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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, 2012

Commission file number: 1-16735

PVR Partners, L.P.

(Exact name of registrant as specified in its charter)

Three Radnor Corporate Center, Suite 301

100 Matsonford Road

Radnor, Pennsylvania 19087

(Address of principal executive offices)

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

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

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  ¨

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

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

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

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

The aggregate market value of common units held by non-affiliates of the registrant was $1,820,682,416 as of June 30, 2012 (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 directors and executive officers and holders of 5% or greater of the registrant’s common units. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of February 4, 2013, 95,635,520 common units, 22,305,788 Class B Units, and 10,346,257 Special Units representing limited partner interests of the registrant were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement being prepared for the solicitation of proxies in connection with the 2013 Annual Meeting of Unitholders are incorporated by reference in Part III of this Form 10-K.

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PVR PARTNERS, L.P. AND SUBSIDIARIES

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Forward-Looking Statements

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

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

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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.

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.

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Part I

Item 1 Business

General Overview of Business

PVR Partners, L.P. is a publicly traded Delaware limited partnership and our common units representing limited partner interests are listed on the New York Stock Exchange under the symbol “PVR.” We are principally engaged in the gathering and processing of natural gas and the management of coal and natural resource properties in the United States. We currently conduct operations in three business segments which are as follows:

Our operating income (loss) was $(4.6) million in 2012, compared to $153.6 million in 2011 and $121.6 million in 2010. In 2012, our Eastern Midstream segment contributed $25.4 million to our operating income, our Midcontinent Midstream segment reduced operating income by $(101.9) million, and our Coal and Natural Resource Management segment contributed $71.9 million 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 PVR Partners, L.P. and its subsidiaries.

In 2011, we consummated a transaction pursuant to a plan and agreement of merger (the “Merger Agreement”) with our general partner Penn Virginia Resource GP, LLC (“PVR GP”), Penn Virginia GP Holdings, L.P. (“PVG”), PVG GP LLC (“PVG GP”) and PVR Radnor, LLC (“Merger Sub”), our wholly-owned subsidiary. Pursuant to the Merger Agreement our general partner, PVG and PVG GP, were merged into Merger Sub. Subsequently, Merger Sub was merged into PVR GP, with PVR GP being the surviving entity as a subsidiary of PVR. In the transaction, PVG unitholders received consideration of 0.98 PVR common units for each PVG common unit, representing aggregate consideration of approximately 38.3 million PVR common units. The incentive distribution rights held by our general partner were extinguished, the 2% general partner interest in PVR held by PVR’s general partner was converted to a noneconomic management interest and approximated 19.6 million PVR common units owned by PVG were cancelled. The merger closed on March 10, 2011. After the effective date of the Merger and related transactions, the separate existence of each of PVG, and PVG GP and Merger Sub ceased, and PVR GP survives as a wholly-owned subsidiary of PVR.

In May 2012, we completed our purchase of the membership interests of Chief Gathering LLC (“Chief Gathering”) from Chief E&D Holdings LP, for a purchase price of approximately $1.0 billion (“Chief Acquisition”), payable in a combination of $849.3 million in cash and fair value of $191.3 million in a new class of limited partner interests in us. Chief Gathering owned and operated six natural gas gathering systems serving over 300,000 dedicated acres in the Marcellus Shale, located in the north central Pennsylvania counties of Lycoming, Bradford, Susquehanna, Sullivan, Wyoming and Greene and in Preston County, West Virginia. This transaction resulted in a major expansion of our pipeline systems in our Eastern Midstream segment.

Eastern Midstream Segment Overview

As of December 31, 2012, we owned and operated natural gas midstream assets located in Pennsylvania and West Virginia including approximately 134 miles of natural gas gathering pipelines, 83 miles of natural gas trunkline pipelines and 42 miles of fresh water pipelines. Our Eastern Midstream segment earns revenues primarily from fees charged to producers for natural gas gathering, compression and other related services. During 2010, we began construction of gathering systems in Wyoming and Lycoming Counties in Pennsylvania. In June 2010, we commenced operations on the Wyoming County system, which consists of 72 miles of gathering pipelines. In February 2011, we commenced operations on the first phase of the Lycoming County system. In April 2011, we also began construction on the second phase of the Lycoming County system, a portion of which became operational in the fourth quarter of 2011. In April of 2012, we began construction on the third phase of the Lycoming County system, which became operational by the end of the year. The Lycoming County system consists of 53 miles of 30- inch trunkline. In May of 2012, we completed the acquisition of Chief Gathering LLC, adding 120 miles of gathering pipelines, 350 MMcfd of capacity and over 300,000 dedicated acres in the Marcellus Shale to the

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Eastern Midstream segment. In the fourth quarter of 2012, we commenced operation of Wyoming Pipeline, which consists of 30 miles of 24-inch diameter natural gas trunkline. Construction and development to provide gathering, compression and related services in Lycoming and Wyoming Counties are ongoing.

In 2012, average gathered volumes on our systems were approximately 389 MMcfd, while our average trunkline volumes were approximately 197 MMcfd. These average flow rates have increased from 2011 average gathered volumes of 74 MMcfd and average trunkline volumes of 40 MMcfd. A significant volume of gas flows through both gathering and trunkline systems. The annual increase in volumes is attributed to both the Chief Acquisition and completion of internal growth projects. Gathered and trunkline volumes for the quarter ended March 31, 2012 were 210 MMcfd and 92 MMcfd, respectively. Compared with gathered and trunkline volumes of 562 MMcfd and 405 MMcfd, respectively, for the quarter ended December 31, 2012.

In September 2011, we entered into a joint venture to construct and operate a pipeline system to supply fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania. The 12-inch diameter steel pipeline largely parallels the trunkline of our existing gathering system in Lycoming County. Phases I and II of the water pipeline were placed into service in early 2012. Phase III is nearing completion and will be in service during the first quarter of 2013. A new three MMgpd pump station was commissioned in December 2012. The new pump station included a high capacity water intake on the West Branch of the Susquehanna River. As of December 31, 2012 and 2011, our contributions to the joint venture were $35.7 million and $5.3 million.

Midcontinent Midstream Segment Overview

As of December 31, 2012, we owned and operated natural gas midstream assets located in Oklahoma and Texas including six natural gas processing facilities having 460 MMcfd of total capacity and approximately 4,541 miles of natural gas gathering pipelines. Our Midcontinent Midstream natural gas 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 are a partner in a joint venture that gathers natural gas. We also own a natural gas marketing business, which aggregates third-party volumes and sells those volumes into interstate and intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

During the first quarter of 2012, we recognized a $124.8 million impairment charge related to our tangible and intangible natural gas gathering assets located in the southern portion of the Fort Worth Basin of north Texas (the “North Texas Gathering System”). This impairment was triggered by continuing market declines of natural gas prices and lack of drilling in the area. The North Texas Gathering System represented an immaterial amount of our consolidated total revenues.

During the fourth quarter of 2012, we recognized an $8.7 million impairment charge related to our 25% membership interest in the Thunder Creek joint venture located in Wyoming’s Powder River basin. The intangible assets related to this joint venture were written down to zero. This impairment was triggered by continuing market declines of natural gas prices, lack of coalbed methane drilling in the area and other market factors. Our share of the joint venture earnings, net of intangible amortization and exclusive of the impairment charge, for the year ended December 31, 2012 were $1.1 million, $2.5 million in 2011 and $6.0 million in 2010. Our share of distributions from the joint venture for the same years was $1.9 million in 2012, $8.2 million in 2011 and $7.0 million in 2010.

On July 3, 2012, we completed the sale of our Crossroads natural gas gathering system and processing plant (the “Crossroads Sale”) for net proceeds of $62.3 million. The Crossroads system, located in the southeastern portion of Harrison County in east Texas, includes approximately eight miles of gas gathering pipeline, an 80 MMcfd cryogenic processing plant, approximately 20 miles of NGL pipeline, and a 50% ownership in an approximately 11-mile gas pipeline. A gain on sale of assets of $31.3 million was recognized.

System throughput volumes at our gas processing plants and gathering systems, including gathering only volumes, were approximately 432 MMcfd in 2012, compared to 421 MMcfd in 2011.

