency re-evaluation. While the final outcome of these cases remains uncertain, if lawsuits challenging the use of valley fills ultimately limits or prohibits the mining methods or operations of our lessees, it could have an adverse effect on our coal royalties revenues. In addition, it is possible that similar litigation affecting recently issued, pending or future individual or general CWA Section 404 permits relevant to the mining and related operations of our lessees could adversely impact our coal royalties revenues.

In December 2008, the Department of Interior published the Excess Spoil, Coal Mine Waste and Buffers for Perennial and Intermittent Streams rule under SMCRA in part to clarify when valley fills are permitted. The rule would require a 100-foot buffer around all waters, including streams, lakes, ponds and wetlands. However, the rule would exempt certain activities, such as permanent spoil fills and coal waste disposal facilities, and allow mining that changes a waterway’s flow, providing the mining company repairs damage later. Companies could also receive a permit to dispose of waste within the buffer zone if they explain why an alternative is not reasonably possible or is not necessary to meet environmental requirements. Environmental groups have brought lawsuits challenging the rule. It is unclear what impact the rule will have on the previously discussed lawsuits related to valley fills or any mining operations undertaken by our lessees in the future.

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

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

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

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

Mine Health and Safety Laws.  The operations of our coal lessees are subject to stringent health and safety standards that have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposes comprehensive health and safety standards on all mining

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operations. In addition, as part of the Mine Health and Safety Acts of 1969 and 1977, the Black Lung Acts require payments of benefits by all businesses conducting current mining operations to coal miners with black lung or pneumoconiosis and to some beneficiaries of miners who have died from this disease.

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

On June 15, 2006, the President signed the “Miner Act,” which was new mining safety legislation that mandates improvements in mine safety practices, increases civil and criminal penalties for non-compliance, requires the creation of additional mine rescue teams and expands the scope of federal oversight, inspection and enforcement activities. Pursuant to the Miner Act, the Mine Safety Health Administration, or MSHA, has promulgated new emergency rules on mine safety and revised MSHA’s civil penalty assessment regulations, which resulted in an across-the-board increase in penalties from the existing regulations. These requirements may add significant costs to our lessees’ operations, particularly for underground mines, and could affect the financial performance of our lessees’ operations.

Implementing and complying with these new laws and regulations could adversely affect our lessees’ coal production and could therefore have an adverse effect on our coal royalties revenues.

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

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

In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including our lessees, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically, our lessees submit the necessary permit applications between 12 and 24 months before they plan to begin mining a new area. In our experience, permits generally are approved within 12 months after a completed application is submitted. In the past, our lessees have generally obtained their mining permits without significant delay. Our lessees have obtained or applied for permits to mine a majority of the reserves that are currently planned to be mined over the next five years. Our lessees are also in the planning phase for obtaining permits for the additional reserves planned to be mined over the following five years. However, there are no assurances that they will not experience difficulty in obtaining mining permits in the future. See “— Coal and Natural Resource Management Segment — Clean Water Act.”

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

Natural Gas Midstream Segment

General Regulation.  Our natural gas gathering facilities generally are exempt from the Federal Energy Regulatory Commission’s, or the FERC, jurisdiction under the Natural Gas Act of 1938, or the NGA, but FERC regulation nevertheless could significantly affect our gathering business and the market for our services. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines into which our gathering pipelines deliver. However, we cannot assure you that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

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

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

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

Texas and Oklahoma administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, or the NGPSA, which requires certain natural gas pipelines to comply with safety standards in constructing and operating the pipelines, and subjects pipelines to regular inspections. We also operate a NGL pipeline that is subject to regulation by the U.S. Department of Transportation under the Hazardous Liquids Pipeline Safety Act of 1979, as amended, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. In response to recent pipeline accidents, Congress and the U.S. Department of Transportation have instituted heightened pipeline safety requirements. Certain of our gathering facilities are exempt from these federal pipeline safety requirements under the rural gathering exemption. We cannot assure you that the rural gathering exemption

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

Air Emissions.  Our natural gas midstream operations are subject to the CAA and comparable state laws and regulations. See “— Coal and Natural Resource Management Segment — Air Emissions.” These laws and regulations govern emissions of pollutants into the air resulting from the activities of our processing plants and compressor stations and also impose procedural requirements on how we conduct our natural gas midstream operations. Such laws and regulations may include requirements that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, strictly comply with the emissions and operational limitations of air emissions permits we are required to obtain or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

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

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

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

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

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

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Employees and Labor Relations

We do not have employees. To carry out our operations, our general partner and its affiliates employed 167 employees who directly supported our operations at December 31, 2009. Our general partner considers current employee relations to be favorable.

Available Information

Our internet address is http://www.pvresource.com. We make available free of charge on or through our website our Corporate Governance Principles, Code of Business Conduct and Ethics, Executive and Financial Officer Code of Ethics and Audit Committee Charter, and we will provide copies of such documents to any unitholder who so requests. We also make available free of charge on or through our website our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. All references in this Annual Report on Form 10-K to the “NYSE” refer to the New York Stock Exchange, and all references to the “SEC” refer to the Securities and Exchange Commission.

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

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Item 1A Risk Factors

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

Risks Inherent in an Investment in Us

The amount of cash that we will be able to distribute on our common units principally depends upon the amount of cash we generate from our coal and natural resource management and natural gas midstream businesses.

Under the terms of our partnership agreement, we must pay our general partner’s expenses and set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash that we will be able to distribute each quarter to our partners principally depends upon the amount of cash we can generate from our coal and natural resource management and natural gas midstream businesses. The amount of cash we will generate will fluctuate from quarter to quarter based on, among other things:

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

Because of these factors, we may not have sufficient available cash each quarter to continue paying distributions at their current level or at all. The amount of cash that we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record profits.

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

While we are permitted by our partnership agreements to incur debt to pay distributions to our unitholders, our payment of principal and interest on such indebtedness will reduce our cash available for distribution to our unitholders. Furthermore, our debt agreement, which currently consists solely of the revolving credit facility, or Revolver, contains covenants limiting our ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to our partners. The Revolver also contains covenants requiring us not to exceed certain specified financial ratios. We are prohibited from making any distribution to our partners if such distribution would cause an event of default or otherwise violate a covenant under the Revolver. Additionally, the Revolver is secured by substantially all of our assets, and if we are unable to satisfy our obligations thereunder, the lenders could seek to foreclose on our assets. The lenders may also sell substantially all of our assets under such foreclosure or other realization upon those encumbrances without prior approval of our unitholders, which would adversely affect the price of our common units. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Long-Term Debt,” for more information about the Revolver.

Our unitholders do not elect our general partner or vote on our general partner’s directors. The owner of our general partner owns a sufficient number of common units to allow it to prevent the removal of our general partner.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders do not have the ability to elect our general partner or the directors of our general partner and will have no right to elect our general partner or the directors of our general partner on an annual or other continuing basis in the future. The board of directors of our general partner, including our independent directors, is chosen by PVG, its sole member. Furthermore, if our public unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Our general partner may not be removed except upon the vote of the holders of at least two-thirds of the outstanding common units. Because PVG owns more than one-third of our outstanding units, our general partner currently cannot be removed without its consent. As a result of these provisions, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

Our general partner may cause us to issue additional common units or other equity securities without the approval of our unitholders, which would dilute their ownership interests and may increase the risk that we will not have sufficient available cash to maintain or increase our cash distributions.

Our general partner may cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval. The issuance of additional common units or other equity securities of equal rank will have the following effects:

The control of our general partner may be transferred to a third party who could replace our current management team, in either case, without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, PVG, the owner of our general partner, may transfer its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner and to control the decisions taken by the board of directors and officers.

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Our unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.

Under Delaware law, our unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders as a group to remove or replace our general partner, to approve some amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in the “control” of our business. Additionally, the limitations on the liability of holders of limited partner interests for the liabilities of a limited partnership have not been clearly established in many jurisdictions.

Furthermore, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Our partnership agreement restricts the rights of unitholders owning 20% or more of our units.

Our unitholders’ voting rights are restricted by the provision in our partnership agreement generally providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of the general partner, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction of our management. As a result of these provisions, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

If Penn Virginia sells all or a part of its remaining partner interests in PVG, our strategic and operational objectives may change.

In September 2009, Penn Virginia sold approximately one-third of its limited partner interest in PVG, constituting approximately 26% of PVG’s common units. Following such sale, Penn Virginia owned the general partner interest in PVG and approximately 51% of PVG’s common units. Penn Virginia may sell all or part of its remaining partner interests in PVG without our or PVG’s consent or the consent of our or PVG’s unitholders.

Several of the members of our and PVG’s management team, including the Chief Executive Officer and Chief Financial Officer of our general partner and PVG’s general partner, are also members of Penn Virginia’s management team. If Penn Virginia sells all or a significant part of its remaining partner interests in PVG, our general partner and PVG’s general partner may replace some or all of those officers with new members of a management team that may have different strategic or operational objectives for us or PVG. A change in strategic or operational objectives could affect our results of operations and cash available for distribution.

Risks Related to Conflicts of Interest

Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner has limited fiduciary duties to us and our unitholders, which may permit it to favor its own interests to the detriment of us and our unitholders.

Penn Virginia and its affiliates, including PVG, own an approximately 37% limited partner interest in us and own and control our general partner. Conflicts of interest may arise between our general partner and its affiliates (including Penn Virginia and PVG), on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

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The fiduciary duties of our general partner’s officers and directors may conflict with those of PVG’s general partner, and our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to us.

Our general partner’s officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our unitholders and the owner of our general partner, PVG. However, three of our general partner’s eight directors and three of its five officers are also directors or officers of PVG’s general partner, which has fiduciary duties to manage the business of PVG in a manner beneficial to PVG and its unitholders, including Penn Virginia. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to us on the one hand, and PVG, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

In addition, our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute a breach of our general partner’s fiduciary duties owed to unitholders. By purchasing our units, our unitholders are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

We may face conflicts of interest in the allocation of administrative time among Penn Virginia’s business, PVG’s business and our business.

