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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007
Commission file number: 1-33171
Penn Virginia GP Holdings, L.P.
(Exact name of registrant as specified in its charter)
| Delaware | 20-5116532 | |
| (State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification Number) |
Three Radnor Corporate Center, Suite 300
100 Matsonford Road
Radnor, Pennsylvania 19087
(Address of principal executive offices)
Registrant’s telephone number, including area code: (610) 687-8900
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class |
Name of exchange on which registered | |
| Common Units | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. 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. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One)
Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes ¨ No x
The aggregate market value of common units held by non-affiliates of the registrant was $216,459,522 as of June 30, 2007 (the last business day of its most recently completed second fiscal quarter), based on the last sale price of such units as quoted on the New York Stock Exchange. For purposes of making this calculation only, the registrant has defined affiliates as including the registrant’s general partner, all affiliates of the registrant’s general partner and all directors and executive officers of the registrant’s general partner. This determination of affiliate status is not necessarily a conclusive determination for other purposes.
As of February 28 2008, 39,074,500 common units representing limited partner interests of the registrant were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
None
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PENN VIRGINIA GP HOLDINGS, L.P. AND SUBSIDIARIES
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| Item 1 | Business |
General
Penn Virginia GP Holdings, L.P. (NYSE: PVG) is a publicly traded Delaware limited partnership formed in June 2006 that currently owns three types of equity interests in Penn Virginia Resource Partners, L.P. (NYSE: PVR), or PVR, a publicly traded Delaware limited partnership that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas. Unless the context requires otherwise, references to the “Partnership,” “we,” “us” or “our” in this Annual Report on Form 10-K refer to Penn Virginia GP Holdings, L.P. and its subsidiaries.
Our Interest in PVR
Our only cash generating assets consist of our partner interests in PVR, which consist of the following:
| • | a 2% general partner interest in PVR, which we hold through our 100% ownership interest in Penn Virginia Resource GP, LLC, PVR’s general partner; |
| • | all of the incentive distribution rights in PVR, which we hold through our 100% ownership interest in PVR’s general partner; and |
| • | 19,587,049 common units of PVR, representing an approximately 42% limited partner interest in PVR. |
All of our cash flows are generated from the cash distributions we receive with respect to the PVR partner interests we own. PVR is required by its partnership agreement to distribute, and it has historically distributed within 45 days of the end of each quarter, all of its cash on hand at the end of each quarter, less cash reserves established by its general partner in its sole discretion to provide for the proper conduct of PVR’s business or to provide for future distributions. While we, like PVR, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of PVR. Most notably, our general partner does not have an economic interest in us and is not entitled to receive any distributions from us and our capital structure does not include incentive distribution rights. Therefore, our distributions are allocated exclusively to our common units, which is our only class of security currently outstanding.
Our ownership of PVR’s incentive distribution rights entitles us to receive the following percentages of cash distributed by PVR as it reaches the following target cash distribution levels:
| • | 13% of all incremental cash distributed in a quarter after $0.275 has been distributed in respect of each common unit of PVR for that quarter; |
| • | 23% of all incremental cash distributed after $0.325 has been distributed in respect of each common unit of PVR for that quarter; and |
| • | the maximum sharing level of 48% of all incremental cash distributed after $0.375 has been distributed in respect of each common unit of PVR for that quarter. |
Since 2001, PVR has increased its quarterly cash distribution 13 times from $0.25 per unit ($1.00 on an annualized basis) to $0.44 per unit ($1.76 on an annualized basis), which is its most recently declared distribution. These increased cash distributions by PVR have placed us at the third and maximum target cash distribution level as described above. As a consequence, any increase in cash distribution level from PVR will allow us to share at the 48% level and the cash distributions we receive from PVR with respect to our indirect ownership of the incentive distribution rights will increase more rapidly than those with respect to our ownership of the general partner and limited partner interests. Because we are at the maximum target cash distribution level on the incentive distribution rights, future growth in distributions we receive from PVR will not result from an increase in the target cash distribution level associated with the incentive distribution rights. See “—Partnership Distributions” for more information regarding the distributions we have received from PVR.
PVR’s Business
PVR is a publicly traded Delaware limited partnership formed by Penn Virginia Corporation (NYSE: PVA), or Penn Virginia, in 2001 that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. Both in its current limited partnership form and in its previous corporate form,
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PVR has managed coal properties since 1882. PVR currently conducts operations in two business segments: (1) coal and natural resource management and (2) natural gas midstream. We consolidate PVR’s results into our financial statements. In 2007, we had an approximately 55% interest in PVR’s net income, including incentive distribution rights. Our operating income was $115.2 million in 2007, compared to $102.4 million in 2006 and $78.1 million in 2005. In 2007, the PVR coal and natural resource management segment contributed $68.8 million, or 60%, to operating income, and the PVR natural gas midstream segment contributed $48.9 million, or 42%, to operating income. Corporate and other functions resulted in $2.5 million of operating expenses.
PVR Coal and Natural Resource Management Segment Overview
The PVR coal and natural resource management segment primarily involves the management and leasing of coal and natural resource properties and the subsequent collection of royalties. PVR also earns revenues from the provision of fee-based coal preparation and loading services, from the sale of standing timber on its properties, from oil and gas royalty interests it owns and from coal transportation, or wheelage, fees.
As of December 31, 2007, PVR owned or controlled approximately 818 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. As of December 31, 2007, approximately 89% of PVR’s proven and probable coal reserves were “steam” coal used primarily by electric generation utilities, and the remaining 11% were metallurgical coal used primarily by steel manufacturers. PVR enters into long-term leases with experienced, third-party mine operators, providing them the right to mine its coal reserves in exchange for royalty payments. PVR actively works with its lessees to develop efficient methods to exploit its reserves and to maximize production from its properties. PVR does not operate any mines. In 2007, PVR’s lessees produced 32.5 million tons of coal from its properties and paid PVR coal royalties revenues of $94.1 million, for an average royalty per ton of $2.89. Approximately 81% of PVR’s coal royalties revenues in 2007 and 84% of PVR’s coal royalties revenues in 2006 were derived from coal mined on its properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of PVR’s coal royalties revenues for the respective periods was derived from coal mined on its properties under leases containing fixed royalty rates that escalate annually. See “—PVR’s Contracts—PVR Coal and Natural Resource Management Segment” for a description of PVR’s coal leases.
PVR Natural Gas Midstream Segment Overview
The PVR natural gas midstream segment is engaged in providing gas processing, gathering and other related natural gas services. PVR owns and operates natural gas midstream assets located in Oklahoma and the panhandle of Texas. These assets include approximately 3,682 miles of natural gas gathering pipelines and three natural gas processing facilities having 160 MMcfd of total capacity. PVR’s natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines. PVR acquired its first natural gas midstream assets through the acquisition of Cantera Gas Resources, LLC, or Cantera, in March 2005.
In 2007, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 67.8 Bcf, or approximately 186 MMcfd. In 2007, three of PVR’s natural gas midstream customers, ConocoPhillips Company, Equistar Chemicals, LP and BP Canada Energy Marketing Corp., accounted for 25%, 14% and 14% of PVR’s natural gas midstream revenues and 20%, 11% and 11% of our total consolidated revenues.
Business Strategy
Our primary business strategy is to increase our cash distributions to our unitholders. We intend to monitor the implementation of PVR’s business strategies. Our business strategy includes supporting the growth of PVR by purchasing PVR units or lending funds to PVR to provide funding for acquisitions or for internal growth projects. We may also provide PVR with other forms of credit support, such as guarantees related to financing a project.
PVR’s primary business objective is to create sustainable, capital-efficient growth in distributable cash flow to maximize its cash distributions to its unitholders by expanding its coal property management and natural gas gathering and processing businesses through both internal growth and acquisitions. PVR has successfully grown its business through organic growth projects and acquisitions of coal and natural resource properties and natural gas midstream assets. Since PVR’s initial public offering in October 2001, PVR has completed numerous accretive acquisitions with an aggregate purchase price of approximately $750 million. For a more detailed discussion of PVR’s acquisitions, see Item 7, “Management’s Discussion
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and Analysis of Financial Condition and Results of Operations—Acquisitions and Investments.” We and PVR intend to continue to pursue the following business strategies:
| • | Continue to grow coal reserve holdings through acquisitions and investments in PVR’s existing market areas, as well as strategically entering new markets. During 2007, PVR increased its coal reserves by 60 million tons, or 8%, from its coal reserves as of December 31, 2006, by completing two acquisitions for an aggregate purchase price of approximately $52 million. While PVR continues to build upon its core holdings in Appalachia, it also continues to pursue coal opportunities in other areas. For example, in 2005, 2006 and 2007, PVR made investments in Illinois Basin coal reserves because PVR views the Illinois Basin as a growth area, both because of its proximity to power plants and because PVR expects future environmental regulations will require scrubbing of not only higher sulfur Illinois Basin coal, but most coals, including lower sulfur coals from other basins. PVR expects to continue to diversify its coal reserve holdings into this and other domestic basins in the future. |
| • | Expand PVR’s coal services and infrastructure business on its properties. Coal infrastructure projects typically involve long-lived, fee-based assets that generally produce steady and predictable cash flows and are therefore attractive to publicly traded limited partnerships. PVR owns a number of such infrastructure facilities and intends to continue to look for growth opportunities in this area of operations. For example, PVR completed the construction of a new preparation and loading facility in September 2006 on property it acquired in 2005. Operations at the facility commenced in the fourth quarter of 2006. In 2007, PVR acquired a preparation plant in connection with its acquisition of coal reserves. PVR also has an equity interest in a coal handling joint venture, which is expected to provide other development opportunities for coal-related infrastructure projects. |
| • | Expand PVR’s other natural resource management assets. PVR’s management continues to focus on acquisitions that increase and diversify its sources of long-term cash flow. For example, in 2007, PVR acquired approximately 62,000 acres of forestland in West Virginia for a purchase price of approximately $93 million and royalty interests in certain oil and gas leases relating to properties located in Kentucky and Virginia for a purchase price of approximately $31 million. |
| • | Expand PVR’s natural gas midstream operations through acquisitions of new gathering and processing related assets and by adding new production to existing systems. PVR continually seeks new supplies of natural gas both to offset the natural declines in production from the wells currently connected to its systems and to increase system throughput volumes. New natural gas supplies are obtained for all of PVR’s systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and by contracting for natural gas that has been released from competitors’ systems. During 2007, PVR expended $38.7 million on expansion projects to allow it to capitalize on such opportunities. The expansion projects included two natural gas processing facilities with a combined 140 MMcfd of inlet gas capacity, which are expected to commence operations in 2008. |
| • | Utilize the advantages of PVR’s relationship with Penn Virginia. During 2006, PVR began marketing Penn Virginia’s natural gas production in Louisiana, Oklahoma and Texas, allowing PVR to add a new source of revenues. In 2007, PVR announced plans to construct a new 80 MMcfd gas processing plant in the Bethany Field in east Texas and entered into a gas gathering and processing agreement with Penn Virginia. The new east Texas plant will provide fee-based gas processing services to Penn Virginia’s oil and gas business, as well as other producers. In addition, as discussed above, PVR purchased approximately $31 million of oil and gas royalty interests from Penn Virginia, allowing PVR to expand its existing oil and gas royalty interest business. PVR will continue to look for ways to take advantage of its natural relationship with Penn Virginia in mutually beneficial ways. |
PVR’s Contracts
PVR Coal and Natural Resource Management Segment
PVR earns most of its coal royalties revenues under long-term leases that generally require its lessees to make royalty payments to it based on the higher of a percentage of the gross sales price or a fixed price per ton of coal they sell. The balance of PVR’s coal royalties revenues are earned under long-term leases that require the lessees to make royalty payments to PVR based on fixed royalty rates which escalate annually. A typical lease either expires upon exhaustion of the leased reserves or has a five to ten-year base term, with the lessee having an option to extend the lease for at least five years after the expiration of the base term. Substantially all of PVR’s leases require the lessee to pay minimum rental payments to PVR in monthly or annual installments, even if no mining activities are ongoing. These minimum rentals are recoupable, usually over a period from one to three years from the time of payment, against the production royalties owed to PVR once coal production commences.
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Substantially all of PVR’s leases impose obligations on the lessees to diligently mine the leased coal using modern mining techniques, indemnify PVR for any damages it incurs in connection with the lessee’s mining operations, including any damages PVR may incur due to the lessee’s failure to fulfill reclamation or other environmental obligations, conduct mining operations in compliance with all applicable laws, obtain its written consent prior to assigning the lease and maintain commercially reasonable amounts of general liability and other insurance. Substantially all of the leases grant PVR the right to review all lessee mining plans and maps, enter the leased premises to examine mine workings and conduct audits of lessees’ compliance with lease terms. In the event of a default by a lessee, substantially all of the leases give PVR the right to terminate the lease and take possession of the leased premises.
In addition, PVR earns revenues under coal services contracts, timber contracts and oil and gas leases. PVR’s coal services contracts generally provide that the users of PVR’s coal services pay PVR a fixed fee per ton of coal processed at its facilities. All of PVR’s coal services contracts are with lessees of PVR’s coal reserves and these contracts generally have terms that run concurrently with the related coal lease. PVR’s timber contracts generally provide that the timber companies pay us a fixed price per thousand board feet of timber harvested from our property. PVR receives royalties under its oil and gas leases based on a percentage of the revenues the producers receive for the oil and gas they sell.
PVR Natural Gas Midstream Segment
PVR’s natural gas midstream business generates revenues primarily from gas purchase and processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. During the year ended December 31, 2007, PVR’s natural gas midstream business generated a majority of its gross margin from two types of contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and NGLs: (i) percentage-of-proceeds and (ii) keep-whole arrangements. As of December 31, 2007, approximately 37% of PVR’s system throughput volumes were processed under gas purchase/keep-whole contracts, 34% were processed under percentage-of-proceeds contracts, and 29% were 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. There is also a processing fee floor included in many of the gas purchase/keep-whole contracts that ensures a minimum processing margin should the actual margins fall below the floor.
Gas Purchase/Keep-Whole Arrangements. Under these arrangements, PVR generally purchases natural gas at the wellhead at either (i) a percentage discount to a specified index price, (ii) a specified index price less a fixed amount or (iii) a combination of (i) and (ii). PVR then gathers the natural gas to one of its plants where it is processed to extract the entrained NGLs, which are then sold to third parties at market prices. PVR resells the remaining natural gas to third parties at an index price which typically corresponds to the specified purchase index. Because the extraction of the NGLs from the natural gas during processing reduces the BTU content of the natural gas, PVR retains a reduced volume of gas to sell after processing. Accordingly, under these arrangements, PVR’s revenues and gross margins increase as the price of NGLs increases relative to the price of natural gas, and its revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. PVR has generally been able to mitigate its exposure in the latter case by requiring the payment under many of its gas purchase/keep-whole arrangements of minimum processing charges which ensure that PVR receives a minimum amount of processing revenues. The gross margins that PVR realizes under the arrangements described in clauses (i) and (iii) above also decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price.
Percentage-of-Proceeds Arrangements. Under percentage-of-proceeds arrangements, PVR generally gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed-upon percentage of the proceeds of those sales based on either an index price or the price actually received for the gas and NGLs. Under these types of arrangements, PVR’s revenues and gross margins increase as natural gas prices and NGL prices increase, and its revenues and gross margins decrease as natural gas prices and NGL prices decrease.
Fee-Based Arrangements. Under fee-based arrangements, PVR receives fees for gathering, compressing and/or processing natural gas. The revenues PVR earns from these arrangements are directly dependent on the volume of natural gas that flows through its systems and are independent of commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, PVR’s revenues from these arrangements would be reduced due to the related reduction in drilling and development of new supply.
In many cases, PVR provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of PVR’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts were signed and customer requirements. The contract mix and, accordingly, exposure to natural gas and
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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.
PVR is also engaged in natural gas marketing by aggregating third-party volumes and selling those volumes into interstate and intrastate pipeline systems such as Enogex and ONEOK and at market hubs accessed by various interstate pipelines. Connect Energy Services, LLC, a wholly-owned subsidiary of PVR, earned fees for marketing a portion of Penn Virginia Oil & Gas, L.P.’s natural gas production during 2007 and 2006. Penn Virginia Oil & Gas, L.P. is a wholly-owned subsidiary of Penn Virginia. The marketing agreement was effective September 1, 2006. Revenues from this business do not generate qualifying income for a publicly traded limited partnership, but PVR does not expect it to have an impact on its tax status, as it does not represent a significant percentage of PVR’s operating income. For the years ended December 31, 2007 and 2006, natural gas marketing activities generated $4.6 million and $2.2 million in net revenues.
Commodity Derivative Contracts. PVR utilizes costless collar and swap derivative contracts to hedge against the variability in cash flows associated with forecasted natural gas midstream revenues and cost of midstream gas purchased. PVR also utilizes swap derivative contracts to hedge against the variability in its “frac spread.” PVR’s frac spread is the spread between the purchase price for the natural gas PVR purchases from producers and the sale price for the NGLs that PVR sells after processing. PVR hedges against the variability in its frac spread by entering into swap derivative contracts to sell NGLs forward at a predetermined swap 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, their use also may limit future revenues or cost savings from favorable price movements.
With respect to a costless collar contract, the counterparty is required to make a payment to PVR if the settlement price for any settlement period is below the floor price for such contract. PVR is required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. With respect to a swap contract, the counterparty is required to make a payment to PVR if the settlement price for any settlement period is less than the swap price for such contract, and PVR is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price for such contract.
See Note 10 in the Notes to Consolidated Financial Statements for a further description of PVR’s derivatives program.
Partnership Structure
Penn Virginia, a publicly held energy company based in Radnor, Pennsylvania, has been engaged in the coal royalty business since 1882 and is also engaged in the exploration, development and production of natural gas and oil. Penn Virginia formed PVR in July 2001 to own and operate substantially all of the assets of and assume the liabilities relating to Penn Virginia’s coal land management business. PVR completed its initial public offering in October 2001. We were formed by Penn Virginia in June 2006 to hold the 2% general partner interest, the incentive distributions rights and a significant limited partner interest in PVR. We completed our initial public offering, or our IPO, in December 2006.
PVR’s operations are conducted through, and its operating assets are owned by, its subsidiaries. PVR owns its subsidiaries through an operating company, Penn Virginia Operating Co., LLC, or the Operating Company. The following diagram depicts our and our affiliates’ current simplified organizational and ownership structure as of December 31, 2007:
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Relationship with Penn Virginia Corporation
Penn Virginia has a history of successfully completing energy acquisitions. PVR pursues acquisitions independently and has the opportunity to participate jointly with Penn Virginia in reviewing potential acquisitions. These may include acquisitions of properties containing multiple natural resources, such as oil, natural gas, coal and timber, as well as infrastructure related to those resources, such as natural gas gathering systems and coal preparation plants and loading facilities. PVR would expect to retain all coal reserves and related infrastructure, all timber resources and all natural gas gathering systems acquired in any such joint acquisition and to allocate the remaining purchased assets between PVR and Penn Virginia as appropriate after considering each entity’s characteristics and strategies. PVR expects that its ability to participate in potential acquisitions with, and its access to the experienced management team and industry contacts of, Penn Virginia will benefit it.
Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Under an omnibus agreement between Penn Virginia, PVR and PVR’s general partner, to which we became subject after our IPO, Penn Virginia and its affiliates, including us, are restricted in their ability to engage in any coal-related business. See Item 13, “Certain Relationships and Related Transactions, and Director Independence—Transactions with Related Persons.”
Partnership Distributions
Cash Distributions
We paid cash distributions of $0.91 per common unit during the year ended December 31, 2007. In the first quarter of 2008, we paid a quarterly distribution of $0.32 ($1.28 on an annualized basis) per common unit with respect to the fourth quarter of 2007. For the remainder of 2008, we expect to pay quarterly distributions of at least $0.32 ($1.28 on an annualized basis) per common unit.
PVR Cash Distributions
Our only cash generating assets consist of our partner interests in PVR. PVR paid cash distributions of $1.66 per common and Class B unit during the year ended December 31, 2007. In the first quarter of 2008, PVR paid a quarterly distribution of $0.44 ($1.76 on an annualized basis) per common unit with respect to the fourth quarter of 2007. For the remainder of 2008, PVR expects to pay quarterly distributions of at least $0.44 ($1.76 on an annualized basis) per common unit.
Prior to our IPO in December 2006, Penn Virginia indirectly owned common units representing an approximately 37% limited partner interest in PVR, as well the sole 2% general partner interest and all of the incentive distribution rights in PVR. Penn Virginia received total distributions from PVR of $28.3 million and $21.2 million in 2006 and 2005, allocated among its limited partner interest, general partner interest and incentive distribution rights in PVR as shown in the following table:
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| Year Ended December 31, | ||||||
| 2006 | 2005 | |||||
| (in thousands) | ||||||
| Limited partner units |
$ | 22,799 | $ | 19,281 | ||
| General partner interest (2%) |
1,254 | 1,021 | ||||
| Incentive distribution rights |
4,273 | 910 | ||||
| Total |
$ | 28,326 | $ | 21,212 | ||
In conjunction with our IPO, Penn Virginia contributed its general partner interest, including its incentive distribution rights, and most of its limited partner interest in PVR to us in exchange for the general partner interest and a limited partner interest in us. We also purchased additional common units and Class B units of PVR with the proceeds of our IPO. We received total distributions from PVR of $45.6 million in 2007, allocated among our limited partner interest, general partner interest and incentive distribution rights in PVR as shown in the following table:
| Year Ended December 31, 2007 | |||
| (in thousands) | |||
| Limited partner units |
$ | 32,515 | |
| General partner interest (2%) |
1,562 | ||
| Incentive distribution rights |
11,551 | ||
| Total |
$ | 45,628 | |
Limited Call Right
If at any time our general partner and its affiliates own more than 90% of our outstanding common units, our general partner has the right, which it may assign in whole or in part to any of its affiliates or us, but not the obligation, to acquire all, but not less than 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 not less than the then-current market price of our common units.
As a result of our general partner’s right to purchase outstanding common units, a holder of common units may have his or her common units purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his or her units in the market.
As of February 28, 2008, Penn Virginia and its affiliates owned 32,087,424 common units, representing approximately 82% of our outstanding common units.
Certain Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships among Penn Virginia, PVR and their respective general partners and affiliates, on the one hand, and us and our limited partners, on the other hand. Like PVR, our general partner is controlled by Penn Virginia. Accordingly, Penn Virginia has the ability to elect, remove and replace the directors and officers of our general partner and the directors and officers of the general partner of PVR. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owner, Penn Virginia. At the same time, our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders.
Certain of the executive officers and non-independent directors of our general partner also serve as executive officers and directors of Penn Virginia or the general partner of PVR. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to Penn Virginia or PVR, on the one hand, and us, on the other hand, are in conflict.
Limits on Fiduciary Responsibilities
Our partnership agreement limits the liability and reduces the fiduciary duties owed by our general partner to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duty.
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Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.
In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct, or in the case of a criminal matter, acted with the knowledge that such conduct was unlawful.
Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be:
| • | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
| • | “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us). |
If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.
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.
We are required to indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above.
Competition
PVR Coal and Natural Resource Management Segment
The coal industry is intensely competitive primarily as a result of the existence of numerous producers. PVR’s lessees compete with both large and small coal producers in various regions of the United States for domestic sales. The industry has undergone significant consolidation which has led to some of the competitors of PVR’s lessees having significantly larger financial and operating resources than most of PVR’s lessees. PVR’s lessees compete on the basis of coal price at the mine, coal quality (including sulfur content), transportation cost from the mine to the customer and the reliability of supply. Continued demand for PVR’s coal and the prices that PVR’s lessees obtain are also affected by demand for electricity, demand for metallurgical coal, access to transportation, environmental and government regulations, technological developments and the availability and price of alternative fuel supplies, including nuclear, natural gas, oil and hydroelectric power. Demand for PVR’s low sulfur coal and the prices PVR’s lessees will be able to obtain for it will also be affected by
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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 requirements.
PVR Natural Gas Midstream Segment
The ability to offer natural gas producers competitive gathering and processing arrangements and subsequent reliable service is fundamental to obtaining and keeping gas supplies for PVR’s gathering systems. The primary concerns of the producer are:
| • | 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. |
PVR experiences competition in all of its natural gas midstream markets. PVR’s competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, process, transport and market natural gas. Many of PVR’s competitors have greater financial resources and access to larger natural gas supplies than PVR does.
Government Regulation and Environmental Matters
The operations of PVR’s coal and natural resource management business and natural gas midstream business are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted.
PVR Coal and Natural Resource Management Segment
General Regulation Applicable to Coal Lessees. PVR’s lessees are obligated to conduct mining operations in compliance with all applicable federal, state and local laws and regulations. These laws and regulations include matters involving the discharge of materials into the environment, employee health and safety, mine permits and other licensing requirements, reclamation and restoration of mining properties after mining is completed, management of materials generated by mining operations, surface subsidence from underground mining, water pollution, legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, plant and wildlife protection, limitations on land use, storage of petroleum products and substances which are regarded as hazardous under applicable laws and management of electrical equipment containing polychlorinated biphenyls, or PCBs. These extensive and comprehensive regulatory requirements are closely enforced, PVR’s lessees regularly have on-site inspections and violations during mining operations are not unusual in the industry, notwithstanding compliance efforts by PVR’s lessees. However, none of the violations to date, or the monetary penalties assessed, have been material to us, PVR or, to our knowledge, to PVR’s lessees. Although many new safety requirements have been instituted recently, PVR does not currently expect that future compliance will have a material adverse effect on PVR.
While it is not possible to quantify the costs of compliance by PVR’s lessees with all applicable federal, state and local laws and regulations, those costs have been and are expected to continue to be significant. The lessees post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. We do not accrue for such costs because PVR’s lessees are contractually liable for all costs relating to their mining operations, including the costs of reclamation and mine closure. However, PVR does require some smaller lessees to deposit into escrow certain funds for reclamation and mine closure costs or post performance bonds for these costs. Although we believe that the lessees typically accrue adequate amounts for these costs, their future operating results would be adversely affected if they later determined these accruals to be insufficient. Compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers.
In addition, the utility industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities which could affect demand for coal mined by PVR’s lessees. The possibility exists that new legislation or regulations may be adopted which have a significant impact on the
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mining operations of PVR’s lessees or their customers’ ability to use coal and may require PVR, its lessees or their customers to change operations significantly or incur substantial costs.
Air Emissions. The Clean Air Act, or the CAA, and corresponding state and local laws and regulations affect all aspects of PVR’s business, both directly and indirectly. The CAA directly impacts PVR’s lessees’ coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants. There have been a series of recent federal rulemakings that are focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and additional measures required under U.S. Environmental Protection Agency, or the EPA, laws and regulations will make it more costly to build and operate coal-fired power plants and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel alternative in the planning and building of power plants in the future. Any reduction in coal’s share of power generating capacity could negatively impact PVR’s lessees’ ability to sell coal, which could have a material effect on PVR’s coal royalties revenues.
The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels.
The EPA has promulgated rules, referred to as the “NOx SIP Call,” that require coal-fired power plants and other large stationary sources in 21 eastern states and Washington D.C. to make substantial reductions in nitrogen oxide emissions in an effort to reduce the impacts of ozone transport between states. Additionally, in March 2005, the EPA issued the final Clean Air Interstate Rule, or CAIR, which will permanently cap nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. beginning in 2009 and 2010. CAIR requires these states to achieve the required emission reductions by requiring power plants to either participate in an EPA-administered “cap-and-trade” program that caps emission in two phases, or by meeting an individual state emissions budget through measures established by the state. The stringency of the caps under CAIR may require many coal-fired sources to install additional pollution control equipment, such as wet scrubbers, to comply. This increased sulfur emission removal capability required by CAIR could result in decreased demand for lower sulfur coal, which may potentially drive down prices for lower sulfur coal.
In March 2005, the EPA finalized the Clean Air Mercury Rule, or CAMR, which was to establish a two-part, nationwide cap on mercury emissions from coal-fired power plants beginning in 2010. It was the subject of extensive controversy and litigation and, in February 2008, the U.S. Circuit Court of Appeals for the District of Columbia vacated CAMR. EPA has not yet indicated if it will appeal the decision or how it will proceed with the regulation of mercury emissions. Various states have promulgated or are considering more stringent emission limits on mercury emissions from coal-fired electric generating units.
The EPA has adopted new, more stringent national air quality standards for ozone and fine particulate matter. As a result, some states will be required to amend their existing state implementation plans to attain and maintain compliance with the new air quality standards. In March 2007, the EPA published final rules addressing how states would implement plans to bring regions designated as non-attainment for fine particulate matter into compliance with the new air quality standard. Under the EPA’s final rule, states have until April 2008 to submit their implementation plans to the EPA for approval. Because coal mining operations and coal-fired electric generating facilities emit particulate matter, PVR’s lessees’ mining operations and their customers could be affected when the new standards are implemented by the applicable states.
Likewise, the EPA’s regional haze program to improve visibility in national parks and wilderness areas required affected states to develop implementation plans by December 2007 that, among other things, identify facilities that will have to reduce emissions and comply with stricter emission limitations. This program may restrict construction of new coal-fired power plants where emissions are projected to reduce visibility in protected areas. In addition, this program may require certain existing coal-fired power plants to install emissions control equipment to reduce haze-causing emissions such as sulfur dioxide, nitrogen oxide and particulate matter.
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
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modifications have been made to these facilities without first obtaining permits required under the new source review program. Several of these lawsuits have settled, but others remain pending. On April 2, 2007, the United States Supreme Court ruled in one such case, Environmental Defense v. Duke Energy Corp. The Court held that EPA is not required to use an “hourly rate test” in determining whether a modification to a coal burning utility requires a permit under the new source review program, thus allowing the EPA to apply a test based on average annual emissions. The use of an annual emissions test could subject more coal-fired utility modification projects to the permitting requirements of the CAA New Source Review Program, such as those that allow plants to run for more hours in a given year. However, Duke is expected to continue to contest remaining issues in the case, and so litigation in this and other pending cases will likely continue. Depending on the ultimate resolution of these cases, demand for PVR’s coal could be affected, which could have an adverse effect on PVR’s coal royalties revenues.
Carbon Dioxide Emissions. The Kyoto Protocol to the United Nations Framework Convention on Climate Change calls for developed nations to reduce their emissions of greenhouse gases to 5% below 1990 levels by 2012. Carbon dioxide, which is a major byproduct of the combustion of coal and other fossil fuels, is subject to the Kyoto Protocol. The Kyoto Protocol went into effect on February 16, 2005 for those nations that ratified the treaty. In 2002, the United States withdrew its support for the Kyoto Protocol, and the United States is not participating in this treaty. Since the Kyoto Protocol became effective, there has been increasing international pressure on the United States to adopt mandatory restrictions on carbon dioxide emissions. In addition, on April 2, 2007 the United States Supreme Court held in Massachusetts v. EPA that unless the EPA affirmatively concludes that greenhouse gases are not causing climate change, the EPA must regulate greenhouse gas emissions from new automobiles under the CAA. The Supreme Court remanded the matter to the EPA for further consideration. This litigation did not directly concern the EPA’s authority to regulate greenhouse gas emissions from stationary sources, such as coal mining operations or coal-fired power plants. However, the Court’s decision is likely to influence another lawsuit currently pending in the U.S. Court of Appeals for the District of Columbia Circuit, involving a challenge to the EPA’s decision not to regulate carbon dioxide from power plants and other stationary sources under a CAA new source performance standard rule, which specifies emissions limits for new facilities. The court remanded that question to EPA for further consideration in light of the ruling in Massachusetts v. EPA, but any decision in this case or any regulatory action by the EPA limiting greenhouse gas emissions from power plants could impact the demand for PVR’s coal, which could have an adverse effect on PVR’s coal royalties revenues.
The permitting of a number of proposed new coal-fired power plants has also recently been contested by environmental organizations for concerns related to greenhouse gas emissions from new plants. In October 2007, state regulators in Kansas became the first to deny an air emissions construction permit for a new coal-fired power plant based on the plant’s projected emissions of carbon dioxide. State regulatory authorities in Florida and North Carolina have also rejected the construction of new coal-fired power plants based on the uncertainty surrounding the potential costs associated with greenhouse gas emissions from these plants under future laws limiting the emission of carbon dioxide. In addition, permits for several new coal-fired power plants without limits imposed on their greenhouse gas emissions have been appealed by environmental organizations to the U.S. EPA’s Environmental Appeals Board.
Several states have also either passed legislation or announced initiatives focused on decreasing or stabilizing carbon dioxide emissions associated with the combustion of fossil fuels, and many of these measures have focused on emissions from coal-fired electric generating facilities. For example, in December 2005, seven northeastern states agreed to implement a regional cap-and-trade program, referred to as the Regional Greenhouse Gas Initiative, or the RGGI, to stabilize carbon dioxide emissions from regional power plants beginning in 2009. This initiative aims to reduce emissions of carbon dioxide to levels roughly corresponding to average annual emissions between 2000 and 2004. Massachusetts and Rhode Island agreed to join this group in February 2007 and Maryland agreed to join the group in April 2007. The members of RGGI agreed to seek to establish in statute and/or regulation a carbon dioxide trading program and have each state’s component of the regional program effective no later than December 31, 2008. Following the RGGI model, seven Western states have also formed a regional greenhouse gas reduction initiative known as the Western Regional Climate Action Initiative, which calls for an overall reduction of regional greenhouse gas emissions from major industrial and commercial sources in participating states through trading of emissions credits beginning in 2012. Also, in 2006, the governor of California signed Assembly Bill 32 into law, requiring the California Air Resources Board to develop regulations and market mechanisms to reduce California’s greenhouse gas emissions by 25% by 2020 with mandatory caps beginning in 2012 for significant sources.
Several different pieces of legislation were introduced in Congress in 2007 to reduce greenhouse gas emissions in the United States. Such or similar federal legislation could be taken in 2008 or later years. It is possible that future federal and state initiatives to control and put a price on carbon dioxide emissions could result in increased costs associated with coal consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for coal consumption could result
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in some customers switching to alternative sources of fuel, which could negatively impact PVR’s lessees’ coal sales, and thereby have an adverse effect on PVR’s coal royalties revenues.
Surface Mining Control and Reclamation Act of 1977. The Surface Mining Control and Reclamation Act of 1977, or SMCRA, and similar state statutes establish minimum national operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of mining activities. SMCRA also imposes on mine operators the responsibility of restoring the land to its original state and compensating the landowner for types of damages occurring as a result of mining operations, and require mine operators to post performance bonds to ensure compliance with any reclamation obligations on the theory that PVR “owned” or “controlled” the mine operator in such a way for liability to attach. Regulatory authorities may attempt to assign the liabilities of PVR’s coal lessees to another entity such as PVR if any of its lessees are not financially capable of fulfilling those obligations. To our knowledge, no such claims have been asserted against PVR to date. In conjunction with mining the property, PVR’s coal lessees are contractually obligated under the terms of their leases to comply with all state and local laws, including SMCRA, with obligations including the reclamation and restoration of the mined areas by grading, shaping and reseeding the soil. Upon completion of the mining, reclamation generally is completed by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan. Additionally, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is 31.5 cents per ton on surface-mined coal and 13.5 cents per ton on underground-mined coal. This tax was set to expire on June 30, 2006, but the program was extended until September 30, 2021.
Federal and state laws require bonds to secure our lessees’ obligations to reclaim lands used for mining and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for mining companies to secure new surety bonds without the posting of partial collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable. It is possible that surety bonds issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Any failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on PVR’s lessees’ ability to produce coal, which could affect PVR’s coal royalties revenues.
Hazardous Materials and Wastes. The Federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, or the Superfund law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources.
Some products used by coal companies in operations generate waste containing hazardous substances. PVR could become liable under federal and state Superfund and waste management statutes if its lessees are unable to pay environmental cleanup costs. CERCLA authorizes the EPA and, in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek recovery from the responsible classes of persons of the costs they incurred in connection with such response. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other wastes released into the environment. The Resource Conservation and Recovery Act, or RCRA, and corresponding state laws and regulations exclude many mining wastes from the regulatory definition of hazardous wastes. Currently, the management and disposal of coal combustion by-products are also not regulated at the federal level and not uniformly at the state level. If rules are adopted to regulate the management and disposal of these by-products, they could add additional costs to the use of coal as a fuel and may encourage power plant operators to switch to a different fuel.
Clean Water Act. PVR’s coal lessees’ operations are regulated under the Clean Water Act, or the CWA, with respect to discharges of pollutants, including dredged or fill material into waters of the United States. Individual or general permits under Section 404 of the CWA are required to conduct dredge or fill activities in jurisdictional waters of the United States. Surface coal mining operators obtain these permits to authorize such activities as the creation of slurry ponds, stream impoundments and valley fills. Uncertainty over what legally constitutes a navigable water of the United States within the CWA’s regulatory scope may adversely impact the ability of PVR’s coal lessees to secure the necessary permits for their mining activities. Some surface mining activities require a CWA Section 404 “dredge and fill” permit under the CWA for valley fills and the associated sediment control ponds. On June 5, 2007, in response to the U.S. Supreme Court’s divided opinion in Rapanos v. United States, the EPA and the U.S. Army Corps of Engineers, or the Corps, issued joint guidance to EPA regions and Corps districts interpreting the geographic extent of regulatory jurisdiction under Section 404 of the CWA.
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Specifically, the guidance places jurisdictional water bodies into two groups: waters where the agencies will assert regulatory jurisdiction “categorically” and waters where the agencies will assert jurisdiction on a case-by-case basis following a “significant nexus analysis.” It remains to be seen how this guidance will affect the permitting process for obtaining additional permits for valley fills and sediment ponds although it is likely to add uncertainty and delays in the issuance of new permits. Some valley fill surface mining activities have the potential to impact headwater streams that are not relatively permanent, which could therefore trigger a detailed “significant nexus analysis” to determine whether a Section 404 permit would be required. Such analyses could require the extensive collection of additional field data and could lead to delays in the issuance of CWA Section 404 permits for valley fill surface mining operations.
Recent federal district court decisions in West Virginia, and related litigation filed in federal district court in Kentucky, have created additional uncertainty regarding the future ability to obtain certain general permits authorizing the construction of valley fills for the disposal of overburden from mining operations. The Corps is authorized by Section 404 of the CWA to issue “nationwide” permits for specific categories of dredging and filling activities that are similar in nature and that are determined to have minimal adverse environmental effects. Nationwide Permit 21 authorizes the disposal of dredged or fill material from surface coal mining activities into the waters of the United States. A July 2004 decision by the Southern District of West Virginia in Ohio Valley Environmental Coalition v. Bulen enjoined the Huntington District of the Corps from issuing further permits pursuant to Nationwide Permit 21. While the decision was vacated by the Fourth Circuit Court of Appeals in November 2005, it has been remanded to the District Court for the Southern District of West Virginia for further proceedings. Moreover, a similar lawsuit has been filed in the U.S. District Court for the Eastern District of Kentucky that seeks to enjoin the issuance of permits pursuant to Nationwide Permit 21 by the Louisville District of the Corps.
In the event similar lawsuits prove to be successful in adjoining jurisdictions, PVR’s lessees may be required to apply for individual discharge permits pursuant to Section 404 of the CWA in areas where they would have otherwise utilized Nationwide Permit 21. Such a change could result in delays in PVR’s lessees obtaining the required mining permits to conduct their operations, which could in turn have an adverse effect on PVR’s coal royalties revenues.
Individual CWA Section 404 permits for valley fills associated with surface mining activities are also subject to certain legal challenges and uncertainty. On September 22, 2005, in the case Ohio Valley Environmental Coalition (“OVEC”) v. United States Army Corps of Engineers, environmental group plaintiffs filed suit in the U.S. District Court for the Southern District of West Virginia challenging the Corps’ decision to issue individual CWA Section 404 permits for certain mining projects. Alex Energy, Inc., or Alex Energy, a lessee of PVR that operates the Republic No. 2 Mine in Kanawha County, West Virginia, intervened as a defendant in this litigation when the plaintiffs’ amended their complaint to add the December 22, 2005 individual CWA Section 404 permit for the Republic No. 2 Mine, or the Republic No. 2 Permit. On March 23, 2007, the district court rescinded several challenged CWA Section 404 permits, including the Republic No. 2 Permit, and remanded the permit applications to the Corps for further proceedings. In addition, the district court enjoined the permit holders, including Alex Energy, from all activities authorized under the rescinded permits. As part of the OVEC litigation, the environmental groups have also challenged the CWA Section 404 permit issued to Alex Energy for the Republic No. 1 Mine, also located in Kanawha County, West Virginia.
On April 10, 2007, Alex Energy filed a notice of appeal of the March 23, 2007 ruling to the United States Court of Appeals. On May 18, 2007, the Corps and the West Virginia Mining Association also filed notices of appeal as defendants. On April 20, 2007, the district court granted a limited stay of its previous order to allow certain valley fills already partially constructed where the receiving waters had been filled. This limited stay specifically allows Alex Energy to continue to use Valley Fill No. 1 with respect to the Republic No. 2 Mine; however, construction of the other valley fills and sediment ponds remain enjoined pending appeal. In December 2007, plaintiff environmental groups brought a similar suit against the issuance of a CWA Section 404 permit for a surface coal mine in the U.S. District Court for the Eastern District of Kentucky, alleging identical violations. The Corps has voluntarily suspended its consideration of the permit application in that case for agency re-evaluation. While the final outcome of these cases remains uncertain, if the OVEC lawsuit ultimately limits or prohibits the mining methods or operations of PVR’s lessees, it could have an adverse effect on PVR’s coal royalties revenues. In addition, it is possible that similar litigation affecting recently issued, pending or future individual or general CWA Section 404 permits relevant to the mining and related operations of PVR’s lessees could adversely impact PVR’s coal royalties revenues.
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 load allocations for these stream segments. The
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adoption of new TMDL-related allocations for streams to which PVR’s lessees’ coal mining operations discharge could require more costly water treatment and could adversely affect PVR’s lessees’ coal production.
The CWA also requires states to develop anti-degradation policies to ensure non-impaired water bodies in the state do not fall below applicable water quality standards. These and other regulatory developments may restrict PVR’s lessees’ ability to develop new mines or could require PVR’s lessees to modify existing operations, which could have an adverse effect on PVR’s coal business.
The Safe Drinking Water Act, or the SDWA, and its state equivalents affect coal mining operations by imposing requirements on the underground injection of fine coal slurries, fly ash and flue gas scrubber sludge, and by requiring permits to conduct such underground injection activities. In addition to establishing the underground injection control program, the SDWA also imposes regulatory requirements on owners and operators of “public water systems.” This regulatory program could impact PVR’s lessees’ reclamation operations where subsidence or other mining-related problems require the provision of drinking water to affected adjacent homeowners.
Endangered Species Act. The Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying PVR’s lessees from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. A number of species indigenous to areas where PVR’s properties are located are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect PVR’s lessees’ ability to mine coal from PVR’s properties in accordance with current mining plans.
Mine Health and Safety Laws. The operations of PVR’s coal lessees are subject to stringent health and safety standards that have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs and reduced productivity. 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.
Recent mining accidents in West Virginia and Kentucky have received national attention and instigated responses at the state and national level that are likely to result in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. In January 2006, West Virginia passed a law imposing stringent new mine safety and accident reporting requirements and increased civil and criminal penalties for violations of mine safety laws. On March 7, 2006, New Mexico Governor Bill Richardson signed into law an expanded miner safety program including more stringent requirements for accident reporting and the installation of additional mine safety equipment at underground mines. Similarly, on April 27, 2006, Kentucky Governor Ernie Fletcher signed mine safety legislation that includes requirements for increased inspections of underground mines and additional mine safety equipment and authorizes the assessment of penalties of up to $5,000 per incident for violations of mine ventilation or roof control requirements.
On June 15, 2006, the President signed the “Miner Act,” which was new mining safety legislation that mandates improvements in mine safety practices, increases civil and criminal penalties for non-compliance, requires the creation of additional mine rescue teams and expands the scope of federal oversight, inspection and enforcement activities. Pursuant to the Miner Act, the Mine Safety Health Administration, or MSHA, has promulgated new emergency rules on mine safety and revised MSHA’s civil penalty assessment regulations, which resulted in an across-the-board increase in penalties from the existing regulations. These requirements may add significant costs to PVR’s lessees’ operations, particularly for underground mines, and could affect the financial performance of PVR’s lessees’ operations.
Implementing and complying with these new laws and regulations could adversely affect PVR’s lessees’ coal production and could therefore have an adverse effect on PVR’s coal royalties revenues.
Mining Permits and Approvals. Numerous governmental permits or approvals are required for mining operations. In connection with obtaining these permits and approvals, PVR’s coal lessees may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations.
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Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations which have outstanding environmental violations. Although, like other coal companies, PVR’s lessees’ have been cited for violations in the ordinary course of business, to our knowledge, none of them have had one of their permits suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.
In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including PVR’s lessees, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically, PVR’s lessees submit the necessary permit applications between 12 and 24 months before they plan to begin mining a new area. In PVR’s experience, permits generally are approved within 12 months after a completed application is submitted. In the past, PVR’s lessees have generally obtained their mining permits without significant delay. PVR’s lessees have obtained or applied for permits to mine a majority of the reserves that are currently planned to be mined over the next five years. PVR’s lessees are also in the planning phase for obtaining permits for the additional reserves planned to be mined over the following five years. However, there are no assurances that they will not experience difficulty in obtaining mining permits in the future. See “—PVR Coal and Natural Resource Management Segment—Clean Water Act.”