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, 2012, we owned or controlled approximately 871 million tons of proven and probable coal reserves in Central and Northern Appalachia, the Illinois Basin and the San Juan 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 2012, our lessees produced 30.2 million tons of coal from our properties and paid

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us coal royalties revenues of $114.1 million, for an average royalty per ton of $3.78. Approximately 75% of our coal royalties revenues in 2012 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.

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

Eastern Midstream and Midcontinent Midstream Segments

Our Eastern Midstream and Midcontinent Midstream segments generate 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, 2012, our Eastern Midstream and Midcontinent Midstream businesses generated a majority of their operating income from three types of contractual arrangements: (i) fee-based, (ii) gas purchase/keep-whole and (ii) percentage-of-proceeds. A majority of the gas purchase/keep-whole and percentage-of-proceeds contracts include fee-based components such as gathering and compression charges.

In 2012, 37% of our total consolidated revenues and 34% of our December 31, 2012 consolidated accounts receivable resulted from four of our natural gas midstream customers. Within the Eastern Midstream segment for 2012, 47% of the segment’s revenues and 33% of the December 31, 2012 accounts receivable for the segment resulted from one customer. Within the Midcontinent Midstream segment for 2012, 42% of the segment’s revenues and 39% of the December 31, 2012 accounts receivable for the segment resulted from three customers.

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 reduction in drilling and development of a new supply in the areas we serve, our revenues from these arrangements would be reduced.

Gas Purchase/Keep-Whole Arrangements. 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 and economic value of the natural gas available for sale, profitability is dependent on the value of the NGLs and related residue gas being higher than the value of unprocessed natural gas. 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.

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

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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 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.

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.

Commodity Derivative Contracts. We have utilized derivative contracts to hedge against the variability in commodity prices. 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. We continually monitor commodity prices and when it is opportunistic, we may choose to manage our exposure to commodity price risk by entering into derivative 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, 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.

Partnership Distributions

Cash Distributions

We paid cash distributions of $2.10 per common unit during the year ended December 31, 2012. In the first quarter of 2013, we paid a cash distribution of $0.55 ($2.20 on an annualized basis) per common unit.

The following table reflects the allocation of total cash distributions paid by us during the years ended December 31, 2012, 2011 and 2010 (in thousands):

Paid-in-kind (“PIK”) Distributions

On May 17, 2012, we financed a portion of the Chief Acquisition by issuing 21,378,942 Class B Units. As of December 31, 2012 there were 22,305,788 Class B Units outstanding. The increase relates to PIK distributions to the holders of the Class B Units issued during the quarters ended September 30, 2012 and December 31, 2012. See Note 6, “PVR Unit Offering,” for a discussion of the distribution rights of the Class B Units.

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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. 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.

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.

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

Eastern Midstream and Midcontinent Midstream Segments

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.

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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:

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 and international 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 domestic 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. Continued demand for United States coal exports are also influenced by a number of factors including global economic conditions, weather patterns and political instability.

Government Regulation and Environmental Matters

The operations of our Eastern Midstream and Midcontinent Midstream natural gas businesses and our Coal and Natural Resource Management business are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions where we operate.

Eastern Midstream and Midcontinent Midstream Segments

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 Eastern Midstream and Midcontinent Midstream natural gas 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 might 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

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

In January 2012, President Obama signed the “Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.” The Act is primarily designed to address pipeline safety-related issues that have been brought to the forefront by a series of high profile incidents involving pipeline integrity. Among other things, the Act increases daily and maximum penalties for violations, and requires the Department of Transportation to undertake a review of state and federal regulations governing natural gas gathering lines to determine whether those regulations should be modified or applied to currently unregulated lines. The Department of Transportation must submit a report to Congress outlining the results of this review within two years of the enactment of the Act. It is not certain what impact, if any, the potential issuance of regulations will have on our natural gas gathering facilities.

Additionally, regulations applicable to the gas industry are under constant review for amendment or expansion. For example, hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations such as the Marcellus Shale. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. The EPA has commenced a study of the potential impacts of hydraulic fracturing activities. Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy (“DOE”), the U.S. Government Accountability Office and the White House Council for Environmental Quality. The U.S. Department of the Interior’s Bureau of Land Management (“BLM”) has also released proposed rules regarding well stimulation and hydraulic fracturing activities on public lands. In addition, legislation was introduced in previous sessions of Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process and could be reintroduced for consideration.

Also, some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. The requirements states have considered range from disclosure of information regarding the substances used in hydraulic fracturing to well construction and cementing regulations to setback and siting restrictions for wells employing hydraulic fracturing. For example, on June 17, 2011, Texas enacted a law that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production) and the public. Various other states have enacted similar laws. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, Pennsylvania and West Virginia have issued setback regulations for wells. Colorado recently enacted new setback restrictions as well and issued requirements to conduct sampling on water wells before and after drilling. Further, states such as Texas and Pennsylvania have water withdrawal restrictions in place that allow suspension of withdrawal rights in times of shortages while other states require reporting on the amount of water used and its source. These and other states are considering further regulation of hydraulic fracturing.

In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities in areas where we operate could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Further, the state and local governments in Pennsylvania have either considered or imposed temporary moratoriums on drilling operations using hydraulic fracturing until further study of the potential for environmental and human health impacts by the EPA or the relevant agencies are completed. No assurance can be given as to whether or not similar measures might be considered or implemented in other jurisdictions in which our gas operations plan to operate. If new laws or regulations that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in states in which we operate, such legal requirements could make it more difficult or costly for our customers to perform hydraulic fracturing activities and thereby could affect the need for our services. We do not conduct any hydraulic fracturing.

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Air Emissions. Our Eastern Midstream and Midcontinent Midstream natural gas 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 Eastern Midstream and Midcontinent Midstream natural gas 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.

On April 17, 2012, the EPA issued new standards to reduce air pollution from oil and gas drilling operations. The finalized rules establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks and other production equipment. In addition, the rules establish new leak detection requirements for natural gas processing plants at 500 ppm. These rules may require a number of modifications to our operations, including the installation of new equipment to control emissions from our compressors at initial startup, or October 15, 2012, whichever is later. Compliance with such rules could result in additional costs, including increased capital expenditures and operating costs.

Recent actions taken by the EPA have suggested that all natural gas operations operated by a single entity within a given area should be considered for aggregation for the purposes of determining the applicability of New Source Review (NSR) and Prevention of Significant Deterioration (PSD). If EPA and delegated states apply permitting requirements so that multiple current and planned facilities are aggregated for the purposes of air permitting, operations that were previously below the applicable thresholds could be classified as a major source for PSD and/or NSR, and possibly a major source for MACT applicability. An aggregated source could potentially include production wells in addition to the midstream assets considered in this review, if the production wells and midstream assets were determined to be under the control of a single company. It is possible that this aggregation of the compressor stations for air permitting purposes would make a formerly exempt facility a major facility for purposes of Title V permitting, New Source Review, and MACT applicability. However, the Sixth Circuit recently vacated an EPA determination to aggregate natural gas wells and a sweetening plant in Summit Petroleum Corp. v. EPA et al.. Subsequently, EPA released a December 21, 2012 memorandum stating that EPA will follow the court’s interpretation when considering aggregation in the Sixth Circuit, but it will continue to follow its current practice of considering interrelatedness in other jurisdictions.

Our failure to comply with existing and any future 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 Eastern Midstream and Midcontinent Midstream natural gas 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 Eastern Midstream and Midcontinent Midstream natural gas 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, and as a result, we may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which those hazardous substances have been released in the environment.

Our Eastern Midstream and Midcontinent Midstream natural gas operations generate certain 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.

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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 substances 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.

With respect to Marcellus Shale hydraulic fracturing operations, disposal of wastes from hydraulic fracturing is subject to various requirements. At present, producers can be limited to certain options for disposal of wastes. For example, on April 19, 2011, the Pennsylvania Department of Environmental Protection announced its intent to not renew permits for publicly owned treatment works (POTW) that treat municipal wastewater to accept wastewater from Marcellus Shale operators. The disposal costs for wastes from hydraulic fracturing may be significant and may have an adverse effect on the future exploration and production of natural gas using hydraulic fracturing methods, and thereby may decrease opportunities for us in these markets.

Water Discharges. Our Eastern Midstream and Midcontinent Midstream natural gas 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.