Our general partner shares administrative personnel with Penn Virginia and PVG’s general partner to operate Penn Virginia’s business, PVG’s business and our business. Our general partner’s officers, who are also the officers of PVG’s general partner and/or Penn Virginia, will have responsibility for overseeing the allocation of time spent by administrative personnel on our behalf and on behalf of PVG and/or Penn Virginia. These officers face conflicts regarding these time allocations that may adversely affect our results of operations, cash flows and financial condition. It is unlikely that these allocations will be the result of arms-length negotiations among Penn Virginia, PVG’s general partner and our general partner.

Our general partner has a call right that may require our unitholders to sell their common units at an undesirable time or price.

If at any time more than 80% of our outstanding common units are owned by our general partner and its affiliates, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or us, but not the obligation, to acquire all, but not less than all, of the remaining units held by unaffiliated persons at a price equal to the greater of (i) the average of the daily closing prices of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his or her units in the market. Affiliates of our general partner currently own approximately 37% of our outstanding common units.

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Risks Related to Our Coal and Natural Resource Management Business

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

We depend on our lessees to effectively manage their operations on our properties. Our lessees make their own business decisions with respect to their operations, including decisions relating to:

If our lessees do not manage their operations well, or if they experience financial difficulties, their production could be reduced, which would result in lower coal royalties revenues to us and could have a material adverse effect on our business, results of operations or financial condition.

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

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

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

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

A substantial or extended decline in coal prices from recent levels could have a material adverse effect on our lessees’ operations (including mine closures) and on the quantities of coal that may be economically produced from our properties. In addition, because a majority of our coal royalties are derived from coal mined on our properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price, our coal royalties revenues could be reduced by such a decline. Such a decline could also reduce our coal services revenues and the value of our coal reserves. Additionally, volatility in coal prices could make it difficult to estimate with precision the value of our coal reserves and any coal reserves that we may consider for acquisition. The future state of the global economy, including financial and credit markets on coal production levels and prices is uncertain. Depending on the longevity and ultimate severity of this downturn, demand for coal may decline, which could adversely effect production and pricing for coal mined by our lessees, and, consequently, adversely effect the royalty income received by us.

We depend on a limited number of primary operators for a significant portion of our coal royalties revenues and the loss of or reduction in production from any of our major lessees would reduce our coal royalties revenues.

We depend on a limited number of primary operators for a significant portion of our coal royalties revenues. In the year ended December 31, 2009, five primary operators, each with multiple leases, accounted for 61% of our coal royalties revenues and 11% of our total consolidated revenues. If any of these operators enters bankruptcy or decides to cease operations or significantly reduces its production, our coal royalties revenues would be reduced.

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

Our coal business will be adversely affected if we are unable to replace or increase our coal reserves through acquisitions.

Because our reserves decline as our lessees mine our coal, our future success and growth depends, in part, upon our ability to acquire additional coal reserves that are economically recoverable. The current state of the global economy, including financial markets, and the consequential adverse effect on credit availability is adversely impacting our access to new capital and credit availability. Depending on the longevity and ultimate severity of this downturn, our ability to make acquisitions may be significantly adversely affected. If we are unable to negotiate purchase contracts to replace or increase our coal reserves on acceptable terms, our coal royalties revenues will decline as our coal reserves are depleted and we could, therefore, experience a material adverse effect on our business, results of operations or financial condition. If we are able to acquire additional coal reserves, there is a possibility that any acquisition could be dilutive to earnings and reduce our ability to make distributions to unitholders or to pay interest on, or the principal of, our debt obligations. Any debt we incur to finance an acquisition may similarly affect our ability to make distributions to unitholders or to pay interest on, or the principal of, our debt obligations. Our ability to make acquisitions in the future also could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.

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

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

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

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

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

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

One of our lessees has one mine operated by unionized employees. This mine was our third largest mine on the basis of coal production for the year ended December 31, 2009. All of our lessees could become increasingly unionized in the future. If some or all of our lessees’ non-unionized operations were to become unionized, it could adversely affect their productivity and increase the risk of work stoppages. In addition, our lessees’ operations may be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our lessees’ operations. Any further unionization of our lessees’ employees could adversely affect the stability of production from our coal reserves and reduce our coal royalties revenues.

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

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

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

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

According to the U.S. Department of Energy, domestic electric power generation accounted for approximately 89% of domestic coal consumption in 2008. The amount of coal consumed for domestic electric power generation is affected primarily by the overall demand for electricity, the price and availability of competing fuels for power plants such as nuclear, natural gas, fuel oil and hydroelectric power and environmental and other governmental regulations. We believe that most new power plants will be built to produce electricity during peak periods of demand. Many of these new power plants will likely be fired by natural gas because of lower construction costs compared to coal-fired plants and because natural gas is a cleaner burning fuel. The increasingly stringent requirements of the CAA may result in more electric power generators shifting from coal to natural gas-fired power plants. See Item 1, “Business — Government Regulation and Environmental Matters — Coal and Natural Resource Management Segment — Air Emissions.”

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

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

Concerns about the environmental impacts of fossil-fuel emissions, including perceived impacts on global climate change, are resulting in increased regulation of emissions of greenhouse gases in many jurisdictions and increased interest in and the likelihood of further regulation, which could significantly affect our coal royalties revenues.

Global climate change continues to attract considerable public and scientific attention. Several widely publicized scientific reports have engendered widespread concern about the impacts of human activity, especially fossil fuel combustion, on global climate change. Legislative attention in the United States is being paid to global climate change and to reducing greenhouse gas emissions, particularly from coal combustion by power plants. Such legislation was introduced in Congress in the last several years to reduce greenhouse gas emissions in the United States and further proposals or amendments are likely to be offered in the future. In anticipation of EPA’s endangerment finding regarding greenhouse gas emissions (which was finalized in December 2009), the agency proposed two sets of rules regarding possible future regulation of greenhouse gas emissions under the CAA. While the first proposes to regulate greenhouse gas emissions from motor vehicles, the other targets greenhouse gas emissions from large stationary sources such as power plants or industrial facilities. Several states have also either passed legislation or announced initiatives focused on decreasing or stabilizing carbon dioxide emissions associated with the combustion of fossil fuels, and many of these measures have focused on emissions from coal-fired power plants. See Item 1, “Business — Governmental Regulation and Environmental Matters — Coal and Natural Resource Management Segment — Air Emissions.” Enactment of laws, passage of regulations regarding greenhouse gas emissions by the United States or some of its states, or other actions to limit carbon dioxide emissions could result in electric generators switching from coal to other fuel sources. This may adversely affect the use of and demand for fossil fuels, particularly coal.

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

Mine operators, including our lessees, must obtain numerous permits and approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal

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

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

To dispose of mining overburden generated from surface mining activities, our lessees often need to obtain government approvals, including CWA Section 404 permits to construct valley fills and sediment control ponds. Ongoing uncertainty over which waters are subject to the CWA may adversely impact our lessees’ ability to secure these necessary permits. In addition, a 2007 decision by a U.S. District Court in West Virginia invalidated a permit issued to one of our lessees for the Republic No. 2 Mine and enjoined our lessee, Alex Energy, Inc., from taking any further actions under this permit. This ruling was appealed and the appellate court reversed and vacated the district court’s order. It is unclear if this ruling will be appealed or if the permits will be challenged on other grounds. Uncertainty over the correct legal standard for issuing Section 404 permits may lead to rulings invalidating other permits, additional challenges to various permits and additional delays and costs in applying for and obtaining new permits that could ultimately have an adverse effect on our coal royalties revenues. See Item 1, “Business — Government Regulation and Environmental Matters — Coal and Natural Resource Management Segment — Clean Water Act,” for more information about the litigation described above.

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

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

Because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry and, notwithstanding compliance efforts, we do not believe violations by our lessees can be eliminated completely. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens and, to a lesser extent, the issuance of injunctions to limit or cease operations. Our lessees may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from their operations. If our lessees are required to pay these costs and liabilities and if their financial viability is

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affected by doing so, then their mining operations and, as a result, our coal royalties revenues and our ability to make distributions, could be adversely affected.

Risks Related to Our Natural Gas Midstream Business

The success of our natural gas midstream business depends upon our ability to find and contract for new sources of natural gas supply.

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

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

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

We typically do not obtain independent evaluations of natural gas reserves dedicated to our gathering systems; therefore, volumes of natural gas on our systems in the future could be less than we anticipate.

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

A reduction in demand for NGL products by the petrochemical, refining or heating industries could materially adversely affect our business, results of operations and financial condition.

The NGL products we produce, including ethane, propane, normal butane, isobutane and natural gasoline, have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general economic conditions, new government regulations, reduced demand by consumers for products made with NGL products, increased competition from petroleum-based products due to pricing differences, mild winter weather or other reasons, could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services. Any reduced demand for our NGL products could adversely affect demand for the services we provide as well as NGL prices, which would negatively impact our results of operations and financial condition.

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

We are subject to significant risks due to fluctuations in natural gas commodity prices. During 2009, we generated a majority of our gross margin from two types of contractual arrangements under which our margin is exposed to increases and decreases in the price of natural gas and NGLs — gas purchase/keep-whole and percentage-of-proceeds arrangements. See Item 1, “Business — Contracts — Natural Gas Midstream Segment.”

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

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

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

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing operations. Readily available access to debt and equity capital and credit availability has been and continues to be critical factors in our ability to grow. The current state of the global economy, including financial markets, and the consequential adverse effect on credit availability is adversely impacting our access to new capital and credit availability. Depending on the longevity and ultimate severity of this downturn, our ability to make acquisitions may be significantly adversely affected. In the event we complete acquisitions, we

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may encounter difficulties integrating these acquisitions with our existing businesses without a loss of employees or customers, a loss of revenues, an increase in operating or other costs or other difficulties. In addition, we may not be able to realize the operating efficiencies, competitive advantages, cost savings or other benefits expected from these acquisitions. Future acquisitions might not generate increases in our cash distributions to our unitholders, and because of the capital used to complete such acquisitions, or the debt incurred, our results of operations may change significantly.

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

One of the ways we may grow our natural gas midstream business is through the construction of additions to existing gathering, compression and processing systems. The construction of a new gathering system or pipeline, the expansion of an existing pipeline through the addition of new pipe or compression and the construction of new processing facilities involve numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of significant amounts of capital. Our access to such capital is currently adversely impacted by the state of the global economy, including financial and credit markets. If we do undertake these projects, they may not be completed on schedule, or at all, or at the anticipated cost. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For example, the construction of gathering facilities requires the expenditure of significant amounts of capital, which may exceed our estimates. Generally, we may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. As a result, there is the risk that new facilities may not be able to attract enough natural gas to achieve our expected investment return, which could have a material adverse effect on our business, results of operations or financial condition.

