Annual Reports

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PVR PARTNERS, L P 10-K 2012
Form 10-K
Table of Contents

 

 

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, 2011

Commission file number: 1-16735

 

Penn Virginia Resource Partners, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware   23-3087517

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification Number)

Five Radnor Corporate Center, Suite 500

100 Matsonford Road

Radnor, Pennsylvania 19087

(Address of principal executive offices)

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

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

 

Title of each class

 

Name of exchange on which registered

Common Units   New York Stock Exchange

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

None

 

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

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

 

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

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

The aggregate market value of common units held by non-affiliates of the registrant was $1,904,077,174 as of June 30, 2011 (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. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of February 6, 2012, 79,032,669 common units representing limited partner interests of the registrant were outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

None

 

 

 


Table of Contents

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

Table of Contents

 

         Page  

Forward-Looking Statements

     1   

Item

    
  Part I   

1.

  Business      3   

1A.

  Risk Factors      19   

1B.

  Unresolved Staff Comments      33   

2.

  Properties      34   

3.

  Legal Proceedings      40   

4.

  Reserved      40   
  Part II   

5.

  Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities      41   

6.

  Selected Financial Data      43   

7.

  Management’s Discussion and Analysis of Financial Condition and Results of Operations      44   
 

Overview of Business

     44   
 

Results of Operations

     47   
 

Liquidity and Capital Resources

     55   
 

Contractual Obligations

     59   
 

Off-Balance Sheet Arrangements

     59   
 

Environmental Matters

     59   
 

Critical Accounting Estimates

     59   
 

New Accounting Standards

     61   

7A.

  Quantitative and Qualitative Disclosures About Market Risk      61   

8.

  Financial Statements and Supplementary Data      64   

9.

  Changes in and Disagreements With Accountants on Accounting and Financial Disclosure      93   

9A.

  Controls and Procedures      93   

9B.

  Other Information      93   
  Part III   

10.

  Directors, Executive Officers and Corporate Governance      94   

11.

  Executive Compensation      94   

12.

  Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters      94   

13.

  Certain Relationships and Related Transactions, and Director Independence      94   

14.

  Principal Accounting Fees and Services      94   
  Part IV   

15.

  Exhibits and Financial Statement Schedules      95   


Table of Contents

Forward-Looking Statements

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

 

   

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

 

   

our ability to access external sources of capital;

 

   

any impairment writedowns of our assets;

 

   

the relationship between natural gas, NGL and coal prices;

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

hedging results;

 

   

accidents;

 

   

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

 

   

uncertainties relating to the outcome of current and future litigation regarding mine permitting;

 

   

risks and uncertainties relating to general domestic and international economic (including inflation, interest rates and financial and credit markets) and political conditions;

 

   

other risks set forth in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2011.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

 

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Common Abbreviations and Definitions

The following are abbreviations and definitions commonly used in the coal and oil and gas industries that are used in this Annual Report on Form 10-K.

 

Bbl    a standard barrel of 42 U.S. gallons liquid volume
Bcf    one billion cubic feet
Bcfe    one billion cubic feet equivalent with one barrel of oil or condensate converted to six thousand cubic feet of natural gas based on the estimated relative energy content
BTU    British thermal unit
MBbl    one thousand barrels
Mbf    one thousand board feet
Mcf    one thousand cubic feet
Mcfe    one thousand cubic feet equivalent
MMBbl    one million barrels
MMbf    one million board feet
MMBtu    one million British thermal units
MMcf    one million cubic feet
MMcfd    one million cubic feet per day
MMcfe    one million cubic feet equivalent
NGL    natural gas liquid
NYMEX    New York Mercantile Exchange
Probable coal reserves    those coal reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are more widely spaced or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation
Proven coal reserves    those coal reserves for which: (i) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; (ii) grade and/or quality are computed from the results of detailed sampling; and (iii) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well defined, that the size, shape, depth and mineral content of reserves are well-established
Proved oil and gas reserves    those estimated quantities of crude oil, condensate and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years

 

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Table of Contents

Part I

Item 1 Business

General

Penn Virginia Resource Partners, L.P. (NYSE: PVR) is a publicly traded Delaware limited partnership that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. We currently conduct operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream.

Our operating income was $153.6 million in 2011, compared to $121.6 million in 2010 and $105.9 million in 2009. In 2011, our coal and natural resource management segment contributed $115.9 million, or 75%, to operating income, and our natural gas midstream segment contributed $37.6 million, or 25%, to operating income. Unless the context requires otherwise, references to the “Partnership,” “we,” “us” or “our” in this Annual Report on Form 10-K refer to Penn Virginia Resource Partners, L.P. and its subsidiaries.

Coal and Natural Resource Management Segment Overview

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

As of December 31, 2011, we owned or controlled approximately 893 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 2011, our lessees produced 38.4 million tons of coal from our properties and paid us coal royalties revenues of $162.9 million, for an average royalty per ton of $4.25. Approximately 81% of our coal royalties revenues in 2011 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.

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 acquired properties are referred to as the Middle Fork acquisition. The mineral rights acquired include approximately 67.7 million tons of coal reserves, and royalty interests from oil and gas wells. There are currently active producing underground and surface mines on the mineral estates acquired. The coal is primarily steam coal that is consumed by major electric utilities and other industrial customers in the southeastern United States. Funding for the acquisition was provided by borrowings under our revolving credit facility (“Revolver”). During the year, we have made other acquisitions that individually and in the aggregate are not material for disclosure purposes. The aggregate cost of all other acquisitions totaled $38.6 million.

Natural Gas Midstream Segment Overview

Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of December 31, 2011, we owned and operated natural gas midstream assets located in Oklahoma, Pennsylvania and Texas, including seven natural gas processing facilities having 420 MMcfd of total capacity and approximately 4,426 miles of natural gas gathering pipelines. Our natural gas midstream business earns revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In addition, we are a partner in several joint ventures that gather, transport and process natural gas and water. 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.

In 2011, system throughput volumes at our gas processing plants and gathering systems, including gathering-only volumes, were 180.8 Bcf, or approximately 495 MMcfd.

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 County system. In April 2011, we also began construction on the second phase of the Lycoming County system, which is expected to be operational in the first quarter of 2012. Construction and development to provide gathering, compression and related services in Lycoming and Wyoming Counties is ongoing. These Wyoming and Lycoming Counties gathering infrastructures are expected to capture anticipated volumes in the Marcellus Shale area, where we have been spending, and expect to continue to spend, a significant portion of our growth capital over the next year, and for the foreseeable future.

 

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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 trunk line of our existing gathering system in Lycoming County. As of December 31, 2011, our contribution to the joint venture was $5.3 million.

During the year, we have made other acquisitions that individually and in the aggregate are not material for disclosure purposes. The aggregate cost of all other acquisitions totaled $12.2 million.

Overview of Business

On September 21, 2010, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) by and among PVR, 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”), a wholly owned subsidiary of PVR. The Merger Agreement received final approval by PVR unitholders on February 16, 2011 and PVG unitholders on March 9, 2011. Pursuant to the Merger Agreement, PVG and PVG GP were merged into Merger Sub, with Merger Sub as the surviving entity (the “Merger”). Merger Sub was subsequently 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. Pursuant to the Merger Agreement and the Fourth Amended and Restated Agreement of Limited Partnership of PVR, the incentive distribution rights held by PVR’s general partner were extinguished, the 2.0% general partner interest in PVR held by PVR’s general partner was converted into 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, PVG GP and Merger Sub ceased, and PVR GP survives as a wholly-owned subsidiary of PVR.

Historically, PVG’s ownership of PVR’s general partner gave it control of PVR. During the periods that PVG controlled PVR (prior to March 10, 2011), PVG had no substantial assets or liabilities other than those of PVR. PVG’s consolidated financial statements included noncontrolling owners’ interest of consolidated subsidiaries, which reflected the proportion of PVR common units owned by PVR’s unitholders other than PVG. These amounts are reflected in the historical financial balances presented up to consummation of the Merger.

PVG is considered the surviving consolidated entity for accounting purposes, while PVR is the surviving consolidated entity for legal and reporting purposes. The Merger was accounted for as an equity transaction. Therefore, the changes in ownership interests as a result of the Merger did not result in gain or loss recognition.

After the Merger, the board of directors of PVR’s general partner, PVR GP, consisted of nine members, six of whom were existing members of the PVR GP board of directors before the Merger and three of whom were the three existing members of the conflicts committee of the board of directors of PVG GP prior to the Merger. On June 22, 2011, PVR held its annual meeting and all nine directors were re-elected to serve on the PVR GP board.

For the years ended December 31, 2011 and 2010, we incurred $6.6 million and $4.6 million of direct costs associated with the Merger. The aggregate costs of $11.2 million were charged to partners’ capital upon the effective date of the Merger in 2011. At December 31, 2010, the $4.6 million of costs incurred at that time were included in other long-term assets on the consolidated balance sheet, and were transferred to partners’ capital upon the effective date of the Merger. Cumulative costs incurred and paid during 2011 and 2010 are reported under the caption “Cash paid for merger” in the financing activities section of the consolidated statement of cash flows.

 

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The following diagrams depict the ownership structure of PVR and PVG before and immediately following the Merger:

 

LOGO

 

LOGO

 

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Business Strategy

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

 

   

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

 

   

Expand our natural gas midstream operations by adding new production to existing systems and acquiring or building new gathering and processing assets. We continually seek new supplies of natural gas both to offset the natural declines in production from the wells currently connected to our systems and to increase system throughput volumes. New natural gas supplies are obtained for all of our systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and by contracting for natural gas that has been released from competitors’ systems.

