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Penn Virginia 10-K 2009 Documents found in this filing:
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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, 2008 Commission file number: 1-13283
Penn Virginia Corporation (Exact name of registrant as specified in its charter)
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: None Securities registered pursuant to Section 12(g) of the Act:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934 (“Exchange Act”). Yes ¨ No x Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One)
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 stock held by non-affiliates of the registrant was $1,966,744,687 as of June 30, 2008 (the last business day of its most recently completed second fiscal quarter), based on the last sale price of such stock as quoted on the New York Stock Exchange. For purposes of making this calculation only, the registrant has defined affiliates as including all directors and executive officers of the registrant, but excluding any institutional shareholders. This determination of affiliate status is not necessarily a conclusive determination for other purposes. As of February 25, 2009, 41,871,607 shares of common stock of the registrant were outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Proxy Statement relating to the registrant’s Annual Meeting of Shareholders, to be held on May 5, 2009, is incorporated by reference in Part III of this Form 10-K.
Table of ContentsPENN VIRGINIA CORPORATION AND SUBSIDIARIES Table of Contents
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General Penn Virginia Corporation (NYSE: PVA) is an independent oil and gas company primarily engaged in the development, exploration and production of natural gas and oil in various domestic onshore regions including East Texas, the Mid-Continent, Appalachia, Mississippi and the Gulf Coast. We also indirectly own partner interests in Penn Virginia Resource Partners, L.P. (NYSE: PVR), or PVR, a publicly traded limited partnership formed by us in 2001. Our ownership interests in PVR are held principally through our general partner interest and our 77% limited partner interest in Penn Virginia GP Holdings, L.P. (NYSE: PVG), or PVG, a publicly traded limited partnership formed by us in 2006. As of December 31, 2008, PVG owned an approximately 37% limited partner interest in PVR and 100% of the general partner of PVR, which holds a 2% general partner interest in PVR. See “—Corporate Structure. PVG consolidates PVR’s results into its financial statements because PVG controls PVR’s general partner. We consolidate PVG’s results into our financial statements because we control PVG’s general partner. PVG and PVR function with capital structures that are independent of each other and us. While we report consolidated financial results of PVR’s coal and natural resource management and natural gas midstream businesses, the only cash we received from those businesses is in the form of cash distributions we received from PVG and PVR in respect of our partner interests in each of them. We received cash distributions of $44.0 million, $29.8 million and $28.6 million in the years ended December 31, 2008, 2007 and 2006 on account of our partner interests in PVG and PVR. Unless the context requires otherwise, references to the “Company,” “Penn Virginia,” “we,” “us” or “our” in this Annual Report on Form 10-K refer to Penn Virginia Corporation and its subsidiaries. Segments We are engaged in three primary business segments: (i) oil and gas, (ii) coal and natural resource management and (iii) natural gas midstream. We operate our oil and gas segment. PVR operates the coal and natural resource management and natural gas midstream segments. Our operating income was $256.8 million in 2008, compared to $192.6 million in 2007 and $170.5 million in 2006. Our segments’ contributions to operating income in 2008 were as follows:
These contributions were partially offset by $29.0 million of intercompany eliminations and corporate expenses, or 10%. Oil and Gas Segment Overview We have a geographically diverse asset base with core areas of operation in the East Texas, Mid-Continent, Appalachian, Mississippi and Gulf Coast regions of the United States. As of December 31, 2008, we had proved natural gas and oil reserves of approximately 916 Bcfe, of which 82% were natural gas and 51% were proved developed. Our operations include both conventional and unconventional developmental drilling opportunities, as well as some exploratory prospects. As of December 31, 2008, 97% of our proved reserves were located in primarily longer-lived, lower-risk basins in East Texas, the Mid-Continent, Appalachia and Mississippi, which comprised 43%, 15%, 19% and 15% of the proved reserves. Our Gulf Coast properties, representing 3% of proved reserves, are shorter-lived and have higher impact exploratory prospects. In 2008, we produced 46.9 Bcfe, a 16% increase compared to 40.6 Bcfe in 2007, with East Texas, the Mid-Continent, Appalachia, Mississippi and the Gulf Coast comprising 29%, 16%, 25%, 16% and 16% of total production volumes. In the three years ended December 31, 2008, we drilled 785 gross (544.4 net) wells, of which 94% were successful in producing natural gas in commercial quantities. For a more detailed discussion of our reserves and production, see Item 2, “Properties.”
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Table of ContentsThe primary development play types that our oil and gas operations are focused on include: (i) the horizontal Lower Bossier (Haynesville) Shale and vertical Cotton Valley plays in East Texas, (ii) the horizontal Granite Wash, horizontal Hartshorne CBM and the Woodford Shale plays in the Mid-Continent, (iii) multi-lateral horizontal CBM and Marcellus Shale plays in Appalachia and (iv) the predominantly horizontal Selma Chalk play in Mississippi. We have grown our reserves and production primarily through development and exploratory drilling, complemented to a lesser extent by making strategic acquisitions. In 2008, we replaced 604% of our 2008 production entirely through the drillbit by adding approximately 283 Bcfe of proved reserves from extensions, discoveries and additions, net of revisions. In 2008, capital expenditures in our oil and gas segment were $641.7 million, of which $481.4 million, or 75%, was related to development drilling, $23.8 million, or 4%, was related to exploratory drilling, $95.5 million, or 15%, was related to leasehold acquisitions and $36.8 million, or 6%, was related to pipelines, gathering and facilities. PVR Coal and Natural Resource Management Segment Overview The PVR coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. PVR also earns revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees. As of December 31, 2008, PVR owned or controlled approximately 827 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. PVR enters into long-term leases with experienced, third-party mine operators, providing them the right to mine PVR’s 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 PVR’s properties. PVR does not operate any mines. In 2008, PVR’s lessees produced 33.7 million tons of coal from its properties and paid PVR coal royalties revenues of $122.8 million, for an average royalty per ton of $3.65. Approximately 86% of PVR’s coal royalties revenues in 2008 were derived from coal mined on PVR’s 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 PVR’s properties under leases containing fixed royalty rates that escalate annually. See “—PVR Contracts—PVR Coal and Natural Resource Management Segment” for a description of PVR’s coal leases. PVR Natural Gas Midstream Segment Overview PVR’s natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of December 31, 2008, PVR owned and operated natural gas midstream assets located in Oklahoma and Texas, including five natural gas processing facilities having 300 MMcfd of total capacity and approximately 4,069 miles of natural gas gathering pipelines. PVR’s natural gas midstream business earns revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In addition, PVR owns a 25% member interest in Thunder Creek Gas Services, LLC, or Thunder Creek, a joint venture that gathers and transports CBM in Wyoming’s Powder River Basin. 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. In 2008, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 98.7 Bcf, or approximately 270 MMcfd. Eliminations and Other Eliminations and other primarily represents elimination of intercompany sales, corporate functions and the oil and gas segment derivatives Business Strategy We intend to pursue the following business strategies:
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Contracts Oil and Gas Segment Transportation. We have entered into contracts which provide firm transportation capacity rights for specified volumes per day on a pipeline system for terms ranging from one to 15 years. The contracts require us to pay transportation demand charges regardless of the amount of pipeline capacity we use. We may sell excess capacity to third parties at our discretion. Marketing. We generally sell our natural gas using spot market and short-term fixed price physical contracts. For the year ended December 31, 2008, approximately 16% and 14% of our oil and gas segment revenues and 6% and 5% of our total consolidated revenues resulted from two of our oil and gas customers, Dominion Field Services, Inc and Crosstex Energy Services, L.P.
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Table of ContentsPVR 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 is earned under long-term leases that require the lessees to make royalty payments to PVR based on fixed royalty rates that escalate annually. A typical lease either expires upon exhaustion of the leased reserves or has a five to ten-year base term, with the lessee having an option to extend the lease for at least five years after the expiration of the base term. Substantially all of 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. 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 PVR a fixed price per thousand board feet of timber harvested from PVR’s 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, 2008, 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) gas purchase/keep-whole and (ii) percentage-of-proceeds. As of December 31, 2008, approximately 27% of PVR’s system throughput volumes were gathered or processed under gas purchase/keep-whole contracts, 45% were gathered or processed under percentage-of-proceeds contracts and 28% were gathered or processed under fee-based gathering contracts. A majority of the gas purchase/keep-whole and percentage-of-proceeds contracts include fee-based components such as gathering and compression charges. 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. In 2008, 27% and 13% of PVR’s natural gas midstream segment revenues and 16% and 8% of our total consolidated revenues resulted from two of PVR’s natural gas midstream customers, Conoco, Inc. and Louis Dreyfus Energy Services. Gas Purchase/Keep-Whole Arrangements. Under gas purchase/keep-whole 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.
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Table of ContentsPercentage-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 NGL prices, may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors. Natural Gas Marketing Contracts. 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, PVR’s wholly owned subsidiary, has earned fees from Penn Virginia Oil & Gas, L.P., or PVOG LP, our wholly owned subsidiary, since September 1, 2006, for marketing a portion of PVOG LP’s natural gas production. Revenues from this business do not generate qualifying income for a publicly traded limited partnership, but 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, 2008 and 2007, PVR’s natural gas marketing activities generated $5.8 million and $4.6 million in net revenues. Fees paid to the PVR natural gas midstream segment by our oil and gas segment are eliminated in consolidation. Commodity Derivative Contracts Oil and Gas Segment Commodity Derivatives. We utilize three-way collar derivative contracts to hedge against the variability in cash flows associated with anticipated sales of our future oil and gas production. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues from favorable price movements. A three-way collar contract consists of a collar contract plus a put option contract sold by us with a price below the floor price of the collar. The counterparty to a collar contract is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are required to make a 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. The additional put option sold by us requires us to make a payment to the counterparty if the settlement price for any settlement period is below the put option price. By combining the collar contract with the additional put option, we are entitled to a net payment equal to the difference between the floor price of the collar contract and the additional put option price if the settlement price is equal to or less than the additional put option price. If the settlement price is greater than the additional put option price, the result is the same as it would have been with a collar contract only. If market prices are below the additional put option, we would be entitled to receive the market price plus the difference between the additional put option and the floor. See the oil and gas segment commodity derivative table in Item 7A –“Quantitative and Qualitative Disclosures About Market Risk – Price Risk.” This strategy enables us to increase the floor and the ceiling prices of the collar beyond the range of a traditional collar contract while defraying the associated cost with the sale of the additional put option. We determine the fair values of our oil and gas derivative agreements based on discounted cash flows derived from third-party quoted forward prices for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices as of December 31, 2008. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties for derivatives in an asset position, and our own credit risk derivatives in a liability position, in accordance with Statement of Financial Accounting Standards, or SFAS, No. 157. PVR Natural Gas Midstream Segment Commodity Derivatives. PVR utilizes three-way collar derivative contracts to hedge against the variability in cash flows associated with anticipated natural gas midstream revenues and cost of midstream
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Table of Contentsgas purchased. PVR also utilizes collar 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 NGLs that PVR sells after processing. PVR hedges against the variability in its frac spread by entering into costless collar and swap derivative contracts to sell NGLs forward at a predetermined commodity price and to purchase an equivalent volume of natural gas forward on an MMBtu basis. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues or cost savings from favorable price movements. A three-way collar contract consists of a collar contract plus a put option contract sold by PVR with a price below the floor price of the collar. The counterparty to a collar contract 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 a 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. The additional put option sold by PVR requires it to make a payment to the counterparty if the settlement price for any settlement period is below the put option price. By combining the collar contract with the additional put option, PVR is entitled to a net payment equal to the difference between the floor price of the collar contract and the additional put option price if the settlement price is equal to or less than the additional put option price. If the settlement price is greater than the additional put option price, the result is the same as it would have been with a collar contract only. If market prices are below the additional put option, PVR would be entitled to receive the market price plus the difference between the additional put option and the floor. See the PVR natural gas midstream segment commodity derivative table in Item 7A –“Quantitative and Qualitative Disclosures About Market Risk – Price Risk.” This strategy enables PVR to increase the floor and the ceiling prices of the collar beyond the range of a traditional collar contract while defraying the associated cost with the sale of the additional put option. See Note 8 – “Derivative Instruments” in the Notes to Consolidated Financial Statements in Item 8, “Financial Statements and Supplementary Data,” for a further description of our and PVR’s derivatives programs. Corporate Structure We are a Virginia corporation formed in 1882. As of December 31, 2008, we owned the general partner of PVG and an approximately 77% limited partner interest in PVG. PVG owns an approximately 37% limited partner interest in PVR and the general partner of PVR, which holds a 2% general partner interest in PVR and all of the incentive distribution rights, or IDRs. We directly owned an additional 0.1% limited partner interest in PVR as of December 31, 2008. The following diagram depicts our ownership of PVG and PVR as of December 31, 2008:
Because PVG controls the general partner of PVR, the financial results of PVR are included in PVG’s consolidated financial statements. Because we control the general partner of PVG, the financial results of PVG are included in our consolidated financial statements. However, PVG and PVR function with capital structures that are independent of each
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Table of Contentsother and us, with each having publicly traded common units and PVR having its own debt instruments. PVG does not currently have any debt instruments. While we report consolidated financial results of PVR’s coal and natural resource management and natural gas midstream businesses, the only cash we receive from those businesses is in the form of cash distributions we receive from PVG and PVR in respect of our partner interests in each of them. PVG and PVR Distributions PVG Cash Distributions PVG paid cash distributions of $1.40 per common unit during the year ended December 31, 2008. In the first quarter of 2009, PVG paid a cash distribution of $0.38 ($1.52 on an annualized basis) per common unit with respect to the fourth quarter of 2008. This distribution was unchanged from the previous distribution paid on November 19, 2008. For the remainder of 2009, PVG expects to pay quarterly cash distributions of at least $0.38 ($1.52 on an annualized basis) per common unit. PVR Cash Distributions PVR paid cash distributions of $1.82 per common unit during the year ended December 31, 2008. In the first quarter of 2009, PVR paid a cash distribution of $0.47 ($1.88 on an annualized basis) per common unit with respect to the fourth quarter of 2008. This distribution was unchanged from the previous distribution paid on November 14, 2008. For the remainder of 2009, PVR expects to pay quarterly cash distributions of at least $0.47 ($1.88 on an annualized basis) per common unit. PVR IDRs In accordance with PVR’s partnership agreement, IDRs represent the right to receive an increasing percentage of quarterly distributions of PVR’s available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. The minimum quarterly distribution is $0.25 ($1.00 on an annualized basis) per unit. PVR’s general partner currently holds 100% of the IDRs, but may transfer these rights separately from its general partner interest to an affiliate (other than an individual) or to another entity as part of the merger or consolidation of PVR’s general partner with or into such entity or the transfer of all or substantially all of PVR’s general partner’s assets to another entity without the prior approval of PVR’s unitholders if the transferee agrees to be bound by the provisions of PVR’s partnership agreement. Prior to September 30, 2011, other transfers of the IDRs will require the affirmative vote of holders of a majority of the outstanding PVR common units. On or after September 30, 2011, the IDRs will be freely transferable. The IDRs are payable as follows: If for any quarter:
then, PVR will distribute any additional available cash from operating surplus for that quarter among the unitholders and its general partner in the following manner:
Since 2001, PVR has increased its quarterly cash distribution from $0.25 ($1.00 on an annualized basis) per unit to $0.47 ($1.88 on an annualized basis) per unit, which is its most recently declared distribution. These increased cash distributions
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Table of Contentsby PVR have placed PVG, as the owner of PVR’s general partner, at the maximum target cash distribution level as described above and, as a consequence, since reaching such level, PVG, as the owner of PVR’s general partner, has received 50% of available cash in excess of $0.375 per unit. Cash Distributions Received In conjunction with the initial public offering of PVG, we contributed our general partner interest, IDRs and most of our limited partner interest in PVR to PVG in exchange for the general partner interest and limited partner interests in PVG. We are currently entitled to receive quarterly cash distributions from PVG and PVR on our limited partner interests in PVG and PVR. As a result of our partner interests in PVG and PVR, we received total cash distributions of $44.0 million and $29.8 million from PVG and PVR in the years ended December 31, 2008 and 2007 as shown in the following table:
We have historically received, on an annual basis, increasing distributions from our partner interests in PVG and PVR. Based on PVG’s and PVR’s current annualized distribution rates of $1.52 and $1.88 per unit, we would expect to receive aggregate annualized distributions of approximately $46.3 million in respect of our partner interests in the year ended December 31, 2009. Prior to PVG’s initial public offering in December 2006, we indirectly owned common units representing an approximately 37% limited partner interest in PVR, as well as the sole 2% general partner interest and all of the IDRs in PVR. We received total distributions from PVR of $28.6 million in the year ended December 31, 2006, allocated among our limited partner interest, general partner interest and IDRs as shown in the following table:
Competition Oil and Gas Segment The oil and natural gas industry is very competitive, and we compete with a substantial number of other companies that are large, well-established and have greater financial and operational resources than we do, which may adversely affect our ability to compete or grow our business. Many such companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also carry on refining operations, electricity generation and the marketing of refined products. Competition is particularly intense in the acquisition of prospective oil and natural gas properties and oil and gas reserves. Our competitive position depends on our geological, geophysical and engineering expertise, our financial resources, our ability to develop properties and our ability to select, acquire and develop proved reserves. We compete with other oil and natural gas companies to secure drilling rigs and other equipment necessary for the drilling and completion of wells and recruiting and retaining qualified personnel, including geologists, geo-physicists, engineers and other specialists. Such equipment and labor may be in short supply from time to time. Shortages of equipment, labor or materials may result in increased costs or the inability to obtain such resources as needed. We also compete with major and independent oil and gas companies in the marketing and sale of oil and natural gas, and the oil and natural gas industry in general competes with other industries supplying energy and fuel to industrial, commercial and individual consumers.