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

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

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

We are subject to risk of loss resulting from nonpayment or nonperformance by our natural gas midstream customers. We depend on a limited number of customers for a significant portion of our natural gas midstream revenues. In 2009, 21%, 15% and 10% of our natural gas midstream segment revenues and 17%, 11% and 8% of our total consolidated revenues resulted from three of our natural gas midstream customers, Conoco, Inc., Tenaska Marketing Ventures and ONEOK Energy Marketing. Any nonpayment or nonperformance by our natural gas midstream segment customers would reduce our cash flows.

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

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

Natural gas derivative transactions may limit our potential gains and involve other risks.

In order to manage our exposure to price risks in the marketing of our natural gas and NGLs, we periodically enter into condensate, natural gas and NGL price hedging arrangements with respect to a portion

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

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

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

The accounting standards regarding hedge accounting are complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our Consolidated Financial Statements may reflect volatility due to these derivatives, even when there is no underlying economic impact at that point. In addition, it is not always possible for us to engage in a derivative transaction that completely mitigates our exposure to commodity prices. Our Consolidated Financial Statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge transaction.

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

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

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

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Federal, state or local regulatory measures could adversely affect our natural gas midstream business.

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

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

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

Our natural gas midstream business is subject to extensive environmental regulation.

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

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

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

The natural gas midstream segment has completed a number of acquisitions in recent years, including the North Texas System (Lone Star Gathering, L.P., or Lone Star). See Note 3 to the Consolidated Financial Statements for a description of our natural gas midstream segment’s material acquisitions. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the

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ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, and the resulting amount of goodwill, if any. Unforeseen changes in operations, the business environment or market conditions could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows. This could result in impairment charges being recorded in our Consolidated Statements of Income.

Tax Risks to Our Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or IRS, on this or any other matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, if our view is incorrect, or if there is a change in our business (or a change in current law), we could be treated as a corporation for federal income tax purposes or otherwise subject to taxation as an entity.

If we were treated as a corporation for federal income tax purposes for any taxable year for which the statute of limitations remains open or for any future taxable year, we would pay federal income tax on our taxable income for such years at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in our anticipated cash flow and likely cause a substantial reduction in the value of our common units. Moreover, treatment of us as a corporation would materially and adversely affect our ability to make payments on our debt.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. Specifically, the present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, at the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we are subject to an entity-level tax on the portion of our income that is generated in Texas. Specifically, the Texas margin tax is imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of such a tax on us by Texas and other states will reduce the cash available for distribution to our unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to

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taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

If the IRS contests the federal income tax positions that we take, it may adversely affect the market for our common units, and the costs of any contest will reduce cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter that affects us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may disagree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders are treated as partners to whom we allocate taxable income which could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability that results from the taxation of their share of our taxable income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If a unitholder sells his or her common units, he or she will recognize a gain or loss equal to the difference between the amount realized and the adjusted tax basis in those common units. Prior distributions to such unitholder in excess of the total net taxable income allocated to him or her, which decreased his or her tax basis in his or her common units, will, in effect, become taxable income to such unitholder if the common units are sold at a price greater than such unitholder’s tax basis in those common units, even if the price he or she receives is less than that unitholder’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income to the unitholder due to recapture items, including depreciation recapture. In addition, if a unitholder sells his or her common units, he or she may incur a tax liability in excess of the amount of cash such unitholder received from the sale because the amount realized from the sale includes a unitholder’s share of our nonrecourse liabilities.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, a significant amount of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult their tax advisor before investing in our common units.

We are registered as a tax shelter. This may increase the risk of an IRS audit of us or a unitholder.

We are registered with the IRS as a “tax shelter.” Our tax shelter registration number is 01309000001. The IRS requires that some types of entities, including some partnerships, register as “tax shelters” in response to the perception that they claim tax benefits that the IRS may believe to be unwarranted. As a result, we may be audited by the IRS and tax adjustments could be made. Any unitholder owning less than a 1% profits interest in us has very limited rights to participate in the income tax audit process. Further, any

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adjustments in our tax returns will lead to adjustments in our unitholders’ tax returns and may lead to audits of unitholders’ tax returns and adjustments of items unrelated to us. A unitholder will bear the cost of any expense incurred in connection with an examination of his or her personal tax return.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Due to a number of factors, including our inability to match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and if the IRS were to challenge this method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Although existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued.

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned common units, such unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

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

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourself using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. Our methodology may be viewed as understating the

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value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the technical termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A sale or exchange would occur, for example, if we sold our business or merged with another company, or if any of our unitholders, including Penn Virginia, PVG or any of their affiliates, sold or transferred their partner interests in us. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination would not effect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

Our unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of our unitholders to file all U.S. federal, state and local tax returns that may be required of each of them.

Item 1B Unresolved Staff Comments

We have received no written SEC staff comments regarding our periodic or current reports under the Exchange Act which were issued 180 days or more preceding the end of our 2009 fiscal year that remain unresolved.

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Item 2 Properties

Title to Properties

The following map shows the general locations of our coal reserves and related infrastructure investments and our natural gas gathering and processing systems as of December 31, 2009:

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

Facilities

We currently lease our office space in Radnor, Pennsylvania, Dallas and Houston, Texas as well as Kingsport, Tennessee. We own the field office in Charleston, West Virginia. We believe that our properties are adequate for our current needs.

Coal Reserves and Production

As of December 31, 2009, we owned or controlled approximately 829 million tons of proven and probable coal reserves located on approximately 497,000 acres (including fee and leased acreage) in Illinois, Kentucky, New Mexico, Virginia and West Virginia. Our coal reserves are in various surface and underground mine seams located on the following properties:

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

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

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

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

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

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

Our lessees mine coal using both underground and surface methods. As of December 31, 2009, our lessees operated 34 surface mines and 41 underground mines. Approximately 52% of the coal produced from our properties in 2009 came from underground mines and 48% came from surface mines. Most of our lessees use the continuous mining method in their underground mines located on our properties. In continuous mining, main airways and transportation entries are developed and remote-controlled continuous miners extract coal from “rooms,” leaving “pillars” to support the roof. Shuttle cars transport coal to a conveyor belt for transportation to the surface. In several underground mines, our lessees use two continuous miners running at the same time, also known as a supersection, to improve productivity and reduce unit costs.

One of our lessees uses the longwall mining method at two different mines to mine underground reserves. Longwall mining uses hydraulic jacks or shields, varying from four feet to twelve feet in height, to support the roof of the mine while a mobile cutting shearer advances through the coal. Chain conveyors then move the coal to a standard deep mine conveyor belt system for delivery to the surface. Continuous mining is used to develop access to long rectangular panels of coal that are mined with longwall equipment, allowing controlled caving behind the advancing machinery. Longwall mining is typically highly productive when used for large blocks of medium to thick coal seams.

Surface mining methods used by our lessees include auger and highwall mining to enhance production, improve reserve recovery and reduce unit costs. On our San Juan Basin property, a combination of the dragline and truck-and-shovel surface mining methods is used to mine the coal. Dragline and truck-and-shovel mining uses large capacity machines to remove overburden to expose the coal seams. Wheel loaders then load the coal in haul trucks for transportation to a loading facility.

Our lessees’ customers are primarily electric utilities, also referred to as “steam” markets. Coal produced from our properties is transported by rail, barge and truck, or a combination of these means of transportation. Coal from the Virginia portion of the Wise property and the Buchanan property is primarily shipped to electric utilities in the Southeast by the Norfolk Southern railroad. Coal from the Kentucky portion of the Wise property is primarily shipped to electric utilities in the Southeast by the CSX railroad. Coal from the Coal River and Spruce Laurel properties in West Virginia is shipped to steam and metallurgical customers by the CSX railroad, by barge along the Kanawha River and by truck or by a combination thereof. Coal from the Northern Appalachia properties is shipped by barge on the Monongahela River, by truck and by the CSX and Norfolk Southern railroads. Coal from the Illinois Basin properties is shipped by barge on the Green River

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and by truck. Coal from the San Juan Basin property is shipped to steam markets in New Mexico and Arizona by the Burlington Northern Santa Fe railroad. All of our properties contain and have access to numerous roads and state or interstate highways.

The following table shows our most important coal producing seams by property at December 31, 2009:

Area		Property		State		Producing Mine Types		Seam Name		Height Range (ft.)
Central Appalachia		Wise		VA, KY		Surface, Underground		Parsons		1.00 – 6.00
								Phillips		1.50 – 6.00
								Low Splint		1.00 – 5.50
								Taggart/Marker		1.50 – 9.00
								U. Wilson		1.50 – 5.50
								Kelly/Imboden		1.00 – 7.50
		Buchanan		VA		Underground		Hagy		2.50 – 3.50
		Wayland		KY		Underground		U. Elkhorn No. 2		2.33 – 4.00
		Coal River, Fields Creek		WV		Surface, Underground		Coalburg		1.00 – 11.00
								Winifrede		1.00 – 6.50
								Cedar Grove		1.00 – 5.50
								No. 2 Gas		1.50 – 8.00
		Alloy		WV		Underground		Powellton		2.50 – 4.50
		Coal River, Cabin Creek		WV		Surface		Coalburg		1.00 – 5.00
								Buffalo Creek		1.00 – 5.50
								Winifrede		1.00 – 10.00
		Coal River, West Coal River		WV		Surface, Underground		Stockton		4.00 – 12.00
								No. 2 Gas		2.50 – 4.00
		Huff Creek/Toney Fork		WV		Surface		Coalburg		5.00 – 16.00
						Underground		Chilton		3.00 – 4.00
						Underground		U. Alma		3.00 – 4.00
		Powell Mountain		VA, KY		Surface, Underground		Splint Seams		2.00 – 2.75
						Underground		Darby		2.50 – 3.00
Northern Appalachia		Federal No 2		WV		Underground		Pittsburgh		6.50 – 9.50
		Upshur				Surface		Pittsburgh		3.00 – 6.50
Illinois Basin		Green River		KY		Surface, Underground		KY No. 9		3.00 – 5.00
		Allied		KY		Underground		KY No. 9		3.00 – 5.00
San Juan Basin		Lee Ranch		NM		Surface		Cleary Seams		8.00 – 16.00