Hydraulic fracturing methods require the use of relatively large volumes of water. In Pennsylvania, Ohio, and West Virginia, permits for use of surface water are obtained from river commissions like the Delaware River Basin Commission (“DRBC”) or Susquehanna River Basin Commission. Delays in finalizing the rules governing water withdrawals for such purposes may complicate the permitting process and could in the future restrict the DRBC’s ability to issue permits for water withdrawal for hydraulic fracturing, which could have an adverse effect on our natural gas gathering operations. Additionally, states such as Texas and Pennsylvania have water withdrawal restrictions allowing suspension of withdrawal rights in times of shortages while others require reporting on the amount of water used and its source.

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

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 set requirements for 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, and the penalties assessed for violations are increasing, we do not currently expect that future compliance will have a material adverse effect on our revenues.

The costs of compliance by our lessees with all applicable federal, state and local laws and regulations have been and are expected to continue to be significant. Our 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.

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In addition, the electric 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 adversely affect demand for coal mined by our lessees. The possibility exists that new legislation or regulations, or new interpretations of existing laws or regulations, may be adopted which have a significant impact on the mining operations of 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 federal Clean Air Act (“CAA”) and corresponding state and local laws and regulations affect all aspects of coal mining operations, both directly and indirectly. The CAA directly impacts 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 and other end users of coal. There have been a series of recent federal rulemakings that are focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and additional measures required under Environmental Protection Agency, or EPA, laws and regulations will make it more costly to build and operate coal-fired power plants and, depending on the requirements of individual state implementation plans (“SIPs”), are likely to 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.

In addition to the greenhouse gas issues discussed below, the air emissions programs that may affect our lessees’ operations, directly or indirectly, include, but are not limited to, the following:

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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. 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.

Climate Change. In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for greenhouse gases, went into effect for those nations that ratified it. The United States is not participating in this treaty. However, the United States is actively participating in international discussions that are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration, with a goal of reaching a consensus on a replacement treaty. Any replacement treaty or other international arrangement requiring additional reductions in greenhouse gas emissions could have a global impact on the demand for coal.

Greenhouse gas emissions have begun to be regulated by the EPA pursuant to the CAA. In 2009, EPA issued a final rule declaring that six greenhouse gases, including carbon dioxide and methane, “endanger both the public health and the public welfare of current and future generations.” Legal challenges to these findings have been asserted, and Congress is considering legislation to delay or repeal EPA’s actions, but we cannot predict the outcome of these efforts. The EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These rules were subject to judicial challenge, but on June 26, 2012, the U.S. Court of Appeals for the District of Columbia Circuit rejected challenges to the Tailoring Rule and other EPA rules relating to the regulation of GHGs under the CAA. Among the rules promulgated after the EPA’s endangerment finding was the Tailoring Rule, which requires newly built sources emitting more than 100,000 tons of greenhouse gases per year and modified facilities increasing their emissions by at least 75,000 tons of greenhouse gases per year to undergo prevention of significant deterioration permitting (“PSD”). PSD permitting requires that the permitted entity adopt the best available control technology. On March 27, 2012, the EPA proposed New Source Performance Standards (“NSPS”) for carbon dioxide emissions from new and modified EGUs. The final NSPS, if promulgated along the lines proposed, would pose significant challenges for the construction of new coal-fired power plants and could result in a decrease in U.S. demand for steam coal.

As a result of revisions to its preconstruction permitting rules that became fully effective on January 2, 2011, EPA is now requiring new sources, including coal-fired power plants, to undergo control technology reviews for GHGs (predominately carbon dioxide) as a condition of permit issuance. These reviews may impose limits on GHG emissions, or otherwise be used to compel consideration of alternatives fuels and generation systems, as well as increase litigation risk for—and so discourage development of—coal-fired power plants.

The EPA has also adopted rules requiring the reporting of GHG emissions from specified large greenhouse gas emission sources in the United States, including coal-fired electric power plants, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

Various states and regions have adopted GHG initiatives and certain governmental bodies, including the State of California, have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities. A number of states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate

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a certain percentage of power. These and other current or future global climate change laws, regulations, court orders or other legally enforceable mechanisms may in the future require additional controls on coal-fired power plants and industrial boilers and may even cause some of our lessees’ customers to switch from coal to alternative sources of fuel. Likewise, these initiatives may restrict emissions of methane associated with coal mining. Such restrictions may increase the costs of mining and may restrict our lessees’ ability to mine certain reserves.

Surface Mining Control and Reclamation Act. The Surface Mining Control and Reclamation Act of 1977, or SMCRA, and similar state statutes establish minimum national operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of mining activities. These requirements typically are implemented through mining permits issued at the state level. SMCRA also imposes on mine operators the responsibility of restoring the land to its original state and compensating the landowner for types of damages occurring as a result of mining operations, and requires mine operators to post performance bonds to ensure compliance with any reclamation obligations. Moreover, regulatory authorities may attempt to assign the liabilities of 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. 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 federal, 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 current tax is 28 cents per ton on surface-mined coal and 12 cents per ton on underground-mined coal. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation of orphaned mine sites and abandoned mine drainage control on a statewide basis.

Federal and state laws require bonds to secure 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-bond 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.

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 our lessees from time-to-time 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.

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.”

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 releases of hazardous substances and natural resource damages. Some products used by coal companies in operations generate waste containing hazardous substances. We could be pursued under federal and state Superfund and waste management statutes if our lessees are unable to pay for environmental cleanup costs or other responses to threats to the public health or the environment. It is also 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.

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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. In June 2010, the EPA released two competing proposals for the regulation of coal combustion byproducts. One would regulate the byproducts as hazardous or special waste and the other would classify the byproducts as non hazardous waste. In April 2012, several environmental organizations filed suit against the EPA to compel the EPA to take action on the proposed rule. If EPA adopts rules to regulate the management and disposal of these by-products as hazardous wastes, additional costs associated with compliance 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 to rivers and streams, and also require dredge and fill permits under Section 404 to construct slurry ponds, stream impoundments, sediment control ponds and valley fills. The EPA issues permits for the discharge of pollutants into navigable waters while the Army Corps of Engineers, or Army Corps, issues dredge and fill permits under Section 404 of the CWA. The CWA authorizes the EPA to review 404 permits issued by the Army Corps and in 2009, EPA began reviewing 404 permits issued by the Army Corps for coal mining in Appalachia. On June 11, 2009, the EPA announced it would undertake a new level of “enhanced review” of 79 coal-related applications for 404 permits (Enhanced Coordination Procedures). On October 6, 2011, in a lawsuit challenging the legality of EPA’s actions, the U.S. District Court for the District of Columbia granted the National Mining Association’s motion for partial summary judgment rejecting the enhanced review procedures on several different legal grounds, including the lack of authority under the CWA and the failure to provide appropriate notice and comment pursuant to the Administrative Procedures Act. As a result of this decision, the Army Corps of Engineers and the EPA Regions in Appalachia have all ceased using the Enhanced Coordination Procedures. Any future application of procedures similar to the Enhanced Coordination Procedures, such as may be enacted following notice and comment rulemaking, would have the potential to delay issuance of permits for surface coal mines, or to change the conditions or restrictions imposed in those permits.

EPA also has used statutory “veto” power under Section 404(c) to effectively revoke a previously issued Section 404 permit after the EPA determined, after notice and an opportunity for a public hearing, that the permit will have an “unacceptable adverse effect.” On January 14, 2011 EPA exercised its veto power to withdraw or restrict the use of previously issued permits in connection with the Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action was the first time that such power was exercised with regard to a previously permitted coal mining project. A challenge to the EPA’s exercise of this authority was made in the federal District Court in the District of Columbia and on March 23, 2012, the Court ruled that the EPA lacked the statutory authority to invalidate an already issued Section 404 permit retroactively. This decision is currently on appeal. Any future use of the EPA’s Section 404 “veto” power could create uncertainly with regard to our lessees’ continued use of their current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our coal royalties revenues.