OSHA. PVR’s lessees and PVR’s own business are subject to the Occupational Safety and Health Act, or OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in PVR’s operations and that this information be provided to employees, state and local government authorities and citizens.
PVR Natural Gas Midstream Segment
General Regulation. PVR’s natural gas gathering facilities generally are exempt from the Federal Energy Regulatory Commission’s, or the FERC, jurisdiction under the Natural Gas Act of 1938, or the NGA, but FERC regulation nevertheless could significantly affect PVR’s gathering business and the market for its services. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines into which PVR’s gathering pipelines deliver. However, we cannot assure you that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.
For example, the FERC will assert jurisdiction over an affiliated gatherer that acts to benefit its pipeline affiliate in a manner that is contrary to the FERC’s policies concerning jurisdictional services adopted pursuant to the NGA. In addition, natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that the FERC has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. PVR’s gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. PVR’s gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on PVR’s natural gas midstream operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
In Texas, PVR’s gathering facilities are subject to regulation by the Texas Railroad Commission, which has the authority to ensure that rates, terms and conditions of gas utilities, including certain gathering facilities, are just and reasonable and not discriminatory. PVR’s operations in Oklahoma are regulated by the Oklahoma Corporation Commission, which prohibits PVR from charging any unduly discriminatory fees for its gathering services. We cannot predict whether PVR’s gathering rates will be found to be unjust, unreasonable or unduly discriminatory.
PVR is subject to ratable take and common purchaser statutes in Texas and Oklahoma. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting PVR’s right as an owner of gathering facilities to decide with whom it contracts 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
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gathering rates and access. We cannot assure you that federal and state authorities will retain their current regulatory policies in the future.
Texas and Oklahoma administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, or the NGPSA, which requires certain pipelines to comply with safety standards in constructing and operating the pipelines, and subjects pipelines to regular inspections. In response to recent pipeline accidents, Congress and the U.S. Department of Transportation have instituted heightened pipeline safety requirements. Certain of PVR’s gathering facilities are exempt from these federal pipeline safety requirements under the rural gathering exemption. We cannot assure you that the rural gathering exemption will be retained in its current form in the future.
Failure to comply with applicable regulations under the NGA, the NGPSA and certain state laws can result in the imposition of administrative, civil and criminal remedies.
Air Emissions. PVR’s natural gas midstream operations are subject to the CAA and comparable state laws and regulations. See “—PVR Coal and Natural Resource Management Segment—Air Emissions.” These laws and regulations govern emissions of pollutants into the air resulting from the activities of PVR’s processing plants and compressor stations and also impose procedural requirements on how PVR conducts its natural gas midstream operations. Such laws and regulations may include requirements that PVR 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 PVR is required to obtain or utilize specific equipment or technologies to control emissions. PVR’s failure to comply with these requirements could subject it to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. PVR will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.
Hazardous Materials and Wastes. PVR’s natural gas midstream operations could incur liability under CERCLA and comparable state laws resulting from the disposal or other release of hazardous substances or wastes originating from properties PVR owns or operates, regardless of whether such disposal or release occurred during or prior to PVR’s acquisition of such properties. See “—PVR Coal and Natural Resource Management Segment—Hazardous Materials and Waste.” Although petroleum, including natural gas and NGLs are generally excluded from CERCLA’s definition of “hazardous substance,” PVR’s natural gas midstream operations do generate wastes in the course of ordinary operations that may fall within the definition of a “hazardous substance.”
PVR’s natural gas midstream operations generate wastes, including some hazardous wastes, which are subject to RCRA, and comparable state laws. However, RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy. Unrecovered petroleum product wastes, however, may still be regulated under RCRA as solid waste. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas and NGLs in pipelines may also generate some hazardous wastes. Although PVR believes that it is unlikely that the RCRA exemption will be repealed in the near future, repeal would increase costs for waste disposal and environmental remediation at PVR’s facilities.
PVR currently owns or leases numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas and NGLs. Although PVR believes that the operators of such properties used operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under such properties or on or under other locations where such wastes have been taken for disposal. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, PVR could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination, whether from prior owners or operators or other historic activities or spills) or to perform remedial plugging or pit closure operations to prevent future contamination. PVR has ongoing remediation projects underway at several sites, but it does not believe that the costs associated with such cleanups will have a material adverse impact on PVR’s operations or revenues.
Water Discharges. PVR’s natural gas midstream operations are subject to the CWA. See “—PVR Coal and Natural Resource Management Segment—Clean Water Act.” Any unpermitted release of pollutants, including NGLs or condensates, from PVR’s systems or facilities could result in fines or penalties as well as significant remedial obligations.
OSHA. PVR’s natural gas midstream operations are subject to OSHA. See “—PVR Coal and Natural Resource Management Segment—OSHA.”
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Employees and Labor Relations
Neither we nor PVR have any employees. To carry out PVR’s operations, our general partner and its affiliates employed 129 employees who directly supported PVR’s operations at December 31, 2007. Our general partner considers current employee relations to be favorable.
Available Information
Our internet address is http://www.pvgpholdings.com. We make available free of charge on or through our internet website our Corporate Governance Principles, Code of Business Conduct and Ethics, Executive and Financial Officer Code of Ethics and Audit Committee Charter, and we will provide copies of such documents to any unitholder who so requests. We also make available free of charge on or through our website our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, or 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 reference to the “SEC” refer to the Securities and Exchange Commission.
Common Abbreviations and Definitions
The following are abbreviations and definitions commonly used in the coal and oil and gas industries that are used in this Annual Report on Form 10-K.
| Bbl | a standard barrel of 42 U.S. gallons liquid volume | |
| Bcf | one billion cubic feet | |
| Bcfe | one billion cubic feet equivalent with one barrel of oil or condensate converted to six thousand cubic feet of natural gas based on the estimated relative energy content | |
| BTU | British thermal unit | |
| Mbbl | one thousand barrels | |
| Mbf | one thousand board feet | |
| Mcf | one thousand cubic feet | |
| Mcfe | one thousand cubic feet equivalent | |
| MMbbl | one million barrels | |
| MMbf | one million board feet | |
| MMbtu | one million British thermal units | |
| MMcf | one million cubic feet | |
| MMcfd | one million cubic feet per day | |
| MMcfe | one million cubic feet equivalent | |
| NGL | natural gas liquid | |
| NYMEX | New York Mercantile Exchange | |
| Probable coal reserves | those reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, | |
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| sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation | ||
| Proved reserves | those estimated quantities of crude oil, condensate and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years | |
| Proven coal reserves | those reserves for which: (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling; and (b) 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 | |
| Item 1A | Risk Factors |
Our business and operations are subject to a number of risks and uncertainties as described below. However, the risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we may currently deem immaterial, may become important factors that harm our business, financial condition or results of operations. If any of the following risks actually occur, our business, financial condition or results of operations could suffer.
Risks Inherent in an Investment in Us
Our cash flow is entirely dependent on the ability of PVR to make cash distributions to us.
Our earnings and cash flow consist exclusively of cash distributions from PVR. Consequently, a significant decline in PVR’s earnings or cash distributions would have a negative impact on us. The amount of cash that PVR will be able to distribute to its partners, including us, each quarter principally depends upon the amount of cash it can generate from its coal and natural resource management and natural gas midstream businesses. The amount of cash that PVR will generate will fluctuate from quarter to quarter based on, among other things:
| • | the amount of coal its lessees are able to produce; |
| • | the price at which its lessees are able to sell the coal; |
| • | its lessees’ timely receipt of payment from their customers; |
| • | the amount of natural gas transported in its gathering systems; |
| • | the amount of throughput in its processing plants; |
| • | the price of natural gas; |
| • | the price of NGLs; |
| • | the relationship between natural gas and NGL prices; |
| • | the fees it charges and the margins it realizes for its natural gas midstream services; and |
| • | its hedging activities. |
In addition, the actual amount of cash that PVR will have available for distribution will depend on other factors, some of which are beyond its control, including:
| • | the level of capital expenditures it makes; |
| • | the cost of acquisitions, if any; |
| • | its debt service requirements; |
| • | fluctuations in its working capital needs; |
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| • | restrictions on distributions contained in its debt agreements; |
| • | prevailing economic conditions; and |
| • | the amount of cash reserves established by its general partner in its sole discretion for the proper conduct of its business. |
Because of these factors, PVR may not have sufficient available cash each quarter to continue paying distributions at their current level or at all. If PVR reduces its per unit distribution, we will have less cash available for distribution to you and would probably be required to reduce our per unit distribution to you. You should also be aware that the amount of cash that PVR has available for distribution depends primarily upon PVR’s cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, PVR may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records profits.
In addition, the timing and amount, if any, of an increase or decrease in distributions by PVR to its unitholders will not necessarily be comparable to the timing and amount of any changes in distributions made by us. Our ability to distribute cash received from PVR to our unitholders is limited by a number of factors, including:
| • | restrictions on distributions contained in any future debt agreements; |
| • | our estimated general and administrative expenses, including expenses we will incur as a result of being a public company as well as other operating expenses; |
| • | expenses of PVR’s general partner and PVR; |
| • | reserves necessary for us to make the necessary capital contributions to maintain our 2% general partner interest in PVR, as required by PVR’s partnership agreement upon the issuance of additional partnership securities by PVR; and |
| • | reserves our general partner believes prudent for us to maintain the proper conduct of our business or to provide for future distributions by us. |
In addition, prior to making any distributions to our unitholders, we will reimburse our general partner and its affiliates for all direct and indirect expenses incurred by them on our behalf. Our general partner will determine the amount of these reimbursed expenses. In addition, our general partner and its affiliates may perform other services for us for which we will be charged fees as determined by our general partner. The reimbursement of these expenses, in addition to the other factors listed above, could adversely affect the amount of distributions we make to our unitholders. The actual amount of cash that is available for distribution to our unitholders will depend on numerous factors, many of which are beyond our control or the control of our general partner.
Our rate of growth may be reduced to the extent we purchase additional units from PVR, which will reduce the percentage of the cash we receive from the incentive distribution rights.
Our business strategy includes supporting the growth of PVR by purchasing PVR units or lending funds to PVR to provide funding for the acquisition of a business or asset or for an internal growth project. To the extent we purchase common units or securities not entitled to a current distribution from PVR, the rate of our distribution growth may be reduced, at least in the short term, as less of our cash distributions will come from our ownership of PVR incentive distribution rights, whose distributions increase at a faster rate than those of our other securities.
Our ability to meet our financial needs may be adversely affected by our cash distribution policy and our lack of operational assets.
Our cash distribution policy, which is consistent with our partnership agreement, requires us to distribute all of our available cash quarterly. Our only cash generating assets are partner interests in PVR, and we currently have no independent operations separate from those of PVR. Moreover, as discussed below, a reduction in PVR’s distributions will disproportionately affect the amount of cash distributions we receive. Given that our cash distribution policy is to distribute available cash and not retain it and that our only cash generating assets are partner interests in PVR, we may not have enough cash to meet our needs if any of the following events occur:
| • | an increase in our operating expenses; |
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| • | an increase in general and administrative expenses; |
| • | an increase in working capital requirements; or |
| • | an increase in cash needs of PVR or its subsidiaries that reduces PVR’s distributions. |
PVR’s general partner, with our consent but without the consent of our unitholders, may limit or modify the incentive distributions we are entitled to receive, which may reduce cash distributions to you.
We own PVR’s general partner, which owns the incentive distribution rights in PVR that entitle us to receive increasing percentages, up to a maximum of 48% of any cash distributed to PVR as certain target distribution levels are reached in excess of $0.375 per PVR unit in any quarter. A substantial portion of the cash flow we receive from PVR is provided by these incentive distribution rights. Because of the high percentage of PVR’s incremental cash flow that is distributed to the incentive distribution rights, certain potential acquisitions might not increase cash available for distribution per PVR unit. In order to facilitate acquisitions by PVR, the board of directors of the general partner of PVR may elect to reduce the incentive distribution rights payable to us with our consent, which we may provide without the approval of our unitholders if our general partner determines that such reduction does not adversely affect our limited partners in any material respect. These reductions may be permanent reductions in the incentive distribution rights or may be reductions with respect to cash flows from the potential acquisition. If distributions on the incentive distribution rights were reduced for the benefit of the PVR units, the total amount of cash distributions we would receive from PVR, and therefore the amount of cash distributions we could pay to our unitholders, would be reduced.
A reduction in PVR’s distributions will disproportionately affect the amount of cash distributions to which we are currently entitled.
Our ownership of the incentive distribution rights in PVR, through our ownership of PVR’s general partner, the holder of the incentive distribution rights, entitles us to receive our pro rata share of specified percentages of total cash distributions made by PVR with respect to any particular quarter only in the event that PVR distributes more than $0.275 per unit for such quarter. As a result, the holders of PVR’s common units have a priority over the holders of PVR’s incentive distribution rights to the extent of cash distributions by PVR up to and including $0.275 per unit for any quarter.
Our incentive distribution rights entitle us to receive increasing percentages, up to 48%, of all incremental cash distributions above $1.50 per unit, on an annualized basis, distributed by PVR. Because we are at the maximum target cash distribution level on the incentive distribution rights, future growth in distributions we receive from PVR will not result from an increase in the target cash distribution level associated with the incentive distribution rights. Furthermore, a decrease in the amount of distributions by PVR to less than $0.375 per unit per quarter would reduce our percentage of the incremental cash distributions above $0.325 per common unit per quarter from 48% to 23%. As a result, any such reduction in quarterly cash distributions from PVR would have the effect of disproportionately reducing the amount of all distributions that we receive from PVR based on our ownership interest in the incentive distribution rights in PVR as compared to cash distributions we receive from PVR with respect to our 2% general partner interest in PVR and our PVR units.
If distributions on our common units are not paid with respect to any fiscal quarter, including those at the anticipated initial distribution rate, our unitholders will not be entitled to receive such payments in the future.
Our distributions to our unitholders will not be cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, including those at the anticipated initial distribution rate, our unitholders will not be entitled to receive such payments in the future.
Our cash distribution policy limits our ability to grow.
Because we distribute almost all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. In fact, our growth is completely dependent upon PVR’s ability to increase its quarterly distribution per unit because currently our only cash-generating assets are partner interests in PVR. If we issue additional units or incur debt to fund acquisitions and growth capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level.
Consistent with the terms of its partnership agreement, PVR distributes to its partners its available cash each quarter. In determining the amount of cash available for distribution, PVR sets aside cash reserves, which it uses to fund its growth capital expenditures. Additionally, PVR has relied upon external financing sources, including commercial borrowings and
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other debt and equity issuances, to fund its acquisition capital expenditures. Accordingly, to the extent PVR does not have sufficient cash reserves or is unable to finance growth externally, its cash distribution policy will significantly impair its ability to grow. In addition, to the extent PVR issues additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that PVR will be unable to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to distribute to our unitholders. The incurrence of additional debt to finance its growth strategy would result in increased interest expense to PVR, which in turn may reduce the available cash that we have to distribute to our unitholders.
While we or PVR may incur debt to pay distributions to our and its unitholders, the agreements governing such debt may restrict or limit the distributions we can pay to our unitholders.
While we or PVR are permitted by our partnership agreements to incur debt to pay distributions to our unitholders, our or PVR’s payment of principal and interest on such indebtedness will reduce our cash available for distribution on our unitholders. We anticipate that any credit facility we enter into will limit our ability to pay distributions to our unitholders during an event of default or if an event of default would result from the distributions. In addition, any future levels of indebtedness may adversely affect our ability to obtain additional financing for future operations or capital needs, limit our ability to pursue acquisitions and other business opportunities, or make our results of operations more susceptible to adverse economic or operating conditions.
Furthermore, PVR’s debt agreements, including its revolving credit facility and senior notes, contain covenants limiting its ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to us. They also contain covenants requiring PVR not to exceed certain specified financial ratios. PVR is prohibited from making any distribution to its partners if such distribution would cause an event of default or otherwise violate a covenant under these agreements. 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 PVR’s revolving credit facility and senior notes.
Our unitholders do not elect our general partner or vote on our general partner’s directors. The owner of our general partner owns a sufficient number of common units to allow it to prevent the removal of our general partner.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders do not have the ability to elect our general partner or the directors of our general partner and will have no right to elect our general partner or the directors of our general partner on an annual or other continuing basis in the future. The board of directors of our general partner, including our independent directors, is chosen by Penn Virginia, its sole member. Furthermore, if our public unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Our general partner may not be removed except upon the vote of the holders of at least two-thirds of the outstanding common units. Because Penn Virginia owns more than one-third of our outstanding units, our general partner currently cannot be removed without its consent. As a result of these provisions, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
Our general partner may cause us to issue additional common units or other equity securities without your approval, which would dilute your ownership interests.
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 the common units may decline. |
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The control of our general partner may be transferred to a third party who could replace our current management team, in either case, without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, Penn Virginia, the owner of our general partner, may transfer its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner and to control the decisions taken by the board of directors and officers.
If PVR’s unitholders remove PVR’s general partner, we would lose our general partner interest and incentive distribution rights in PVR and the ability to manage PVR.
We currently manage PVR through Penn Virginia Resource GP, LLC, PVR’s general partner and our wholly-owned subsidiary. PVR’s partnership agreement, however, gives unitholders of PVR the right to remove the general partner of PVR upon the affirmative vote of holders of two-thirds of PVR’s outstanding units. If Penn Virginia Resource GP, LLC were removed as general partner of PVR, it would receive cash or common units in exchange for its 2% general partner interest and the incentive distribution rights and would lose its ability to manage PVR. While the common units or cash we would receive are intended under the terms of PVR’s partnership agreement to fully compensate us in the event such an exchange is required, the value of these common units or investments we make with the cash over time may not be equivalent to the value of the general partner interest and the incentive distribution rights had we retained them.
In addition, if Penn Virginia Resource GP, LLC is removed as general partner of PVR, we would face an increased risk of being deemed an investment company. See “—If in the future we cease to manage and control PVR, we may be deemed to be an investment company under the Investment Company Act of 1940.”
Our ability to sell our partner interests in PVR may be limited by securities law restrictions and liquidity constraints.
As of December 31, 2007, we owned 19,587,049 common units of PVR, all of which are unregistered and restricted securities within the meaning of Rule 144 under the Securities Act of 1933, or the Securities Act. Unless we were to register these units, we are limited to selling into the market in any three-month period an amount of PVR common units that does not exceed the greater of 1% of the total number of common units outstanding or the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale. In addition, we face contractual limitations on our ability to sell our general partner interest and incentive distribution rights and the market for such interests is illiquid.
You may not have limited liability if a court finds that unitholder action constitutes control of our business.
Under Delaware law, you could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders as a group to remove or replace our general partner, to approve some amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in the “control” of our business. Additionally, the limitations on the liability of holders of limited partner interests for the liabilities of a limited partnership have not been clearly established in many jurisdictions.
Furthermore, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
If in the future we cease to manage and control PVR, we may be deemed to be an investment company under the Investment Company Act of 1940.
If we cease to manage and control PVR and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contractual rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us and our affiliates, and adversely affect the price of our common units.
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Our partnership agreement restricts the rights of unitholders owning 20% or more of our units.
Our unitholders’ voting rights are restricted by the provision in our partnership agreement generally providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of the general partner, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction of our management. As a result, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
PVR may issue additional limited partner interests or other equity securities, which may increase the risk that PVR will not have sufficient available cash to maintain or increase its cash distribution level.
PVR has wide latitude to issue additional limited partner interests on the terms and conditions established by its general partner. We receive cash distributions from PVR on the general partner interest, incentive distribution rights and the limited partner interest that we hold. Because a majority of the cash we receive from PVR is attributable to our ownership of the incentive distribution rights, payment of distributions on additional PVR limited partner interests may increase the risk that PVR will be unable to maintain or increase its quarterly cash distribution per unit, which in turn may reduce the amount of incentive distributions we receive and the available cash that we have to distribute to our unitholders.
If PVR’s general partner is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of PVR, its value, and, therefore, the value of our common units, could decline.
The general partner of PVR may make expenditures on behalf of PVR for which it will seek reimbursement from PVR. Under Delaware partnership law, the general partner, in its capacity as the general partner of PVR, has unlimited liability for the obligations of PVR, such as its debts and environmental liabilities, except for those contractual obligations of PVR that are expressly made without recourse to the general partner. To the extent its general partner incurs obligations on behalf of PVR, it is entitled to be reimbursed or indemnified by PVR. If PVR is unable or unwilling to reimburse or indemnify its general partner, PVR’s general partner may not be able to satisfy those liabilities or obligations, which would reduce its cash flows to us.
Risks Related to Conflicts of Interest
PVR’s general partner owes fiduciary duties to PVR’s unitholders that may conflict with our interests.
Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including PVR’s general partner, on one hand, and PVR and its unitholders, on the other hand. The directors and officers of PVR’s general partner have fiduciary duties to manage PVR in a manner beneficial to us, the owner of PVR’s general partner. At the same time, PVR’s general partner has a fiduciary duty to manage PVR in a manner beneficial to PVR and its unitholders. The board of directors of PVR’s general partner or its conflicts committee will resolve any such conflict and they have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.
| • | For example, conflicts of interest may arise in the following situations: |
| • | the terms and conditions of any contractual agreements between us and our affiliates, on the one hand, and PVR, on the other hand; |
| • | the interpretation and enforcement of contractual obligations between us and our affiliates, on one hand, and PVR, on the other hand; |
| • | the determination of the amount of cash to be distributed to PVR’s partners and the amount of cash to be reserved for the future conduct of PVR’s business; |
| • | the determination of whether PVR should make acquisitions and on what terms; |
| • | the determination of whether PVR should use cash on hand, borrow or issue equity to raise cash to finance acquisitions or expansion capital projects, repay indebtedness, meet working capital needs, pay distributions or otherwise; |
| • | any decision we make in the future to engage in business activities independent of PVR; and |
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| • | the allocation of shared overhead expenses to PVR and us. |
Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner has limited fiduciary duties to us and our unitholders, which may permit it to favor its own interests to the detriment of us and our unitholders.
Penn Virginia and its affiliates, own an approximately 82% limited partner interest in us and own and control our general partner. Conflicts of interest may arise between our general partner and its affiliates (including Penn Virginia), on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
| • | Our general partner is allowed to take into account the interests of parties other than us, such as Penn Virginia, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders. |
| • | Our general partner determines whether or not we incur debt and that decision may affect our or PVR’s credit ratings. |
| • | Our general partner may limit its liability and reduce its fiduciary duties under our partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations and reductions, might constitute breaches of fiduciary duty. As a result of purchasing units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law. |
| • | Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available to be distributed to our unitholders. |
| • | Our general partner controls the enforcement of obligations owed to us by it and its affiliates. |
| • | Our partnership agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution. |
| • | Our general partner determines which costs incurred by it and its affiliates are reimbursable by us. |
| • | Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf. |
| • | Our general partner decides whether to retain separate counsel, accountants or others to perform services for us. |
The fiduciary duties of our general partner’s officers and directors may conflict with those of PVR’s general partner, and our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to us.
Our general partner’s officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our unitholders and the owner of our general partner, Penn Virginia. However, a majority of our general partner’s eight directors and all of its officers are also directors or officers of PVR’s general partner, which has fiduciary duties to manage the business of PVR in a manner beneficial to PVR and its unitholders. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to us on the one hand, and PVR, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.
In addition, our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute a breach of our general partner’s fiduciary duties owed to unitholders. By purchasing our units, you are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.
We may face conflicts of interest in the allocation of administrative time among Penn Virginia’s business, our business and PVR’s business.
Our general partner shares administrative personnel with Penn Virginia and PVR’s general partner to operate Penn Virginia’s business, our business and PVR’s business. Our general partner’s officers, who are also the officers of PVR’s general partner and/or Penn Virginia, will have responsibility for overseeing the allocation of time spent by administrative
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personnel on our behalf and on behalf of PVR and/or Penn Virginia. These officers face conflicts regarding these time allocations that may adversely affect our results of operations, cash flows and financial condition. It is unlikely that these allocations will be the result of arms-length negotiations among Penn Virginia, our general partner and PVR’s general partner.
Our general partner has a call right that may require you to sell your common units at an undesirable time or price.
If at any time more than 90% of our outstanding units are owned by our general partner and its affiliates, our general partner will have the right, which it may assign to any of its affiliates or to 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 (x) 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 (y) 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, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your common units. Affiliates of our general partner currently own approximately 82% of our outstanding common units.
Our general partner may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without prior approval of our unitholders.
Our general partner may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without prior approval of our unitholders. If our general partner at any time decided to incur debt and secures its obligations or indebtedness by all or substantially all of our assets, and if our general partner is unable to satisfy such obligations or repay such indebtedness, the lenders could seek to foreclose on our assets. The lenders may also sell all or 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
Risks Related to PVR’s Coal and Natural Resource Management Business
If PVR’s lessees do not manage their operations well, their production volumes and PVR’s coal royalties revenues could decrease.
PVR depends on its lessees to effectively manage their operations on its properties. PVR’s lessees make their own business decisions with respect to their operations, including decisions relating to:
| • | 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 PVR’s lessees do not manage their operations well, their production could be reduced, which would result in lower coal royalties revenues to PVR and could adversely affect PVR’s ability to make its quarterly distributions.
The coal mining operations of PVR’s lessees are subject to numerous operational risks that could result in lower coal royalties revenues.
PVR’s coal royalties revenues are largely dependent on the level of production from its coal reserves achieved by its lessees. The level of PVR’s lessees’ production is subject to operating conditions or events that may increase PVR’s lessees’
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cost of mining and delay or halt production at particular mines for varying lengths of time and that are beyond their or its control, including:
| • | the inability to acquire necessary permits; |
| • | 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 PVR’s reserves could reduce its coal royalties revenues and adversely affect its ability to make its quarterly distributions. In addition, PVR’s coal royalties revenues are based upon sales of coal by its lessees to their customers. If PVR’s lessees do not receive payments for delivered coal on a timely basis from their customers, their cash flow would be adversely affected, which could cause PVR’s cash flow to be adversely affected and could adversely affect PVR’s ability to make its quarterly distributions.
A substantial or extended decline in coal prices could reduce PVR’s coal royalties revenues and the value of PVR’s coal reserves.
A substantial or extended decline in coal prices from recent levels could have a material adverse effect on PVR’s lessees’ operations (including mine closures) and on the quantities of coal that may be economically produced from its properties. This, in turn, could reduce PVR’s coal royalties revenues, its coal services revenues and the value of its coal reserves. Additionally, volatility in coal prices could make it difficult to estimate with precision the value of PVR’s coal reserves and any coal reserves that PVR may consider for acquisition.
PVR depends on a limited number of primary operators for a significant portion of its coal royalties revenues and the loss of or reduction in production from any of PVR’s major lessees would reduce its coal royalties revenues.
PVR depends on a limited number of primary operators for a significant portion of its coal royalties revenues. In 2007, five primary operators, each with multiple leases, accounted for 65% of PVR’s coal royalties revenues and 11% of our total consolidated revenues. If any of these operators enters bankruptcy or decides to cease operations or significantly reduce its production, PVR’s coal royalties revenues would be reduced.
A failure on the part of PVR’s lessees to make coal royalty payments could give PVR the right to terminate the lease, repossess the property or obtain liquidation damages and/or enforce payment obligations under the lease. If PVR repossessed any of its properties, PVR would seek to find a replacement lessee. PVR may not be able to find a replacement lessee and, if it finds a replacement lessee, PVR may not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If PVR enters into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as the lessee it replaced. In addition, it may be difficult for PVR to secure new or replacement lessees for small or isolated coal reserves, since industry trends toward consolidation favor larger-scale, higher technology mining operations to increase productivity rates.
PVR’s coal business will be adversely affected if PVR is unable to replace or increase its coal reserves through acquisitions.
Because its reserves decline as its lessees mine its coal, PVR’s future success and growth depends, in part, upon its ability to acquire additional coal reserves that are economically recoverable. If PVR is unable to negotiate purchase contracts to replace or increase its coal reserves on acceptable terms, its coal royalties revenues will decline as its coal reserves are
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depleted. In addition, if PVR is unable to successfully integrate the companies, businesses or properties it is able to acquire, its coal royalties revenues may decline and PVR could, therefore, experience a material adverse effect on its business, financial condition or results of operations. If PVR acquires additional coal reserves, there is a possibility that any acquisition could be dilutive to earnings and reduce its ability to make distributions to unitholders, including us, or to pay interest on, or the principal of, its debt obligations. Any debt PVR incurs to finance an acquisition may similarly affect its ability to make distributions to unitholders, including us, or to pay interest on, or the principal of, its debt obligations. PVR’s ability to make acquisitions in the future also could be limited by restrictions under its existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.
PVR’s lessees could satisfy obligations to their customers with coal from properties other than PVR’s, depriving PVR of the ability to receive amounts in excess of the minimum coal royalty payments.
PVR does not control its lessees’ business operations. PVR’s lessees’ customer supply contracts do not generally require its lessees to satisfy their obligations to their customers with coal mined from PVR’s reserves. Several factors may influence a lessee’s decision to supply its customers with coal mined from properties PVR does not own or lease, including the royalty rates under the lessee’s lease with PVR, mining conditions, transportation costs and availability and customer coal quality specifications. If a lessee satisfies its obligations to its customers with coal from properties PVR does not own or lease, production under its lease will decrease, and PVR will receive lower coal royalties revenues.
Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal mined from PVR’s properties.
Transportation costs represent a significant portion of the total cost of coal for the customers of PVR’s lessees. Increases in transportation costs could make coal a less competitive source of energy or could make coal produced by some or all of PVR’s lessees less competitive than coal produced from other sources. On the other hand, significant decreases in transportation costs could result in increased competition for PVR’s lessees from coal producers in other parts of the country or increased imports from offshore producers.
PVR’s lessees depend upon rail, barge, trucking, overland conveyor and other systems to deliver coal to their customers. Disruption of these transportation services due to weather-related problems, strikes, lockouts, bottlenecks, mechanical failures and other events could temporarily impair the ability of PVR’s lessees to supply coal to their customers. PVR’s lessees’ transportation providers may face difficulties in the future and impair the ability of its lessees to supply coal to their customers, thereby resulting in decreased coal royalties revenues to PVR.
PVR’s lessees could experience labor disruptions, and PVR’s lessees’ workforces could become increasingly unionized in the future.
Two of PVR’s lessees each has one mine operated by unionized employees. One of the mines operated by unionized employees was PVR’s second largest mine on the basis of coal production as of December 31, 2007. All of PVR’s lessees could become increasingly unionized in the future. If some or all of PVR’s lessees’ non-unionized operations were to become unionized, it could adversely affect their productivity and increase the risk of work stoppages. In addition, PVR’s lessees’ operations may be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against its lessees’ operations. Any further unionization of PVR’s lessees’ employees could adversely affect the stability of production from its coal reserves and reduce its coal royalties revenues.
PVR’s coal reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of PVR’s coal reserves.
PVR’s estimates of its coal reserves may vary substantially from the actual amounts of coal its lessees may be able to economically recover. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond PVR’s control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions relate to:
| • | 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 |
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| • | future coal prices, operating costs, capital expenditures, severance and excise taxes and development and reclamation costs. |
Actual production, revenues and expenditures with respect to PVR’s coal reserves will likely vary from estimates, and these variations may be material. As a result, you should not place undue reliance on the coal reserve data provided by PVR.
Any change in fuel consumption patterns by electric power generators away from the use of coal could affect the ability of PVR’s lessees to sell the coal they produce and thereby reduce PVR’s coal royalties revenues.
According to the U.S. Department of Energy, domestic electric power generation accounts for approximately 90% of domestic coal consumption. The amount of coal consumed for domestic electric power generation is affected primarily by the overall demand for electricity, the price and availability of competing fuels for power plants such as nuclear, natural gas, fuel oil and hydroelectric power and environmental and other governmental regulations. PVR believes that most new power plants will be built to produce electricity during peak periods of demand. Many of these new power plants will likely be fired by natural gas because of lower construction costs compared to coal-fired plants and because natural gas is a cleaner burning fuel. The increasingly stringent requirements of the CAA may result in more electric power generators shifting from coal to natural gas-fired power plants. See Item 1, “Business—Government Regulation and Environmental Matters—PVR Coal and Natural Resource Management Segment—Air Emissions.”
Extensive environmental laws and regulations affecting electric power generators could have corresponding effects on the ability of PVR’s lessees to sell the coal they produce and thereby reduce PVR’s coal royalties revenues.
Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants, which are the ultimate consumers of the coal PVR’s 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. There is also continuing pressure on state and federal regulators to impose limits on carbon dioxide emissions from electric power plants, particularly coal-fired power plants. 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 PVR’s lessees produce and thereby reducing its coal royalties revenues. See Item 1, “Business—Government Regulation and Environmental Matters—PVR Coal and Natural Resource Management Segment—Air Emissions.”
Delays in PVR’s lessees obtaining mining permits and approvals, or the inability to obtain required permits and approvals, could have an adverse effect on PVR’s coal royalties revenues.
Mine operators, including PVR’s 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 are complex and can change over time. The public has the right to comment on many permit applications and otherwise participate in the permitting process, including through court intervention. Accordingly, permits required by PVR’s lessees to conduct operations may not be issued, maintained or renewed, may not be issued or renewed in a timely fashion, or may involve requirements that restrict PVR’s lessees’ ability to economically conduct their mining operations. Limitations on PVR’s lessees’ ability to conduct their mining operations due to the inability to obtain or renew necessary permits, or due to uncertainty, litigation or delays associated with the eventual issuance of these permits, could have an adverse effect on its coal royalties revenues. See Item 1, “Business—Government Regulation and Environmental Matters—PVR Coal and Natural Resource Management Segment—Mining Permits and Approvals.”
Uncertainty over the precise parameters of the Clean Water Act’s regulatory scope and a recent federal district court decision may adversely impact PVR’s coal lessees’ ability to secure the necessary permits for their valley fill surface mining activities.
To dispose of mining overburden generated from surface mining activities, PVR’s lessees often need to obtain government approvals, including Clean Water Act Section 404 permits to construct valley fills and sediment control ponds. Ongoing uncertainty over which waters are subject to the Clean Water Act may adversely impact PVR’s lessees’ ability to secure these necessary permits. In addition, a recent decision by a United States District Court in West Virginia invalidated a permit issued to one of PVR’s lessees for the Republic No. 2 Mine and enjoined its lessee, Alex Energy, Inc., from taking any further actions under this permit. Although this ruling has been appealed, uncertainty over the correct legal standard for issuing Section 404 permits may lead to rulings invalidating other permits, additional challenges to various permits and additional delays and costs in applying for and obtaining new permits. Unless this decision is overturned or further limited in
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subsequent proceedings, the ruling and its collateral consequences could ultimately have an adverse effect on PVR’s coal royalties revenues. See Item 1, “Business—Government Regulation and Environmental Matters—PVR Coal and Natural Resource Management Segment—Clean Water Act,” for more information about the litigation described above.
PVR’s lessees’ mining operations are subject to extensive and costly laws and regulations, which could increase operating costs and limit its lessees’ ability to produce coal, which could have an adverse effect on PVR’s coal royalties revenues.
PVR’s lessees are subject to numerous and detailed federal, state and local laws and regulations affecting coal mining operations, including laws and regulations pertaining to employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Numerous governmental permits and approvals are required for mining operations. PVR’s lessees are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be significant and time-consuming and may delay commencement or continuation of exploration or production operations. The possibility exists that new laws or regulations (or judicial interpretations of existing laws and regulations) may be adopted in the future that could materially affect PVR’s lessees’ mining operations, either through direct impacts such as new requirements impacting its lessees’ existing mining operations, or indirect impacts such as new laws and regulations that discourage or limit coal consumers’ use of coal. Any of these direct or indirect impacts could have an adverse effect on PVR’s coal royalties revenues. See Item 1, “Business—Government Regulation and Environmental Matters—PVR Coal and Natural Resource Management Segment.”
Because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry and, notwithstanding compliance efforts, PVR does not believe violations by its lessees can be eliminated completely. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens and, to a lesser extent, the issuance of injunctions to limit or cease operations. PVR’s lessees may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from their operations. If PVR’s lessees are required to pay these costs and liabilities and if their financial viability is affected by doing so, then their mining operations and, as a result, PVR’s coal royalties revenues and its ability to make distributions to us, could be adversely affected.
Recent mining accidents in West Virginia and Kentucky have received national attention and instigated responses at the state and national level that have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. See Item 1, “Business—Government Regulation and Environmental Matters—PVR Coal and Natural Resource Management Segment—Mine Health and Safety Laws,” for a more detailed discussion of recently enacted legislation that addresses mine safety equipment, training and emergency reporting requirements. Implementing and complying with these new laws and regulations could adversely affect PVR’s lessees’ coal production and could therefore have an adverse effect on PVR’s coal royalties revenues and its ability to make distributions to us.
Risks Related to PVR’s Natural Gas Midstream Business
The success of PVR’s natural gas midstream business depends upon its ability to find and contract for new sources of natural gas supply.
In order to maintain or increase system throughput levels on PVR’s gathering systems and asset utilization rates at its processing plants, PVR must contract for new natural gas supplies. The primary factors affecting PVR’s ability to connect new supplies of natural gas to its gathering systems include the level of drilling activity creating new gas supply near its gathering systems, PVR’s success in contracting for existing natural gas supplies that are not committed to other systems and PVR’s ability to expand and increase the capacity of its systems. PVR may not be able to obtain additional contracts for natural gas supplies.
Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. PVR has no control over the level of drilling activity in its areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, PVR has no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital.
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PVR’s natural gas midstream assets, including its gathering systems and processing plants, are connected to natural gas reserves and wells for which the production will naturally decline over time. PVR’s cash flows associated with these systems will decline unless it is able to secure new supplies of natural gas by connecting additional production to these systems. A material decrease in natural gas production in PVR’s areas of operation, as a result of depressed commodity prices or otherwise, would result in a decline in the volume of natural gas PVR handles, which would reduce its revenues and operating income. In addition, PVR’s future growth will depend, in part, upon whether it can contract for additional supplies at a greater rate than the rate of natural decline in PVR’s currently connected supplies.
The profitability of PVR’s natural gas midstream business is dependent upon prices and market demand for natural gas and NGLs, which are beyond PVR’s control and have been volatile.
PVR is subject to significant risks due to fluctuations in natural gas commodity prices. During 2007, PVR generated a majority of its gross processing 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—percentage-of-proceeds and gas purchase/keep-whole arrangements. See Item 1, “Business—PVR’s Contracts—PVR Natural Gas Midstream Segment.”
Virtually all of the natural gas gathered on PVR’s Crescent System and Hamlin System is contracted under percentage-of-proceeds arrangements. The natural gas gathered on PVR’s Beaver System is contracted primarily under either percentage-of proceeds or gas purchase/keep-whole arrangements. Under both types of arrangements, PVR provides gathering and processing services for natural gas received. Under percentage-of-proceeds arrangements, PVR generally sells the NGLs produced from the processing operations and the remaining residue gas at market prices and remits to the producers an agreed upon percentage of the proceeds based upon an index price for the gas and the price received for the NGLs. Under these arrangements, revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have a material adverse effect on PVR’s results of operations. Under gas purchase/keep-whole arrangements, PVR generally buys natural gas from producers based upon an index price and then sells the NGLs and the remaining residue gas to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the volume of natural gas available for sale, profitability is dependent on the value of those NGLs being higher than the value of the volume of gas reduction or “shrink.” Under these arrangements, revenues and gross margins decrease when the price of natural gas increases relative to the price of NGLs. Accordingly, a change in the relationship between the price of natural gas and the price of NGLs could have a material adverse effect on PVR’s results of operations.
In the past, the prices of natural gas and NGLs have been extremely volatile, and PVR expects this volatility to continue. The markets and prices for residue gas and NGLs depend upon factors beyond PVR’s control. These factors include demand for oil, natural gas and NGLs, which fluctuates with changes in market and economic conditions, and other factors, including:
| • | 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 PVR’s business by substantially increasing the level of its indebtedness and contingent liabilities and increasing the risks of being unable to effectively integrate these new operations.
From time to time, PVR evaluates and acquires assets and businesses that it believes complement its existing operations. PVR may encounter difficulties integrating these acquisitions with its existing businesses without a loss of employees or customers, a loss of revenues, an increase in operating or other costs or other difficulties. In addition, PVR may not be able to realize the operating efficiencies, competitive advantages, cost savings or other benefits expected from these acquisitions. Future acquisitions may require substantial capital or the incurrence of substantial indebtedness. As a result, PVR’s capitalization and results of operations may change significantly following an acquisition. Future acquisitions might not generate increases in PVR’s cash distributions to its unitholders.
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Expanding PVR’s natural gas midstream business by constructing new gathering systems, pipelines and processing facilities subjects PVR to construction risks.
One of the ways PVR may grow its natural gas midstream business is through the construction of additions to existing gathering, compression and processing systems. The construction of a new gathering system or pipeline, the expansion of an existing pipeline through the addition of new pipe or compression and the construction of new processing facilities involve numerous regulatory, environmental, political and legal uncertainties beyond PVR’s control and require the expenditure of significant amounts of capital. If PVR undertakes these projects, they may not be completed on schedule, or at all, or at the budgeted cost. Moreover, PVR’s revenues may not increase immediately upon the expenditure of funds on a particular project. For example, the construction of gathering facilities requires the expenditure of significant amounts of capital, which may exceed PVR’s estimates. Generally, PVR may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, PVR may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. As a result, there is the risk that new facilities may not be able to attract enough natural gas to achieve PVR’s expected investment return, which could adversely affect its financial position or results of operations and its ability to make distributions to us.
If PVR is unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then PVR may be unable to fully execute its growth strategy and its cash flows could be reduced.
The construction of additions to PVR’s existing gathering assets may require PVR to obtain new rights-of-way before constructing new pipelines. PVR may be unable to obtain rights-of-way to connect new natural gas supplies to its existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for PVR to obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, then PVR’s cash flows could be reduced.
PVR is exposed to the credit risk of its natural gas midstream customers, and nonpayment or nonperformance by PVR’s customers would reduce its cash flows.
PVR is subject to risk of loss resulting from nonpayment or nonperformance by its natural gas midstream customers. PVR depends on a limited number of customers for a significant portion of its natural gas midstream revenues. In 2007, three of PVR’s natural gas midstream customers accounted for 53% of PVR’s natural gas midstream revenues and 42% of our total consolidated revenues. Any nonpayment or nonperformance by PVR’s natural gas midstream customers would reduce its cash flows.
Any reduction in the capacity of, or the allocations to, PVR in interconnecting third-party pipelines could cause a reduction of volumes processed, which could adversely affect PVR’s revenues and cash flows.
PVR is dependent upon connections to third-party pipelines to receive and deliver residue gas and NGLs. Any reduction of capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures or other causes could result in reduced volumes gathered and processed in PVR’s natural gas midstream facilities. Similarly, if additional shippers begin transporting volumes of residue gas and NGLs on interconnecting pipelines, PVR’s allocations in these pipelines could be reduced. Any reduction in volumes gathered and processed in PVR’s facilities could adversely affect its revenues and cash flows.
Natural gas derivative transactions may limit PVR’s potential gains and involve other risks.
In order to manage PVR’s exposure to price risks in the marketing of its natural gas and NGLs, PVR periodically enters into natural gas and NGL price hedging arrangements with respect to a portion of its expected production. PVR’s hedges are limited in duration, usually for periods of two years or less. However, in connection with acquisitions, sometimes PVR’s hedges are for longer periods. These hedging transactions may limit PVR’s potential gains if natural gas or NGL prices were to rise over the price established by the hedging arrangements. In trying to maintain an appropriate balance, PVR may end up hedging too much or too little, depending upon how natural gas or NGL prices fluctuate in the future.
In addition, derivative transactions may expose PVR to the risk of financial loss in certain circumstances, including instances in which:
| • | PVR’s production is less than expected; |
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| • | there is a widening of price basis differentials between delivery points for PVR’s production and the delivery point assumed in the hedge arrangement; |
| • | the counterparties to PVR’s 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 derivatives certain volumes of production may have more or less variability than the regional price index used for the sale of that production.
PVR’s natural gas midstream business involves many hazards and operational risks, some of which may not be fully covered by insurance.
PVR’s natural gas midstream operations are subject to the many hazards inherent in the gathering, compression, treating, processing and transportation of natural gas and NGLs, including:
| • | damage to pipelines, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism; |
| • | 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 PVR’s related operations. PVR’s natural gas midstream operations are concentrated in Texas and Oklahoma, and a natural disaster or other hazard affecting these areas could have a material adverse effect on its operations. PVR is not fully insured against all risks incident to its natural gas midstream business. PVR does not have property insurance on all of its underground pipeline systems that would cover damage to the pipelines. PVR is not insured against all environmental accidents that might occur, other than those considered to be sudden and accidental. If a significant accident or event occurs that is not fully insured, it could adversely affect PVR’s operations and financial condition.
Federal, state or local regulatory measures could adversely affect PVR’s natural gas midstream business.
PVR owns and operates an 11-mile interstate natural gas pipeline that, pursuant to the NGA, is subject to the jurisdiction of the FERC. The FERC has granted PVR waivers of various requirements otherwise applicable to conventional FERC-jurisdictional pipelines, including the obligation to file a tariff governing rates, terms and conditions of open access transportation service. The FERC has determined that PVR will have to comply with the filing requirements if the natural gas company ever desires to apply for blanket transportation authority to transport third-party gas on the 11-mile pipeline. The FERC may revoke these waivers at any time.
PVR’s natural gas gathering facilities generally are exempt from the FERC’s jurisdiction under the NGA, but the FERC regulation nevertheless could change and significantly affect PVR’s gathering business and the market for its services. For a more detailed discussion of how regulatory measures affect PVR’s natural gas gathering systems, see Item 1, “Business—Government Regulation and Environmental Matters—PVR Natural Gas Midstream Segment.”