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

		Production for Year Ended December 31,
Property		2009				2008				2007
Central Appalachia			18.3				19.6				18.8
Northern Appalachia			3.8				3.6				4.2
Illinois Basin			4.7				4.6				3.8
San Juan Basin			7.5				5.9				5.7
Total			34.3				33.7				32.5

		Proven and Probable Reserves as of December 31, 2009
Property		Underground				Surface				Total				Steam				Metallurgical				Total
Central Appalachia			443.6				160.3				603.9				514.7				89.2				603.9
Northern Appalachia			23.4				—				23.4				23.4				—				23.4
Illinois Basin			154.2				9.7				163.9				163.9				—				163.9
San Juan Basin			—				37.4				37.4				37.4				—				37.4
Total			621.2				207.4				828.6				739.4				89.2				828.6

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

The following table sets forth the coal reserves we owned and leased with respect to each of our coal properties as of December 31, 2009 (tons in millions):

Property		Owned				Leased				Total Controlled
Central Appalachia			452.9				151.0				603.9
Northern Appalachia			23.4				—				23.4
Illinois Basin			133.9				30.0				163.9
San Juan Basin			33.6				3.8				37.4
Total			643.8				184.8				828.6

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

		2009				2008				2007
Reserves – beginning of year			826.8				818.4				765.4
Purchase of coal reserves			2.4				34.6				60.0
Tons mined by lessees			(34.3	)			(33.7	)			(32.5	)
Revisions of estimates and other			33.7				7.5				25.5
Reserves – end of year			828.6				826.8				818.4

Our coal reserve estimates are prepared from geological data assembled and analyzed by our general partner’s or its affiliates’ geologists and engineers. These estimates are compiled using geological data taken from thousands of drill holes, geophysical logs, adjacent mine workings, outcrop prospect openings and other sources. These estimates also take into account legal, qualitative, technical and economic limitations that may keep coal from being mined. Coal reserve estimates will change from time to time due to mining activities, analysis of new engineering and geological data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods and other factors.

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We classify low sulfur coal as coal with a sulfur content of less than 1.0%, medium sulfur coal as coal with a sulfur content between 1.0% and 1.5% and high sulfur coal as coal with a sulfur content of greater than 1.5%. Compliance coal is that portion of low sulfur coal that meets compliance standards for the CAA. As of December 31, 2009, approximately 25% of our reserves met compliance standards for the CAA and 37% were low sulfur. The following table sets forth our estimate of the sulfur content and the typical clean coal quality of our recoverable coal reserves for the period presented (tons in millions):

						Sulfur Content																				Typical Clean Coal Quality
						Reserves as of December 31, 2009																				Heat Content
Property		Compliance(1)				Low Sulfur(2)				Medium Sulfur				High Sulfur				Sulfur Unclassified				Total				BTU per Pound(3)				Sulfur (%)				Ash (%)
Central Appalachia			203.1				283.0				205.4				106.9				8.6				603.9				14,041				1.04				6.50
Northern Appalachia			—				—				—				23.4				—				23.4				12,900				2.58				8.80
Illinois Basin			—				—				—				163.9				—				163.9				11,034				2.39				8.32
San Juan Basin			—				22.1				11.5				3.8				—				37.4				9,200				0.89				17.80
Total			203.1				305.1				216.9				298.0				8.6				828.6

The following table shows the proven and probable coal reserves we leased to mine operators by property for the period presented (tons in millions):

		Proven and Probable Reserves As of December 31, 2009
Property		Total Controlled				Leased to Operators				Percentage Leased
Central Appalachia			603.9				540.2				89	%
Northern Appalachia			23.4				23.0				98	%
Illinois Basin			163.9				111.5				68	%
San Juan Basin			37.4				37.4				100	%
Total			828.6				712.1				86	%

Other Natural Resource Management Assets

Coal Preparation and Loading Facilities

We generate coal services revenues from fees we charge to our lessees for the use of our coal preparation and loading facilities, which are located in Virginia, West Virginia and Kentucky. The facilities provide efficient methods to enhance lessee production levels and exploit our reserves.

Timber and Oil and Gas Royalty Interests

We own approximately 243,000 acres of forestland in Kentucky, Virginia and West Virginia. The majority of our forestland is located on properties that also contain our coal reserves.

We own royalty interests in approximately 7.2 Bcfe of proved oil and gas reserves located in Kentucky, Virginia and West Virginia. Approximately 86% of our oil and gas royalty interests in these reserves are associated with properties acquired from Penn Virginia in 2007.

Natural Gas Midstream Systems

Our natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services.

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We own, lease or have rights-of-way to the properties where the majority of our natural gas midstream facilities are located. We also own a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

We owned six natural gas processing facilities having 400 MMcfd of total capacity as of December 31, 2009. Our natural gas midstream operations currently include four natural gas gathering and processing systems and two stand-alone natural gas gathering systems, including: (i) the Panhandle gathering and processing facilities in the Texas/Oklahoma panhandle area; (ii) the Crossroads gathering and processing facilities in East Texas; (iii) the Crescent gathering and processing facilities in central Oklahoma; (iv) the Arkoma gathering system in eastern Oklahoma; (v) the North Texas gathering and pipeline facilities in the Fort Worth Basin; and (vi) the Hamlin gathering and processing facilities in west-central Texas. These assets included approximately 4,118 miles of natural gas gathering pipelines as of December 31, 2009. In addition, we own a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin.

Panhandle System

General.  The Panhandle System is a natural gas gathering system stretching over ten counties in the Anadarko Basin of the panhandle of Texas and Oklahoma. The system consists of approximately 1,681 miles of natural gas gathering pipelines, ranging in size from two to 16 inches in diameter, and the Beaver, Spearman and Sweetwater natural gas processing plants. Included in the system is an 11-mile, 10-inch diameter, FERC-jurisdictional residue line.

In July 2009, we completed an acquisition of a natural gas processing and residue pipeline facilities in western Oklahoma for approximately $22.6 million in cash. The acquired assets included a 60 MMcfd gas processing plant located near Sweetwater, Oklahoma (the “Sweetwater” plant). Additionally, we completed a 40 MMcfd processing plant expansion in our Spearman complex that was put into service on July 31, 2009. The acquired and expanded processing facilities increased our processing capacity in the Panhandle System to 260 MMcfd. The increased processing capacity has allowed us to process gas volumes that were being bypassed due to processing capacity constraints in the Panhandle System and has alleviated pipeline pressure-related volume constraints in the eastern portion of the Panhandle System.

The Panhandle System is comprised of a number of major gathering systems and 26 related compressor stations that gather natural gas, directly or indirectly, to the Beaver, Spearman and Sweetwater plants. These include the Beaver, Perryton, Spearman, Wolf Creek/Kiowa Creek and Ellis systems. These gathering systems are located in Beaver, Ellis, Harper and Roger Mills Counties in Oklahoma and Hansford, Hemphill, Hutchinson, Lipscomb, Ochiltree and Roberts Counties in Texas.

The Beaver plant has 100 MMcfd of inlet gas capacity. The plant is capable of operating in high ethane recovery mode or in ethane rejection mode and has instrumentation allowing for unattended operation of up to 16 hours per day.

The Spearman plant has 100 MMcfd of inlet capacity. The plant is capable of operating in high ethane recovery mode or in ethane rejection mode and has instrumentation allowing for unattended operation of up to 16 hours per day.

The Sweetwater plant is capable of operating in high ethane recovery mode or in ethane rejection mode and has instrumentation allowing for unattended operation of up to 16 hours per day.

In conjunction with the acquisition of the Sweetwater plant, two new gas compressor stations were installed; one is located on the east end of the North Canadian pipeline and the other on the east end of the Hemphill pipeline.

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Natural Gas Supply and Markets for Sale of Natural Gas and NGLs.  The supply in the Panhandle System comes from approximately 203 producers pursuant to 332 contracts. The residue gas from the Beaver plant can be delivered into the Northern Natural Gas, Southern Star Central Gas or ANR Pipeline Company pipelines for sale or transportation to market. The NGLs produced at the Beaver plant are delivered into ONEOK Hydrocarbon’s pipeline system for transportation to and fractionation at ONEOK’s Conway fractionator.

The residue gas from the Spearman plant is delivered into Northern Natural Gas pipelines for sale or transportation to market. The NGLs produced at the Spearman plant are delivered into MAPCO’s (Mid-America Pipeline Company) pipeline system. MAPCO’s pipeline system has the flexibility of delivering the NGLs to either Mont Belvieu or Conway for fractionation.

The residue gas from the Sweetwater plant is delivered into Northern Natural Gas pipelines for sale or transportation to market. The NGLs produced at the Sweetwater plant are delivered into ONEOK Hydrocarbon’s pipeline system for transportation to and fractionation at ONEOK’s Conway fractionator.

Crossroads System

General.  The Crossroads System is a natural gas gathering system located in the southeast portion of Harrison County, Texas. The Crossroads System consists of approximately eight miles of natural gas gathering pipelines, ranging in size from eight to twelve inches in diameter, and the Crossroads plant. The Crossroads System also includes approximately 20 miles of six-inch NGL pipeline that transport the NGLs produced at the Crossroads plant to the Panola Pipeline.

The Crossroads plant has 80 MMcfd of inlet capacity. The plant is capable of operating in high ethane recovery mode or in ethane rejection mode and has instrumentation allowing for unattended operation of up to 16 hours per day.

Natural Gas Supply and Markets for Sale of Natural Gas and NGLs.  The natural gas on the Crossroads System originates from the Bethany Field from where we have contracted with five producers. The Crossroads System delivers the residue gas from the Crossroads plant into the CenterPoint Energy pipeline for sale or transportation to market. The NGLs produced at the Crossroads plant are delivered into the Panola Pipeline for transportation to Mont Belvieu, Texas for fractionation.

Crescent System

General.  The Crescent System is a natural gas gathering system stretching over seven counties within central Oklahoma’s Sooner Trend. The system consists of approximately 1,701 miles of natural gas gathering pipelines, ranging in size from two to 10 inches in diameter, and the Crescent natural gas processing plant located in Logan County, Oklahoma. Fifteen compressor stations are operating across the Crescent System.