 

   

Mitigate commodity price exposure in our natural gas midstream segment. Our natural gas midstream operations consist of a mix of fee-based and margin-based services that are expected to generate relatively stable cash flows for a portion of our operations. During the quarter ended December 31, 2011, approximately 33% of the system throughput volumes in our natural gas midstream segment were gathered or processed under fee-based contracts, including those contracts in the Marcellus Shale which are a combination of fee-based and capacity reservations charges. Under such fee-based contracts, we are not exposed directly to commodity price risk. The remainder of our system throughput volumes were gathered or processed under gas purchase/keep-whole arrangements and percentage-of-proceeds arrangements that are subject to commodity price risk. We continually monitor commodity prices and when it is opportunistic, we may choose to manage our exposure to commodity price risk by entering into hedging transactions. Based upon November 2011 volumes, we have entered into hedging agreements covering approximately 94% of our commodity-sensitive volumes in 2012. This coverage amount is higher than our historic coverage amounts due to the processing capacity constraints in our Texas/Oklahoma Panhandle System. These constraints have caused us to bypass more of our owned natural gas without processing, lowering the net NGL recoveries specific to PVR. The percent hedged will decrease in the near future as we continue to enact measures to alleviate our processing capacity constraints.

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.

 

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

Natural Gas Midstream Segment

Our natural gas midstream business generates revenues primarily from gas purchase and processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. During the year ended December 31, 2011, our natural gas midstream business generated a majority of its gross margin from two types of contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and NGLs: (i) gas purchase/keep-whole and (ii) percentage-of-proceeds. For the fourth quarter of 2011, approximately 12% of our system throughput volumes were gathered or processed under gas purchase/keep-whole contracts, 55% were gathered or processed under percentage-of-proceeds contracts and 33% were gathered or processed under fee-based gathering contracts. A majority of the gas purchase/keep-whole and percentage-of-proceeds contracts include fee-based components such as gathering and compression charges.

In 2011, 47% of our natural gas midstream segment revenues and 40% of our total consolidated revenues resulted from four of our natural gas midstream customers, Conoco Phillips Company, Williams NGL Marketing, LLC, Tenaska Marketing Ventures, and Targa Liquids Marketing and Trade.

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

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.

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.

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

Natural Gas Marketing Contracts. We are also engaged in natural gas marketing by aggregating third-party volumes and selling those volumes into interstate and intrastate pipeline systems such as Enogex and Panhandle Eastern Pipeline and at market hubs accessed by various interstate pipelines. Revenues from this business do not generate qualifying income for a publicly traded limited partnership, but we do not expect it to have an impact on our tax status, as it does not represent a significant percentage of our operating income. For the three years ended December 31, 2011, natural gas marketing activities generated $2.6 million, $2.8 million and $1.8 million in net revenues.

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

 

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Partnership Distributions

Cash Distributions

We paid cash distributions of $1.94 per common unit during the year ended December 31, 2011. In the first quarter of 2012, we paid a cash distribution of $0.51 ($2.04 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, 2011, 2010 and 2009 (in thousands):

 

     Year Ended December 31,  
     2011      2010      2009  

PVG limited partners

   $ 15,239       $ 60,565       $ 59,392   

PVR limited partners (1)

     119,679         61,019         60,560   

PVR phantom units

     378         440         498   
  

 

 

    

 

 

    

 

 

 

Total cash distribution paid during period

   $ 135,296       $ 122,024       $ 120,450   
  

 

 

    

 

 

    

 

 

 

 

(1) PVR limited partner unit distributions represent distributions paid to public unitholders and not to units owned by PVG prior to the Merger.

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.

 

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

Competition

Coal and Natural Resource Management Segment

The coal industry is intensely competitive primarily as a result of the existence of numerous producers. Our lessees compete with both large and small coal producers in various regions of the United States for domestic 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.

Natural Gas Midstream Segment

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

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

 

   

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

 

   

the relative volumes of gas consumed as fuel and lost;

 

   

the gathering/processing fees charged;

 

   

the timeliness of well connects;

 

   

the customer service orientation of the gatherer/processor; and

 

   

the reliability of the field services provided.

Government Regulation and Environmental Matters

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

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.

 

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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.

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:

 

   

The EPA’s Clean Air Interstate Rule (“CAIR”) calls for power plants in 28 states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar to the system now in effect for acid rain. In June 2011, the EPA finalized a replacement rule to CAIR called the Cross-State Air Pollution Rule (“CSAPR”), which requires 28 states in the Midwest and eastern seaboard of the U.S. to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions would commence in 2012 with further reductions effective in 2014. However, on December 30, 2011, the District of Columbia Circuit Court of Appeals stayed the implementation of CSAPR pending resolution of judicial challenges to the rules and ordered the EPA to continue enforcing CAIR until the pending legal challenges have been resolved. We are unable to predict whether the CSAPR program will be upheld or reversed but for states to meet their requirements under the CSAPR, a number of coal-fired electric generating units will likely need to be retired, rather than be retrofitted with the necessary emission control technologies. These closures are likely to reduce the demand for steam coal.

 

   

The proposed Utility Boiler Maximum Achievable Control Technology (“MACT”) would regulate the emission of other air pollutants, including mercury and other metals, fine particulates, and acid gases such as hydrogen chloride.

 

   

On December 16, 2011, the EPA signed a rule to establish a national standard to reduce mercury and other toxic air pollutants from coal and oil-fired power plants, referred to as the EPA’s Mercury and Air Toxics Standards (“MATS”). Regulation of mercury emissions by the EPA, pursuant to state programs, or pursuant to legislation implementing an international treaty may decrease the future demand for coal, which would reduce our royalties revenues.

 

   

The Clean Air Act requires the EPA to set standards, referred to as national ambient air quality standards (“NAAQS”), for six common air pollutants. Areas that are not in compliance (referred to as non-attainment areas) with these standards must take steps to reduce emissions levels. On February 9, 2010, the EPA published a revised NAAQS for nitrogen dioxide. On June 22, 2010, the EPA published a final rule that tightens the NAAQS for sulfur dioxide. Non-attainment designations will be finalized by June 2012 for the rules respectively; state implementation plans are due in the winter of 2014; and the deadline to achieve attainment is the summer of 2017. We do not know whether or to what extent these developments might indirectly reduce the demand for coal mined by our lessees.

 

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The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels. These acid rain requirements would not be supplanted by the CSAPR, were it to take effect.

 

   

The EPA’s regional haze program is designed to improve visibility in national parks and wilderness areas. On December 23, 2011, the EPA Administrator signed a final rule under which the emission caps imposed under the CSAPR for a given state would supplant the obligations of that state with regard to visibility protection. That rule has not yet been published, and EPA’s plans about publishing this rule in light of the stay of the CSAPR have yet to be announced.

 

   

In addition, the EPA’s new source review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly increase emissions, to install the more stringent air emissions control equipment. This program may indirectly reduce the demand for coal from our lessees’ operations.

 

   

There is pending litigation to force the EPA to list coal mines as a category of air pollution sources that endanger public health or welfare under Section 111 of the Clean Air Act and establish standards to reduce emissions from new or modified coal mine sources of methane and other emissions our lessees’ operations could be affected if these standards are implemented by the EPA or the applicable states.

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 are currently subject to judicial challenge, but the D.C. Circuit Court of Appeals has refused to stay their implementation while the challenges are pending. 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. Under a consent decree with environmental groups, the EPA is expected to finalize new source performance standards (“NSPS”) for electric power generation facilities in May 2012. As of early December 2012, EPA reportedly has prepared a proposal to regulate greenhouse gas, or GHG, emissions from only new plants, not existing ones, but that proposal is pending review at the Office of Management and Budget, and is not yet public. EPA’s failure to propose rules by the required date will delay final action.

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.

 

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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 31.5 cents per ton on surface-mined coal and 13.5 cents per ton on underground-mined coal. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation of orphaned mine sites and abandoned mine drainage control on a statewide basis.

Federal and state laws require bonds to secure 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. 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. Whether this decision reduces the back up and delay in the Section 404 permit application procedures remains to be seen.

EPA also has statutory “veto” power over a Section 404 permit if EPA determines, 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. More frequent use of the EPA’s Section 404 “veto” power as well as the increased risk of application of this power to previously permitted projects could create uncertainly with regard to 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 lessess may no longer seek general permits under Nationwide Permit 21 (“NWP 21”) adopted by the Army Corps under its authority in Section 404 of the CWA because on June 17, 2010, the Army Corps suspended the use of NWP 21 in the Appalachian states where our lessees operate, but NWP 21 authorizations already granted remain in effect. While the suspension is in effect, our lessees must seek 404 permits on an individual basis subject to the EPA measures discussed above with the uncertainties and delays attendant to that process for now.

In December 2008, the Department of Interior published the Excess Spoil, Coal Mine Waste and Buffers for Perennial and Intermittent Streams rule under SMCRA in part to clarify when valley fills are permitted. The rule would require a 100-foot buffer around all waters, including streams, lakes, ponds and wetlands. However, the rule would exempt certain activities, such as permanent spoil fills and coal waste disposal facilities, and allow mining that changes a waterway’s flow, providing the mining company repairs 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 agreed to rewrite the “stream buffer zone rule”. In addition, Congress has proposed, and may in the future propose, legislation to restrict the placement of mining material in streams.

Total Maximum Daily Load, or TMDL, regulations under the CWA establish a process to calculate the maximum amount of a pollutant that a water body can receive and still meet state water quality standards and to allocate pollutant loads among the point- and non-point pollutant sources discharging into that water body. This process applies to those waters that states have designated as impaired (not meeting present water quality standards). Industrial dischargers, including coal mines, discharging to such waters will be required to meet new TMDL allocations for these stream segments. The 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 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.

