PVR Pvr Partners, L.P.

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 (“NYSE”) 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 $132.7 million in 2013, compared to $(4.6) million in 2012 and $153.6 million in 2011. In 2013, our Eastern Midstream segment contributed $68.5 million to our operating income, our Midcontinent Midstream segment contributed $12.2 million, and our Coal and Natural Resource Management segment contributed $52.0 million. 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.

Merger Agreement with Regency Energy Partners L.P. On October 9, 2013, we entered into an Agreement and Plan of Merger with Regency Energy Partners LP (or “Regency”), RVP LLC, a Delaware limited liability company and Regency’s wholly owned subsidiary, and Regency’s general partner. Pursuant to the Agreement and Plan of Merger, as amended by Amendment No. 1 thereto dated as of November 7, 2013 (or the “Regency Merger Agreement”), we will merge with and into Regency (or the “Regency Merger”), and Regency will continue its existence under Delaware law as the surviving entity in the Regency Merger. Regency has filed with the Securities Exchange Commission (“SEC”) a registration statement on Form S-4 (or the “Form S-4”) relating to the merger.

The Regency Merger Agreement provides that, at the effective time of the merger, each of our common units and each of our class B units issued and outstanding or deemed issued and outstanding as of immediately prior to the effective time will be converted into the right to receive the merger consideration, consisting of (i) 1.020 of Regency common units and (ii) an amount of cash equal to the difference between (x) our annualized distribution less (y) Regency’s adjusted annualized distribution. Our annualized distribution is the product of four and the per unit amount of the quarterly cash distribution most recently declared by us prior to the closing of the Regency Merger. Regency’s adjusted annualized distribution is the product of four and the per unit amount of quarterly cash distribution most recently declared by Regency prior to the closing of the Regency Merger, multiplied by the exchange ratio of 1.020.

The completion of the Regency Merger is subject to the satisfaction or waiver of certain customary closing conditions, including, among other things: (i) approval of the Regency Merger Agreement by our unitholders, (ii) approval for listing of Regency common units issuable as part of the merger consideration on the New York Stock Exchange, (iii) there being no law or injunction prohibiting the consummation of the Regency Merger, (iv) the effectiveness of the Form S-4, (v) subject to specified materiality standards, the accuracy of the representations and warranties of each party, (vi) compliance by each party in all material respects with its covenants and (vii) the receipt of certain legal opinions by us and Regency.

If the Regency Merger Agreement is not adopted by PVR unitholders or if the Regency Merger is not completed for any other reason, PVR unitholders will not receive any form of consideration for their PVR units in connection with the merger. Instead, PVR will remain an independent publicly traded limited partnership and its common units will continue to be listed and traded on the NYSE. If the Regency Merger Agreement is terminated under specified circumstances, including if unitholder approval is not obtained, PVR will be required to pay all of the reasonably documented out-of-pocket expenses incurred by Regency and its affiliates in connection with the Regency Merger Agreement and the transactions contemplated thereby, up to a maximum amount of $20.0 million. In addition, if the Regency Merger Agreement is terminated in specified circumstances, including due to an adverse recommendation change having occurred, PVR will be required to pay Regency a termination fee of $134.5 million, less any expenses previously paid by PVR to Regency. Following payment of the termination fee, PVR will not be obligated to pay any additional expenses incurred by Regency or its affiliates.

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We expect the Regency Merger to close in the first quarter of 2014. Additional information regarding the proposed transaction and the terms and conditions of the Merger Agreement are set forth on our Current Reports on Form 8-K, filed on October 10, 2013 and November 7, 2013, respectively.

Chief Gathering Acquisition. 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.

PVR-PVG Merger. In 2011, we consummated a transaction pursuant to a plan and agreement of merger (the “PVR 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 PVR 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 (the PVR-PVG Merger”). 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 approximately 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.