The Crescent plant is a NGL recovery plant with current capacity of approximately 40 MMcfd. The Crescent facility also includes a gas engine-driven generator which is routinely operated, making the plant self-sufficient with respect to electric power. The cost of fuel (residue gas) for the generator is borne by the producers under the terms of their respective gas contracts.

Natural Gas Supply and Markets for Sale of Natural Gas and NGLs.  The gas supply on the Crescent System is primarily gas associated with the production of oil or “casinghead gas” from the mature Sooner Trend. Wells in this region producing casinghead gas are generally characterized as low volume, long-lived producers of gas with large quantities of NGLs. The supply in the Crescent System comes from approximately 256 producers pursuant to 411 contracts. The Crescent plant’s connection to the Enogex and ONEOK Gas Transportation pipelines for residue gas and the ONEOK Hydrocarbon pipeline for NGLs gives the Crescent System access to a variety of market outlets.

Hamlin System

General.  The Hamlin System is a natural gas gathering system stretching over eight counties in West Central Texas. The system consists of approximately 516 miles of natural gas gathering pipelines, ranging in size from two to 12 inches in diameter and with current capacity of approximately 20 MMcfd, and the Hamlin natural gas processing plant located in Fisher County, Texas. Eight compressor stations are operating across the system.

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Natural Gas Supply and Markets for Sale of Natural Gas and NGLs.  The gas on the Hamlin System is primarily gas associated with the production of oil or “casinghead gas.” The supply on the Hamlin System comes from approximately 143 producers pursuant to 114 contracts. The Hamlin System delivers the residue gas from the Hamlin plant into the Enbridge or Atmos pipelines. The NGLs produced at the Hamlin plant are delivered into TEPPCO’s pipeline system.

North Texas System

General.  The North Texas assets are located in the southern portion of the Fort Worth Basin of North Texas and include approximately 134 miles of gas gathering pipelines and approximately 240,000 acres dedicated by active producers. This expands the geographic scope of the natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin.

Natural Gas Supply.  The gathering and transportation infrastructure captures current and expected volumes in Johnson, Hill, Bosque, Somervell, Hamilton and Erath counties. Since the acquisition, we have averaged 18 MMcfd in gathered volumes during 2009.

Item 3 Legal Proceedings

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

Item 4 Reserved

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Part II

Market Information

Our common units are traded on the NYSE under the symbol “PVR.” The high and low sales prices (composite transactions) and distributions declared related to each fiscal quarter in 2009 and 2008 were as follows:

Quarter Ended		High				Low				Cash Distribution Declared
December 31, 2009		$	22.30			$	16.57			$	0.47
September 30, 2009		$	17.98			$	12.35			$	0.47
June 30, 2009		$	15.99			$	10.96			$	0.47
March 31, 2009		$	16.51			$	9.10			$	0.47
December 31, 2008		$	19.85			$	8.34			$	0.47
September 30, 2008		$	27.38			$	15.08			$	0.47
June 30, 2008		$	30.15			$	24.69			$	0.46
March 31, 2008		$	29.00			$	18.00			$	0.45

Equity Holders

As of February 22, 2010, there were 227 record holders and approximately 21,360 beneficial owners (held in street name) of our common units.

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

		2009				2008				2007				2006				2005(1)
		(in thousands, except per unit data)
Statement of Income Data:
Revenues(2)		$	656,704			$	881,580			$	549,445			$	517,891			$	446,348
Expenses(2)		$	548,402			$	766,338			$	431,720			$	415,071			$	368,258
Operating income		$	108,302			$	115,242			$	117,725			$	102,820			$	78,090
Net income		$	65,215			$	104,500			$	56,623			$	73,928			$	51,161
Common Unit Data:
Net income per limited partner unit, basic and diluted		$	0.76			$	1.63			$	0.92			$	1.59			$	1.21
Distributions paid		$	124,009			$	111,076			$	89,649			$	66,954			$	51,949
Distributions paid per unit		$	1.88			$	1.82			$	1.66			$	1.48			$	1.24
Balance Sheet and Other Financial Data:
Property, plant and equipment, net		$	900,844			$	895,119			$	731,282			$	556,513			$	458,782
Total assets(3)		$	1,208,060			$	1,218,819			$	931,279			$	714,023			$	657,879
Long-term debt		$	620,100			$	568,100			$	399,153			$	207,214			$	246,846
Cash flows provided by operating activities		$	159,972			$	139,176			$	127,824			$	107,344			$	93,172
Cash acquisitions and additions		$	80,677			$	332,028			$	225,040			$	129,712			$	303,673
Other Statistical Data:
Coal royalty tons (in thousands)			34,330				33,690				32,528				32,778				30,227
System throughput volumes (MMcf)			121,335				98,683				67,810				55,991				38,875

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The following discussion and analysis of the financial condition and results of operations of Penn Virginia Resource Partners, L.P. and its subsidiaries (the “Partnership,” “we,” “us” or “our”) should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Item 8. All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated.

Overview of Business

We are a publicly traded Delaware limited partnership formed by Penn Virginia in 2001 that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. Both in our current limited partnership form and in our previous corporate form, we have managed coal properties since 1882. We currently conduct operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream. In 2009, our coal and natural resource management segment contributed $87.5 million, or 81%, to operating income, and our natural gas midstream segment contributed $20.8 million, or 19%, to operating income.

As of December 31, 2009, we owned or controlled approximately 829 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. We enter into long-term leases with experienced, third-party mine operators, providing them the right to mine our coal reserves in exchange for royalty payments. We actively work with our lessees to develop efficient methods to exploit our reserves and to maximize production from our properties. We do not operate any mines. In 2009, our lessees produced 34.3 million tons of coal from our properties and paid us coal royalties revenues of $120.4 million, for an average royalty per ton of $3.51. Approximately 82% of our coal royalties revenues in 2009 were derived from coal mined on our properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of our coal royalties revenues for the respective periods was derived from coal mined on our properties under leases containing fixed royalty rates that escalate annually.

Coal royalties are impacted by several factors that we generally cannot control. The number of tons mined annually is determined by an operator’s mining efficiency, labor availability, geologic conditions, access to capital, ability to market coal and ability to arrange reliable transportation to the end-user. New legislation or regulations have been or may be adopted which may have a significant impact on the mining operations of our lessees or their customers’ ability to use coal and which may require us, our lessees or our lessees’ customers to change operations significantly or incur substantial costs. See Item 1A, “Risk Factors.”

To a lesser extent, coal prices also impact coal royalties revenues. Generally, as coal prices change over an extended period of time, our average royalty per ton may change as the majority of our lessees pay royalties based on the gross sales prices of the coal mined. However, most of our lessees’ coal is sold under contracts with a duration of one year or more; therefore, the underlying prices for our royalties are less susceptible to short-term volatility in coal prices and prices change primarily as our lessees’ long-term contracts are renegotiated.

We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees.

Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of December 31, 2009, we owned and operated natural gas midstream assets located in Oklahoma and Texas, including six natural gas processing facilities having 400 MMcfd of total capacity and approximately 4,118 miles of natural gas gathering pipelines. Our natural gas midstream business earns revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In addition, we own a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. We also own a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

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In 2009, system throughput volumes at our gas processing plants and gathering systems, including gathering-only volumes, were 121.3 Bcf, or approximately 332 MMcfd. In 2009, 21%, 15% and 10% of our natural gas midstream segment revenues and 17%, 11% and 8% of our total consolidated revenues related to three of our natural gas midstream customers, Conoco, Inc., Tenaska Marketing Ventures and ONEOK Energy Marketing.

We continually seek new supplies of natural gas to both offset the natural declines in production from the wells currently connected to our systems and to increase system throughput volumes. New natural gas supplies are obtained for all of our systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and contracting for natural gas that has been released from competitors’ systems. In 2009, our natural gas midstream segment made aggregate capital expenditures of $72.8 million, primarily related to our acquisition of the Sweetwater plant, expansion of the Spearman plant and other expansion related projects in the panhandle of Texas and Oklahoma. For a more detailed discussion of our acquisitions and investments, see “— Acquisitions and Investments.”

Key Developments

2009 Commodity Prices

The 2009 average commodity prices for coal, timber, natural gas, crude oil and NGLs declined from 2008 levels. NGLs refer to ethane, propane, iso butane, normal butane and pentane. The pricing of these commodities directly and indirectly drive our earnings.

Coal royalties, which accounted for 83% of the 2009 coal and natural resource management segment revenues, were slightly lower as compared 2008. We continue to benefit from long-term contract prices our lessees previously negotiated with their customers. However, the state of the global economy, including financial and credit markets, has reduced worldwide demand for coal with resultant price declines. Depending on the longevity and ultimate severity of the deterioration, demand for coal may continue to decline, which could adversely affect production and pricing for coal mined by our lessees.

Revenues, profitability and the future rate of growth of our natural gas midstream segment are highly dependent on market demand and prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market demand. As part of our risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. Our derivative financial instruments include costless collars and swaps. Based upon current volumes, we have entered into hedging arrangements covering approximately 58% and 37% of our commodity-sensitive volumes in 2010 and 2011. We generally target hedging 50% to 60% of our commodity-sensitive volumes covering a two-year period.

Acquisitions and Investments

In July 2009, we completed an acquisition of gas processing and residue pipeline facilities in western Oklahoma from Atlas Pipeline Partners, L.P. for approximately $22.6 million in cash. Funding for the acquisition was provided by borrowings under the Revolver. The acquired assets included a 60 MMcfd processing plant within Atlas’ 180 MMcfd Sweetwater facility. Additionally, we completed a 40 MMcfd processing plant expansion in our Spearman complex that was put into service on July 31, 2009. The acquired and expanded processing facilities increased our processing capacity in the Panhandle System to 260 MMcfd and overall processing capacity to 400 MMcfd. The increased processing capacity has allowed the natural gas midstream segment to process gas volumes that were being bypassed due to processing capacity constraints in the Panhandle System and has alleviated pipeline pressure-related volume constraints in the eastern portion of the Panhandle System.