 

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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.

Natural Gas Midstream Segment

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

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

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

 

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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 environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012. 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 is also considering regulation of hydraulic fracturing activities on public lands. In addition, legislation has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.

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. 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. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. 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, 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 state and local governments in the Marcellus Shale region in Pennsylvania and New York have 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.

Air Emissions. Our natural gas midstream operations are subject to the CAA and comparable state laws and regulations. See “— Coal and Natural Resource Management Segment — Air Emissions.” These laws and regulations govern emissions of pollutants into the air resulting from the activities of our processing plants and compressor stations and also impose procedural requirements on how we conduct our natural gas midstream operations. Such laws and regulations may include requirements that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, strictly comply with the emissions and operational limitations of air emissions permits we are required to obtain or utilize specific equipment or technologies to control emissions.

 

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On July 28, 2011, the EPA proposed new standards to reduce air pollution from oil and gas drilling operations. The proposal includes a new source performance standard for volatile organic compounds, a new source performance standard for sulfur dioxide, an air toxics standard for natural gas production, and an air toxics standard for natural gas transmission and storage. We have not evaluated the effect these new standards would have on our operations or on those of natural gas producers but any increase in costs associated with production and gathering operations could have an adverse effect on our operations.

Recent actions taken by the EPA have suggested that all natural gas operations operated by a single entity within a given area should be aggregated 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.

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

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

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.

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

Employees and Labor Relations

We do not have employees. To carry out our operations, our general partner and its affiliates employed 250 employees who directly supported our operations at December 31, 2011. 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.

 

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Item 1A Risk Factors

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

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

 

   

the amount of coal our lessees are able to produce;

 

   

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

 

   

our lessees’ timely receipt of payment from their customers;

 

   

our timely receipt of payments from our lessees;

 

   

the amount of natural gas transported in our gathering systems;

 

   

the amount of throughput in our processing plants;

 

   

the price of and demand for natural gas;

 

   

the price of and demand for NGLs;

 

   

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

 

   

the relationship between natural gas and NGL prices, which impact the effectiveness of our hedging positions, if any; and

 

   

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

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

 

   

the level of capital expenditures we make;

 

   

the cost of acquisitions, if any;

 

   

our debt service requirements;

 

   

fluctuations in our working capital needs;

 

   

restrictions on distributions contained in our debt agreements;

 

   

prevailing economic conditions; and

 

   

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

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

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, 2011, our total outstanding long-term indebtedness was approximately $841.0 million. 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 indenture 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.

 

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

 

   

make it more difficult for us to make distributions to our unitholders;

 

   

impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general partnership purposes or other purposes;

 

   

result in higher interest expense in the event of increases in interest rates since some of our debt is, and will continue to be, at variable rates of interest;

 

   

have a material adverse effect on us if we fail to comply with financial and restrictive covenants in our debt agreements and an event of default occurs as a result of that failure that is not cured or waived;

 

   

require us to dedicate a substantial portion of our cash flow to payments of our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general partnership requirements;

 

   

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

 

   

place us at a competitive disadvantage compared to our competitors that have proportionately less debt.

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 indenture 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:

 

   

pay distributions on, redeem or repurchase our equity interests or redeem or repurchase our subordinated debt;

 

   

make investments;

 

   

incur or guarantee additional indebtedness or issue preferred securities;

 

   

create or incur certain liens;

 

   

enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

 

   

consolidate, merge or transfer all or substantially all of our assets;

 

   

engage in transactions with affiliates;

 

   

create unrestricted subsidiaries; and

 

   

create non-guarantor subsidiaries.

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.

 

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

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

 

   

our unitholders’ proportionate ownership interest in us will decrease;

 

   

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

 

   

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

 

   

the ratio of taxable income to distributions may increase; and

 

   

the market price of our common units may decline.

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

 

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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.

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 Coal and Natural Resource Management Business

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

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

 

   

the method of mining;

 

   

credit review of their customers;

 

   

marketing of the coal mined;

 

   

coal transportation arrangements;

 

   

negotiations with unions;

 

   

employee hiring and firing;

 

   

employee wages, benefits and other compensation;

 

   

permitting;

 

   

surety bonding; and

 

   

mine closure and reclamation.

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

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

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

 

   

the inability to acquire necessary permits;

 

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

 

   

changes in governmental regulation of the coal industry;

 

   

mining and processing equipment failures and unexpected maintenance problems;

 

   

adverse claims to title or existing defects of title;

 

   

interruptions due to power outages;

 

   

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

 

   

labor-related interruptions;

 

   

employee injuries or fatalities; and

 

   

fires and explosions.

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

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

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

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

We depend on a limited number of primary operators for a significant portion of our coal royalties revenues. In the year ended December 31, 2011, five primary operators, each with multiple leases, accounted for 66% of our coal royalties revenues and 9% 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 business will be adversely affected if we are unable to replace or increase our coal reserves through acquisitions.

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

 

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

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

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

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

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

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

One of our lessees has one mine operated by unionized employees. This mine was our second largest mine on the basis of coal production for the year ended December 31, 2011. 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:

 

   

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

 

   

the amount of ultimately recoverable coal in the ground;

 

   

the effects of regulation by governmental agencies; and

 

   

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

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

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. During the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. Increased competition by coal producers or producers of alternate fuels could decrease the demand for, or pricing of, or both, for our coal, adversely impacting demand for the coal that our lessees produce and thereby reducing our coal royalties revenues.

        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 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. If foreign demand for U.S. coal were to decline, this decline could cause 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.

 

 

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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.”

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 greenhouse gases, primarily through the development of regional greenhouse gas cap-and-trade programs.

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

The permitting of new coal-fired power plants has also been contested by state regulators and environmental organizations for concerns related to greenhouse gas emissions from the new plants. Other state regulatory authorities have also rejected the construction of new coal-fired power plants based on the uncertainty surrounding the potential costs associated with greenhouse gas emissions from these plants under future laws limiting the emissions of carbon dioxide. In addition, several permits issued to new coal-fired power plants without limits on greenhouse gas emissions have been appealed to EPA’s Environmental Appeals Board. The regulation of emissions of GHGs associated with the use of coal may lead 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 some cases, the EPA is retroactively rescinding permits that have 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.

 

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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 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.

Risks Related to Our Natural Gas Midstream Business

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.

 

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

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

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

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

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

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

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

We are subject to significant risks due to fluctuations in natural gas commodity prices. During 2011, we generated a majority of our gross margin from two types of contractual arrangements under which our margin is exposed to increases and decreases in the price of natural gas and NGLs — gas purchase/keep-whole and percentage-of-proceeds arrangements. See Item 1, “Business — Contracts — Natural Gas Midstream Segment.”

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

 

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

 

   

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

 

   

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

 

   

the level of domestic oil and natural gas production;

 

   

the availability of imported oil and natural gas;

 

   

actions taken by foreign oil and gas producing nations;

 

   

the availability of local, intrastate and interstate transportation systems;

 

   

the availability and marketing of competitive fuels;

 

   

the impact of energy conservation efforts; and

 

   

the extent of governmental regulation and taxation.

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

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing operations. Readily available access to debt and equity capital and credit availability 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. 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 realize the operating efficiencies, competitive advantages, cost savings or other benefits expected from these acquisitions. Future acquisitions might not generate increases in our cash distributions to our unitholders, and because of the capital used to complete such acquisitions, or the debt incurred, our results of operations may change significantly.

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

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

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

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

 

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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 2011, 47% of our natural gas midstream segment revenues and 40% of our total consolidated revenues resulted from four of our natural gas midstream customers, Conoco Phillips Company, Williams NGL Marketing, LLC, Tenaska Marketing Ventures, and Targa Liquids Marketing and Trade. Any nonpayment or nonperformance by our natural gas midstream segment customers would reduce our cash flows.

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

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

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

In order to manage our exposure to price risks in the marketing of our natural gas and NGLs, we continually monitor commodity prices and when it is opportunistic, we may choose to enter into condensate, natural gas or NGL price hedging arrangements with respect to a portion of our expected production. Historically, our hedges are limited in duration, usually for periods of two years or less. However, in connection with acquisitions, sometimes our hedges are for longer periods. These hedging transactions may limit our potential gains if NGL prices were to rise over the price established by the hedging arrangements, or if prices decline with respect to our natural gas hedges entered into to lock the frac spread. Moreover, for 2012 we have entered into derivative transactions related to only a portion of our condensate, natural gas and NGL volumes. As a result, we will continue to have direct commodity price risk with respect to the unhedged portion of these volumes. In trying to maintain an appropriate balance, we may end up hedging too much or too little, depending upon how natural gas or NGL prices fluctuate in the future.

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

 

   

our production is less than expected;

 

   

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

 

   

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

 

   

a sudden, unexpected event materially impacts natural gas or NGL prices.

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

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

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

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

 

   

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

 

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inadvertent damage from construction and farm equipment;

 

   

leaks of natural gas, NGLs and other hydrocarbons; and

   

fires and explosions.

These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. Our natural gas midstream operations are concentrated in Texas, Oklahoma and Pennsylvania, 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.

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.

 

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The natural gas midstream segment has completed a number of acquisitions in recent years, including the North Texas System (Lone Star Gathering, L.P., or Lone Star). See Note 3 to the Consolidated Financial Statements for a description of our natural gas midstream segment’s material acquisitions. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, and the resulting amount of goodwill, if any. Unforeseen changes in operations, the business environment or market conditions could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows. This could result in impairment charges being recorded in our Consolidated Statements of Income.

Tax Risks to Our Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, 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.

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

 

 

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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.