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

Our lessees may seek general permits under Nationwide Permit 21 (“NWP 21”) adopted by the Army Corps under its authority in Section 404 of the CWA because in February 2012, the Army Corps reinstated the use of NWP 21 in the Appalachian states where our lessees operate, but limited application of NWP 21 authorizations to discharges with impacts not greater than a half-acre of water, including no more than 300 linear feet of streambed, and disallowed the use of NWP 21 for valley fills. If these restrictions on the newly issued NWP 21 preclude its use by our lessees for any of their proposed coal mining projects, they will have to seek 404 permits on an individual basis subject to the EPA measures discussed above with the uncertainties and delays attendant to that process.

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 the damage later. Companies could also receive a permit to dispose of waste within the buffer zone if they explain why an alternative is not reasonably possible or is not necessary to meet environmental requirements. Environmental groups brought lawsuits challenging the rule and in a March 2010 settlement with litigation

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parties, the U.S. Office of Surface Mining and Reclamation (“OSM”) agreed to rewrite the “stream buffer zone rule”. The new rule has not been proposed or finalized and the OSM is currently developing an environmental impact statement for use in drafting the new rule. We are unable to predict the impact on our lessees, if any, of these actions by the OSM, although the actions potentially could result in additional delays and costs associated with obtaining permits, prohibitions or restrictions relating to mining activities near streams, and additional enforcement actions. In addition, Congress has proposed, and may in the future propose, legislation to restrict the placement of mining material in streams.

Total Maximum Daily Load, or TMDL, regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired 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. Likewise, 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. The adoption of new TMDL-related allocations or anti-degradation policies for stream near our lessees’ coal mines could lead to more stringent discharge limits, thereby requiring more costly water treatment and could adversely affect our lessees’ coal production and our coal royalties revenues.

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

Mining accidents in the last several years in West Virginia, Utah, and Kentucky have received national attention and instigated responses at the state and national level that are likely to result in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. More stringent mine safety laws and regulations promulgated by these states and the federal government have included increased sanctions for non-compliance. Other states have proposed or passed similar bills, resolutions or regulations addressing mine safety practices. Moreover, workplace accidents, such as the April 5, 2010, Upper Big Branch Mine incident, are likely to result in more stringent enforcement and possibly the passage of new laws and regulations.

In 2006, the Mine Improvement and New Emergency Response Act (“Miner Act”) was enacted which imposed obligations related to improvements in mine safety practices, increased civil and criminal penalties for non-compliance, created additional mine rescue teams and expanded the scope of federal oversight, inspection and enforcement activities. Pursuant to the Miner Act, the Mine Safety Health Administration, or MSHA, has promulgated new emergency rules on mine safety and revised MSHA’s civil penalty assessment regulations, which resulted in an across-the-board increase in penalties from the existing regulations. Since passage of the Miner Act, enforcement scrutiny has also increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and the severity of enforcement actions and related penalties. Various states also have enacted their own new laws and regulations addressing many of these same subjects. The Dodd Frank Bill that was enacted by Congress in 2010 now requires mining companies, including coal companies, to include various safety statistics regarding citations, penalties, notices of violation and pending legal actions in periodic reports that are required by the securities laws. These disclosures may lead to the enactment of yet further legislation regarding mine safety.

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

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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. We have implemented various internal standards to promote employee health and safety and comply with these laws.

Employees and Labor Relations

We do not have employees. To carry out our operations, our general partner and its affiliates employed 305 employees who directly supported our operations at December 31, 2012. Our general partner considers current employee relations to be favorable.

Available Information

Our internet address is http://www.pvrpartners.com. We make available free of charge on or through our website our Corporate Governance Principles, Code of Business Conduct and Ethics, Executive and Financial Officer Code of Ethics, Compensation and Benefits Committee Charter, Nominating and Governance Committee Charter and Audit Committee Charter, and we will provide copies of such documents to any unitholder who so requests. We also make available free of charge on or through our website our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. All references in this Annual Report on Form 10-K to the “NYSE” refer to the New York Stock Exchange, and all references to the “SEC” refer to the Securities and Exchange Commission. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with, or furnish to, the SEC.

Item 1A Risk Factors

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

Risks Inherent in an Investment in Us

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 natural gas midstream and coal and natural resource management 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 natural gas midstream and coal and natural resource management businesses. The amount of cash we will generate will fluctuate from quarter to quarter based on, among other things:

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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.

Our indebtedness may limit our ability to borrow additional funds, make distributions to our unitholders, or capitalize on acquisition or other business opportunities, in addition to impairing our ability to fulfill our debt obligations.

As of December 31, 2012, our total outstanding long-term indebtedness was approximately $1.5 billion. While we are permitted by our partnership agreement 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 leverage, various limitations in the agreements governing our revolving credit facility (“Revolver”), other restrictions governing our indebtedness and the indentures governing our senior notes (“Senior Notes”) may reduce our ability to incur additional indebtedness, to engage in some transactions and to capitalize on acquisition or other business opportunities.

Our indebtedness and other financial obligations could have important consequences. For example, they could:

If we are unable to meet our debt service obligations and other financial obligations, we could be forced to restructure or refinance our indebtedness and other financial transactions, seek additional equity capital or sell our assets. We may then be unable to obtain such financing or capital or sell our assets on satisfactory terms, if at all.

Restrictive covenants in the agreements governing our indebtedness may reduce our operating flexibility.

The indentures governing our outstanding Senior Notes and credit agreement governing our Revolver and any agreements governing our other future indebtedness contain or may contain various covenants limiting our ability and the ability of our specified subsidiaries to, among other things:

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These restrictions could limit our ability and the ability of our subsidiaries to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, conduct operations, or otherwise take advantage of business opportunities that may arise. Our Revolver contains covenants requiring us to maintain specified financial ratios and satisfy other financial conditions. We may be unable to meet those ratios and conditions. Any future breach of these covenants and our failure to meet any of those ratios and conditions could result in a default under the terms of our Revolver, which could result in the acceleration of our debt and other financial obligations. Additionally, our 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 general partner may cause us to issue additional common units or other equity securities without the approval of our unitholders, which would dilute their ownership interests and may increase the risk that we will not have sufficient available cash to maintain or increase our cash distributions.

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

Our unitholders 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.

Our partnership agreement limits the liability of the directors and officers of our general partner.

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The directors and officers of our general partner owe fiduciary duties to our unitholders. Provisions of our partnership agreement, however, contain language limiting the liability of the officers and directors of our general partner to our unitholders for actions or omissions taken in good faith which do not involve gross negligence or willful misconduct. In addition, our partnership agreement grants broad rights of indemnification to our general partner’s directors, officers, employees and affiliates.

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.

Risks Related to Our Natural Gas Eastern Midstream and Midcontinent Midstream Businesses

The success of our natural gas midstream business depends upon our ability to 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 and production 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

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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.

The profitability of certain activities in 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.

A portion of our Midcontinent Midstream natural gas business is subject to significant risks due to fluctuations in natural gas commodity prices. During 2012, our Midcontinent Midstream segment generated a portion of its revenues from two types of contractual arrangements under which our gross 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.” This risk is mitigated by our increasing volumes under fixed fee contracts.

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 and economic value of the natural gas available for sale, profitability is dependent on the value of the NGLs and related residue gas being higher than the value of unprocessed natural gas. 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 Midcontinent Midstream 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:

Future 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. Acquisitions may require substantial capital or the incurrence of substantial indebtedness and readily available access to debt and equity capital and credit availability have been and continue to be critical factors in our ability to grow. While global financial markets and economic conditions have been disrupted in the past, these conditions have improved more recently. However, if we become unable to finance our future growth expansions in a cost effective manner due to tightened capital markets we may be required to seek alternative financing strategies or revise or cancel our plans. If we consummate future acquisitions, our capitalization and results of operations may change significantly. In the event we complete acquisitions, we 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

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realize the operating efficiencies, competitive advantages, cost savings or other benefits expected from these acquisitions. Moreover, we may incur or assume unanticipated liabilities, losses, or costs associated with the businesses or assets acquired for which we are not indemnified or for which the indemnity is inadequate. 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.

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. If we do undertake these projects, they may not be completed on schedule, or at all, or at the anticipated cost. A variety of factors outside our control, such as weather, difficulties in obtaining permits or other regulatory approvals, obtaining or renewing rights-of-way, as well as performance by third party contractors, may result in increased costs or delays in construction. 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. In addition, 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 throughput or contracted capacity reservation to achieve our expected investment return, which could have a material adverse effect on our business, results of operations or financial condition.