Eastern Midstream Segment Overview

As of December 31, 2013, we owned and operated natural gas midstream assets located in Pennsylvania and West Virginia including approximately 257 miles of natural gas gathering pipelines, 68 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, transportation, compression and other related services. During 2013, we continued construction of our internal growth projects and acquired assets in the Chief acquisition. In September 2013, we announced that we entered into a definitive agreement to construct, own and operate a 45-mile natural gas trunkline and associated gathering pipelines and facilities servicing lean gas production in the Utica Shale in eastern Ohio. We expect the capital investment for the trunkline, initial gathering line, compression stations and dehydration facilities to be $125.0 million to $150.0 million through 2015.

In 2013, average gathered volumes on our systems were approximately 649 MMcfd, while our average trunkline volumes were approximately 742 MMcfd. These average flow rates have increased from 2012 average gathered volumes of 389 MMcfd and average trunkline volumes of 197 MMcfd. A significant volume of gas flows through both gathering and trunkline systems. The annual increase in volumes is attributed to the completion of internal growth projects.

Midcontinent Midstream Segment Overview

As of December 31, 2013, 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 4,650 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.

System throughput volumes at our gas processing plants and gathering systems, including gathering only volumes, were approximately 379 MMcfd in 2013, compared to 432 MMcfd in 2012. The decrease in throughput volumes is attributed to the sale of the Crossroads Plant in 2012 and declines in natural gas production.

On August 19, 2013, we sold our 25% membership interest in Thunder Creek Gas Services LLC, a joint venture that gathers and transports coalbed methane gas in Wyoming’s Powder River Basin. This Midcontinent Midstream investment was accounted for using the equity method of accounting, and had a carrying value of $44.3 million. The proceeds from the sale were $58.6 million, resulting in a gain of $14.3 million recorded in other revenues on the Consolidated Statement of Operations.

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.

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As of December 31, 2013, we owned or controlled approximately 847 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 2013, our lessees produced 25.1 million tons of coal from our properties and paid us coal royalties revenues of $88.1 million, for an average royalty per ton of $3.50. Approximately 65% of our coal royalties revenues in 2013 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. For the year ended December 31, 2013, $22.1 million in coal royalties were earned in the San Juan Basin. During 2014, our coal reserves located in the San Juan Basin will deplete and the associated royalty revenue will cease.

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:

As previously discussed, in October 2013 we announced a definitive Merger Agreement with Regency. Under the Merger Agreement we are subject to certain restrictions on our business prior to completing the transaction, which may adversely affect our ability to execute certain of our business strategies without first obtaining consent from Regency, including our ability in certain cases to enter into certain contracts, incur capital expenditures or grow our business.

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, 2013, 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 2013, 51% of our total consolidated revenues and 51% of our December 31, 2013 consolidated accounts receivable resulted from seven of our natural gas midstream customers. Within the Eastern Midstream segment for 2013, 55% of the segment’s revenues and 54% of the December 31, 2013 accounts receivable for the segment resulted from three customers. Within the Midcontinent Midstream segment for 2013, 57% of the segment’s revenues and 54% of the December 31, 2013 accounts receivable for the segment resulted from four customers.

Fee-Based Arrangements . Under fee-based arrangements, we receive fees for gathering, transporting, 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

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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 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 some 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 $2.20 per common unit during the year ended December 31, 2013. In the first quarter of 2014, 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, 2013, 2012 and 2011 (in thousands):

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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, 2013 there were 24,305,507 Class B Units outstanding. The increase relates to PIK distributions to the holders of the Class B Units issued during 2013 and 2012. See Note 13, “PVR Unit Offerings,” for a discussion of the distribution rights of the Class B Units.

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

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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 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

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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 have also examined 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. After rescinding its initial May 2012 proposal, BLM re-proposed a rule in May 2013 that would require the disclosure of chemicals used during the fracturing process and addresses drilling plans, water management, and wastewater disposal on federal and Indian lands. Ongoing, proposed, or future studies, depending on their degree of pursuit and any meaningful results obtained, could spur additional regulatory and legislative initiatives.