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Table of ContentsPVR 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 the price and availability of high sulfur coal, which can be marketed in tandem with emissions allowances which permit the high sulfur coal to meet federal Clean Air Act, or CAA, requirements. PVR Natural Gas Midstream Segment 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. 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:
Government Regulation and Environmental Matters The operations of our oil and gas business and PVR’s coal and natural resource management business and PVR’s 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. Oil and Gas Segment State Regulatory Matters. Various aspects of our oil and natural gas operations are regulated by administrative agencies under statutory provisions of the states where such operations are conducted. All of the jurisdictions in which we own or operate producing crude oil and natural gas properties have statutory provisions regulating the exploration for and production of crude oil and natural gas. These provisions include permitting regulations regarding the drilling of wells, maintaining bonding requirements to drill or operate wells, locating wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area and the unitization or pooling of crude oil and natural gas properties. In addition, state conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. The effect of these regulations is to limit the amounts of crude oil and natural gas we can produce from our wells and to limit the number of wells or the locations at which we can drill. Federal Energy Regulatory Commission. The Federal Energy Regulatory Commission, or the FERC, regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938, or the NGA, and the Natural Gas Policy Act of 1978, or the NGPA. In the past, the federal government has regulated the prices at which oil
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Table of Contentsand gas could be sold. The Natural Gas Wellhead Decontrol Act of 1989 removed all NGA and NGPA price and nonprice controls affecting producers’ wellhead sales of natural gas effective January 1, 1993. While sales by producers of their own natural gas production and all sales of crude oil, condensate and NGLs can currently be made at market prices, Congress could reenact price controls in the future. Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and 636-C, or Order No. 636, which require interstate pipelines to provide transportation separate, or “unbundled,” from the pipelines’ sale of gas. Also, Order No. 636 requires pipelines to provide open-access transportation on a basis that is equal for all gas supplies. Although Order No. 636 does not directly regulate gas producers like us, the FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its open access regulations. In particular, the FERC has issued Order Nos. 637, 637-A and 637-B which, among other things, (i) permit pipelines to charge different maximum cost-based rates for peak and off-peak periods, (ii) encourage auctions for pipeline capacity, (iii) require pipelines to implement imbalance management services and (iv) restrict the ability of pipelines to impose penalties for imbalances, overruns and non-compliance with operational flow orders. The Energy Policy Act of 2005 amended the NGA and the NGPA and gave the FERC the authority to assess civil penalties of up to $1 million per day per violation for violations of rules, regulations and orders issued under these acts. In addition, the FERC has issued regulations that make it unlawful for any entity in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of the FERC to use any manipulative or deceptive device or contrivance. While any additional FERC action on these matters would affect us only indirectly, these changes are intended to further enhance competition in, and prevent manipulation of, natural gas markets. We cannot predict what further action the FERC will take on these matters, nor can we predict whether the FERC’s actions will achieve its stated goal of increasing competition in, and preventing manipulation of, natural gas markets. However, we do not believe that we will be treated materially differently than other natural gas producers with which we compete. Environmental Matters. Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material adverse impact on us. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws have the potential to adversely affect our operations. OSHA. We are subject to the requirements of the Occupational Safety and Health Act, or OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. 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
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Table of Contentsof 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 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 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 Environmental Protection Agency, or EPA, laws and regulations will make it more costly to build and operate coal-fired power plants and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel alternative in the planning and building of power plants in the future. Any reduction in coal’s share of power generating capacity could negatively impact 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 would have permanently capped nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. beginning in 2009 and 2010. CAIR required those states to achieve the required emission reductions by requiring power plants to either participate in an EPA-administered “cap-and-trade” program that caps emission in two phases, or by meeting an individual state emissions budget through measures established by the state. The stringency of the caps under CAIR may have required many coal-fired sources to install additional pollution control equipment, such as wet scrubbers, to comply. This increased sulfur emission removal capability required by CAIR could have resulted in decreased demand for lower sulfur coal, which may have potentially driven down prices for lower sulfur coal. On July 11, 2008, the D.C. Circuit Court of Appeals vacated CAIR in its entirety. The EPA subsequently filed a petition for rehearing or, in the alternative, for a remand of the case without vacatur. On December 23, 2008, the Court issued an opinion to remand without vacating CAIR. Therefore, CAIR will remain in effect while the EPA conducts rulemaking to modify CAIR to comply with the Court’s July 2008 opinion. The Court declined to impose a schedule by
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Table of Contentswhich the EPA must complete the rulemaking, but reminded the EPA that the Court does “.not intend to grant an indefinite stay of the effectiveness of this Court’s decision.” The EPA is considering its options on how to proceed. In March 2005, the EPA finalized the Clean Air Mercury Rule, or CAMR, which was to establish a two-part, nationwide cap on mercury emissions from coal-fired power plants beginning in 2010. It was the subject of extensive controversy and litigation and, in February 2008, the U.S. Circuit Court of Appeals for the District of Columbia vacated CAMR. The EPA appealed the decision to the U.S. Supreme Court in October 2008, but withdrew its petition for certiorari on February 6, 2009. However, a utility group continues to seek certiorari, challenging the court of appeals decision to overturn CAMR. In the meantime, the EPA plans to develop standards consistent with the court of appeal’s ruling. In addition, various states have promulgated or are considering more stringent emission limits on mercury emissions from coal-fired electric generating units. The EPA has adopted new, more stringent national air quality standards for ozone and fine particulate matter. As a result, some states will be required to amend their existing state implementation plans to attain and maintain compliance with the new air quality standards. In March 2007, the EPA published final rules addressing how states would implement plans to bring regions designated as non-attainment for fine particulate matter into compliance with the new air quality standard. Under the EPA’s final rule, states had until April 2008 to submit their implementation plans to the EPA for approval. Because coal mining operations and coal-fired electric generating facilities emit particulate matter, 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 modifications have been made to these facilities without first obtaining permits required under the new source review program. Several of these lawsuits have settled, but others remain pending. On April 2, 2007, the U.S. Supreme Court ruled in one such case, Environmental Defense v. Duke Energy Corp. The Court held that the EPA is not required to use an “hourly rate test” in determining whether a modification to a coal burning utility requires a permit under the new source review program, thus allowing the EPA to apply a test based on average annual emissions. The use of an annual emissions test could subject more coal-fired utility modification projects to the permitting requirements of the CAA New Source Review Program, such as those that allow plants to run for more hours in a given year. However, Duke is expected to continue to contest remaining issues in the case, and so litigation in this and other pending cases will likely continue. Depending on the ultimate resolution of these cases, demand for 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 U.S. Supreme Court held in Massachusetts v. EPA that unless the EPA affirmatively concludes that greenhouse gases are not causing climate change, the EPA must regulate greenhouse gas emissions from new automobiles under the CAA. The Court remanded the matter to the EPA for further consideration. This litigation did not directly concern the EPA’s authority to regulate greenhouse gas emissions from stationary sources, such as coal mining operations or coal-fired power plants. However, the Court’s decision is likely to influence another lawsuit currently pending in the U.S. Court of Appeals for the District of Columbia Circuit, involving a challenge to the EPA’s decision not to regulate carbon dioxide from power plants and other stationary sources under a CAA new source performance standard rule, which specifies emissions limits for new facilities. The court remanded that question to the EPA for further consideration in light of the ruling in Massachusetts v. EPA. On July 11, 2008, the EPA released an advanced notice of proposed rulemaking to regulate greenhouse gases under the CAA in response to the ruling in Massachusetts v. EPA. The notice did not contain a definitive proposal of what a greenhouse gas regulatory program would look like, but it presented the EPA’s analyses and policy alternatives for consideration. The EPA stated that promulgating a program under the CAA would take years to issue. Any decision in this case or any regulatory action by the EPA limiting greenhouse gas emissions
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Table of Contentsfrom 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. For instance, in October 2007, state regulators in Kansas became the first to deny an air emissions construction permit for a new coal-fired power plant based on the plant’s projected emissions of carbon dioxide. State regulatory authorities in Florida and North Carolina have also rejected the construction of new coal-fired power plants based on the uncertainty surrounding the potential costs associated with greenhouse gas emissions from these plants under future laws limiting the emission of carbon dioxide. In addition, permits for several new coal-fired power plants without limits imposed on their greenhouse gas emissions have been appealed by environmental organizations to the EPA’s Environmental Appeals Board, or EAB, and other judicial forums under the CAA. For example, in June 2008, a Georgia court voided a CAA permit and halted the construction of a coal-fired power plant for failure to address carbon dioxide emissions. Likewise, in November 2008, in another case, In re Deseret Power Electric Cooperative, the EAB remanded the permitting decision back to the Region to reopen the record and reconsider whether carbon dioxide is a pollutant subject to regulation under the CAA with instructions to consider its nationwide implications. In December 2008, the EPA Administrator issued an interpretive rule determining that phrase in the CAA “not subject to regulation” does not include pollutants for which only monitoring and reporting is required. Because carbon dioxide is such a pollutant, this interpretive rule has the effect of precluding any consideration of carbon dioxide emissions in connection with federal permitting under the CAA. Environmental groups filed a Petition for Reconsideration of the interpretive rule. On February 17, 2009, the EPA stated that it would grant the Petition for Reconsideration and allow public comment, but it declined to stay the effectiveness of the interpretive rule at that time. A number of states have also either passed legislation or announced initiatives focused on decreasing or stabilizing carbon dioxide emissions associated with the combustion of fossil fuels, and many of these measures have focused on emissions from coal-fired electric generating facilities. For example, ten northeastern and mid-Atlantic states have agreed to implement a regional cap-and-trade program, referred to as the Regional Greenhouse Gas Initiative, or RGGI, to stabilize carbon dioxide emissions from regional power plants beginning in 2009. This initiative aims to reduce emissions of carbon dioxide to levels roughly corresponding to average annual emissions between 2000 and 2004. The members of RGGI agreed to seek to establish in statute and/or regulation a carbon dioxide trading program and have each state’s component of the regional program effective no later than December 31, 2008. Auctions for carbon dioxide allowances under the program began in September 2008. Following the RGGI model, seven Western states and four Canadian provinces have also formed a regional greenhouse gas reduction initiative known as the Western Regional Climate Action Initiative, which calls for an overall reduction of regional greenhouse gas emissions from major industrial and commercial sources, including fossil-fuel fired power plants, in participating states through trading of emissions credits beginning in 2012. Similarly, in 2007, six Midwestern states and one Canadian province signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions, including developing a market-based, multi-sector cap. Some states have passed laws individually. For example, in 2006, the governor of California signed Assembly Bill 32 into law, requiring the California Air Resources Board to develop regulations and market mechanisms to reduce California’s greenhouse gas emissions by 25% by 2020 with mandatory caps beginning in 2012 for significant sources. In 2007, New Jersey passed a greenhouse gas reduction that would be economy wide, requiring emissions to drop to 1990 levels by 2020 and that emissions be capped at 80% of 2006 levels by 2050. Several different pieces of legislation were introduced in Congress in 2007 and 2008 to reduce greenhouse gas emissions in the United States. Newly elected President Obama, stated in his campaign that climate change policy would be a priority of his administration, and the Democratic majority in Congress has indicated that it will seek to enact legislation to reduce greenhouse gas emissions. 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 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
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Table of Contentsdamages occurring as a result of mining operations, and requires mine operators to post performance bonds to ensure compliance with any reclamation obligations. Moreover, regulatory authorities may attempt to assign the liabilities of PVR’s coal lessees to another entity such as PVR if any of its lessees are not financially capable of fulfilling those obligations on the theory that PVR “owned” or “controlled” the mine operator in such a way for liability to attach. 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 PVR’s 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. 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.
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Table of ContentsRecent 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. The Corps, Alex Energy, other impacted mining companies, and mining associations appealed the March 23, 2007 ruling to the U.S. Court of Appeals for the Fourth Circuit. On February 13, 2009, the Fourth Circuit reversed and vacated the District Court’s March 23, 2007 opinion and order that had rescinded the challenged permits and vacated the District Court’s injunction of activity under those permits and reversed a related order by the District Court that would have required yet additional permits under the CWA. One of the three judges dissented from this decision and would have upheld the decision rescinding the permits and enjoining future activity but agreed with the other two judges on the other parts of the decision. This decision may be subject to further appellate review including by the Fourth Circuit itself. We are unable to predict the outcome of any further appellate review that may be obtained. In December 2007, plaintiff environmental groups brought a similar suit against the issuance of a CWA Section 404 permit for a surface coal mine in the U.S. District Court for the Eastern District of Kentucky, alleging identical violations. The Corps has voluntarily suspended its consideration of the permit application in that case for agency re-evaluation. While the final outcome of these cases remains uncertain, if lawsuits challenging the use of valley fills ultimately limits or prohibits the mining methods or operations of 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. In December 2008, the Department of Interior published the Excess Spoil, Coal Mine Waste and Buffers for Perennial and Intermittent Streams rule under SMCRA in part to clarify when valley fills are permitted. The rule would require a 100-foot buffer around all waters, including streams, lakes, ponds and wetlands. However, the rule would exempt certain activities, such as permanent spoil fills and coal waste disposal facilities, and allow mining that changes a waterway’s flow, providing the mining company repairs damage later. Companies could also receive a permit to dispose of waste within the buffer zone if they explain why an alternative is not reasonably possible or is not necessary to meet environmental requirements. Environmental groups have brought lawsuits challenging the rule. It is unclear what impact the rule will have on the previously discussed lawsuits related to valley fills or any mining operations undertaken by PVR’s lessees in the future.
