We purchased our natural gas midstream business on March 3, 2005. The results of operations of the natural gas midstream segment since that date are included in the operations and financial summary table below.
The natural gas midstream segment 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. Revenues, profitability and the future rate of growth of the 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.
Average realized sales prices were $8.98 per thousand cubic feet (Mcf) in the three months ended September 30, 2005, and $8.05 per Mcf in the nine months ended September 30, 2005. Natural gas inlet volumes at our three gas processing plants were approximately 11.6 billion cubic feet (Bcf) and 27.0 Bcf during the three months and nine months ended September 30, 2005.
Operating Costs and Expenses. Operating costs and expenses primarily consisted of the cost of gas purchased and also included operating expenses, taxes other than income, general and administrative expenses and depreciation and amortization.
Cost of gas purchased for the three months and nine months ended September 30, 2005, consisted of amounts paid to third-party producers for gas purchased under percentage of proceeds and keep-whole contracts. The average purchase price for gas was $7.75 per Mcf in the three months ended September 30, 2005, and $6.89 per Mcf in the nine months ended September 30, 2005. The midstream processing margin, consisting of total revenues minus marketing revenues and the cost of gas purchased, was $14.2 million, or $1.23 per Mcf of inlet gas, in the three months ended September 30, 2005, and $31.3 million, or $1.16 per Mcf of inlet gas, in the nine months ended September 30, 2005.
Operating expenses are costs directly associated with the operations of the natural gas midstream segment and include direct labor and supervision, property insurance, repair and maintenance expenses, measurement and utilities. These costs are generally fixed across broad volume ranges. The fuel expense to operate pipelines and plants is more variable in nature and is sensitive to changes in volume and commodity prices; however, a large portion of the fuel cost is generally borne by our producers.
General and administrative expenses consisted of costs to manage the midstream assets as well as integration costs.
Depreciation and amortization expense for the three months and nine months ended September 30, 2005, included $1.2 million and $2.9 million in amortization of intangibles recognized in connection with the Cantera Acquisition and $2.7 million and $5.9 million of depreciation on property, plant and equipment.
Other
Interest expense for the three months and nine months ended September 30, 2005, increased compared to the same periods in 2004 primarily due to interest incurred on additional borrowings to finance the Cantera Acquisition and coal property acquisitions in 2005.
The noncash unrealized loss on derivatives of $11.2 million for the nine months ended September 30, 2005, included a $13.9 million noncash unrealized loss for mark-to-market adjustments on certain derivative agreements and a noncash net unrealized gain for changes in effectiveness of open commodity price hedges related to the natural gas midstream segment of $3.6 million for the three months ended September 30, 2005, and $2.7 million for the nine months ended September 30, 2005. The $13.9 million unrealized loss represented the change in the market value of derivative agreements between the time we entered into the agreements in January 2005 and the time they qualified for hedge accounting after closing the Cantera Acquisition in March 2005. When we agreed to acquire Cantera, we wanted to ensure an acceptable return on the investment. This objective was supported by entering into pre-closing commodity price derivative agreements covering approximately 75 percent of the net volume of NGLs expected to be sold from April 2005 through December 2006. Rising commodity prices resulted in a significant change in the market value of those derivative agreements before they qualified for hedge accounting. This change in market value resulted in a noncash charge to earnings for the unrealized loss on derivatives. Upon qualifying for hedge accounting, changes in the derivative agreements’ market value are accounted for as other comprehensive income or loss to the extent they are effective rather than a direct effect on net income. Cash settlements with the counterparties related to the derivative agreements will occur monthly in the future over the remaining life of the agreements, with PVR receiving a correspondingly higher or lower amount for the physical sale of the commodity over the same period.
Liquidity and Capital Resources
Since closing our initial public offering in October 2001, cash generated from operations and our borrowing capacity, supplemented by proceeds from the issuance of new common units, have been sufficient to meet our scheduled distributions, working capital requirements and capital expenditures. Our primary cash requirements consist of distributions to our general partner and unitholders, normal operating expenses, interest and principal payments on our long-term debt and acquisitions of new assets or businesses.
Cash Flows. Net cash provided by operating activities was $71.7 million in the first nine months of 2005 compared with $38.7 million in the first nine months of 2004. The increase was largely due to higher average gross royalties per ton and accretive cash flows from our newly acquired natural gas midstream segment.
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Net cash used in investing activities was $299.7 million in the first nine months of 2005 compared with $28.8 million in first nine months of 2004. Cash used in investing activities for the nine months ended September 30, 2005, primarily related to approximately $199 million paid for the Cantera Acquisition, net of cash received and including capitalized acquisition costs, and approximately $62 million paid for the Green River Acquisition. The balance of cash used in investing activities was primarily for the $9 million Coal River Acquisition, the $15 million Alloy Acquisition, the $4 million cash portion of the Wayland Acquisition price, the $4 million acquisition of railcars that we previously leased and pipeline additions to one of our gathering systems in the natural gas midstream segment. Net cash used in investing activities for the nine months ended September 30, 2004, primarily related to a $28.4 million equity investment in a coal handling joint venture as well as the completion of a new coal loading facility on our Coal River property in West Virginia and two smaller infrastructure projects.
Net cash provided by financing activities was $229.3 million in the first nine months of 2005 compared with $3.2 million used in financing activities in the first nine months of 2004. We had borrowings, net of repayments, of $140.2 million in the first nine months of 2005 to finance acquisitions, compared to $26.0 million of net borrowings in the first nine months of 2004 to finance an equity investment. We received proceeds of $126.5 million from our sale of common units in a public offering which was completed in March 2005 and a $2.8 million contribution from our general partner. Distributions to partners increased to $37.8 million for the first nine months of 2005 from $29.2 million in the same period of 2004, primarily due to an increase in units outstanding as a result of the March 2005 public unit offering and an increase in the distribution rate per unit.