Failure to comply with applicable federal and state laws and regulations can result in the imposition of administrative, civil and criminal remedies.
PVR’s natural gas midstream business is subject to extensive environmental regulation.
Many of the operations and activities of PVR’s gathering systems, plants and other facilities are subject to significant federal, state and local environmental laws and regulations. These include, for example, laws and regulations that impose obligations related to air emissions and discharge of wastes from PVR’s facilities and the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by PVR or the prior owners of its natural gas midstream business or locations to which it or they have sent wastes for disposal. These laws and regulations can restrict or impact PVR’s business activities in many ways, including restricting the manner in which it disposes of substances,
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requiring pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with control requirements. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances and wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.
There is inherent risk of the incurrence of environmental costs and liabilities in PVR’s natural gas midstream business due to its handling of natural gas and other petroleum products, air emissions related to its natural gas midstream operations, historical industry operations, waste disposal practices and the use by the prior owners of its natural gas midstream business of natural gas flow meters containing mercury. For example, an accidental release from one of PVR’s pipelines or processing facilities could subject it to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase PVR’s compliance costs and the cost of any remediation that may become necessary. PVR may incur material environmental costs and liabilities. Insurance may not provide sufficient coverage in the event an environmental claim is made. See Item 1, “Business—Government Regulation and Environmental Matters—PVR Natural Gas Midstream Segment.”
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 IRS were to treat us or PVR as a corporation for federal income tax purposes or we or PVR were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.
The value of our investment in PVR depends largely on PVR being treated as a partnership for federal income tax purposes, which requires that 90% or more of PVR’s gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code. PVR may not meet this requirement or current law may change so as to cause, in either event, PVR to be treated as a corporation for federal income tax purposes or otherwise subject to federal income tax. Moreover, the anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or IRS, on this or any other matter affecting us.
If PVR were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to us would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to us. As a result, there would be a material reduction in our anticipated cash flow and distributions to unitholders and likely cause a substantial reduction in the value of our common units.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in our anticipated cash flow and likely cause a substantial reduction in the value of our common units.
Current law may change, causing us or PVR to be treated as a corporation for federal income tax purposes or otherwise subjecting us or PVR to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, PVR is subject to a new entity-level tax on the portion of its income that is generated in Texas. Specifically, the Texas margin tax is imposed at a maximum effective rate of 0.7% of PVR’s federal gross income apportioned to Texas. Imposition of such a tax on us or PVR by Texas, or any other state, will reduce the cash available for distribution to our unitholders.
PVR’s partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects PVR to taxation as a corporation or otherwise subjects PVR to entity-level taxation for federal, state or local income
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tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on PVR. Likewise, our cash distributions to you will be reduced if we or PVR is subjected to any form of such entity-level taxation.
The tax treatment of our structure is subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The U.S. federal income tax treatment of unitholders depends in some instances on determinations of fact and interpretations of complex provisions of U.S. federal income tax law. You should be aware that the U.S. federal income tax rules are constantly under review by persons involved in the legislative process, the IRS and the U.S. Treasury Department, frequently resulting in revised interpretations of established concepts, statutory changes, revisions to Treasury Regulations and other modifications and interpretations. The present U.S. federal income tax treatment of an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation (referred to as the “Qualifying Income Exception”), affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code section 7704(d). It is possible that these efforts could result in changes to the existing U.S. federal tax laws that affect publicly traded partnerships, including us. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
If the IRS contests the federal income tax positions that we or PVR take, it may adversely affect the market for our common units or PVR’s common units, and the costs of any contest will reduce cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter that affects us. Moreover, PVR has not requested any ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes or any other matter that affects it. The IRS may adopt positions that differ from the positions we or PVR take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we or PVR take. A court may disagree with some or all of the positions we or PVR take. Any contest with the IRS may materially and adversely impact the market for our common units or PVR’s common units and the price at which they trade. In addition, the cost of any contest between PVR and the IRS will result in a reduction in cash available for distribution to PVR unitholders and thus will be borne indirectly by us, as a unitholder and as the owner of the general partner of PVR. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
Because our unitholders are treated as partners to whom we allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the tax liability that results from the taxation of your share of our taxable income.
Tax gain or loss on disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and the adjusted tax basis in those common units. Prior distributions to you in excess of the total net taxable income allocated to you, which decreased your tax basis in your common units, will, in effect, become taxable income to you if the common units are sold at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you. In addition, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
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Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in our common units.
We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned common units, such unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.
When we or PVR issue additional units or engage in certain other transactions, PVR determines the fair market value of its assets and allocates any unrealized gain or loss attributable to such assets to the capital accounts of PVR’s unitholders and us. Although PVR may from time to time consult with professional appraisers regarding valuation matters, including the valuation of its assets, PVR makes many of the fair market value estimates of its assets itself using a methodology based on the market value of its common units as a means to measure the fair market value of its assets. PVR’s methodology may be viewed as understating the value of PVR’s assets. In that case, there may be a shift of income, gain, loss and deduction between certain PVR unitholders and us, which may be unfavorable to such PVR unitholders. Moreover, under our valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to PVR’s intangible assets and a lesser portion allocated to PVR’s tangible assets. The IRS may challenge PVR’s valuation methods, or our or PVR’s allocation of the Section 743(b) adjustment attributable to
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PVR’s tangible and intangible assets, and allocations of income, gain, loss and deduction between us and certain of PVR’s unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the technical termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A sale or exchange would occur, for example, if we sold our business or merged with another company, or if any of our unitholders, including Penn Virginia or any of its affiliates, sold or transferred their partner interests in us. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination would not effect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred.
Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in PVR.
Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in PVR. Other holders of common units in PVR will receive remedial allocations of deductions from PVR. Remedial allocations of deductions to us will be very limited. In addition, our ownership of PVR incentive distribution rights will cause more taxable income to be allocated to us from PVR than will be allocated to holders who hold only common units in PVR. If PVR is successful in increasing its distributions over time, our income allocations from our PVR incentive distribution rights will increase, and, therefore, our ratio of taxable income to cash distributions will increase. Because our ratio of taxable income to cash distributions will be greater than the ratio applicable to holders of common units in PVR, your allocable taxable income will be significantly greater than that of a holder of common units in PVR who receives cash distributions from PVR equal to the cash distributions you receive from us.
You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.
In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or PVR do business or own property now or in the future, even if you do not reside in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. It is your responsibility to file all United States federal, state and local tax returns that may be required of you.
| Item 1B | Unresolved Staff Comments |
We received no written comments from the SEC staff regarding our periodic or current reports under the Exchange Act within 180 days before the end of our fiscal year ended December 31, 2007.
| Item 2 | Properties |
Title to Properties Owned or Controlled by PVR
The following map shows the general locations of PVR’s coal reserves and related infrastructure investments and PVR’s natural gas gathering and processing systems as of December 31, 2007:
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PVR believes that it has satisfactory title to all of its properties and the associated coal reserves in accordance with standards generally accepted in the coal and natural resource management and natural gas midstream industries.
Facilities
PVR’s general partner provides all of PVR’s office space, except for a field office that PVR owns near Charleston, West Virginia.
Coal Reserves and Production
As of December 31, 2007, PVR owned or controlled approximately 818 million tons of proven and probable coal reserves located on approximately 397,000 acres (including fee and leased acreage) in Illinois, Kentucky, New Mexico, Virginia and West Virginia. PVR’s coal reserves are in various surface and underground mine seams located on the following properties:
| • | Central Appalachia Basin: properties located in eastern Kentucky, southwestern Virginia and southern West Virginia; |
| • | Northern Appalachia Basin: properties located in northern West Virginia; |
| • | Illinois Basin: properties located in southern Illinois 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 PVR’s coal reserves are classified as proven and probable reserves. Proven and probable reserves are defined as follows:
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Proven Reserves. Proven 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 Reserves. Probable 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 reserves, is high enough to assume continuity between points of observation.
In areas where geologic conditions indicate potential inconsistencies related to coal reserves, PVR performs additional exploration to ensure the continuity and mineability of the coal reserves. Consequently, sampling in those areas involves drill holes or channel samples that are spaced closer together than those distances cited above.
Coal reserve estimates are adjusted annually for production, unmineable areas, acquisitions and sales of coal in place. The majority of PVR’s coal reserves are high in energy content, low in sulfur and suitable for either the steam or 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 reserves.” Included among the factors that influence profitability are the existing market price, coal quality and operating costs.
PVR’s lessees mine coal using both underground and surface methods. As of December 31, 2007, PVR’s lessees operated 27 surface mines and 33 underground mines. Approximately 53% of the coal produced from PVR’s properties in 2007 came from underground mines and 47% came from surface mines. Most of PVR’s lessees use the continuous mining method in all of their underground mines located on PVR’s properties. In continuous mining, main airways and transportation entries are developed and remote-controlled continuous miners extract coal from “rooms,” leaving “pillars” to support the roof. Shuttle cars transport coal to a conveyor belt for transportation to the surface. In several underground mines, PVR’s lessees use two continuous miners running at the same time, also known as a supersection, to improve productivity and reduce unit costs.
Two of PVR’s lessees use the longwall mining method to mine underground reserves. Longwall mining uses hydraulic jacks or shields, varying from four feet to twelve feet in height, to support the roof of the mine while a mobile cutting shearer advances through the coal. Chain conveyors then move the coal to a standard deep mine conveyor belt system for delivery to the surface. Continuous mining is used to develop access to long rectangular panels of coal that are mined with longwall equipment, allowing controlled caving behind the advancing machinery. Longwall mining is typically highly productive when used for large blocks of medium to thick coal seams.
Surface mining methods used by PVR’s lessees include auger and highwall mining to enhance production, improve reserve recovery and reduce unit costs. On PVR’s San Juan Basin property, a combination of the dragline and truck-and-shovel surface mining methods is used to mine the coal. Dragline and truck-and-shovel mining uses large capacity machines to remove overburden to expose the coal seams. Wheel loaders then load the coal in haul trucks for transportation to a loading facility.
PVR’s lessees’ customers are primarily electric utilities, also referred to as “steam” markets. Coal produced from PVR’s properties is transported by rail, barge and truck, or a combination of these means of transportation. Coal from the Virginia portion of the Wise property and the Buchanan property is primarily shipped to electric utilities in the Southeast by the Norfolk Southern railroad. Coal from the Kentucky portion of the Wise property is primarily shipped to electric utilities in the Southeast by the CSX railroad. Coal from the Coal River and Spruce Laurel properties is shipped to steam and metallurgical customers by the CSX railroad, by barge along the Kanawha River and by truck or by a combination thereof. Coal from the Northern Appalachia properties is shipped by barge on the Monongahela River, by truck and by the CSX and Norfolk Southern railroads. Coal from the Illinois Basin properties is shipped by barge on the Green River and by truck. Coal from the San Juan Basin property is shipped to steam markets in New Mexico and Arizona by the Burlington Northern Santa Fe railroad. All of PVR’s properties contain and have access to numerous roads and state or interstate highways.
The following table shows PVR’s most important coal producing seams by property:
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| Area |
Property |
State |
Producing Mine Types |
Seam Name |
Height Range (ft.) | |||||
| Central Appalachia | Wise | Virginia, Kentucky | Surface, Underground | Parsons | 1.00 -6.00 | |||||
| Phillips | 1.50 -6.00 | |||||||||
| Low Splint | 1.00 -5.50 | |||||||||
| Taggart/Marker | 1.50 -9.00 | |||||||||
| U. Wilson | 1.50 -5.50 | |||||||||
| Kelly/Imboden | 1.00 -7.50 | |||||||||
| Buchanan | Virginia | Surface, Underground | Hagy | 2.50 -3.50 | ||||||
| Splashdam | 2.50 -4.00 | |||||||||
| Wayland | Kentucky | Underground | U. Elkhorn No. 2 | 2.33 -4.00 | ||||||
| Coal River, Fields Creek | West Virginia | Surface, Underground | Stockton | 4.00 -12.00 | ||||||
| Coalburg | 1.00 -11.00 | |||||||||
| Winifrede | 1.00 -7.00 | |||||||||
| Chilton | 1.00 -4.00 | |||||||||
| Cedar Grove | 1.00 -5.50 | |||||||||
| No. 2 Gas | 1.50 -8.00 | |||||||||
| Toney Fork | West Virginia | Surface | Coalburg | 5.00 -16.00 | ||||||
| Spruce Laurel | West Virginia | Underground | Coalburg | 3.00 -6.00 | ||||||
| Winifrede | 2.50 -4.00 | |||||||||
| Chilton | 2.50 -4.00 | |||||||||
| Alma | 2.50 -7.00 | |||||||||
| Northern Appalachia | Federal | West Virginia | Underground | Pittsburgh | 6.50 -9.50 | |||||
| Upshur | West Virginia | Surface, Underground | Redstone | 3.00 -6.50 | ||||||
| Pittsburgh | 2.00 -9.00 | |||||||||
| San Juan Basin | Lee Ranch | New Mexico | Surface | Cleary Group Seams | 8.00 -16.00 | |||||
| Illinois Basin | Green River | Kentucky | Surface, Underground | KY No. 9 | 3.00 -5.00 | |||||
| Allied | Kentucky | Underground | KY No. 9 | 3.00 - 5.00 | ||||||
| Knight Hawk | Illinois | Underground | Herrin No. 6 | 5.00 - 8.00 |
The following tables set forth production data and reserve information with respect to each of PVR’s properties:
| Production for the Year Ended December 31, | ||||||
| Property |
2007 | 2006 | 2005 | |||
| (tons in millions) | ||||||
| Central Appalachia |
18.8 | 20.2 | 19.0 | |||
| Northern Appalachia |
4.2 | 5.0 | 5.0 | |||
| Illinois Basin |
3.8 | 2.5 | 1.4 | |||
| San Juan Basin |
5.7 | 5.1 | 4.8 | |||
| Total |
32.5 | 32.8 | 30.2 | |||
| Proven and Probable Reserves as of December 31, 2007 | ||||||||||||
| Property |
Underground | Surface | Total | Steam | Metallurgical | Total | ||||||
| (tons in millions) | ||||||||||||
| Central Appalachia |
413.8 | 155.5 | 569.3 | 481.1 | 88.2 | 569.3 | ||||||
| Northern Appalachia |
29.6 | 0.1 | 29.7 | 29.7 | — | 29.7 | ||||||
| Illinois Basin |
156.6 | 11.9 | 168.5 | 168.5 | — | 168.5 | ||||||
| San Juan Basin |
— | 50.9 | 50.9 | 50.9 | — | 50.9 | ||||||
| Total |
600.0 | 218.4 | 818.4 | 730.2 | 88.2 | 818.4 | ||||||
Of the approximately 818 million tons of proven and probable coal reserves to which PVR had rights as of December 31, 2007, PVR owned the mineral interests and the related surface rights to 448 million tons, or 55%, and PVR owned only the mineral interests to 196 million tons, or 24%. PVR leased the mineral rights to the remaining 174 million tons, or 21%, from unaffiliated third parties and, in turn, subleased these reserves to its lessees. For the reserves PVR leases from third parties, PVR pays royalties to the owner based on the amount of coal produced from the leased reserves. Additionally, in some instances, PVR purchases surface rights or otherwise compensates surface right owners for mining activities on their properties. In 2007, PVR’s aggregate expenses to third-party surface and mineral owners were $5.5 million.
The following table sets forth the coal reserves PVR owns and leases with respect to each of its coal properties as of December 31, 2007:
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| Property |
Owned | Leased | Total Controlled | |||
| (tons in millions) | ||||||
| Central Appalachia |
428.1 | 141.2 | 569.3 | |||
| Northern Appalachia |
29.7 | — | 29.7 | |||
| Illinois Basin |
139.5 | 29.0 | 168.5 | |||
| San Juan Basin |
47.0 | 3.9 | 50.9 | |||
| Total |
644.3 | 174.1 | 818.4 | |||
The following table sets forth PVR’s coal reserve activity for each of its coal properties for the years ended December 2007, 2006 and 2005:
| 2007 | 2006 | 2005 | |||||||
| (tons in millions) | |||||||||
| Reserves—beginning of year |
765.4 | 689.1 | 557.3 | ||||||
| Purchase of coal reserves |
60.0 | 96.2 | 162.1 | ||||||
| Tons mined by lessees |
(32.5 | ) | (32.8 | ) | (30.2 | ) | |||
| Revisions of estimates and other |
25.5 | 12.9 | (0.1 | ) | |||||
| Reserves—end of year |
818.4 | 765.4 | 689.1 | ||||||
PVR’s coal reserve estimates are prepared from geological data assembled and analyzed by PVR’s general partner’s or its affiliates’ geologists and engineers. These estimates are compiled using geological data taken from thousands of drill holes, geophysical logs, adjacent mine workings, outcrop prospect openings and other sources. These estimates also take into account legal, qualitative, technical and economic limitations that may keep coal from being mined. Coal reserve estimates will change from time to time due to mining activities, analysis of new engineering and geological data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods and other factors.
PVR classifies low sulfur coal as coal with a sulfur content of less than 1.0%, medium sulfur coal as coal with a sulfur content between 1.0% and 1.5% and high sulfur coal as coal with a sulfur content of greater than 1.5%. Compliance coal is that portion of low sulfur coal that meets compliance standards for the CAA. As of December 31, 2007, approximately 26% of PVR’s reserves met compliance standards for the CAA and 39% were low sulfur. The following table sets forth PVR’s estimate of the sulfur content and the typical clean coal quality of its recoverable coal reserves at December 31, 2007:
| Sulfur Content | Typical Clean Coal Quality | |||||||||||||||||
| Reserves as of December 31, 2007 | Heat Content | |||||||||||||||||
| Property |
Compliance (1) |
Low Sulfur (2) |
Medium Sulfur |
High Sulfur |
Sulfur Unclassified |
Total | BTU per Pound (3) |
Sulfur (%) |
Ash (%) | |||||||||
| (tons in millions) | ||||||||||||||||||
| Central Appalachia |
213.7 | 288.8 | 156.8 | 30.2 | 93.5 | 569.3 | 14,044 | 1.03 | 6.46 | |||||||||
| Northern Appalachia |
— | — | — | 29.7 | — | 29.7 | 12,900 | 2.58 | 8.80 | |||||||||
| Illinois Basin |
— | — | — | 168.5 | — | 168.5 | 11,034 | 2.39 | 8.32 | |||||||||
| San Juan Basin |
— | 31.1 | 15.2 | 4.6 | — | 50.9 | 9,200 | 0.89 | 17.80 | |||||||||
| Total |
213.7 | 319.9 | 172.0 | 233.0 | 93.5 | 818.4 | ||||||||||||
| (1) | Compliance coal is low sulfur coal which, when burned, emits less than 1.2 pounds of sulfur dioxide per million BTU. Compliance coal meets the sulfur dioxide emission standards imposed by Phase II of the CAA without blending in other coals or using sulfur dioxide reduction technologies. Compliance coal is a subset of low sulfur coal and is, therefore, also reported within the amounts for low sulfur coal. |
| (2) | Includes compliance coal. |
| (3) | As-received BTU per pound includes the weight of moisture in the coal on an as sold basis. |
The following table shows the proven and probable coal reserves PVR leases to mine operators by property:
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| Proven and Probable Reserves as of December 31, | |||||||
| Property |
Total Controlled |
Leased to Operators |
Percentage Leased |
||||
| (tons in millions) | |||||||
| Central Appalachia |
569.3 | 491.8 | 86 | % | |||
| Northern Appalachia |
29.7 | 29.3 | 98 | % | |||
| Illinois Basin |
168.5 | 111.8 | 66 | % | |||
| San Juan Basin |
50.9 | 50.9 | 100 | % | |||
| Total |
818.4 | 683.8 | 84 | % | |||
Other Natural Resource Management Assets
Coal Preparation and Loading Facilities
PVR generates coal services revenues from fees it charges to its lessees for the use of its coal preparation and loading facilities, which are located in Virginia, West Virginia and Kentucky. The facilities provide efficient methods to enhance lessee production levels and exploit PVR’s reserves.
Timber and Oil and Gas Royalty Interests
PVR owns approximately 220,000 acres of forestland in Kentucky, Virginia and West Virginia. Approximately 28% of PVR’s forestland is located on the 62,000 acres in West Virginia that PVR acquired in September 2007. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Acquisitions and Investments,” for a discussion of PVR’s forestland acquisition. The balance of PVR’s forestland is located on properties that also contain its coal reserves.
PVR owns royalty interests in approximately 11.2 Bcfe of proved oil and gas reserves located on approximately 165,000 acres in Kentucky, Virginia and West Virginia. Approximately 40% of PVR’s oil and gas royalty interests are associated with the leases of property in eastern Kentucky and southwestern Virginia that PVR acquired in October 2007. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Acquisitions and Investments,” for a discussion of PVR’s oil and gas royalty interest acquisition.
Natural Gas Midstream Systems
PVR’s natural gas midstream operations currently include three natural gas gathering and processing systems and a stand-alone natural gas gathering system, including: (i) the Beaver/Perryton gathering and processing facilities in the Texas/Oklahoma panhandle area, (ii) the Crescent gathering and processing facilities in central Oklahoma, (iii) the Hamlin gathering and processing facilities in west-central Texas and (iv) the Arkoma gathering system in eastern Oklahoma. These systems include approximately 3,682 miles of natural gas gathering pipelines and three natural gas processing facilities, which have 160 MMcfd of total capacity. PVR’s natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. PVR owns, leases or has rights-of-way to the properties where the majority of its natural gas midstream facilities are located.
The following table sets forth information regarding PVR’s natural gas midstream assets:
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| Type |
Approximate Length (Miles) |
Approximate Number of Wells Connected |
Current Processing Capacity (MMcfd) |
Year Ended December 31, 2007 | ||||||||||
| Asset |
Average System Throughput (MMcfd) |
Utilization of Processing Capacity (%) |
||||||||||||
| Beaver/Perryton System | Gathering pipelines and processing facility | 1,421 | 1,044 | 100 | 126 | (1) | 100 | % | ||||||
| Crescent System | Gathering pipelines and processing facility | 1,680 | 865 | 40 | 20 | 50 | % | |||||||
| Hamlin System | Gathering pipelines and processing facility | 503 | 220 | 20 | 7 | 37 | % | |||||||
| Arkoma System | Gathering pipelines | 78 | 79 | — | 13 | (2) | ||||||||
| 3,682 | 2,208 | 160 | 166 | |||||||||||
| (1) | Includes gas processed at other systems connected to the Beaver/Perryton System via the pipeline acquired in June 2006. |
| (2) | Gathering-only volumes. |
Beaver/Perryton System
General. The Beaver/Perryton System is a natural gas gathering system stretching over ten counties in the Anadarko Basin of the panhandle of Texas and Oklahoma. The system consists of approximately 1,421 miles of natural gas gathering pipelines, ranging in size from two to 16 inches in diameter, and the Beaver natural gas processing plant. Included in the system is an 11-mile, 10-inch diameter, FERC-jurisdictional residue line.
The Beaver/Perryton System is comprised of a number of major gathering systems and sixteen related compressor stations that gather natural gas, directly or indirectly, to the Beaver plant in Beaver County, Oklahoma. These include the Beaver, Perryton, Spearman, Wolf Creek/Kiowa Creek and Ellis systems. These gathering systems are located in Beaver, Ellis and Harper Counties in Oklahoma and Hansford, Hutchinson, Lipscomb, Ochiltree and Roberts Counties in Texas.
The Beaver natural gas processing plant has 100 MMcfd of inlet gas capacity. The plant is capable of operating in high ethane recovery mode or in ethane rejection mode and has instrumentation allowing for unattended operation 16 hours per day.
PVR expects to place a new Spearman natural gas processing plant in service by April 2008. The Spearman natural gas processing plant will process gas gathered on the Spearman system. The new Spearman plant will create space in the Beaver natural gas processing plant for the gas that is currently bypassing the Beaver plant. PVR plans to expand the Spearman gathering system to connect it to the Perryton and Wolf Creek/Kiowa Creek gathering systems. This expansion will provide flexibility and allow for maximum utilization of both the Beaver and Spearman natural gas processing plants.
The Spearman natural gas processing plant will have 60 MMcfd of inlet capacity. The plant will be capable of operating in high ethane recovery mode or in ethane rejection mode and will have instrumentation allowing for unattended operation 16 hours per day. In conjunction with the construction of the Spearman plant, three new gas compressor stations have been constructed on the Spearman gathering system. These compressor stations will allow for more efficient operation of the Spearman system and provide lower wellhead pressures.
Natural Gas Supply. The supply in the Beaver/Perryton System comes from approximately 171 producers pursuant to 333 contracts. The average gas quality on the Beaver/Perryton System for 2007 was 3.6 gallons of NGLs per delivered Mcf.
Markets for Sale of Natural Gas and NGLs. The residue gas from the Beaver plant can be delivered into the Northern Natural Gas, Southern Star Central Gas or ANR Pipeline Company pipelines for sale or transportation to market. The NGLs produced at the Beaver plant are delivered into ONEOK Hydrocarbon’s pipeline system for transportation to and fractionation at ONEOK’s Conway fractionator.
The residue gas from the Spearman plant will be delivered into Northern Natural Gas pipelines for sale or transportation to market. The NGLs produced at the Spearman plant will be 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.
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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 1,680 miles of natural gas gathering pipelines, ranging in size from two to 10 inches in diameter, and the Crescent 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. The gas supply on the Crescent System is primarily gas associated with the production of oil or “casinghead gas” from the mature Sooner Trend. Wells in this region producing casinghead gas are generally characterized as low volume, long-lived producers of gas with large quantities of NGLs. The supply in the Crescent System comes from approximately 259 producers pursuant to 409 contracts. The average gas quality on the Crescent System for 2007 was 5.5 gallons of NGLs per delivered Mcf.
Markets for Sale of Natural Gas and NGLs. The Crescent plant’s connection to the Enogex and ONEOK Gas Transportation pipelines for residue gas and the ONEOK Hydrocarbon pipeline for NGLs give 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 503 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. The gas on the Hamlin System is primarily gas associated with the production of oil or “casinghead gas.” The supply on the Hamlin System comes from approximately 109 producers pursuant to 138 contracts. The average gas quality on the Hamlin System for 2007 was 8.9 gallons of NGLs per delivered Mcf.
Markets for Sale of Natural Gas and NGLs. 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.
Arkoma System
General. The Arkoma System is a stand-alone gathering operation in southeastern Oklahoma’s Arkoma Basin and is comprised of three separate gathering systems, two of which are 100% owned with the third system being 49% owned. We operate and maintain all three systems. The Arkoma System consists of a total of approximately 78 miles of natural gas gathering pipelines, ranging in size from three to 12 inches in diameter. Three compressor stations are operating across the Arkoma System.
Natural Gas Supply. The supply on the Arkoma System comes from approximately 18 producers pursuant to 32 contracts.
Markets for Sale of Natural Gas and NGLs. The Arkoma System lines deliver gas into the Ozark, Noram and NGPL pipelines.
Crossroads System
General. PVR is currently constructing a new natural gas gathering system located in the southeast portion of Harrison County, Texas (the Crossroads System). The Crossroads System will consist of approximately eight miles of natural gas gathering pipelines, ranging in size from eight to twelve inches in diameter, and the Crossroads natural gas processing plant. The Crossroads System will also include approximately 19 miles of six-inch NGL pipeline to transport the NGLs produced at the Crossroads plant to Panola Pipeline. The Crossroads System is expected to begin operations by April 2008.
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The Crossroads natural gas processing plant will have 80 MMcfd of inlet capacity. The plant will be capable of operating in high ethane recovery mode or in ethane rejection mode and will have instrumentation allowing for unattended operation 16 hours per day.
Natural Gas Supply. The gas on the Crossroads System will originate from the Bethany Field from two producers pursuant to two contracts. The average gas quality on the Crossroads System is expected to be 3.1 gallons of NGLs per delivered Mcf.
Markets for Sale of Natural Gas and NGLs. The Crossroads System will deliver 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 will be delivered into Panola Pipeline for transportation to Mont Belvieu for fractionation.
| Item 3 | Legal Proceedings |
We are not currently a party to any litigation. Although PVR may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, PVR is not currently a party to any material legal proceedings. In addition, PVR is not aware of any material legal or governmental proceedings against it, or contemplated to be brought against it, under the various environmental protection statutes to which it is subject. See Item 1, “Business—Government Regulation and Environmental Matters,” for a more detailed discussion of PVR’s material environmental obligations.
| Item 4 | Submission of Matters to a Vote of Security Holders |
There were no matters submitted to a vote of security holders during the fourth quarter of 2007.
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| Item 5 | Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities |
Market Information
Our common units began trading on the NYSE under the symbol “PVG” on December 6, 2006. The high and low sales prices (composite transactions) for each fiscal quarter in 2007 and the fourth quarter of 2006 were as follows:
| Quarter Ended |
High | Low | ||||
| December 31, 2007 |
$ | 39.00 | $ | 28.17 | ||
| September 30, 2007 |
$ | 40.74 | $ | 28.56 | ||
| June 30, 2007 |
$ | 32.36 | $ | 22.29 | ||
| March 31, 2007 |
$ | 26.75 | $ | 18.18 | ||
| December 31, 2006 |
$ | 20.45 | $ | 18.00 | ||
Equity Holders
As of February 22, 2008, there were 35 record holders and approximately 3,200 beneficial owners (held in street name) of our common units.
Distributions
For the year ended December 31, 2007, we paid cash distributions of $0.91 per common unit. The quarterly cash distributions paid in 2007 and 2006 were as follows:
| Period Covered by Distribution |
Record Date | Payment Date | Amount Per Unit | |||||
| Third quarter 2007 |
November 5, 2007 | November 19, 2007 | $ | 0.30 | ||||
| Second quarter 2007 |
August 6, 2007 | August 20, 2007 | $ | 0.28 | ||||
| First quarter 2007 |
May 11, 2007 | May 25, 2007 | $ | 0.26 | ||||
| Fourth quarter 2006 |
February 5, 2007 | February 14, 2007 | $ | 0.07 | (1) | |||
| (1) | Amount per unit was prorated for the period beginning on beginning on December 5, 2006, the initial trading date of our common units of the NYSE, and ending on December 31, 2006. |
On February 19, 2008, we paid a cash distribution with respect to the fourth quarter of 2007 of $0.32 per common unit. For the remainder of 2008, we expect to pay quarterly cash distributions of at least $0.32 per common unit, or $1.28 per common unit on an annualized basis.
There is no guarantee that we will pay quarterly cash distributions on our common units in any quarter, and we will be prohibited from making any distributions to our unitholders if it would cause an event of default under any debt that we might incur in the future, although we do not currently have any indebtedness.
| Item 6 | Selected Financial Data |
On December 8, 2006, we completed our IPO whereby we became the successor to Penn Virginia Resource GP, LLC on a combined basis (predecessor). For the purposes of this selected financial data, we refer to the predecessor for the periods prior to December 8, 2006 and to us for the periods beginning on December 8, 2006. The financial data present our results of operations and financial position as if we had existed as a single entity, separate from Penn Virginia, for the periods prior to December 8, 2006.
Because we own and control the general partner of PVR, we reflect our ownership interest in PVR on a consolidated basis, which means that our financial results are combined with PVR’s financial results and the results of our other subsidiaries. We have no separate operating activities apart from those conducted by PVR, and our cash flows consist solely of distributions from PVR on the partner interests, including incentive distribution rights, that we own in PVR. Accordingly, the selected historical financial data set forth in the following table primarily reflect the operating activities and results of operations of PVR. The limited partner interests in PVR not owned by our affiliates are reflected as minority interest on our
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balance sheet and the non-affiliated partners’ share of income from PVR is reflected as an expense in our results of operations.
The following selected historical financial information was derived from our audited consolidated financial statements as of December 31, 2007, 2006, 2005, 2004 and 2003, 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 in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 8, “Financial Statements and Supplementary Data.”
| Year Ended December 31, | |||||||||||||||
| 2007 | 2006 | 2005 (1) | 2004 | 2003 | |||||||||||
| (in thousands, except per unit data) | |||||||||||||||
| Revenues |
$ | 549,445 | $ | 517,891 | $ | 446,348 | $ | 75,630 | $ | 55,642 | |||||
| Expenses |
$ | 434,202 | $ | 415,468 | $ | 368,258 | $ | 35,111 | $ | 29,082 | |||||
| Operating income |
$ | 115,243 | $ | 102,423 | $ | 78,090 | $ | 40,519 | $ | 26,560 | |||||
| Net income |
$ | 29,169 | $ | 32,048 | $ | 20,769 | $ | 15,289 | $ | 10,180 | |||||
| Net income per limited partner unit, basic and diluted |
$ | 0.75 | $ | 0.98 | $ | 0.65 | $ | 0.48 | $ | 0.32 | |||||
| Total assets |
$ | 942,251 | $ | 716,269 | $ | 659,947 | $ | 285,470 | $ | 261,267 | |||||
| Long-term debt |
$ | 399,153 | $ | 207,214 | $ | 246,846 | $ | 112,926 | $ | 90,286 | |||||
| Cash flows provided by operating activities |
$ | 126,480 | $ | 100,683 | $ | 94,450 | $ | 53,852 | $ | 40,770 | |||||
| Distributions paid (2) |
$ | 35,558 | $ | — | $ | — | $ | — | $ | — | |||||
| Distributions paid per unit (2) |
$ | 0.91 | $ | — | $ | — | $ | — | $ | — | |||||
| (1) | The 2005 column includes the results of operations of our natural gas midstream segment since March 3, 2005, the closing date of the acquisition of Cantera. |
| (2) | We paid a pro rata quarterly distribution of $0.07 per unit in February 2007, which covered the period from December 5, 2006 to December 31, 2006. |
| Item 7 | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
The following discussion and analysis of the financial condition and results of operations of Penn Virginia GP Holdings, L.P. and its subsidiaries should be read in conjunction with our consolidated financial statements and the accompanying notes in Item 8, “Financial Statements and Supplementary Data.” Our discussion and analysis include the following items:
| • | Overview of Our Business |
| • | Overview of PVR’s Business |
| • | Acquisitions and Investments |
| • | Liquidity and Capital Resources |
| • | Contractual Obligations |
| • | Off-Balance Sheet Arrangements |
| • | Results of Operations |
| • | Summary of Critical Accounting Policies and Estimates |
| • | Environmental Matters |
| • | Recent Accounting Pronouncements |
| • | Forward-Looking Statements |
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Overview of Our Business
General
We are a publicly traded Delaware limited partnership formed in June 2006. Our only cash generating assets consist of our partner interests in PVR, which consist of the following:
| • | a 2% general partner interest in PVR, which we hold through our 100% ownership interest in Penn Virginia Resource GP, LLC, PVR’s general partner; |
| • | all of the incentive distribution rights in PVR, which we hold through our 100% ownership interest in PVR’s general partner; and |
| • | 19,587,049 common units of PVR, representing an approximately 42% limited partner interest in PVR. |
All of our cash flows are generated from the cash distributions we receive with respect to the PVR partner interests we own. PVR is required by its partnership agreement to distribute, and it has historically distributed within 45 days of the end of each quarter, all of its cash on hand at the end of each quarter, less cash reserves established by its general partner in its sole discretion to provide for the proper conduct of PVR’s business or to provide for future distributions. While we, like PVR, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of PVR. Most notably, our general partner does not have an economic interest in us and is not entitled to receive any distributions from us and our capital structure does not include incentive distribution rights. Therefore, our distributions are allocated exclusively to our common units, which is our only class of security currently outstanding.
Our ownership of PVR’s incentive distribution rights entitles us to receive the following percentages of cash distributed by PVR as it reaches the following target cash distribution levels:
| • | 13% of all incremental cash distributed in a quarter after $0.275 has been distributed in respect of each common unit of PVR for that quarter; |
| • | 23% of all incremental cash distributed after $0.325 has been distributed in respect of each common unit of PVR for that quarter; and |
| • | the maximum sharing level of 48% of all incremental cash distributed after $0.375 has been distributed in respect of each common unit of PVR for that quarter. |
Since 2001, PVR has increased its quarterly cash distribution 13 times from $0.25 per unit ($1.00 on an annualized basis) to $0.44 per unit ($1.76 on an annualized basis), which is its most recently declared distribution. These increased cash distributions by PVR have placed us at the third and maximum target cash distribution level as described above. As a consequence, any increase in cash distribution level from PVR will allow us to share at the 48% level and the cash distributions we receive from PVR with respect to our indirect ownership of the incentive distribution rights will increase more rapidly than those with respect to our ownership of the general partner and limited partner interests. Because we are at the maximum target cash distribution level on the incentive distribution rights, future growth in distributions we receive from PVR will not result from an increase in the target cash distribution level associated with the incentive distribution rights.
Financial Presentation
We reflect our ownership interest in PVR on a consolidated basis, which means that our financial results are combined with PVR’s financial results and the results of our other subsidiaries. The 45% limited partner interest in PVR that we do not own, after the effect of incentive distribution rights, is reflected as a minority interest in our results of operations. We have no separate operating activities apart from those conducted by PVR, and our cash flows currently consist of distributions from PVR on the partner interests, including the incentive distribution rights, that we own. Accordingly, the discussion and analysis of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects the operating activities and results of operations of PVR. The historical results of our operations for 2006 do not reflect the incremental expenses we incur as a result of being a publicly traded partnership.
Overview of PVR’s Business
PVR is a publicly traded Delaware limited partnership formed by Penn Virginia in 2001 that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States.
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Both in its current limited partnership form and in its previous corporate form, PVR has managed coal properties since 1882. PVR currently conducts operations in two business segments: (1) coal and natural resource management and (2) natural gas midstream. We consolidate PVR’s results into our financial statements. In 2007, we had an approximately 55% interest in PVR’s net income, including incentive distribution rights. Our operating income was $115.2 million in 2007, compared to $102.4 million in 2006 and $78.1 million in 2005. In 2007, the PVR coal and natural resource management segment contributed $68.8 million, or 60%, to operating income, and the PVR natural gas midstream segment contributed $48.9 million, or 42%, to operating income. Corporate operating expenses increased from $0.4 million in 2006 to $2.5 million in 2007 primarily due to a full year of operations in 2007.
The following table presents a summary of certain financial information relating to our segments:
| Coal and Natural Resource Management |
Natural Gas Midstream |
Corporate and Other |
Consolidated | ||||||||||
| (in thousands) | |||||||||||||
| For the Year Ended December 31, 2007: |
|||||||||||||
| Revenues |
$ | 111,639 | $ | 437,806 | $ | — | $ | 549,445 | |||||
| Cost of midstream gas purchased |
— | 343,293 | — | 343,293 | |||||||||
| Operating costs and expenses |
20,138 | 26,777 | 2,482 | 49,397 | |||||||||
| Depreciation, depletion and amortization |
22,690 | 18,822 | — | 41,512 | |||||||||
| Operating income |
$ | 68,811 | $ | 48,914 | $ | (2,482 | ) | $ | 115,243 | ||||
| For the Year Ended December 31, 2006: |
|||||||||||||
| Revenues |
$ | 112,981 | $ | 404,910 | $ | — | $ | 517,891 | |||||
| Cost of midstream gas purchased |
— | 334,594 | — | 334,594 | |||||||||
| Operating costs and expenses |
19,138 | 23,846 | 397 | 43,381 | |||||||||
| Depreciation, depletion and amortization |
20,399 | 17,094 | — | 37,493 | |||||||||
| Operating income |
$ | 73,444 | $ | 29,376 | $ | (397 | ) | $ | 102,423 | ||||
| For the Year Ended December 31, 2005: |
|||||||||||||
| Revenues |
$ | 95,755 | $ | 350,593 | $ | — | $ | 446,348 | |||||
| Cost of midstream gas purchased |
— | 303,912 | — | 303,912 | |||||||||
| Operating costs and expenses |
16,121 | 17,597 | — | 33,718 | |||||||||
| Depreciation, depletion and amortization |
17,890 | 12,738 | — | 30,628 | |||||||||
| Operating income |
$ | 61,744 | $ | 16,346 | $ | — | $ | 78,090 | |||||
PVR Coal and Natural Resource Management Segment
As of December 31, 2007, PVR owned or controlled approximately 818 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. As of December 31, 2007, approximately 89% of PVR’s proven and probable coal reserves were “steam” coal used primarily by electric generation utilities, and the remaining 11% were metallurgical coal used primarily by steel manufacturers. PVR enters into long-term leases with experienced, third-party mine operators, providing them the right to mine its coal reserves in exchange for royalty payments. PVR actively works with its lessees to develop efficient methods to exploit its reserves and to maximize production from its properties. PVR does not operate any mines. In 2007, PVR’s lessees produced 32.5 million tons of coal from its properties and paid PVR coal royalties revenues of $94.1 million, for an average royalty per ton of $2.89. Approximately 81% of PVR’s coal royalties revenues in 2007 and 84% of PVR’s coal royalties revenues in 2006 were derived from coal mined on its properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of PVR’s coal royalties revenues for the respective periods was derived from coal mined on its properties under leases containing fixed royalty rates that escalate annually. In 2007, five lessees accounted for 65% of PVR’s coal royalties revenues and 11% of our total consolidated revenues.
Coal royalties are impacted by several factors that PVR generally cannot control. The number of tons mined annually is determined by an operator’s mining efficiency, labor availability, geologic conditions, access to capital, ability to market coal and ability to arrange reliable transportation to the end-user. New legislation or regulations have been or may be adopted which may have a significant impact on the mining operations of PVR’s lessees or their customers’ ability to use coal and which may require PVR, its lessees or its lessee’s customers to change operations significantly or incur substantial costs. See
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Item 1A, “Risk Factors.” To a lesser extent, coal prices also impact coal royalties revenues. Generally, as coal prices change, PVR’s average royalty per ton also changes because the majority of PVR’s lessees pay royalties based on the gross sales prices of the coal mined. Most of PVR’s coal is sold by its lessees under contracts with a duration of one year or more; therefore, changes to PVR’s average royalty occur as its lessees’ contracts are renegotiated. Coal prices, especially in Central Appalachia where the majority of PVR’s coal is produced, increased significantly from the beginning of 2005 through most of 2006. The price increase during that period was primarily the result of increased electricity demand, rebuilding of inventories and decreasing coal production in Central Appalachia. In the second half of 2006 and continuing into 2007, coal prices decreased from the historically high levels experienced in the previous two and one half years, due to higher than normal coal inventories at electric utilities and milder than normal winter weather. Coal prices increased significantly in the fourth quarter of 2007 after remaining nearly stagnant since late 2006. The global markets for most types of coal remain strong. Continued demand from emerging countries and the increased consumption domestically have created a strong global picture. U.S.-produced coal enjoyed increased demand abroad during 2007 as dwindling supplies and the decline of the dollar made U.S.-exported coal more attractive. Pricing appears strong heading into 2008 primarily due to increasing global demand and supply difficulties.
PVR also earns revenues from the provision of fee-based coal preparation and loading services, from the sale of standing timber on its properties, from oil and gas royalty interests it owns and from coal transportation, or wheelage, fees.
PVR’s management continues to focus on acquisitions that increase and diversify its sources of cash flow. During 2007, PVR acquired 60 million tons of coal reserves in two acquisitions for an aggregate purchase price of approximately $52 million. In addition, in 2007, PVR acquired approximately 62,000 acres of forestland in West Virginia for a purchase price of approximately $93 million to expand its existing timber business. In 2007, PVR also acquired royalty interests in certain oil and gas leases relating to properties located in Kentucky and Virginia for a purchase price of approximately $31 million to expand its existing oil and gas royalty interest business. For a more detailed discussion of PVR’s acquisitions, see “—Acquisitions and Investments.”
PVR Natural Gas Midstream Segment
PVR owns and operates natural gas midstream assets located in Oklahoma and the panhandle of Texas. These assets include approximately 3,682 miles of natural gas gathering pipelines and three natural gas processing facilities having 160 MMcfd of total capacity. PVR’s natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines. PVR acquired its first natural gas midstream assets through the acquisition of Cantera in March 2005.
In 2007, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 67.8 Bcf, or approximately 186 MMcfd. In 2007, three of PVR’s natural gas midstream customers accounted for 53% of PVR’s natural gas midstream revenues and 42% of our total consolidated revenues.
Revenues, profitability and the future rate of growth of the PVR 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 uncertainty.
PVR continually seeks new supplies of natural gas to both offset the natural declines in production from the wells currently connected to its systems and to increase system throughput volumes. New natural gas supplies are obtained for all of PVR’s systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and contracting for natural gas that has been released from competitors’ systems. During 2007, PVR expended $38.7 million on expansion projects to allow it to capitalize on such opportunities. The expansion projects include two natural gas processing facilities with a combined 140 MMcfd of inlet gas capacity.
Acquisitions and Investments
Set forth below are brief descriptions of PVR’s significant acquisitions for the years ended December 31, 2007, 2006 and 2005.
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PVR Coal and Natural Resource Management Segment
In October 2007, PVR purchased from Penn Virginia oil and gas royalty interests associated with leases of property in eastern Kentucky and southwestern Virginia and with estimated proved reserves of 8.7 Bcfe at January 1, 2007. The purchase price was $31.0 million in cash and was funded with long-term debt under PVR’s revolving credit facility.
In September 2007, PVR acquired fee ownership of approximately 62,000 acres of forestland in northern West Virginia. The purchase price was $93.3 million in cash and was funded with long-term debt under PVR’s revolving credit facility.