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Table of ContentsTotal Maximum Daily Load, or TMDL, regulations under the CWA establish a process to calculate the maximum amount of a pollutant that a water body can receive and still meet state water quality standards and to allocate pollutant loads among the point- and non-point pollutant sources discharging into that water body. This process applies to those waters that states have designated as impaired (not meeting present water quality standards). Industrial dischargers, including coal mines, discharging to such waters will be required to meet new TMDL allocations for these stream segments. The adoption of new TMDL-related allocations for streams to which 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. 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.
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Table of ContentsMining 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. 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 OSHA. See “—Oil and Gas Segment—OSHA.” PVR Natural Gas Midstream Segment General Regulation. PVR’s natural gas gathering facilities generally are exempt from the FERC’s jurisdiction under 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
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Table of Contentsproducers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering rates and access. We cannot assure you that federal and state authorities will retain their current regulatory policies in the future. Texas and Oklahoma administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, or the NGPSA, which requires certain natural gas pipelines to comply with safety standards in constructing and operating the pipelines, and subjects pipelines to regular inspections. PVR also operates a NGL pipeline that is subject to regulation by the U.S. Department of Transportation under the Hazardous Liquids Pipeline Safety Act of 1979, as amended, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. In response to recent pipeline accidents, Congress and the U.S. Department of Transportation have instituted heightened pipeline safety requirements. Certain of 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 Wastes.” 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 CERCLA “hazardous substance,” or be subject to regulation under state laws. 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.
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Table of ContentsWater 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 “—Oil and Gas Segment—OSHA.” Employees and Labor Relations We and our subsidiaries had a total of 392 employees at December 31, 2008, including 157 employees who directly supported PVR’s operations. We consider our current employee relations to be favorable. Available Information Our internet address is http://www.pennvirginia.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, Audit Committee Charter, Compensation and Benefits Committee Charter and Nominating and Governance Committee Charter and we will provide copies of such documents to any shareholder 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 references 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.
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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 Related to Our Oil and Gas Business Natural gas and crude oil prices are volatile, and a substantial or extended decline in prices would hurt our profitability and financial condition. Our revenues, operating results, cash flow, profitability, future rate of growth and the carrying value of our oil and gas properties depend heavily on prevailing market prices for natural gas and crude oil. Historically, natural gas and crude oil prices have been volatile, and they are likely to continue to be volatile. Wide fluctuations in natural gas and crude oil prices may result from relatively minor changes in the supply of and demand for oil and gas, market demand and other factors that are beyond our control, including:
Some of our projections and estimates are based on assumptions as to the future prices of natural gas and crude oil. These price assumptions are used for planning purposes. We expect our assumptions will change over time and that actual prices in the future will likely differ from our estimates. Any substantial or extended decline in the actual prices of natural gas or crude oil would have a material adverse effect on our financial position and results of operations (including reduced cash flow and borrowing capacity and possible asset impairment), the quantities of natural gas and crude oil reserves that we can economically produce, the quantity of estimated proved reserves that may be attributed to our properties and our ability to fund our capital program.
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Table of ContentsThe current deterioration of the credit and capital markets may adversely impact our ability to obtain financing on acceptable terms or obtain funding under our revolving credit facility. This may hinder or prevent us from implementing our development plan, completing acquisitions or otherwise meeting our future capital needs. Global financial markets have been experiencing extreme volatility and disruption, and the debt and equity capital markets have been exceedingly distressed. These issues have made, and will likely continue to make, it difficult to obtain financing. In particular, the cost of raising money in the equity capital markets has increased substantially while the availability of funds from those markets has diminished significantly. The current global economic downturn may adversely impact our ability to issue additional equity in the future at prices which will not be dilutive to our existing shareholders or preclude us from issuing equity at all. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers. Moreover, even if lenders and institutional investors are willing and able to provide adequate funding, interest rates may rise in the future and therefore increase the cost of borrowing we incur on any of our floating rate debt. In addition, we may be unable to obtain adequate funding under our revolving credit facility, or the Revolver, because (i) our lending counterparties may be unwilling or unable to meet their future funding obligations or (ii) our borrowing base is re-determined twice a year and may decrease as a result of lower oil or natural gas prices and declines in reserves. See “Long-Term Debt” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for a more detailed description of our and PVR’s debt covenants and borrowing capacities. Due to these factors, we cannot be certain that future funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, it might adversely affect our development plan as currently anticipated and our ability to complete acquisitions each of which could have a material adverse effect on our production, revenues and results of operations. Our future performance depends on our ability to find or acquire additional oil and gas reserves that are economically recoverable. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in oil and gas production and lower revenues and cash flows from operations. We have historically succeeded in substantially replacing reserves primarily through exploration and development and, to a lesser extent, acquisitions. We have conducted such activities on our existing oil and gas properties as well as on newly acquired properties. We may not be able to continue to replace reserves from such activities at acceptable costs. The currently depressed oil and gas prices may further limit the types of reserves that can be developed at acceptable costs. Lower prices also decrease our cash flows and may cause us to reduce capital expenditures. The business of exploring for, developing or acquiring reserves is capital intensive. We may not be able to make the necessary capital investments to maintain or expand our oil and gas reserves if cash flows from operations are reduced and external sources of capital remain limited or unavailable due to the deterioration of the global economy, including financial and credit markets. In addition, exploration and development activities involve numerous risks that may result in dry holes, the failure to produce oil and gas in commercial quantities and the inability to fully produce discovered reserves. We are continually identifying and evaluating acquisition opportunities. However, competition for producing oil and gas properties is intense and many of our competitors have financial and other resources substantially greater than those available to us. Depending on the longevity of the deterioration of the market, our ability to make acquisitions may be significantly adversely affected. In the event we are successful in completing an acquisition, we cannot ensure that such acquisition will consist of properties that contain economically recoverable reserves or that such acquisition will be profitably integrated into our operations. We may not be able to fund our planned capital expenditures. We make, and will continue to make, substantial capital expenditures to find, acquire, develop, exploit and produce oil and natural gas reserves. In 2009, we anticipate making oil and gas segment capital expenditures, excluding acquisitions, of up to approximately $250.0 million. This is $391.7 million, or 61%, lower than the $641.7 million of capital expenditures, excluding acquisitions, that our oil and gas segment made in 2008. As a result of our decreased anticipated capital expenditures, we project a decrease in the number of wells that will be drilled in 2009.
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Table of ContentsIf oil and gas prices decrease or we encounter operating difficulties that result in our cash flow from operations being less than expected, we may have to reduce the capital we can spend unless we raise additional funds through debt or equity financing. The current global economic downturn may adversely impact our ability to issue additional equity in the future at prices which will not be dilutive to our existing shareholders or preclude us from issuing equity at all. In addition, debt financing may not be available if needed and to the extent required, on acceptable terms. Future cash flows and the availability of financing will also be subject to a number of variables, such as:
If our revenues were to decrease due to lower oil and natural gas prices, decreased production or other reasons, and if we could not obtain capital through the Revolver, or otherwise, our ability to execute our development plans, replace our reserves or maintain production levels could be greatly limited. Exploration and development drilling may not result in commercially productive reserves. Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive natural gas or oil reserves will be found. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:
The prevailing prices of oil and gas also affect the cost of and the demand for drilling rigs, production equipment and related services. The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region. Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays which jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to explore on or develop our properties. The wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that natural gas or oil is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Drilling activities can result in dry wells or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover initial drilling costs. Our future drilling activities may not be successful, nor can we be sure that our overall drilling success rate or our drilling success rate within a particular area will not decline. Unsuccessful drilling activities could have a material adverse effect on our business results of operations or financial condition. Also, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Although we have identified numerous potential drilling locations, we may not be able to economically produce oil or natural gas from all of them.
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Table of ContentsWe are exposed to the credit risk of our customers, and nonpayment or nonperformance by our customers would reduce our cash flows. We are subject to risk from loss resulting from our customers’ nonperformance or nonpayment. We depend on a limited number of customers for a significant portion of revenues from our oil and gas segment. In 2008, 30% of our oil and gas segment revenues and 11% of our total consolidated revenues resulted from two of our oil and gas customers. Any nonpayment or nonperformance by our oil and gas customers would reduce our cash flows. Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate. Our operations are subject to all of the risks and hazards typically associated with the exploitation, development and exploration for and the production and transportation of oil and natural gas. These operating risks include:
Any of these risks could result in substantial losses resulting from injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damages, clean-up responsibilities, regulatory investigations and penalties and suspension of operations. In addition, under certain circumstances, we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease or operate. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse effect on our business, results of operations or financial condition. Our business depends on transportation facilities owned by others. We deliver substantially all of our oil and natural gas production through pipelines that we do not own. The marketability of our production depends upon the availability, proximity and capacity of these pipelines as well as gathering systems and processing facilities. The unavailability or lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Federal, state and local regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and market our oil and natural gas. Estimates of oil and natural gas reserves are not precise. This Annual Report on Form 10-K contains estimates of our proved oil and gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. These estimates are dependent on many variables and, therefore, changes often occur as these variables evolve and commodity prices fluctuate. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from those estimated. Any significant variance could
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Table of Contentsmaterially affect the estimated quantities and present value of reserves disclosed by us. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. At December 31, 2008, approximately 49% of our estimated proved reserves were proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is based on volumetric calculations and adjacent reserve performance data. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Production revenues from proved developed non-producing reserves will not be realized until some time in the future. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our reserves and the costs associated with these reserves in accordance with industry standards, these estimated costs may not be accurate, development may not occur as scheduled and actual results may not occur as estimated. You should not assume that the present value of estimated future net cash flows (standardized measure) referred to herein is the current fair value of our estimated oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual current and future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. As a result, net present value estimates using actual prices and costs may be significantly less than the SEC estimate that is provided herein. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor for us. The oil and gas segment may record impairment losses on its oil and gas properties. Quantities of proved reserves are estimated based on economic conditions in existence in the period of assessment. Lower oil and gas prices may have the impact of shortening the economic lives on certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, thus reducing proved property reserve estimates. If such revisions in the estimated quantities of proved reserves occur, it will have the effect of increasing the rates of depreciation, depletion and amortization, or DD&A, on the affected properties, which would decrease earnings or result in losses through higher DD&A expense. The revisions may also be sufficient enough to cause impairment losses on certain properties that would result in a further non-cash expense to earnings. If natural gas, crude oil and NGL prices decline or we drill uneconomic wells, it is reasonably possible we will have a significant impairment. We have limited control over the activities on properties we do not operate. In 2008, other companies operated approximately 21% of our net production. Our success in properties operated by others will depend upon a number of factors outside of our control, including timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other participants in drilling wells, selection of technology and maintenance of safety and environmental standards. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund for their operation. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns or lead to unexpected future costs. Certain working interest owners in our properties have the right to control the timing of drilling activities on our properties under certain circumstances. Under certain circumstances, certain of the other working interest owners in our properties have the right to limit the amount of drilling activities that can take place on our properties at any given time. If these working interest owners chose to exercise this right, we could be required to scale back anticipated drilling activities on the affected properties. In such an event, production from the affected properties would be deferred, thereby decreasing production from the properties in the short-term. Our producing property acquisitions carry significant risks. Acquisition of producing oil and gas properties is a key element of maintaining and growing reserves and production. Competition for these assets has been and will continue to be intense. Depending on the longevity of the deterioration of the market, our ability to make acquisitions may be significately adversely affected. In the event we do complete an acquisition,
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Table of Contentsits success will depend on a number of factors, many of which are beyond our control. These factors include the purchase price, future oil and gas prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation and development activities on the acquired properties and future abandonment and possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject properties will not necessarily reveal all existing or potential problems. Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited. Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results, and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions. Derivative transactions may limit our potential gains and involve other risks. In order to manage our exposure to price risks in the sale of our oil and natural gas, we periodically enter into oil and gas price hedging arrangements with respect to a portion of our expected production. Our hedges are limited in duration, usually for periods of two years or less. While intended to reduce the effects of volatile oil and natural gas prices, such transactions may limit our potential gains if oil or natural gas prices were to rise over the price established by the hedging arrangements. In trying to maintain an appropriate balance, we may end up hedging too much or too little, depending upon how oil or natural gas prices fluctuate in the future. In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
In addition, derivative instruments involve basis risk. Basis risk in a derivative contract occurs when the index upon which the contract is based is more or less variable than the index upon which the hedged asset is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of production may have more or less variability than the regional price index used for the sale of that production. We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business. Exploration, development, production and sale of oil and gas are subject to extensive federal, state and local laws and regulations, including complex environmental laws. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations, inability to obtain necessary regulatory approvals or a failure to comply with existing legal requirements may harm our business, results of operations or financial condition. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection and taxation. Our operations create the risk of environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations, we may be charged with remedial costs. Laws and regulations protecting the environment have become more stringent in recent years, and may, in some circumstances, result in liability for environmental damage regardless of negligence or fault. In addition, pollution and similar environmental risks generally are
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Table of Contentsnot fully insurable. These liabilities and costs could have a material adverse effect on our business, financial condition or results of operations. See Item 1, “Business—Government Regulation and Environmental Matters—Oil and Gas Segment—Environmental Matters.” Risks Related to Our Ownership Interests in PVG and PVR We are not the only partners of PVG and PVR, and PVG’s and PVR’s respective partnership agreements require them to distribute all available cash to their respective partners, including public unitholders. PVG and PVR are publicly traded limited partnerships. We own PVG GP, LLC, the sole general partner of PVG. As of December 31, 2008, we also owned an approximately 77% limited partner interest in PVG. As of December 31, 2008, PVG owned an approximately 37% limited partner interest in PVR, as well as 100% of the general partner of PVR, which owns a 2% general partner interest and the IDRs. We directly owned an additional 0.1% limited partner interest in PVR as of December 31, 2008. The remainder of the outstanding limited partner interests in each of PVG and PVR are owned by public unitholders. Although PVG’s and PVR’s respective partnership agreements require them to distribute, on a quarterly basis, 100% of their available cash to their respective unitholders of record and their respective general partners, we are not the only limited partners of PVG and PVR and, therefore, we receive only our proportionate share of cash distributions from each of PVG and PVR based on our partner interests in each of them. The remainder of the quarterly cash distributions is distributed, pro rata, to the public unitholders. For each of PVG and PVR, available cash is generally all cash on hand at the end of each quarter, after payment of fees and expenses and the establishment of cash reserves by their respective general partners. PVG’s and PVR’s general partners determine the amount and timing of cash distributions by PVG and PVR and have broad discretion to establish and make additions to the respective partnership’s reserves in amounts the general partner determines to be necessary or appropriate:
Accordingly, cash distributions we receive on our partner interests in PVG and PVR may be reduced at any time, or we may not receive any cash distributions from PVG or PVR, which would in turn reduce our available cash. PVG’s ability to make distributions to us is entirely dependent upon PVG receiving distributions from PVR, and the amount of cash that PVR will be able to distribute to its unitholders, including PVG, principally depends upon the amount of cash it can generate from its coal and natural resource management and natural gas midstream businesses. PVG’s 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 its distributions to its partners, including us. The amount of cash that PVR will be able to distribute to its partners, including PVG, 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:
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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:
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, PVG will have less cash available for distribution to its unitholders, including us, and would probably be required to reduce its per unit distribution to its unitholders, including us. 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. Since PVR’s inception as a publicly traded partnership, it has grown principally by making acquisitions in both of its business segments and, to a lesser extent, by organic growth on its properties. Readily available access to debt and equity capital and credit availability has been and continue to be critical factors in PVR’s ability to grow. The current deterioration in the global financial markets and the consequential adverse effect on credit availability is adversely impacting PVR’s access to new capital and credit availability. Depending on the longevity and ultimate severity of this deterioration, PVR’s ability to make acquisitions may be significantly adversely affected, as may PVR’s ability to make cash distributions to its unitholders and, in turn, would affect our ability to make cash distributions to our unitholders. 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 PVG. PVG’s ability to distribute cash received from PVR to its unitholders, including us, is limited by a number of factors, including:
A reduction in PVR’s distributions will disproportionately affect the amount of cash distributions to which PVG is currently entitled, and, consequently, will affect the amount of cash distributions PVG is able to make to its unitholders, including us. PVG’s ownership of the IDRs in PVR, through PVG’s ownership of PVR’s general partner, entitles PVG to receive its 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 IDRs to the extent of cash distributions by PVR up to and including $0.275 per unit for any quarter. PVG’s IDRs entitle it to receive increasing percentages, up to 50%, of incremental cash distributions above $0.375 per unit distributed by PVR on a quarterly basis. Because PVG is at the maximum target cash distribution level on the IDRs,
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Table of Contentsfuture growth in distributions PVG receives from PVR, and in distributions we receive from PVG, will not result from an increase in the target cash distribution level associated with the IDRs. Furthermore, a decrease in the amount of distributions by PVR to less than $0.375 per unit per quarter would reduce PVG’s percentage of the incremental cash distributions above $0.325 per common unit per quarter from 50% to 25%, consequently resulting in less cash available to PVG to distribute to its unitholders, including us. A decrease in the amount of distributions by PVR and, consequently, PVG may be caused by a variety of circumstances. PVR may generate less cash available for distributions or determine to create larger reserves in computing cash available for distribution. Even if cash available for distribution remained stable, PVG and PVR may determine to modify the IDRs to reduce the percentage of incremental cash distributions such IDRs are entitled to receive. 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, which in turn may reduce the available cash that PVG has to distribute to its unitholders, including us. PVR has wide latitude to issue additional limited partner interests on the terms and conditions established by its general partner. PVG receives cash distributions from PVR on the general partner interest, IDRs and the limited partner interest that PVG holds. Because a majority of the cash PVG receives from PVR is attributable to PVG’s indirect ownership of the IDRs, 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 PVG receives and the available cash that PVG has to distribute to its unitholders, including us. Conflicts of interest may arise because the board of directors of the respective general partners of PVG and PVR has a fiduciary duty to manage the general partners in a manner that is beneficial to their owners, and at the same time, in a manner that is beneficial to the respective unitholders of PVG and PVR. We own the sole general partner of PVG and PVG owns the sole general partner of PVR. PVG and PVR are publicly traded limited partnerships. Each of the board of directors of the general partners owes a fiduciary duty to the respective unitholders of PVG and PVR, and not just to us and PVG as owners of the general partners. As a result of these conflicts, the board of directors of the general partners of PVG and PVR may favor the interests of the public unitholders of PVG and PVR over the interests of the respective owners of the general partners. Our ability to sell our common units of PVG, and PVG’s ability to sell its partner interests in PVR, may be limited by securities law restrictions and liquidity constraints. As of December 31, 2008, we owned 30,077,429 common units of PVG and PVG 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 or PVG were to register these units, we or PVG are limited to selling into the market in any three-month period an amount of PVG common units or 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, PVG faces contractual limitations on its ability to sell its general partner interest and IDRs in PVR and the market for such interests is illiquid. Congress is considering proposed legislation that may, if enacted, negatively impact the value of our limited partner interests in PVG by precluding PVG from qualifying for treatment as a partnership for U.S. federal income tax purposes under the publicly traded partnership rules. In response to recent public offerings of interests in the management operations of private equity funds and hedge funds, members of Congress are considering substantive changes to the definition of qualifying income under Section 7704(d) of the Internal Revenue Code and changing the characterization of certain types of income received from partnerships. In particular, one proposal recharacterizes certain income and gain received with respect to “investment service partnership interests” as ordinary income for the performance of services, which may not be treated as qualifying income for publicly traded partnerships. As such proposal is currently interpreted, a significant portion of PVG’s interests in PVR may be viewed as an investment service partnership interest. Although we are unable to predict whether the proposed legislation, or any other proposals, will ultimately be enacted, the enactment of any such legislation could negatively impact the value of our limited partner interests in PVG. Risks Related to PVR’s Coal and Natural Resource Management Business
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Table of ContentsIf PVR’s lessees do not manage their operations well or experience financial difficulties, 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:
If PVR’s lessees do not manage their operations well, or if they experience financial difficulties, their production could be reduced, which would result in lower coal royalties revenues to PVR and could have a material adverse effect on PVR’s business, results of operations or financial condition. 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’ 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:
Any interruptions to the production of coal from PVR’s reserves could reduce its coal royalties revenues and could have a material adverse effect on PVR’s business, results of operations or financial condition. 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 have a material adverse effect on PVR’s business, results of operations or financial condition.
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Table of ContentsA 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. In addition, because a majority of PVR’s coal royalties are derived from coal mined on PVR’s properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price, PVR’s coal royalties revenues could be reduced by such a decline. Such a decline could also reduce PVR’s 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. The future impact of the current deterioration of the global economy, including financial and credit markets on coal production levels and prices is uncertain. Depending on the longevity and ultimate severity of the deterioration, demand for coal may decline, which could adversely effect production and pricing for coal mined by PVR’s lessees, and, consequently, adversely effect the royalty income received by PVR. 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 the year ended December 31, 2008, five primary operators, each with multiple leases, accounted for 65% of PVR’s coal royalties revenues and 7% of our total consolidated revenues. If any of these operators enters bankruptcy or decides to cease operations or significantly reduces 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 PVR’s 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. The current deterioration in the global economy, including financial markets, and the consequential adverse effect on credit availability is adversely impacting PVR’s access to new capital and credit availability. Depending on the longevity and ultimate severity of this deterioration, PVR’s ability to make acquisitions may be significantly adversely affected. If PVR is unable to negotiate purchase contracts to replace or increase its coal reserves on acceptable terms, PVR’s coal royalties revenues will decline as its coal reserves are depleted and PVR could, therefore, experience a material adverse effect on its business, results of operations or financial condition. If PVR is able to acquire 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 royalties 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.
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Table of ContentsFluctuations 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’ workforces could become increasingly unionized in the future, which could adversely affect their productivity and thereby reduce PVR’s coal royalties revenues. One of PVR’s lessees has one mine operated by unionized employees. This mine was PVR’s third largest mine on the basis of coal production for the year ended December 31, 2008. 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:
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 accounted for approximately 90% of domestic coal consumption in 2007. 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.”
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Table of ContentsExtensive 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. 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.” Concerns about the environmental impacts of fossil-fuel emissions, including perceived impacts on global climate change, are resulting in increased regulation of emissions of greenhouse gases in many jurisdictions and increased interest in and the likelihood of further regulation, which could significantly affect PVR’s coal royalties revenues. Global climate change continues to attract considerable public and scientific attention. Several widely publicized scientific reports have engendered widespread concern about the impacts of human activity, especially fossil fuel combustion, on global climate change. Legislative attention in the United States is being paid to global climate change and to reducing greenhouse gas emissions, particularly from coal combustion by power plants. Such legislation was introduced in Congress in 2006, 2007 and 2008 to reduce greenhouse gas emissions in the United States and further proposals or amendments are likely to be offered in the future. Although the United States Supreme Court’s recent decision in Massachusetts v. Environmental Protection Agency related to new motor vehicles, the reasoning of the decision could affect regulation of carbon dioxide emissions under other federal regulatory programs, including those that regulate emissions from coal-fired power plants. Several states have also either passed legislation or announced initiatives focused on decreasing or stabilizing carbon dioxide emissions associated with the combustion of fossil fuels, and many of these measures have focused on emissions from coal-fired power plants. See Item 1, “Business—Governmental Regulation and Environmental Matters—PVR Coal and Natural Resource Management Segment—Air Emissions.” Enactment of laws, passage of regulations regarding greenhouse gas emissions by the United States or some of its states, or other actions to limit carbon dioxide emissions could result in electric generators switching from coal to other fuel sources. This may adversely affect the use of and demand for fossil fuels, particularly coal. Delays in 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 CWA’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 CWA Section 404 permits to construct valley fills and sediment control ponds. Ongoing uncertainty over which waters are subject to the CWA may adversely impact PVR’s lessees’ ability to secure these necessary permits. In addition, a 2007 decision by a U.S. District Court in West Virginia invalidated a permit issued to one of PVR’s lessees for the Republic No. 2 Mine and enjoined PVR’s lessee, Alex Energy, Inc., from taking any further actions under this permit. This ruling was appealed and the appellate court reversed and vacated the district court’s order. It is unclear if this ruling will be appealed or if the permits will be challenged on other grounds. Uncertainty over the correct legal standard for issuing Section 404 permits may lead to rulings invalidating other permits, additional challenges to various permits and additional delays and costs in applying for and obtaining new permits that could ultimately have an adverse effect on PVR’s
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Table of Contentscoal 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. The PVR coal and natural resource management segment may record impairment losses on its long-lived assets. The PVR coal and natural resource management segment has completed a number of acquisitions in recent years. See Note 4, “Acquisitions and Divestitures,” in the Notes to Consolidated Financial Statements in Item 8, “Financial Statements and Supplementary Data,” for a description of the PVR coal and natural resource management segment’s material acquisitions. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, and the resulting amount of goodwill, if any. Unforeseen changes in operations, the business environment or market conditions could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows. This could result in impairment charges being recorded in our consolidated statements of income. 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,
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Table of Contentswhich 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. 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. PVR typically does not obtain independent evaluations of natural gas reserves dedicated to its gathering systems; therefore, volumes of natural gas on PVR’s systems in the future could be less than it anticipates. PVR typically does not obtain independent evaluations of natural gas reserves connected to its gathering systems due to the unwillingness of producers to provide reserve information, as well as the cost of such evaluations. Accordingly, PVR does not have independent estimates of total reserves dedicated to its gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to PVR’s gathering systems is less than it anticipates and PVR’s is unable to secure additional sources of natural gas, then the volumes of natural gas gathered on PVR’s gathering systems in the future could be less than PVR anticipates. A decline in the volumes of natural gas on PVR’s systems could have a material adverse effect on PVR’s business, results of operations or financial condition. A reduction in demand for NGL products by the petrochemical, refining or heating industries could materially adversely affect PVR’s business, results of operations and financial condition. The NGL products PVR produces, including ethane, propane, normal butane, isobutane and natural gasoline, have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general economic conditions, new government regulations, reduced demand by consumers for products made with NGL products, increased competition from petroleum-based products due to pricing differences, mild winter weather or other reasons, could result in a decline in the volume of NGL products PVR handles or reduce the fees PVR charges for its services. Any reduced demand for PVR’s NGL products could adversely affect demand for the services PVR provides as well as NGL prices, which would negatively impact PVR’s results of operations and financial condition. 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 2008, PVR 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— gas purchase/keep-whole and percentage-of-proceeds arrangements. See Item 1, “Business—Contracts—PVR Natural Gas Midstream Segment.” Virtually all of the system throughput volumes in PVR’s Crescent System and Hamlin System are processed under percentage-of-proceeds arrangements. The system throughput volumes in PVR’s Panhandle System are processed 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 on either an index price or the price actually received for gas and NGLs. Under these arrangements, revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have a material adverse effect on PVR’s business, results of operations or financial condition. 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 business, results of operations or financial condition.
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Table of ContentsIn 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:
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. Readily available access to debt and equity capital and credit availability has been and continues to be critical factors in PVR’s ability to grow. The current deterioration in the global economy, including financial markets, and the consequential adverse effect on credit availability is adversely impacting PVR’s access to new capital and credit availability. Depending on the longevity and ultimate severity of the deterioration, PVR’s ability to make acquisitions may be significantly adversely affected. In the event PVR completes acquisitions, 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 might not generate increases in PVR’s cash distributions to its unitholders, and because of the capital used to complete such acquisitions, or the debt incurred, PVR’s and our results of operations may change significantly. 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. PVR’s access to such capital is currently adversely impacted by the deterioration in the global economy, including financial and credit markets. If PVR does undertake these projects, they may not be completed on schedule, or at all, or at the anticipated 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 have a material adverse effect on PVR’s business, results of operations or financial condition. 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.
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Table of ContentsPVR 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 the year ended December 31, 2008, 40% of PVR’s natural gas midstream segment revenues and 24% of our total consolidated revenues related to two of PVR’s natural gas midstream segment customers. Any nonpayment or nonperformance by PVR’s natural gas midstream segment 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 condensate, 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 (or decline with respect to natural gas hedges entered into to lock the frac spread) over the price established by the hedging arrangements. Moreover, PVR has entered into derivative transactions related to only a portion of its condensate, natural gas and NGL volumes. As a result, PVR will continue to have direct commodity price risk with respect to the unhedged portion of these volumes. 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:
In addition, derivative instruments involve basis risk. Basis risk in a derivative contract occurs when the index upon which the contract is based is more or less variable than the index upon which the hedged asset is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of production may have more or less variability than the regional price index used for the sale of that production. The accounting standards regarding hedge accounting are complex, and even when PVR engages in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect volatility due to these derivatives, even when there is no underlying economic impact at that point. In addition, it is not always possible for PVR to engage in a derivative transaction that completely mitigates its exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which PVR is unable to enter into a completely effective hedge transaction. 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:
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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 business, results of operations or financial condition. 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 business, results of operations or 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 PVR natural gas midstream segment ever desires to apply for blanket transportation authority to transport third-party gas on the 11-mile pipeline. The FERC may revoke these waivers at any time. 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 business, 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. The PVR 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, 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
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Table of Contentslaws, 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.” The PVR natural gas midstream segment may record impairment losses on its long-lived assets. The PVR natural gas midstream segment has completed a number of acquisitions in recent years. See Note 4, “Acquisitions and Divestitures,” in the Notes to Consolidated Financial Statements in Item 8, “Financial Statements and Supplementary Data,” for a description of the PVR natural gas midstream segment’s material acquisitions. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, and the resulting amount of goodwill, if any. Unforeseen changes in operations, the business environment or market conditions could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows. This could result in impairment charges being recorded in our consolidated statements of income. The North Texas Gas Gathering System has a limited operating history and has system throughput volumes representing only a small percentage of its total design capacity. The assets comprising the North Texas Gas Gathering System were all built after June 2005 and, consequently, have a limited operating history. In addition, the total current system throughput volumes on the North Texas Gas Gathering System represent only a small percentage of its total design capacity. Accordingly, the North Texas Gas Gathering System to date has generated only modest levels of revenues. In order for PVR’s 2008 acquisition of substantially all of the assets of Lone Star Gathering L.P., or Lone Star, to be a success, PVR will need to substantially increase system throughput volumes over historical levels. Any such increase will require a significant increase in PVR’s producers’ production in the areas served by the North Texas Gas Gathering System, and no assurance can be given that they will be able to so increase production or sustain such an increase over time. In particular, while producers are currently actively drilling in Johnson and Hill Counties, PVR expects that the success of the Lone Star acquisition will require producers to expand their drilling and production activities in Bosque, Hamilton, Somervell and Erath Counties. PVR also will need to operate the North Texas Gas Gathering System reliably and efficiently, in the absence of any significant operating history on which to draw. While the North Texas Gas Gathering System is modern, there may be unexpected operating and capital expenditures necessary to operate it properly. In addition, PVR will need to effectively integrate the North Texas Gas Gathering System within its existing natural gas midstream business, both operationally and administratively. We cannot assure that these endeavors will be successful. If PVR is unsuccessful, the revenues from the North Texas Gas Gathering System will be adversely affected.