 

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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.

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 coal reserves and related infrastructure investments and our natural gas gathering and processing systems as of December 31, 2011:

 

LOGO

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

Coal Reserves and Production

As of December 31, 2011, we owned or controlled approximately 893 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:

 

   

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

 

   

Northern Appalachia Basin : properties located in northern West Virginia;

 

   

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

 

   

San Juan Basin : properties located in the four corners area of New Mexico.

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

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.

 

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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, 2011, our lessees operated 44 surface mines and 54 underground mines. Approximately 45% of the coal produced from our properties in 2011 came from underground mines and 55% came from surface mines. Most of our lessees use the continuous mining method in their underground mines located on our properties. In continuous mining, main airways and transportation entries are developed and remote-controlled continuous miners extract coal from “rooms,” leaving “pillars” to support the roof. Shuttle cars transport coal to a conveyor belt for transportation to the surface. In several underground mines, our lessees use two continuous miners running at the same time, also known as a supersection, to improve productivity and reduce unit costs.

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

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

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

 

     Production for Year
Ended December 31,
 

Property

   2011      2010      2009  

Central Appalachia

     19.7         18.2         18.3   

Northern Appalachia

     3.9         4         3.8   

Illinois Basin

     4.7         4.2         4.7   

San Juan Basin

     10.1         8.1         7.5   
  

 

 

    

 

 

    

 

 

 

Total

     38.4         34.5         34.3   
  

 

 

    

 

 

    

 

 

 

 

     Proven and Probable Reserves as of December 31, 2011  

Property

   Underground      Surface      Total      Steam      Metallurgical      Total  

Central Appalachia

     472.4         191.5         663.9         562.8         101.1         663.9   

Northern Appalachia

     25.9         —           25.9         25.9         —           25.9   

Illinois Basin

     175.3         8.9         184.2         184.2         —           184.2   

San Juan Basin

     —           19.3         19.3         19.3         —           19.3   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     673.6         219.7         893.3         792.2         101.1         893.3   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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Of the approximately 893 million tons of proven and probable coal reserves to which we had rights as of December 31, 2011, we owned the mineral interests and the related surface rights to 434 million tons, or 49%, and we owned only the mineral interests to 281 million tons, or 31%. We leased the mineral rights to the remaining 178 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 2011, our aggregate expenses to third-party surface and mineral owners were $12.9 million.

The following table sets forth the coal reserves we owned and leased with respect to each of our coal properties as of December 31, 2011 (tons in millions):

 

Property

   Owned      Leased      Total Controlled  

Central Appalachia

     519.3         144.6         663.9   

Northern Appalachia

     25.9         —           25.9   

Illinois Basin

     154.7         29.5         184.2   

San Juan Basin

     15.4         3.9         19.3   
  

 

 

    

 

 

    

 

 

 

Total

     715.3         178.0         893.3   
  

 

 

    

 

 

    

 

 

 

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

 

     2011     2010     2009  

Reserves - beginning of year

     803.7        828.6        826.8   

Purchase of coal reserves

     113.8        11.4        2.4   

Tons mined by lessees

     (38.4     (34.5     (34.3

Revisions of estimates and other

     14.2        (1.8     33.7   
  

 

 

   

 

 

   

 

 

 

Reserves - end of year

     893.3        803.7        828.6   
  

 

 

   

 

 

   

 

 

 

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, 2011, 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, 2011 (tons in millions):

 

            Sulfur Content      Typical Clean
Coal Quality
 
            Reserves as of December 31, 2011      Heat Content  

Property

   Compliance
(1)
     Low
Sulfur (2)
     Medium
Sulfur
     High
Sulfur
     Sulfur
Unclassified
     Total      BTU
per
Pound  (3)
     Sulfur
(%)
     Ash
(%)
 

Central Appalachia

     207.3         301.9         194.1         77.2         90.7         663.9         14,041         1.04         6.50   

Northern Appalachia

     —           —           —           25.9         —           25.9         12,900         2.58         8.80   

Illinois Basin

     —           —           —           184.2         —           184.2         11,034         2.39         8.32   

San Juan Basin

     —           12.6         5.4         1.3         —           19.3         9,200         0.89         17.80   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

          

Total

     207.3         314.5         199.5         288.6         90.7         893.3            
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

          

 

(1) Compliance coal is low sulfur coal which, when burned, emits less than 1.2 pounds of sulfur dioxide per million BTU. Compliance coal meets the sulfur dioxide emission standards imposed by Phase II of the CAA without blending in other coals or using sulfur dioxide reduction technologies. Compliance coal is a subset of low sulfur coal and is, therefore, also reported within the amounts for low sulfur coal.
(2) Includes compliance coal.
(3) As-received BTU per pound includes the weight of moisture in the coal on an as sold basis.

 

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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, 2011 (tons in millions):

 

     Proven and Probable Reserves As of
December 31, 2011
 

Property

   Total
Controlled
     Leased to
Operators
     Percentage
Leased
 

Central Appalachia

     663.9         621.3         94

Northern Appalachia

     25.9         25.2         97

Illinois Basin

     184.2         117.9         64

San Juan Basin

     19.3         19.3         100
  

 

 

    

 

 

    

 

 

 

Total

     893.3         783.7         88
  

 

 

    

 

 

    

 

 

 

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 7.0 Bcfe of proved oil and gas reserves located in Kentucky, Tennessee, Virginia and West Virginia.

Natural Gas Midstream Systems

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

We owned seven natural gas processing facilities having 420 MMcfd of total capacity as of December 31, 2011. We are in the process of adding an additional 120 MMcfd of processing capacity which is expected to be in service during 2012. Our natural gas midstream operations include four natural gas gathering and processing systems and three stand-alone natural gas gathering systems, including: (i) the Panhandle gathering and processing facilities in the Texas/Oklahoma panhandle area; (ii) the Crossroads gathering and processing facilities in East Texas; (iii) the Crescent gathering and processing facilities in central Oklahoma; (iv) the Arkoma gathering system in eastern Oklahoma; (v) the North Texas gathering and pipeline facilities in the Fort Worth Basin; (vi) the Hamlin gathering and processing facilities in west-central Texas; and (vii) the Marcellus gathering system located in northern Pennsylvania. These assets included approximately 4,426 miles of natural gas gathering pipelines as of December 31, 2011. In addition, we own a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin, and a 50% member interest in Crosspoint, a joint venture that gathers residue gas from our Crossroads Plant and transports it to market. We also own a 51% member 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.

Panhandle System

General. The Panhandle System is a natural gas gathering system stretching over eleven counties in the Anadarko Basin of the panhandle of Texas and Oklahoma. The system consists of approximately 1,964 miles of natural gas gathering pipelines, ranging in size from two to 16 inches in diameter, and the Antelope Hills, Beaver, Spearman and Sweetwater natural gas processing plants. Included in the system is an 11-mile, 10-inch diameter, FERC-jurisdictional residue line.

 

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Due to the increased well development activities in the Panhandle region of the Midstream operations, our system volumes have increased significantly over past years’ volumes. The increase in the volumes we have under contract in the Granite Wash has outpaced the capacity of our processing plants in the Panhandle. Further, third-party processing plants in the Panhandle region, that we have traditionally relied on to manage overruns in volumes, are fully utilized and unable to handle our excess volumes. Although we have recently been able to utilize some off system processing capacity, we expect these constraints to continue until our new facilities come on line in early 2012. We continue to take steps to alleviate our capacity constraints, and since our acquisition of the Antelope Hills processing facility in June 2011, we have initiated both our Phase One expansion of the Antelope Hills facility from 20 MMcfd to 80 MMcfd, and our Phase Two expansion of that facility to bring the processing capacity to 140 MMcfd. Phase One is scheduled to be in service in the first quarter of 2012 and is expected to provide significant relief to our current processing capacity constraints. Phase Two is expected to be operational by mid-year 2012, and it will enable us to meet our expected future processing requirements as volumes continue to grow. 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.

The Panhandle System is comprised of a number of major gathering systems and 43 compressor stations that gather natural gas, directly or indirectly, to the Antelope Hills, Beaver, Spearman and Sweetwater plants. These include the Beaver, Perryton, Spearman, Wolf Creek/Kiowa Creek, South Lipscomb and Ellis systems. These gathering systems are located in Beaver, Ellis, Harper, and Roger Mills Counties in Oklahoma and Hansford, Hemphill, Hutchinson, Lipscomb, Ochiltree, Roberts and Wheeler Counties in Texas.

The Antelope Hills plant has 20 MMcfd of inlet gas capacity with additional capacity being constructed. 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.

Each of the Beaver plant and Spearman Plant has 100 MMcfd of inlet gas capacity.

The Sweetwater plant has 60 MMcfd of inlet capacity.

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 pipeline 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 Northern Natural Gas 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.

Crossroads System

General. The Crossroads System is a natural gas gathering system located in east Texas. The Crossroads System consists of approximately eight miles of natural gas gathering pipelines, ranging in size from eight to 12 inches in diameter, and the Crossroads plant. The Crossroads System also includes approximately 20 miles of six-inch NGL pipeline that transports the NGLs produced at the Crossroads plant to the Panola Pipeline.

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

 

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Natural Gas Supply and Markets for Sale of Natural Gas and NGLs. The Crossroads System delivers the residue gas from the Crossroads plant into the CenterPoint Energy pipeline for sale or transportation to market. The NGLs produced at the Crossroads plant are delivered into the Panola Pipeline for transportation to Mont Belvieu, for fractionation.