In June 2007, PVR acquired a combination of fee ownership and lease rights to approximately 51 million tons of coal reserves, along with a preparation plant and coal handling facilities. The property is located on approximately 17,000 acres in western Kentucky. The purchase price was $42.0 million in cash and was funded with long-term debt under PVR’s revolving credit facility.
In May 2006, PVR acquired lease rights to approximately 69 million tons of coal reserves. The reserves are located on approximately 20,000 acres in southern West Virginia. The purchase price was $65.0 million and was funded with long-term debt under PVR’s revolving credit facility.
In July 2005, PVR acquired fee ownership of approximately 94 million tons of coal reserves. The reserves are located along the Green River in the western Kentucky portion of the Illinois Basin. The purchase price was $62.4 million in cash and the assumption of $3.3 million of deferred income and was funded with long-term debt under PVR’s revolving credit facility.
PVR Natural Gas Midstream Segment
PVR is currently constructing an 80 MMcfd gas processing plant and related pipelines (“the Crossroads System”) in east Texas. The processing plant is expected to be placed in service by April 2008. The processing plant will provide fee-based gas processing services to Penn Virginia’s oil and gas business, as well as other producers. The plant and related facilities are expected to cost approximately $22 million and are being funded with long-term debt under PVR’s revolving credit facility.
In June 2006, PVR completed the acquisition of approximately 115 miles of gathering pipelines and related compression facilities in Texas and Oklahoma. These assets are contiguous to PVR’s Beaver/Perryton System. The purchase price was $14.7 million and was funded with cash. Subsequently, PVR borrowed $14.7 million under the PVR revolving credit facility to replenish the cash used for the acquisition.
In March 2005, PVR completed its acquisition of Cantera, a natural gas midstream gas gathering and processing company with primary locations in the Mid-Continent area of Oklahoma and the panhandle of Texas. Cash paid in connection with the acquisition was $199.2 million, net of cash received and including capitalized acquisition costs, which we funded with a $110 million term loan and with long-term debt under its revolving credit facility. PVR used the proceeds from our sale of common units in a subsequent public offering in March 2005 to repay the term loan in full and to reduce outstanding indebtedness under its revolving credit facility. See Note 5 in the Notes to Consolidated Financial Statements for pro forma financial information.
Liquidity and Capital Resources
We rely exclusively on distributions from PVR to fund any cash requirements for our operations. PVR generally satisfies its working capital requirements and funds its capital expenditures and debt service obligations from cash generated from its operations and borrowings under its revolving credit facility. PVR believes that the cash generated from its operations and its borrowing capacity will be sufficient to meet its working capital requirements, anticipated capital expenditures (other than major capital improvements or acquisitions), scheduled debt payments and distribution payments. See Note 3 in the Notes to Consolidated Financial Statements for a tabular presentation of distribution thresholds. PVR’s ability to satisfy its obligations and planned expenditures will depend upon its future operating performance, which will be affected by, among other things, prevailing economic conditions in the coal industry and natural gas midstream market, some of which are beyond its control.
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Cash Flows
The following table summarizes our cash flow statements for the years ended December 31, 2007 and 2006, consolidating our segments:
| For the Year Ended December 31, 2007 |
Coal and Natural Resource Management |
Natural Gas Midstream |
Corporate and Other |
Consolidated | ||||||||||||
| (in thousands) | ||||||||||||||||
| Cash flows from operating activities: |
||||||||||||||||
| Net income (loss) contribution |
$ | 51,681 | $ | 4,942 | $ | (27,454 | ) | $ | 29,169 | |||||||
| Adjustments to reconcile net income to net cash provided by operating activities (summarized) |
22,238 | 51,206 | 25,407 | 98,851 | ||||||||||||
| Net change in operating assets and liabilities |
3,964 | (6,207 | ) | 703 | (1,540 | ) | ||||||||||
| Net cash provided by (used in) operating activities |
$ | 77,883 | $ | 49,941 | $ | (1,344 | ) | 126,480 | ||||||||
| Net cash used in investing activities |
$ | (177,101 | ) | $ | (47,081 | ) | $ | — | (224,182 | ) | ||||||
| Net cash provided by financing activities |
114,518 | |||||||||||||||
| Net increase in cash and cash equivalents |
$ | 16,816 | ||||||||||||||
| For the Year Ended December 31, 2006 |
Coal and Natural Resource Management |
Natural Gas Midstream |
Corporate and Other |
Consolidated | ||||||||||||
| (in thousands) | ||||||||||||||||
| Cash flows from operating activities: |
||||||||||||||||
| Net income (loss) contribution |
$ | 55,015 | $ | 18,913 | $ | (41,880 | ) | $ | 32,048 | |||||||
| Adjustments to reconcile net income to net cash provided by operating activities (summarized) |
22,478 | 10,878 | 42,896 | 76,252 | ||||||||||||
| Net change in operating assets and liabilities |
1,450 | (1,390 | ) | (7,677 | ) | (7,617 | ) | |||||||||
| Net cash provided by (used in) operating activities |
$ | 78,943 | $ | 28,401 | $ | (6,661 | ) | 100,683 | ||||||||
| Net cash used in investing activities |
$ | (92,692 | ) | $ | (36,984 | ) | $ | — | (129,676 | ) | ||||||
| Net cash provided by financing activities |
19,530 | |||||||||||||||
| Net decrease in cash and cash equivalents |
$ | (9,463 | ) | |||||||||||||
Cash provided by operating activities increased by $25.8 million, or 26%, from $100.7 million in 2006 to $126.5 million in 2007. The overall increase in cash provided by operating activities in 2007 compared to 2006 was primarily attributable to the increase in the PVR natural gas midstream segment’s operating income, partially offset by increased cash outflows for derivative settlements. Cash provided by operating activities increased by $6.2 million, or 7%, from $94.5 million in 2005 to $100.7 million in 2006. The overall increase in cash provided by operating activities in 2006 compared to 2005 was primarily attributable to a higher average coal royalty per ton and cash flows from PVR’s natural gas midstream business, which was acquired in March 2005, partially offset by increased cash outflows for derivative settlements.
Capital Expenditures
In 2007, PVR made aggregate capital expenditures of $225.5 million primarily for coal reserve acquisitions, a forestland acquisition, an oil and gas royalty interest acquisition and natural gas midstream gathering system expansion projects. In 2006, PVR made aggregate capital expenditures of $129.8 million primarily for coal reserve acquisitions, coal loadout facility construction projects, a natural gas midstream acquisition and natural gas midstream gathering system expansion projects. In 2005, PVR made aggregate capital expenditures of $304.9 million primarily for the acquisition of its natural gas midstream business and coal reserve acquisitions. Other investments in 2005 included a $4.1 million purchase of railcars that PVR previously leased and $4.4 million of natural gas gathering system additions. Capital expenditures comprise the primary portion of cash used in investing activities. The following table sets forth capital expenditures by segment made during the years ended December 31, 2007, 2006 and 2005:
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| Year Ended December 31, | |||||||||
| 2007 | 2006 | 2005 | |||||||
| (in thousands) | |||||||||
| Coal and natural resource management |
|||||||||
| Acquisitions (1) |
$ | 176,918 | $ | 75,182 | $ | 92,093 | |||
| Expansion capital expenditures |
85 | 15,103 | 5,657 | ||||||
| Other property and equipment expenditures |
84 | 100 | 351 | ||||||
| Total |
177,087 | 90,385 | 98,101 | ||||||
| Natural gas midstream |
|||||||||
| Acquisitions, net of cash acquired |
— | 14,626 | 199,223 | ||||||
| Expansion capital expenditures |
38,686 | 15,394 | 3,324 | ||||||
| Other property and equipment expenditures |
9,767 | 9,414 | 4,264 | ||||||
| Total |
48,453 | 39,434 | 206,811 | ||||||
| Total capital expenditures |
$ | 225,540 | $ | 129,819 | $ | 304,912 | |||
| (1) | Amount in 2007 includes an $11.5 million lease receivable associated with the acquisition of fee ownership and lease rights to coal reserves in western Kentucky. Amount in 2007 also includes $31 million of royalty interests that PVR purchased from Penn Virginia. Amount in 2006 excludes the acquisition of assets and liabilities other than property or equipment of $1.2 million. Amount in 2005 excludes $10.4 million of equity issued and $0.7 million of liabilities assumed in connection with the acquisition of coal reserves in eastern Kentucky. Amount in 2005 also excludes $3.3 million of deferred income assumed in connection with the acquisition of coal reserves in western Kentucky. |
PVR funded capital expenditures in 2007 with cash provided by operating activities and borrowings under its revolving credit facility. PVR funded capital expenditures in 2006 with cash provided by operating activities, borrowings under its revolving credit facility, proceeds from the sale of common and Class B units to us and a contribution from us to maintain our 2% general partner interest in PVR. PVR funded capital expenditures in 2005 with cash provided by operating activities, borrowings under its revolving credit facility, proceeds from its secondary public offering of common units and a contribution from us to maintain our 2% general partner interest in PVR.
PVR’s distributions to partners increased to $89.6 million in 2007 from $67.0 million in 2006 and $51.9 million in 2005 because PVR increased the quarterly distribution per unit.
PVR had $193.5 of net borrowings in 2007, comprised of net borrowings of $204.5 million under the PVR revolving credit facility and net repayments of $11.0 million under the PVR senior unsecured notes. This is compared to $37.1 million of net repayments in 2006, comprised of net repayments of $28.8 million under the PVR revolving credit facility and net repayments of $8.3 million under the PVR senior unsecured notes. Funds from the borrowings in 2007 and 2006 were primarily used for capital expenditures.
Long-Term Debt
As of December 31, 2007, we had no outstanding borrowings other than the borrowings of PVR discussed below, which are included in our consolidated financial statements.
As of December 31, 2007, PVR had outstanding borrowings of $411.7 million, consisting of $347.7 million borrowed under its revolving credit facility and $64.0 million of senior unsecured notes, or the PVR Notes. The current portion of the PVR Notes as of December 31, 2007 was $12.7 million.
PVR Revolving Credit Facility. As of December 31, 2007, PVR had $347.7 million outstanding under its unsecured $450 million revolving credit facility, or the PVR Revolver, that matures in December 2011. The PVR Revolver is available to PVR for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10 million sublimit for the issuance of letters of credit. PVR had outstanding letters of credit of $1.6 million as of December 31, 2007. At the current $450 million limit on the PVR Revolver, and given the outstanding balance of $347.7 million, net of $1.6 million of letters of credit, PVR could borrow up to $100.7 million. In 2007, PVR incurred commitment fees of $0.3 million on the unused portion of the PVR Revolver. The interest rate under the PVR Revolver fluctuates based on the ratio of PVR’s total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 0.75% if PVR selects the
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base rate borrowing option under the PVR Revolver or at a rate derived from the London Inter Bank Offering Rate, or the LIBOR, plus an applicable margin ranging from 0.75% to 1.75% if PVR selects the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under the PVR Revolver during 2007 was 6.2%.
The financial covenants under the PVR Revolver require PVR not to exceed specified debt-to-consolidated EBITDA and consolidated EBITDA-to-interest expense ratios. The PVR Revolver prohibits PVR from making distributions to its partners if any potential default, or event of default, as defined in the PVR Revolver, occurs or would result from the distributions. In addition, the PVR Revolver contains various covenants that limit, among other things, PVR’s ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of its business, acquire another company or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. As of December 31, 2007, PVR was in compliance with all of its covenants under the PVR Revolver.
PVR Senior Unsecured Notes. As of December 31, 2007, PVR owed $64.0 million under the PVR Notes. The PVR Notes bear interest at a fixed rate of 6.02% and mature in March 2013, with semi-annual principal and interest payments. The PVR Notes are equal in right of payment with all of PVR’s other unsecured indebtedness, including the PVR Revolver. The PVR Notes require PVR to obtain an annual confirmation of its credit rating, with a 1.00% increase in the interest rate payable on the PVR Notes in the event that its credit rating falls below investment grade. In March 2007, PVR’s investment grade credit rating was confirmed by Dominion Bond Rating Services. The PVR Notes contain various covenants similar to those contained in the PVR Revolver. As of December 31, 2007, PVR was in compliance with all of its covenants under the PVR Notes.
PVR Interest Rate Swaps. PVR has entered into interest rate swap agreements, or the PVR Revolver Swaps, to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver. Until March 2010, the notional amounts of the PVR Revolver Swaps total $160 million. From March 2010 to December 2011, the notional amounts of the PVR Revolver Swaps total $100 million. Until March 2010, PVR will pay a weighted average fixed rate of 4.33% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. From March 2010 to December 2011, PVR will pay a weighted average fixed rate of 4.40% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. Settlements on the PVR Revolver Swaps are recorded as interest expense. The PVR Revolver Swaps were designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings in interest expense. After considering the applicable margin of 1.25% in effect as of December 31, 2007, the total interest rate on the $160 million portion of PVR Revolver borrowings covered by the PVR Revolver Swaps was 5.58% at December 31, 2007.
Future Capital Needs and Commitments
Currently, we have no capital requirements. In the future, we may decide to facilitate PVR acquisitions by providing additional debt or equity to PVR.
Part of PVR’s strategy is to make acquisitions and other capital expenditures which increase cash available for distribution to its unitholders. PVR’s ability to make these acquisitions in the future will depend in part on the availability of debt financing and on its ability to periodically use equity financing through the issuance of new common units, which will depend on various factors, including prevailing market conditions, interest rates and its financial condition and credit rating at the time. In 2008, PVR anticipates making capital expenditures, excluding acquisitions, of approximately $23 million, including approximately $21 million for natural gas midstream system expansion projects and maintenance capital expenditures and approximately $2 million for coal services projects and other property and equipment. PVR intends to fund these capital expenditures with a combination of cash flows provided by operating activities and borrowings under the PVR Revolver. PVR makes quarterly cash distributions of its available cash, generally defined as all of its cash and cash equivalents on hand at the end of each quarter less cash reserves. PVR believes that it will continue to have adequate liquidity to fund future recurring operating and investing activities. Short-term cash requirements, such as operating expenses and quarterly distributions to PVR’s general partner and unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for asset acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under credit facilities and the issuance of additional equity and debt securities.
Contractual Obligations
We did not have any contractual obligations as of December 31, 2007. The following table summarizes PVR’s contractual obligations as of December 31, 2007:
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| Payments Due by Period | |||||||||||||||
| Total | Less than 1 Year |
1-3 Years |
4-5 Years |
Thereafter | |||||||||||
| (in thousands) | |||||||||||||||
| Revolving credit facility |
$ | 347,700 | $ | — | $ | — | $ | 347,700 | $ | — | |||||
| Senior unsecured notes |
64,400 | 12,700 | 27,500 | 19,900 | 4,300 | ||||||||||
| Asset retirement obligation |
2,028 | — | — | — | 2,028 | ||||||||||
| Interest expense |
77,901 | 24,913 | 47,384 | 5,475 | 129 | ||||||||||
| Derivatives |
43,048 | 41,733 | 1,315 | — | — | ||||||||||
| Natural gas midstream activities (1) |
40,307 | 11,838 | 10,913 | 10,202 | 7,354 | ||||||||||
| Rental commitments (2) |
7,902 | 1,810 | 3,395 | 2,697 | — | ||||||||||
| Total contractual obligations (3) |
$ | 583,286 | $ | 92,994 | $ | 90,507 | $ | 385,974 | $ | 13,811 | |||||
| (1) | Commitments for natural gas midstream activities relate to firm transportation agreements. |
| (2) | PVR’s rental commitments primarily relate to equipment and building leases and leases of coal reserve-based properties which PVR subleases, or intends to sublease, to third parties. The obligation with respect to leased properties which PVR subleases expires when the property has been mined to exhaustion or the lease has been canceled. The timing of mining by third party operators is difficult to estimate due to numerous factors. See Item 1A, “Risk Factors.” PVR believes that the future rental commitments cannot be estimated with certainty; however, based on current knowledge and historical trends, PVR believes that it will incur $0.9 million in rental commitments annually until the reserves have been exhausted. |
| (3) | Total contractual obligations do not include reimbursements to Penn Virginia. Penn Virginia is entitled to receive reimbursements of direct and indirect expenses incurred on our and PVR’s behalf until we and it are dissolved. |
Neither we nor PVR have employment agreements with executive officers and neither of us have any other employees. Our and PVR’s compensation obligations with respect to our and its executive officers can be significantly different from one year to another and are based on variables such as PVR’s performance for the given year. For a more detailed discussion on our and PVR’s executive compensation, see Item 11, “Executive Compensation.”
Off-Balance Sheet Arrangements
At December 31, 2007, neither we nor PVR had any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We are, therefore, not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships.
Results of Operations
Selected Financial Data—Consolidated
The following table sets forth a summary of certain consolidated financial data for the years ended December 31, 2007, 2006 and 2005:
| Year Ended December 31, | |||||||||
| 2007 | 2006 | 2005 | |||||||
| (in thousands, except per unit data) | |||||||||
| Revenues |
$ | 549,445 | $ | 517,891 | $ | 446,348 | |||
| Expenses |
$ | 434,202 | $ | 415,468 | $ | 368,258 | |||
| Operating income |
$ | 115,243 | $ | 102,423 | $ | 78,090 | |||
| Net income |
$ | 29,169 | $ | 32,048 | $ | 20,769 | |||
| Net income per limited partner unit, basic and diluted |
$ | 0.75 | $ | 0.98 | $ | 0.65 | |||
| Cash flows provided by operating activities |
$ | 126,480 | $ | 100,683 | $ | 94,450 | |||
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Operating income increased in 2007 compared to 2006 primarily due to a $21.8 million increase in natural gas midstream gross processing margin, a $1.4 million increase in coal services revenues and a $0.9 million increase in oil and gas royalties, partially offset by a $4.4 million increase in general and administrative expenses, a $4.1 million decrease in coal royalties revenues and a $4.0 million increase in depreciation, depletion and amortization, or DD&A, expenses. Operating income increased in 2006 compared to 2005 primarily due to a $23.4 million increase in natural gas midstream gross processing margin and a $15.4 million increase in coal royalties revenues, partially offset by a $6.9 million increase in DD&A expenses, a $4.9 million increase in operating expenses and a $4.8 million increase in general and administrative expenses.
Net income decreased in 2007 compared to 2006 primarily due to a $34.3 million increase in derivative losses, partially offset by a $12.8 million increase in operating income and a $1.5 million decrease in interest expense. Net income increased in 2006 compared to 2005 primarily due to a $24.3 million increase in operating income and a $2.8 million decrease in derivative losses, partially offset by a $4.8 million increase in interest expense.
The assets, liabilities and earnings of PVR are fully consolidated in our financial statements, with the public unitholders’ interest (45%, after the effect of incentive distribution rights, as of December 31, 2007) reflected as minority interest in our consolidated financial statements.
PVR Coal and Natural Resource Management Segment
Year Ended December 31, 2007 Compared With Year Ended December 31, 2006
The following table sets forth a summary of certain financial and other data for the PVR coal and natural resource management segment and the percentage change for the years ended December 31, 2007 and 2006:
| Year Ended December 31, | % Change |
||||||||
| 2007 | 2006 | ||||||||
| (in thousands, except as noted) | |||||||||
| Financial Highlights |
|||||||||
| Revenues |
|||||||||
| Coal royalties |
$ | 94,140 | $ | 98,163 | (4 | )% | |||
| Coal services |
7,252 | 5,864 | 24 | % | |||||
| Timber |
1,711 | 1,024 | 67 | % | |||||
| Oil and gas royalty |
1,864 | 957 | 95 | % | |||||
| Other |
6,672 | 6,973 | (4 | )% | |||||
| Total revenues |
111,639 | 112,981 | (1 | )% | |||||
| Expenses |
|||||||||
| Coal royalties |
5,540 | 6,927 | (20 | )% | |||||
| Other operating |
2,531 | 1,673 | 51 | % | |||||
| Taxes other than income |
1,110 | 934 | 19 | % | |||||
| General and administrative |
10,957 | 9,604 | 14 | % | |||||
| Depreciation, depletion and amortization |
22,690 | 20,399 | 11 | % | |||||
| Total expenses |
42,828 | 39,537 | 8 | % | |||||
| Operating income |
$ | 68,811 | $ | 73,444 | (6 | )% | |||
| Operating Statistics |
|||||||||
| Royalty coal tons produced by lessees (tons in thousands) |
32,528 | 32,778 | (1 | )% | |||||
| Average royalty per ton ($/ton) |
$ | 2.89 | $ | 2.99 | (3 | )% | |||
Revenues. Coal royalties revenues decreased by $4.1 million, or 4%, from $98.2 million in 2006 to $94.1 million in 2007 primarily due to a lower average royalty per ton. Tons produced by PVR’s lessees remained relatively constant from 2006 to 2007. The mix of production in 2007 shifted from 2006, with higher lessee production in the Illinois Basin and the San Juan Basin, which have lower average royalties per ton, partially offset by lower lessee production in Central Appalachia, which has higher average royalties per ton. Primarily due to the combination of increased production in
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the relatively lower average royalty rate Illinois Basin and reduced production in Central Appalachia, PVR’s average royalty per ton decreased by $0.10, or 3%, from $2.99 in 2006 to $2.89 in 2007.
The following table summarizes coal production and coal royalties revenues by property for the years ended December 31, 2007 and 2006:
| Coal Production | Coal Royalties Revenues | |||||||||
| Year Ended December 31, | Year Ended December 31, | |||||||||
| Region |
2007 | 2006 | 2007 | 2006 | ||||||
| (tons in thousands) | (in thousands) | |||||||||
| Central Appalachia |
18,827 | 20,156 | $ | 68,815 | $ | 76,542 | ||||
| Northern Appalachia |
4,194 | 5,009 | 6,434 | 7,314 | ||||||
| Illinois Basin |
3,779 | 2,540 | 7,432 | 4,768 | ||||||
| San Juan Basin |
5,728 | 5,073 | 11,459 | 9,539 | ||||||
| Total |
32,528 | 32,778 | $ | 94,140 | $ | 98,163 | ||||
Coal services revenues increased by $1.4 million, or 24%, from $5.9 million in 2006 to $7.3 million in 2007 primarily due to the completed construction of a coal services facility in Knott County, Kentucky, which began operations in October 2006. Timber revenues increased by $0.7 million, or 67%, from $1.0 million in 2006 to $1.7 million in 2007 primarily due to the increased harvesting resulting from PVR’s September 2007 forestland acquisition. Oil and gas royalty revenues increased by $0.9 million, or 95%, from $1.0 million in 2006 to $1.9 million in 2007 primarily due to the increased royalties resulting from PVR’s October 2007 oil and gas royalty interest acquisition. Other revenues, which consisted primarily of wheelage fees, forfeiture income and management fee income, remained relatively constant from 2006 to 2007.
Expenses. Coal royalties expense decreased by $1.4 million, or 20%, from $6.9 million in 2006 to $5.5 million in 2007 primarily due to a decrease in production from properties PVR subleases in Central Appalachia. Other operating expenses increased by $0.8 million, or 51%, from $1.7 million in 2006 to $2.5 million in 2007 primarily due to an increase in mine maintenance and core-hole drilling expenses on PVR’s Central Appalachian and Illinois Basin properties. General and administrative expenses increased by $1.4 million, or 14%, from $9.6 million in 2006 to $11.0 million in 2007 primarily due to increased staffing costs. DD&A expenses increased by $2.3 million, or 11%, from $20.4 million in 2006 to $22.7 million in 2007 primarily due to increased depletion resulting from PVR’s forestland acquisition in September 2007 and PVR’s oil and gas royalty interest acquisition in October 2007. In addition, PVR began depreciating its coal services facility in Knott County, Kentucky, which began operations in October 2006.
Year Ended December 31, 2006 Compared With Year Ended December 31, 2005
The following table sets forth a summary of certain financial and other data for the PVR coal and natural resource management segment and the percentage change for the years ended December 31, 2006 and 2005:
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| Year Ended December 31, | |||||||||
| 2006 | 2005 | % Change | |||||||
| (in thousands, except as noted) | |||||||||
| Financial Highlights |
|||||||||
| Revenues |
|||||||||
| Coal royalties |
$ | 98,163 | $ | 82,725 | 19 | % | |||
| Coal services |
5,864 | 5,230 | 12 | % | |||||
| Timber |
1,024 | 776 | 32 | % | |||||
| Oil and gas royalty |
957 | 1,444 | (34 | )% | |||||
| Other |
6,973 | 5,580 | 25 | % | |||||
| Total revenues |
112,981 | 95,755 | 18 | % | |||||
| Expenses |
|||||||||
| Coal royalties |
6,927 | 4,151 | 67 | % | |||||
| Other operating |
1,673 | 1,604 | 4 | % | |||||
| Taxes other than income |
934 | 1,129 | (17 | )% | |||||
| General and administrative |
9,604 | 9,237 | 4 | % | |||||
| Depreciation, depletion and amortization |
20,399 | 17,890 | 14 | % | |||||
| Total expenses |
39,537 | 34,011 | 16 | % | |||||
| Operating income |
$ | 73,444 | $ | 61,744 | 19 | % | |||
| Operating Statistics |
|||||||||
| Royalty coal tons produced by lessees (tons in thousands) |
32,778 | 30,227 | 8 | % | |||||
| Average royalty per ton ($/ton) |
$ | 2.99 | $ | 2.74 | 9 | % | |||
Revenues. Coal royalties revenues increased by $15.5 million, or 19%, from $82.7 million in 2005 to $98.2 million in 2006 primarily due to a higher average royalty per ton and increased production. Tons produced by PVR’s lessees increased by 2.6 million tons, or 8%, from 30.2 million tons in 2005 to 32.8 million tons in 2006, and PVR’s average royalty per ton increased $0.25, or 9%, from $2.74 in 2005 to $2.99 in 2006. Coal production by PVR’s lessees increased primarily due to the addition of production from the Illinois Basin reserves PVR acquired in July 2005 and increased production on PVR’s Central Appalachian property due to additional property PVR acquired in May 2006. The average royalty per ton increased primarily due to a greater percentage of coal being produced from certain price-sensitive leases and, for most of 2006, stronger market conditions for coal resulting in higher prices.
The following table summarizes coal production and coal royalties revenues by property for the years ended December 31, 2006 and 2005:
| Coal Production | Coal Royalties Revenues | |||||||||
| Year Ended December 31, | Year Ended December 31, | |||||||||
| Region |
2006 | 2005 | 2006 | 2005 | ||||||
| (tons in thousands) | (in thousands) | |||||||||
| Central Appalachia |
20,156 | 18,996 | $ | 76,542 | $ | 64,645 | ||||
| Northern Appalachia |
5,009 | 4,958 | 7,314 | 6,973 | ||||||
| Illinois Basin |
2,540 | 1,449 | 4,768 | 2,709 | ||||||
| San Juan Basin |
5,073 | 4,824 | 9,539 | 8,398 | ||||||
| Total |
32,778 | 30,227 | $ | 98,163 | $ | 82,725 | ||||
Coal services revenues increased by $0.7 million, or 12%, from $5.2 million in 2005 to $5.9 million in 2006 primarily due to increased equity earnings from PVR’s coal handling joint venture and increased revenues from coal handling facilities that processed higher volumes. PVR’s facility on its Central Appalachian property began operations in October 2006 and contributed $0.2 million to coal services revenues in 2006. Timber revenues increased by $0.2 million, or 32%, from $0.8 million in 2005 to $1.0 million in 2006 primarily due to an increase in forestland cutting in 2006. Cutting in 2005 was lower than in 2006 due to weather conditions. Oil and gas royalty revenues decreased by $0.4 million, or 34%, from $1.4 million in 2005 to $1.0 million in 2006 primarily due to a decrease in production and pricing. Other revenues increased by $1.4 million, or 25%, from $5.6 million in 2005 to $7.0 million in 2006 primarily due to a $0.9 million increase in revenues for the
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management of certain coal properties, a $1.1 million increase in forfeiture income due to timing of lease terms, a $0.4 million increase in railcar rental income related to railcars PVR purchased in June 2005 and a $0.6 million increase in wheelage fees primarily as a result of PVR’s April 2005 coal reserve acquisition, partially offset the $1.5 million PVR received in 2005 from the sale of a bankruptcy claim filed against a former lessee in 2004 for lost future rents.
Expenses. Coal royalties expense increased by $2.7 million, or 67%, from $4.2 million in 2005 to $6.9 million in 2006 primarily due to production on PVR’s subleased Central Appalachian property acquired in May 2006. This increase was partially offset by a decrease in production from other subleased properties primarily resulting from the movement of longwall mining operations at one of these properties. Fluctuations in production on subleased properties have a direct impact on coal royalties expense. Other operating expenses increased by $0.1 million, or 4%, from $1.6 million in 2005 to $1.7 million in 2006 primarily due to an increase in core-hole drilling expenses. General and administrative expenses increased by $0.4 million, or 4%, from $9.2 million in 2005 to $9.6 million in 2006 primarily due to absorbing operations related to PVR’s 2005 and 2006 acquisitions, increased professional fees and payroll costs relating to evaluating acquisition opportunities and increased reimbursement to PVR’s general partner for shared corporate overhead costs. DD&A expenses increased by $2.5 million, or 14%, from $17.9 million in 2005 to $20.4 million in 2006 primarily due to the increase in production and a higher depletion rate on recently acquired reserves.
PVR Natural Gas Midstream Segment
Year Ended December 31, 2007 Compared With Year Ended December 31, 2006
The following table sets forth a summary of certain financial and other data for the PVR natural gas midstream segment and the percentage change for the years ended December 31, 2007 and 2006:
| Year Ended December 31, | |||||||||
| 2007 | 2006 | % Change | |||||||
| (in thousands, except as noted) | |||||||||
| Financial Highlights |
|||||||||
| Revenues |
|||||||||
| Residue gas |
$ | 242,129 | $ | 259,764 | (7 | )% | |||
| Natural gas liquids |
172,144 | 130,675 | 32 | % | |||||
| Condensate |
13,889 | 9,989 | 39 | % | |||||
| Gathering and transportation fees |
5,012 | 2,287 | 119 | % | |||||
| Total natural gas midstream revenues |
433,174 | 402,715 | 8 | % | |||||
| Producer services |
4,632 | 2,195 | 111 | % | |||||
| Total revenues |
437,806 | 404,910 | 8 | % | |||||
| Expenses |
|||||||||
| Cost of midstream gas purchased |
343,293 | 334,594 | 3 | % | |||||
| Operating |
12,893 | 11,403 | 13 | % | |||||
| Taxes other than income |
1,926 | 1,420 | 36 | % | |||||
| General and administrative |
11,958 | 11,023 | 8 | % | |||||
| Depreciation and amortization |
18,822 | 17,094 | 10 | % | |||||
| Total operating expenses |
388,892 | 375,534 | 4 | % | |||||
| Operating income |
$ | 48,914 | $ | 29,376 | 67 | % | |||
| Operating Statistics |
|||||||||
| System throughput volumes (MMcf) |
67,810 | 61,995 | 9 | % | |||||
| Gross processing margin |
$ | 89,881 | $ | 68,121 | 32 | % | |||
Gross Processing Margin. PVR’s gross processing margin is the difference between its natural gas midstream revenues and its cost of midstream gas purchased. Natural gas midstream revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to PVR’s gas processing plants. Cost of
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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.
Natural gas midstream revenues increased by $30.5 million, or 8%, from $402.7 million in 2006 to $433.2 million in 2007. Cost of midstream gas purchased increased by $8.7 million, or 3%, from $334.6 million in 2006 to $343.3 million in 2007. PVR’s gross processing margin increased by $21.8 million, or 32%, from $68.1 million in 2006 to $89.9 million in 2007. The gross processing margin increase was a result of higher fractionation or “frac” spread, which is the difference between the NGLs sold and the cost of natural gas purchased on a per MMbtu basis, during 2007 and higher volumes of processed gas. Processed gas is the portion of the system throughput volumes that is actually processed at a processing facility. The increase in processed gas was attributed to the success in contracting and connecting new supply to PVR’s facilities. Much of this new gas is a result of continued successful development by the producers operating in the vicinity of PVR’s systems. Additionally, the pipeline PVR acquired in 2006 allowed PVR to connect a number of gathering systems directly to the PVR Beaver plant, bring its utilization of processing capacity to 100%. Gathering and transportation revenues benefited from a short-term gathering contract that was entered into and completed during the third quarter of 2007. These gathered volumes contributed to PVR’s overall system throughput increase, but did not result in a corresponding increase in throughput volumes at PVR’s processing plants because the volumes were delivered off of the gathering system prior to reaching the processing facility. System throughput volumes at PVR’s gas processing plants and gathering systems increased by 16 MMcfd, or 9%, from 170 MMcfd in 2006 to 186 MMcfd in 2007.
During 2007, PVR generated a majority of its gross processing margin from contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and NGLs. See Item 1, “Business—PVR’s Contracts—PVR Natural Gas Midstream Segment,” for a discussion of the types of contracts utilized by the PVR natural gas midstream segment. As part of PVR’s risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased. The following table shows a summary of the effects of derivative activities on PVR’s gross processing margin for the years ended December 31, 2007 and 2006:
| Year Ended December 31, |
||||||||
| 2007 | 2006 | |||||||
| (in thousands) | ||||||||
| Gross processing margin, as reported |
$ | 89,881 | $ | 68,121 | ||||
| Derivatives expenses included in gross processing margin |
4,595 | 1,953 | ||||||
| Gross processing margin before impact of derivatives |
94,476 | 70,074 | ||||||
| Cash settlements on derivatives |
(17,779 | ) | (19,436 | ) | ||||
| Gross processing margin, adjusted for derivatives |
$ | 76,697 | $ | 50,638 | ||||
Producer Services Revenues. Producer services revenues increased by $2.4 million, or 111%, from $2.2 million in 2006 to $4.6 million in 2007 primarily due to an increase in collected agent fees for the marketing of Penn Virginia’s natural gas production.
Expenses. Total operating costs and expenses remained relatively constant in 2007 compared to 2006.
Operating expenses increased by $1.5 million, or 13%, from $11.4 million in 2006 to $12.9 million in 2007 primarily due to a full year of operations in 2007 on the pipeline PVR acquired in 2006 and increased compressor rentals. General and administrative expenses increased by $0.9 million, or 8%, from $11.0 million in 2006 to $11.9 million in 2007 primarily due to increased staffing costs. Taxes other than income increased by $0.5 million, or 36%, from $1.4 million in 2006 to $1.9 million in 2007. Depreciation and amortization expenses increased by $1.7 million, or 10%, from $17.1 million in 2006 to $18.8 million in 2007. Increases in both taxes other than income and depreciation and amortization expenses were primarily due to capital spending on organic growth and acquisition opportunities occurring in both 2006 and 2007.
Year Ended December 31, 2006 Compared With Year Ended December 31, 2005
PVR began operating its natural gas midstream segment on March 3, 2005 with the acquisition of Cantera’s natural gas midstream business. The results of operations of the PVR natural gas midstream segment since that date are discussed below.
The following table sets forth a summary of certain financial and other data for the PVR natural gas midstream segment and the percentage change for the years ended December 31, 2006 and 2005:
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| Year Ended December 31, | |||||||||
| 2006 | 2005 (1) | % Change | |||||||
| (in thousands, except as noted) | |||||||||
| Financial Highlights |
|||||||||
| Revenues |
|||||||||
| Residue gas |
$ | 259,764 | $ | 233,208 | 11 | % | |||
| Natural gas liquids |
130,675 | 106,453 | 23 | % | |||||
| Condensate |
9,989 | 7,322 | 36 | % | |||||
| Gathering and transportation fees |
2,287 | 1,674 | 37 | % | |||||
| Total natural gas midstream revenues |
402,715 | 348,657 | 16 | % | |||||
| Producer services |
2,195 | 1,936 | 13 | % | |||||
| Total revenues |
404,910 | 350,593 | 15 | % | |||||
| Expenses |
|||||||||
| Cost of midstream gas purchased |
334,594 | 303,912 | 10 | % | |||||
| Operating |
11,403 | 9,347 | 22 | % | |||||
| Taxes other than income |
1,420 | 1,268 | 12 | % | |||||
| General and administrative |
11,023 | 6,982 | 58 | % | |||||
| Depreciation and amortization |
17,094 | 12,738 | 34 | % | |||||
| Total operating expenses |
375,534 | 334,247 | 12 | % | |||||
| Operating income |
$ | 29,376 | $ | 16,346 | 80 | % | |||
| Operating Statistics |
|||||||||
| System throughput volumes (MMcf) |
61,995 | 43,729 | 42 | % | |||||
| Gross processing margin |
$ | 68,121 | $ | 44,745 | 52 | % | |||
| (1) | Represents the results of operations of the PVR natural gas midstream segment since March 3, 2005, the closing date of the acquisition of Cantera. |
The financial and other data presented in the table above for 2005 include ten months of operations of PVR’s natural gas midstream business. One of the primary reasons for the significant differences in PVR’s results of operations for 2006 as compared to 2005 is that the 2006 data includes 12 full months of operations of PVR’s natural gas midstream business.
Gross Processing Margin. Natural gas midstream revenues increased by $54.0 million, or 16%, from $348.7 million in 2005 to $402.7 million in 2006. Cost of midstream gas purchased increased by $30.7 million, or 10%, from $303.9 million in 2005 to $334.6 million in 2006. Cost of midstream gas purchased included a $4.6 million non-cash charge to reserves for amounts related to balances assumed as part of the acquisition of Cantera. PVR’s gross processing margin increased by $23.4 million, or 52%, from $44.7 million in 2005 to $68.1 million in 2006 primarily due to an additional two months of operations in 2006, higher average NGL and condensate prices and the overall increase in system throughput volumes in 2006 over 2005. System throughput volumes at PVR’s gas processing plants and gathering systems increased by 27 MMcfd, or 19%, from 143 MMcfd in 2005 to 170 MMcfd in 2006.
During 2006, PVR generated a majority of its gross processing margin from contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and NGLs. See Item 1, “Business—PVR’s Contracts—PVR Natural Gas Midstream Segment,” for a discussion of the types of contracts utilized by the PVR natural gas midstream segment. As part of PVR’s risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased. The following table shows a summary of the effects of derivative activities on PVR’s gross processing margin for the years ended December 31, 2006 and 2005:
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| Year Ended December 31, | ||||||||
| 2006 | 2005 | |||||||
| (in thousands) | ||||||||
| Gross processing margin, as reported |
$ | 68,121 | $ | 44,745 | ||||
| Derivatives expenses included in gross processing margin |
1,953 | (988 | ) | |||||
| Gross processing margin before impact of derivatives |
70,074 | 43,757 | ||||||
| Cash settlements on derivatives |
(19,436 | ) | (4,752 | ) | ||||
| Gross processing margin, adjusted for derivatives |
$ | 50,638 | $ | 39,005 | ||||
Producer Services Revenues. Producer services revenues remained relatively constant from 2006 to 2007.
Expenses. Operating costs and expenses increased due to an additional two months of activity in 2006 related to the PVR natural gas midstream segment that were not present in 2005, as well as due to increases in cost of midstream gas purchased, operating expenses, taxes other than income, general and administrative expenses and depreciation and amortization expenses.
Operating expenses increased by $2.1 million, or 22%, from $9.3 million in 2005 to $11.4 million in 2006 primarily due to rent and maintenance costs associated with additional compressors. General and administrative expenses increased by $4.0 million, or 58%, from $7.0 million in 2005 to $11.0 million in 2006 primarily due to additional personnel added to support the business and recent acquisitions and increased reimbursement to PVR’s general partner for shared corporate overhead costs from $0.8 million in 2005 to $2.4 million in 2006. Depreciation and amortization expenses increased by $4.4 million, or 34%, from $12.7 million in 2005 to $17.1 million in 2006 primarily due to depreciation on the pipeline acquired in June 2006 and recent gathering system expansions.
Corporate and Other
Our corporate and other results consist of corporate operating expenses, interest expense, derivative gains and losses and minority interest.
Corporate Operating Expenses. Corporate operating expenses primarily consist of general and administrative expenses other than from the PVR coal and natural resource management and PVR natural gas midstream segments. Corporate operating expenses increased by $2.1 million, or 525%, from $0.4 million in 2006 to $2.5 million in 2007 primarily due to a full year of operations in 2007.
Interest Expense. Interest expense decreased by $1.5 million, or 8%, from $18.8 million in 2006 to $17.3 million in 2007 primarily due to PVR making a $114.6 million principal payment on the PVR Revolver in December 2006. Interest expense increased by $4.7 million, or 33%, from $14.1 million in 2005 to $18.8 million in 2006 primarily due to interest incurred on additional borrowings under the PVR Revolver to finance the acquisition of Cantera, the June 2006 pipeline acquisition and coal property acquisitions in 2005 and 2006 and a general increase in interest rates. PVR capitalized interest costs amounting to $0.8 million in 2007 related to the construction of natural gas processing plants. PVR capitalized interest costs amounting to $0.3 million in 2006 related to the construction of a coal services facility in October 2006. PVR had no capitalized interest in 2005.
Derivatives. Derivative losses increased by $34.3 million, or 304%, from $11.3 million in 2006 to $45.6 million in 2007. The derivative losses in 2007 consisted of a $27.8 million unrealized loss for mark-to-market adjustments and a $17.8 realized loss. Derivative losses decreased by $2.7 million, or 19%, from $14.0 million in 2005 to $11.3 million in 2006. The derivative losses in 2006 consisted of a $11.2 unrealized loss for mark-to-market adjustments and a $0.1 million realized loss.
Minority Interest. Minority interest represents net income allocated to the limited partner units owned by the public. In 2007 and 2006, minority interest reduced our consolidated income from operations by $25.4 million and $42.7 million. The decrease in minority interest was primarily due to the decrease in PVR’s net income from $73.9 million in 2006 to $56.6 million in 2007. The decrease in minority interest was also due to an increase in distributions we receive on account of our incentive distribution rights, or IDRs, in PVR. PVR paid to us distributions with respect to our IDRs of $11.6 million and $4.3 million in 2007 and 2006.
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Summary of Critical Accounting Policies and Estimates
The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. We consider the following to be the most critical accounting policies which involve the judgment of our management.
Natural Gas Midstream Revenues
We recognize revenues from the sale of NGLs and residue gas when PVR sells the NGLs and residue gas produced at its gas processing plants. We recognize gathering and transportation revenues based upon actual volumes delivered. Due to the time needed to gather information from various purchasers and measurement locations and then calculate volumes delivered, the collection of natural gas midstream revenues may take up to 30 days following the month of production. Therefore, we make accruals for revenues and accounts receivable and the related cost of midstream gas purchased and accounts payable based on estimates of natural gas purchased and NGLs and residue gas sold. We record any differences, which we do not expect to be significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized.
Coal Royalties Revenues
We recognize coal royalties revenues on the basis of tons of coal sold by PVR’s lessees and the corresponding revenues from those sales. Since PVR does not operate any coal mines, it does not have access to actual production and revenues information until approximately 30 days following the month of production. Therefore, our financial results include estimated revenues and accounts receivable for the month of production. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized.
Derivative Activities
PVR historically has entered into derivative financial instruments that would qualify for hedge accounting under Statement of Financial Accounting Standards, or SFAS, No. 133, Accounting for Derivative Instruments and Hedging Activities. Hedge accounting affects the timing of revenue recognition and cost of midstream gas purchased in our consolidated statements of income, as a majority of the gain or loss from a contract qualifying as a cash flow hedge is deferred until the hedged transaction settles. Because during the first quarter of 2006 PVR’s natural gas derivatives and a large portion of PVR’s NGL derivatives no longer qualified for hedge accounting and to increase clarity in its consolidated financial statements, PVR elected to discontinue hedge accounting prospectively for its remaining and future commodity derivatives beginning May 1, 2006. Consequently, from that date forward, PVR began recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (partners’ capital). Because PVR no longer uses hedge accounting for its commodity derivatives, we have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to swings in the value of these contracts. These fluctuations could be significant in a volatile pricing environment.
The net mark-to-market loss on PVR’s outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in future earnings through 2008 as the original hedged transactions settle. PVR will recognize hedging losses of $5.5 million in 2008 related to such settlements. The discontinuation of hedge accounting has no impact on our reported cash flows, although PVR’s results of operations are affected by the potential volatility of mark-to-market gains and losses, which fluctuate with changes in NGL, crude oil and natural gas prices.
Depletion
PVR depletes coal properties on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by PVR’s own geologists and coal reserve engineers. PVR’s estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. PVR depletes timber on an area-by-area basis at a rate based upon the quantity of timber sold. PVR determines depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves.
Goodwill
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Under SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets, goodwill recorded in connection with a business combination is not amortized, but tested for impairment at least annually. Accordingly, we do not amortize goodwill. We test goodwill for impairment during the fourth quarter of each fiscal year. Based on the results of our test during the fourth quarter of 2007, no goodwill impairment was recognized in 2007.
Intangible Assets
Intangible assets are primarily associated with assumed contracts, customer relationships and rights-of-way. These intangible assets are amortized over periods of up to 15 years, the period in which benefits are derived from the contracts, relationships and rights-of-way, and are reviewed for impairment under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.
Environmental Matters
PVR’s operations and those of its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of PVR’s coal property leases impose liability for all environmental and reclamation liabilities arising under those laws and regulations on the relevant lessees. The lessees are bonded and have indemnified PVR against any and all future environmental liabilities. PVR regularly visits its coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. PVR’s management believes that its operations and those of its lessees comply with existing laws and regulations and does not expect any material impact on its financial condition or results of operations.
As of December 31, 2007 and 2006, PVR’s environmental liabilities included $1.5 million and $1.6 million, which represents PVR’s best estimate of the liabilities as of those dates related to its coal and natural resource management and natural gas midstream businesses. PVR has reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future. For a summary of the environmental laws and regulations applicable to PVR’s operations, see Item 1, “Business—Government Regulation and Environmental Matters.”