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, 2008.
Title to Properties The following map shows the general locations of our oil and gas production and exploration, PVR’s coal reserves and related infrastructure investments and PVR’s natural gas gathering and processing systems as of December 31, 2008:
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We believe that we have satisfactory title to all of our properties and the associated oil, natural gas and coal reserves in accordance with standards generally accepted in the oil and natural gas, coal and natural resource management and natural gas midstream industries. Facilities We are headquartered in Radnor, Pennsylvania, with additional offices in Oklahoma, Tennessee, Texas and West Virginia. All of our office facilities are leased, except for PVR’s West Virginia office, which it owns. We believe that our properties are adequate for our current needs. Oil and Gas Segment Properties As is customary in the oil and gas industry, we make only a cursory review of title to farmout acreage and to undeveloped oil and gas leases upon execution of any contracts. Prior to the commencement of drilling operations, a thorough title examination is conducted and curative work is performed with respect to significant defects. To the extent title opinions or other investigations reflect defects, we cure such title defects. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on a property, we could suffer a loss of our investment in the property. Prior to completing an acquisition of producing oil and gas assets, we obtain title opinions on all material leases. Our oil and gas properties are subject to customary royalty interests, liens for current taxes and other burdens that we believe do not materially interfere with the use or materially affect the value of such properties. Production and Pricing The following table sets forth production, average realized prices and production expenses with respect to our properties in the oil and gas segment for the years ended December 31, 2008, 2007 and 2006:
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Proved Reserves The following table presents certain information regarding our proved reserves as of December 31, 2008, 2007 and 2006. The proved reserve estimates presented below were prepared by Wright and Company, Inc., independent petroleum engineers. No reserve estimate has been filed with any federal authority or agency since January 1, 2008. For additional information regarding estimates of proved reserves, the preparation of such estimates by Wright and Company, Inc. and other information about our oil and gas reserves, see the Supplemental Information on Oil and Gas Producing Activities (Unaudited) in the Notes to Consolidated Financial Statements in Item 8, “Financial Statements and Supplementary Data.” Our estimates of proved reserves in the following table are consistent with those filed by us with other federal agencies.
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In accordance with the SEC’s guidelines, the engineers’ estimates of future net revenues from our properties and the standardized measure thereof are based on oil and natural gas sales prices in effect as of December 31, 2008, and estimated future costs as of December 31, 2008. The prices are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. Prices for oil and gas are subject to substantial seasonal fluctuations as well as fluctuations resulting from numerous other factors. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Proved reserves are the 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. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. Therefore, the standardized measure amounts shown above should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. The information set forth in the foregoing tables includes revisions of certain volumetric reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in production prices. Production and Reserves by Region The following table sets forth by region the estimated quantities of proved reserves as of December 31, 2008:
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The following table sets forth by region the average daily production and total production for the years ended December 31, 2008, 2007 and 2006:
Acreage The following table sets forth our developed and undeveloped acreage as of December 31, 2008. The acreage is located primarily in the Appalachian, Mississippi, East Texas, Mid-Continent and Gulf Coast regions of the United States.
Wells Drilled The following table sets forth the gross and net numbers of exploratory and development wells that we drilled during the years ended December 31, 2008, 2007 and 2006. The number of wells drilled refers to the number of wells reaching total depth at any time during the respective year. Net wells equal the number of gross wells multiplied by our working interest in each of the gross wells. Productive wells represent either wells which were producing oil or gas or which were capable of production.
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The eleven development wells under evaluation at December 31, 2008 included seven Cotton Valley wells in East Texas, one horizontal Lower Bossier (Haynesville) Shale well in East Texas, one additional well in East Texas and two wells in the Mid-Continent region. The exploratory well under evaluation at December 31, 2008 was in the Mid-Continent region. The four exploratory wells under evaluation as of December 31, 2007 included two Devonian Shale wells in West Virginia, one New Albany Shale well in Illinois and one horizontal CBM well in West Virginia. In 2008, we determined that all four wells were not commercially viable. Accordingly, we charged $4.3 million to expense related to those wells. The exploratory well under evaluation as of December 31, 2006 was a Cotton Valley well in East Texas. In 2007, we determined that this well was commercially viable and reclassified $1.1 million to wells, equipment and facilities based on the determination of proved reserves. Productive Wells The following table sets forth the number of productive oil and gas wells in which we had a working interest at December 31, 2008. Productive wells are wells that are producing oil or gas or that are capable of commercial production.
In addition to the above working interest wells, we own royalty interests in 2,611 gross wells. Coal Reserves and Production As of December 31, 2008, PVR owned or controlled approximately 827 million tons of proven and probable coal reserves located on approximately 495,000 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:
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 coal reserves are defined as follows:
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Table of ContentsProven Coal Reserves. Proven coal reserves are reserves for which: (i) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; (ii) grade and/or quality are computed from the results of detailed sampling; and (iii) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well defined, that the size, shape, depth and mineral content of reserves are well-established. Probable Coal Reserves. Probable coal reserves are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are more widely spaced or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven 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 coal reserves.” Included among the factors that influence profitability are the existing market price, coal quality and operating costs. The following tables set forth production data for the years ended December 31, 2008, 2007 and 2006 and reserve information as of December 31, 2008 with respect to each of PVR’s properties:
The following table sets forth the coal reserves PVR owned and leased with respect to each of its coal properties as of December 31, 2008:
The following table sets forth PVR’s coal reserve activity for each of its coal properties for the years ended December 31, 2008, 2007 and 2006:
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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 243,000 acres of forestland in Kentucky, Virginia and West Virginia. Approximately 26% of PVR’s forestland is located on the approximately 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 Divestitures,” 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 10.9 Bcfe of proved oil and gas reserves located on approximately 56,000 acres in Kentucky, Virginia and West Virginia. Approximately 85% of PVR’s oil and gas royalty interests are associated with the leases of property in eastern Kentucky and southwestern Virginia that PVR acquired from us in October 2007. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Acquisitions and Divestitures” for a discussion of PVR’s oil and gas royalty interest acquisition. Natural Gas Midstream Systems 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. 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 owned five natural gas processing facilities having 300 MMcfd of total capacity as of December 31, 2008. PVR’s natural gas midstream operations currently include four natural gas gathering and processing systems and two stand-alone natural gas gathering systems, including: (i) the Panhandle gathering and processing facilities in the Texas/Oklahoma panhandle area; (ii) the Crossroads gathering and processing facilities in East Texas; (iii) the Crescent gathering and processing facilities in central Oklahoma; (iv) the Arkoma gathering system in eastern Oklahoma; (v) the North Texas gathering and pipeline facilities in the Fort Worth Basin; and (vi) the Hamlin gathering and processing facilities in west-central Texas. These assets included approximately 4,069 miles of natural gas gathering pipelines as of December 31, 2008. In addition, PVR owns a 25% member interest in Thunder Creek, a joint venture that gathers and transports CBM in Wyoming’s Powder River Basin. The following table sets forth information regarding PVR’s natural gas midstream assets:
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Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. See Item 1, “Business—Government Regulation and Environmental Matters,” for a more detailed discussion of our material environmental obligations.
There were no matters submitted to a vote of security holders during the fourth quarter of 2008.
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Table of ContentsPart II
Market Information Our common stock is traded on the NYSE under the symbol “PVA.” The high and low sales prices (composite transactions) and dividends paid for each fiscal quarter in 2008 and 2007 were as follows:
Equity Holders As of February 6, 2009, there were 500 record holders and approximately 8,261 beneficial owners (held in street name) of our common stock. Performance Graph The following graph compares our five-year cumulative total shareholder return (assuming reinvestment of dividends) with the cumulative total return of the Standard & Poor’s 600 Oil & Gas Exploration & Production Index and the Standard & Poor’s SmallCap 600 Index. There are six companies in the Standard & Poor’s 600 Oil & Gas Exploration & Production Index: Cabot Oil & Gas Corporation, Penn Virginia Corporation, Petroleum Development Corporation, St. Mary Land & Exploration Company, Stone Energy Corporation and Swift Energy Company. The graph assumes $100 is invested on January 1, 2004 in us and each index at December 31, 2003 closing prices.
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Table of ContentsComparison of Cumulative Five-Year Total Return Penn Virginia Corporation, S&P SmallCap 600 Index and S&P 600 Oil & Gas Exploration & Production Index
The following selected historical financial information was derived from our consolidated financial statements as of December 31, 2008, 2007, 2006, 2005 and 2004, 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.”
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The following discussion and analysis of the financial condition and results of operations of Penn Virginia Corporation and its subsidiaries (“Penn Virginia,” “we,” “us” or “our”) should be read in conjunction with our consolidated financial statements and the accompanying notes in Item 8, “Financial Statements and Supplementary Data.” Overview of Business We are an independent oil and gas company primarily engaged in the development, exploration and production of natural gas and oil in various domestic onshore regions including East Texas, the Mid-Continent, Appalachia, Mississippi and the Gulf Coast. We also indirectly own partner interests in PVR, which is engaged in the coal and natural resource management and natural gas midstream businesses. Our ownership interests in PVR are held principally through our general partner interest and our 77% limited partner interest in PVG. As of December 31, 2008, PVG owned an approximately 37% limited partner interest in PVR and 100% of the general partner of PVR, which holds a 2% general partner interest in PVR and all of the IDRs. We are engaged in three primary business segments: (i) oil and gas, (ii) coal and natural resource management and (iii) natural gas midstream. We operate our oil and gas segment and PVR operates the coal and natural resource management and natural gas midstream segments. Our operating income was $256.8 million in 2008, compared to $192.6 million in 2007 and $170.5 million in 2006. Our segments’ contributions to operating income in 2008 were as follows:
These contributions to operating income were partially offset by $29.0 million of intercompany eliminations and corporate expenses, or 10%. The following table presents a summary of certain financial information relating to our segments for the years ended December 31, 2008, 2007 and 2006:
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We have grown by making acquisitions in all three of our business segments and by organic growth on our and PVR’s properties. Readily available access to debt and equity capital and credit availability have been and continue to be critical factors in our and PVR’s ability to grow. The current deterioration in global financial markets and the consequential adverse effect on credit availability is adversely impacting our and PVR’s access to new capital and credit availability. Depending on the longevity and ultimate severity of this deterioration, our and PVR’s ability to make acquisitions may be significantly adversely affected, as may PVR’s ability to make cash distributions to its limited partners and to PVG, the owner of its general partner. See Item 1A, “Risk Factors.” Oil and Gas Segment We have a geographically diverse asset base with core areas of operation in the East Texas, Mid-Continent, Appalachian, Mississippi and Gulf Coast regions of the United States. As of December 31, 2008, we had proved natural gas and oil reserves of approximately 916 Bcfe, of which 82% were natural gas and 51% were proved developed. As of December 31, 2008, 97% of our proved reserves were located in primarily longer-lived, lower-risk basins in East Texas, the Mid-Continent, Appalachia and Mississippi, which comprised 43%, 15%, 19% and 15% of the proved reserves. Our Gulf Coast properties, representing 3% of proved reserves, are shorter-lived and have higher impact exploratory prospects. In 2008, we produced 46.9 Bcfe, a 16% increase compared to 40.6 Bcfe in 2007, with East Texas, the Mid-Continent, Appalachia, Mississippi and the Gulf Coast comprising 29%, 16%, 25%, 16% and 16% of total production volumes. In the three years ended December 31, 2008, we drilled 785 gross (544.4 net) wells, of which 94% were successful in producing natural gas in commercial quantities. For a more detailed discussion of our reserves and production, see Item 2, “Properties.” The primary development play types that our oil and gas operations are focused on include: (i) the horizontal Lower Bossier (Haynesville) Shale and vertical Cotton Valley plays in East Texas, (ii) the horizontal Granite Wash, horizontal Hartshorne CBM and the Woodford Shale plays in the Mid-Continent, (iii) multi-lateral horizontal CBM and Marcellus Shale plays in Appalachia and (iv) the predominantly horizontal Selma Chalk play in Mississippi. We have grown our reserves and production primarily through development and exploratory drilling, complemented to a lesser extent by making strategic acquisitions. In 2008, we replaced 604% of our 2008 production entirely through the
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Table of Contentsdrillbit by adding approximately 283 Bcfe of proved reserves from extensions, discoveries and additions, net of revisions. In 2008, capital expenditures in our oil and gas segment were $641.7 million, of which $481.4 million, or 75%, was related to development drilling, $23.8 million, or 4%, was related to exploratory drilling, $95.5 million, or 15%, was related to leasehold acquisitions and $36.8 million, or 6%, was related to pipelines, gathering and facilities. As of December 31, 2008, we owned 1.2 million net acres of leasehold interests, approximately 37% of which were undeveloped. We have identified approximately 1,400 proved undeveloped locations and over 2,800 additional potential drilling locations, of which approximately half are located in East Texas and the Mid-Continent. Many of our proved undeveloped locations and additional potential drilling locations are direct offsets or extensions from existing production. We believe our existing undeveloped acreage position represents over 10 years of drilling opportunities based on our historical drilling rate. Our operations include both conventional and unconventional developmental drilling opportunities, as well as some exploratory prospects. In the East Texas play, we drilled 102 gross (76.4 net) wells in 2008, including 93 gross (68.4 net) successful wells. We recently shifted our focus to the Lower Bossier (Haynesville) Shale play, which we believe has increased proved reserves and production levels. In Appalachia, we drilled 75 gross (33.1 net) wells in 2008, including 18 gross (9.0 net) horizontal CBM locations and 71 gross (30.6 net) successful locations. In the Selma Chalk play in Mississippi, we drilled 29 gross (28.6 net) wells in 2008, including 28 gross (27.6 net) successful horizontal wells. We also have unconventional development programs in the Mid-Continent and some higher-impact exploratory prospects in the Gulf Coast. In the Mid-Continent region, we drilled 75 gross (37.7 net) wells in 2008, including 29 gross (23.9 net) successful CBM locations. Our aggressive growth profile in our oil and gas segment has been accomplished primarily by drilling oil and natural gas wells in our operating areas and, to a lesser extent, by making acquisitions of both producing properties and undeveloped leases. This growth profile has required us to spend capital in excess of our cash flow from operations, and readily available access to debt and equity capital were and continue to be a critical factor in our ability to grow. The current deterioration in global financial markets and the consequential adverse effect on credit availability is adversely impacting access to new capital and expanded credit availability. We currently have internal cash flows and available credit facility borrowings that we believe supports growth through 2009. However, depending on the longevity and ultimate severity of the global financial and credit markets deterioration, we may ultimately need to limit our capital spending to more closely mirror internally generated cash flow, which may materially adversely effect how aggressively we can grow. See Item 1A, “Risk Factors.” In addition, our revenues, profitability and future rate of growth are highly dependent on the prevailing prices for oil and natural gas, which are affected by numerous factors that are generally beyond our control. Crude oil prices are generally determined by global supply and demand. Natural gas prices are influenced by national and regional supply and demand. A substantial or extended decline in the price of oil or natural gas could have a material adverse effect on our revenues, profitability and cash flow and could, under certain circumstances, result in an impairment of some of our oil and natural gas properties. Our future profitability and growth are also highly dependent on the results of our exploratory and development drilling programs. PVR Coal and Natural Resource Management Segment As of December 31, 2008, PVR owned or controlled approximately 827 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. PVR enters into long-term leases with experienced, third-party mine operators, providing them the right to mine PVR’s 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 PVR’s properties. PVR does not operate any mines. In 2008, PVR’s lessees produced 33.7 million tons of coal from its properties and paid PVR coal royalties revenues of $122.8 million, for an average royalty per ton of $3.65. Approximately 86% of PVR’s coal royalties revenues in 2008 were derived from coal mined on PVR’s 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 PVR’s properties under leases containing fixed royalty rates that escalate annually. 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 its customers’ ability to use coal and which may require PVR, its lessees or its lessees’ customers to change operations significantly or incur substantial costs. See Item 1A, “Risk Factors.”