Crescent System

General. The Crescent System is a natural gas gathering system stretching over seven counties within central Oklahoma’s Sooner Trend. The system consists of approximately 1,708 miles of natural gas gathering pipelines, ranging in size from two to 10 inches in diameter, and the Crescent natural gas processing plant located in Logan County, Oklahoma. Fourteen compressor stations are operating across the Crescent System.

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

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

Hamlin System

General. The Hamlin System is a natural gas gathering system stretching over eight counties in West Central Texas. The system consists of approximately 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.

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.

North Texas System

General. The North Texas assets are located in the southern portion of the Fort Worth Basin of North Texas and include approximately 135 miles of gas gathering pipelines and approximately 240 thousand acres dedicated by active producers. This expands the geographic scope of the natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin.

Natural Gas Supply. The gathering and transportation infrastructure captures current and expected volumes in Johnson, Hill, Bosque, Somervell, Hamilton and Erath counties.

Marcellus System

General. 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 County system. In April 2011, we also began construction on the second phase of the Lycoming County system, which is expected to be operational in the first quarter of 2012. The Lycoming County system consists of a 30- inch trunk line. Construction and development to provide gathering, compression and related services in Lycoming and Wyoming Counties are ongoing.

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

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. The water pipeline is expected to be operational in 2012.

 

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Item 3 Legal Proceedings

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

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

On November 18, 2011, the Court entered an Order and Final Judgment approving the settlement and dismissing the complaint with prejudice. The settlement became final and non-appealable on December 18, 2011.

We are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. See Item 1, “Business — Government Regulation and Environmental Matters,” for a more detailed discussion of our material environmental obligations.

Item 4 Reserved

 

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Part II

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 2011 and 2010 were as follows:

 

Quarter Ended

   High      Low      Cash
Distribution
Declared
 

December 31, 2011

   $ 26.94       $ 21.13       $ 0.51   

September 30, 2011

   $ 28.05       $ 20.85       $ 0.50   

June 30, 2011

   $ 28.31       $ 24.00       $ 0.49   

March 31, 2011

   $ 29.10       $ 24.41       $ 0.48   

December 31, 2010

   $ 29.11       $ 24.78       $ 0.47   

September 30, 2010

   $ 25.00       $ 20.26       $ 0.47   

June 30, 2010

   $ 24.75       $ 10.01       $ 0.47   

March 31, 2010

   $ 24.93       $ 19.63       $ 0.47   

Equity Holders

As of December 31, 2011, there were 182 record holders and approximately 61,520 beneficial owners of our common units.

Common Unitholder Return Performance Presentation

The performance graph below compares the cumulative total unitholder return on our common units with the cumulative total returns on the Standard & Poor’s 500 Index (the “S&P 500 Index”) and the Alerian MLP Total Return Index (the “Alerian Total Return Index”). The Alerian Total Return Index is a composite of the 50 most prominent energy master limited partnerships and limited liability companies, as determined by Standard & Poor’s using a float-adjusted market capitalization methodology. The graph assumes an investment of $100 in our common units, and in each of the S&P 500 Index and the Alerian Total Return Index on December 31, 2006 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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LOGO

 

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     12/31/2006      12/31/2007      12/31/2008      12/31/2009      12/31/2010      12/31/2011  

Penn Virginia Resource Partners, L.P

     100.0         100.5         50.8         108.4         154.1         149.5   

S&P 500 Total Return Index

     100.0         105.5         66.5         84.1         96.7         98.8   

Alerian MLP Total Return Index

     100.0         112.7         71.1         125.4         170.4         194.1   

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, 2011, 2010, 2009, 2008 and 2007, 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”:

 

     2011      2010      2009      2008      2007  
            (in thousands, except per unit data)         

Statement of Income Data:

              

Revenues (1)

   $ 1,159,975       $ 864,136       $ 656,704       $ 881,580       $ 549,445   

Expenses (1)

   $ 1,006,404       $ 742,551       $ 550,779       $ 768,408       $ 434,202   

Operating income

   $ 153,571       $ 121,585       $ 105,925       $ 113,172       $ 115,243   

Net income

   $ 96,343       $ 64,187       $ 62,911       $ 102,598       $ 54,576   

Net income attributable to Penn Virginia Resource Partners, L.P.

   $ 97,007       $ 37,144       $ 37,879       $ 52,686       $ 29,169   

Common Unit Data:

              

Net income per limited partner unit, basic and diluted (2)

   $ 1.45       $ 0.97       $ 0.99       $ 1.38       $ 0.76   

Distributions paid (3)

   $ 135,296       $ 122,024       $ 120,450       $ 108,263       $ 79,579   

Distributions paid per unit (3)

   $ 1.94       $ 1.88       $ 1.88       $ 1.82       $ 1.66   

Balance Sheet and Other Financial Data:

              

Property, plant and equipment, net

   $ 1,282,297       $ 971,046       $ 900,844       $ 895,119       $ 731,282   

Total assets (4)

   $ 1,593,992       $ 1,304,205       $ 1,219,063       $ 1,227,674       $ 942,251   

Long-term debt

   $ 841,000       $ 708,000       $ 620,100       $ 568,100       $ 399,153   

Cash flows provided by operating activities

   $ 190,330       $ 178,450       $ 158,214       $ 137,187       $ 126,480   

Additions to property, plant and equipment

   $ 376,602       $ 124,116       $ 80,677       $ 332,028       $ 225,040   

Other Statistical Data:

              

Coal royalty tons (in thousands)

     38,357         34,512         34,330         33,690         32,528   

System throughput volumes (MMcfd)

     495         355         332         270         186   

 

(1) In 2010, 2009 and 2008, we recorded $27.8 million, $72.5 million and $127.9 million of natural gas midstream revenue and $27.8 million, $72.5 million and $127.9 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG LP, a subsidiary of Penn Virginia Corporation and considered a related party company up to June 7, 2010, and the subsequent sale of that gas to third parties. We took title to the gas prior to transporting it to third parties. These transactions do not impact the gross margin, nor do they impact operating income.
(2) Pursuant to the Merger, PVG’s unitholders received 0.98 of a PVR common unit for each PVG common unit they owned, or approximately 38.3 million of PVR common units in the aggregate, in exchange for all outstanding PVG common units. Also pursuant to the Merger, approximately 19.6 million PVR common units that were held by PVG were cancelled. As a result, PVR’s common units outstanding increased from 52.3 million to 71.0 million. However, for historical reporting purposes, the impact of this change was accounted for as a reverse unit split of 0.98 to 1.0. Therefore, since PVG was the surviving entity for accounting purposes, the weighted average common units outstanding used for basic and diluted earnings per unit calculations are PVG’s historical weighted average common units outstanding adjusted for the retrospective application of the reverse unit split. Amounts reflecting historical PVG common unit and per common unit amounts included in this report have been restated for the reverse unit split.

 

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(3) Distribution paid and Distributions paid per unit have been retroactively restated to only include the amounts paid to public unitholders of PVR and PVG’s common units. The distributions paid are consistent with the distributions to partners noted in the consolidated statements of cash flows. The distributions paid per unit represent the distributions declared and paid by PVR for the noted time periods.
(4) Total assets for the year ended December 31, 2011 include PVR’s Middle Fork acquisition, which expanded our geographic scope in the Central Appalachian coal region. During 2010 and 2011, we increased internal growth project spending in our Marcellus and Panhandle Systems to expand our natural gas gathering and operational footprint in these areas. Total assets for the year ended December 31, 2008 include PVR’s Lone Star acquisition, which expanded the geographic scope of the PVR natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin.

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

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

Overview of Business

We are a publicly traded Delaware limited partnership principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. We currently conduct operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream. In 2011, our coal and natural resource management segment contributed $115.9 million, or 75%, to operating income, and our natural gas midstream segment contributed $37.6 million, or 25%, to operating income.

Coal and Natural Resource Segment

As of December 31, 2011, we owned or controlled approximately 893 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 2011, our lessees produced 38.4 million tons of coal from our properties and paid us coal royalties revenues of $162.9 million, for an average royalty per ton of $4.25. Approximately 81% of our coal royalties revenues in 2011 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.”

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.

 

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Natural Gas Midstream Segment

Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of December 31, 2011, we owned and operated natural gas midstream assets located in Oklahoma, Pennsylvania and Texas, including seven natural gas processing facilities having 420 MMcfd of total capacity and approximately 4,426 miles of natural gas gathering pipelines. We are currently in the process of adding an additional 120 MMcfd of processing capacity, which is expected to be in service during 2012. Our natural gas midstream business earns revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In addition, we are a partner in several joint ventures that gather and transport natural gas and water. We also own a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

In 2011, system throughput volumes at our gas processing plants and gathering systems, including gathering-only volumes, were 180.8 Bcf, or approximately 495 MMcfd. In 2011, 47% of our natural gas midstream segment revenues and 40% of our total consolidated revenues resulted from four of our natural gas midstream customers, Conoco Phillips Company, Williams NGL Marketing, LLC, Tenaska Marketing Ventures and Targa Liquids Marketing and Trade.

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 2011, our natural gas midstream segment made aggregate capital expenditures of $256.9 million, primarily related to our expansion of the Panhandle System and Marcellus System due to growth opportunities in those areas.

Key Developments

Coal and Natural Resource Management Segment

Middle Fork Acquisition

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.

Oatsville Reserves

In June 2011, we acquired 26.9 million tons of additional coal reserves in the Illinois Basin for $13.5 million. The Oatsville Reserve properties are deep minable Springfield V seam coal located on approximately 5,875 acres in Gibson and Pike counties in Indiana.

CC Lewis Acquisition

In October 2011, we acquired 17.4 million tons of additional coal reserves along with associated timber, oil and gas assets on over 4,700 acres in Kanawha and Boone counties, West Virginia. The coal reserves have excellent transportation access to both railroad and river barge facilities and producing deep mines are located on or adjacent to the acquired properties. The purchase price for the acquired assets and assumed liabilities was $21.3 million.