Recent Accounting Pronouncements
See Note 4 in the Notes to Consolidated Financial Statements for a description of recent accounting pronouncements.
Forward-Looking Statements
Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the risks set forth in Item 1A, “Risk Factors.”
Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC. 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.
| Item 7A | Quantitative and Qualitative Disclosures About Market Risk |
Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which PVR is exposed are NGL, crude oil, natural gas and coal price risks and interest rate risk.
PVR is also indirectly exposed to the credit risk of its customers and lessees. If its customers or lessees become financially insolvent, they may not be able to continue to operate or meet their payment obligations.
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Price Risk Management
PVR’s price risk management program permits the utilization of derivative financial instruments (such as futures, forwards, option contracts and swaps) to seek to mitigate the price risks associated with fluctuations in natural gas, NGL and crude oil prices as they relate to PVR’s natural gas midstream business. The derivative financial instruments are placed with major financial institutions that PVR believes are of minimum credit risk. The fair values of PVR’s price risk management activities are significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.
For the year ended December 31, 2007, PVR reported a net derivative loss of $45.6 million. Because during the first quarter of 2006 PVR’s natural gas derivatives and a large portion of PVR’s NGL derivatives no longer qualified for hedge accounting and to increase clarity in its consolidated financial statements, PVR elected to discontinue hedge accounting prospectively for its remaining and future commodity derivatives beginning May 1, 2006. Consequently, from that date forward, PVR began recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (partners’ capital). The net mark-to-market loss on PVR’s outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in future earnings through 2008 as the original hedged transactions settle. PVR will recognize hedging losses of $5.5 million in 2008 related to such settlements. The discontinuation of hedge accounting has no impact on our reported cash flows, although our results of operations are affected by the potential volatility of mark-to-market gains and losses, which fluctuate with changes in NGL, crude oil and natural gas prices. See the discussion and tables in Note 10 in the Notes to Consolidated Financial Statements for a description of PVR’s derivatives program.
The following table lists PVR’s open mark-to-market derivative agreements and their fair values as of December 31, 2007:
| Average Volume Per Day |
Weighted Average Price |
Weighted Average Price |
Estimated Fair Value |
||||||||||||
| Collars | |||||||||||||||
| Floor | Ceiling | ||||||||||||||
| (in thousands) | |||||||||||||||
| Frac Spreads |
(in MMbtu) | (per MMbtu) | |||||||||||||
| First quarter 2008 through fourth quarter 2008 |
7,824 | $ | 5.02 | $ | (11,599 | ) | |||||||||
| Ethane Sale Swaps |
(in gallons) | (per gallon) | |||||||||||||
| First quarter 2008 through fourth quarter 2008 |
34,440 | $ | 0.4700 | (6,279 | ) | ||||||||||
| Propane Sale Swaps |
(in gallons) | (per gallon) | |||||||||||||
| First quarter 2008 through fourth quarter 2008 |
26,040 | $ | 0.7175 | (7,372 | ) | ||||||||||
| Crude Oil Sale Swaps |
(in barrels) | (per barrel) | |||||||||||||
| First quarter 2008 through fourth quarter 2008 |
560 | $ | 49.27 | (8,788 | ) | ||||||||||
| Natural Gasoline Collars |
(in gallons) | (per gallon) | |||||||||||||
| First quarter 2008 through fourth quarter 2008 |
6,300 | $ | 1.4800 | $ | 1.6465 | (953 | ) | ||||||||
| Crude Oil Collars |
(in barrels) | (per barrel) | |||||||||||||
| First quarter 2008 through fourth quarter 2008 |
400 | $ | 65.00 | $ | 75.25 | (2,669 | ) | ||||||||
| Natural Gas Purchase Swaps |
(in MMbtu) | (per MMbtu) | |||||||||||||
| First quarter 2008 through fourth quarter 2008 |
4,000 | $ | 6.97 | 1,205 | |||||||||||
| Settlements to be paid in subsequent period |
(3,469 | ) | |||||||||||||
| Natural gas midstream segment commodity derivatives – net liability |
$ | (39,924 | ) | ||||||||||||
We estimate that excluding the derivative positions described above, for every $1.00 per MMbtu decrease or increase in natural gas prices from the $7.50 per MMbtu budgeted 2008 benchmark price, natural gas midstream gross processing margin and operating income in 2008 would increase or decrease by approximately $12.0 million. This assumes oil and other liquids prices and inlet volumes remain constant at budgeted levels. In addition, we also estimate that excluding the derivative positions described above, for every $5.00 per barrel increase or decrease in the oil prices from the $80.00 per barrel budgeted 2008 benchmark price, natural gas midstream gross processing margin and operating income would increase
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or decrease by approximately $10.8 million. This assumes natural gas prices and inlet volumes remain constant at budgeted levels. These estimated changes in gross processing margin and operating income exclude the potential cash receipts or payments in settling these derivative positions.
Interest Rate Risk
As of December 31, 2007, PVR had $347.7 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. PVR entered into the PVR Revolver Swaps to effectively convert the interest rate on $160 million of the amount outstanding under the PVR Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 4.33% plus the applicable margin until March 2010. From March 2010 to December 2011, the PVR Revolver Swaps will effectively convert the interest rate on $100 million of the amount outstanding under the PVR Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 4.40% plus the applicable margin. The interest rate swaps are accounted for as cash flow hedges in accordance with SFAS No. 133. A 1% increase in short-term interest rates on the floating rate debt outstanding under the PVR Revolver (net of amounts fixed through hedging transactions) at December 31, 2007 would cost PVR approximately $1.9 million in additional interest expense.
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| Item 8 | Financial Statements and Supplementary Data |
PENN VIRGINIA GP HOLDINGS, L.P. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| Page | ||
| 67 | ||
| 68 | ||
| 69 |
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
Penn Virginia GP Holdings, L.P.:
We have audited the accompanying consolidated balance sheets of Penn Virginia GP Holdings, L.P., a Delaware limited partnership, and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2007. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Penn Virginia GP Holdings, L.P. and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 15 to the consolidated financial statements, effective January 1, 2006, the Partnership’s changed its method of accounting for unit-based payments.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Penn Virginia GP Holdings, L.P.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2008 expressed an unqualified opinion on the effectiveness of internal control over financial reporting.
KPMG LLP
| Houston, Texas |
| February 28, 2008 |
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
Penn Virginia GP Holdings L.P.:
We have audited Penn Virginia GP Holdings, L.P.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Penn Virginia GP Holdings, L.P.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting (Item 9A(b) herein). Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Penn Virginia GP Holdings, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Penn Virginia GP Holdings, L.P. as of December 31, 2007 and 2006, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2007, and our report dated February 28, 2008, expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Houston, Texas
February 28, 2008
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PENN VIRGINIA GP HOLDINGS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per unit amounts)
| Year Ended December 31, | ||||||||||||
| 2007 | 2006 | 2005 | ||||||||||
| Revenues |
||||||||||||
| Natural gas midstream |
$ | 433,174 | $ | 402,715 | $ | 348,657 | ||||||
| Coal royalties |
94,140 | 98,163 | 82,725 | |||||||||
| Coal services |
7,252 | 5,864 | 5,230 | |||||||||
| Other |
14,879 | 11,149 | 9,736 | |||||||||
| Total revenues |
549,445 | 517,891 | 446,348 | |||||||||
| Expenses |
||||||||||||
| Cost of midstream gas purchased |
343,293 | 334,594 | 303,912 | |||||||||
| Operating |
20,964 | 20,003 | 15,102 | |||||||||
| Taxes other than income |
3,040 | 2,354 | 2,397 | |||||||||
| General and administrative |
25,393 | 21,024 | 16,219 | |||||||||
| Depreciation, depletion and amortization |
41,512 | 37,493 | 30,628 | |||||||||
| Total expenses |
434,202 | 415,468 | 368,258 | |||||||||
| Operating income |
115,243 | 102,423 | 78,090 | |||||||||
| Other income (expense) |
||||||||||||
| Interest expense |
(17,338 | ) | (18,821 | ) | (14,057 | ) | ||||||
| Interest income |
2,239 | 2,359 | 1,149 | |||||||||
| Derivatives |
(45,568 | ) | (11,260 | ) | (14,024 | ) | ||||||
| Income from operations before minority interest |
54,576 | 74,701 | 51,158 | |||||||||
| Minority interest |
(25,407 | ) | (42,653 | ) | (30,389 | ) | ||||||
| Net income |
$ | 29,169 | $ | 32,048 | $ | 20,769 | ||||||
| Basic and diluted net income per limited partner unit |
$ | 0.75 | $ | 0.98 | $ | 0.65 | ||||||
| Weighted average number of units outstanding: |
||||||||||||
| Basic: |
39,071 | 32,700 | 32,125 | |||||||||
See accompanying notes to consolidated financial statements.
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PENN VIRGINIA GP HOLDINGS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit amounts)
| As of December 31, | ||||||||
| 2007 | 2006 | |||||||
| Assets |
||||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 30,503 | $ | 13,687 | ||||
| Accounts receivable |
78,888 | 66,987 | ||||||
| Derivative assets |
1,212 | 449 | ||||||
| Other current assets |
4,104 | 2,587 | ||||||
| Total current assets |
114,707 | 83,710 | ||||||
| Property, plant and equipment |
877,571 | 665,135 | ||||||
| Accumulated depreciation, depletion and amortization |
(146,289 | ) | (108,622 | ) | ||||
| Net property, plant and equipment |
731,282 | 556,513 | ||||||
| Equity investments |
25,640 | 25,355 | ||||||
| Goodwill |
7,718 | 7,718 | ||||||
| Intangibles, net |
28,938 | 33,045 | ||||||
| Derivative assets |
— | 2,455 | ||||||
| Other long-term assets |
33,966 | 7,473 | ||||||
| Total assets |
$ | 942,251 | $ | 716,269 | ||||
| Liabilities and Partners’ Capital |
||||||||
| Current liabilities |
||||||||
| Accounts payable |
$ | 65,763 | $ | 51,931 | ||||
| Accrued liabilities |
10,903 | 11,409 | ||||||
| Current portion of long-term debt |
12,561 | 10,832 | ||||||
| Deferred income |
2,958 | 6,999 | ||||||
| Derivative liabilities |
41,733 | 6,996 | ||||||
| Total current liabilities |
133,918 | 88,167 | ||||||
| Deferred income |
6,889 | 6,592 | ||||||
| Other liabilities |
19,517 | 3,339 | ||||||
| Derivative liabilities |
1,315 | 6,618 | ||||||
| Long-term debt |
399,153 | 207,214 | ||||||
| Commitments and contingencies (see Note 16) |
||||||||
| Minority interests of subsidiary |
161,075 | 330,148 | ||||||
| Partners’ capital |
||||||||
| Common units (39,074,500 units outstanding at |
||||||||
| December 31, 2007 and 39,025,000 at December 31, 2006) |
77,317 | 82,842 | ||||||
| Accumulated other comprehensive loss |
(7,392 | ) | (8,651 | ) | ||||
| Gain on sale of subsidiary units (see Note 6) |
150,459 | — | ||||||
| Total partners’ capital |
220,384 | 74,191 | ||||||
| Total liabilities and partners’ capital |
$ | 942,251 | $ | 716,269 | ||||
See accompanying notes to consolidated financial statements.
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PENN VIRGINIA GP HOLDINGS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| Year Ended December 31, | ||||||||||||
| 2007 | 2006 | 2005 | ||||||||||
| Cash flows from operating activities |
||||||||||||
| Net income |
$ | 29,169 | $ | 32,048 | $ | 20,769 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
| Depreciation, depletion and amortization |
41,512 | 37,493 | 30,628 | |||||||||
| Commodity derivative contracts: |
||||||||||||
| Total derivative losses (gains) |
50,163 | 13,213 | 12,188 | |||||||||
| Cash settlements on derivatives |
(17,779 | ) | (19,439 | ) | (4,752 | ) | ||||||
| Minority interest |
25,407 | 42,653 | 30,389 | |||||||||
| Non-cash interest expense |
678 | 769 | 1,735 | |||||||||
| Equity earnings, net of distributions received |
(285 | ) | 1,317 | 1,269 | ||||||||
| Other |
(845 | ) | 246 | 2,468 | ||||||||
| Changes in operating assets and liabilities |
||||||||||||
| Accounts receivable |
(11,901 | ) | (914 | ) | (27,326 | ) | ||||||
| Other current assets |
15 | 558 | 1,532 | |||||||||
| Accounts payable |
13,791 | (3,323 | ) | 16,398 | ||||||||
| Accrued liabilities |
(2,228 | ) | (2,333 | ) | 6,981 | |||||||
| Deferred income |
(1,799 | ) | (1,676 | ) | 2,063 | |||||||
| Other assets and liabilities |
582 | 71 | 108 | |||||||||
| Net cash provided by operating activities |
126,480 | 100,683 | 94,450 | |||||||||
| Cash flows from investing activities |
||||||||||||
| Acquisitions, net of cash acquired |
(176,917 | ) | (91,259 | ) | (290,938 | ) | ||||||
| Additions to property, plant and equipment |
(48,123 | ) | (38,453 | ) | (12,735 | ) | ||||||
| Other |
858 | 36 | 52 | |||||||||
| Net cash used in investing activities |
(224,182 | ) | (129,676 | ) | (303,621 | ) | ||||||
| Cash flows from financing activities |
||||||||||||
| Distributions to minority interest holders of PVR |
(44,022 | ) | (38,387 | ) | (30,571 | ) | ||||||
| Distributions to affiliates |
(35,557 | ) | (22,426 | ) | (21,894 | ) | ||||||
| Proceeds from borrowings |
220,500 | 85,800 | 288,800 | |||||||||
| Repayments of borrowings |
(27,000 | ) | (122,900 | ) | (151,600 | ) | ||||||
| Proceeds from PVR’s issuance of units |
916 | 119,408 | 129,026 | |||||||||
| Payment of offering costs |
(56 | ) | (1,590 | ) | — | |||||||
| Payments for debt issuance costs |
(263 | ) | (375 | ) | (2,385 | ) | ||||||
| Net cash provided by (used in) financing activities |
114,518 | 19,530 | 211,376 | |||||||||
| Net increase (decrease) in cash and cash equivalents |
16,816 | (9,463 | ) | 2,205 | ||||||||
| Cash and cash equivalents – beginning of period |
13,687 | 23,150 | 20,945 | |||||||||
| Cash and cash equivalents – end of period |
$ | 30,503 | $ | 13,687 | $ | 23,150 | ||||||
| Supplemental disclosure: |
||||||||||||
| Cash paid for interest |
$ | 15,880 | $ | 18,312 | $ | 12,138 | ||||||
| Noncash investing and financing activities: |
||||||||||||
| Issuance of PVR units for acquisitions |
$ | — | $ | — | $ | 10,415 | ||||||
| Assumption of liabilities in acquisitions |
$ | — | $ | — | $ | 3,981 | ||||||
See accompanying notes to consolidated financial statements.
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PENN VIRGINIA GP HOLDINGS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL AND COMPREHENSIVE INCOME
(in thousands)
| Common Units | Accumulated Other Comprehensive Income (Loss) |
Unearned Compensation |
Gain on sale of subsidiary units |
Total | Comprehensive Income (Loss) |
||||||||||||||||||||
| Balance at December 31, 2004 |
— | $ | (37,648 | ) | $ | — | $ | (874 | ) | $ | — | $ | (38,522 | ) | $ | 15,289 | |||||||||
| Capital contributions |
— | 3,222 | — | — | — | 3,222 | |||||||||||||||||||
| Distributions to affiliates |
— | (22,545 | ) | — | — | — | (22,545 | ) | |||||||||||||||||
| PVR units held for compensation, net |
— | 2,557 | — | (426 | ) | — | 2,131 | ||||||||||||||||||
| Net income |
— | 20,769 | — | — | — | 20,769 | $ | 20,769 | |||||||||||||||||
| Other comprehensive loss |
— | — | (4,891 | ) | — | — | (4,891 | ) | (4,891 | ) | |||||||||||||||
| Balance at December 31, 2005 |
— | $ | (33,645 | ) | $ | (4,891 | ) | $ | (1,300 | ) | $ | — | $ | (39,836 | ) | $ | 15,878 | ||||||||
| Adoption of SFAS No. 123(R) |
— | (1,300 | ) | — | 1,300 | — | — | ||||||||||||||||||
| Distributions to affiliates |
— | (22,426 | ) | — | — | — | (22,426 | ) | |||||||||||||||||
| PVR units held for compensation, net |
— | 157 | — | — | — | 157 | |||||||||||||||||||
| Gain on sale of subsidiary units |
— | (1,160 | ) | — | — | — | (1,160 | ) | |||||||||||||||||
| Distribution of net assets to Penn Virginia |
— | (13,868 | ) | — | — | — | (13,868 | ) | |||||||||||||||||
| Issuance of units to Penn Virginia |
32,125 | 5,218 | — | — | — | 5,218 | |||||||||||||||||||
| Issuance of units to the public, net of offering and other costs |
6,900 | 117,818 | — | — | — | 117,818 | |||||||||||||||||||
| Net income |
— | 32,048 | — | — | — | 32,048 | 32,048 | ||||||||||||||||||
| Other comprehensive loss |
— | — | (3,760 | ) | — | — | (3,760 | ) | (3,760 | ) | |||||||||||||||
| Balance at December 31, 2006 |
39,025 | $ | 82,842 | $ | (8,651 | ) | $ | — | $ | — | $ | 74,191 | $ | 28,288 | |||||||||||
| Issuance of units |
50 | 860 | — | — | — | 860 | |||||||||||||||||||
| Gain on sale of subsidiary units |
— | — | — | — | 150,459 | 150,459 | |||||||||||||||||||
| Distributions paid ($0.91 per unit) |
— | (35,554 | ) | — | — | — | (35,554 | ) | |||||||||||||||||
| Net income |
— | 29,169 | — | — | — | 29,169 | 29,169 | ||||||||||||||||||
| Other comprehensive income |
— | — | 1,259 | — | — | 1,259 | 1,259 | ||||||||||||||||||
| Balance at December 31, 2007 |
39,075 | $ | 77,317 | $ | (7,392 | ) | $ | — | $ | 150,459 | $ | 220,384 | $ | 30,428 | |||||||||||
See accompanying notes to consolidated financial statements.
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PENN VIRGINIA GP HOLDINGS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| 1. | Organization |
Penn Virginia GP Holdings, L.P. (the “Partnership,” “we,” “us” or “our”) is a publicly traded Delaware limited partnership formed in June 2006 that currently owns three types of equity interests in Penn Virginia Resource Partners, L.P. (“PVR”), a publicly traded Delaware limited partnership. Our only cash generating assets consist of our partner interests in PVR. Due to our control of the general partner of PVR, the financial results of PVR are included in our condensed consolidated financial statements. However, PVR functions with a capital structure that is independent of ours, consisting of its own debt instruments and publicly traded common units.
Our general partner is an indirect wholly-owned subsidiary of Penn Virginia Corporation (“Penn Virginia”). Penn Virginia and its subsidiaries own an approximately 82% limited partner interest in us. We own 100% of Penn Virginia Resource GP, LLC, a Delaware limited liability company and the general partner of PVR. We completed our initial public offering in December 2006, selling approximately 18% of our outstanding common units to the public and using the proceeds from the offering to purchase 416,444 newly issued common units and 4,045,311 newly issued Class B units from PVR. As of December 31, 2007, we owned approximately 44% of PVR, consisting of a 2% general partner interest and an approximately 42% limited partner interest. As part of our ownership of PVR’s general partner, we also own the rights, referred to as “incentive distribution rights,” to receive an increasing percentage of PVR’s quarterly distributions of available cash from operating surplus after certain levels of cash distributions have been achieved.
| 2. | Business of Penn Virginia Resource Partners, L.P. |
Penn Virginia Resource Partners, L.P. is a publicly traded Delaware limited partnership formed by Penn Virginia in 2001 that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. PVR currently conducts operations in two business segments: (1) coal and natural resource management and (2) natural gas midstream.
The PVR coal and natural resource management segment primarily involves the management and leasing of coal and natural resource properties and the subsequent collection of royalties. PVR also earns revenues from the provision of fee-based coal preparation and loading services, from the sale of standing timber on its properties, from oil and gas royalty interests it owns and from coal transportation, or wheelage, fees.
The PVR natural gas midstream segment is engaged in providing gas processing, gathering and other related natural gas services. PVR owns and operates natural gas midstream assets located in Oklahoma and the panhandle of Texas. PVR’s natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.
We, through our ownership of the general partner of PVR, manage the operations and activities of PVR. Most of PVR’s personnel are employees of Penn Virginia or its affiliates. PVR’s general partner is liable for all of PVR’s debts (to the extent not paid from PVR’s assets), except for indebtedness or other obligations that are made specifically non-recourse to us.
We do not receive any management fee or other compensation for the management of PVR. We and our affiliates are reimbursed for expenses incurred on PVR’s behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to PVR and all other expenses necessary or appropriate to conduct the business of, and allocable to, PVR. PVR’s partnership agreement provides that PVR’s general partner will determine the expenses that are allocable to PVR in any reasonable manner determined by PVR in its sole discretion.
| 3. | Unit Ownership Interests in Penn Virginia Resource Partners, L.P. |
PVR makes quarterly cash distributions of its available cash, generally defined as all of PVR’s cash and cash equivalents on hand at the end of each quarter less cash reserves established by the general partner at its sole discretion. According to PVR’s partnership agreement, PVR’s general partner receives incremental incentive cash distributions if cash distributions exceed certain target thresholds as follows:
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| Unitholders | General Partner |
|||||
| Quarterly cash distribution per unit: |
||||||
| First target—up to $0.275 per unit |
98 | % | 2 | % | ||
| Second target—above $0.275 per unit up to $0.325 per unit |
85 | % | 15 | % | ||
| Third target—above $0.325 per unit up to $0.375 per unit |
75 | % | 25 | % | ||
| Thereafter—above $0.375 per unit |
50 | % | 50 | % |
The following table reflects the allocation of total cash distributions paid by PVR during the years ended December 31, 2007, 2006 and 2005:
| Year Ended December 31, | |||||||||
| 2007 | 2006 | 2005 | |||||||
| (in thousand, except per unit data) | |||||||||
| Limited partner units |
$ | 76,536 | $ | 61,427 | $ | 50,018 | |||
| General partner interest (2%) |
1,562 | 1,254 | 1,021 | ||||||
| Incentive distribution rights |
11,551 | 4,273 | 910 | ||||||
| Total cash distributions paid |
$ | 89,649 | $ | 66,954 | $ | 51,949 | |||
| Total cash distributions paid per unit |
$ | 1.6660 | $ | 1.4750 | $ | 1.2413 | |||
On February 14, 2008, PVR paid a $0.44 per unit quarterly distribution ($1.76 per unit on an annualized basis) to unitholders of record on February 4, 2007.
We received total distributions from PVR of $45.6 million, allocated among our limited partner interest, general partner interest and incentive distribution rights in PVR as shown in the following table:
| Year Ended December 31, 2007 | |||
| (in thousands) | |||
| Limited partner units |
$ | 32,515 | |
| General partner interest (2%) |
1,562 | ||
| Incentive distribution rights |
11,551 | ||
| Total |
$ | 45,628 | |
| 4. | Summary of Significant Accounting Policies |
Basis of Presentation
Unless otherwise indicated, for the purposes of our consolidated financial statements, the “Partnership,” “we,” “us” or “our” refers to Penn Virginia GP Holdings, L.P. and subsidiaries. References to the “parent company” are intended to mean Penn Virginia GP Holdings, L.P. individually as the parent company and not on a consolidated basis.
In accordance with generally accepted accounting principles, the distribution of net assets from the parent company to affiliates of Penn Virginia in December 2006 was accounted for as a reorganization of entities under common control in a manner similar to a pooling of interests. As a result, our historical consolidated financial information presented in this Annual Report on Form 10-K for periods prior to our receipt of contributions from Penn Virginia has been presented using the consolidated financial information of Penn Virginia Resource GP, LLC and subsidiaries, which was our predecessor company.
The presentation of such predecessor consolidated financial information assumes that the historical ownership interests in PVR held by affiliates of Penn Virginia (prior to the contribution of net assets in December 2006) were owned by the parent company. This method of presentation is substantially on the same basis that our consolidated results of operations and financial position have been presented since the contribution of net assets from affiliates of Penn Virginia.
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Our consolidated financial statements include the accounts of the Partnership, all of its wholly-owned subsidiaries and PVR, of which we indirectly owned the sole 2% general partner interest and an approximately 42% limited partner interest as of December 31, 2007. Penn Virginia Resource GP, LLC, our wholly-owned subsidiary, serves as PVR’s general partner and controls PVR. Intercompany balances and transactions have been eliminated in consolidation. Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and Securities and Exchange Commission regulations. These statements involve the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our consolidated financial statements have been included. Certain reclassifications have been made to conform to the current year’s presentation.
Use of Estimates
Preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents
We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Property, Plant and Equipment
Property, plant and equipment consist of PVR’s ownership in coal fee mineral interests, PVR’s royalty interest in oil and natural gas wells, forestlands, processing facilities, gathering systems, compressor stations and related equipment. Property, plant and equipment are carried at cost and include expenditures for additions and improvements, such as roads and land improvements, which increase the productive lives of existing assets. Maintenance and repair costs are expensed as incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. We compute depreciation and amortization of property, plant and equipment using the straight-line method over the estimated useful life of each asset as follows:
| Useful Life | ||
| Gathering systems |
15 years | |
| Compressor stations |
5-15 years | |
| Processing plants |
15 years | |
| Other property and equipment |
3-20 years |
We deplete coal properties on an area-by-area basis at a rate based upon the cost of the mineral properties and estimated proven and probable tonnage therein. From time to time, PVR carries out core-hole drilling activities on its coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling activities are expensed as incurred. We deplete timber on an area-by-area basis at a rate based upon the quantity of timber sold. We deplete oil and gas properties on a unit-of-production basis over the remaining life of the reserves. When PVR retires or sells an asset, we remove its cost and related accumulated depreciation and amortization from our consolidated balance sheets. We record the difference between the net book value (net of any related asset retirement obligation) and proceeds from disposition as gain or loss.
Asset Retirement Obligations
In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, we recognize the fair value of a liability for an asset retirement obligation (an “ARO”) in the period in which it is incurred. The determination of fair value is based upon regional market and facility type information. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. See Note 11, “Asset Retirement Obligations.” The amount of an ARO and the costs capitalized equal the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using an assumed cost of funds for us. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds, and the additional capitalized costs are depreciated over the productive life of the assets. Both the accretion and the depreciation are included in depreciation,
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depletion and amortization expense on our consolidated statements of income. In connection with PVR’s natural gas midstream assets, we are obligated under federal regulations to perform limited procedures around the abandonment of pipelines. We are unable to reasonably determine the fair value of such AROs because the settlement dates, or ranges thereof, are indeterminable. An ARO will be recorded in the periods wherein we can reasonably determine the settlement dates.
Impairment of Long-Lived Assets
We review long-lived assets to be held and used whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. We recognize an impairment loss when the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flows. In this circumstance, we recognize an impairment loss equal to the difference between the carrying value and the fair value of the asset. Fair value is estimated to be the present value of future net cash flows from the asset, discounted utilizing a rate commensurate with the risk and remaining life of the asset.
Equity Investments
We use the equity method of accounting to account for PVR’s investment in a coal handling joint venture, recording PVR’s initial investment at cost. Subsequently, the carrying amount of the investment is increased to reflect PVR’s share of income of the investee and is reduced to reflect PVR’s share of losses of the investee or distributions received from the investee as the joint venture reports them. PVR’s share of earnings or losses from the investment is included in coal services revenues on our consolidated statements of income. Coal services revenues also includes amortization of the amount of PVR’s equity investment that exceeds its portion of the underlying equity in net assets. We record amortization over the life of coal services contracts in place at the time of PVR’s initial investment.
Goodwill
We had approximately $7.7 million of goodwill at December 31, 2007 and 2006 based upon the purchase price allocation for the Cantera Acquisition (as defined in Note 5). The goodwill has been allocated to the PVR natural gas midstream segment. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, goodwill is assessed at least annually for impairment. We tested goodwill for impairment during the fourth quarter of 2007 and determined that no impairment charge was necessary.
Intangible Assets
Intangible assets at December 31, 2007 and 2006 included $37.7 million for customer contracts and relationships and $4.6 million for rights-of-way acquired in the Cantera Acquisition (see Note 5). Customer contracts and relationships are amortized on a straight-line basis over the expected useful lives of the individual contracts and relationships, up to 15 years. Rights-of-way are amortized on a straight-line basis over a period of 15 years. Total intangible amortization expense for the years ended December 31, 2007, 2006 and 2005 was approximately $4.1 million, $5.0 million and $4.2 million. As of December 31, 2007, accumulated amortization of intangible assets was $13.3 million. The following table sets forth our estimated aggregate amortization expense for the next five years and thereafter:
| Year |
Amortization Expense | ||
| (in thousands) | |||
| 2008 |
$ | 3,485 | |
| 2009 |
3,219 | ||
| 2010 |
3,006 | ||
| 2011 |
2,764 | ||
| 2012 |
2,515 | ||
| Thereafter |
13,949 | ||
| Total |
$ | 28,938 | |
Debt Issuance Costs
Debt issuance costs relating to long-term debt have been capitalized and are being amortized over the term of the related debt instrument.
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Long-Term Prepaid Minimums
PVR leases a portion of its reserves from third parties which require monthly or annual minimum rental payments. The prepaid minimums are recoupable from future production and are deferred and charged to coal royalties expense as the coal is subsequently produced. PVR evaluates the recoverability of the prepaid minimums on a periodic basis; consequently, any prepaid minimums that cannot be recouped are charged to coal royalties expense.
Environmental Liabilities
Other liabilities include accruals for environmental liabilities that PVR either assumed in connection with certain acquisitions or recorded in operating expenses when it became probable that a liability had been incurred and the amount of that liability could be reasonably estimated.
Concentration of Credit Risk
Approximately 88% of our consolidated accounts receivable at December 31, 2007 resulted from the PVR natural gas midstream segment and approximately 12% resulted from the PVR coal and natural resource management segment. Approximately 24% of our consolidated accounts receivable at December 31, 2007 related to one of PVR’s natural gas midstream customers. These concentrations may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a lessee or customer, PVR analyzes the entity’s net worth, cash flows, earnings and credit ratings to the extent information is available. Receivables are generally not collateralized. Historical credit losses incurred on receivables have not been significant.
Fair Value of Financial Instruments
Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivative instruments, a capital lease and long-term debt. The carrying values of all of these financial instruments, except fixed rate long-term debt, approximate fair value. The fair value of fixed rate long-term debt at December 31, 2007 and 2006 was $65.8 million and $75.4 million.
Revenues
Natural Gas Midstream Revenues. We recognize revenues from the sale of natural gas liquids (“NGLs”) and residue gas when PVR sells the NGLs and residue gas produced at its gas processing plants. We recognize gathering and transportation revenues based upon actual volumes delivered. Due to the time needed to gather information from various purchasers and measurement locations and then calculate volumes delivered, the collection of natural gas midstream revenues may take up to 30 days following the month of production. Therefore, we make accruals for revenues and accounts receivable and the related cost of midstream gas purchased and accounts payable based on estimates of natural gas purchased and NGLs and residue gas sold. We record any differences, which have not historically been significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized.
Coal Royalties Revenues and Deferred Income. We recognize coal royalties revenues on the basis of tons of coal sold by PVR’s lessees and the corresponding revenues from those sales. Since PVR does not operate any coal mines, it does not have access to actual production and revenues information until approximately 30 days following the month of production. Therefore, our financial results include estimated revenues and accounts receivable for the month of production. We record any differences, which we do not expect to be significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. Most of PVR’s lessees must make minimum monthly or annual payments that are generally recoupable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recoups a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of income. Deferred income also includes unearned income from a coal services facility lease, which is recognized as interest income as it is earned.
Coal Services Revenues. We recognize coal services revenues when lessees use PVR’s facilities for the processing, loading and/or transportation of coal. Coal services revenues consist of fees collected from lessees for the use of PVR’s loadout facility, coal preparation plants and dock loading facility. We also include equity earnings in coal services revenues.
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PVR recognizes its share of income or losses from its investment in a coal handling joint venture as the joint venture reports them to PVR.
Timber Revenues. PVR recognizes timber revenues based on the volume of timber harvested and sold from our properties.
Derivative Activities
From time to time, PVR enters into derivative financial instruments to mitigate its exposure to NGL, crude oil and natural gas price volatility. The derivative financial instruments, which are placed with major financial institutions that PVR believes are minimum credit risks, take the form of costless collars and swaps. All derivative financial instruments are recognized in our consolidated financial statements at fair value in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. The fair values of PVR’s derivative instruments are determined based on third party price quotes. All derivative transactions are subject to PVR’s risk management policy, which has been reviewed and approved by the board of directors of PVR’s general partner.
PVR historically has entered into derivative financial instruments that would qualify for hedge accounting under SFAS No. 133. Hedge accounting affects the timing of revenue recognition and cost of midstream gas purchased in our consolidated statements of income, as a majority of the gain or loss from a contract qualifying as a cash flow hedge is deferred until the hedged transaction settles. Because during the first quarter of 2006 PVR’s natural gas derivatives and a large portion of PVR’s NGL derivatives no longer qualified for hedge accounting and to increase clarity in its consolidated financial statements, PVR elected to discontinue hedge accounting prospectively for its remaining and future commodity derivatives beginning May 1, 2006. Consequently, from that date forward, PVR began recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (partners’ capital).
The net mark-to-market loss on PVR’s outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in future earnings through 2008 as the original hedged transactions settle. See Note 10, “Derivative Instruments.” The discontinuation of hedge accounting has no impact on our reported cash flows, although PVR’s results of operations are affected by the potential volatility of mark-to-market gains and losses, which fluctuate with changes in NGL, crude oil and natural gas prices.
Income Taxes
As a partnership, we are not a taxable entity and have no federal income tax liability. Penn Virginia Resource GP, LLC is a limited liability company which is treated as a partnership for federal income tax purposes. Therefore, Penn Virginia Resource GP, LLC is not a taxable entity and generally incurs no federal income tax liability. PVR is a partnership and is also not a taxable entity and has no federal income tax liability. The taxable income or losses of the Partnership and PVR are includable in the federal and state income tax returns of their partners. Net income for financial statement purposes may differ significantly from taxable income reportable to partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under our and PVR’s partnership agreements.
Net Income per Limited Partner Unit
Basic and diluted net income per limited partner unit is determined by dividing net income by the weighted average number of outstanding common units. At December 31, 2007, there were no dilutive units.
The consolidated financial information presented for periods prior to December 2006 is based on the consolidated financial information of the parent company’s predecessor, Penn Virginia Resource GP, LLC. Our net income per limited partner unit amounts for periods prior to our initial public offering in December 2006 assume that affiliates of Penn Virginia owned 32,125,000 limited partner units during those periods.
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Unit-Based Compensation
Our general partner has a long-term incentive plan that permits the grant of awards to directors and employees of our general partner and employees of its affiliates who perform services for us. Awards under our long-term incentive plan can be in the form of common units, restricted units, unit options, phantom units and deferred common units. Our long-term incentive plan is administered by the compensation and benefits committee of our general partner’s board of directors. We reimburse our general partner for payments made pursuant to our long-term incentive plan and recognize the associated compensation expense over the vesting period of the awards.
The general partner of PVR has a long-term incentive plan that permits the grant of awards to directors and employees of PVR’s general partner and employees of its affiliates who perform services for PVR. Awards under the PVR long-term incentive plan can be in the form of PVR common units, restricted PVR units, PVR unit options, phantom PVR units and deferred PVR common units. The PVR long-term incentive plan is administered by the compensation and benefits committee of the board of directors of PVR’s general partner. PVR reimburses its general partner for payments made pursuant to the PVR long-term incentive plan.
New Accounting Standards
In September 2006, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 157, Fair Value Measurements, which provides enhanced guidance for using fair value to measure assets and liabilities. SFAS No.157 requires us to evaluate the fair value of our assets and liabilities according to a specified fair value hierarchy and present additional disclosures. SFAS No. 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value. SFAS No. 157 does not expand the use of fair value in any new circumstances. SFAS No. 157 is to be applied prospectively, except for in certain situations, none of which apply to us. We adopted SFAS No. 157 as of January 1, 2008 and are currently in the process of determining the effects of adoption, such as the effect of incorporating our own credit standing in the measurement of certain liabilities. We do not expect that the final effects of adoption will have a significant impact on our consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115, which provides companies with an option to report selected financial assets and liabilities at fair value. The objective of SFAS No. 159 is to reduce both the complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of an entity’s first fiscal year beginning after November 15, 2007. We adopted SFAS 159 as of January 1, 2008. The adoption of SFAS No. 159 had no effect on our consolidated financial position or results of operations.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS No.141(R)”). SFAS No. 141(R) provides companies with principles and requirements on how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree as well as the recognition and measurement of goodwill acquired or a gain from a bargain purchase in a business combination. SFAS No. 141(R) also requires certain disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination. Acquisition costs associated with the business combination will generally be expensed as incurred. In addition, changes in an acquired entity’s valuation allowance for deferred tax assets and uncertain tax positions after the measurement period will impact income tax expense. SFAS No. 141(R) is effective for business combinations occurring in fiscal years beginning after December 15, 2008. Early adoption of SFAS No. 141(R) is not permitted. We are currently assessing the impact SFAS No. 141(R) will have on our process of analyzing business combinations.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51, which mandates that a noncontrolling (minority) interest shall be reported in the consolidated statement of financial position within equity, separately from the parent company’s equity. This statement amends ARB No. 51 and clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity. SFAS No. 160 also requires consolidated net income to include amounts attributable to both parent and noncontrolling interest and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS No. 160 is effective for fiscal years and interim periods beginning after December 15, 2008. We are currently assessing the impact on our consolidated financial statements of adopting SFAS No. 160 effective January 1, 2009.
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| 5. | Acquisitions |
In the following paragraphs, all references to coal, crude oil and natural gas reserves and acreage acquired are unaudited. The factors we used to determine the fair market value of acquisitions include, but are not limited to, discounted future net cash flows on a risked-adjusted basis, geographic location, quality of resources, potential marketability and financial condition of lessees.
Business Acquisitions
On March 3, 2005, PVR completed its acquisition (the “Cantera Acquisition”) of Cantera Gas Resources, LLC (“Cantera”), a natural gas midstream gas gathering and processing company with primary locations in Oklahoma and Texas. The results of operations of PVR Midstream LLC since March 3, 2005, the closing date of the Cantera Acquisition, are included in our consolidated statements of income.
Cash paid in connection with the Cantera Acquisition was $199.2 million, net of cash received and including capitalized acquisition costs, which PVR funded with a $110 million term loan and with long-term debt under PVR’s revolving credit facility. PVR used proceeds of $126.4 million from its sale of common units in a subsequent public offering in March 2005 and a $2.6 million contribution from its general partner to repay the term loan in full and to reduce outstanding indebtedness under its revolving credit facility. The total purchase price was allocated to the assets purchased and the liabilities assumed in the Cantera Acquisition based upon the fair values on the date of acquisition as follows (in thousands):
| Cash consideration paid for Cantera |
$ | 201,326 | ||
| Plus: Acquisition costs |
3,275 | |||
| Total purchase price |
204,601 | |||
| Less: Cash acquired |
(5,378 | ) | ||
| Total purchase price, net of cash acquired |
$ | 199,223 | ||
| Current assets acquired |
$ | 43,697 | ||
| Property and equipment acquired |
145,448 | |||
| Other assets acquired |
645 | |||
| Liabilities assumed |
(38,337 | ) | ||
| Intangible assets |
40,052 | |||
| Goodwill |
7,718 | |||
| Total purchase price, net of cash acquired |
$ | 199,223 | ||
The purchase price allocation includes approximately $7.7 million of goodwill. The significant factors that contributed to the recognition of goodwill include PVR’s entry into the natural gas midstream business and its ability to acquire an established business with an assembled workforce.
Under SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets, goodwill recorded in connection with a business combination is not amortized, but rather is tested for impairment at least annually. Accordingly, the unaudited pro forma financial information presented below does not include amortization of the goodwill recorded in the Cantera Acquisition. The purchase price allocation also includes $40.1 million of intangible assets that are primarily associated with assumed customer contracts, customer relationships and rights-of-way. These intangible assets are being amortized over periods of up to 15 years, the period in which benefits are derived from the acquired contracts, relationships and rights-of-way, and are reviewed for impairment under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.
The following unaudited pro forma financial information reflects our consolidated results of operations as if the Cantera Acquisition and related debt and equity financings had occurred on January 1, 2005. The pro forma information includes adjustments primarily for depreciation of acquired property and equipment, amortization of intangible assets, interest expense for acquisition debt and the change in weighted average common units resulting from the public offering. The pro forma financial information is not necessarily indicative of the results of operations as it would have been had these transactions been effected on the assumed date.
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| Year Ended December 31, 2005 | |||
| (unaudited) | |||
| (in thousands, except per unit data) | |||
| Revenues |
$ | 518,790 | |
| Net income |
$ | 21,717 | |
| Net income per limited partner unit, basic and diluted |
$ | 0.68 | |
In September 2007, PVR acquired fee ownership of approximately 62,000 acres of forestland in northern West Virginia. The purchase price was $93.3 million in cash and was funded with long-term debt under PVR’s revolving credit facility. The purchase price has been preliminarily allocated as follows: $5.9 million to land and $87.4 million to timber. The purchase price allocation is preliminary. PVR is awaiting final appraisals of an assumed contract and additional analysis on the fair value of the land and timber.
In June 2007, PVR acquired a combination of fee ownership and lease rights to approximately 51 million tons of coal reserves, along with a preparation plant and coal handling facilities. The property is located on approximately 17,000 acres in western Kentucky. The purchase price was $42.0 million in cash and was funded with long-term debt under PVR’s revolving credit facility. The purchase price allocation has been allocated as follows: $30.0 million to coal properties, $0.5 million to land, $28.1 million to a lease receivable and $16.6 million to deferred rent relating to a coal services facility lease.
The pro forma results for the years ended December 31, 2006 and 2005 for the northern West Virginia timber and western Kentucky coal acquisitions do not materially change the net income for these periods.
Other Acquisitions
In October 2007, PVR purchased from Penn Virginia oil and gas royalty interests associated with leases of property in eastern Kentucky and southwestern Virginia and with estimated proved reserves of 8.7 billion cubic feet of natural gas equivalent at January 1, 2007. The purchase price was $31.0 million in cash and was funded with long-term debt under the PVR revolving credit facility.
In June 2006, PVR completed the acquisition of approximately 115 miles of gathering pipelines and related compression facilities in Texas and Oklahoma. These assets are contiguous to PVR’s Beaver/Perryton System. The purchase price was $14.7 million and was funded with cash. Subsequently, PVR borrowed $14.7 million under its revolving credit facility to replenish the cash used for the acquisition.
In May 2006, PVR acquired lease rights to approximately 69 million tons of coal reserves. The reserves are located on approximately 20,000 acres in southern West Virginia. The purchase price was $65.0 million and was funded with long-term debt under PVR’s revolving credit facility.