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Table of ContentsTo 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. PVR also earns revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees. The future impact of the current deterioration of the global economy, including financial and credit markets, on coal production levels and prices is uncertain. Depending on the longevity and ultimate severity of the deterioration, demand for coal may decline, which could adversely effect production and pricing for coal mined by PVR’s lessees, and, consequently, adversely effect the royalty income received by PVR and its ability to make cash distributions to its limited partners and to PVG, the owner of PVR’s general partner. PVR Natural Gas Midstream Segment PVR’s natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of December 31, 2008, PVR owned and operated natural gas midstream assets located in Oklahoma and Texas, including five natural gas processing facilities having 300 MMcfd of total capacity and approximately 4,069 miles of natural gas gathering pipelines. PVR’s natural gas midstream business earns revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In addition, PVR owns a 25% member interest in Thunder Creek, a joint venture that gathers and transports CBM in Wyoming’s Powder River Basin. 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. In 2008, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 98.7 Bcf, or approximately 270 MMcfd. In 2008, 27% and 13% of PVR’s natural gas midstream segment revenues and 16% and 8% of our total consolidated revenues were related to two of PVR’s natural gas midstream customers, Conoco, Inc. and Louis Dreyfus Energy Services. 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. In 2008, PVR’s natural gas midstream segment made aggregate capital expenditures of $333.3 million, primarily related to PVR’s 25% member interest acquisition of Thunder Creek, the Lone Star acquisition, PVR’s acquisition of pipeline assets in the Anadarko Basin of Oklahoma and Texas and PVR’s capacity expanding capital expenditures related to the Spearman and Crossroads plants. For a more detailed discussion of PVR’s acquisitions and investments, see “— Acquisitions and Divestitures.” 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. The current deterioration in global economy, including financial and credit markets, will likely result in a decrease in worldwide demand for oil and domestic demand for natural gas and NGLs. Depending on the longevity and ultimate severity of the deterioration, NGL production from PVR’s processing plants could decrease and adversely effect its natural gas midstream processing income and PVR’s ability to make cash distributions to its limited partners and to PVG, the owner of PVR’s general partner. Eliminations and Other Eliminations and other primarily represents elimination of intercompany sales, corporate functions such as interest expense and income tax expense, and the oil and gas segment derivatives. Ownership of and Relationship with PVG and PVR Penn Virginia, PVG and PVR are publicly traded on the NYSE under the symbols “PVA,” “PVG” and “PVR.” As of December 31, 2008, we owned the general partner of PVG and an approximately 77% limited partner interest in PVG. PVG
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Table of Contentsalso owns an approximately 37% limited partner interest in PVR and 100% of the general partner of PVR, which holds a 2% general partner interest in PVR and all of the IDRs. We directly owned an additional 0.1% limited partner interest in PVR as of December 31, 2008. Because PVG controls the general partner of PVR, the financial results of PVR are included in PVG’s consolidated financial statements. Because we control the general partner of PVG, the financial results of PVG are included in our consolidated financial statements. However, PVG and PVR function with capital structures that are independent of each other and us, with each having publicly traded common units and PVR having its own debt instruments. PVG does not currently have any debt instruments. While we report consolidated financial results of PVR’s coal and natural resource management and natural gas midstream businesses, the only cash we received from those businesses is in the form of cash distributions we received from PVG and PVR in respect of our partner interests in each of them. In conjunction with the initial public offering of PVG, we contributed our general partner interest, IDRs and most of our limited partner interest in PVR to PVG in exchange for the general partner interest and a limited partner interest in PVG. We are currently entitled to receive quarterly cash distributions from PVG and PVR on our limited partner interests in PVG and PVR. As a result, we received total distributions of $44.0 million and $29.8 million from PVG and PVR in the years ended December 31, 2008 and 2007 as shown in the following table:
We have historically received increasing distributions from our partner interests in PVG and PVR. Based on PVG’s and PVR’s current annualized distribution rates of $1.52 and $1.88 per unit, we would receive aggregate annualized distributions of $46.3 million in respect of our partner interests in the year ended December 31, 2009. As a result of PVR’s 2008 unit offering, we recognized a gain in shareholders’ equity and PVG recognized gains in its partners’ capital. See Note 3 – “Summary of Significant Accounting Policies” and Note 6 – “PVR Unit Offering” in the Notes to Consolidated Financial Statements in Item 8, “Financial Statements and Supplementary Data.” Prior to PVG’s initial public offering in December 2006, we indirectly owned common units representing an approximately 37% limited partner interest in PVR, as well as the sole 2% general partner interest and all of the IDRs in PVR. We received total distributions from PVR of $28.6 million in 2006, allocated among our limited partner interest, general partner interest and IDRs as shown in the following table:
Acquisitions and Divestitures Oil and Gas Segment In July 2008, we completed the sale of certain unproved oil and gas acreage in Louisiana for cash proceeds of $32.0 million and recognized a $30.5 million gain on that sale. In October 2007, we acquired lease rights to property covering 4,800 acres located in East Texas, with estimated proved reserves of 21.9 Bcfe. The purchase price was $44.9 million in cash and was funded with long-term debt under the Revolver.
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Table of ContentsIn October 2007, we sold to PVR oil and gas royalty interests associated with leases of property in eastern Kentucky and southwestern Virginia with estimated proved reserves of 8.7 Bcfe at January 1, 2007. The sale price was $31.0 million in cash, and the proceeds of the sale were used to repay borrowings under the Revolver. The gain on the sale and the related depletion expenses have been eliminated in the consolidation of our financial statements. In September 2007, we sold non-operated working interests in oil and gas properties located in eastern Kentucky and southwestern Virginia, with estimated proved reserves of 13.3 Bcfe. The sale price was $29.1 million in cash, and the proceeds of the sale were used to repay borrowings under the Revolver. We recognized a gain of $12.4 million on the sale, which is reported in the revenues section of our consolidated statements of income. In August 2007, we acquired lease rights to property covering approximately 22,700 acres located in eastern Oklahoma, with estimated proved reserves of 18.8 Bcfe. The purchase price was $47.9 million in cash and was funded with long-term debt under the Revolver. In July 2007, we acquired lease rights to property covering approximately 4,000 acres located in East Texas, with estimated proved reserves of 19.5 Bcfe. The purchase price was $22.0 million in cash and was funded with long-term debt under the Revolver. In June 2006, we acquired 100% of the capital stock of Crow Creek Holding Corporation, or Crow Creek. Crow Creek was a privately owned independent exploration and production company with operations primarily in the Oklahoma portions of the Arkoma and Anadarko Basins. Crow Creek’s assets included estimated net proved reserves of 42.7 Bcfe, approximately 85% of which were natural gas. The purchase price was $71.5 million in cash and was funded with long-term debt under the Revolver. PVR Coal and Natural Resource Management Segment In May 2008, PVR acquired fee ownership of approximately 29 million tons of coal reserves and approximately 56 million board feet of hardwood timber in western Virginia and eastern Kentucky. The purchase price was $24.5 million in cash and was funded with long-term debt under PVR’s revolving credit facility, or the PVR Revolver. 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 the PVR Revolver. 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 the PVR Revolver. 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 in cash and was funded with long-term debt under the PVR Revolver. PVR Natural Gas Midstream Segment In July 2008, PVR completed the Lone Star acquisition. Lone Star’s assets are located in the southern portion of the Fort Worth Basin of North Texas and include approximately 129 miles of gas gathering pipelines and approximately 240,000 acres dedicated by active producers. The Lone Star acquisition expanded the geographic scope of the PVR natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin. PVR acquired this business for approximately $164.3 million and a liability of $4.7 million, which represents the fair value of a $5.0 million guaranteed payment, plus contingent payments of $30.0 million and $25.0 million. Funding for the acquisition was provided by $80.7 million of borrowings under the PVR Revolver, 2,009,995 PVG common units (which PVR purchased from two of our subsidiaries for $61.8 million) and 542,610 newly issued PVR common units. The contingent payments will be triggered if revenues from certain assets located in a defined geographic area reach certain targets by or before June 30, 2013 and will be funded in cash or PVR common units, at PVR’s election. In April 2008, PVR acquired a 25% member interest in Thunder Creek, a joint venture that gathers and transports CBM in Wyoming’s Powder River Basin. The purchase price was $51.6 million in cash, after customary closing adjustments, and was funded with long-term debt under the PVR Revolver.
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Table of ContentsIn 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 Panhandle System. The purchase price was $14.7 million and was funded with cash. Subsequently, PVR borrowed $14.7 million under the PVR Revolver to replenish the cash used for the acquisition. Liquidity and Capital Resources Although results are consolidated for financial reporting, Penn Virginia, PVG and PVR operate with independent capital structures. Since PVR’s inception in 2001 and PVG’s inception in 2006, with the exception of cash distributions paid to us by PVG and PVR, the cash needs of each entity have been met independently with a combination of operating cash flows, credit facility borrowings and the issuance of new PVG and PVR units. We expect that our cash needs and the cash needs of PVG and PVR will continue to be met independently of each other with a combination of these funding sources. Liquidity is defined as the ability to convert assets into cash or to obtain cash. Short-term liquidity refers to the ability to meet short-term obligations of 12 months or less. Liquidity is a matter of degree and is expressed in terms of working capital and the current ratio and, due to the recent deterioration of the credit and financial markets, in terms of the availability of borrowing capacity against existing credit facilities and debt instruments. Our consolidated working capital (current assets minus current liabilities) and consolidated current ratio (current assets divided by current liabilities) are as follows as of December 31, 2008 and 2007:
As discussed in more detail in “Long-Term Debt” below, as of December 31, 2008, we had availability of $146.7 million, subject to redetermination in the second quarter of 2009, and PVR had availability of $130.3 million under our separate credit facilities. With respect to Penn Virginia (excluding the sources and uses of capital by PVG and PVR), we satisfy our working capital requirements and fund our capital expenditures using cash generated from our operations, borrowings under the Revolver and proceeds from equity offerings. We satisfy our debt service obligations and dividend payments solely using cash generated from our operations. We believe that the cash generated from our operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major capital improvements or acquisitions), scheduled debt payments and dividend payments. Our ability to satisfy our obligations and planned expenditures will depend on our future operating performance, which will be affected by, among other things, prevailing economic conditions in the commodity markets of oil and natural gas, some of which are beyond our control. In addition, depending on the longevity and ultimate severity of the current deterioration of the global economy, including financial and credit markets, our ability to grow through acquisitions may be significantly adversely effected. This is due to our debt capacity not being as readily expandable as in the past, which is driven by the overall restrictions on lending by the banking industry. Because of this deterioration in the financial and credit markets, we are anticipating a decrease in capital spending in 2009. See Item 1A, “Risk Factors.” PVR’s ability to satisfy its obligations and planned expenditures will depend upon its future operating performance, which will be affected by prevailing economic conditions in the coal industry and natural gas midstream market, some of which are beyond PVR’s control. In addition, depending on the longevity and ultimate severity of the current deterioration of the global economy, including financial and credit markets, PVR’s ability to grow may be significantly adversely affected, as may PVR’s ability to make acquisitions and cash distributions to its limited partners, to us and to PVG, the owner of PVR’s general partner. This is due to PVR’s debt capacity not being as readily expandable as in the past, which is driven by the overall restrictions on lending by the banking industry. Because of these restrictions to PVR’s debt capacity and deterioration in the financial and credit markets, PVR is anticipating a decrease in capital spending in 2009. See Item 1A, “Risk Factors.”
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Table of ContentsCash Flows Except where noted, the following discussion of cash flows and capital expenditures relates to our consolidated results. The following table summarizes our cash flow statements for the years ended December 31, 2008, 2007 and 2006, consolidating the PVG cash flow statement and the oil and gas, corporate and other cash flow statement:
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Table of ContentsNet Cash Provided by Operating Activities Changes to working capital and to our current ratio are largely affected by net cash provided by both our and PVR’s operating activities. Net cash provided by our and PVR’s operating activities primarily came from the following sources: Oil and gas segment:
PVR coal and natural resource management segment:
PVR natural gas midstream segment:
In addition, we receive settlements from our interest rate swaps, or the Interest Rate Swaps, which are included in our corporate and other activities. Both we and PVR use the cash provided by operating activities in the oil and gas segment, the PVR coal and natural resource management segment and the PVR natural gas midstream segment in the following ways:
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Table of ContentsNet cash provided by operating activities of the oil and gas segment and for Penn Virginia corporate and other activities in 2008 increased by $60.0 million, or 32%, to $246.6 million from $186.6 million in 2007. This increase was primarily attributable to increased natural gas, crude oil and NGL revenues resulting from increases in both production and pricing, partially offset by increased staffing costs in the oil and gas segment; increased severance taxes, which were driven by increased natural gas, crude oil and NGL production; increased cash outflows for oil and gas commodity derivative settlements; and increased operating costs in the oil and gas segment. See “ –Oil and Gas Segment” and “–Eliminations and Other – Corporate Operating Expenses” for a more detailed explanation of the factors that increased cash provided by operating activities. Net cash provided by operating activities of the oil and gas segment and for Penn Virginia corporate and other activities in 2007 increased by $11.5 million, or 7%, to $186.6 million from $175.1 million in 2006. The overall increase in cash provided by operating activities in 2007 compared to 2006 was primarily attributable to increased natural gas and crude oil production, partially offset by increased consulting fees and staffing costs. See “– Oil and Gas Segment” and “–Eliminations and Other –Corporate Operating Expenses” for a more detailed explanation of the factors that increased cash provided by operating activities. PVG does not have any operations on a stand-alone basis. It primarily relies on cash distributions received from PVR for its general and administrative expenses, which are the costs of PVG being a publicly-traded company. Net cash provided by PVG’s consolidated operating activities in 2008 increased by $10.7 million, or 8%, to $137.2 million from $126.5 million in 2007. The overall increase in net cash provided by PVG’s consolidated operating activities in 2008 compared to 2007 was primarily attributable to increased cash received from the sales of residue gas and NGLs, which was primarily driven by increased system throughput volume; increased coal royalties received, which was driven primarily by increased production and sales prices of coal in the Central Appalachian and Illinois Basin regions; and increased cash received from the sale of standing timber, which was due primarily to increased harvesting from PVR’s September 2007 forestland acquisition. These increases were partially offset by increased cash outflows from PVR’s natural gas midstream derivative settlements. See “– PVR Coal and Natural Resource Management Segment” and “– PVR Natural Gas Midstream Segment” for a more detailed explanation of the factors that increased cash provided by PVR’s operating activities. Net cash provided by PVG’s consolidated operating activities in 2007 increased by $25.8 million, or 26%, to $126.5 million from $100.7 million in 2006. This increase was primarily attributable to increased sales of NGLs, which was primarily driven by increased volumes of processed gas and a higher frac spread during 2007 than in 2006; and decreased cash outflows for PVR’s natural gas midstream commodity derivative settlements. These increases were partially offset by a decrease in coal royalties received, which was driven by a decrease in coal production from subleased properties in the Central Appalachian region. See “– PVR Coal and Natural Resource Management Segment” and “– PVR Natural Gas Midstream Segment” for a more detailed explanation of the factors that increased cash provided by PVR’s operating activities.