Natural Gas Midstream Segment

Marcellus Shale Construction

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 County system. In April 2011, we also began construction on the second phase of the Lycoming County system, which is expected to be operational in the first quarter of 2012. Construction and development to provide gathering, compression and related services in Lycoming and Wyoming Counties is ongoing. These Wyoming and Lycoming Counties gathering infrastructures are expected to capture anticipated volumes in the Marcellus Shale area, where we have been spending, and expect to continue to spend, a significant portion of our growth capital over the next year, and for the foreseeable future.

 

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Panhandle

Due to the increased well development activities in the Panhandle region of the Midstream operations, our system volumes have increased significantly over past years’ volumes. The increase in the volumes we have under contract in the Granite Wash has outpaced the capacity of our processing plants in the Panhandle. Further, third-party processing plants in the Panhandle region, that we have traditionally relied on to manage overruns in volumes, are fully utilized and unable to handle our excess volumes. Accordingly, we have had to forego processing a significant amount of our volumes in the Panhandle which has adversely impacted our gross margins during 2011. Although we have recently been able to utilize some off system processing capacity, we expect these constraints to continue until our new facilities come on line in early 2012. We continue to take steps to alleviate our processing capacity constraints. Since our acquisition of the Antelope Hills processing facility in June 2011, we have initiated both our Phase One expansion of the Antelope Hills facility from 20 MMcfd to 80 MMcfd, and our Phase Two expansion of that facility to bring the processing capacity to 140 MMcfd. Phase One is scheduled to be in service in the first quarter of 2012 and is expected to provide significant relief to our current processing capacity constraints. Phase Two is expected to be operational by mid-year 2012, and it will enable us to meet our expected future processing requirements as volumes continue to grow. 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.

Aqua Joint Venture

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 trunk line of our existing gathering system in Lycoming County. As of December 31, 2011 our contribution to the joint venture was $5.3 million.

2011 Commodity Prices

Coal royalties, which accounted for 86% of the coal and natural resource management segment revenues for year ended December 31, 2011, were higher as compared to 2010. The increase was attributed to increased production and higher realized coal royalty per ton primarily in the Central Appalachian and San Juan regions. Average coal prices received by lessees increased in 2011 compared to 2010 due to strong market pricing for thermal and metallurgical coal.

The average commodity prices for crude oil and natural gas liquids, or NGLs, increased in 2011 from levels experienced in 2010, while natural gas prices decreased.

Revenues, profitability and the future rate of growth of our natural gas midstream segment are highly dependent on market demand and prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market demand. We continually monitor commodity prices and when it is opportunistic, we may choose to use derivative financial instruments to hedge NGLs sold and natural gas purchased. Our derivative financial instruments include costless collars and swaps. Based upon November 2011 volumes, we have entered into hedging agreements covering approximately 94% of our commodity-sensitive volumes in 2012. This coverage amount is higher than historic coverage amounts due to the processing capacity constraints in our Texas/Oklahoma Panhandle System. These constraints have caused us to bypass more of our owned natural gas without processing, lowering the net NGL recoveries specific to PVR. The percent hedged will decrease in the near future as we continue to enact measures to alleviate our processing capacity constraints.

PVR Equity Issuance

In November 2011, we issued 7.0 million common units representing limited partner interests in PVR in a registered public offering. In December 2011, we issued an additional 1.05 million common units after the underwriters exercised in full their option to purchase additional units. Total net proceeds of $189.2 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:

 

     Year Ended December 31,  
     2011     2010     2009  

Revenues

   $ 1,159,975      $ 864,136      $ 656,704   

Expenses

     (1,006,404     (742,551     (550,779
  

 

 

   

 

 

   

 

 

 

Operating income

     153,571        121,585        105,925   

Other expense

     (57,228     (57,398     (43,014
  

 

 

   

 

 

   

 

 

 

Net income

     96,343        64,187        62,911   

Net loss (income) attributable to noncontrolling interests, pre-merger

     664        (27,043     (25,032
  

 

 

   

 

 

   

 

 

 

Net income attributable to Penn Virginia Resource Partners, L.P.

   $ 97,007      $ 37,144      $ 37,879   
  

 

 

   

 

 

   

 

 

 

Coal and Natural Resource Management Segment

Year Ended December 31, 2011 Compared With Year Ended December 31, 2010

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

 

            Favorable
(Unfavorable)
    % Change
Favorable
(Unfavorable)
 
     Year Ended December 31,       
     2011      2010       

Financial Highlights

          

Revenues

          

Coal royalties

   $ 162,915       $ 130,349       $ 32,566        25

Coal services

     8,839         7,830         1,009        13

Timber

     5,031         6,261         (1,230     (20 %) 

Oil and gas royalty

     3,944         2,651         1,293        49

Other

     8,224         5,397         2,827        52
  

 

 

    

 

 

    

 

 

   

Total revenues

     188,953         152,488         36,465        24
  

 

 

    

 

 

    

 

 

   

Expenses

          

Operating

     17,167         11,437         (5,730     (50 %) 

General and administrative

     18,682         17,046         (1,636     (10 %) 

Depreciation, depletion and amortization

     37,177         30,873         (6,304     (20 %) 
  

 

 

    

 

 

    

 

 

   

Total expenses

     73,026         59,356         (13,670     (23 %) 
  

 

 

    

 

 

    

 

 

   

Operating income

   $ 115,927       $ 93,132       $ 22,795        24
  

 

 

    

 

 

    

 

 

   

Other data

          

Coal royalty tons by region

          

Central Appalachia

     19,683         18,207         1,476        8

Northern Appalachia

     3,938         3,965         (27     (1 %) 

Illinois Basin

     4,705         4,182         523        13

San Juan Basin

     10,031         8,158         1,873        23
  

 

 

    

 

 

    

 

 

   

Total tons

     38,357         34,512         3,845        11
  

 

 

    

 

 

    

 

 

   

Coal royalties revenues by region

          

Central Appalachia

   $ 119,035       $ 92,827       $ 26,208        28

Northern Appalachia

     8,741         8,449         292        3

Illinois Basin

     12,493         11,208         1,285        11

San Juan Basin

     22,646         17,865         4,781        27
  

 

 

    

 

 

    

 

 

   

Total royalties

   $ 162,915       $ 130,349       $ 32,566        25
  

 

 

    

 

 

    

 

 

   

Coal royalties per ton by region ($/ton)

          

Central Appalachia

   $ 6.05       $ 5.10       $ 0.95        19

Northern Appalachia

     2.22         2.13         0.09        4

Illinois Basin

     2.66         2.68         (0.02     (1 %) 

San Juan Basin

     2.26         2.19         0.07        3
  

 

 

    

 

 

    

 

 

   

Average royalties per ton

   $ 4.25       $ 3.78       $ 0.47        12
  

 

 

    

 

 

    

 

 

   

 

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Revenues

Coal royalties revenues increased due to higher production and realized coal royalties per ton. The Middle Fork acquisition on January 25, 2011 contributed $10.2 million to Central Appalachia coal royalties and 1.7 million tons of coal production. Equipment added during 2010 to the mines in the San Juan Basin increased production and related coal royalties compared to the prior year.

Coal royalties per ton increased in all regions in 2011 compared to 2010, except for the Illinois Basin. In Central Appalachia, average coal prices received by lessees increased due to the strong market pricing for thermal and metallurgical coal. The reduced realized royalty rate in the Illinois Basin was due to contractual changes in royalties we receive on some properties in this region.

Consistent with the increase in coal production, coal services revenues increased in 2011.

Timber revenues decreased due to a reduction in timber harvested and average price received per board foot in 2011. These decreases are associated with the depressed construction and furniture making industries.

Oil and gas royalty income increased in 2011 due to a settlement against a producer for deductions made on past royalties. The Middle Fork acquisition and the $0.6 million in royalties earned from these properties also contributed to the increase.

Other revenues increased in 2011 due to minimum royalty forfeitures. Based upon lease contracts, which vary by lessee, lessees paying minimum royalties have an established time to recoup minimum royalties paid. If the stated levels of production have not occurred at the exhaustion of that time period, the minimum payments are recognized into earnings. Additionally, a gain on sale of property to a local oil and gas company related to their exploration activities was recognized in 2011.

Expenses

Operating expenses have increased primarily due to higher production on subleased properties and the recent Middle Fork acquisition and related operating costs. Increased pricing and mining activity by our lessees from subleased properties in Central Appalachia increased coal royalties expense. Mining activity on our subleased property fluctuates between periods due to the proximity of our property boundaries and other mineral owners.

General and administrative expenses increased as a result of our change in management structure related to the Merger, and some costs (such as executive and legal costs) we shared with our former parent, Penn Virginia Corporation, are no longer shared but are now direct costs of the Partnership. Also contributing to the increase were due diligence costs related to recent acquisitions. Partially offsetting these increases were lower employee costs related to equity compensation. In the second quarter of 2010, there was an acceleration of recognized equity compensation due to Penn Virginia Corporation’s divestiture of its interest in PVG.

DD&A expenses increased for the comparative periods due to the increase in coal production and related depletion expense.