In July 2005, PVR acquired fee ownership of approximately 94 million tons of coal reserves. The reserves are located along the Green River in the western Kentucky portion of the Illinois Basin. The purchase price was $62.4 million in cash and the assumption of $3.3 million of deferred income and was funded with long-term debt under PVR’s revolving credit facility.
| 6. | Gain on Sale of Subsidiary Units |
We accounted for the PVR IPO and each subsequent PVR equity issuance as a sale of a minority interest. For each PVR equity issuance, we calculated a gain under SEC Staff Accounting Bulletin No. 51 (or Topic 5-H), Accounting for Sales of Stock by a Subsidiary (“SAB 51”). Because the PVR common units had preference over the PVR subordinated units with respect to distributions, the gain was not recognized at the time of each PVR equity issuance. This gain was to be recognized in partners’ capital when all of the subordinated units converted to common units. By November 2006, all of the subordinated units had converted to common units. However, because the issuance of the PVR Class B units, which were subordinate to the PVR common units with respect to distributions, was contemplated at the time the final PVR subordinated units converted to PVR common units in November 2006, we did not recognize the SAB 51 gain at the time. After the conversion of the Class B units to common units on a one-for-one basis in May 2007, PVR no longer had any form of junior securities outstanding. Accordingly, at that time, we recognized a $150.5 million gain in partners’ capital related to PVR equity issuances from the time of the PVR IPO in October 2001 to May 2007. SAB 51 gains will be recognized with respect
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to future PVR equity issuances at the time of the equity issuances as long PVR does not have any junior securities outstanding and is not contemplating the issuance of junior securities.
| 7. | Property and Equipment |
The following table summarizes our property and equipment as of December 31, 2007 and 2006:
| As of December 31, | ||||||||
| 2007 | 2006 | |||||||
| (in thousands) | ||||||||
| Coal properties |
$ | 453,484 | $ | 414,935 | ||||
| Compressor stations |
49,693 | 49,071 | ||||||
| Gathering systems |
159,652 | 121,467 | ||||||
| Coal services equipment |
38,840 | 38,755 | ||||||
| Processing plants |
28,695 | 19,273 | ||||||
| Land |
17,753 | 11,291 | ||||||
| Oil and gas royalties |
36,395 | 5,395 | ||||||
| Timber |
87,800 | 399 | ||||||
| Other property and equipment |
5,259 | 4,549 | ||||||
| 877,571 | 665,135 | |||||||
| Accumulated depreciation, depletion and amortization |
(146,289 | ) | (108,622 | ) | ||||
| Net property and equipment |
$ | 731,282 | $ | 556,513 | ||||
| 8. | Equity Investments |
In 2004, PVR acquired a 50% interest in Coal Handling Solutions, LLC, a joint venture formed to own and operate end-user coal handling facilities. PVR accounts for the investment under the equity method of accounting. At December 31, 2007 and 2006, PVR’s equity investment totaled $25.6 million and $25.4 million, which exceeded its portion of the underlying equity in net assets by $7.7 million and $8.7 million. The difference is being amortized to equity earnings over the life of coal services contracts in place at the time of the acquisition. In accordance with the equity method, we recognized equity earnings of $1.8 million in 2007, $1.3 million in 2006 and $1.1 million in 2005, with a corresponding increase in the investment. The joint venture generally pays to PVR quarterly distributions of PVR’s portion of the joint venture’s cash flows. PVR received cash distributions from the joint venture of $1.5 million in 2007, $2.7 million in 2006 and $2.3 million in 2005. Equity earnings are included in coal services revenues on our consolidated statements of income, and the equity investment is included in other long-term assets on our consolidated balance sheets.
| 9. | Allowance for Prepaid Minimums |
PVR establishes provisions for losses on long-term prepaid minimums if PVR determines that it will not recoup all or part of the outstanding balance. Collectibility is reviewed periodically and an allowance is established or adjusted, as necessary, using the specific identification method. The allowance is netted against long-term prepaid minimums on our consolidated balance sheets. The following table presents the activity of PVR’s allowance for prepaid minimums for the years ended December 31, 2007, 2006 and 2005:
| Year Ended December 31, | |||||||||||
| 2007 | 2006 | 2005 | |||||||||
| (in thousands) | |||||||||||
| Balance at beginning of period |
$ | 1,737 | $ | 1,692 | $ | 1,514 | |||||
| Charges to expense |
(91 | ) | 60 | 178 | |||||||
| Forfeiture of prepaid minimum |
— | (15 | ) | — | |||||||
| Balance at end of period |
$ | 1,646 | $ | 1,737 | $ | 1,692 | |||||
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| 10. | Derivative Instruments |
PVR Natural Gas Midstream Segment Commodity Derivatives
PVR utilizes costless collar and swap derivative contracts to hedge against the variability in cash flows associated with forecasted natural gas midstream revenues and cost of midstream gas purchased. PVR also utilizes swap derivative contracts to hedge against the variability in its “frac spread.” PVR’s frac spread is the spread between the purchase price for the natural gas PVR purchases from producers and the sale price for the NGLs that PVR sells after processing. PVR hedges against the variability in its frac spread by entering into swap derivative contracts to sell NGLs forward at a predetermined swap 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, their use also may limit future revenues or cost savings from favorable price movements.
With respect to a costless collar contract, the counterparty is required to make a payment to PVR if the settlement price for any settlement period is below the floor price for such contract. PVR is required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. With respect to a swap contract, the counterparty is required to make a payment to PVR if the settlement price for any settlement period is less than the swap price for such contract, and PVR is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price for such contract.
The fair values of PVR’s derivative agreements are determined based on forward price quotes for the respective commodities as of December 31, 2007. The following table sets forth PVR’s positions as of December 31, 2007 for commodities related to natural gas midstream revenues (ethane, propane, natural gasoline and crude oil) and cost of midstream gas purchased (natural gas):
| Average Volume Per Day |
Weighted Average Price |
Weighted Average Price |
Estimated Fair Value |
||||||||||||||
| Collars | |||||||||||||||||
| Floor | Ceiling | ||||||||||||||||
| (in thousands) | |||||||||||||||||
| Frac Spreads |
(in MMbtu | ) | (per MMbtu | ) | |||||||||||||
| First quarter 2008 through fourth quarter 2008 |
7,824 | $ | 5.02 | $ | (11,599 | ) | |||||||||||
| Ethane Sale Swaps |
(in gallons | ) | (per gallon | ) | |||||||||||||
| First quarter 2008 through fourth quarter 2008 |
34,440 | $ | 0.4700 | (6,279 | ) | ||||||||||||
| Propane Sale Swaps |
(in gallons | ) | (per gallon | ) | |||||||||||||
| First quarter 2008 through fourth quarter 2008 |
26,040 | $ | 0.7175 | (7,372 | ) | ||||||||||||
| Crude Oil Sale Swaps |
(in barrels | ) | (per barrel | ) | |||||||||||||
| First quarter 2008 through fourth quarter 2008 |
560 | $ | 49.27 | (8,788 | ) | ||||||||||||
| Natural Gasoline Collars |
(in gallons | ) | (per gallon) | ||||||||||||||
| First quarter 2008 through fourth quarter 2008 |
6,300 | $ | 1.4800 | $ | 1.6465 | (953 | ) | ||||||||||
| Crude Oil Collars |
(in barrels | ) | (per barrel) | ||||||||||||||
| First quarter 2008 through fourth quarter 2008 |
400 | $ | 65.00 | $ | 75.25 | (2,669 | ) | ||||||||||
| Natural Gas Purchase Swaps |
(in MMbtu | ) | (per MMbtu | ) | |||||||||||||
| First quarter 2008 through fourth quarter 2008 |
4,000 | $ | 6.97 | 1,205 | |||||||||||||
| Settlements to be paid in subsequent period |
(3,469 | ) | |||||||||||||||
| Natural gas midstream segment commodity derivatives – net liability |
$ | (39,924 | ) | ||||||||||||||
At December 31, 2007, PVR reported (i) a net derivative liability related to the natural gas midstream segment of $39.9 million and (ii) a loss in accumulated other comprehensive income of $5.5 million related to derivatives in the natural gas midstream segment for which PVR discontinued hedge accounting in 2006. The $5.5 million loss will be recorded in
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earnings through the end of 2008 as the hedged transactions settle. The following table summarizes the effects of commodity derivative activities on our consolidated statements of income for the years ended December 31, 2007, 2006 and 2005:
| Year Ended December 31, | ||||||||||||
| 2007 | 2006 | 2005 | ||||||||||
| (in thousands) | ||||||||||||
| Income statement caption: |
||||||||||||
| Natural gas midstream revenues |
$ | (8,515 | ) | $ | (10,331 | ) | $ | (3,871 | ) | |||
| Cost of midstream gas purchased |
3,920 | 8,378 | 4,859 | |||||||||
| Derivatives |
(45,568 | ) | (11,260 | ) | (14,024 | ) | ||||||
| Increase (decrease) in net income |
$ | (50,163 | ) | $ | (13,213 | ) | $ | (13,036 | ) | |||
| Realized and unrealized derivative impact: |
||||||||||||
| Cash paid for derivative settlements |
$ | (17,779 | ) | $ | (19,436 | ) | $ | (4,752 | ) | |||
| Unrealized derivative gain (loss) |
(32,384 | ) | 6,223 | (8,284 | ) | |||||||
| Increase (decrease) in net income |
$ | (50,163 | ) | $ | (13,213 | ) | $ | (13,036 | ) | |||
PVR Interest Rate Swaps
PVR has entered into interest rate swap agreements (the “PVR Revolver Swaps”) to establish fixed rates on a portion of the outstanding borrowings under PVR’s revolving credit facility. Until March 2010, the notional amounts of the PVR Revolver Swaps total $160 million. From March 2010 to December 2011, the notional amounts of the PVR Revolver Swaps total $100 million. Until March 2010, PVR will pay a weighted average fixed rate of 4.33% on the notional amount, and the counterparties will pay a variable rate equal to the three-month London Inter Bank Offering Rate (the “LIBOR”). From March 2010 to December 2011, PVR will pay a weighted average fixed rate of 4.40% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. Settlements on the PVR Revolver Swaps are recorded as interest expense. The PVR Revolver Swaps were designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings as interest expense. PVR reported (i) a derivative liability of $1.9 million at December 31, 2007 and (ii) a loss in accumulated other comprehensive income of $1.9 million at December 31, 2007 related to the PVR Revolver Swaps. In connection with periodic settlements, PVR recognized $0.7 million in net hedging gains in interest expense for the year ended December 31, 2007. Based upon future interest rate curves at December 31, 2007, PVR expects to realize $0.6 million of hedging losses within the next 12 months. The amounts that PVR ultimately realizes will vary due to changes in the fair value of open derivative agreements prior to settlement.
| 11. | Asset Retirement Obligations |
The following table reconciles the beginning and ending aggregate carrying amount of PVR’s asset retirement obligations, which are included in other liabilities on our consolidated balance sheets:
| Year Ended December 31, | ||||||
| 2007 | 2006 | |||||
| (in thousands) | ||||||
| Balance at beginning of period |
$ | 1,881 | $ | 1,458 | ||
| Liabilities incurred |
— | 301 | ||||
| Accretion expense |
147 | 122 | ||||
| Balance at end of period |
$ | 2,028 | $ | 1,881 | ||
| 12. | Long-Term Debt |
We have no long-term debt. The following table summarizes PVR’s long-term debt as of December 31, 2007 and 2006:
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| Year Ended December 31, | ||||||||
| 2007 | 2006 | |||||||
| (in thousands) | ||||||||
| Revolving credit facility—variable rate of 6.2% at December 31, 2007 |
$ | 347,700 | $ | 143,200 | ||||
| Senior unsecured notes |
64,014 | 74,846 | ||||||
| Total debt |
411,714 | 218,046 | ||||||
| Less: Current maturities |
(12,561 | ) | (10,832 | ) | ||||
| Total long-term debt |
$ | 399,153 | $ | 207,214 | ||||
PVR capitalized interest costs amounting to $0.8 million in 2007 because the borrowings funded the construction of natural gas processing plants. PVR capitalized interest costs amounting to $0.3 million in 2006 related to the construction of a coal services facility in October 2006. PVR did not capitalize any interest in 2005.
PVR Revolving Credit Facility
As of December 31, 2007, PVR had $347.7 million outstanding under its unsecured $450 million revolving credit facility (the “PVR Revolver”) that matures in December 2011. The PVR Revolver is available to PVR for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10 million sublimit for the issuance of letters of credit. PVR had outstanding letters of credit of $1.6 million as of December 31, 2007. At the current $450 million limit on the PVR Revolver, and given the outstanding balance of $347.7 million, net of $1.6 million of letters of credit, PVR could borrow up to $100.7 million. In 2007, PVR incurred commitment fees of $0.3 million on the unused portion of the PVR Revolver. The interest rate under the PVR Revolver fluctuates based on the ratio of PVR’s total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 0.75% if PVR selects the base rate borrowing option under the Revolver or at a rate derived from the LIBOR, plus an applicable margin ranging from 0.75% to 1.75% if PVR selects the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under the PVR Revolver during 2007 was 6.2%.
The financial covenants under the PVR Revolver require PVR not to exceed specified debt-to-consolidated EBITDA and consolidated EBITDA-to-interest expense ratios. The PVR Revolver prohibits PVR from making distributions to its partners if any potential default, or event of default, as defined in the PVR Revolver, occurs or would result from the distributions. In addition, the PVR Revolver contains various covenants that limit, among other things, PVR’s ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of its business, acquire another company or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. As of December 31, 2007, PVR was in compliance with all of its covenants under the PVR Revolver.
PVR Senior Unsecured Notes
As of December 31, 2007, PVR owed $64.0 million under its senior unsecured notes (the “PVR Notes”). The PVR Notes bear interest at a fixed rate of 6.02% and mature in March 2013, with semi-annual principal and interest payments. The PVR Notes are equal in right of payment with all of PVR’s other unsecured indebtedness, including the PVR Revolver. The PVR Notes require PVR to obtain an annual confirmation of its credit rating, with a 1.00% increase in the interest rate payable on the PVR Notes in the event that its credit rating falls below investment grade. In March 2007, PVR’s investment grade credit rating was confirmed by Dominion Bond Rating Services. The PVR Notes contain various covenants similar to those contained in the PVR Revolver. As of December 31, 2007, PVR was in compliance with all of its covenants under the PVR Notes.
Debt Maturities
The following table sets forth the aggregate maturities of the principal amounts of long-term debt for the next five years and thereafter:
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| Year |
Aggregate Maturities of Principal Amounts |
|||
| (in thousands) | ||||
| 2008 |
$ | 12,700 | ||
| 2009 |
14,100 | |||
| 2010 |
13,400 | |||
| 2011 |
358,500 | |||
| 2012 |
9,100 | |||
| Thereafter |
4,300 | |||
| Total principal |
412,100 | |||
| Less: Terminated interest rate swap |
(386 | ) | ||
| Total debt, including current maturities |
$ | 411,714 | ||
| 13. | Partners’ Capital and Distributions |
As of December 31, 2007, partners’ capital consisted of 39.1 million common units. As of December 31, 2007, affiliates of Penn Virginia, in the aggregate, owned an 82% interest in us, consisting of 32.1 million common units and a non-economic general partner interest.
Cash Distributions
We distribute 100% of Available Cash (as defined in our partnership agreement) within 55 days after the end of each quarter to unitholders of record. Available Cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established by our general partner for future requirements. Our general partner has the discretion to establish cash reserves that are necessary or appropriate to (i) provide for the proper conduct of our business; (ii) comply with applicable law, any of our debt instruments or other agreements; (iii) provide funds for distributions to unitholders and our general partner for any one or more of the next four quarters; or (iv) permit Penn Virginia Resource GP, LLC to make capital contributions to PVR to maintain its 2% general partner interest upon the issuance of additional partnership securities by PVR.
On February 19, 2008, the board of directors of our general partner paid a $0.32 per unit quarterly distribution ($1.28 per unit on an annualized basis) to unitholders of record on February 4, 2008.
Limited Call Right
If at any time our general partner and its affiliates own more than 90% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then current market price of the common units.
| 14. | Related Party Transactions |
General and Administrative
Penn Virginia charges us for certain corporate administrative expenses which are allocable to us and our subsidiaries. When allocating general corporate expenses, consideration is given to property and equipment, payroll and general corporate overhead. Any direct costs are paid by us. Total corporate administrative expenses charged to us totaled $4.6 million for the year ended December 31, 2007. These costs are reflected in general and administrative expenses in our consolidated statements of income. At least annually, our management performs an analysis of general corporate expenses based on time allocations of shared employees and other pertinent factors. Based on this analysis, our management believes that the allocation methodologies used are reasonable.
Accounts Payable—Affiliate
Amounts payable to related parties totaled $2.6 million and $1.9 million as of December 31, 2007 and 2006. This balance consists primarily of amounts due to our general partner for general and administrative expenses incurred on our behalf and is included in accounts payable on our consolidated balance sheets.
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Marketing Revenues
Penn Virginia Oil & Gas, L.P. (“PVOG”) and Connect Energy Services, LLC (“Connect Energy”), a wholly-owned subsidiary of PVR, are parties to a Master Services Agreement effective September 1, 2006. Pursuant to the Master Services Agreement, PVOG and Connect Energy have agreed that Connect Energy will market all of PVOG’s oil and gas production in Arkansas, Louisiana, Oklahoma and Texas for a fee equal to 1% of the net sales price (subject to specified limitations) received by PVOG for such production. The Master Services Agreement has a primary term of five years and automatically renews for additional one year terms until terminated by either party. In 2007 and 2006, PVOG paid Connect Energy $2.2 million and $0.4 million in fees pursuant to the Master Services Agreement. Marketing revenues are included in other revenues on our consolidated statements of income.
Purchase of Royalty Interests
In October 2007, PVR purchased from Penn Virginia Oil & Gas Corporation, a wholly-owned subsidiary of Penn Virginia, oil and gas royalty interests associated with leases of property in eastern Kentucky and Lee, Scott and Wise Counties, Virginia and with estimated proved reserves of 8.7 Bcfe at January 1, 2007. The purchase price was $31.0 million in cash and was funded with long-term debt under PVR’s revolving credit facility.
| 15. | Unit-Based Payments |
Long-Term Incentive Plan
Our general partner has adopted a long-term incentive plan. Our long-term incentive plan permits the grant of awards covering an aggregate of 300,000 common units to employees and directors of our general partner and employees of its affiliates who perform services for us. Awards under our long-term incentive plan can be in the form of common units, restricted units, unit options, phantom units and deferred common units. Our long-term incentive plan is administered by the compensation and benefits committee of our general partner’s board of directors. We reimburse our general partner for payments made pursuant to our long-term incentive plan and recognize compensation expense over the vesting period of the awards.
We recognize compensation expense related to the granting of common units and deferred common units and the vesting of restricted units granted under our long-term incentive plan. We recognized compensation expense related to our long-term incentive plan of $0.4 million for the year ended December 31, 2007. We granted no awards under and recognized no compensation expense related to our long-term incentive plan prior to 2007.
Deferred Common Units. A portion of the compensation to the non-employee directors of our general partner is paid in deferred common units. Each deferred common unit represents one common unit, which vests immediately upon issuance and is available to the holder upon termination or retirement from the board of directors of our general partner. Our general partner granted 13,396 deferred common units at a weighted average grant-date fair value of $27.30 per unit in 2007.
PVR Long-Term Incentive Plan
PVR’s general partner has adopted a long-term incentive plan. PVR’s long-term incentive plan permits the grant of awards covering an aggregate of 600,000 PVR common units to employees and directors of PVR’s general partner and employees of its affiliates who perform services for PVR. Awards under the PVR long-term incentive plan can be in the form of PVR common units, restricted PVR units, PVR unit options, phantom PVR units and deferred PVR common units. The PVR long-term incentive plan is administered by the compensation and benefits committee of the board of directors of PVR’s general partner. PVR reimburses its general partner for payments made pursuant to the PVR long-term incentive plan. PVR recognizes compensation cost based on the fair value of the awards over the vesting period.
PVR recognizes compensation expense related to the granting of common units and deferred common units and the vesting of restricted units granted under PVR’s long-term incentive plan. PVR recognized compensation expense related to the PVR long-term incentive plan of $2.4 million, $1.9 million and $1.4 million for the years ended December 31, 2007, 2006 and 2005.
PVR Common Units. PVR’s general partner granted 1,183 common units at a weighted average grant-date fair value of $27.09 per unit to non-employee directors in 2007. PVR’s general partner granted 1,795 common units at a weighted average grant-date fair value of $26.01 per unit to non-employee directors in 2006. PVR’s general partner granted 876 common units at a weighted average grant-date fair value of $25.36 per unit to non-employee directors in 2005.
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Restricted PVR Units. Restricted PVR units vest upon terms established by the compensation and benefits committee. In addition, all restricted PVR units will vest upon a change of control of PVR’s general partner or Penn Virginia. If a grantee’s employment with, or membership on the board of directors of, PVR’s general partner terminates for any reason, the grantee’s unvested restricted PVR units will be automatically forfeited unless, and to the extent that, the compensation and benefits committee provides otherwise. Distributions payable with respect to restricted PVR units may, in the compensation and benefits committee’s discretion, be paid directly to the grantee or held by PVR’s general partner and made subject to a risk of forfeiture during the applicable restriction period. Restricted PVR units generally vest over a three-year period, with one-third vesting in each year.
The following table summarizes the status of nonvested restricted PVR units as of December 31, 2007, and changes during the year then ended:
| Nonvested Restricted Units |
Weighted Average Grant-Date Fair Value | |||||
| Nonvested at January 1, 2007 |
114,214 | $ | 27.85 | |||
| Granted |
87,033 | 26.88 | ||||
| Vested |
(43,049 | ) | 27.54 | |||
| Forfeited |
(1,267 | ) | 27.65 | |||
| Nonvested at December 31, 2007 |
156,931 | $ | 27.40 | |||
At December 31, 2007, PVR had $2.7 million of total unrecognized compensation cost related to nonvested restricted PVR units. PVR expects to reimburse its general partner for that cost over a weighted average period of 0.9 years. The total grant-date fair value of restricted PVR units that vested in 2007, 2006 and 2005 was $1.2 million, $2.2 million and $0.4 million.
Deferred PVR Common Units. A portion of the compensation to the non-employee directors of PVR’s general partner is paid in deferred PVR common units. Each deferred PVR common unit represents one PVR common unit, which vests immediately upon issuance and is available to the holder upon termination or retirement from the board of directors of PVR’s general partner. At December 31, 2006, 39,009 deferred PVR common units were outstanding at a weighted average grant-date fair value of $25.26 per common unit. PVR’s general partner granted 22,209 deferred PVR common units in 2007 at a weighted average grant-date fair value of $26.43. At December 31, 2007, 61,218 deferred PVR common units were outstanding at a weighted average grant-date fair value of $25.58. The aggregate intrinsic value of deferred PVR common units converted to PVR common units in 2006 was $0.2 million. No deferred PVR common units converted to PVR common units in 2007 or 2005.
| 16. | Commitments and Contingencies |
Rental Commitments
Operating lease rental expense in the years ended December 31, 2007, 2006 and 2005 was $2.6 million, $1.9 million and $0.9 million. The following table sets forth our minimum rental commitments for the next five years under all non-cancelable operating leases in effect at December 31, 2007:
| Year |
Minimum Rental Commitments | ||
| (in thousands) | |||
| 2008 |
$ | 1,810 | |
| 2009 |
1,709 | ||
| 2010 |
1,686 | ||
| 2011 |
1,479 | ||
| 2012 |
1,218 | ||
| Total minimum payments |
$ | 7,902 | |
Our rental commitments primarily relate to equipment and building leases and leases of coal reserve-based properties which PVR subleases, or intends to sublease, to third parties. The obligation with respect to leased properties which PVR subleases expires when the property has been mined to exhaustion or the lease has been canceled. The timing of mining by
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third party operators is difficult to estimate due to numerous factors. We believe that the future rental commitments cannot be estimated with certainty; however, based on current knowledge and historical trends, PVR believes that it will incur $0.9 million in rental commitments annually until the reserves have been exhausted.
Firm Transportation Commitments
As of December 31, 2007, PVR’s firm transportation capacity rights for specified volumes per day on a pipeline system for terms ranging from one to seven years. The contracts require PVR to pay transportation demand charges regardless of the amount of pipeline capacity PVR uses. PVR may sell excess capacity to third parties at its discretion. The following table set forth PVR’s obligation for firm transportation commitments in effect at December 31, 2007 for the next five years and thereafter:
| Year |
Firm Transportation Commitments | ||
| (in thousands) | |||
| 2008 |
$ | 11,838 | |
| 2009 |
4,745 | ||
| 2010 |
6,168 | ||
| 2011 |
5,694 | ||
| 2012 |
4,508 | ||
| Thereafter |
7,354 | ||
| Total firm transportation commitments |
$ | 40,307 | |
Legal
We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, liquidity or operations.
Environmental Compliance
PVR’s operations and those of its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of PVR’s coal property leases impose liability for all environmental and reclamation liabilities arising under those laws and regulations on the relevant lessees. The lessees are bonded and have indemnified PVR against any and all future environmental liabilities. PVR regularly visits its coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. PVR’s management believes that its operations and those of its lessees comply with existing laws and regulations and does not expect any material impact on its financial condition or results of operations.
As of December 31, 2007 and 2006, PVR’s environmental liabilities included $1.5 million and $1.6 million, which represents PVR’s best estimate of the liabilities as of those dates related to its coal and natural resource management and natural gas midstream businesses. PVR has reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.
Mine Health and Safety Laws
There are numerous mine health and safety laws and regulations applicable to the coal mining industry. However, since PVR does not operate any mines and does not employ any coal miners, PVR is not subject to such laws and regulations. Accordingly, we have not accrued any related liabilities.
| 17. | Comprehensive Income |
Comprehensive income represents changes in partners’ capital during the reporting period, including net income and charges directly to partners’ capital which are excluded from net income. The following table sets forth the components of comprehensive income for the years ended December 31, 2007, 2006 and 2005:
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| Year Ended December 31, | ||||||||||||
| 2007 | 2006 | 2005 | ||||||||||
| Net income |
$ | 29,169 | $ | 32,048 | $ | 20,769 | ||||||
| Unrealized holding losses on derivative activities |
(2,599 | ) | (5,669 | ) | (3,903 | ) | ||||||
| Reclassification adjustment for derivative activities |
3,859 | 1,909 | (988 | ) | ||||||||
| Comprehensive income |
$ | 30,429 | $ | 28,288 | $ | 15,878 | ||||||
| 18. | Segment Information |
Segment information has been prepared in accordance with SFAS No. 131, Disclosure about Segments of an Enterprise and Related Information. Under SFAS No. 131, operating segments are defined as components of an enterprise about which separate financial information is available and is evaluated regularly by the chief operating decision maker, or decision-making group, in assessing performance. Our chief operating decision-making group consists of our Chief Executive Officer and other senior officers. This group routinely reviews and makes operating and resource allocation decisions among PVR’s coal and natural resource management operations and PVR’s natural gas midstream operations. Accordingly, our reportable segments are as follows:
| • | PVR Coal and Natural Resource Management—management and leasing of coal properties and subsequent collection of royalties; other land management activities such as selling standing timber and real estate rentals; leasing of fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants; and collection of oil and gas royalties. |
| • | PVR Natural Gas Midstream—natural gas processing, natural gas gathering and other related services. |
The following table presents a summary of certain financial information relating to our segments as of and for the years ended December 31, 2007, 2006 and 2005:
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| Coal and Natural Resource Management |
Natural Gas Midstream |
Corporate and other |
Consolidated | |||||||||||
| (in thousands) | ||||||||||||||
| For the year ended December 31, 2007 |
||||||||||||||
| Revenues |
$ | 111,639 | $ | 437,806 | $ | — | $ | 549,445 | ||||||
| Cost of midstream gas purchased |
— | 343,293 | — | 343,293 | ||||||||||
| Operating costs and expenses |
20,138 | 26,777 | 2,482 | 49,397 | ||||||||||
| Depreciation, depletion and amortization |
22,690 | 18,822 | — | 41,512 | ||||||||||
| Operating income |
$ | 68,811 | $ | 48,914 | $ | (2,482 | ) | 115,243 | ||||||
| Interest expense, net |
(15,099 | ) | ||||||||||||
| Derivatives |
(45,568 | ) | ||||||||||||
| Minority interest |
(25,407 | ) | ||||||||||||
| Net income |
$ | 29,169 | ||||||||||||
| Total assets |
$ | 610,866 | $ | 320,413 | $ | 10,972 | $ | 942,251 | ||||||
| Equity investments |
25,580 | 60 | — | 25,640 | ||||||||||
| Additions to property, plant and equipment and acquisitions (1) |
177,960 | 47,080 | — | 225,040 | ||||||||||
| For the year ended December 31, 2006 |
||||||||||||||
| Revenues |
$ | 112,981 | $ | 404,910 | $ | — | $ | 517,891 | ||||||
| Cost of midstream gas purchased |
— | 334,594 | — | 334,594 | ||||||||||
| Operating costs and expenses |
19,138 | 23,846 | 397 | 43,381 | ||||||||||
| Depreciation, depletion and amortization |
20,399 | 17,094 | — | 37,493 | ||||||||||
| Operating income |
$ | 73,444 | $ | 29,376 | $ | (397 | ) | 102,423 | ||||||
| Interest expense, net |
(16,462 | ) | ||||||||||||
| Derivatives |
(11,260 | ) | ||||||||||||
| Minority interest |
(42,653 | ) | ||||||||||||
| Net income |
$ | 32,048 | ||||||||||||
| Total assets |
$ | 409,709 | $ | 304,314 | $ | 2,246 | $ | 716,269 | ||||||
| Equity investments |
25,295 | 60 | — | 25,355 | ||||||||||
| Additions to property, plant and equipment and acquisitions (2) |
92,697 | 37,015 | — | 129,712 | ||||||||||
| For the year ended December 31, 2005 |
||||||||||||||
| Revenues |
$ | 95,755 | $ | 350,593 | $ | — | $ | 446,348 | ||||||
| Cost of midstream gas purchased |
— | 303,912 | — | 303,912 | ||||||||||
| Operating costs and expenses |
16,121 | 17,597 | — | 33,718 | ||||||||||
| Depreciation, depletion and amortization |
17,890 | 12,738 | — | 30,628 | ||||||||||
| Operating income |
$ | 61,744 | $ | 16,346 | $ | — | 78,090 | |||||||
| Interest expense, net |
(12,908 | ) | ||||||||||||
| Derivatives |
(14,024 | ) | ||||||||||||
| Minority interest |
(30,389 | ) | ||||||||||||
| Net income |
$ | 20,769 | ||||||||||||
| Total assets |
$ | 372,322 | $ | 285,557 | $ | 2,068 | $ | 659,947 | ||||||
| Equity investments |
26,612 | 60 | — | 26,672 | ||||||||||
| Additions to property, plant and equipment and acquisitions (3) |
96,862 | 206,811 | — | 303,673 | ||||||||||
| (1) | PVR coal and natural resource management segment additions to property, plant and equipment and acquisitions in 2007 includes an $11.5 million lease receivable associated with the acquisition of fee ownership and lease rights to coal reserves in western Kentucky. |
| (2) | PVR coal and natural resource management segment additions to property, plant and equipment and acquisitions in 2006 include acquisition of assets other than property or equipment of $1.2 million. |
| (3) | PVR coal and natural resource management segment additions to property, plant and equipment and acquisitions in 2005 exclude noncash expenditures of $14.4 million related to acquisitions. |
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Operating income is equal to total revenues less cost of midstream gas purchased, operating costs and expenses and depreciation, depletion and amortization. Operating income does not include certain other income items, interest expense, interest income and income taxes. Identifiable assets are those assets used in our operations in each segment.
For the year ended December 31, 2007, three customers of the PVR natural gas midstream segment accounted for $109.2 million, $61.0 million and $60.5 million, or 20%, 11% and 11%, of our total consolidated net revenues. For the year ended December 31, 2006, two customers of the PVR natural gas midstream segment accounted for $129.1 million and $67.4 million, or 25% and 13%, of our total consolidated net revenues. For the year ended December 31, 2005, two customers of the PVR natural gas midstream segment accounted for $81.9 million and $77.1 million, or 18% and 17%, of our total consolidated net revenues.
Supplemental Quarterly Financial Information (Unaudited)
| First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter | |||||||||
| (in thousands, except unit data) | ||||||||||||
| 2007 | ||||||||||||
| Revenues |
$ | 124,200 | $ | 144,144 | $ | 130,204 | $ | 150,897 | ||||
| Operating income |
$ | 21,578 | $ | 26,836 | $ | 31,497 | $ | 35,332 | ||||
| Net income (loss) |
$ | 7,720 | $ | 8,301 | $ | 8,878 | $ | 4,270 | ||||
| Basic and diluted net income (loss) per limited partner unit, common and subordinated (1) |
$ | 0.20 | $ | 0.21 | $ | 0.23 | $ | 0.11 | ||||
| Weighted average number of units outstanding, basic and diluted |
39,062 | 39,075 | 39,075 | 39,075 | ||||||||
| 2006 | ||||||||||||
| Revenues |
$ | 135,164 | $ | 123,463 | $ | 131,494 | $ | 127,770 | ||||
| Operating income |
$ | 18,246 | $ | 29,288 | $ | 29,899 | $ | 24,990 | ||||
| Net income (loss) |
$ | 3,451 | $ | 5,461 | $ | 12,801 | $ | 10,335 | ||||
| Basic and diluted net income (loss) per limited partner unit, common and subordinated (1) |
$ | 0.11 | $ | 0.17 | $ | 0.40 | $ | 0.30 | ||||
| Weighted average number of units outstanding, basic and diluted |
32,125 | 32,125 | 32,125 | 34,425 | ||||||||
| (1) | The sum of the quarters may not equal the total of the respective year’s net income per limited partner unit due to changes in the weighted average units outstanding throughout the year. |
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| Item 9 | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure |
None.
| Item 9A | Controls and Procedures |
| (a) | Disclosure Controls and Procedures |
Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of December 31, 2007. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of December 31, 2007, such disclosure controls and procedures were effective.
| (b) | Management’s Annual Report on Internal Control Over Financial Reporting |
Our management, including our Chief Executive Officer and our Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over our financial reporting. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2007. This evaluation was completed based on the framework established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Our management has concluded that, as of December 31, 2007, our internal control over financial reporting was effective. KPMG LLP, an independent registered public accounting firm, or KPMG, has issued an attestation report on our internal control over financial reporting as of December 31, 2007, which is included in Item 8 of this Annual Report or Form 10-K.
| (c) | Changes in Internal Control Over Financial Reporting |
No changes were made in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
| Item 9B | Other Information |
There was no information that was required to be disclosed by us on a Current Report on Form 8-K during the fourth quarter of 2007 which we did not disclose.
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| Item 10 | Directors, Executive Officers and Corporate Governance |
Directors and Executive Officers of Our General Partner
The following table sets forth information concerning the directors and executive officers of our general partner. All directors of our general partner are elected, and may be removed, by Penn Virginia Resource GP Corp., its sole member and a wholly-owned subsidiary of Penn Virginia.
| Name |
Age |
Position with our General Partner | ||
| A. James Dearlove |
60 | Chairman of the Board of Directors and President and Chief Executive Officer | ||
| Robert Garrett |
71 | Director | ||
| Robert J. Hall |
62 | Director | ||
| Frank A. Pici |
52 | Director and Vice President and Chief Financial Officer | ||
| Nancy M. Snyder |
54 | Director and Vice President and General Counsel | ||
| John C. van Roden, Jr. |
58 | Director | ||
| Jonathan B. Weller |
61 | Director |
A. James Dearlove has served as Chairman of the Board of Directors and President and Chief Executive Officer of our general partner since September 2006 and as Chairman of the Board of Directors and Chief Executive Officer of PVR’s general partner since December 2002 and July 2001. Mr. Dearlove has also served in various capacities with Penn Virginia since 1977, including as President and Chief Executive Officer since May 1996, as President and Chief Operating Officer from 1994 to May 1996, as Senior Vice President from 1992 to 1994 and as Vice President from 1986 to 1992. Mr. Dearlove also serves as a director of Penn Virginia and as a director of the National Council of Coal Lessors.
Robert Garrett has served as a director of our general partner since September 2006 and as non-executive Chairman of the Board and a director of Penn Virginia since May 2000 and May 1997, respectively. Mr. Garrett was also the founder, and has served as Managing Director of, AdMedia Partners, Inc., or AdMedia, an investment banking firm serving media, advertising and marketing services businesses from 2005 to 2007. From 1990 to 2005, Mr. Garrett served as President of AdMedia. From 1986 to date, Mr. Garrett has also served as President of Robert Garrett & Sons, Inc., a private investing and financial advisory company.
Robert J. Hall has served as a director of our general partner since September 2006. Since June 2004, Mr. Hall has been providing consulting services in newspaper industry acquisitions. From January 2004 to May 2004, Mr. Hall was retired. From 1990 to December 2003, Mr. Hall served as Publisher and Chairman of Philadelphia Newspapers, Inc., which publishes the Philadelphia Inquirer and the Philadelphia Daily News. From 1985 to 1989, Mr. Hall served as General Manager of Detroit Free Press, and from 1989 to 1990, he served as Chairman of Detroit Free Press.
Frank A. Pici has served as Vice President and Chief Financial Officer and as a director of our general partner since September 2006 and as Vice President and Chief Financial Officer and as a director of PVR’s general partner since September 2001 and as a director since October 2002. Mr. Pici has also served as Executive Vice President and Chief Financial Officer of Penn Virginia since September 2001. From 1996 to 2001, Mr. Pici served as Vice President—Finance and Chief Financial Officer of Mariner Energy, Inc., or Mariner, a Houston, Texas-based oil and gas exploration and production company, where he managed all financial aspects of Mariner, including accounting, tax, finance, banking, investor relations, planning and budgeting and information technology. From 1994 to 1996, Mr. Pici served as Corporate Controller of Cabot Oil & Gas Corporation, an oil and gas exploration and production company.
Nancy M. Snyder has served as Vice President and General Counsel and as a director of our general partner since September 2006 and as Vice President and General Counsel and as a director of PVR’s general partner since July 2001. Ms. Snyder has also served in various capacities with Penn Virginia since 1997, including as Executive Vice President since May 2006, as Senior Vice President from February 2003 to May 2006, as Vice President from December 2000 to February 2003 and as General Counsel and Corporate Secretary since 1997.
John C. van Roden, Jr. has served as a director of our general partner since September 2006. From January 2007 to date, Mr. van Roden has been a consultant to Glatfelter, a global manufacturer of specialty papers and engineered products. From April 2003 to December 2006, Mr. van Roden served as Executive Vice President of Glatfelter, and from April 2003 to June
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2006, he served as Chief Financial Officer of Glatfelter. From 1998 to April 2003, Mr. van Roden served as Senior Vice President and Chief Financial Officer of Conectiv, a company engaged in the transmission and distribution of electricity and the distribution of natural gas to customers in the Mid-Atlantic region. From 1982 to 1998, Mr. van Roden served as Senior Vice President and Chief Financial Officer of Lukens, Inc., a producer of specialty steel. Mr. van Roden serves as a director of Airgas, Inc., H.B. Fuller Company and Horsehead Corporation.
Jonathan B. Weller has served as a director of our general partner since September 2006. Since January 2007, Mr. Weller has been an Adjunct Lecturer at The Wharton School of the University of Pennsylvania. From April 2006 to January 2007, Mr. Weller was retired. From 1994 to April 2006, Mr. Weller has served in various capacities with Pennsylvania Real Estate Investment Trust, an owner, operator and developer of shopping centers in the eastern United States, including as Vice Chairman and Trustee since June 2004 to April 2006, as President and Chief Operating Officer from 1994 to June 2004 and as Trustee from 1994 to March 2006. Mr. Weller serves as a director of AMREP Corporation.
Executive Officers of PVR’s General Partner
The following table sets forth information concerning the executive officers of PVR’s general partner:
| Name |
Age | Position with PVR’s General Partner | ||
| A. James Dearlove |
60 | Chairman of the Board of Directors and Chief Executive Officer | ||
| Frank A. Pici |
52 | Director and Vice President and Chief Financial Officer | ||
| Nancy M. Snyder |
54 | Director and Vice President and General Counsel | ||
| Keith D. Horton |
54 | Co-President and Chief Operating Officer—Coal | ||
| Ronald K. Page |
57 | Co-President and Chief Operating Officer—Midstream |
Keith D. Horton has served as Co-President and Chief Operating Officer—Coal of PVR’s general partner since June 2006 and as President of the Operating Company since September 2001. From July 2001 to June 2006, Mr. Horton served as President and Chief Operating Officer of PVR’s general partner. Mr. Horton has also served in various capacities with Penn Virginia since 1981, including as Executive Vice President since December 2000, as Vice President—Eastern Operations from February 1999 to December 2000 and as Vice President from February 1996 to February 1999. Mr. Horton also serves as a director of Penn Virginia and as director of the Virginia Mining Association, the Powell River Project and the Eastern Coal Council.
Ronald K. Page has served as Co-President and Chief Operating Officer—Midstream of PVR’s general partner since June 2006 and as President of PVR Midstream LLC since January 2005. From July 2003 to June 2006, Mr. Page served as Vice President, Corporate Development of PVR’s general partner. Mr. Page has also served in various capacities with Penn Virginia since July 2003, including as Vice President since May 2005 and as Vice President, Corporate Development from July 2003 to May 2005. From January 1998 to May 2003, Mr. Page served in various positions with El Paso Field Services Company, including Vice President of Commercial Operations—Texas Pipelines and Processing from 2001 to 2003, Vice President of Business Development from 2000 to 2001 and Director of Business Development from 1999 to 2000.
Role of the Board of Directors of our General Partner
Our business is managed under the direction of the board of directors of our general partner. The board of directors of our general partner has adopted Corporate Governance Principles outlining its duties. A current copy of our general partner’s Corporate Governance Principles is available at the “Governance” section of our website, http://www.pvgpholdings.com, or in print upon request to PVG GP, LLC, Attention: Secretary, Three Radnor Corporate Center, Suite 300, 100 Matsonford Road, Radnor, Pennsylvania 19087, without charge. The board of directors of our general partner meets regularly to review significant developments affecting us and to act on matters requiring its approval.
Code of Business Conduct and Ethics
The board of directors of our general partner has adopted a Code of Business Conduct and Ethics as its “code of ethics” as defined in Item 406 of Regulation S-K, which applies to all directors, officers and employees of our general partner, including its Chief Executive Officer, Chief Financial Officer, principal accounting officer or controller or persons performing similar functions, and all employees of any affiliate of our general partner who provide services to us. A current copy of our general partner’s Code of Business Conduct and Ethics is available at the “Governance” section of our website, http://www.pvgpholdings.com, or in print upon request to PVG GP, LLC, Attention: Secretary, Three Radnor Corporate Center, Suite 300, 100 Matsonford Road, Radnor, Pennsylvania 19087, without charge.
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Executive Sessions and Meetings of Independent Directors; Communications with the Board
Our general partner’s Independent Directors, as such term is defined in “Item 13—Certain Relationships and Related Transactions, and Director Independence—Director Independence,” meet during regularly scheduled executive sessions without management as well as during meetings which are scheduled on an as needed basis. John C. van Roden, Jr., an Independent Director, presides over executive sessions. Unitholders and other interested parties may communicate any concerns they have regarding us by contacting Mr. van Roden in writing c/o Secretary, PVG GP, LLC, Three Radnor Corporate Center, Suite 300, 100 Matsonford Road, Radnor, Pennsylvania 19087.
Committees of the Board of Directors of our General Partner
The board of directors of our general partner has an audit committee, a conflicts committee and a compensation and benefits committee.
Audit Committee. Messrs. Hall, van Roden and Weller are the members of the audit committee of our general partner, and each such member is an Independent Director. Mr. van Roden is an “audit committee financial expert” as defined in Item 407(d)(5) of Regulation S-K. The audit committee of our general partner is responsible for the appointment, compensation, evaluation and termination of our independent registered public accountants, and oversees the work, internal quality-control procedures and independence of the independent registered public accountants. The committee discusses with management and the independent registered public accountants our annual audited and quarterly unaudited financial statements and recommends to the board of directors of our general partner that our annual audited financial statements be included in our Annual Report on Form 10-K. The committee also discusses with management earnings press releases and guidance provided to analysts. The committee also provides oversight with respect to business risk matters, compliance with ethics policies, compliance with legal and regulatory requirements and performance of our internal audit function. The committee has established procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls, auditing and other matters and the confidential anonymous submission by employees of concerns regarding questionable accounting, auditing and other matters. The committee may obtain advice and assistance from outside legal, accounting or other advisors as it deems necessary to carry out its duties.
Conflicts Committee. Messrs. Hall, van Roden and Weller are the members of the conflicts committee of our general partner, and each such member is an Independent Director. The conflicts committee of our general partner reviews transactions between or among us and Penn Virginia or PVR, or any of their affiliates, and any other transactions involving us or our affiliates that the board of directors of our general partner believes may involve conflicts of interest. The conflicts committee then determines whether such transactions are fair and reasonable to us, and whether our general partner has upheld the fiduciary or other duties it owes to us. The committee may obtain advice and assistance from outside legal, financial or other advisors as it deems necessary to carry out its duties.
Compensation and Benefits Committee. Messrs. Hall, van Roden and Weller are the members of the compensation and benefits committee of our general partner, and each such member is an Independent Director. The compensation and benefits committee of our general partner assists the compensation and benefits committee of Penn Virginia, or the Penn Virginia Committee, when the Penn Virginia Committee determines the compensation for the executive officers of our general partner. See “Item 11—Executive Compensation—Compensation Discussion and Analysis—How Compensation Is Determined—Committee Process.” The committee reviews and discusses with management the information contained in Item 11, “Executive Compensation—Compensation Discussion and Analysis,” and recommends that such information be included herein. The committee periodically reviews and makes recommendations or decisions regarding our general partner’s incentive compensation and equity-based plans, provides oversight with respect to our general partner’s other employee benefit plans and reports its recommendations to the board of directors of our general partner. The committee also reviews and makes recommendations to the board of directors of our general partner regarding director compensation policy. The committee may obtain advice and assistance from outside compensation consultants or other advisors as it deems necessary to carry out its duties.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires officers and directors of our general partner and beneficial owners more than 10% of our common units to file, by a specified date, reports of beneficial ownership and changes in beneficial ownership with the SEC and to furnish copies of such reports to us. We believe that all such filings were made on a timely basis in 2007.
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| Item 11 | Executive Compensation |
Compensation Discussion and Analysis
Under the rules established by the SEC, we are required to provide a discussion and analysis of information necessary to an understanding of our compensation policies and decisions regarding our Chief Executive Officer, or CEO, Chief Financial Officer, or CFO, and the other executive officers of our general partner named in the Summary Compensation Table included in this Annual Report on Form 10-K. The required disclosure includes the use of specified tables and a report of the compensation and benefits committee of our general partner. Unless otherwise indicated, all references in this Annual Report on Form 10-K to the “NEOs” refer to the executive officers named in the Summary Compensation Table, all references to “our Committee” or the “Committee” refer to the compensation and benefits committee of our general partner and all references to the “PVR Committee” refer to the compensation and benefits committee of PVR’s general partner.
Compensation Structure
Penn Virginia controls our general partner and owns a significant limited partner interest in us. Because of this relationship, and since all of the NEOs are also executives of Penn Virginia and three of the NEOs, including our CEO, devote a majority of their professional time to Penn Virginia, the Penn Virginia Committee sets compensation for the NEOs. A. James Dearlove, our President and CEO, Frank A. Pici, our Vice President and CFO, and Nancy M. Snyder, our Vice President and General Counsel, who are referred to in this Annual Report on Form 10-K as the “Shared Executives,” are employees of Penn Virginia and rendered services not only to us, but also to Penn Virginia and PVR, during 2007. We are responsible for reimbursing to Penn Virginia that portion of the Shared Executives’ compensation related to the services they perform for us, and PVR is responsible for reimbursing to Penn Virginia that portion of the Shared Executives’ compensation related to the services they perform for PVR. The specific portions of compensation reimbursed to Penn Virginia by us and PVR depend on the portions of professional time devoted by each Shared Executive to us and PVR. The Shared Executives are required to document the amount of professional time they spend rendering services to us and PVR. See “How Compensation Is Determined—Committee Process” for a discussion of our Committee’s and the PVR Committee’s review of such allocations.