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, including Oklahoma, Pennsylvania and West Virginia, 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 passed Act 13 in February 2012, which provided for new well fees assessed and collected on unconventional wells, substantial revisions to environmental protections for both surface and subsurface activities, and prevented local zoning rules from imposing burdens on oil and gas activities beyond those required by the state. However, on December 19, 2013, the Pennsylvania Supreme Court struck down various portions of Act 13. West Virginia also increased its regulation of hydraulic fracturing by establishing a permitting process for wells, requiring additional studies and authorizing the West Virginia Department of Environmental Protection to adopt new rules (“WVDEP”). 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.

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, some local governments have attempted temporary moratoriums on drilling operations using hydraulic fracturing. No assurance can be given as to whether or not such measures might be considered or implemented in 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. On September 23, 2013, the EPA published updates to the 2012 performance standards, setting the compliance deadline for tanks based upon when they were put into use. 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 by the applicable compliance deadline. Texas has also implemented more stringent emissions, monitoring, inspection, maintenance, and repair requirements on operators in order to minimize VOC releases. Compliance with such federal rules and their implementing state laws and regulations 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 the 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, the EPA released a December 21, 2012 memorandum stating that the 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 (“PADEP”) announced its intent to not renew permits for publicly owned treatment works that treat municipal wastewater to accept wastewater from Marcellus Shale operators. West Virginia also has similar disposal regulations. Among other permit requirements, the West Virginia rules require operators to maintain records regarding the quality and quantity of flowback and produced water from the well and the method of management or disposal of the flowback and produced water. Operators also are required to maintain records regarding the quantity of flowback and produced water transported, the collection and disposal location, and names of companies transporting flowback and produced water. 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 Clean Water Act (“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 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 (“SRBC”) when withdrawing from waters within their river basins. Operators who must submit plans per DRBC or SRBC requirements may utilize those plans to satisfy this requirement but must still formally apply to the PADEP. 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

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be insufficient. Compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers.

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, 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 (“GHG”) 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, the 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 the 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 April 13, 2013, the EPA published draft 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. In its Climate Action Plan, the Obama Administration announced its intent to issue regulations under Section 111(b) and Section 111(d) of the CAA to set NSPS for both new and existing power plants by June 2015. As of December 31, 2013, the EPA has not formally published any rules

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to finalize these requirements. In addition, in October 2013, the U.S. Supreme Court granted certiorari to hear arguments related to a combination of several petitions challenging the EPA’s approach to CO2 regulation.

As a result of revisions to its preconstruction permitting rules that became fully effective on January 2, 2011, the 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, that began in 2012 for emissions occurring in 2011 and beyond.

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 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.”

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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.

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 byproducts, or coal combustion residues (“CCR”), 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 when destined for disposal in landfills or surface impoundments 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. However, as of December 31, 2013, EPA has not finalized CCR rules nor established a timeframe for doing so. If EPA adopts rules to regulate the management and disposal of these byproducts 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 was appealed and reversed by the D.C. Circuit Court of Appeals on April 23, 2013, finding that the EPA’s retroactive veto was legal. The case has been remanded back to the district court for consideration of the merits of the Agency decision while the mining company has also petitioned the U.S. Supreme Court for certiorari to overturn the ruling. Any future use of the EPA’s Section 404 “veto” power could create uncertainty 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.

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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 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 (“EIS”) 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.

Third parties have recently sought to force the EPA to regulate selenium discharges in areas currently and previously used for coal mining operations and to impose liability and penalties on current owners of those lands. For example, there is at least one CWA citizen suit pending in the Fourth Circuit, Ohio Valley Environmental Coalition, Inc. v. Hernshaw Partners, LLC , where the plaintiffs allege the current owner of land previously utilized by another party for coal mining operations is in violation of the CWA for selenium discharges that continue to have effects on the waterbody. If the ultimate resolution of the litigation results in a current owner deemed to be in violation of the CWA even if the activities of prior owners or operators that caused the violations have ceased, current owners may be responsible for preventing and remediating any selenium discharges that may arise after the operator has ceased utilizing the coal mine.

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 to federal regulatory programs, all of the states in which we operate also have state programs for mine safety and health regulation and enforcement. 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.

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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 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 321 employees who directly supported our operations at December 31, 2013. 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.