 

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

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

 

            Favorable
(Unfavorable)
    % Change
Favorable
(Unfavorable)
 
     Year Ended December 31,       
     2010      2009       

Financial Highlights

          

Revenues

          

Coal royalties

   $ 130,349       $ 120,435       $ 9,914        8

Coal services

     7,830         7,332         498        7

Timber

     6,261         5,726         535        9

Oil and gas royalty

     2,651         2,471         180        7

Other

     5,397         8,636         (3,239     (38 %) 
  

 

 

    

 

 

    

 

 

   

Total revenues

     152,488         144,600         7,888        5
  

 

 

    

 

 

    

 

 

   

Expenses

          

Operating

     11,437         9,692         (1,745     (18 %) 

General and administrative

     17,046         14,539         (2,507     (17 %) 

Impairments

     —           1,511         1,511        —     

Depreciation, depletion and amortization

     30,873         31,330         457        1
  

 

 

    

 

 

    

 

 

   

Total expenses

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

 

 

    

 

 

    

 

 

   

Operating income

   $ 93,132       $ 87,528       $ 5,604        6
  

 

 

    

 

 

    

 

 

   

Other data

          

Coal royalty tons by region

          

Central Appalachia

     18,207         18,319         (112     (1 %) 

Northern Appalachia

     3,965         3,786         179        5

Illinois Basin

     4,182         4,724         (542     (11 %) 

San Juan Basin

     8,158         7,501         657        9
  

 

 

    

 

 

    

 

 

   

Total tons

     34,512         34,330         182        1
  

 

 

    

 

 

    

 

 

   

Coal royalties revenues by region

          

Central Appalachia

   $ 92,827       $ 85,183       $ 7,644        9

Northern Appalachia

     8,449         6,931         1,518        22

Illinois Basin

     11,208         12,420         (1,212     (10 %) 

San Juan Basin

     17,865         15,901         1,964        12
  

 

 

    

 

 

    

 

 

   

Total royalties

   $ 130,349       $ 120,435       $ 9,914        8
  

 

 

    

 

 

    

 

 

   

Coal royalties per ton by region ($/ton)

          

Central Appalachia

   $ 5.10       $ 4.65       $ 0.45        10

Northern Appalachia

     2.13         1.83         0.30        16

Illinois Basin

     2.68         2.63         0.05        2

San Juan Basin

     2.19         2.12         0.07        3
  

 

 

    

 

 

    

 

 

   

Average royalties per ton

   $ 3.78       $ 3.51       $ 0.27        8
  

 

 

    

 

 

    

 

 

   

Revenues

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

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

 

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

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

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

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

Expenses

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

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

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

DD&A expenses decreased slightly due to decreased timber depletion expense resulting from the lower harvest in 2010. The decrease was partially offset by an increase in coal depletion due to a shift in production mix of coal mined from our properties by our lessees.

 

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Natural Gas Midstream Segment

Year Ended December 31, 2011 Compared With Year Ended December 31, 2010

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

 

                 Favorable
(Unfavorable)
    % Change
Favorable
(Unfavorable)
 
     Year Ended December 31,      
     2011     2010      

Financial Highlights

        

Revenues

        

Residue gas

   $ 426,690      $ 359,745      $ 66,945        19

Natural gas liquids

     462,210        297,885        164,325        55

Condensate

     38,448        26,425        12,023        45

Gathering, processing and transportation fees

     37,863        18,109        19,754        109
  

 

 

   

 

 

   

 

 

   

Total natural gas midstream revenues

     965,211        702,164        263,047        37

Equity earnings in equity investments

     3,209        6,664        (3,455     (52 %) 

Producer services and other

     2,602        2,820        (218     (8 %) 
  

 

 

   

 

 

   

 

 

   

Total revenues

     971,022        711,648        259,374        36
  

 

 

   

 

 

   

 

 

   

Expenses

        

Cost of gas purchased

     817,937        577,813        (240,124     (42 %) 

Operating

     40,444        32,806        (7,638     (23 %) 

General and administrative

     22,798        23,235        437        2

Depreciation and amortization

     52,199        45,027        (7,172     (16 %) 
  

 

 

   

 

 

   

 

 

   

Total operating expenses

     933,378        678,881        (254,497     (37 %) 
  

 

 

   

 

 

   

 

 

   

Operating income

   $ 37,644      $ 32,767      $ 4,877        15
  

 

 

   

 

 

   

 

 

   

Operating Statistics

        

Daily throughput volumes (MMcfd)

     495        355        140        39

Gross margin

   $ 147,274      $ 124,351      $ 22,923        18

Cash impact of derivatives

     (17,921     (1,860     (16,061     (863 %) 
  

 

 

   

 

 

   

 

 

   

Gross margin, adjusted for impact of derivatives

   $ 129,353      $ 122,491      $ 6,862        6
  

 

 

   

 

 

   

 

 

   

Gross Margin

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

The gross margin increase was a result of higher system volumes, as well as higher NGL pricing and higher fractination, or frac, spreads. Natural gas prices were down for the comparative periods. Offsetting the higher volumes and frac spreads was a change in contract mix. Given our completion of certain assets in the Marcellus Shale, during 2011 we gathered and transported an average of 74 MMcfd of fee-based volumes from these assets. This added a lower-risk, lower-margin element to our total gross margin. Gross margin from the Marcellus System in 2011 was $26.2 million. We process gas under three general types of contracts (gas purchase/keep whole contracts, percentage-of-proceeds contracts, and fee-based arrangements). These contracts are more fully described Item 1, “Business – Contracts – Natural Gas Midstream Segment.” New gas volumes being added to our Panhandle system are primarily under fee-based processing percentage-of-proceeds contracts where we return the NGL revenue to the producers. The result of this is a relative volumetric decrease in the higher commodity-risked, higher-margin gas purchase/keep whole contracts; however, the performance of these fee-based and percentage of proceeds contracts does suffer during periods when we experience processing capacity constraints.

Due to the increased well development activities in the Panhandle region of the Midstream operations, our system volumes have increased significantly over historical volumes. The increase in the volumes we have under contract in the Granite Wash has outpaced the capacity of our processing plants in the Panhandle. Further, third-party processing plants in the Panhandle region, that we have traditionally relied on to manage overruns in volumes, are fully utilized and unable to handle our excess volumes. Accordingly, we have had to forego processing a significant amount of our volumes in the Panhandle which has adversely impacted our gross margins during 2011. Although we have recently been able to utilize some off system processing capacity, we expect these constraints to continue until our new facilities come on line in 2012. We continue to take steps to alleviate our processing capacity constraints.

 

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Since our acquisition of the Antelope Hills processing facility in June 2011, we have initiated both our Phase One expansion of the Antelope Hills facility from 20 MMcfd to 80 MMcfd, and our Phase Two expansion of that facility to bring the processing capacity to 140 MMcfd. Phase One is scheduled to be in service in the first quarter of 2012 and is expected to provide significant relief to our current processing capacity constraints. Phase Two is expected to be operational by mid-year 2012, and it will enable us to meet our expected future processing requirements as volumes continue to grow. 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.

We generated a portion of our gross margin from contractual arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of our risk management strategy, we use derivative financial instruments to hedge NGLs sold and natural gas purchased. See Note 6 to the Consolidated Financial Statements for a description of our derivatives. Midstream gross margin, including the cash impact of midstream derivatives, was $129.4 million compared to $122.5 million. This $6.9 million increase was primarily due to the increased system volumes and commodity pricing, partially offset by a relative increase in lower-risk, lower-margin, percentage of proceeds and fee-based contracts (as noted above), lower margins as a result of the short-term capacity constraints, and increased derivative settlements given the higher commodity prices.

Revenues Other Than Gross Margin

Equity earnings in our equity investments decreased primarily due to decreased volumes at Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin.

Expenses

Operating expenses increased due to our expansion projects and acquisitions. The related costs of these facilities included increased costs of labor, chemicals, compressor rentals, and property tax.

General and administrative expenses decreased slightly as a result of the acceleration of recognized equity compensation in the second quarter of 2010 due to Penn Virginia Corporation’s divestiture of its remaining interest in PVG. Offsetting this decrease are increased cost related to our change in management structure due to the Merger and some shared administrative costs with our former parent, Penn Virginia Corporation, are no longer shared but are now direct costs of the Partnership. Also, we incurred more due diligence costs this year related to acquisitions.

Depreciation and amortization expenses increased primarily due to acquisitions and capital expansions in the Marcellus Shale and Panhandle systems.

 

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

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

 

            Favorable
(Unfavorable)
    % Change
Favorable
(Unfavorable)
 
     Year Ended December 31,       
     2010     2009       

Financial Highlights

         

Revenues

         

Residue gas (1)

   $ 359,745      $ 289,427       $ 70,318        24

Natural gas liquids

     297,885        182,794         115,091        63

Condensate

     26,425        17,010         9,415        55

Gathering, processing and transportation fees

     18,109        15,558         2,551        16
  

 

 

   

 

 

    

 

 

   

Total natural gas midstream revenues

     702,164        504,789         197,375        39

Equity earnings in equity investments

     6,664        5,548         1,116        20

Producer services and other

     2,820        1,767         1,053        60
  

 

 

   

 

 

    

 

 

   

Total revenues

     711,648        512,104         199,544        39
  

 

 

   

 

 

    

 

 

   

Expenses

         

Cost of gas purchased (1)

     577,813        406,583         (171,230     (42 %) 

Operating

     32,806        29,096         (3,710     (13 %) 

General and administrative

     23,235        16,746         (6,489     (39 %) 

Depreciation and amortization

     45,027        38,905         (6,122     (16 %) 
  

 

 

   

 

 

    

 

 

   

Total operating expenses

     678,881        491,330         (187,551     (38 %) 
  

 

 

   

 

 

    

 

 

   

Operating income

   $ 32,767      $ 20,774       $ 11,993        58
  

 

 

   

 

 

    

 

 

   

Operating Statistics

         

Daily throughput volumes (MMcfd)

     355        332         23        7

Gross margin

   $ 124,351      $ 98,206       $ 26,145        27

Cash impact of derivatives

     (1,860     10,566         (12,426     (118 %) 
  

 

 

   

 

 

    

 

 

   

Gross margin, adjusted for impact of derivatives

   $ 122,491      $ 108,772       $ 13,719        13
  

 

 

   

 

 

    

 

 

   

 

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

Gross Margin

The gross margin increase was a result of higher commodity pricing and higher frac spreads. System volumes also increased during 2010, but primarily on systems not entirely exposed to commodity pricing. These systems include a newly constructed system in the Marcellus Shale region, a fee-based gathering system, and Crossroads, a primarily fee-based gathering and processing system. The volumes at our Panhandle and Crossroads processing plants (inlet volumes) also increased during 2010. Processing contracts on our Panhandle system are primarily gas purchase and percentage of proceeds contracts. Thus, we experienced a growth in our gross margin due to higher commodity pricing and frac spreads.