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In July 2008, we completed the Lone Star acquisition. Lone Star’s assets are located in the southern portion of the Fort Worth Basin of North Texas and include approximately 129 miles of gas gathering pipelines and approximately 240,000 acres dedicated by active producers. The Lone Star acquisition expanded the geographic scope of the natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin. We acquired this business for approximately $164.3 million and a liability of $4.7 million, which represents the fair value of a $5.0 million guaranteed payment, plus contingent payments of $30.0 million and $25.0 million. Funding for the acquisition was provided by $80.7 million of borrowings under the Revolver, 2,009,995 PVG common units (which we purchased from two subsidiaries of Penn Virginia for $61.8 million) and 542,610 of our newly issued common units. The contingent payments will be triggered if revenues from certain assets located in a defined geographic area reach certain targets by or before June 30, 2013 and will be funded in cash or common units, at our election.

In April 2008, we acquired a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. The purchase price was $51.6 million in cash, after customary closing adjustments, and was funded with long-term debt under the Revolver.

In May 2008, we acquired fee ownership of approximately 29 million tons of coal reserves and approximately 56 MMbf of hardwood timber in western Virginia and eastern Kentucky. The purchase price was $24.5 million in cash and was funded with long-term debt under the Revolver.

Liquidity and Capital Resources

Cash Flows

On an ongoing basis, we generally satisfy our working capital requirements and fund our capital expenditures using cash generated from our operations, borrowings under the Revolver and proceeds from equity offerings. We satisfy our debt service obligations and distributions to unitholders solely using cash generated from our operations. We believe that the cash generated from our operations and our borrowing capacity will be sufficient to meet our 2010 working capital requirements, anticipated capital expenditures (other than major capital improvements or acquisitions), scheduled debt payments and distributions. However, our ability to meet these requirements in the future will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and natural gas midstream market, some of which are beyond our control.

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

		For the Year Ended December 31,
		2009				2008				2007
Cash flows from operating activities:
Net income contribution		$	65,215			$	104,500			$	56,623
Adjustments to reconcile net income to net cash provided by operating activities (summarized)			100,065				41,205				73,444
Net changes in operating assets and liabilities			(5,308	)			(6,529	)			(2,243	)
Net cash provided by operating activities			159,972				139,176				127,824
Net cash used in investing activities			(79,530	)			(331,030	)			(224,182	)
Net cash provided by (used in) financing activities			(81,267	)			181,808				104,448
Net increase (decrease) in cash and cash equivalents		$	(825	)		$	(10,046	)		$	8,090

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Cash Flows From Operating Activities

The overall increase in net cash provided by operating activities in 2009 as compared to 2008 was driven by an increase in the natural gas midstream segment’s gross margin, adjusted for the cash impact of midstream derivatives and impairments. We received a net $10.6 million in midstream derivative settlements in 2009 compared to paying a net $37.2 million in 2008. The difference in net derivative settlements relates to decreased commodity pricing and the expiration of older commodity derivatives. This increase was partially offset by a decrease in operating income, before DD&A expense and impairments from the coal and natural resource management segment primarily due to decreases in coal royalties, oil and gas royalties and other revenue.

The overall increase in net cash provided by operating activities in 2008 as compared to 2007 was primarily attributable to increased cash received from the sales of residue gas and NGLs, which was primarily due to increased system throughput volume; increased coal royalties received, which was primarily due to increased production and sales prices of coal in the Central Appalachian and Illinois Basin regions; and increased cash received from the sale of standing timber, which was due primarily to increased harvesting from our September 2007 forestland acquisition. These increases were partially offset by increased cash outflows from our natural gas midstream commodity derivative settlements.

Cash Flows From Investing Activities

Net cash used in investing activities were primarily for capital expenditures. The following table sets forth our capital expenditures programs, by segment, for the periods presented:

		Year Ended December 31,
		2009				2008
Coal and natural resource management
Acquisitions		$	2,067			$	27,075
Expansion capital expenditures			—				—
Other property and equipment expenditures			185				195
Total			2,252				27,270
Natural gas midstream
Acquisitions			27,514				259,417
Expansion capital expenditures			36,863				59,385
Other property and equipment expenditures			8,399				14,505
Total			72,776				333,307
Total capital expenditures		$	75,028			$	360,577

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

Our 2008 capital expenditures were primarily discretionary in nature and included our 25% member interest acquisition in Thunder Creek, the Lone Star acquisition, pipeline assets in the Anadarko Basin of Oklahoma and Texas, expansion capital expenditures related to the Spearman and Crossroads plants and the acquisition of approximately 29 million tons of coal reserves and an estimated 56 MMbf of hardwood timber in western Virginia and eastern Kentucky. Our natural gas midstream segment also incurred approximately $14.5 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas.

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Cash Flows From Financing Activities

During 2009, we had net borrowings of $52.0 million under the Revolver. These borrowings were used to fund our capital expenditure program. During 2008, we had net borrowings of $156.0 million primarily attributable to the Revolver offset by the repayments of $63.3 million under the Senior Unsecured Notes due 2013. In 2008 we also received net proceeds of $141.1 million from the sale of our common units in a public offering, which was comprised of net proceeds of $138.2 million from the sale of the common units to the public and $2.9 million in contributions from our general partner to maintain its 2% general partner interest. This increase in outstanding common units also increased distributions paid to our partners.

In January 2010 we declared a $0.47 ($1.88 on an annualized basis) per unit quarterly distribution for the three months ended December 31, 2009 paid on February 12, 2010 to unitholders of record at the close of business on February 2, 2010.

Sources of Liquidity

Long-Term Debt

Revolver.  As of December 31, 2009, net of outstanding borrowings of $620.1 million and letters of credit of $1.6 million, we had remaining borrowing capacity of $178.3 million on the Revolver. In March 2009, we increased the size of our Revolver from $700.0 million to $800.0 million and secured the Revolver with substantially all of our assets. The Revolver matures in December 2011 and is available to us for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10.0 million sublimit for the issuance of letters of credit. In 2009, we incurred commitment fees of $0.5 million on the unused portion of the Revolver. The interest rate under the Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 1.25% if we select the base rate borrowing option under the Revolver or at a rate derived from the London Interbank Offered Rate, or LIBOR, plus an applicable margin ranging from 1.75% to 2.75% if we select the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under the Revolver during 2009 was approximately 2.7%. We do not have a public credit rating for the Revolver. A discussion of the applicable covenants and related compliance with respect to the Revolver is provided in the discussion of Financial Condition that follows.

Interest Rate Swaps.  We have entered into interest rate swaps, or Interest Rate Swaps, to establish fixed rates on a portion of the outstanding borrowings under the Revolver. The following table sets forth the Interest Rate Swap positions at December 31, 2009 (in millions):

Dates		Notional Amounts				Weighted-Average Fixed Rate
Until March 2010		$	310.0				3.54	%
March 2010 – December 2011		$	250.0				3.37	%
December 2011 – December 2012		$	100.0				2.09	%

The Interest Rate Swaps extend one year past the maturity of the current Revolver. After considering the applicable margin of 2.25% in effect as of December 31, 2009 the total interest rate on the $310 million portion of the Revolver borrowings covered by the Interest Rate Swaps was 5.79% as of December 31, 2009.

Unit Offering

In 2008, we completed the sale of 5.15 million common units representing limited partner interests in a registered public offering and received $138.2 million in net proceeds. We received total contributions of $2.9 million from our general partner to maintain its 2% general partner interest in us. The net sales proceeds were used to repay a portion of our borrowings under the Revolver.

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Financial Condition

Covenant Compliance

The terms of the Revolver require us to maintain financial covenants. These covenants are as follows:

As of December 31, 2009, we were in compliance with all of the Revolver’s covenants. The following table summarizes the actual results of our covenant compliance for the period ended December 31, 2009:

Description of Covenant		Covenant				Actual Results
Debt to EBITDA			5.25				3.36
EBITDA to interest expense			2.50				7.50

In the event that we would be in default of our covenants under the Revolver, we could appeal to the banks for a waiver of the covenant default. Should the banks deny our appeal to waive the covenant default, the outstanding borrowings under the Revolver would become payable upon demand and would be reclassified to the current liabilities section of our Consolidated Balance Sheet. The Revolver prohibits us from making distributions to our partners if any potential default, or event of default, as defined in the Revolver, occurs or would result from the distributions.

In addition, the Revolver contains various covenants that limit our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business or enter into a merger or sale of our assets, including the sale or transfer of interests in our subsidiaries.

Future Capital Needs and Commitments

We believe that our remaining borrowing capacity of $178.3 million will be sufficient for our 2010 capital needs and commitments. Our short-term cash requirements for operating expenses and quarterly distributions to PVG, as the owner of our general partner, and unitholders are expected to be funded through operating cash flows. In 2010, we anticipate making capital expenditures, excluding acquisitions, of approximately $60.0 million. The majority of the 2010 capital expenditures are expected to be incurred in the natural gas midstream segment. We intend to fund these capital expenditures with a combination of operating cash flows and borrowings under the Revolver. Long-term cash requirements for acquisitions and other capital expenditures are expected to be funded by operating cash flows, borrowings under the Revolver and the issuances of additional debt and equity securities if available under commercially acceptable terms.

Part of our long-term strategy is to increase cash available for distribution to our unitholders by making acquisitions and other capital expenditures. Our ability to make these acquisitions and other capital expenditures in the future will depend largely on the availability of debt financing and on our ability to periodically use equity financing through the issuance of new common units. Future financing will depend on various factors, including prevailing market conditions, interest rates and our financial condition and credit rating.

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Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2009 (in thousands):

		Payments Due by Period
		Total				Less Than 1 Year				1 – 3 Years				3 – 5 Years				More Than 5 years
Revolver		$	620,100			$	—			$	620,100			$	—			$	—
Asset retirement obligations(1)			2,014				—				369				—				1,645
Interest expense(2)			30,034				15,440				14,594				—				—
Derivatives(3)			15,536				11,251				4,285				—				—
Natural gas midstream activities(4)			32,320				13,103				10,202				7,354				1,661
Rental commitments(5)			24,480				4,243				6,430				5,864				7,943
Total contractual obligations(6)		$	724,484			$	44,037			$	655,980			$	13,218			$	11,249

Part of the purchase price for the Lone Star acquisition includes contingent payments of approximately $55.0 million. These contingency payments will be made by us if certain revenue targets are met before June 30, 2013. Because the outcome of these contingent payments is not determinable beyond a reasonable doubt, we have not accrued them as a liability. Rather, once the revenue targets are met, the contingent payments will be recorded as an additional cost of the Lone Star acquisition.