If we do not continue to expand our pipeline systems, our future growth could be limited.

During the past several years, we have constructed several new pipelines, and are currently involved in constructing several pipeline system expansions. Our results of operations and ability to grow and to increase distributable cash flow per unit will depend, in part, on our ability to construct pipeline expansions that are accretive to our distributable cash flow. We may be unable to construct pipeline expansions that are accretive to distributable cash flow for any of the following reasons, among others:

Further, even if we construct a pipeline expansion that we believe will be accretive, the pipeline may adversely affect our results of operations or results from those projected prior to the commencement of construction.

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 2012, 37% of our total consolidated revenues and 34% of our December 31, 2012 consolidated accounts receivable resulted from four of our natural gas midstream customers. Within the Eastern Midstream segment for 2012, 47% of the segment’s revenues and 33% of the December 31, 2012 accounts receivable for the segment resulted from one customer. Within the Midcontinent Midstream segment for 2012, 42% of the segment’s revenues and 39% of the December 31, 2012 accounts receivable for the segment resulted from three customers. 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.

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Commodity 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 continually monitor commodity prices and when it is opportunistic, we may choose to enter into derivative contracts intended to hedge a portion of our expected exposure. Historically, our hedges are limited in duration, usually for periods of two years or less. These hedging transactions may limit our potential gains if commodity prices were to move in an otherwise favorable direction. We will continue to have direct commodity price risk on the portion of expected production that is not hedged. 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.

Accordingly, our Consolidated Financial Statements have reflected volatility due to 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, Oklahoma, Pennsylvania, and West Virginia, 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.

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.

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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 segments have completed a number of acquisitions in recent years. See Note 5 to the Consolidated Financial Statements for a description of our natural gas midstream segments’ material acquisitions. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, and the resulting amount of goodwill, if any. Unforeseen changes in operations, the business environment or market conditions could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows. This could result in impairment charges being recorded in our Consolidated Statements of Operations. For example, during the fiscal year ended December 31, 2012, we recognized a $124.8 million impairment charge related to our tangible and intangible natural gas gathering assets on the North Texas System. The gathering lines and customer contracts were written down to their fair value, which was determined using the income approach and discounting the estimated cash flows of the assets. This is a nonrecurring fair value measurement (see Note 7 to Consolidated Financial Statements) that was triggered by continuing market declines of natural gas prices and lack of drilling in the area.

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:

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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.

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

The domestic demand for, and price of, our coal primarily depend on coal consumption patterns of the domestic electric utility industry. Consumption by the domestic electric utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments and the price of competing coal and alternative fuel sources, such as natural gas, nuclear, hydroelectric power and other renewable energy sources. In addition, during the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. Increased competition by coal producers or producers of alternate fuels could decrease the demand for, and/or pricing of, our coal, adversely impacting demand for the coal that our lessees produce and thereby reducing our coal royalties revenues. Indirect competition from gas-fired plants that are less expensive to construct and easier to permit has the most potential to displace a significant amount of coal-fired generation in the near term, particularly for older, less efficient coal-powered generators.

The demand for U.S. coal exports is dependent upon a number of factors, including the overall demand for electricity in foreign markets, currency exchange rates, ocean freight rates, the demand for foreign-produced steel both in foreign markets and in the U.S. market (which is dependent in part on tariff rates on steel), general economic conditions in foreign

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countries, technological developments and environmental and other governmental regulations and any other pressures placed on companies that are connected to the emission of greenhouse gases. Historically, global demand for electricity and steel production has decreased during periods of economic downturn. If there is a worsening of foreign and U.S. economic and financial market conditions, and additional tightening of global credit markets, foreign demand for U.S. coal could decline, causing competition among coal producers in the United States to intensify, potentially resulting in additional downward pressure on domestic coal prices and thereby reducing our coal royalties revenues.

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

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

During 2012, weaker international and domestic economies, low natural gas prices and mild weather have impacted coal markets and market weakness is expected to continue into 2103. A substantial or extended decline in coal prices 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. 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 continue to decline, which could adversely affect production and pricing for coal mined by our lessees, and, consequently, adversely affect 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, 2012, five primary operators, each with multiple leases, accounted for 73% of our coal royalties revenues and 8% 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.

Our coal reserves decline as our lessees mine our coal and our inability to acquire additional coal reserves that are economically recoverable may have a material adverse effect on the future profitability of our coal business.

Because our reserves decline as our lessees mine our coal, we have historically expanded our coal operations by adding and developing coal reserves in existing, adjacent and neighboring properties and through acquisitions of additional coal reserves that are economically recoverable to replace the reserves we produce. 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 eventually depleted and we could, therefore, experience a material adverse effect on our business, results of operations or financial condition. As of December 31, 2012, we owned or controlled approximately 871 million tons of proven or probable coal reserves located in Kentucky, Virginia, West Virginia, Illinois and New Mexico. We anticipate that these reserves will take over 28 years to deplete, based upon 2012 production volumes. Our current business strategy does not contemplate any additional growth in our coal reserve holdings through acquisitions or investments in our existing market areas. See Item 1, “Business — Business Strategy.”

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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, 2012. 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 due to a potential increase in 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.

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

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

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There are many regulatory approaches currently in effect or being considered to address GHGs, including possible future U.S. treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program and regulation by the EPA. EPA rules require extensive regulation of GHG emissions from mobile sources and stationary sources, including imposing permitting requirements and obligations to use best available control technology for the reduction of GHG emissions whenever certain stationary sources, such as power plants, are built or significantly modified. Moreover, the EPA has updated pollution standards for fossil fuel power plants and petroleum refineries.

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

Delays in obtaining, inability to obtain, or revocation of our lessees’ mining 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 mining. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult, and may possibly preclude the continuance of ongoing mining operations or the development of future mining operations.

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, stream impoundments, and sediment control ponds. Recently, these Section 404 permits and the Section 404 permitting standard have been the target of increased scrutiny by environmental groups, legislators, the White House, and the EPA which has made it more difficult for miners to obtain, and in some cases maintain, Section 404 permits. In one case, the EPA retroactively rescinded a permit that had been issued. The U.S. Office of Surface Mining and Reclamation is in the process of rewriting the “stream buffer zone rule” which currently requires surface mining operators to minimize soil disturbances and dispose of excess mining spoil away from water sources. If the EPA promulgates a more restrictive stream buffer zone rule, any such additional requirements could impact coal mining operations, particularly in Appalachia, including, for example, by reducing locations where coal mining operations can be conducted or by further restricting common spoil disposal practices. Regulations which dramatically increase the costs of compliance or prohibit our lessees from obtaining new permits could reduce coal production and cash flows, and could ultimately have an adverse effect on our royalty revenues.

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 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. 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

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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 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.

Our lessees operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.

Our lessees operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. We could become subject to claims for toxic torts, natural resource damages and other damages as well as for the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of conditions at sites that we currently own as well as at sites that we previously owned, or may acquire. We may be held responsible for more than our share of the contamination or other damages, or even for the entire share.

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, or IRS, treats us as a corporation for U.S. federal income tax purposes or we become subject to additional amounts of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to common unitholders.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being a partnership for federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations we believe that we are treated as a partnership rather than a corporation for such purposes; however, a change in our business could cause us to be treated as a corporation for federal income tax purposes.

In addition, a change in current law may cause us to be treated as a corporation for federal income tax purposes. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. If we were subject to federal income tax as a corporation or any state were to impose a tax upon us, our cash available to pay distributions would be reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amount will be adjusted to reflect the impact of that law on us.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. 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 not agree with 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 with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.

Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners in us for federal income tax purposes we will allocate a share of our taxable income to our unitholders which could be different in amount than the cash we distribute, and our unitholders may be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they do not receive any cash distributions from us.

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

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount they realized and their tax basis in those common units. Because distributions in excess of their allocable shares of our total net taxable income result in a reduction in their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to our unitholders if they sell their units at a price greater than their tax basis in those common units, even if the price they receive is equal to their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation deductions. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if unitholders sell their units they may incur a tax liability in excess of the amount of cash they receive from the sale.