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Table of ContentsNet Cash Used in Investing Activities Net cash used in the oil and gas segment and for Penn Virginia corporate and other activities in 2008 increased by $55.2 million, or 12%, to $514.5 million from $459.3 million in 2007. PVG’s investing activities consist solely of cash provided by and used in PVR’s investing activities. Net cash used by PVR in its investing activities in 2008 increased by $106.8 million, or 48%, to $331.0 million from $224.2 million in 2007. The cash used by both us and PVR in investing activities for the years ended December 31, 2008, 2007 and 2006 were used primarily for capital expenditures. The following table sets forth capital expenditures by segment made during the years ended December 31, 2008, 2007 and 2006:
In 2008, the oil and gas segment made aggregate capital expenditures of $641.7 million. These capital expenditures were primarily discretionary capital ependitures and included development drilling and various lease acquisitions primarily in East Texas. In 2008, we drilled a successful horizontal Lower Bossier (Haynesville) Shale well in Harrison County, Texas. Based on this successful horizontal test, we had four drilling rigs drilling horizontal Lower Bossier (Haynesville) Shale wells as of December 31, 2008. In addition to these capital expenditures, we also completed the sale of unproved oil and gas acreage in Louisiana for cash proceeds of $32.0 million.
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Table of ContentsIn 2007, the oil and gas segment made aggregate capital expenditures of $520.4 million. These capital expenditures were primarily discretionary capital expenditures and included development drilling, the acquisitions of lease rights to property in eastern Oklahoma with estimated proved reserves of 18.8 Bcfe, the acquisition of lease rights to property in East Texas with estimated proved reserves of 21.9 Bcfe and lease rights to property in East Texas with estimated proved reserves of 19.5 Bcfe. In addition to these capital expenditures, we sold non-operated working interests in oil and gas properties located in eastern Kentucky and southwestern Virginia for $29.1 million in cash and sold to PVR oil and gas royalty interests associated with leases of property in eastern Kentucky and southwestern Virginia with estimated proved reserves of 8.7 Bcfe for $31.0 million. Other capital expenditures of $7.3 million in 2007 were also discretionary capital expenditures and were primarily due to consulting fees related to the implementation of a software system. In 2006, the oil and gas segment made aggregate capital expenditures of $338.5 million, which were primarily discretionary capital expenditures related to development drilling, the acquisition of Crow Creek for $71.5 million and exploratory drilling. In 2008, PVR made aggregate capital expenditures of $360.6 million. These capital expenditures consisted primarily of discretionary capital expenditures which included PVR’s 25% member interest acquisition in Thunder Creek, the Lone Star acquisition, pipeline assets in the Anadarko Basin of Oklahoma and Texas, expansion capital expenditures related to the Spearman and Crossroads plants and the acquisition of approximately 29 million tons of coal reserves and an estimated 56 million board feet of hardwood timber in western Virginia and eastern Kentucky. The PVR natural gas midstream segment also incurred approximately $14.5 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas. In 2007, PVR made aggregate capital expenditures of $225.5 million. These capital expenditures consisted primarily of discretionary capital expenditures, which included PVR’s coal reserve acquisitions, a forestland acquisition, an oil and gas royalty interest acquisition and natural gas midstream gathering system expansion projects. The PVR natural gas midstream segment also incurred $9.8 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas. In 2006, PVR made aggregate capital expenditures of $131.0 million. These capital expenditures consisted primarily of discretionary capital expenditures, which included PVR’s coal reserve acquisitions, coal loadout facility construction projects, a natural gas midstream acquisition and coal and natural gas midstream gathering system expansion projects. The PVR natural gas midstream segment also incurred $9.4 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas. We funded oil and gas and other capital expenditures in 2008 with borrowings under the Revolver, cash provided by operating activities, cash distributions received from PVG and PVR and cash provided by operating activities. We funded oil and gas and other capital expenditures in 2007 with borrowings under the Revolver, cash provided by operating activities, cash distributions received from PVG and PVR, the issuance of common stock and convertible notes, the sale of common stock warrants and proceeds from the sale of oil and gas working and royalty interests. We funded oil and gas and other capital expenditures in 2006 with cash provided by operating activities, cash distributions received from PVG and PVR and borrowings under the Revolver. PVR funded its coal and natural resource management and natural gas midstream capital expenditures in 2008 primarily with cash provided by operating activities, borrowings under the PVR Revolver, proceeds from the sale of common units and a contribution from its general partner to maintain its 2% general partner interest. PVR funded its capital expenditures in 2007 with cash provided by operating activities and borrowings under the PVR Revolver. PVR funded its capital expenditures in 2006 with cash provided by operating activities, borrowings under the PVR Revolver, proceeds from the sale of common and Class B units to PVG and a contribution from its general partner to maintain its 2% general partner interest. Net Cash Provided by Financing Activities Net cash provided by financing in the oil and gas segment and for corporate activities in 2008 decreased by $6.2 million, or 2%, to $263.9 million from $270.1 million in 2007, due primarily to proceeds received in 2007, but not 2008, for a stock offering, higher net proceeds from debt borrowings in 2008 and higher distributions received from PVG and PVR in 2008. Net cash provided by financing activities in the oil and gas segment and for corporate activities in 2007 increased by $108.7 million, or 67%, to $270.1 million from $161.4 million in 2006, due primarily to the $135.4 million in net proceeds received from our 2007 stock offering, $18.2 million received in 2007 for the stock warrants that we sold and higher distributions received from PVG and PVR in 2007, partially offset by the $36.8 million paid in 2007 for the convertible note hedges.
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Table of ContentsIn 2008, we had $210.0 million of net borrowings, consisting of borrowings under the Revolver of $273.0 million and repayments under the Revolver of $63.0 million. See “— Long-Term Debt” below for a more detailed description of our December 31, 2008 long-term debt balance. We had $131.0 million of net borrowings in 2007, comprised of net borrowings of $230.0 million under our convertible senior subordinated notes, or the Convertible Notes, and net repayments of $99.0 million under the Revolver. In addition, proceeds from the sale of our oil and gas working interests in 2007 were used to repay borrowings under the Revolver. We had net borrowings of $142.0 million under the Revolver in 2006, which consisted of $162.0 million of borrowings, partially offset by $20.0 million of repayments. As a result of our partner interests in PVG and PVR, we received cash distributions of $44.0 million in 2008, $29.8 million in 2007 and $28.6 million in 2006. These distributions we received were primarily used for oil and gas segment capital expenditures. Net cash provided by PVG’s financing activities in 2008 increased by $67.2 million, or 59%, to $181.7 million from $114.5 million in 2007. This increase was primarily due to net PVR borrowings of $156.0 million in 2008, comprised of net borrowings of $220.4 million under the PVR Revolver and net repayments of $64.4 million under PVR’s Senior Unsecured Notes due 2013, or the PVR Notes. See “— Long-Term Debt” below for a more detailed description of PVR’s December 31, 2008 long-term debt balance. PVR also received net proceeds of $141.1 million from the sale of its common units in a public offering in 2008, which was comprised of net proceeds of $138.2 million from the sale of the common units to the public and $2.9 million in contributions from its general partner to maintain its 2% general partner interest in PVR. These increases in 2008 financing activities were partially offset by increased cash distributions paid to PVR’s and PVG’s partners. Cash distributions paid to unaffiliated partners increased by $28.7 million, or 36%, from $79.6 million in 2007 to $108.3 million in 2008 because both PVG and PVR increased their cash distributions paid per unit. This increase in cash distributions paid to unaffiliated partners was also due to the increase in PVR’s outstanding common units resulting from PVR’s 2008 unit offering, where PVR issued an additional 5.15 million PVR common units to the public. See “– PVR Unit Offering” below for a more detailed description of this event. PVR also incurred $4.2 million of payments for debt issuance costs. Net cash provided by PVG’s financing activities in the year ended December 31, 2008 was used primarily for PVR’s capital expenditures. PVR’s cash distributions per unit increased in every sequential quarter from the distribution paid in February 2007 for the fourth quarter of 2006 through the distribution paid in November 2008 for the third quarter of 2008. However, the most recent cash distribution paid to PVR’s partners in February 2009 for the fourth quarter of 2008 was unchanged from the distribution paid for the immediately prior quarter. PVG’s cash distribution per unit increased in every sequential quarter from the distribution paid in May 2007 for the first quarter of 2007 to the distribution paid in November 2008 for the third quarter of 2008. However, the most recent cash distribution paid to PVG’s partners in February 2009 for the fourth quarter of 2008 was unchanged from the distribution paid for the immediately prior quarter. Both PVG and PVR will continue to be cautious about increasing cash distributions to unitholders in the foreseeable future in order to preserve cash liquidity in light of uncertain commodity and financial markets. Net cash provided by PVG’s financing activities in 2007 increased by $95.0 million, or 486%, to $114.5 million from $19.5 million in 2006. This increase is due primarily to $193.5 million of net borrowings in 2007, comprised of net borrowings of $204.5 million under the PVR Revolver and net repayments of $11.0 million under the PVR Notes. These increases in 2007 financing activities were partially offset by cash distributions paid to PVG’s and PVR’s partners. Distributions to partners increased by $18.8 million, or 31%, from $60.8 million in 2006 to $79.6 million in 2007 because PVG and PVR increased their cash distributions paid per unit. Net cash provided by PVG’s financing activities in the year ended December 31, 2007 was used primarily for PVR’s capital expenditures. In December 2006, PVG completed its initial public offering and used substantially all of the resulting proceeds to purchase newly issued common and Class B units from PVR. PVR used the proceeds received from this transaction to repay $114.6 million of debt outstanding under the PVR Revolver. PVR had a total of $37.1 million of net repayments of debt in 2006, comprised of $28.8 million of net repayments under the PVR Revolver and $8.3 million of net repayments under the PVR Notes. PVG and PVR also paid $60.8 million in cash distributions to their partners in 2006. In January 2009, PVG declared a $0.38 ($1.52 on an annualized basis) per unit quarterly distribution for the three months ended December 31, 2008, of which we will receive $11.4 million, or $45.6 million on an annualized basis, as a result of our limited partner interest in PVG. This distribution was paid on February 18, 2009 to unitholders of record at the close of business on February 2, 2009. In January 2009, PVR declared a $0.47 ($1.88 on an annualized basis) per unit quarterly distribution for the three months ended December 31, 2008, of which we will receive $0.1 million, or $0.4 million on an annualized basis, as a result of our limited partner interest in PVR. This distribution was paid on February 13, 2009 to
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Table of Contentsunitholders of record at the close of business on February 2, 2009. The portion of PVR’s distribution paid to PVG serves as the basis for PVG’s distribution to its unitholders, including us. Long-Term Debt Revolver. As of December 31, 2008, we had $332.0 million outstanding under the Revolver, which is senior to the Convertible Notes. At the current $479.0 million limit on the Revolver, and given our outstanding balance of $332.0 million, net of $0.3 million of letters of credit, we could borrow up to $146.7 million at December 31, 2008. The Revolver, which matures in December 2010, is secured by a portion of our proved oil and gas reserves. Our borrowing base can be redetermined twice per year. The Revolver is available to us for general purposes, including working capital, capital expenditures and acquisitions, and includes a $20.0 million sublimit for the issuance of letters of credit. We had outstanding letters of credit of $0.3 million as of December 31, 2008. In 2008, we incurred commitment fees of $0.8 million on the unused portion of the Revolver. The commitments, which can be redetermined relative to our borrowing base, cannot be withdrawn by the bank. We capitalized $2.0 million of interest cost incurred in 2008. The Revolver is governed by a borrowing base calculation and is redetermined semi-annually. We anticipate that the Revolver’s borrowing base will be decreased when it is redetermined in the second quarter of 2009. We have the option to elect interest at (i) London Interbank Offered Rate, or LIBOR, plus a margin ranging from 1.00% to 1.75%, based on the ratio of our outstanding borrowings to the borrowing base or (ii) the greater of the prime rate or federal funds rate plus a margin of up to 1.00%. The weighted average interest rate on borrowings outstanding under the Revolver during 2008 was approximately 4.4%. We do not have a public credit rating for the Revolver. The financial covenants under the Revolver require us not to exceed specified ratios. We are required to maintain a Debt-to-EBITDAX ratio of no more than 3.5-to-1.0 and at December 31, 2008 such ratio was 1.5-to-1.0. We are also required to maintain an EBITDAX-to-interest expense ratio of no less than 2.5-to-1.0 and at December 31, 2008 such ratio was 21.8-to-1.0. In the event that we would be in default of our covenants, we could appeal to the banks for a waiver of the covenant default. Should the banks deny our appeal to waive the covenant default, the outstanding borrowings under the Revolver would become payable upon demand and would be reclassified to the current liabilities section of our consolidated balance sheet. The Revolver contains cross-default provisions for default of indebtedness of more than $5.0 million. The Revolver does not contain a subjective acceleration clause. EBITDAX, which is a non-GAAP measure, is generally defined in the Revolver as our net income before the effects of interest expense, interest income, income tax expense, DD&A expense, other similar non-cash charges, exploration expense, non-cash compensation expense and non-cash hedging activity. For covenant calculation purposes, EBITDAX is further adjusted for distributions received through the company’s ownership in PVG and for dividends paid to shareholders. In addition, the financial covenants impose dividend limitation restrictions. The Revolver contains various other covenants that limit our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business or enter into a merger or sale of our assets, including the sale or transfer of interests in our subsidiaries. As of December 31, 2008, we were in compliance with all of our covenants under the Revolver. Convertible Notes, Note Hedges and Warrants. As of December 31, 2008, we had $230.0 million of Convertible Notes outstanding. The Convertible Notes bear interest at a rate of 4.50% per year payable semiannually in arrears on May 15 and November 15 of each year. We do not have a public credit rating for the Convertible Notes. The Convertible Notes are convertible into cash up to the principal amount thereof and shares of our common stock, if any, in respect of the excess conversion value, based on an initial conversion rate of 17.3160 shares of common stock per $1,000 principal amount of the Convertible Notes (which is equal to an initial conversion price of approximately $57.75 per share of common stock), subject to adjustment, and, if not converted or repurchased earlier, will mature on November 15, 2012. Holders of Convertible Notes may convert their Convertible Notes at their option prior to the close of business on the business day immediately preceding September 15, 2012 only under the following circumstances: (i) during any fiscal quarter if the last reported sale price per share of common stock for at least 20 trading days (whether or not consecutive) in the 30 consecutive trading days ending on the last trading day of the immediately preceding fiscal quarter is greater than or equal to 130% of the then applicable conversion price on each such trading day; (ii) during the five business day period after any ten consecutive trading day period in which the trading price per $1,000 principal amount of the Convertible Notes for each day of such period was less than 98% of the product of the last reported sale price per share of common stock and the applicable conversion rate on each such day; or (iii) upon the occurrence of certain corporate events set forth in the indenture governing the Convertible Notes. On and after September 15, 2012 until the close of business on the third business day immediately preceding November 15, 2012, holders of the Convertible Notes may convert their Convertible Notes at any time, regardless of the foregoing circumstances.