We do not have employment agreements with our executive officers and do not have any other employees. Our compensation obligations with respect to our executive officers can be significantly different from one year to another and are based on variables such as our performance for the given year. For a more detailed discussion on our executive compensation, see Item 11, “Executive Compensation.”

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2009, the material off-balance sheet arrangements and transactions that we have entered into included operating lease arrangements, firm transportation agreements, and letters of credit, all of which are customary in our business. See Contractual Obligations summarized above for more detail related to the value of off-balance sheet arrangements. We did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We are, therefore, not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships.

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Results of Operations

Consolidated Review

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

		Year Ended December 31,
		2009				2008				2007
Revenues		$	656,704			$	881,580			$	549,445
Expenses			548,402				766,338				431,720
Operating income			108,302				115,242				117,725
Other income (expense)			(43,087	)			(10,742	)			(61,102	)
Net income		$	65,215			$	104,500			$	56,623

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

		Coal and Natural Resource Management				Natural Gas Midstream				Consolidated
For the Year Ended December 31, 2009:
Revenues		$	144,600			$	512,104			$	656,704
Cost of midstream gas purchased			—				406,583				406,583
Operating costs and expenses			24,231				45,842				70,073
Impairments			1,511				—				1,511
Depreciation, depletion and amortization			31,330				38,905				70,235
Operating income		$	87,528			$	20,774			$	108,302
For the Year Ended December 31, 2008:
Revenues		$	153,327			$	728,253			$	881,580
Cost of midstream gas purchased			—				612,530				612,530
Operating costs and expenses			26,226				37,615				63,841
Impairments			—				31,801				31,801
Depreciation, depletion and amortization			30,805				27,361				58,166
Operating income		$	96,296			$	18,946			$	115,242
For the Year Ended December 31, 2007:
Revenues		$	111,639			$	437,806			$	549,445
Cost of midstream gas purchased			—				343,293				343,293
Operating costs and expenses			20,138				26,777				46,915
Depreciation, depletion and amortization			22,690				18,822				41,512
Operating income		$	68,811			$	48,914			$	117,725

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Coal and Natural Resource Management Segment

Year Ended December 31, 2009 Compared With Year Ended December 31, 2008

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

		Year Ended December 31,								Favorable (Unfavorable)				% Change
		2009				2008
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
Coal royalties			5,768				9,534				3,766				40%
Other operating			2,892				2,406				(486	)			(20%)
Taxes other than income			1,704				1,680				(24	)			(1%)
General and administrative			13,867				12,606				(1,261	)			(10%)
Impairments			1,511				—				(1,511	)			—
Depreciation, depletion and amortization			31,330				30,805				(525	)			(2%)
Total expenses			57,072				57,031				(41	)			(0%)
Operating income		$	87,528			$	96,296			$	(8,768	)			(9%)
Other 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			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%
		$	120,435			$	122,834			$	(2,399	)			(2%)
Less coal royalties expenses(1)			(5,768	)			(9,534	)			3,766				(40%)
Net coal royalties revenues		$	114,667			$	113,300			$	1,367				1%
Coal royalties per ton by region ($/ton)
Central Appalachia		$	4.65			$	4.78			$	(0.13	)			(3%)
Northern Appalachia			1.83				1.84				(0.01	)			(1%)
Illinois Basin			2.63				2.28				0.35				15%
San Juan Basin			2.12				2.06				0.06				3%
		$	3.51			$	3.65			$	(0.14	)			(4%)
Less coal royalties expenses(1)			(0.17	)			(0.28	)			0.11				(39%)
Net coal royalties revenues		$	3.34			$	3.37			$	(0.03	)			(1%)

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Revenues

Coal royalties revenues decreased slightly due to the decrease in the average coal royalty received per ton. This decrease was due to an overall shift in production mix to lower royalty lessees, primarily to fixed rate leases in the San Juan Basin from the higher royalty Central Appalachian region.

Coal production by our lessees increased slightly due to higher production in the San Juan Basin resulting from the start up of a second mine and improved mining conditions. This increase was partially offset by a decline in production in the Central Appalachian region which was due to a reduction in longwall mining activity and a depressed coal market.

Timber revenues decreased due to lower sales prices resulting from weakened market conditions for furniture-grade wood products. The average price received for timber decreased 27% from $287 per Mbf in 2008 to $209 per Mbf in 2009.

The oil and gas royalty revenues decrease was primarily attributable to lower natural gas prices in 2009. Realized prices received for natural gas decreased 57% from $10.63 per Mcf in 2008 to $4.55 per Mcf in 2009.

Other revenues, which consisted primarily of wheelage fees, forfeiture income and management fees, decreased due to lower wheelage income from a decline in coal production in certain areas. In addition, in 2008, a $0.8 million gain on the settlement of unmined coal was recognized.

Expenses

Coal royalties expenses decreased due to a decline in mining activity by our lessees from subleased properties in the Central Appalachian region where our coal royalties expense is primarily incurred. Mining activity on our subleased property fluctuates between periods due to the proximity of our property boundaries and other mineral owners.

General and administrative expenses increased as a result of an uncollectible account receivable resulting from a lessee bankruptcy and increased staffing and related benefit costs.

The $1.5 million impairment expense in 2009 was the result of a reduction in the value of an intangible asset. We test long-lived assets for impairment if a triggering event occurs and the impairment was triggered by a wheelage contract being rejected in bankruptcy. As a result of the impairment, the fair value of the contract has been reduced to zero.

DD&A expenses increased slightly due to higher depletion expense resulting from the increase in coal mined from our properties by our lessees. On a per ton basis, DD&A remained constant at $0.91 per ton for both periods.

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Year Ended December 31, 2008 Compared With Year Ended December 31, 2007

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

		Year Ended December 31,								Favorable (Unfavorable)				% Change
		2008				2007
Financial Highlights
Revenues
Coal royalties		$	122,834			$	94,140			$	28,694				30%
Coal services			7,355				7,252				103				1%
Timber			6,943				1,711				5,232				306%
Oil and gas royalty			5,989				1,864				4,125				221%
Other			10,206				6,672				3,534				53%
Total revenues			153,327				111,639				41,688				37%
Expenses
Coal royalties			9,534				5,540				(3,994	)			(72%)
Other operating			2,406				2,531				125				5%
Taxes other than income			1,680				1,110				(570	)			(51%)
General and administrative			12,606				10,957				(1,649	)			(15%)
Depreciation, depletion and amortization			30,805				22,690				(8,115	)			(36%)
Total expenses			57,031				42,828				(14,203	)			(33%)
Operating income		$	96,296			$	68,811			$	27,485				40%
Other data
Coal royalty tons by region
Central Appalachia			19,587				18,827				760				4%
Northern Appalachia			3,578				4,194				(616	)			(15%)
Illinois Basin			4,584				3,779				805				21%
San Juan Basin			5,941				5,728				213				4%
Total			33,690				32,528				1,162				4%
Coal royalties revenues by region
Central Appalachia		$	93,577			$	68,815			$	24,762				36%
Northern Appalachia			6,568				6,434				134				2%
Illinois Basin			10,451				7,432				3,019				41%
San Juan Basin			12,238				11,459				779				7%
		$	122,834			$	94,140			$	28,694				30%
Less coal royalties expenses(1)			(9,534	)			(5,540	)			(3,994	)			72%
Net coal royalties revenues		$	113,300			$	88,600			$	24,700				28%
Coal royalties per ton by region ($/ton)
Central Appalachia		$	4.78			$	3.66			$	1.12				31%
Northern Appalachia			1.84				1.53				0.31				20%
Illinois Basin			2.28				1.97				0.31				16%
San Juan Basin			2.06				2.00				0.06				3%
		$	3.65			$	2.89			$	0.76				26%
Less coal royalties expenses(1)			(0.28	)			(0.17	)			(0.11	)			65%
Net coal royalties revenues		$	3.37			$	2.72			$	0.65				24%

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Revenues

Coal royalties revenues increased as a result of higher coal prices and additional tons being mined by our lessees. Coal royalty tons increased primarily due to higher production in the Central Appalachia and Illinois Basin regions, partially offset by a production decline in the Northern Appalachian region. The Central Appalachian region increase was the result of longwall mining and the timing of additional mining equipment added to our properties during 2008. The Illinois Basin region increase was primarily due to a full year of production in 2008 on coal reserves which were acquired in June 2007. The Northern Appalachian region decrease was a result of adverse longwall mining conditions.

Coal prices were higher on average due to international coal shortages on both the metallurgical and steam markets, which not only drove increases in export metallurgical pricing, but also allowed some higher thermal capacity steam coal to crossover into the metallurgical market; consequently, this caused the domestic steam coal markets to tighten and resulted in higher domestic pricing. Our coal royalties revenues are dependent on the prevailing coal prices received by our lessees, which are affected by numerous factors that are generally beyond our control. Coal prices are generally determined by national and regional supply and demand.

Timber revenues increased due to increased harvesting from our September 2007 forestland acquisition. The average price received for timber increased 20% from $240 per Mbf in 2007 to $287 per Mbf in 2008.

The oil and gas royalty revenues increase was primarily due to the increased royalties resulting from our October 2007 oil and gas royalty interest acquisition. Realized prices received for natural gas increased 31% from $8.11 per Mcf in 2007 to $10.63 per Mcf in 2008.

Other revenues increased primarily due to increased coal transportation, or wheelage, fees attributable to greater production, increased forfeiture income and the recognition of a $0.8 million gain on the settlement of unmined coal.

Expenses

Coal royalties expenses increased due to additional mining by our lessees from subleased properties in the Central Appalachian region.

Taxes other than income increased primarily due to increased severance taxes resulting from our September 2007 forestland acquisition and October 2007 oil and gas royalty interest acquisition.

General and administrative expenses increased primarily due to increased staffing and related benefit costs.

DD&A expenses increased due to increased depletion resulting from our September 2007 forestland acquisition, October 2007 oil and gas royalty interest acquisition and May 2008 coal reserves and forestland acquisition. A discussion of our DD&A methodologies is provided in the Critical Accounting Estimates that follows.