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

Investments in our common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as “IRAs”), and non-U.S. persons raise issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest applicable tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their shares of our taxable income. Tax-exempt entities and non-U.S. persons should consult their tax advisors before investing in our common units.

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

To maintain the uniformity of the economic and tax characteristics of our common units, we have adopted certain depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. These positions may result in an understatement of deductions and an overstatement of income to our unitholders. For example, we do not amortize certain goodwill assets, the value of which has been attributed to certain of our outstanding units. A subsequent holder of those units may be entitled to an amortization deduction attributable to that goodwill under Internal Revenue Code Section 743(b). But, because we cannot identify these units once they are traded by the initial holder, we do not allocate any subsequent holder of a unit any such amortization deduction. This approach may understate deductions available to those unitholders who own those units and may result in those unitholders reporting that they have a higher tax basis in their units than would be the case if the IRS strictly applied Treasury Regulations relating to these depreciation or amortization adjustments. This, in turn, may result in those unitholders reporting less gain or more loss on a sale of their units than would be the case if the IRS strictly applied those Treasury Regulations.

The IRS may challenge the manner in which we calculate our unitholder’s basis adjustment under Section 743(b). If so, because the specific unitholders to which this issue relates cannot be identified, the IRS may assert adjustments to all unitholders selling units within the period under audit. A successful IRS challenge to this position or other positions we may take could adversely affect the amount of taxable income or loss allocated to our unitholders. It also could affect the gain from a unitholder’s sale of common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. Consequently, a successful IRS challenge could have a negative impact on the value of our common units.

We prorate our items of income, gain, loss and deduction between existing unitholders and unitholders who purchase units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular 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 existing unitholders and unitholders who purchase our units based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

If you loan your units to a “short seller” to cover a short sale of units, you may be considered as having disposed of the loaned units, and you may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and you may recognize gain or loss from such disposition. During the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by you and any cash distributions you receive as to those units may be fully taxable as ordinary income. To assure your status as a partner and avoid the risk of gain recognition from a loan to a short seller you are urged to modify any applicable brokerage account agreements to prohibit your broker from borrowing your units.

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

We will be considered to have constructively terminated as a partnership for federal income tax purposes if there is a sale or exchange within a twelve-month period of 50% or more of the total interests in our capital and profits. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders which could result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one calendar year. Our termination could also 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 calendar year, 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. Our termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal income 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 termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

Unitholders may be subject to state, local and non-U.S. taxes and return filing requirements.

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

Item 1B Unresolved Staff Comments

None.

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Item 2 Properties

Title to Properties

The following map shows the general locations of our natural gas gathering and processing systems and our coal reserves and related infrastructure investments as of December 31, 2012:

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 and Williamsport, Pennsylvania, Irving, Texas, and Kingsport, Tennessee. We own the field office in Charleston, West Virginia. We believe that our properties are adequate for our current needs.

Eastern Midstream and Midcontinent Midstream Segments

Our Eastern Midstream and Midcontinent Midstream natural gas businesses derive revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. 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.

Our Eastern Midstream and Midcontinent Midstream natural gas operations include natural gas gathering and processing systems. The Eastern Midstream segment includes several natural gas gathering systems located in the Marcellus Shale area in Pennsylvania and West Virginia. We also own a 51% membership interest in Aqua-PVR Water Services LLC, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania. The Midcontinent Midstream segment includes gathering and processing facilities in the Texas/Oklahoma panhandle area. We owned six natural gas processing facilities having 460 MMcfd of total capacity as of December 31, 2012. In addition, we own a 25% membership interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin.

As of December 31, 2012, we owned approximately 134 miles of natural gas gathering pipelines, 83 miles of natural gas trunkline pipelines, and 42 miles of fresh water pipelines in the Eastern Midstream segment. In the Midcontinent Midstream segment we owned approximately 4,541 miles of natural gas gathering pipelines. A discussion of our more prominent and evolving systems for each segment follows.

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Eastern Midstream Systems

General. During 2010, we began construction of gathering systems in Wyoming and Lycoming Counties in Pennsylvania. We have completed initial construction of 12-inch gas gathering pipelines in Wyoming County and began gathering natural gas on the system in June 2010. In February 2011, we commenced operations on the first phase of the Lycoming System. In April 2011, we also began construction on the second phase of the Lycoming System, a portion of which became operational in the fourth quarter of 2011. In April of 2012, we began construction on the third phase of the Lycoming System, which became operational by the end of the year. The Lycoming System consists of 53 miles of 30- inch trunkline. Construction and development to provide gathering, compression and related services in Lycoming and Wyoming Counties are ongoing. Below is a listing of the multiple gathering systems that make up the Eastern Midstream Segment.

Chief Gathering Acquisition. In May of 2012, we completed the acquisition of Chief Gathering LLC. This acquisition added 120 miles of gathering pipelines, 350 MMcfd of capacity, and over 300,000 dedicated acres in the Marcellus Shale to the Eastern Midstream System.

Lycoming System

General. The Lycoming System includes a 30” trunkline and associated gathering and compression for Range, Anadarko, Southwest Energy, and Shell. In total, there are 73 miles of pipeline, three market outlets to Transco, and a current capacity of 510 MMcfd. The System gathers gas in Lycoming and Tioga counties in Pennsylvania with eight active compressor and dehydration facilities.

Wyoming System

General. The Wyoming System includes a newly constructed 24” trunkline and associated gathering and compression facilities. In total, there are over 72 miles of pipeline, two active compressor stations, three market outlets to the Tennessee Gas Pipeline, and one market outlet to the Transco pipeline. Gas is being gathered for Citrus, Chief E&P, and Chesapeake with an overall capacity of 665 MMcfd. There are well connect projects and compressor station construction projects in progress.

East Lycoming System

General. The East Lycoming System gathers gas in Lycoming and portions of western Sullivan counties in Pennsylvania. The system is comprised of 41 miles of pipeline; one active compressor station and 120 MMcfd capacity tap into the Transco system. Additional well connect projects and compression are under construction to provide market access for EXCO and XTO.

Bradford System

General. The Bradford System is located in Bradford County, Pennsylvania. The System currently has over 20 miles of gathering pipeline, one active compressor/dehydration facility and 55 MMcfd of capacity into the Tennessee Gas Pipeline. Well connect projects and a capacity expansion of the compressor station is underway to provide market access for Chief E&P and Chesapeake.

Greene County System

General. The Greene County System is a small gathering system in Greene County, Pennsylvania. It includes  ¹/₂ mile of pipeline and a tap into the Columbia Gas system for Chevron. A 15 MMcfd compressor station is under construction and is expected to be in service by the second quarter of 2013.

Preston County System

General. The Preston County System is located in Preston County, West Virginia. There is active construction underway to accommodate a well connect for Enerplus with a tap on the Dominion pipeline.

Eastern Midstream Natural Gas Supply. The gathering infrastructure captures current and expected volumes in the Marcellus Shale area. The Eastern Midstream Systems deliver the natural gas to local customers and provides avenues for local producers to major pipeline systems such as Transco and Tennessee.

Aqua-PVR Joint Venture

Water Supply. We are a partner in a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania. Phases I and II of the water pipeline were placed into service in early 2012. Phase III is nearing completion and will be in service the first quarter of 2013. A new three MMgpd pump station was commissioned in December 2012. The new pump station included a high capacity water intake on the West Branch of the Susquehanna River.

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Midcontinent Midstream Systems

Panhandle System

General. The Panhandle System is a natural gas gathering system stretching over eleven counties in the Anadarko Basin of the panhandle region of Texas and Oklahoma. The System consists of approximately 2,088 miles of natural gas gathering pipelines, ranging in size from two to 16 inches in diameter, and four natural gas processing plants. Included in the system is an 11-mile, 10-inch diameter, FERC-jurisdictional residue line.

During 2012, we completed construction of and placed into service one of the four processing facilities. Phase I expansion of the facility was completed in March bringing inlet capacity to 80 MMcfd. Phase II expansion of the same facility was completed in June bringing the total inlet capacity of the plant to 140 MMcfd. This addition to the Panhandle System enables us to meet our current and expected future processing requirements in this area. We are also improving the connectivity between plants to enable us to better utilize our Panhandle processing capabilities and better serve the growing needs of the area producers, including those in the Granite Wash.