The Shared Executives are our only executive officers. However, because we control PVR’s general partner and own 100% of PVR’s incentive distribution rights and a significant limited partner interest in PVR, we include in the NEOs two executive officers of PVR’s general partner, Keith D. Horton, Co-President and Chief Operating Officer—Coal, and Ronald K. Page, Co-President and Chief Operating Officer—Midstream, who are referred to in this Annual Report on Form 10-K as the “Partnership Executives.” The Partnership Executives render their services solely to PVR so PVR pays all of their compensation.
Objectives of the Compensation Program
The compensation program is based on the following objectives, which reflect that our only assets consist of our ownership interests in PVR and PVR’s general partner:
| • | Executive compensation should be industry-competitive so that we and PVR can attract, retain and motivate talented executives with appropriate experience and skill sets. |
| • | Executives should be accountable for PVR’s performance as well as their own individual performance, so compensation should be tied to both partnership financial measures and individual performance measures. |
| • | Executive compensation should balance and align the short-term and long-term interests of our executives with those of our and PVR’s unitholders, so executive compensation packages should include a mix of cash and equity-based compensation. |
Elements of Compensation
Penn Virginia and PVR pay the NEOs a base salary and give them an opportunity to earn an annual cash bonus and an annual long-term compensation award. In determining these three elements of compensation, the Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, takes into account certain peer group information obtained by the PVR Committee, the Penn Virginia Committee, each such committee’s independent consultants and management, typically focusing on approximately the 50th percentile of the peer benchmarks described below under “How Compensation is Determined—Peer Benchmarks for PVR” and “How Compensation is Determined—Peer Benchmarks for Penn Virginia,” but also applying its independent judgment to these matters and considering such other factors as it deems relevant.
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| • | Base Salary—Penn Virginia and PVR pay each of the NEOs an industry-competitive salary so that we can attract and retain talented executives. The base salaries also reflect the capabilities, level of experience, tenure, position and responsibilities of the NEOs. |
| • | Annual Cash Bonus—Penn Virginia and PVR give each of the NEOs the opportunity to earn an industry-competitive annual cash bonus. Penn Virginia and PVR provide this opportunity to create a strong financial incentive for the NEOs to achieve or exceed a combination of partnership and individual goals. The performance criteria by which each NEO is measured and other factors affecting the compensation of the NEOs are described below under the headings “Peer Benchmarks for PVR,” “Peer Benchmarks for Penn Virginia” and “Partnership, Company and Individual Performance Criteria.” In addition to the performance criteria, the PVR Committee and the Penn Virginia Committee may consider any other factors they deem appropriate when awarding annual cash bonuses to the NEOs. |
| • | Long-Term Compensation Awards—Penn Virginia and PVR give each of the NEOs the opportunity to earn an industry-competitive annual long-term compensation award. Penn Virginia and PVR provide this opportunity to create a strong financial incentive for the NEOs to promote the long-term financial and operational success of the Partnership and PVR and to encourage a significant equity stake in PVR. Neither we nor PVR has unit ownership requirements for the NEOs. Long-term compensation awards are expressed in dollar values, and PVR or Penn Virginia pay those awards in the form of restricted PVR units, stock options or restricted stock. The actual numbers of restricted PVR units and shares of restricted stock awarded are based on the NYSE closing prices of PVR’s common units and Penn Virginia’s common stock on the dates of grant. The actual number of stock options awarded is based on a weighted-average value of all options granted to all classes of Penn Virginia’s employees on the date of grant using the Black-Scholes-Merton option-pricing formula. The Shared Executives’ long-term compensation awards are split between restricted units of PVR, on the one hand, and stock options or restricted stock of Penn Virginia, on the other hand. For each Shared Executive, the ratio of the split between PVR-related long-term compensation and Penn Virginia-related long-term compensation is determined based on the amount of time such Shared Executive devotes to PVR, on the one hand, and us and Penn Virginia, on the other hand. Time devoted to us is included with time devoted to Penn Virginia for the purpose of splitting the type of long-term compensation awards because we are a majority-owned subsidiary of Penn Virginia. Executives who render services wholly or predominately to PVR may receive only restricted PVR units, and executives who render services wholly or predominantly to us or Penn Virginia may receive only stock options or restricted stock. Executives who receive Penn Virginia awards are given the opportunity to elect whether to receive those awards in stock options, restricted stock or a combination of both. |
How Compensation Is Determined
Committee Process. Because of our relationship with Penn Virginia, as discussed above, the Penn Virginia Committee sets compensation for the NEOs. Our Committee and the PVR Committee assist the Penn Virginia Committee in determining executive compensation for the NEOs in the manner described below. Each of our Committee, the Penn Virginia Committee and the PVR Committee is comprised entirely of Independent Directors.
With respect to Messrs. Horton and Page, who manage PVR’s coal and natural resource management-related and natural gas midstream-related operations, respectively, and devote substantially all of their business time to PVR, the PVR Committee has the primary responsibility to assess all factors relevant to their compensation. Based on that assessment and after discussing such assessment with our Committee, the PVR Committee recommends to the Penn Virginia Committee salary, annual cash bonus and long-term compensation awards for them. Since the PVR Executives report directly to, and work on a daily basis with, our CEO, the PVR Committee reviews and discusses with our CEO his evaluation of the performance of each of the PVR Executives prior to making its recommendation regarding such PVR Executive’s compensation, and the PVR Committee gives our CEO’s evaluations considerable weight in assessing the amount of compensation to recommend to the Penn Virginia Committee for the PVR Executives. Our CEO bases his evaluation of each of the PVR Executives primarily on whether PVR met or exceeded certain quantitative partnership performance criteria and whether such PVR Executive met or exceeded certain specifically tailored job-related individual performance criteria. All such performance criteria are recommended by our CEO and the PVR Committee and set by the Penn Virginia Committee during the preceding year. These performance criteria and other factors relevant to the PVR Executives’ compensation are described in detail below under the headings “Peer Benchmarks for PVR” and “Partnership, Company and Individual Performance Criteria.” The Penn Virginia Committee then considers our CEO’s and the PVR Committee’s recommendations as well as other factors it deems relevant and makes the final determination regarding the compensation of each of the PVR Executives. The Penn Virginia Committee set the 2008 base salary and 2007-related bonus and long-term compensation awards for each of the PVR Executives in the amounts the PVR Committee recommended.
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With respect to the Shared Executives, including our CEO, the Penn Virginia Committee assesses the factors relevant to their compensation and, after discussing such assessment with our Committee and the PVR Committee, sets the salary, annual cash bonus and long-term compensation for each Shared Executive. Since the Shared Executives other than our CEO report directly to, and work on a daily basis with, our CEO, the Penn Virginia Committee reviews and discusses with our CEO his evaluation of the performance of each of the other Shared Executives, and gives considerable weight to our CEO’s evaluations, when assessing their performance and determining their compensation. The Penn Virginia Committee bases its evaluation of our CEO, and our CEO bases his evaluation of each of the other Shared Executives, primarily on whether PVR or Penn Virginia met or exceeded certain quantitative partnership or corporate performance criteria and whether each Shared Executive met or exceeded certain specifically tailored job-related individual performance criteria. All corporate, partnership and individual performance criteria, including those by which our CEO’s performance is measured, are recommended by our CEO and set by the Penn Virginia Committee during the preceding year. These performance criteria and other factors relevant to the Shared Executives’ compensation are described in detail below under the headings “Peer Benchmarks for PVR,” “Peer Benchmarks for Penn Virginia” and “Partnership, Company and Individual Performance Criteria.” Since we and PVR reimburse Penn Virginia for a portion of the Shared Executives’ compensation based on the amount of time they devote to us and PVR, our Committee and the PVR Committee review the amount of the Shared Executives’ time allocable to us and PVR each year and determine whether such time allocations are reasonable in light of the business conducted by us and PVR during such year.
Peer Benchmarks for PVR. In December 2007, the PVR Committee engaged BDO Seidman LLP, or BDO Seidman, as its independent consultant to assist it in a general review of the compensation packages for the NEOs. BDO Seidman identified a peer group of 13 publicly traded limited partnerships, referred to herein as the “BDO Peer Group,” against which to benchmark the compensation of the NEOs. The BDO Peer Group includes Alliance Resource Partners, L.P., AmeriGas Partners, L.P., Boardwalk Pipeline Partners, LP, Copano Energy, L.L.C., Crosstex Energy, L.P., Ferrellgas Partners, L.P., Inergy Holdings, L.P., Magellan Midstream Partners, L.P., MarkWest Energy Partners, L.P., Natural Resource Partners L.P., NuStar Energy L.P., Regency Energy Partners LP and Sunoco Logistics Partners L.P. Based on the analysis of base salaries, target bonuses and target long-term compensation opportunities of the BDO Peer Group, the total target compensation of each of the NEOs is appropriate in relation to the BDO Peer Group, but PVR’s overall cost of management is significantly lower than that of the BDO Peer Group because PVR reimburses Penn Virginia for only a portion of the Shared Executives’ compensation.
During 2007, Penn Virginia also performed an internal analysis of PVR’s peer compensation practices principally as related to chief operating officers, such as the PVR Executives, who devote substantially all of their time to such peers. Ms. Snyder and Penn Virginia’s Vice President, Human Resources worked with the PVR Executives and other PVR personnel to identify a peer group for PVR, comprised of 18 publicly traded limited partnerships, referred to herein as the “PVR Peer Group,” which are comparable to PVR based on market capitalization and type and geographic location of operations. The PVR Peer Group consists of Alliance Resource Partners, L.P., Atlas Pipeline Partners, L.P., Boardwalk Pipeline Partners, LP, Buckeye Partners, L.P., Copano Energy, L.L.C., Crosstex Energy, L.P., DCP Midstream Partners, LP, Enbridge Energy Partners, L.P., Energy Transfer Partners, L.P. Hiland Partners, LP, MarkWest Energy Partners, L.P., Magellan Midstream Partners, L.P., Natural Resource Partners L.P., Nustar Energy L.P., ONEOK Partners, L.P., Regency Energy Partners LP, Sunoco Logistics Partners L.P. and TEPPCO Partners, L.P. Penn Virginia studied what the PVR Peer Group actually paid to executives during or with respect to 2006, as reflected in 2007 annual reports on Form 10-K, and during 2007, as reflected in current reports on Form 8-K. The results of Penn Virginia’s analysis were generally consistent with the results of BDO Seidman’s analysis in that Penn Virginia’s analysis showed that the total compensation of the PVR Executives falls between the 50th and 75th percentile of the PVR Peer Group, but that PVR’s overall cost of management is significantly lower than that of the PVR Peer Group because PVR reimburses Penn Virginia for only a portion of the Shared Executives’ compensation. See “How Compensation is Determined—Partnership, Company and Individual Performance Criteria” for information regarding the competitive compensation positioning of individual NEOs.
Peer Benchmarks for Penn Virginia. In December 2007, the Penn Virginia Committee engaged Hewitt Associates LLC, or Hewitt, as its independent compensation consultant to assist it in a general review of the compensation packages for the Shared Executives and the president of Penn Virginia’s oil and gas subsidiary. As part of its analysis, Hewitt discussed with each of these Penn Virginia executives PVR’s and Penn Virginia’s businesses and Penn Virginia’s current compensation practices. Hewitt identified a peer group, referred to herein as the “Hewitt Peer Group,” against which to benchmark the compensation of these Penn Virginia executives. The Hewitt Peer Group, which is comprised of 18 oil and gas companies included in Hewitt’s oil and gas compensation database and similar to Penn Virginia based on revenues, assets, capitalization, scope of operations and total shareholder return, includes Berry Petroleum Company, Cabot Oil & Gas Corporation, Cimarex Energy Co., Comstock Resources, Inc., Denbury Resources Inc., Encore Acquisition Company, Forest Oil Corporation, Goodrich Petroleum Corporation, Petroleum Development Corporation, PetroQuest Energy, Inc., Plains Exploration & Production Company, Quicksilver Resources Inc., Range Resources Corporation, Southwestern Energy Company, St. Mary
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Land & Exploration Company, Stone Energy Corporation, Swift Energy Company and Whiting Petroleum Corporation. Based on the analysis of base salaries, target bonuses and target long-term compensation opportunities of the Hewitt Peer Group, total 2007 compensation opportunities for the Shared Executives and the president of Penn Virginia’s oil and gas subsidiary, as a group, were 11% below the 25th percentile, and 43% below the 50th percentile, of the Hewitt Peer Group.
During 2007, Penn Virginia also performed an internal analysis of its peer compensation practices. Ms. Snyder and Penn Virginia’s Vice President, Human Resources worked with the president of Penn Virginia’s oil and gas subsidiary and Penn Virginia’s investor relations manager to identify a peer group of 17 oil and gas companies, referred to herein as the “Penn Virginia Peer Group,” which are comparable to Penn Virginia based on revenues, market capitalization and type and geographic location of operations, and some of which were also included in the Hewitt Peer Group. The Penn Virginia Peer Group includes Berry Petroleum Company, Bill Barrett Corporation, Cabot Oil & Gas Corporation, Carrizo Oil & Gas, Inc., Clayton Williams Energy, Inc., CNX Gas Corporation, Delta Petroleum Corporation, EXCO Resources, Inc., Goodrich Petroleum Corporation, Parallel Petroleum Corporation, Petrohawk Energy Corporation, PetroQuest Energy, Inc., Quicksilver Resources Inc., Range Resources Corporation, Southwestern Energy Company and St. Mary Land & Exploration Company. Penn Virginia studied what the Penn Virginia Peer Group actually paid to executives during or with respect to 2006, as reflected in 2007 proxy statements and annual reports on Form 10-K, and during 2007, as reflected in current reports on Form 8-K. The overall results of Penn Virginia’s analysis were generally consistent with the results of Hewitt’s analysis in that Penn Virginia’s analysis showed that the total compensation of the Shared Executives and the president of Penn Virginia’s oil and gas subsidiary, as a group, was well below the 50th percentile of the Company Peer Group. See “How Compensation is Determined—Partnership, Company and Individual Performance Criteria” for information regarding the competitive compensation positioning of individual NEOs.
Partnership, Company and Individual Performance Criteria. The Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, targets the amount of salary, cash bonus and long-term compensation awards for each NEO at approximately the 50th percentile of comparable executives of PVR’s peers, in the case of the PVR Executives, or comparable executives of Penn Virginia’s peers, in the case of the Shared Executives. However, given the importance of executive accountability for PVR’s and Penn Virginia’s performance as well as for individual performance, our Committee, the Penn Virginia Committee and the PVR Committee recognize that compensation for any NEO could exceed such 50th percentile targets, reflecting a reward for exceptional PVR, Penn Virginia or individual performance, or be lower than such 50th percentile targets, reflecting PVR, Penn Virginia or individual underperformance. To measure specific performance, the Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, uses certain quantitative PVR and Penn Virginia performance criteria and certain quantitative and qualitative individual performance criteria which measure achievement and contribution to PVR or Penn Virginia. Our Committee, the Penn Virginia Committee and the PVR Committee believe that these performance criteria for each NEO are focused on factors over which such NEO has some control and which should have a positive effect on PVR’s and Penn Virginia’s operations and on the price of our or PVR’s common units or Penn Virginia’s common stock. The weight given any one criterion and the mix of criteria included in determining amounts of compensation vary among the NEOs depending on their positions and principal areas of responsibility. The relevance and the relative importance of any of these criteria change from time to time, even within the same year, depending on PVR’s and Penn Virginia’s strategic objectives, operational needs and general business and regulatory environments. For this reason, the Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, may change these performance criteria from year to year, may assign an aggregate weight to several performance criteria applicable to a NEO or may consider adding criteria which were not known at the time the original criteria were established, or deleting criteria which became obsolete or unimportant.
Compensation of A. James Dearlove, President and CEO. In February 2008, the Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, set Mr. Dearlove’s 2008 base salary at $450,000, representing a 18.4% increase over his 2007 base salary. This increase was based on the results of Hewitt’s and Penn Virginia’s peer compensation studies, which showed that Mr. Dearlove’s 2007 salary was not industry-competitive in that it was below the 25th percentile of the Hewitt Peer Group and significantly below the 50th percentile of the Penn Virginia Peer Group. The Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, also awarded to Mr. Dearlove a cash bonus of $550,000, or approximately 145% of his 2007 base salary, and a long-term compensation award valued at $2,000,000, or approximately 526% of his base salary. We reimbursed Penn Virginia for 11% of Mr. Dearlove’s 2007-related bonus and long-term compensation awards, or $60,500 and $220,000, and PVR reimbursed Penn Virginia for 38% of Mr. Dearlove’s 2007-related cash bonus and long-term compensation awards, or $209,000 and $760,000. In making 2007-related bonus and long-term compensation awards to Mr. Dearlove in these amounts, the Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, considered PVR’s, Penn Virginia’s and his performance against the following criteria:
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| CORPORATE AND PARTNERSHIP CRITERIA |
GOAL |
PERFORMANCE | ||
| Growth in PVR’s distributable cash flow per unit from December 31, 2006 to December 31, 2007 (1) | Target – $1.93 Stretch – $2.05 |
Exceeded target by $0.04 per unit | ||
| Growth in Penn Virginia’s net asset value per share from December 31, 2006 to December 31, 2007 (2) | Target – 11% Stretch – 15% |
Exceeded stretch by 33% | ||
| INDIVIDUAL CRITERIA |
ASSESSMENT | |||
| Continually assess and modify our, Penn Virginia’s and PVR’s strategy as needed to accommodate changes in energy and general business environments | Principal architect of our, Penn Virginia’s and PVR’s individual and collective strategies as presented to the board of directors of our general partner, Penn Virginia’s board of directors and the board of directors of PVR’s general partner
Facilitated Penn Virginia’s strategy to grow through the drillbit by directing planning and budgeting of approximately $428 million for development and exploratory drilling in 2008 and spending of $520 million for development and exploratory drilling in 2007
Promoted Penn Virginia’s strategy to increase lower-risk drilling inventory by overseeing ten acquisitions, or the “Oil and Gas Acquisitions,” of an aggregate of approximately $130 million of oil and gas assets principally in East Texas Cotton Valley, Mid-Continent and Mississippi Selma Chalk
Promoted both PVR’s and Penn Virginia’s strategy to utilize PVR’s relationship with each other and PVR’s strategy to diversify revenues by facilitating and overseeing Penn Virginia’s tax efficient disposition to us of $31 million of non-core oil and gas royalty interests and execution of agreement under which PVR will gather and process Penn Virginia’s gas through PVR’s newly constructed East Texas gas processing plant, or, together, the “PVA/PVR Transactions”
Promoted PVR’s strategy to grow coal reserves and diversify its business by overseeing four acquisitions, or the “PVR Coal Acquisitions,” whereby PVR’s coal and natural resource management division, or “PVR Coal,” acquired approximately 70 million tons of coal reserves, 62,000 acres of prime forestland and the oil and gas royalty interests described above
Promoted PVR’s strategy to expand its natural gas midstream operations by overseeing execution of agreement by PVR’s natural gas midstream division, or “PVR Midstream,” to purchase a pipeline, or the “Midstream Transaction,” expected to expand our gas gathering and processing footprint, expansion of two of PVR Midstream’s existing processing facilities and construction of new processing plant in East Texas
Oversaw strategic rebalancing of Penn Virginia’s capital structure through December 2007 $172.5 million common stock/$230 million convertible notes dual tranche public offering, or the “Dual Tranche Offering”
Recognized advantage of us as financial partner to PVR to facilitate significant transactions and helped create several possible structures to accomplish this in future transactions | |||
| Increase Penn Virginia’s market value per barrel of oil and Mcf of natural gas | Oversaw aggressive investor relations program, aggressive and successful oil and gas development program and our December 2006 initial public offering, which Penn Virginia believes defined our value to Penn Virginia and caused an increase in its stock price unrelated to our market value | |||
| Work with Penn Virginia’s board of directors to maintain current succession plan for CEO position | Succession plan and internal candidate assessments reviewed with Penn Virginia’s board of directors on annual and as-needed basis | |||
| Represent us, Penn Virginia and PVR to investment community | Eight quarterly public teleconferences and eight investor conferences, including more than 70 “one-on-one” investor meetings, three sales force presentations and four road shows held during 2007 | |||
| Ensure ethical “tone at the top” regarding compliance by us, Penn Virginia and PVR with all applicable laws, rules and regulations | We, Penn Virginia and PVR have excellent regulatory and ethical track record | |||
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| Other considerations |
Penn Virginia’s stock price rose by approximately 25% in 2007
Penn Virginia’s 2007 total shareholder return was near the 75th percentile of Hewitt Peer Group
Significant complexity of managing three separate publicly traded entities engaged in multiple businesses | |||
| (1) | “Distributable cash flow per unit,” as PVR and Penn Virginia compute it, is equal to (x) the sum of PVR’s (A) operating income plus (B) DD&A expenses minus (y) the sum of PVR’s (A) interest expense plus (B) maintenance capital expenditures, divided by (z) the total number of PVR common units issued and outstanding. |
| (2) | “Net asset value per share,” as Penn Virginia computes it, is equal to (x) the value of Penn Virginia’s proved oil and natural gas reserves and other assets (principally, the market value of Penn Virginia’s ownership interest in us), minus (y) Penn Virginia’s debt not related to PVR, divided by (z) the total number of shares of Penn Virginia’s common stock issued and outstanding. |
In addition to the assessments described above, the Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, considered Hewitt’s market data which showed that Mr. Dearlove’s target total cash compensation, including the portions reimbursed to Penn Virginia by us and PVR, was below the 25th percentile, and his target long-term compensation, including our and PVR’s portions, was well below the 50th percentile, of CEOs in the Hewitt Peer Group. Penn Virginia’s internal compensation analysis had similar results showing that neither Mr. Dearlove’s total compensation nor his long-term compensation, including the portions reimbursed to Penn Virginia by us and PVR, was industry-competitive. The Penn Virginia Committee believes, and Hewitt’s data confirmed, that the amounts of 2007-related bonus and long-term compensation awarded to Mr. Dearlove, when combined with his 2008 base salary, comprise an industry-competitive compensation package that falls at approximately the 50th percentile of CEOs in the Hewitt Peer Group. Further, the Penn Virginia Committee believes that this compensation appropriately reflects our, Penn Virginia’s and Mr. Dearlove’s 2007 performance. Our Committee and the PVR Committee reviewed Mr. Dearlove’s time allocated to us and PVR during 2007 and concluded that such allocations were reasonable given the business conducted by us and PVR during 2007.
Compensation of Frank A. Pici, Vice President and CFO. In February 2008, the Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, set Mr. Pici’s 2008 base salary at $275,000, representing a 4.6% increase over his 2007 base salary. The Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, also awarded Mr. Pici a cash bonus of $220,000, or approximately 84% of his 2007 base salary, and a long-term compensation award valued at $800,000, or approximately 304% of his 2007 base salary. We reimbursed Penn Virginia for 4% of Mr. Pici’s 2007-related cash bonus and long-term compensation awards, or $8,800 and $32,000, and PVR reimbursed Penn Virginia for 28% of Mr. Pici’s 2007-related cash bonus and long-term compensation awards, or $61,600 and $224,000. In making 2007-related bonus and long-term compensation awards to Mr. Pici in these amounts, the Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, considered PVR’s, Penn Virginia’s and his performance against the following criteria:
| CORPORATE AND PARTNERSHIP CRITERIA |
GOAL |
PERFORMANCE | ||
| Growth in PVR’s distributable cash flow per unit from December 31, 2006 to December 31, 2007 | Target – $1.93 Stretch – $2.05 |
Exceeded target by $0.04 per unit | ||
| Growth in Penn Virginia’s net asset value per share from December 31, 2006 to December 31, 2007 | Target – 11% Stretch – 15% |
Exceeded stretch by 33% | ||
| INDIVIDUAL CRITERIA |
ASSESSMENT | |||
| Contribute to formulating and executing individual and overall strategies for us, Penn Virginia and PVR and define financial role, if any, for us | Contributed to formulation of individual and overall strategies for us, Penn Virginia and PVR
Championed and oversaw strategic and financial analyses related to rebalancing Penn Virginia’s capital structure through Dual Tranche Offering, including cost-reducing complex call spread structure
Helped create possible structures to accomplish financial role for us in significant PVR acquisitions | |||
| Oversee financial planning, modeling and evaluation of potential acquisitions by PVR and Penn Virginia and promote efficiency in any transactions between PVR and Penn Virginia | Contributed to or oversaw strategic and economic evaluations of all Oil and Gas Acquisitions, PVA/PVR Transactions, PVR Coal Acquisitions and Midstream Transaction
Oversaw significant improvement in financial planning models | |||
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| Promoted efficiency of financial analyses in PVA/PVR Transactions | ||||
| Monitor and, if necessary, set hedging policy for PVR’s natural gas midstream business and Penn Virginia’s oil and gas exploration and production business and set policy for SOX compliance | Current hedging policies for PVR Midstream’s and Penn Virginia’s businesses in place and monitored regularly
SOX compliance policies in place, and we, Penn Virginia and PVR have had no SOX-related regulatory compliance problems | |||
| Develop succession plan for the position of CFO | Assessment of internal candidates reviewed with CEO annually | |||
| Overall responsibility for finance, accounting, tax, audits, investor relations and information technology | Oversaw conversion to new accounting system
Excellent relationship with PVR’s and Penn Virginia’s bank groups comprised of 21 banks
Expanded and improved investor relations function
Expanded and improved structure and efficiency of financial planning group | |||
| Other considerations | Penn Virginia’s stock price rose by approximately 25% in 2007
Penn Virginia’s 2007 total shareholder return was near the 75th percentile of Hewitt Peer Group
Significant complexity of managing finance, tax, accounting, treasury, investor relations and information technology-related aspects of three separate publicly traded entities engaged in multiple businesses | |||
In addition to the assessments described above, the Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, considered Hewitt’s market data which showed that Mr. Pici’s target total cash compensation, including the portions reimbursed to Penn Virginia by us and PVR, was not industry-competitive in that it was below the 25th percentile, and his target long-term compensation, including our and PVR’s portions, was well below the 50th percentile, of the Hewitt Peer Group. Penn Virginia’s internal compensation analysis showed that, including our and PVR’s portions, Mr. Pici’s actual total cash compensation was generally industry-competitive, but his long-term compensation was not competitive. The Penn Virginia Committee believes, and Hewitt’s data confirmed, that the amounts of 2007-related bonus and long-term compensation awarded to Mr. Pici, when combined with his 2008 base salary, comprise an industry-competitive compensation package that falls at approximately the 50th percentile of CFOs in the Hewitt Peer Group. Further, the Penn Virginia Committee believes that this compensation appropriately reflects PVR’s, Penn Virginia’s and Mr. Pici’s 2007 performance. Our Committee and the PVR Committee reviewed Mr. Pici’s time allocated to us and PVR during 2007 and concluded that such allocations were reasonable given the business conducted by us and PVR during 2007.
Compensation of Nancy M. Snyder, Vice President and General Counsel. In February 2008, the Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, set Ms. Snyder’s 2008 base salary at $265,000, representing a 15.2% increase over her 2007 base salary. This increase was based on the results of Hewitt’s and Penn Virginia’s peer compensation analyses, which showed that Ms. Snyder’s 2007 salary was below the 25th percentile of the Hewitt Peer Group and significantly below the 50th percentile of the Penn Virginia Peer Group, and also on the fact that Ms. Snyder’s responsibilities were expanded in October 2007 to include managing Penn Virginia’s human resources department. The Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, also awarded Ms. Snyder a cash bonus of $215,000, or approximately 93% of her 2007 base salary, and a long-term compensation award valued at $800,000, or approximately 348% of her 2007 base salary. We reimbursed Penn Virginia for 6% of Ms. Snyder’s 2007-related cash bonus and long-term compensation awards, or $12,900 and $48,000, and PVR reimbursed Penn Virginia for 33% of Ms. Snyder’s 2007-related cash bonus and long-term compensation awards, or $70,950 and $264,000. In making 2007-related bonus and long-term compensation awards to Ms. Snyder in these amounts, the Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, considered PVR’s, Penn Virginia’s and her performance against the following criteria:
| CORPORATE AND PARTNERSHIP CRITERIA |
GOAL |
PERFORMANCE | ||
| Growth in PVR’s distributable cash flow per unit from December 31, 2006 to December 31, 2007 | Target – $1.93 Stretch – $2.05 |
Exceeded target by $0.04 per unit | ||
| Growth in Penn Virginia’s net asset value per share from December 31, 2006 to December 31, 2007 | Target – 11% Stretch – 15% |
Exceeded stretch by 33% | ||
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| INDIVIDUAL CRITERIA |
ASSESSMENT | |||
| Negotiate issues related to PVR’s and Penn Virginia’s acquisitions, dispositions and other transactions | Negotiated or oversaw negotiation of Dual Tranche Offering, all Oil and Gas Acquisitions, PVA/PVR Transactions, PVR Coal Acquisitions and Midstream Transaction, numerous final acquisition bids, joint operating agreements, master service agreements, gas processing and transportation agreements, leases, easements and other day-to-day transactions
All Oil and Gas Acquisitions, PVA/PVR Transactions, PVR Coal Acquisitions and Midstream Transaction completed in-house with outside counsel retained only with respect to local title opinions or advice related to specialties such as tax and local environmental matters | |||
| Facilitate efficiency of transactions between PVR and Penn Virginia | PVA/PVR Transactions accomplished and potential conflicts identified and resolved | |||
| Advise PVR and Penn Virginia with respect to business and strategic transactional issues | Contributed to formulation of our, Penn Virginia’s and PVR’s individual and collective strategy in general and with respect to all transactions described above | |||
| Advise and assist other officers of our general partner, Penn Virginia and PVR’s general partner regarding day-to-day legal matters, including those related to banking, insurance and financing | Advised regarding negotiation of call spread structure in Dual Tranche Offering and advised regarding, or completed or oversaw in-house completion of, several credit agreement amendments for PVR and Penn Virginia and renewal of PVR’s and Penn Virginia’s directors and officers liability and other insurance policies | |||
| Oversee regulatory compliance and governance requirements for us, Penn Virginia and PVR | We, Penn Virginia and PVR have excellent legal compliance track record
Monitored and reacted in timely manner to changes in laws, rules and regulations
Reviewed and suggested amendment, as necessary, of all governance and other documents, including committee charters, codes of conduct, whistleblower policies, trading policies and equity plans for us, Penn Virginia and PVR | |||
| Oversee outside legal counsel, in-house legal staff and corporate secretary function | Oversaw outside litigation or dispute related work with five positive outcomes in five disputes
Directed outside counsel with respect to Dual Tranche Offering
Oversaw in-house legal staff, which, in addition to transactional work and day-to-day contractual matters, reviewed or prepared our, Penn Virginia’s and PVG’s periodic filings and governance documents, including more than 48 Form 8-Ks, 92 sets of board and committee minutes and 175 Form 4s | |||
| Other considerations | Penn Virginia’s stock price rose by approximately 25% in 2007
Penn Virginia’s 2007 total shareholder return was near the 75th percentile of Hewitt Peer Group
Expanded and improved structure and efficiency of human resource department Oversaw compensation peer group analyses
Good ability to select and manage personnel
Significant complexity of managing legal, human resource aspects, as well as corporate secretary function, of three separate publicly traded entities engaged in multiple businesses | |||
In addition to the assessments described above, the Penn Virginia Committee, with the assistance of our Committee and the PVR Committee, considered Hewitt’s market data which showed that Ms. Snyder’s target total cash compensation, including the portions reimbursed to Penn Virginia by us and PVR, was below the 25th percentile and her target long-term compensation, including our and PVR’s portions, was well below the 50th percentile of the Hewitt Peer Group. Penn Virginia’s internal compensation analysis showed that her actual total cash compensation was generally industry-competitive, but her actual long-term compensation was not competitive. The Penn Virginia Committee believes, and the Company Peer Group data confirmed, that the amounts of 2007-related bonus and long-term compensation awarded to Ms. Snyder, when combined with her 2008 base salary, comprise an industry-competitive compensation package that falls at approximately the 50th percentile of general counsels in the Company Peer Group who have responsibilities comparable to those of Ms. Snyder. Further, the Penn Virginia Committee believes that this compensation appropriately reflects PVR’s, Penn Virginia’s and Ms.
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Snyder’s 2007 performance. Our Committee and the PVR Committee reviewed Ms. Snyder’s time allocated to us and PVR during 2007 and concluded that such allocations were reasonable given the business conducted by us and PVR during 2007.
Compensation of Keith D. Horton, Chief Operating Officer—Coal. In February 2008, the PVR Committee, with the assistance of the our Committee, recommended and the Penn Virginia Committee set Mr. Horton’s 2008 base salary at $280,000, representing a 3.7% increase over his 2007 base salary. The PVR Committee, with the assistance of our Committee, also recommended and the Penn Virginia Committee, with the concurrence of the PVR Committee, awarded Mr. Horton a cash bonus of $185,000, or approximately 69% of his 2007 base salary, and a long-term compensation award valued at $400,000, or approximately 148% of his 2007 base salary. PVR paid all of Mr. Horton’s 2007-related bonus and long-term compensation awards. In recommending or making 2007-related bonus and long-term compensation awards to Mr. Horton in these amounts, the PVR Committee and the Penn Virginia Committee, with the assistance of our Committee, considered PVR’s and his performance against the following criteria:
| PARTNERSHIP CRITERIA |
GOAL |
PERFORMANCE | ||
| Increase in PVR’s coal and natural resource management-related EBITDA from December 31, 2006 to December 31, 2007 | Target – $94 million Stretch – $98 million |
EBITDA 2% under target, but exceeded budget of $91.2 million by approximately 1% | ||
| Increase in PVR’s coal reserves from December 31, 2006 to December 31, 2007 | Target – 100 million tons Stretch – 150 million tons |
Coal reserves increased by 70 million tons, but also completed strategically important $93 million acquisition of 62,000 acres of prime forestland and $30 million acquisition of oil and gas royalty interests which diversified PVR’s revenues sources | ||
| Increase in revenues from non-coal reserve assets, such as railcar loading facilities, processing plants and other infrastructure and timber from December 31, 2006 to December 31, 2007 | Target – $9 million Stretch – $11 million | Non-coal reserve revenues increased by $8 million Evaluated acquiring or constructing several river terminals and loadout facilities Worked to expand efforts of Coal Handling Solutions LLC, PVR’s coal handling joint venture with Massey Energy Company | ||
| INDIVIDUAL CRITERIA |
ASSESSMENT | |||
| Develop a succession plan |
Assessment of internal candidates reviewed with CEO annually | |||
| Other considerations |
PVR increased distributions by 10% during 2007
PVR had record distributable cash flow in 2007 | |||
| (1) | PVR and Penn Virginia define coal and natural resource management-related EBITDA as the sum of coal and natural resource management segment-related (x) operating income plus (y) DD&A expenses. |
In addition to the assessments described above, the PVR Committee and the Penn Virginia Committee, with the assistance of our Committee, considered BDO Seidman’s market data which showed that Mr. Horton’s total target cash compensation was industry-competitive and Penn Virginia’s internal compensation analysis which showed that Mr. Horton’s actual total compensation was industry-competitive. The PVR Committee and the Penn Virginia Committee believe, and BDO Seidman’s data confirmed, that the amounts of 2007-related bonus and long-term compensation awarded to Mr. Horton, when combined with his 2008 base salary, continue to comprise an industry-competitive compensation package that falls between the 50th and 75th percentiles of chief operating officers in the BDO Peer Group and the PVR Peer Group. Further, the PVR Committee and the Penn Virginia Committee believe that this compensation appropriately reflects PVR’s and Mr. Horton’s 2007 performance. These amounts also reflect Mr. Horton’s strong leadership abilities, significant industry experience, tenure at PVR and PVR’s desire to retain his services, as well as the PVR Committee’s and the Penn Virginia
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Committee’s desire to facilitate, to the extent reasonable and appropriate, the opportunity for all of the NEOs to earn reasonably comparable compensation notwithstanding that they work in different industries that have different compensation practices.
Compensation of Ronald K. Page, Chief Operating Officer—Midstream. In February 2008, the PVR Committee, with the assistance of our Committee, recommended and the Penn Virginia Committee set Mr. Page’s 2008 base salary at $260,000, representing a 10.6% increase over his 2007 base salary. Since Mr. Page has responsibilities similar to those of Mr. Horton, the PVR Committee, with the assistance of our Committee, recommended, and the Penn Virginia Committee agreed, that Mr. Page’s base salary should be increased to amount comparable to Mr. Horton’s 2008 base salary. The PVR Committee, with the assistance of our Committee, also recommended and the Penn Virginia Committee, with the concurrence of the PVR Committee, awarded Mr. Page a cash bonus of $170,000, or approximately 72% of his 2007 base salary, and a long-term compensation award valued at $400,000, or approximately 170% of his 2007 base salary. PVR paid all of Mr. Page’s 2007-related bonus and long-term compensation awards. In recommending or making 2007-related bonus and long-term compensation awards to Mr. Page in these amounts, the PVR Committee and the Penn Virginia Committee considered PVR’s and his performance against the following criteria:
| PARTNERSHIP CRITERIA |
GOAL |
PERFORMANCE | ||
| Increase in PVR’s natural gas midstream-related EBITDA from December 31, 2006 to December 31, 2007 | Target – $51.3 million Stretch – $54 million |
Exceeded stretch by 3.7% | ||
| Increase in PVR’s 2007 natural gas midstream-related EBITDA from acquisitions completed during 2007 | Target – $5 million Stretch – $10 million |
PVR Midstream completed no acquisitions in 2007 | ||
| INDIVIDUAL CRITERIA |
ASSESSMENT | |||
| Complete Spearman plant expansion by October 2007 and complete evaluation of construction of new processing plant in East Texas, or the “New East Texas Plant” | Spearman expansion expected to be completed in March 2008 due to equipment delivery issues New East Texas Plant expected to begin operating in April 2008 | |||
| Expand size and reach of existing facilities | Expended $38.7 million in 2007 expansion projects resulting in increase of 140 MMcfd of inlet gas capacity | |||
| Identify and complete joint venture opportunities with Penn Virginia Oil & Gas Corporation, or “PVOG” | Completed transaction whereunder PVR Midstream will gather and process PVOG’s East Texas gas through New East Texas Plant | |||
| Develop a succession plan | Succession plan developed, time and effort spent to develop personnel and assessment of internal candidates reviewed with CEO annually | |||
| Other considerations | PVR increased distributions by 10% during 2007 PVR had record distributable cash flow in 2007 PVR Midstream creative and aggressive in developing and pursing new opportunities | |||
| (1) | PVR and Penn Virginia define natural gas midstream-related EBITDA as the sum of natural gas midstream segment-related (x) operating income plus (y) DD&A expenses. |
In addition to the assessments described above, the PVR Committee and the Penn Virginia Committee, with the assistance of our Committee, considered BDO Seidman’s market data which showed that Mr. Page’s total target cash compensation was industry-competitive and Penn Virginia’s internal compensation analysis which showed that Mr. Page’s actual total compensation was industry-competitive. The PVR Committee and the Penn Virginia Committee believe, and BDO Seidman’s data confirmed, that the amounts of 2007-related bonus and long-term compensation awarded to Mr. Page, when combined with his 2008 base salary, continue to comprise an industry-competitive compensation package that falls between the 50th and 75th percentiles of chief operating officers in the BDO Peer Group and the PVR Peer Group. Further, the PVR Committee and the Penn Virginia Committee believe that this compensation appropriately reflects PVR’s and Mr. Page’s 2007 performance. These amounts also reflect Mr. Page’s strong leadership abilities, significant industry experience and PVR’s desire to retain his services, as well as the PVR Committee’s and the Penn Virginia Committee’s desire to facilitate, to the extent reasonable and appropriate, the opportunity for all of the NEOs to earn reasonably comparable compensation notwithstanding that they work in different industries that have different compensation practices.
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Summary Compensation Table
The following table sets forth the compensation paid by us and PVR for services rendered to us and our subsidiaries, during or with respect to the years ended December 31, 2007 and 2006, to (i) our CEO, our CFO and our one other executive officer and (ii) for the reasons previously stated under “Compensation Structure,” two executive officers of PVR’s general partner:
Summary Compensation Table
| Name and Principal Position |
Year | Salary ($) |
Bonus ($) |
Stock Awards ($) (1) |
All Other Compensation ($) (2) |
Total ($) | ||||||
| A. James Dearlove President and Chief Executive Officer |
2007 | 186,200 | 269,500 | 257,859 | 19,196 | 732,755 | ||||||
| 2006 | 183,500 | 185,000 | 253,348 | 19,024 | 640,872 | |||||||
| Frank A. Pici Vice President and Chief Financial Officer |
2007 | 84,160 | 70,400 | 136,006 | 10,862 | 301,428 | ||||||
| 2006 | 80,960 | 65,600 | 125,175 | 10,200 | 281,935 | |||||||
| Keith D. Horton Co-President and Chief Operating Officer—Coal of PVR’s general partner |
2007 | 270,000 | 185,000 | 279,457 | 34,228 | 768,685 | ||||||
| 2006 | 260,000 | 182,000 | 261,957 | 32,528 | 736,485 | |||||||
| Ronald K. Page Co-President and Chief Operating Officer—Midstream of PVR’s general partner |
2007 | 235,000 | 170,000 | 225,828 | 33,769 | 664,597 | ||||||
| 2006 | 220,000 | 150,000 | 151,644 | 32,104 | 553,748 | |||||||
| Nancy M. Snyder Vice President and General Counsel |
2007 | 89,700 | 83,850 | 124,830 | 13,349 | 311,729 | ||||||
| 2006 | 94,600 | 77,400 | 110,444 | 13,987 | 296,431 | |||||||
| (1) | Represents the amounts of expense recognized by us in 2007 and 2006 for financial statement reporting purposes with respect to restricted PVR units previously granted by the PVR Committee to the NEOs in consideration for services rendered to PVR. These amounts were computed in accordance with SFAS No. 123(R), Share-Based Payment, and were based on the NYSE closing prices of PVR’s common units on the dates of grant. See Note 15 in the Notes to Consolidated Financial Statements. |
| (2) | Reflects amounts paid or reimbursed by us and PVR for (i) automobile allowances, executive health exams and life insurance premiums and (ii) matching and other contributions to the NEOs’ 401(k) Plan accounts. |
The cash components of our executive compensation consist of a base salary and the opportunity to earn an annual cash bonus. See “Compensation Discussion and Analysis—Elements of Compensation.” The amounts of salary and bonus reflected in the Summary Compensation Table above include only amounts paid or reimbursed by us and PVR in consideration for services rendered to us or PVR by the NEOs and do not include any amounts paid by Penn Virginia to any of the NEOs in consideration for services rendered to Penn Virginia. The specific portions of salary and bonus paid, or reimbursed to Penn Virginia, by us and PVR depend on the portions of professional time devoted by each NEO to us and PVR. See “Compensation and Discussion Analysis—Compensation Structure” for a description of the manner in which the NEOs are compensated. In 2007, Mr. Dearlove, Mr. Pici and Ms. Snyder devoted approximately 11%, 4% and 6% of his or her professional time to us and, accordingly, we reimbursed Penn Virginia for 11%, 4% and 6% of Mr. Dearlove’s, Mr. Pici’s and Ms. Snyder’s 2007 salary and 2007-related bonus. In 2007, Mr. Dearlove, Mr. Pici and Ms. Snyder devoted approximately 38%, 28% and 33% of his or her professional time to PVR and, accordingly, PVR reimbursed Penn Virginia for 38%, 28% and 33% of Mr. Dearlove’s, Mr. Pici’s and Ms. Snyder’s 2007 salary and 2007-related bonus. The Shared Executives did not devote any professional time to us in 2006. In 2006, Mr. Dearlove, Mr. Pici and Ms. Snyder devoted approximately 50%, 32% and 43% of his or her professional time to PVR and, accordingly, PVR reimbursed Penn Virginia for 50%, 32% and 43% of Mr. Dearlove’s, Mr. Pici’s and Ms. Snyder’s 2006 salary and 2006-related bonus. Because each of the PVR Executives devoted all of his professional time to PVR in 2007 and 2006, PVR paid all of his 2007 and 2006
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salaries and 2007- and 2006-related bonuses. For a discussion of the salaries and bonuses paid to the Shared Executives by Penn Virginia, see the Penn Virginia Proxy Statement relating to its 2008 Annual Meeting of Shareholders.
The equity components of our executive compensation program consist of the opportunity to earn awards of restricted units from PVR and stock options and restricted stock from Penn Virginia. Like the cash component of executive compensation, that portion of the value of each NEO’s equity-based compensation paid or reimbursed by us and PVR depends on the portion of professional time that each NEO devotes to us and PVR. The values of the stock awards reflected in the Summary Compensation Table above include only the values of restricted unit awards granted by the PVR Committee.