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Table of ContentsThe holders of the Convertible Notes who convert their Convertible Notes in connection with a make-whole fundamental change, as defined in the indenture governing the Convertible Notes, may be entitled to an increase in the conversion rate as specified in the indenture governing the Convertible Notes. Additionally, in the event of a fundamental change, as defined in the indenture governing the Convertible Notes, the holders of the Convertible Notes may require us to purchase all or a portion of their Convertible Notes at a purchase price equal to 100% of the principal amount of the Convertible Notes, plus accrued and unpaid interest, if any. The Convertible Notes are our unsecured senior subordinated obligations, ranking junior in right of payment to any of our senior indebtedness and to any of our secured indebtedness to the extent of the value of the assets securing such indebtedness and equal in right of payment to any of our future unsecured senior subordinated indebtedness. The Convertible Notes will rank senior in right of payment to any of our future junior subordinated indebtedness and will structurally rank junior to all existing and future indebtedness of our subsidiaries. In connection with the sale of the Convertible Notes, we entered into convertible note hedge transactions, or the Note Hedges, with respect to shares of our common stock with affiliates of certain of the underwriters of the Convertible Notes (collectively, the “Option Counterparties”). The Note Hedges cover, subject to anti-dilution adjustments, the net shares of our common stock that would be deliverable to converting noteholders in the event of a conversion of the Convertible Notes. In December 2007, we paid an aggregate amount of $18.6 million of the net proceeds from the sale of the Convertible Notes for the cost of the Note Hedges (after such cost was offset by the proceeds of the Warrants described below). We also entered into separate warrant transactions, or the Warrants, whereby we sold to the Option Counterparties warrants to acquire, subject to anti-dilution adjustments, approximately 3,982,680 shares of our common stock at an exercise price of $74.25 per share. In December 2007, we received proceeds of $18.2 million resulting from this sale. Upon exercise of the Warrants, we will deliver shares of our common stock equal to the difference between the then market price and the strike price of the Warrants. If the market value per share of our common stock at the time of conversion of the Convertible Notes is above the strike price of the Note Hedges, the Note Hedges entitle us to receive from the Option Counterparties net shares of our common stock (and cash for any fractional share cash amount) based on the excess of the then current market price of our common stock over the strike price of the Note Hedges. Additionally, if the market price of our common stock at the time of exercise of the Warrants exceeds the strike price of the Warrants, we will owe the Option Counterparties net shares of our common stock (and cash for any fractional share cash amount), not offset by the Note Hedges, in an amount based on the excess of the then current market price of our common stock over the strike price of the Warrants. On October 3, 2008, one of the Option Counterparties, Lehman Brothers OTC Derivatives Inc., or Lehman OTC, joined other Lehman Brothers entities and filed for bankruptcy protection. We had purchased 22.5% of the Note Hedges from Lehman OTC, or the Lehman Note Hedges, for approximately $8.3 million, and we had sold 22.5% of the Warrants to Lehman OTC for approximately $4.1 million. If the Lehman Note Hedges are rejected or terminated in connection with the Lehman OTC bankruptcy, we would have a claim against Lehman OTC and possibly Lehman Brothers Inc., as guarantor, for the damages and/or close-out values resulting from any such rejection or termination. While we intend to pursue any claim for damages and/or close-out values resulting from the rejection or termination of the Lehman Note Hedges, at this point in the Lehman bankruptcy cases it is not possible to determine with accuracy the ultimate recovery, if any, that we may realize on potential claims against Lehman OTC or its affiliated guarantor resulting from any rejection or termination of the Lehman Note Hedges. We also do not know whether Lehman OTC will assume or reject the Lehman Note Hedges, and therefore cannot predict whether Lehman OTC intends to perform its obligations under the Lehman Note Hedges. If Lehman OTC does not perform such obligations and the price of our common stock exceeds the $57.75 conversion price (as adjusted) of the Convertible Notes, our existing shareholders would experience dilution at the time or times the Convertible Notes are converted. The extent of any such dilution would depend, among other things, on the then prevailing market price of our common stock and the number of shares of common stock then outstanding, but we believe the impact will not be material and will not affect our income statement presentation. We are not otherwise exposed to counterparty risk related to the bankruptcies of Lehman Brothers Inc. or its affiliates and do not believe that the Lehman bankruptcies will have a material adverse effect on our financial condition or results of operations. Interest Rate Swaps. We have entered into the Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver until December 2010. The notional amounts of the Interest Rate Swaps total $50.0 million, or approximately 15% of our total long-term debt outstanding under the Revolver. We will pay a weighted average fixed rate of 5.34% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. Settlements on the Interest Rate Swaps are recorded as interest expense. The Interest Rate Swaps followed hedge accounting. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period
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Table of Contentsin 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, 2008, the total interest rate on the $50.0 million portion of Revolver borrowings covered by the Interest Rate Swaps was 6.6% at December 31, 2008. PVR Revolver. As of December 31, 2008, net of outstanding borrowings of $568.1 million and letters of credit of $1.6 million, PVR had remaining borrowing capacity of $130.3 million on the PVR Revolver. PVR believes that its remaining borrowing capacity, which will be used primarily for capital expenditures, will be sufficient for its future capital needs and commitments. In August 2008, PVR increased the size of the PVR Revolver from $600.0 million to $700.0 million and secured the PVR Revolver with substantially all of PVR’s assets. The PVR Revolver matures in December 2011 and is available to PVR for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10.0 million sublimit for the issuance of letters of credit. In 2008, PVR incurred commitment fees of $0.5 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 PVR Revolver or at a rate derived from 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 2008 was approximately 4.6%. PVR does not have a public credit rating for the PVR Revolver. The financial covenants under the PVR Revolver require PVR not to exceed specified ratios. PVR is required to maintain a debt-to-consolidated EBITDA ratio of less than 5.25-to-1.0 and at December 31, 2008 such ratio was 4.05-to-1.0. PVR is also required to maintain a consolidated EBITDA-to-interest expense ratio of greater than 2.5-to-1.0 and at December 31, 2008, such ratio was 4.74-to-1.0. EBITDA, which is a non-GAAP measure, is generally defined in the PVR Revolver as PVR’s net income before the effects of interest expense, interest income, DD&A expense and non-cash hedging activity. In the event that PVR would be in default of its covenants, PVR could appeal to the banks for a waiver of the covenant default. Should the banks deny PVR’s appeal to waive the covenant default, the outstanding borrowings under the PVR Revolver would become payable upon demand and would be reclassified to the current liabilities section of our consolidated balance sheet. The PVR Revolver contains cross-default provisions for default of indebtedness of more than $7.5 million. The PVR Revolver does not contain a subjective acceleration clause. 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 PVR’s ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of PVR’s business, or enter into a merger or sale of PVR’s assets, including the sale or transfer of interests in PVR’s subsidiaries. As of December 31, 2008, PVR was in compliance with all of its covenants under the PVR Revolver. PVR Notes. In July 2008, PVR paid an aggregate of $63.3 million to the holders of the PVR Notes to prepay 100% of the aggregate principal amount of the PVR Notes. This amount consisted of approximately $58.4 million aggregate principal amount outstanding on the PVR Notes, $1.1 million in accrued and unpaid interest on the PVR Notes through the prepayment date and $3.8 million in make-whole amounts due in connection with the prepayment. The $3.8 million of make-whole payments were recorded in interest expense on our consolidated statements of income. The PVR Notes were repaid with borrowings under the PVR Revolver. While the PVR Notes were outstanding, PVR had a DBRS public credit rating. However, due to the repayment of the PVR Notes, PVR has elected not to renew this rating. As of December 31, 2007, PVR owed $64.0 million under the PVR Notes, the current portion of which was $12.6 million. The PVR Notes bore interest at a fixed rate of 6.02%. PVR Interest Rate Swaps. PVR has entered into the PVR Interest Rate 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 Interest Rate Swaps total $285.0 million, or approximately 50% of PVR’s total long-term debt outstanding as of December 31, 2008, with PVR paying a weighted average fixed rate of 3.67% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From March 2010 to December 2011, the notional amounts of the PVR Interest Rate Swaps total $225.0 million, with PVR paying a weighted average fixed rate of 3.52% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From December 2011 to December 2012, the notional amounts of the PVR Interest Rate Swaps total $75.0 million, with PVR paying a weighted average fixed rate of 2.10% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. The PVR Interest Rate Swaps extend one year past the maturity of the current PVR Revolver and they have been entered into with six financial institution counterparties, with no counterparty having more than 26% of the open positions. After considering the applicable margin of 1.75% in effect as of December 31, 2008, the total interest rate on the $285.0 million portion of PVR Revolver borrowings covered by the PVR Interest Rate Swaps was 5.42% at December 31, 2008. In January 2009, PVR entered into an additional $25.0 million interest rate swap with a maturity of December 2012. Inclusive of this additional interest rate swap, the
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Table of Contentsweighted average fixed interest rate PVR pays to its counterparties is 3.54% through March 2010, 3.37% from March 2010 through December 2011 and 2.09% from December 2011 through December 2012. PVR monitors changes in its counterparties and are not aware of any specific concerns regarding PVR’s counterparties’ ability to make payments under any of the PVR Interest Rate Swaps, including the January 2009 swap agreement. PVR Unit Offering In 2008, PVR issued 5.15 million common units to the public representing limited partner interests and received $138.2 million in net proceeds. PVR received total contributions of $2.9 million from its general partner in order to maintain its 2% general partner interest in PVR. The net proceeds were used to repay a portion of PVR’s borrowings under the PVR Revolver. Future Capital Needs and Commitments Subject to commodity prices and the availability of capital, we are committed to expanding our oil and gas operations over the next several years through a combination of development, exploration and acquisition of new properties. We have a portfolio of assets which balances relatively low risk, moderate to potentially higher return development projects in East Texas, the Mid-Continent, Appalachia and Mississippi, with higher risk, potentially higher return exploration prospects in south Louisiana and south Texas. We expect to continue to execute a program dominated by development drilling and, to a lesser extent, exploration drilling, supplemented periodically with property and reserve acquisitions. In 2009, we anticipate making oil and gas segment capital expenditures, excluding acquisitions, of up to approximately $250.0 million. The capital expenditures are expected to be primarily funded from internally generated sources of cash, including cash distributions received from PVG and PVR, supplemented by Revolver borrowings as needed. At December 31, 2008, we had $146.7 million of borrowing capacity under the Revolver. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on industry conditions, cash flows provided by operating activities and the availability of capital. We believe our cash flow from operating activities and sources of debt financing are sufficient to fund our 2009 planned oil and gas capital expenditure program. For future periods, we continue to assess funding needs for our growth opportunities in the context of our presently available debt capacity. We expect to use a combination of cash flows from operating activities, borrowings under the Revolver and issuances of additional debt and equity securities to fund our growth. However, if the current disruptions in the worldwide credit, capital and commodities markets continue into the future, our ability to grow will likely become limited. We cannot be certain that we will be able to issue our debt or equity securities on terms or in the amounts that we anticipate, or at all, and we may be unable to refinance the Revolver when it expires in 2010. In addition, we may be unable to obtain adequate funding under the Revolver because our lending counterparties may be unwilling or unable to meet their funding obligations. We believe our portfolio of assets provides us with opportunities for organic growth in 2009 which will require capital in excess of our internal sources. We expect to continue to rely on the Revolver to fund a large portion of our capital needs, supplemented by the issuance of additional debt and equity securities as needed, if available under commercially acceptable terms. Currently, PVG has no capital requirements. In the future, we may decide to facilitate PVR acquisitions and other capital expenditures by the issuance of PVG debt or equity if market conditions are favorable to such an issuance. PVR believes that its remaining borrowing capacity of $130.3 million will be sufficient for its 2009 capital needs and commitments. In 2009, PVR anticipates making capital expenditures, excluding acquisitions, of up to $72.0 million. The majority of the 2009 capital expenditures will be incurred in the PVR natural gas midstream segment. PVR intends to fund these capital expenditures with a combination of cash flows provided by operating activities and borrowings under the PVR Revolver. Long-term cash requirements for acquisitions and other capital expenditures are expected to be funded by several sources, including cash flows from operating activities, borrowings under the PVR Revolver and the issuances of additional debt and equity securities, if available under commercially acceptable terms. PVR’s short-term cash requirements for operating expenses and quarterly distributions to PVG, as the owner of PVR’s general partner, and unitholders are expected to be funded through operating cash flows. Part of PVR’s long-term strategy is to increase cash available for distribution to PVR’s unitholders by making acquisitions and other capital expenditures. PVR’s ability to make these acquisitions and other capital expenditures in the future will depend largely on the availability of debt financing and on PVR’s ability to periodically use equity financing
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Table of Contentsthrough the issuance of new common units. Future financing will depend on various factors, including prevailing market conditions, interest rates and PVR’s financial condition and credit rating. The current disruptions in the global financial and commodities markets and the general economic climate have made access to equity and debt capital markets very difficult since late in 2008. While signs of improvement in these markets have started to arise in 2009, with issuances of debt and equity securities by other publicly traded partnerships, the short-term outlook remains uncertain with respect to PVR’s ability to access the capital markets on acceptable terms. If the situation worsens and PVR is unable to access the capital markets for an extended period, PVR’s ability to make acquisitions and other capital expenditures, as well as PVR’s ability to increase or sustain cash distributions to its limited partners and to PVG, the owner of PVR’s general partner, will likely become limited. If additional financing is required, there are no assurances that it will be available, or if available, that it can be obtained on terms favorable to PVR or not dilutive to PVR’s future earnings. Contractual Obligations The following table summarizes our and PVR’s contractual obligations as of December 31, 2008:
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Part of the purchase price for the PVR Lone Star acquisition includes contingent payments of approximately $55.0 million. These contingency payments will be made by PVR if certain revenue targets are met before June 30, 2013. Because the outcome of these contingent payments is not determinable beyond a reasonable doubt, PVR did not accrue these contingent payments as a liability during the year ended December 31, 2008. Rather, once the revenue targets are met, the contingent payments will be recorded as an additional cost of Lone Star. Off-Balance Sheet Arrangements As of December 31, 2008, we did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We are, therefore, not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships. 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, 2008, 2007 and 2006:
Operating income increased in 2008 compared to 2007 primarily due to a $106.6 million increase in natural gas revenues, a $28.7 million increase in coal royalties and a $15.3 million increase in gross margin, partially offset by a $62.7 million increase in DD&A expenses and $51.8 million of impairments recorded in 2008. Operating income increased in 2007 compared to 2006 primarily due to a $49.3 million increase in natural gas revenues, a $21.8 million increase in natural gas midstream gross margin and $12.4 million in net gains on the sales of properties in 2007, partially offset by a $35.3 million increase in DD&A expense, a $17.4 million increase in general and administrative expenses and a $20.2 million increase in operating expenses. Net income increased in 2008 compared to 2007 primarily due to the increase in operating income and a $93.9 million increase in derivatives income resulting from changes in the valuation of unrealized derivative positions, partially offset by the corresponding increase in income tax expense. Net income decreased in 2007 compared to 2006 primarily due to a $66.8 million increase in derivative losses and a $12.6 million increase in interest expense, partially offset by the increase in operating income and the corresponding decrease in income tax expense. The assets, liabilities and earnings of PVG are fully consolidated in our financial statements, with the public unitholders’ interest (23% as of December 31, 2008) reflected as a minority interest in our consolidated financial statements. The assets,
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Table of Contentsliabilities and earnings of PVR are fully consolidated in PVG’s financial statements, with the interest that PVG does not own (61%, after the effect of IDRs, as of December 31, 2008) reflected as a minority interest in PVG’s consolidated financial statements. Oil and Gas Segment Year Ended December 31, 2008 Compared With Year Ended December 31, 2007 The following table sets forth a summary of certain financial and other data for our oil and gas segment and the percentage change for the years ended December 31, 2008 and 2007:
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