All four plants are capable of operating in high ethane recovery mode or in ethane rejection mode and have instrumentation allowing for unattended operation of up to 16 hours per day.

The Panhandle System is comprised of a number of pipeline gathering systems and 43 field compressor stations that gather natural gas, directly or indirectly, to the plants. These gathering systems are located in Beaver, Ellis, Harper, and Roger Mills Counties in Oklahoma and Hansford, Hemphill, Hutchinson, Lipscomb, Ochiltree, Roberts and Wheeler Counties in Texas.

Natural Gas Supply and Markets for Sale of Natural Gas and NGLs. The residue gas from the Antelope Hills plant is delivered into Southern Star Central Gas or Northern Natural Gas pipelines for sale or transportation to market. The NGLs produced at the Antelope Hills plant are delivered into ONEOK Hydrocarbon’s pipeline system for transportation to and fractionation at ONEOK’s Conway fractionator.

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

The residue gas from the Sweetwater plant is delivered into Oklahoma Gas Transmission or ANR pipelines for sale or transportation to market. The NGLs produced at the Sweetwater plant are delivered into ONEOK Hydrocarbon’s pipeline system for transportation and fractionation, with the majority being handled at ONEOK’s Conway fractionator and a portion being delivered to the Mont Belvieu markets.

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 1,724 miles of natural gas gathering pipelines, ranging in size from two to 10 inches in diameter, and the Crescent natural gas processing plant located in Logan County, Oklahoma. Fourteen compressor stations are operating across the Crescent System. We continue to look at potential growth opportunities to service the Mississippian Lime formation.

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

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

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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. We continue to look at potential growth opportunities to service the emerging Cline formation.

Natural Gas Supply and Markets for Sale of Natural Gas and NGLs. The gas on the Hamlin System is primarily casinghead gas associated with the production of oil. 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.

Coal Reserves and Production

As of December 31, 2012, we owned or controlled approximately 871 million tons of proven and probable coal reserves located in Illinois, Indiana, Kentucky, New Mexico, Tennessee, 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:

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 the 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, 2012, our lessees operated 45 surface mines and 53 underground mines. Approximately 43% of the coal produced from our properties in 2012 came from underground mines and 57% 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.

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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 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 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):

Of the approximately 871 million tons of proven and probable coal reserves to which we had rights as of December 31, 2012, we owned the mineral interests and the related surface rights to 416 million tons, or 48%, and we owned only the mineral interests to 283 million tons, or 32%. We leased the mineral rights to the remaining 172 million tons, or 20%, 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 2012, our aggregate expenses to third-party surface and mineral owners were $12.0 million.

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The following table sets forth the coal reserves we owned and leased with respect to each of our coal properties as of December 31, 2012 (tons in millions):

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

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.

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, 2012, approximately 23% of our reserves met compliance standards for the CAA and 35% 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 as of December 31, 2012 (tons in millions):

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The following table shows the proven and probable coal reserves we leased to mine operators by property as of December 31, 2012 (tons in millions):

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 249 thousand acres of forestland in Kentucky, Tennessee, 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 6.4 Bcfe of proved oil and gas reserves located in Kentucky, Tennessee, Virginia and West Virginia.

Item 3 Legal Proceedings

In the ordinary course of business, we are involved in various claims and legal proceedings. We are generally unable to predict the timing or outcome of these claims and proceedings. Based upon our evaluation of existing claims and proceedings and the probability of losses relating to such contingencies, we have accrued certain amounts relating to such claims and proceedings, none of which are considered material.

On July 24, 2012, the Pennsylvania Department of Environmental Protection (“PA DEP”) presented the Partnership’s subsidiary, PVR Marcellus Gas Gathering, LLC, with a proposed Consent Assessment of Civil Penalty totaling approximately $0.2 million in connection with alleged erosion and sediment control violations incurred during construction of its pipelines and related facilities in Lycoming County, Pennsylvania. We are in discussions with the PA DEP regarding the proposed penalty. The timing or outcome of these discussions cannot be reasonably determined at this time.

Item 4 Mine Safety Disclosures

Not applicable.

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Part II

Item 5 Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common units are traded on the NYSE under the symbol “PVR.” The high and low sales prices (composite transactions) and distributions declared related to each fiscal quarter in 2012 and 2011 were as follows:

Equity Holders

As of December 31, 2012, there were 183 record holders and approximately 62,324 beneficial owners of our common units. There is no established trading market for our Class B Units or our Special Units. As of December 31, 2012, our Class B Units were held by one holder of record and our Special Units were held by one holder of record.

Common Unitholder Return Performance Presentation

The performance graph below compares the cumulative total unitholder return on our common units with the cumulative total returns on the Standard & Poor’s 500 Index (the “S&P 500 Index”) and the Alerian MLP Total Return Index (the “Alerian Total Return Index”). The Alerian Total Return Index is a composite of the 50 most prominent energy master limited partnerships and limited liability companies, as determined by Standard & Poor’s using a float-adjusted market capitalization methodology. The graph assumes an investment of $100 in our common units, and in each of the S&P 500 Index and the Alerian Total Return Index on December 31, 2007 and reinvestment of all dividends and distributions. The results shown in the graph are based on historical data and should not be considered indicative of future performance.

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

Item 6 Selected Financial Data

The following selected historical financial information was derived from our Consolidated Financial Statements as of December 31, 2012, 2011, 2010, 2009 and 2008, 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”:

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Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the financial condition and results of operations of PVR 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 that is principally engaged in the gathering and processing of natural gas and the management of coal and natural resource properties in the United States. We currently conduct operations in three business segments which are as follows:

Our operating income (loss) was $(4.6) million in 2012, compared to $153.6 million in 2011 and $121.6 million in 2010. In 2012, our Eastern Midstream segment contributed $25.4 million to our operating income, our Midcontinent Midstream segment reduced operating income by $(101.9) million, and our Coal and Natural Resource Management segment contributed $71.9 million to operating income.

Eastern Midstream Segment Overview

As of December 31, 2012, we owned and operated natural gas midstream assets located in Pennsylvania and West Virginia including approximately 134 miles of natural gas gathering pipelines, 83 miles of natural gas trunkline pipelines, and 42 miles of fresh water pipelines. Our Eastern Midstream segment earns revenues primarily from fees charged to producers for natural gas gathering, compression and other related services. During 2010, we began construction of gathering systems in Wyoming and Lycoming Counties in Pennsylvania. In June 2010, we commenced operations on the Wyoming County system, which consists of 72 miles of gathering pipelines. In February 2011, we commenced operations on the first phase of the Lycoming County system. In April 2011, we also began construction on the second phase of the Lycoming County system, a portion of which became operational in the fourth quarter of 2011. In April of 2012, we began construction on the third phase of the Lycoming County system, which became operational by the end of the year. The Lycoming County system consists of 53 miles of 30- inch trunkline. In May of 2012, we completed the acquisition of Chief Gathering LLC, adding 120 miles of gathering pipelines, 350 MMcfd of capacity and over 300,000 dedicated acres in the Marcellus Shale to the Eastern Midstream segment. In the fourth quarter of 2012, we commenced operation of Wyoming Pipeline, which consists of 30 miles of 24-inch diameter natural gas trunkline. Construction and development to provide gathering, compression and related services in Lycoming and Wyoming Counties are ongoing.

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In 2012, average gathered volumes on our Eastern Midstream systems were approximately 389 MMcfd, while our average trunkline volumes were approximately 197 MMcfd. These average flow rates have increased from 2011 average gathered volumes of 74 MMcfd and average trunkline volumes of 40 MMcfd. A significant volume of gas flows through both gathering and trunkline systems. The annual increase in volumes is attributed to both the Chief Acquisition and completion of internal growth projects. Gathered and trunkline volumes for the quarter ended March 31, 2012 were 210 MMcfd and 92 MMcfd, respectively. Compared with gathered and trunkline volumes of 562 MMcfd and 405 MMcfd, respectively, for the quarter ended December 31, 2012.