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Natural Gas Midstream Segment

Year Ended December 31, 2009 Compared With Year Ended December 31, 2008

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

		Year Ended December 31,								Favorable (Unfavorable)				% Change
		2009				2008
Financial Highlights
Revenues
Residue gas		$	289,427			$	452,535			$	(163,108	)			(36%)
Natural gas liquids			182,794				229,765				(46,971	)			(20%)
Condensate			17,010				26,009				(8,999	)			(35%)
Gathering, processing and transportation fees			15,558				11,693				3,865				33%
Total natural gas midstream revenues(1)			504,789				720,002				(215,213	)			(30%)
Equity earnings in equity investment			5,548				2,408				3,140				130%
Producer services			1,767				5,843				(4,076	)			(70%)
Total revenues			512,104				728,253				(216,149	)			(30%)
Expenses
Cost of midstream gas purchased(1)			406,583				612,530				205,947				34%
Operating			26,451				20,737				(5,714	)			(28%)
Taxes other than income			3,090				2,578				(512	)			(20%)
General and administrative			16,301				14,300				(2,001	)			(14%)
Impairments			—				31,801				31,801				100%
Depreciation and amortization			38,905				27,361				(11,544	)			(42%)
Total operating expenses			491,330				709,307				217,977				31%
Operating income		$	20,774			$	18,946			$	1,828				10%
Operating 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%

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Gross Margin

Gross margin is the difference between our natural gas midstream revenues and our cost of midstream gas purchased. Natural gas midstream revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to our gas processing plants. Cost of midstream gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts.

The gross margin decrease was a result of lower commodity pricing and lower fractionation, or frac spreads, partially offset by increased system throughput volumes and increased natural gas processing capacity. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis.

Drilling activities by producers central to our natural gas gathering and processing plants were at reduced levels from the previous year due to lower natural gas prices. However, the 2009 system throughput volumes benefited from the results of drilling activity in 2008 and the first part of 2009. The expansion and acquisition activity, especially in the Panhandle System, has alleviated pipeline pressures and allowed us to move all of our gas in this region to our processing plants. As noted above, in July 2009 we completed an acquisition of gas processing and residue pipeline facilities in western Oklahoma. The acquired assets included the 60 MMcfd Sweetwater plant. Additionally, we completed a 40 MMcfd processing plant expansion in our Spearman complex that was put into service on July 31, 2009. The acquired and expanded processing facilities increased our processing capacity in the Panhandle System to 260 MMcfd and overall processing capacity to 400 MMcfd. The increased processing capacity has allowed us to process natural gas volumes that were being bypassed due to processing capacity constraints in the Panhandle System and has alleviated pipeline pressure-related volume constraints in the eastern portion of the Panhandle.

During 2009, we generated a majority of the gross margin from contractual arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. See Item 1, “Business — Contracts — Natural Gas Midstream Segment,” for discussion of the types of contracts utilized by the natural gas midstream segment. As part of our risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. See Note 6 to the Consolidated Financial Statements for a description of our derivatives program. On a per Mcf basis, adjusted for the impact of our commodity derivative instruments, our gross margin increased in 2009 by $0.13, or 17%. This favorable impact of commodity derivatives is a result of overall lower commodity prices during 2009 and the expiration of older derivative instruments.

Revenues Other Than Gross Margin

Equity earnings in equity investment increased due to a full year of results in 2009 compared with a partial year in 2008. In April 2008, we acquired a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. In addition, revenues from the joint venture have grown in 2009 due to mainline volume increases in the Powder River Basin.

Producer services revenues decreased due to a negative relative change in the natural gas indices on which our purchases and sales of natural gas are based and a decrease in marketing fees resulting from lower commodity prices.

Expenses

Operating expenses increased due to prior and current years’ acquisitions, expansion projects, compressor rentals and labor costs. Increased costs for compressor rentals and labor costs were incurred due to expanding our footprint in the Panhandle System.

Taxes other than income increased due to higher property taxes. The increase in property taxes was a result of acquisitions and plant expansions.

General and administrative expenses increased due to increased staffing and related benefit costs. The increase was primarily attributable to labor costs resulting from the 2008 acquisitions and plant expansions. We incurred a full year of salaries and benefits in 2009 compared with a partial year in 2008.

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Impairment expense in 2008 was the result of a reduction in the value of goodwill. We test goodwill for impairment on an annual basis, at a minimum, and more frequently if a triggering event occurs. The goodwill testing during the fourth quarter of 2008 identified a goodwill impairment loss of $31.8 million. The impairment charge, which was triggered by fourth quarter declines in oil and gas spot and futures prices and a decline in our market capitalization, reduced to zero all goodwill recorded in conjunction with acquisitions made by our natural gas midstream segment in 2008 and prior years.

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

Year Ended December 31, 2008 Compared With Year Ended December 31, 2007

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

		Year Ended December 31,								Favorable (Unfavorable)				% Change
		2008				2007
Financial Highlights
Revenues
Residue gas		$	452,535			$	242,129			$	210,406				87%
Natural gas liquids			229,765				172,144				57,621				33%
Condensate			26,009				13,889				12,120				87%
Gathering, processing and transportation fees			11,693				5,012				6,681				133%
Total natural gas midstream revenues(1)			720,002				433,174				286,828				66%
Equity earnings in equity investment			2,408				—				2,408				—
Producer services			5,843				4,632				1,211				26%
Total revenues			728,253				437,806				290,447				66%
Expenses
Cost of midstream gas purchased(1)			612,530				343,293				(269,237	)			(78%)
Operating			20,737				12,893				(7,844	)			(61%)
Taxes other than income			2,578				1,926				(652	)			(34%)
General and administrative			14,300				11,958				(2,342	)			(20%)
Impairments			31,801				—				(31,801	)			—
Depreciation and amortization			27,361				18,822				(8,539	)			(45%)
Total operating expenses			709,307				388,892				(320,415	)			(82%)
Operating income		$	18,946			$	48,914			$	(29,968	)			(61%)
Operating Statistics
System throughput volumes (MMcf)			98,683				67,810				30,873				46%
Daily throughput volumes (MMcfd)			270				186				84				45%
Gross margin		$	107,472			$	89,881			$	17,591				20%
Cash impact of derivatives			(31,709	)			(13,184	)			(18,525	)			(141%)
Gross margin, adjusted for impact of derivatives		$	75,763			$	76,697			$	(934	)			(1%)
Gross margin ($/Mcf)		$	1.09			$	1.33			$	(0.24	)			(18%)
Cash impact of derivatives ($/Mcf)			(0.32	)			(0.19	)			(0.13	)			(68%)
Gross margin, adjusted for impact of derivatives ($/Mcf)		$	0.77			$	1.14			$	(0.37	)			(32%)

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Gross Margin

Gross margin is the difference between our natural gas midstream revenues and our cost of midstream gas purchased. Natural gas midstream revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to our gas processing plants. Cost of midstream gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts.

The gross margin increase was a result of higher commodity pricing, increased system throughput volume production and higher frac spreads during 2008 compared to 2007.

The system throughput volumes increase is due primarily to the Crossroads plant in East Texas, which became fully operational in 2008, and to the Lone Star acquisition, which was consummated in the third quarter of 2008. Also, the continued development by producers operating in the vicinity of the Panhandle System, as well as our success in contracting and connecting new supply contributed to the increase in throughput volume.

During 2008, we generated a majority of the gross margin from contractual arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. See Item 1, “Business — Contracts — Natural Gas Midstream Segment,” for discussion of the types of contracts utilized by the natural gas midstream segment. As part of our risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. See Note 6 to the Consolidated Financial Statements for a description of our derivatives program. On a per Mcf basis, adjusted for the impact of our commodity derivative instruments for which we discontinued hedge accounting in 2006, our gross margin decreased by $0.37, or 32%. Gross margins during the first part of 2008 continued to increase given the favorable pricing environment, such as higher commodity prices and frac spreads, and increased system throughput volumes. However, margins decreased towards the end of 2008 due to a significant decrease in the prices of NGLs as a result of reduced industrial demand in a weakening economy. The gross margin on a per Mcf basis decreased in 2008 due to an increase in fee-based system throughput volumes. These increased volumes are associated with our 2008 expansions and acquisitions.

Revenues Other Than Gross Margin

Equity earnings in equity investment increased due to our April 2008 acquisition of a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. We acquired the member interest in April 2008.

Producer services revenues increased due to an increase in agent fees for the marketing of Penn Virginia’s and third parties’ natural gas production. Agent fees increased primarily due to increases in Penn Virginia’s natural gas production as well as increases in the price of natural gas.

Expenses

Operating expenses increased due to expenses related to our expanding footprint in areas of operation, including acquisitions and the addition of the Spearman and Crossroads plants. These expenses include increased repairs and maintenance expenses, increased compressor rentals, chemical and treating expenses and increased labor costs.

Taxes other than income decreased due to higher property taxes. The increase in property taxes was a result of acquisitions and plant expansions.

General and administrative expenses increased due to increased staffing and related benefit costs. The increase in personnel was primarily attributable to acquisitions, plant expansions and well connects in established areas of operation.

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Impairment expense in 2008 was the result of a reduction in the value of goodwill. We test goodwill for impairment on an annual basis, at a minimum, and more frequently if a triggering event occurs. The goodwill testing during the fourth quarter of 2008 identified a goodwill impairment loss of $31.8 million. The impairment loss, which was triggered by fourth quarter declines in oil and gas spot and futures prices and a decline in our market capitalization, reduced to zero all goodwill recorded in conjunction with acquisitions made by our natural gas midstream segment in 2008 and prior years.

Depreciation and amortization expenses increased primarily due to capital expansions on the Spearman and Crossroads plants and acquisitions.

Other

Our other results consist of interest expense and derivative gains and losses. The following table sets forth a summary of certain financial data for our other results for the periods presented:

		Year Ended December 31,
		2009				2008				2007
Operating income		$	108,302			$	115,242			$	117,725
Other income (expense)
Interest expense			(24,653	)			(24,672	)			(17,338	)
Other			1,280				(2,907	)			1,804
Derivatives			(19,714	)			16,837				(45,568	)
Net income		$	65,215			$	104,500			$	56,623