Grants of Plan-Based Awards
We did not make any plan-based awards to the NEOs in 2007. The following table sets forth the grant date and number of all restricted PVR units granted to the NEOs in 2007 by the PVR Committee with respect to services rendered to PVR in 2006:
2007 Grants of Plan-Based Awards
| Name |
Grant Date |
All Other Stock Awards: Number of Shares of Stock or Units (#) |
Grant Date Fair Value of Stock and Option Awards ($) | |||
| A. James Dearlove |
February 27, 2007 | 11,639 | 312,507 | |||
| Frank A. Pici |
February 27, 2007 | 4,529 | 121,604 | |||
| Keith D. Horton |
February 27, 2007 | 11,732 | 315,004 | |||
| Ronald K. Page |
February 27, 2007 | 9,870 | 265,010 | |||
| Nancy M. Snyder |
February 27, 2007 | 5,162 | 138,600 |
The values of PVR’s restricted units were based on the NYSE closing prices of PVR’s common units on the dates of grant. All restricted PVR units granted to the NEOs since 2005 vest over a three-year period, with one-third of each award vesting on the first, second and third anniversaries of the grant date unless (i) the restricted unitholder’s employment terminates for any reason other than death or retirement as provided in (ii) below, in which event any unvested restricted units are forfeited unless otherwise determined by the PVR Committee, or (ii) the restricted unitholder dies, retires after ten years of employment with PVR’s general partner or its affiliate and reaching age 62 or there occurs a change in control of PVR or PVR’s general partner, in which events all restrictions lapse. Restricted PVR units are valued based on the NYSE closing price of PVR’s common units on the grant date. The PVR Committee grants annual compensation-based restricted units during the first quarter of each year after the Penn Virginia Committee, with our Committee’s and the PVR Committee’s assistance, has concluded its analysis of executive compensation with respect to the preceding year. The PVR Committee also grants restricted units from time to time in connection with the hiring of new PVR-related employees and, while it has not done so, may consider such grants in connection with promotions or at such other times as it may deem appropriate. During 2007, PVR paid quarterly distributions ranging from $0.40 to $0.43 on each restricted PVR unit. The distributions were paid at the same times and in the same amounts as distributions paid to the other holders of PVR’s common units and were taken into consideration when determining the values of the restricted PVR units shown previously in the Summary Compensation Table and in the Grants of Plan-Based Awards Table above.
Outstanding Equity Awards at Fiscal Year-End
We do not have any equity awards that have not vested. The following table sets forth certain information regarding the numbers and values of restricted PVR units not vested as of December 31, 2007 held by the NEOs on December 31, 2007. The market value of non-vested restricted PVR units is based on the NYSE closing price of PVR’s common units on December 31, 2007.
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Outstanding Equity Awards at Fiscal Year-End 2007
| Stock Awards | ||||
| Name |
Number of Shares or Units of Stock That Have Not Vested (#) |
Market Value of Shares or Units of Stock That Have Not Vested ($) | ||
| A. James Dearlove | 21,269 (1) | 522,579 | ||
| Frank A. Pici | 10,305 (2) | 253,194 | ||
| Keith D. Horton | 22,770 (3) | 559,459 | ||
| Ronald K. Page | 18,550 (4) | 455,774 | ||
| Nancy M. Snyder | 10,022 (5) | 246,241 | ||
| (1) | Of these restricted units, 7,236 vested on February 27, 2008, 2,918 will vest on March 3, 2008, 7,236 will vest on February 27, 2009 and 3,879 will vest on February 27, 2010. |
| (2) | Of these restricted units, 3,540 vested on February 27, 2008, 1,716 will vest on March 3, 2008, 3,540 will vest on February 27, 2009 and 1,509 will vest on February 27, 2010. |
| (3) | Of these restricted units, 7,947 vested on February 27, 2008, 2,966 will vest on March 3, 2008, 7,947 will vest on February 27, 2009 and 3,910 will vest on February 27, 2010. |
| (4) | Of these restricted units, 6,404 vested on February 27, 2008, 2,452 will vest on March 3, 2008, 6,404 will vest on February 27, 2009 and 3,290 will vest on February 27, 2010. |
| (5) | Of these restricted units, 3,417 vested on February 27, 2008, 1,470 will vest on March 3, 2008, 3,415 will vest on February 27, 2009 and 1,720 will vest on February 27, 2010. |
Vesting of Restricted Units
The NEOs did not acquire any common units upon the vesting of restricted units during 2007. The following table sets forth the number of PVR common units acquired, and the values realized, by the NEOs upon the vesting of restricted PVR units during 2007:
Option Exercises and Stock Vested in 2007
| Stock Awards | ||||
| Name |
Number of Shares Acquired on Vesting (#) |
Value Realized on Vesting ($) | ||
| A. James Dearlove | 6,276 | 167,314 | ||
| Frank A. Pici | 3,746 | 99,877 | ||
| Keith D. Horton | 7,006 | 186,894 | ||
| Ronald K. Page | 5,566 | 148,442 | ||
| Nancy M. Snyder | 3,168 | 84,457 | ||
Nonqualified Deferred Compensation
The following table sets forth certain information regarding compensation paid by our general partner, PVR’s general partner and Penn Virginia and deferred by the NEOs under Penn Virginia’s Supplemental Employee Retirement Plan:
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2007 Nonqualified Deferred Compensation
| Name |
Executive Contributions in Last FY ($) (1) |
Registrant Contributions in Last FY ($) |
Aggregate Earnings in Last FY ($) (2) |
Aggregate Withdrawals/ Distributions ($) |
Aggregate Balance at Last FYE ($) (3) | |||||
| A. James Dearlove | 218,546 | 0 | 76,115 | 0 | 665,389 | |||||
| Frank A. Pici | 349,967 | 0 | 88,642 | 0 | 1,683,863 | |||||
| Keith D. Horton | 1,350 | 0 | 927 | 0 | 19,296 | |||||
| Ronald K. Page | 50,458 | 0 | 13,887 | 0 | 99,366 | |||||
| Nancy M. Snyder | 183,058 | 0 | 124,512 | 0 | 1,087,528 |
| (1) | All of these amounts are included in the amounts of salary and bonus for 2007 reported by us or Penn Virginia in the Summary Compensation Tables included in this Annual Report on Form 10-K and Penn Virginia’s Proxy Statement relating to its 2008 Annual Meeting of Shareholders. |
| (2) | These amounts are not reported in the Summary Compensation Table because they are not above-market or preferential earnings. |
| (3) | Except with respect to aggregate contributions by Penn Virginia of $22,923 on behalf of Mr. Pici in 2001 and 2002, these amounts reflect only salaries and bonuses paid to the NEOs and earnings on those salaries and bonuses. All such salary and bonus amounts were previously reported by us or Penn Virginia as compensation to the NEOs in the Summary Compensation Tables included in our Annual Reports on Form 10-K and Penn Virginia’s Proxy Statements. |
The Penn Virginia Corporation Supplemental Employee Retirement Plan, or the SERP, allows all of Penn Virginia’s and its affiliates’ employees, including employees of our general partner and PVR’s general partner, whose salaries exceeded $125,000 in 2007 to defer receipt of up to 100% of their salary, net of their salary deferrals under Penn Virginia’s 401(k) Plan, and up to 100% of their annual cash bonuses. The amounts reported in the Nonqualified Deferred Compensation Table above include not only contributions and earnings thereon related to deferred salaries and bonuses paid for services rendered to us, but also contributions and earnings thereon related to deferred salaries and bonuses paid for services rendered to Penn Virginia. All deferrals under the SERP are credited to an account maintained by Penn Virginia and are invested by Penn Virginia, at the employee’s election, in Penn Virginia’s common stock or in certain mutual funds made available by Penn Virginia and selected by the employee. Since all amounts deferred under the SERP consist of previously earned salary or bonus, all SERP participants are fully vested at all times in all amounts credited to their accounts. Amounts held in a participant’s account will be distributed to the participant on the earlier of the date on which such participant’s employment terminates or there occurs a change of control of Penn Virginia. Neither we nor Penn Virginia are required to make any contributions to the SERP. Since Penn Virginia established the SERP in 1996, it has contributed an aggregate of $27,308 in 2001 and 2002 to the SERP in connection with offers of employment to Mr. Pici and another executive of Penn Virginia, but has made no other contributions to the SERP.
Penn Virginia has established a rabbi trust to fund the benefits payable under the SERP. Other than the $27,308 of Penn Virginia contributions described above, the assets of the rabbi trust consist of the cash amounts of salary and bonus already earned and deferred by the NEOs and other employees under the SERP and the securities in which those amounts have been invested. Assets held in the rabbi trust are designated for the payment of benefits under the SERP and are not available for Penn Virginia’s general use. However, the assets held in the rabbi trust are subject to the claims of Penn Virginia’s general creditors, and SERP participants may not be paid in the event of Penn Virginia’s insolvency.
Long-Term Incentive Plans
Our Long-Term Incentive Plan
Our general partner has adopted the Amended and Restated PVG GP, LLC Long-Term Incentive Plan. Our long-term incentive plan permits the grant of awards covering an aggregate of 300,000 common units to employees and directors of our general partner and employees of its affiliates who perform services for us. Awards under our long-term incentive plan can be in the form of common units, restricted units, unit options, phantom units and deferred common units. Our long-term incentive plan is administered by our Committee.
Our general partner’s board of directors in its discretion may terminate or amend our long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Our general partner’s board of directors also has the right to alter or amend our long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to unitholder approval as required by the exchange upon which the common
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units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.
Common Units. Our long-term incentive plan permits the grant of common units to employees and directors. No grants of common units have been made under our long-term incentive plan.
Restricted Units. Our long-term incentive plan permits the grant of restricted units to employees and directors. No grants of restricted units have been made under our long-term incentive plan. Restricted units vest upon terms established by our Committee. In addition, all restricted units will vest upon a change of control of our general partner or us. If a grantee’s employment with, or membership on the board of directors of, our general partner terminates for any reason, the grantee’s unvested restricted units will be automatically forfeited unless, and to the extent, that our Committee provides otherwise. Distributions payable with respect to restricted units may, in our Committee’s discretion, be paid directly to the grantee or held by our general partner and made subject to a risk of forfeiture during the applicable restriction period.
Unit Options. Our long-term incentive plan permits the grant of options covering common units to employees and directors. No grants of unit options have been made under our long-term incentive plan. Unit options will have an exercise price that, in the discretion of our Committee, may be less than, equal to or more than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by our Committee. In addition, all unit options will become exercisable upon a change in control of our general partner or us. If a grantee’s employment with, or membership on the board of directors of, our general partner terminates for any reason, the grantee’s unit options will be automatically forfeited unless, and to the extent, that our Committee provides otherwise. Upon exercise of a unit option, our general partner will acquire common units in the open market or directly from us or any other person or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring these common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us.
Phantom Units. Our long-term incentive plan permits the grant of phantom units to employees and directors. No grants of phantom units have been made under our long-term incentive plan. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of our Committee, the cash equivalent of the value of a common unit. Our Committee will determine the time period over which phantom units granted to employees and directors will vest. In addition, all phantom units will vest upon a change of control of our general partner or us. If a grantee’s employment with, or membership on the board of directors of, our general partner terminates for any reason, the grantee’s phantom units will be automatically forfeited unless, and to the extent, our Committee provides otherwise. Common units delivered upon the vesting of phantom units may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. Our Committee, in its discretion, may grant tandem distribution equivalent rights with respect to phantom units.
Deferred Common Units. Our long-term incentive plan permits the grant of deferred common units to directors. Our general partner granted 13,396 deferred common units to directors of our general partner in 2007. Each deferred common unit represents one common unit, which vests immediately upon issuance and is available to the holder upon termination or retirement from the board of directors of our general partner. Common units delivered in connection with deferred common units may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. Deferred common units awarded to directors receive additional deferred common units equal in value to all cash or other distributions paid by us on account of our common units.
PVR Long-Term Incentive Plan
PVR’s general partner has adopted the Third Amended and Restated Penn Virginia Resource GP, LLC Long-Term Incentive Plan. PVR’s long-term incentive plan permits the grant of awards covering an aggregate of 600,000 PVR common units to employees and directors of PVR’s general partner and employees of its affiliates who perform services for PVR. Awards under the PVR long-term incentive plan can be in the form of PVR common units, restricted PVR units, PVR unit options, phantom PVR units and deferred PVR common units. The terms and conditions of the PVR long-term incentive plan are substantially the same as those of our long-term incentive plan described above. The PVR long-term incentive plan is administered by the PVR Committee. PVR’s general partner granted 1,183 PVR common units to a director of PVR’s
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general partner, 87,033 restricted PVR units to officers and employees of PVR’s general partner and 22,209 deferred PVR common units to directors of PVR’s general partner in 2007. No grants of PVR unit options or phantom PVR units have been made under the PVR long-term incentive plan. 1,267 restricted PVR units were forfeited in 2007.
Change-in-Control Arrangements
The PVR Committee, the Penn Virginia Committee, PVR and Penn Virginia believe that the PVR Executives, together with PVR’s other senior management and key employees, are a primary reason for PVR’s success and that it is important for PVR to protect them in the event that they lose their jobs under certain circumstances upon a change of control. Four of our five NEOs are age 54 or older, and the NEOs have served PVR or Penn Virginia for an average of more than 15 years, with Messrs. Dearlove and Horton and Ms. Snyder having served in various capacities for 30, 25 and 10 years. PVR and Penn Virginia also believe that, by providing change of control protection, the NEOs will be able to evaluate every PVR or Penn Virginia opportunity, including a change of control, that may likely result in the termination of their employment, without the distraction of personal considerations. For these reasons, PVR’s general partner has entered in change of control severance agreements with the PVR Executives, which entitle them to the benefits described below and which are substantially the same as the change of control severance agreements entered into between Penn Virginia and each of the Shared Executives. PVR and Penn Virginia have studied the executive severance arrangements of the PVR Peer Group and the Penn Virginia Peer Group, as described in their 2007 proxy statements and 2006 annual reports on Form 10-K, and found that the terms of PVR’s and Penn Virginia’s change of control severance agreements are comparable to those of PVR’s and Penn Virginia’s peers.
General Partner Executive Change of Control Severance Agreements
On March 9, 2006, PVR’s general partner entered into an Executive Change of Control Severance Agreement, or a General Partner Severance Agreement, with each of Messrs. Horton and Page containing the terms and conditions described below.
Term. Each General Partner Severance Agreement has a two-year term which is automatically extended for consecutive one-day periods until terminated by notice from PVR’s general partner. If such notice is given, the General Partner Severance Agreement will terminate two years after the date of such notice.
Triggering Events. Each General Partner Severance Agreement provides severance benefits to the PVR Executive upon the occurrence of two events, or the GP Triggering Events. Specifically, if a change of control of PVR’s general partner occurs and, within two years after the date of such change of control, either (a) the PVR Executive’s employment is terminated for any reason other than for cause or the PVR Executive’s inability to perform his duties for at least 180 days due to mental or physical impairment or (b) the PVR Executive terminates his employment due to a reduction in his authority, duties, title, status or responsibility, a reduction in his base salary, a discontinuation of a material incentive compensation plan in which he participated, the failure of PVR’s general partner to obtain an agreement from its successor to assume his General Partner Severance Agreement or his relocation by more than 100 miles of the office of PVR’s general partner at which he was working at the time of the change of control, then the PVR Executive may elect to receive the change of control severance payments and other benefits described below.
Change of Control Severance Benefits. Upon the occurrence of the GP Triggering Events, the PVR Executive may elect to receive a lump sum, in cash, of an amount equal to three times the sum of his annual base salary plus the highest cash bonus paid to him during the two-year period prior to termination, subject to reduction as described below under “Excise Taxes.” In addition, all options to purchase shares of Penn Virginia common stock then held by the PVR Executive will immediately vest and will remain exercisable for the shorter of three years or the remainder of the options’ respective terms and all restricted Penn Virginia stock and all restricted units then held by the PVR Executive will immediately vest and all restrictions will lapse. PVR’s general partner will also provide certain health and dental benefit-related payments to the PVR Executive as well as certain outplacement services. PVR’s general partner will not be entitled to reimbursement from PVR for any of the change of control severance payments or other benefits described in this paragraph.
Excise Taxes. The General Partner Severance Agreements do not include “gross up” benefits to cover excise taxes. If the independent registered public accountants of PVR’s general partner determine that any payments to be made or benefits to be provided to the PVR Executive under his General Partner Severance Agreement would result in him being subject to the excise tax imposed by Section 4999 of the Internal Revenue Code, such payments or benefits will be reduced to the extent necessary to prevent him from being subject to such excise tax.
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Restrictive Covenants and Releases. Each General Partner Severance Agreement prohibits the PVR Executive from (a) disclosing, either during or after his term of employment, confidential information regarding PVR’s general partner or its affiliates and (b) until two years after his employment has ended, soliciting or diverting business from PVR’s general partner or its affiliates. The General Partner Severance Agreement also requires that, upon payment of the severance benefits to the PVR Executive, the PVR Executive and PVR’s general partner release each other from all claims relating to the PVR Executive’s employment or the termination of such employment.
Estimated Payments
The following table sets forth the estimated aggregate payments by PVR’s general partner to each of Messrs. Horton and Page under his General Partner Severance Agreement assuming that there occurred a change of control of PVR’s general partner on December 31, 2007:
| Name of Executive Officer |
Estimate Severance Payment ($) | |
| Keith D. Horton | 1,993,233 | |
| Ronald K. Page | 1,673,474 |
Penn Virginia Executive Change of Control Severance Agreements
On February 27, 2006, Penn Virginia entered into an Executive Change of Control Severance Agreement, or a Penn Virginia Severance Agreement, with each of the Shared Executives containing terms and conditions substantially similar to those of the General Partner Severance Agreements. For a discussion of the terms and conditions of, and the estimated payments under, the Penn Virginia Severance Agreements, see the Penn Virginia Proxy Statement relating to its 2008 Annual Meeting of Shareholders. Any payments required to be made to the Shared Executives under the Penn Virginia Severance Agreements will be the sole responsibility of Penn Virginia.
Compensation of Directors
The following table sets forth the aggregate compensation paid by us to the non-employee directors of our general partner during 2007:
2007 Director Compensation
| Name |
Fees Earned or Paid in Cash ($) |
Stock Awards ($) (1) |
Total ($) | |||
| Robert Garrett | 31,000 | 90,000 (2) | 121,000 (3) | |||
| Robert J. Hall | 55,500 | 90,000 (4) | 145,500 (5) | |||
| John C. van Roden, Jr. | 59,000 | 90,000 (6) | 149,000 (7) | |||
| Jonathan B. Weller | 56,500 | 90,000 (8) | 146,500 (9) |
| (1) | Represents the amounts of expense recognized by us in 2007 for financial statement reporting purposes with respect to the deferred common units previously granted to the non-employee directors of our general partner. These amounts were computed in accordance with SFAS No. 123(R) and are based on the NYSE closing price of our common units on the dates of grant. See Note 15 in the Notes to Consolidated Financial Statements. |
| (2) | As of December 31, 2007, Mr. Garrett had 3,349 deferred common units outstanding. |
| (3) | Consists of (a) $90,000 annual retainer paid in deferred common units, (b) $20,000 annual cash retainer and (c) $11,000 in meeting fees. |
| (4) | As of December 31, 2007, Mr. Hall had 3,349 deferred common units outstanding. |
| (5) | Consists of (a) $90,000 annual retainer paid in deferred common units, (b) $20,000 annual cash retainer, (c) $23,000 in meeting fees and (d) $10,000 annual cash retainer as a member of the audit committee of our general partner and $2,500 annual cash retainer as Chairman of the conflicts committee of our general partner. |
| (6) | As of December 31, 2007, Mr. van Roden had 3,349 deferred common units outstanding. |
| (7) | Consists of (a) $90,000 annual retainer paid in deferred common units, (b) $20,000 annual cash retainer, (c) $24,000 in meeting fees and (d) $15,000 annual cash retainer as Chairman of the audit committee of our general partner. |
| (8) | As of December 31, 2006, Mr. Weller had 3,349 deferred common units outstanding. |
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| (9) | Consists of (a) $90,000 annual retainer paid in deferred common units, (b) $20,000 annual cash retainer, (c) $24,000 in meeting fees and (d) $10,000 annual cash retainer as a member of the audit committee of our general partner and $2,500 annual cash retainer as Chairman of the compensation and benefits committee of our general partner. |
Each non-employee director of our general partner receives an annual retainer of $110,000, consisting of $20,000 of cash and $90,000 worth of deferred common units. The actual number of deferred common units awarded in any given year is based upon the NYSE closing price of our common units on the dates on which such awards are granted. Each deferred common unit represents one common unit representing a limited partner interest in us, which vests immediately upon issuance and is available to the holder upon termination or retirement from the board of directors of our general partner. The Chairman of the audit committee of the board of directors of our general partner receives an annual cash retainer of $15,000, and each audit committee member receives an annual cash retainer of $10,000. The Chairmen of all other committees of the board of directors of our general partner receive annual cash retainers of $2,500. In addition to annual retainers, each non-employee director receives $1,000 cash for each board of directors and committee meeting he or she attends. Directors appointed during a year, or who cease to be directors during a year, receive a pro rata portion of cash and deferred common units. Directors may elect to receive any cash payments in common units or deferred common units, and may elect to defer the receipt of any cash or common units they receive under our general partner’s Amended and Restated Non-Employee Directors Deferred Compensation Plan.
PVR’s general partner compensates its directors in the same manner as we compensate our directors. For a detailed discussion of the 2007 director compensation for PVR’s general partner, see PVR’s Annual Report on Form 10-K for the year ended December 31, 2007.
Non-Employee Directors Deferred Compensation Plan
Our general partner has adopted the PVG GP, LLC Amended and Restated Non-Employee Directors Deferred Compensation Plan. This plan permits the non-employee directors of our general partner to defer the receipt of any or all cash, common units and restricted units they receive as compensation. All deferrals, and any distributions with respect to deferred common units or deferred restricted units, are credited to a deferred compensation account, the cash portion of which is credited quarterly with interest calculated at the prime rate. Non-employee directors of our general partner are fully vested at all times in any cash or deferred common units credited to their deferred compensation accounts. Any restricted unit awards credited to a deferred compensation account are subject to the same vesting and forfeiture restrictions that apply to the underlying award. Amounts held in a non-employee director’s deferred compensation account will be distributed to the director on the January 1st following the earlier to occur of the director reaching age 70 or the resignation or removal of the director from the board of directors of our general partner. Upon the death of a non-employee director, all vested amounts held in the deferred compensation account of the non-employee director will be distributed to the director’s estate.
Compensation Committee Interlocks and Insider Participation
During 2007, Messrs. Hall, van Roden and Weller served on the compensation and benefits committee of our general partner. None of these members is a former or current officer or employee of us or any of our subsidiaries or had any relationship requiring disclosure under Item 404 of Regulation S-K, “Transactions with Related Persons, Promoters and Certain Control Persons.” In 2007, none of the executive officers of our general partner served as a member of the board of directors or compensation committee of any entity that has one or more executive officers serving on the board of directors or the compensation and benefits committee of our general partner.
Compensation Committee Report
Under the rules established by the SEC, we are required to discuss the compensation and benefits of the executive officers of our general partner, including our CEO, our CFO and our other NEOs. The Compensation and Benefits Committee is furnishing the following report in fulfillment of the SEC’s requirements.
The Compensation and Benefits Committee has reviewed the information contained above under the heading “Compensation Discussion and Analysis” and has discussed the Compensation Discussion and Analysis with management. Based upon its review and discussions with management, the Compensation and Benefits Committee recommended to the board of directors of the Partnership’s general partner that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
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Compensation and Benefits Committee
Jonathan B. Weller (Chairman)
Robert J. Hall
John C. van Roden, Jr.
| Item 12 | Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters |
Beneficial Ownership of Units
The following table sets forth, as of February 28, 2008, the amount and percentage of our outstanding common units beneficially owned by (i) each person known by us to own beneficially more than 5% of our common units, (ii) each director of our general partner, (iii) each executive officer of our general partner and PVR’s general partner and (iv) all directors and executive officers of our general partner as a group:
| Name of Beneficial Owner |
Common Units (1) | Percent of Common Units (2) |
||||
| Penn Virginia Resource GP Corp. (3) | 11,279,925 | 28.9 | % | |||
| Penn Virginia Resource LP Corp. (3) | 19,362,198 | 49.6 | % | |||
| Kanawha Rail Corp. (3) | 1,445,301 | 3.7 | % | |||
| A. James Dearlove | 8,000 | * | ||||
| Robert Garrett | 10,748 | (4) | * | |||
| Robert J. Hall | 4,848 | (4) | * | |||
| Keith D. Horton | 2,500 | * | ||||
| Ronald K. Page | 2,500 | * | ||||
| Frank A. Pici | 6,600 | * | ||||
| Nancy M. Snyder | 4,000 | * | ||||
| John C. van Roden, Jr. | 4,748 | (4) | * | |||
| Jonathan B. Weller | 6,748 | (4) | * | |||
| All directors and executive officers as a group (9 persons) | 50,692 | (5) | * |
| * | Less than 1%. |
| (1) | Unless otherwise indicated, all common units are owned directly by the named holder and such holder has sole power to vote and dispose of such units. |
| (2) | Based on 39,074,500 common units issued and outstanding on February 28, 2008. On February 28, 2008, there were approximately 3,200 holders of our common units. |
| (3) | Penn Virginia is the ultimate parent company of Penn Virginia Resource GP Corp., Penn Virginia Resource LP Corp. and Kanawha Rail Corp. As such, Penn Virginia may be deemed to beneficially own the common units held by Penn Virginia GP Holdings, L.P. and Penn Virginia Resource GP Corp., which together own 82.1% of our common units. The address for each of Penn Virginia Resource GP Corp., Penn Virginia Resource LP Corp. and Kanawha Rail Corp. is c/o Penn Virginia Corporation, Three Radnor Corporate Center, Suite 300, 100 Matsonford Road, Radnor, Pennsylvania 19087. |
| (4) | Includes 4,248 deferred common units. |
| (5) | Includes 16,992 deferred common units. |
Equity Compensation Plan Information
The following table sets forth certain information as of December 31, 2007 regarding the options outstanding and securities issued and to be issued under our general partner’s equity compensation plans not approved by our unitholders. Our general partner does not have any equity compensation plans which were approved by our unitholders.
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| Plan Category |
Number of Securities To Be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a) |
Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b) |
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c) | |||
| Equity compensation plans approved by unitholders | N/A | N/A | N/A | |||
| Equity compensation plans not approved by unitholders | 0 | N/A | 286,604 |
| Item 13 | Certain Relationships and Related Transactions, and Director Independence |
Transactions with Related Persons
Management and Administrative Services
We are managed and controlled by our general partner pursuant to our partnership agreement. Under our partnership agreement, our general partner is reimbursed for all direct and indirect expenses it incurs or payments it makes on our behalf. These expenses include salaries, fees and other compensation and benefit expenses of employees, officers and directors, insurance, other administrative or overhead expenses and all other expenses necessary or appropriate to conduct our business. The costs allocated to us by our general partner for administrative services and overhead totaled $0.4 million for the year ended December 31, 2007.
Incentive Distributions
PVR’s partnership agreement provides for incentive distributions payable to its general partner, which is a wholly-owned subsidiary of us, out of our Available Cash (as defined in PVR’s partnership agreement) in the event quarterly distributions to unitholders exceed certain specified targets. In general, subject to certain limitations, if a quarterly distribution exceeds a target of $0.275 per common unit, we will receive incentive distributions equal to (i) 15% of that portion of the distribution per common unit which exceeds but is not more than $0.325, plus (ii) 25% of that portion of the quarterly distribution per common unit which exceeds $0.325 but is not more than $0.375, plus (iii) 50% of that portion of the quarterly distribution per common unit which exceeds $0.375. In 2007, we received total distributions, including incentive distributions, of $45.6 million from PVR. See also Item 1, “Business—Partnership Distributions.”
Units Purchase Agreement
In connection with our IPO in December 2006, we entered into a Units Purchase Agreement with PVR. Pursuant to the Units Purchase Agreement, we purchased an aggregate of 416,444 common units and 4,045,311 Class B units from PVR in three separate sales in December 2006 and January 2007. The total purchase price paid by us to PVR for the common and Class B units was $113.6 million.
Roaring Fork Royalty Interest Acquisition
In October 2007, PVR purchased from Penn Virginia Oil & Gas Corporation, a wholly-owned subsidiary of Penn Virginia, oil and gas royalty interests associated with leases of property in eastern Kentucky and southwestern Virginia and estimated proved reserves of 8.7 Bcfe at January 1, 2007. The purchase price was $31.0 million in cash and was funded with long-term debt under PVR’s revolving credit facility.
Gas Gathering and Processing Agreement
Penn Virginia Oil & Gas, L.P., or PVOG, a wholly-owned subsidiary of Penn Virginia, and PVR East Texas Gas Processing LLC, or PVR East Texas, a wholly-owned subsidiary of PVR, are parties to a Gas Gathering and Processing Agreement effective April 1, 2007. Pursuant to the Gas Gathering and Processing Agreement, PVOG and PVR East Texas have agreed that PVR East Texas will gather and process all of PVOG’s current and future gas production in certain areas of the Bethany Field in east Texas and redeliver the natural gas liquids to PVOG for a $0.30/MMbtu service fee (with an annual CPI adjustment). The Gas Gathering and Processing Agreement has a primary term of 15 years and automatically renews for
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additional one year terms until terminated by either party. PVR East Texas will begin gathering and processing PVOG’s gas upon completion of the new Crossroads System, which is expected to begin operations by April 2008.
Oil and Gas Marketing Agreement
PVOG and Connect Energy Services, LLC, or Connect Energy, a wholly-owned subsidiary of PVR, are parties to a Master Services Agreement effective September 1, 2006. Pursuant to the Master Services Agreement, PVOG and Connect Energy have agreed that Connect Energy will market all of PVOG’s oil and gas production in Arkansas, Louisiana, Oklahoma and Texas for a fee equal to 1% of the net sales price (subject to specified limitations) received by PVOG for such production. The Master Services Agreement has a primary term of five years and automatically renews for additional one year terms until terminated by either party. In 2007, PVOG paid Connect Energy $2.2 million in fees pursuant to the Master Services Agreement.
Omnibus Agreement
Penn Virginia, PVR, PVR’s general partner and the Operating Company are parties to an Omnibus Agreement that governs potential competition among them. The Omnibus Agreement was entered into in connection with PVR’s initial public offering in October 2001. Upon completion of our IPO, we became subject to the Omnibus Agreement as an affiliate of Penn Virginia. For purposes of the Omnibus Agreement, any restrictions that apply to Penn Virginia also apply to us.
Under the Omnibus Agreement, Penn Virginia and its affiliates are not permitted to engage in the businesses of: (i) owning, mining, processing, marketing or transporting coal, (ii) owning, acquiring or leasing coal reserves or (iii) growing, harvesting or selling timber, unless it or they first offers PVR the opportunity to acquire these businesses or assets and the board of directors of PVR’s general partner, with the concurrence of its conflicts committee, elects to cause PVR not to pursue such opportunity or acquisition. In addition, Penn Virginia and its affiliates will be able to purchase any business which includes the purchase of coal reserves, timber or infrastructure relating to the production or transportation of coal if the majority value of such business is not derived from owning, mining, processing, marketing or transporting coal or growing, harvesting or selling timber. If Penn Virginia or its affiliates make any such acquisition, it or they must offer PVR the opportunity to purchase the coal reserves, timber or related infrastructure following the acquisition and the conflicts committee of the board of directors of PVR’s general partner will determine whether PVR should pursue the opportunity. The restriction will terminate upon a change in control of Penn Virginia or PVR’s general partner.
Non-Compete Agreement
We and PVR are parties to a Non-Compete Agreement that governs potential competition among us. The Non-Compete Agreement was entered into in connection with our IPO in December 2006, but is not effective until we are no longer subject to the Omnibus Agreement. Pursuant to the Non-Compete Agreement, we will have a right of first refusal with respect to the potential acquisition of any general partner interest, and any other equity interests under common ownership with such general partner, in a publicly traded partnership, other than any partnerships engaged in the coal or timber businesses described above or the business of gathering or processing natural gas or other hydrocarbons. PVR will have a right of first refusal with respect to the potential acquisition of assets that relate to the business of (i) owning, mining, processing, marketing or transporting coal, (ii) owning, acquiring or leasing coal reserves, (iii) growing, harvesting or selling timber or (iv) the gathering or processing of natural gas or other hydrocarbons.
Policies Regarding Transactions with Related Persons
Under our Corporate Governance Principles, all directors must recuse themselves from any decision affecting their personal, business or professional interests. In addition, as a general matter, our practice is that any proposed transaction between us (or any of our subsidiaries) and Penn Virginia or PVR (or any of their respective subsidiaries) is approved by the conflicts committee of our general partner. For a discussion of the conflicts committee of our general partner, see “Item 10—Directors, Executive Officers and Corporate Governance—Committees of the Board of Directors of our General Partner—Conflicts Committee.” With respect to any proposed transaction with any other related person, as a general matter, our practice is that such transactions are approved by disinterested directors. The General Counsel of our general partner advises the board of directors of our general partner as to which transactions involve related persons, which transactions require the approval of the conflicts committee of our general partner and which directors are prohibited from voting on a particular transaction. All of the related transactions described above which were entered into since January 1, 2007 were approved in accordance with the foregoing policies.
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Director Independence
Messrs. Garrett, Hall, van Roden and Weller are “independent directors,” as defined by NYSE Listing Standards and SEC rules and regulations. We refer to those directors as “Independent Directors.” The board of directors of our general partner has determined that none of the Independent Directors have any relationship with us other than as a director of our general partner or its affiliates, Penn Virginia or PVR’s general partner.
| Item 14 | Principal Accounting Fees and Services |
In connection with the audits of our consolidated financial statements and our internal control over financial reporting, or ICFR, for 2007, we entered into an agreement with KPMG which sets forth the terms by which KPMG will perform audit services for us. That agreement is subject to alternative dispute resolution procedures, an exclusion of the right to collect punitive damages and various other provisions. The following table shows fees for professional audit services rendered by KPMG for the audits of our and PVR’s consolidated financial statements for 2007 and 2006, the audit of our ICFR for 2007 and the audits of PVR’s ICFR for 2007 and 2006 and fees billed for other services rendered by KPMG:
| 2007 | 2006 | |||||
| Penn Virginia GP Holdings, L.P. | ||||||
| Audit Fees (1) |
$ | 132,900 | $ | 510,100 | ||
| Audit-Related Fees |
— | — | ||||
| Tax Fees |
— | — | ||||
| All Other Fees |
— | — | ||||
| Penn Virginia Resource Partners, L.P. | ||||||
| Audit Fees (2) |
$ | 766,800 | $ | 696,100 | ||
| Audit-Related Fees (3) |
5,000 | 5,000 | ||||
| Tax Fees (4) |
13,600 | 5,300 | ||||
| All Other Fees |
— | — | ||||
| Total Fees |
$ | 918,300 | $ | 1,216,500 | ||
| (1) | Audit fees for us consist of fees for the audit of our consolidated financial statements, the audit of our ICFR for 2007, the audits performed in connection with our IPO in 2006, consents for registration statements and comfort letters. Also included in audit fees are reimbursements of travel-related expenses. |
| (2) | Audit fees for PVR consist of fees for the audit of our consolidated financial statements, the audit of PVR’s ICFR, consents for registration statements and comfort letters. Also included in audit fees are reimbursements of travel-related expenses. |
| (3) | Audit-related fees for PVR consist of fees pertaining to debt compliance letters issued by KPMG for the PVR Notes. |
| (4) | Tax fees for PVR consist of fees for reviews of state tax returns for certain subsidiaries of PVR. |
Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Registered Public Accountants
The policy of the audit committee of our general partner is to pre-approve all audit, audit-related and non-audit services provided by the independent registered public accountants. These services may include audit services, audit-related services, tax services and other services. The audit committee may also pre-approve particular services on a case-by-case basis. The independent registered public accountants are required to periodically report to the audit committee regarding the extent of services provided by the independent registered public accountants in accordance with such pre-approval. The audit committee may also delegate pre-approval authority to one or more of its members. Such member(s) must report any decisions to the audit committee at the next scheduled meeting.
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| Item 15 | Exhibits, Financial Statement Schedules |
The following documents are filed as exhibits to this Annual Report on Form 10-K:
| (1) | Financial Statements—The financial statements filed herewith are listed in the Index to Consolidated Financial Statements on page 66 of this Annual Report on Form 10-K. | |
| (2) | All schedules are omitted because they are not required, inapplicable or the information is included in the consolidated financial statements or the notes thereto. | |
| (3) | Exhibits | |
| (2.1) | Purchase and Sale Agreement dated as of August 23, 2007 among Penn Virginia Operating Co., LLC and MeadWestvaco Corporation (incorporated by reference to Exhibit 2.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on September 24, 2007). | |
| (3.1) | Certificate of Limited Partnership of Penn Virginia GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to Registrant’s Registration Statement on Form S-1 filed on July 11, 2006). | |
| (3.2) | Amendment dated June 19, 2006 to the Certificate of Limited Partnership of Penn Virginia GP Holdings, L.P. (incorporated by reference to Exhibit 3.2 to Registrant’s Registration Statement on Form S-1 filed on July 11, 2006). | |
| (3.3) | Amendment dated September 6, 2006 to the Certificate of Limited Partnership of Penn Virginia GP Holdings, L.P. (incorporated by reference to Exhibit 3.15 to Amendment No. 2 to Registrant’s Registration Statement on Form S-1 filed on October 6, 2006). | |
| (3.4) | Second Amended and Restated Agreement of Limited Partnership of Penn Virginia GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on October 26, 2007). | |
| (3.5) | Certificate of Formation of PVG GP, LLC (incorporated by reference to Exhibit 3.12 to Amendment No. 1 to Registrant’s Registration Statement on Form S-1 filed on September 7, 2006). | |
| (3.6) | First Amended and Restated Limited Liability Company Agreement of PVG GP, LLC (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed on December 13, 2006). | |
| (3.7) | Certificate of Limited Partnership of Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 3.1 to Penn Virginia Resource Partners, L.P.’s Registration Statement on Form S-1 filed on July 19, 2001). | |
| (3.8) | Second Amended and Restated Agreement of Limited Partnership of Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 3.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on October 26, 2007). | |
| (3.9) | Certificate of Formation of Penn Virginia Resource GP, LLC (incorporated by reference to Exhibit 3.5 to Amendment No. 1 to Penn Virginia Resource Partners, L.P.’s Registration Statement Form S-1 filed on September 7, 2001). | |
| (3.10) | Fourth Amended and Restated Limited Liability Company Agreement of Penn Virginia Resource GP, LLC (incorporated by reference to Exhibit 3.2 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on December 13, 2006). | |
| (4.1) | Note Purchase Agreement dated as of March 27, 2003 among Penn Virginia Operating Co., LLC, Penn Virginia Resource Partners, L.P. and the noteholders party thereto (incorporated by reference to Exhibit 2.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on April 2, 2003). | |
| (4.2) | First Amendment to Note Purchase Agreement and Parent Guaranty dated as of March 3, 2005 among Penn Virginia Operating Co., LLC, Penn Virginia Resource Partners, L.P. and the noteholders party thereto (incorporated by reference to Exhibit 10.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on March 9, 2005). | |
| (4.3) | Second Amendment to Note Purchase Agreement dated as of December 11, 2006 among Penn Virginia Operating Co., LLC, Penn Virginia Resource Partners, L.P. and the noteholders party thereto (incorporated by reference to Exhibit 4.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on December 13, 2006). | |
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| (4.4) | Third Amendment to Note Purchase Agreement and Parent Guaranty dated as of September 19, 2007 among Penn Virginia Operating Co., LLC, Penn Virginia Resource Partners, L.P. and the noteholders party thereto (incorporated by reference to Exhibit 4.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on September 20, 2007). | |
| (10.1) | Amended and Restated Credit Agreement dated as of March 3, 2005 among Penn Virginia Operating Co., LLC, the guarantors party thereto, PNC Bank, National Association, as agent, and the other financial institutions party thereto (incorporated by reference to Exhibit 10.2 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on March 9, 2005). | |
| (10.2) | First Amendment, Waiver, and Consent to Amended and Restated Credit Agreement dated as of July 15, 2005 among Penn Virginia Operating Co., LLC, the guarantors party thereto, PNC Bank, National Association, as agent, and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on July 21, 2005). | |
| (10.3) | Second Amendment to Amended and Restated Credit Agreement dated as of August 22, 2006 among Penn Virginia Operating Co., LLC, the guarantors party thereto, PNC Bank, National Association, as agent, and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to Penn Virginia Resource Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2006). | |
| (10.4) | Third Amendment to Amended and Restated Credit Agreement dated as of December 11, 2006 among Penn Virginia Operating Co., LLC, the guarantors party thereto, PNC Bank, National Association, as agent, and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on December 13, 2006). | |
| (10.5) | Fourth Amendment to Amended and Restated Credit Agreement dated as of September 7, 2007 among Penn Virginia Operating Co., LLC, the guarantors party thereto, PNC Bank, National Association, as agent, and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on September 7, 2007). | |
| (10.6) | Fifth Amendment to Amended and Restated Credit Agreement dated as of October 8, 2007 among Penn Virginia Operating Co., LLC, the guarantors party thereto, PNC Bank, National Association, as agent, and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on October 10, 2007). | |
| (10.7) | Contribution and Conveyance Agreement dated as of December 8, 2006 among Penn Virginia Resource LP Corp., Penn Virginia Resource GP, LLC, Kanawha Rail Corp., Penn Virginia GP Holdings, L.P. and Penn Virginia Resource GP Corp. (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on December 13, 2006). | |
| (10.8) | Omnibus Agreement dated October 30, 2001 among the Penn Virginia Corporation, Penn Virginia Resource GP, LLC, Penn Virginia Operating Co., LLC and Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 10.6 to Amendment No. 2 to Penn Virginia Resource Partners, L.P.’s Registration Statement on Form S-1 filed on October 4, 2001). | |
| (10.9) | Amendment No. 1 to Omnibus Agreement dated December 19, 2002 among the Penn Virginia Corporation, Penn Virginia Resource GP, LLC, Penn Virginia Operating Co., LLC and Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 10.7 to Penn Virginia Resource Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2002). | |
| (10.10) | Non-Compete Agreement dated December 8, 2006 among Penn Virginia GP Holdings, L.P., Penn Virginia Resource Partners, L.P. and Penn Virginia Resource GP, LLC (incorporated by reference to Exhibit 10.2 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on December 13, 2006). | |
| (10.11) | PVG GP, LLC Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on October 29, 2007).* | |
| (10.12) | Form of Agreement for Deferred Common Unit Grants under the PVG GP, LLC Amended and Restated Long-Term Incentive Plan.* | |
| (10.13) | Form of Agreement for Restricted Unit Awards under the PVG GP, LLC Amended and Restated Long-Term Incentive Plan.* | |
| (10.14) | PVG GP, LLC Amended and Restated Non-Employee Directors Deferred Compensation Plan (incorporated by reference to Exhibit 10.4 to Registrant’s Current Report on Form 8-K filed on October 29, 2007).* | |
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| (10.15) | Penn Virginia Resource GP, LLC Third Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on October 29, 2007).* | |
| (10.16) | Form of Agreement for Deferred Common Unit Grants under the Penn Virginia Resource GP, LLC Third Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Penn Virginia Resource Partners, L.P.’s Annual Report on 10-K for the year ended December 31, 2007).* | |
| (10.17) | Form of Agreement for Restricted Unit Awards under the Penn Virginia Resource GP, LLC Third Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.15 to Penn Virginia Resource Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2007).* | |
| (10.18) | Penn Virginia Resource GP, LLC Amended and Restated Non-Employee Directors Deferred Compensation Plan (incorporated by reference to Exhibit 10.4 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on October 29, 2007).* | |
| (10.19) | Executive Change of Control Severance Agreement dated March 9, 2006 between Penn Virginia Resource GP, LLC and Keith D. Horton (incorporated by reference to Exhibit 10.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on March 14, 2006).* | |
| (10.20) | Executive Change of Control Severance Agreement dated March 9, 2006 between Penn Virginia Resource GP, LLC and Ronald K. Page (incorporated by reference to Exhibit 10.2 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on March 14, 2006).* | |
| (12.1) | Statement of Computation of Ratio of Earnings to Fixed Charges Calculation. | |
| (21.1) | Subsidiaries of Penn Virginia GP Holdings, L.P. | |
| (23.1) | Consent of KPMG LLP. | |
| (31.1) | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| (31.2) | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| (32.1) | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| (32.2) | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| * | Management contract or compensatory plan or arrangement. |
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| PENN VIRGINIA GP HOLDINGS, L.P. | ||||||
| By: PVG GP, LLC | ||||||
| February 28, 2008 |
||||||
| By: | /s/ FRANK A. PICI | |||||
| Frank A. Pici Vice President and Chief Financial Officer | ||||||
| February 28, 2008 |
||||||
| By: | /s/ FORREST W. MCNAIR | |||||
| Forrest W. McNair Vice President and Controller | ||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
| /s/ A. JAMES DEARLOVE A. James Dearlove |
Chairman of the Board and President and Chief Executive Officer | February 28, 2008 | ||
| /s/ ROBERT GARRETT |
Director | February 28, 2008 | ||
| Robert Garrett | ||||
| /s/ ROBERT J. HALL |
Director | February 28, 2008 | ||
| Robert J. Hall | ||||
| /s/ FRANK A. PICI Frank A. Pici |
Director and Vice President and Chief Financial Officer | February 28, 2008 | ||
| /s/ NANCY M. SNYDER |
Director and Vice President and General Counsel | February 28, 2008 | ||
| Nancy M. Snyder | ||||
| /s/ JOHN C. VAN RODEN, JR. |
Director | February 28, 2008 | ||
| John C. van Roden, Jr. | ||||
| /s/ JONATHAN B. WELLER |
Director | February 28, 2008 | ||
| Jonathan B. Weller | ||||
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