In September 2011, we entered into a joint venture to construct and operate a pipeline system to supply fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania. The 12-inch diameter steel pipeline will largely parallel the trunkline of our existing gathering system in Lycoming County. Phases I and II of the water pipeline were placed into service in early 2012. Phase III is nearing completion and will be in service during the first quarter of 2013. A new three MMgpd pump station was commissioned in December 2012. The new pump station included a high capacity water intake on the West Branch of the Susquehanna River. As of December 31, 2012, our cumulative contributions to the joint venture were $41.0 million.

We continually seek new supplies of natural gas both to offset the natural declines in production from the wells currently connected to our systems and to increase system throughput volumes. New natural gas supplies are obtained for all of our systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and contracting for natural gas that has been released from competitors’ systems. In 2012, our Eastern Midstream natural gas segment made aggregate capital expenditures of $1.5 billion, primarily related to the Chief Acquisition and our expansion of the Marcellus Systems due to growth opportunities in those areas.

Midcontinent Midstream Segment Overview

As of December 31, 2012, we owned and operated natural gas midstream assets located in Oklahoma and Texas including six natural gas processing facilities having 460 MMcfd of total capacity and approximately 4,541 miles of natural gas gathering pipelines. Our Midcontinent Midstream natural gas 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 are a partner in a joint venture that gathers natural gas. We also own a natural gas marketing business, which aggregates third-party volumes and sells those volumes into interstate and intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

System throughput volumes at our gas processing plants and gathering systems, including gathering only volumes, were approximately 432 MMcfd in 2012, compared to 421 MMcfd in 2011.

We continually seek new supplies of natural gas both to offset the natural declines in production from the wells currently connected to our systems and to increase system throughput volumes. New natural gas supplies are obtained for all of our systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and contracting for natural gas that has been released from competitors’ systems. In 2012, Midcontinent Midstream natural gas segment made aggregate capital expenditures of $132.6 million, primarily related to our expansion of the Panhandle System due to growth opportunities in those areas.

Coal and Natural Resource Segment Overview

As of December 31, 2012, we owned or controlled approximately 871 million tons of proven and probable coal reserves in Central and Northern Appalachia, the Illinois Basin and the San Juan 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 2012, our lessees produced 30.2 million tons of coal from our properties and paid us coal royalties revenues of $114.1 million, for an average royalty per ton of $3.78. Approximately 75% of our coal royalties revenues in 2012 was 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. 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.”

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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.

Key Developments

Eastern Midstream Segment

On May 17, 2012, we purchased the membership interests of Chief Gathering (“Chief Gathering”) from Chief E&D Holdings LP, for a purchase price of approximately $1.0 billion (“Chief Acquisition”), payable in a combination of $849.3 million in cash and fair value of $191.3 million in a new class of limited partner interests in us (“Special Units”). The Special Units are substantially similar to our common units except that we will neither pay nor accrue distributions on the Special Units for six consecutive quarters following their issuance. The Special Units automatically convert to common units, on a one-for one basis, on the first business day after the record date for distributions with respect to the quarter ending September 30, 2013. The Special Units are subject to early conversion by us or a holder of Special Units in connection with certain events. See Note 6 “PVR Unit Offerings” in the Notes to the Consolidated Financial Statements for a description of the conversion rights and distribution rights applicable to the Special Units.

Chief Gathering owned and operated six natural gas gathering systems serving over 300,000 dedicated acres in the Marcellus Shale, located in the north central Pennsylvania counties of Lycoming, Bradford, Susquehanna, Sullivan, Wyoming and Greene and in Preston County, West Virginia. This transaction resulted in a major expansion of our pipeline systems in our Eastern Midstream segment.

We financed the cash portion of the purchase price for the Chief Acquisition through a combination of equity and debt. In May 2012, we received (i) $400 million in cash related to the sale of Class B Units to Riverstone V PVR Holdings, L.P. and Riverstone Global Energy and Power Fund V (FT), L.P., representing a new class of limited partner interests in us, and (ii) $180 million in cash related to the sale of common units to institutional investors in a private placement. We used the proceeds from the sale of the Class B Units and the common units to fund a portion of the cash purchase price for the Chief Acquisition. The remainder of the purchase price was funded by a portion of the $600 million of senior notes issued in a private placement in May 2012. See Note 6 “PVR Unit Offerings” in the Notes to the Consolidated Financial Statements for a description of the conversion rights and distribution rights applicable to the Class B Units.

In the fourth quarter of 2012, we completed construction and commenced commercial operation of a 30-mile long, 24 inch diameter natural gas trunkline serving Marcellus Shale producers in Pennsylvania. The pipeline has a capacity of 750 million cubic feet per day and extends from northern Wyoming County southward to a new connection in Luzerne County with Transco’s interstate pipeline system. We have long term fee-based agreements with five producers for transportation service on the pipeline.

Midcontinent Midstream Segment

During 2012, we completed construction of and placed into service the Antelope Hills processing facility. Phase I expansion of the facility was completed in March bringing inlet capacity to 80 MMcfd. Phase II expansion of the same facility was completed in June bringing the total inlet capacity of the Antelope Hills plant to 140 MMcfd. This addition to the Panhandle System enables us to meet our current and expected future processing requirements in this area. We are also improving the connectivity between our Antelope Hills, Beaver and Sweetwater plants to enable us to better utilize our Panhandle processing capabilities and better serve the growing needs of the area producers, including those in the Granite Wash.

During the first quarter of 2012, we recognized a $124.8 million impairment charge related to our tangible and intangible natural gas gathering assets located in the southern portion of the Fort Worth Basin of north Texas (the “North Texas Gathering System”). This impairment was triggered by continuing market declines of natural gas prices and lack of drilling in the area. The North Texas Gathering System represented a de minimis amount of our consolidated total revenues.

On July 3, 2012, we completed the sale of our Crossroads natural gas gathering system and processing plant (the “Crossroads Sale”) for net proceeds of $62.3 million. The Crossroads system, located in the southeastern portion of Harrison County in east Texas, includes approximately eight miles of gas gathering pipeline, an 80 MMcfd cryogenic processing plant, approximately 20 miles of NGL pipeline, and a 50% ownership in an approximately 11-mile gas pipeline. A gain on sale of assets of $31.3 million was recognized.

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During the fourth quarter of 2012, we recognized an $8.7million impairment charge related to our 25% membership interest in the Thunder Creek joint venture located in Wyoming’s Powder River basin. The intangible assets related to this joint venture were written down to zero. This impairment was triggered by continuing market declines of natural gas prices, lack of coalbed methane drilling in the area and other market factors. Our share of the joint venture earnings, net of intangible amortization and exclusive of the impairment charge, for the year ended December 31, 2012 were $1.1 million, $2.5 million in 2011 and $6.0 million in 2010. Our share of the distributions from the joint venture for the same years was $1.9 million in 2012, $8.2 million in 2011 and $7.0 million in 2010.

Coal and Natural Resource Management Segment

On January 25, 2011, we acquired certain mineral rights and associated oil and gas royalty interests in Kentucky and Tennessee for approximately $95.7 million. The mineral rights included approximately 67.7 million tons of coal reserves. The coal is primarily steam coal and expands our geographic scope in the Central Appalachia coal region.

2012 Commodity Prices

The average commodity prices for natural gas, NGLs, condensate and crude oil decreased in 2012 from levels experienced in 2011. Revenues, profitability and the future rate of growth of our Midcontinent Midstream segment is highly dependent on market demand and prevailing NGL and natural gas prices. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas. This volatility is somewhat mitigated by the growing fee-based business in the Eastern Midstream segment. We continually monitor commodity prices and when it appears opportunistic, we may choose to use derivative financial instruments to hedge NGLs sold and natural gas purchased. As of December 31, 2012, we had no open derivative positions hedging commodity prices. In January 2013, we entered into a crude oil swap to hedge condensate volumes. The term of the swap covers February 2013 through December 2013, the notional amount is 500 barrels per day at a swap price of $94.80 per barrel.

Coal royalties, which accounted for 84% of the Coal and Natural Resource Management segment revenues for year ended December 31, 2012, were lower compared to 2011. The decrease was attributed to reduced demand for coal from our lessees’ customers due to the mild winter and lower natural gas prices.

PVR Equity Issuance

In November 2012, we issued 7.5 million common units representing limited partner interests in PVR in a registered public offering. Total net proceeds of approximately $165.7 million were used to repay a portion of the Revolver.

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Results of Operations

Consolidated Review

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