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

During 2010, we generated a portion of the gross margin from contractual arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of our risk management strategy, we use derivative financial instruments to hedge NGLs sold and natural gas purchased. The unfavorable impact of commodity derivatives was a result of changing commodity prices during 2010 and the expiration of older derivative instruments.

 

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Revenues Other Than Gross Margin

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

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

Expenses

Operating expenses increased due to our expanding footprint on existing and newly constructed systems. Increased costs included compressor rentals and labor costs.

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

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

Other

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

 

      Year Ended December 31,  
     2011     2010     2009  

Operating income

   $ 153,571      $ 121,585      $ 105,925   

Other income (expense)

      

Interest expense

     (44,287     (35,591     (24,653

Derivatives

     (13,442     (22,493     (19,714

Other

     501        686        1,353   
  

 

 

   

 

 

   

 

 

 

Net income

   $ 96,343      $ 64,187      $ 62,911   
  

 

 

   

 

 

   

 

 

 

Interest Expense. Our consolidated interest expense increased during 2011 due to the issuance of Senior Notes in April 2010. The Senior Notes bear an 8.25% interest rate, whereas the Revolver’s annualized interest rates have been 2.7%, 2.5% and 2.7% for the years ended December 31, 2011, 2010 and 2009. The Senior Notes were issued to pay down borrowings on the Revolver and to increase the availability of funds under the Revolver for acquisitions and growth capital needs. Non-cash amortization of debt issuance costs has also increased over the three year period due to the issuance of the Senior Notes and amendment fees on the Revolver.

Our consolidated interest expense for the periods presented is comprised of the following:

 

      Year Ended December 31,  

Source

   2011     2010     2009  

Interest on Revolver

   $ (15,352   $ (11,614   $ (16,546

Interest on Senior Notes

     (24,750     (16,706     —     

Debt issuance costs

     (5,779     (5,278     (4,392

Bank fees

     (1,748     (1,294     (585

Interest Rate Swaps

     —          (1,090     (3,356

Capitalized interest (1)

     3,342        391        226   
  

 

 

   

 

 

   

 

 

 

Total interest expense

   $ (44,287   $ (35,591   $ (24,653
  

 

 

   

 

 

   

 

 

 

 

(1) Capitalized interest primarily relates to the construction efforts on the Marcellus Shale and Panhandle systems.

 

 

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Derivatives. Our results of operations and operating cash flows were impacted by changes in market prices for NGLs, crude oil and natural gas, as well as the Interest Rate Swaps.

Commodity markets are volatile, and as a result, our hedging activity results can vary significantly. Our results of operations are affected by the volatility of changes in fair value, which fluctuate with changes in NGL, crude oil and natural gas prices. We determine the fair values of our commodity derivative agreements using discounted cash flows based on quoted forward prices for the respective commodities. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties for derivatives in an asset position, and our own credit risk for derivatives in a liability position.

During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps and our commodity derivatives are all recognized in the derivatives line item on our Consolidated Statements of Income.

Our derivative activity for the periods presented is summarized below:

 

      Year Ended December 31,  
     2011     2010     2009  

Interest Rate Swap unrealized derivative gain

   $ 7,250      $ 1,000        3,260   

Interest Rate Swap realized derivative loss

     (7,767     (8,215     (7,566

Interest Rate Swap other comprehensive income reclass

     (334     (715     —     

Natural gas midstream commodity unrealized derivative gain (loss)

     5,330        (12,703     (25,974

Natural gas midstream commodity realized derivative gain (loss)

     (17,921     (1,860     10,566   
  

 

 

   

 

 

   

 

 

 

Total derivative loss

   $ (13,442   $ (22,493   $ (19,714
  

 

 

   

 

 

   

 

 

 

Liquidity and Capital Resources

Cash Flows

On an ongoing basis, we generally satisfy our working capital requirements and fund our capital expenditures using cash generated from our operations, borrowings under the Revolver and proceeds from debt and equity offerings. We satisfy our debt service obligations and distributions to unitholders solely using cash generated from our operations. We believe that the cash generated from our operations and our borrowing capacity will be sufficient to meet our 2012 working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments and distributions. However, our ability to meet these requirements in the future will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and natural gas midstream market, many of which are beyond our control.

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

 

      Year Ended December 31,  
     2011     2010     2009  

Cash flows from operating activities:

      

Net income

   $ 96,343      $ 64,187      $ 62,911   

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

     94,229        103,257        100,066   

Net changes in operating assets and liabilities

     (242     11,006        (4,763
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     190,330        178,450        158,214   

Net cash used in investing activities

     (374,227     (122,787     (79,530

Net cash provided by (used in) financing activities

     176,573        (59,013     (77,708
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

   $ (7,324   $ (3,350   $ 976   
  

 

 

   

 

 

   

 

 

 

Cash Flows From Operating Activities

The overall increase in net cash provided by operating activities in 2011 as compared to 2010 was primarily driven by an increase in coal royalties revenue, an increase in natural gas midstream segment’s gross margin, and equity investment distributions in excess of equity earnings. These increases were offset by increased cash derivative payments and higher operating costs, which were incurred as a result of expanding operations.

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

 

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Cash Flows From Investing Activities

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

 

      Year Ended December 31,  
     2011      2010      2009  

Coal and natural resource management

        

Acquisitions

   $ 136,694       $ 27,641       $ 2,067   

Internal growth

     1         —           —     

Maintenance

     484         1,170         185   
  

 

 

    

 

 

    

 

 

 

Total

     137,179         28,811         2,252   
  

 

 

    

 

 

    

 

 

 

Natural gas midstream

        

Acquisitions

     12,243         —           27,514   

Internal growth

     233,932         96,334         36,863   

Maintenance

     10,727         14,126         8,399   
  

 

 

    

 

 

    

 

 

 

Total

     256,902         110,460         72,776   
  

 

 

    

 

 

    

 

 

 

Total capital expenditures

   $ 394,081       $ 139,271       $ 75,028   
  

 

 

    

 

 

    

 

 

 

Our 2011 capital expenditures consisted primarily of the Middle Fork acquisition in the Coal and Natural Resources Segment and natural gas midstream expansion capital used to increase our natural gas gathering and operational footprint in our Marcellus Shale and Panhandle Systems. During 2012, we expect to invest approximately $200 million to $250 million in internal growth capital.

Our 2010 capital expenditures consisted primarily of natural gas midstream expansion capital used to increase our natural gas gathering and operational footprint in our Panhandle and Marcellus Systems. We also added to our reserve base in Northern Appalachia by amending an existing coal mineral lease and from a coal mineral acquisition.

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

Cash Flows From Financing Activities

In November 2011, we issued 7.0 million common units representing limited partner interests in PVR in a registered public offering. In December 2011, we issued an additional 1.05 million common units after the underwriters exercised in full their option to purchase additional units. Total net proceeds of $189.2 million were used to repay a portion of the Revolver. Offsetting the repayment were funds drawn to finance our acquisitions and expansion growth capital. Also during 2011, we amended our Revolver to increase our borrowing capacity to $1.0 billion at a cost of $3.7 million and incurred $6.6 million of costs related to the Merger of PVR and PVG. Distributions have also increased annually due to both an increase in quarterly distributions and the Merger, which increased the number of outstanding units.

During 2010, we amended the Revolver to extend the maturity date and increase our borrowing capacity to $850 million. We also issued $300 million of Senior Notes. The net proceeds from the sale of the Senior Notes were used to repay borrowings under the Revolver. Debt issuance cost related to these events was $19.2 million. Offsetting the repayment were funds drawn to finance our expansion growth capital.

During 2009, we had net borrowings of $52.0 million under the Revolver. These borrowings were used to fund our capital expenditure program. We also incurred $9.3 million of costs to amend and increase the size of our Revolver.

In January 2012 we declared a $0.51 per unit quarterly distribution for the three months ended December 31, 2011 paid on February 13, 2012 to unitholders of record at the close of business on February 6, 2012.

Certain Non-GAAP Financial Measures

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

 

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     Three Months Ended
December 31,
    Year Ended
December 31,
 
     2011     2010     2011     2010  

Reconciliation of GAAP “Operating Income” to Non-GAAP “EBITDA”

        

Operating income

   $ 34,834      $ 39,424      $ 153,571      $ 121,585   

Depreciation, depletion and amortization

     24,019        21,117        89,376        75,900   
  

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA (a)

   $ 58,853      $ 60,541      $ 242,947      $ 197,485   
  

 

 

   

 

 

   

 

 

   

 

 

 

Reconciliation of GAAP “Net income” to Non-GAAP “Distributable cash flow”

        

Net income

   $ 17,317      $ 18,254      $ 96,343      $ 64,187   

Depreciation, depletion and amortization

     24,019        21,117<