In October 2005, we announced a $0.65 per unit quarterly distribution for the three months ended September 30, 2005, or $2.60 per unit on an annualized basis. The distribution will be paid on November 14, 2005, to unitholders of record on November 3, 2005.
Long-Term Debt. As of September 30, 2005, we had outstanding borrowings of $257.9 million, consisting of $175.0 million borrowed under our revolving credit facility and $82.9 million of senior unsecured notes (the “Notes”). The current portion of the Notes as of September 30, 2005, was $8.1 million.
Concurrent with the closing of the Cantera Acquisition in March 2005, Penn Virginia Operating Co., LLC, the parent of PVR Midstream LLC and a subsidiary of the Partnership, entered into a new unsecured $260 million, five-year credit agreement consisting of a $150 million revolving credit facility (the “revolver”) that matures in March 2010 and a $110 million term loan. A portion of the revolving credit facility and the term loan were used to fund the Cantera Acquisition and to repay borrowings under our previous credit facility. Proceeds of $126.5 million received from a subsequent public offering of 2.5 million common units in March 2005 and a $2.8 million contribution from our general partner were used to repay the $110 million term loan and a portion of the amount outstanding under the revolver. The term loan cannot be re-borrowed. The revolver is available for general Partnership purposes, including working capital, capital expenditures and acquisitions, and includes a $10 million sublimit for the issuance of letters of credit.
In conjunction with the closing of the Cantera Acquisition, Penn Virginia Operating Co., LLC, also amended its $88 million Notes to allow us to enter the natural gas midstream business and to increase certain covenant coverage ratios, including the debt to EBITDA test. In exchange for this amendment, we agreed to a 0.25 percent increase in the fixed interest rate on the Notes, from 5.77 percent to 6.02 percent. The amendment to the Notes also requires that we obtain an annual confirmation of our credit rating, with a 1.00 percent increase in the interest rate payable on the Notes in the event our credit rating falls below investment grade. On March 15, 2005, our investment grade credit rating was confirmed by Dominion Bond Rating Services.
In July 2005, we amended the credit agreement to increase the size of the revolver from $150 million to $300 million. We increased a one-time option under the revolver to expand the facility from $100 million to $150 million, for a potential total credit facility of $450 million, upon receipt by the credit facility’s administrative agent of commitments from one or more lenders. The amendment also updated certain debt covenant definitions. The interest rate under the credit agreement remained unchanged and will fluctuate based on our ratio of total indebtedness to EBITDA. Interest is payable at a base rate plus an applicable margin ranging from zero to 1.00 percent if we select the base rate borrowing option under the credit agreement or at a rate derived from the London Interbank Offering Rate (“LIBOR”) plus an applicable margin ranging from 1.00 percent to 2.00 percent if we select the LIBOR-based borrowing option. Other terms of the credit agreement remained unchanged.
In September 2005, we entered into the Revolver Swaps described below under “Interest Rate Swaps” to establish a fixed interest rate on $60 million of the LIBOR-based portion of the outstanding balance of the revolving credit facility, which effectively fixed the interest rate at 4.22 percent plus the applicable margin, which was 1.75 percent, as of September 30, 2005.
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Interest Rate Swaps. In March 2003, we entered into an interest rate swap agreement with an original notional amount of $30 million to hedge a portion of the fair value of the Notes (the “Senior Notes Swap”). The notional amount decreased by one-third of each principal payment. Under the terms of the Senior Notes Swap agreement, the counterparty paid a fixed rate of 5.77 percent on the notional amount and received a variable rate equal to the floating interest rate which was determined semi-annually and was based on the six month LIBOR plus 2.36 percent. Settlements on the Senior Notes Swap were recorded as interest expense. In conjunction with the closing of the Cantera Acquisition, we entered into an amendment to the Notes in which we agreed to a 0.25 percent increase in the fixed interest rate on the Notes, from 5.77 percent to 6.02 percent. The Senior Notes Swap was redesignated as a fair value hedge on that date and was determined to be highly effective.
The Senior Notes Swap agreement was settled on June 30, 2005, for $0.8 million. The settlement was paid in cash by us to the counterparty in July 2005. Upon settlement of the Senior Notes Swap agreement, the $0.8 million negative fair value adjustment of the carrying amount of long-term debt will be amortized as interest expense over the remaining term of the Notes using the interest rate method.
In September 2005, we entered into two interest rate swap agreements with notional amounts totaling $60 million to establish fixed rates on the LIBOR-based portion of the outstanding balance of the revolver until March 2010 (the “Revolver Swaps”). We pay a fixed rate of 4.22 percent, plus the applicable margin, on the notional amount, and the counterparties pay a variable rate equal to the three month LIBOR. Settlements on the Revolver Swaps are recorded as interest expense. The Revolver Swap agreements were designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value is recorded to current period earnings in interest expense. After considering the applicable margin of 1.75 percent currently in effect on the revolver, the total interest rate on the $60 million portion of revolver borrowings covered by the Revolver Swaps is 5.97 percent.
Future Capital Needs and Commitments. For the remainder of 2005, we anticipate making additional capital expenditures, excluding acquisitions, of approximately $6 million to $8 million, primarily for construction of a processing plant and high speed rail loading facility on the Wayland property acquired in July 2005 and for system expansion and enhancement projects in our midstream segment. Part of our strategy is to make acquisitions which increase cash available for distribution to our unitholders. Our ability to make these acquisitions in the future will depend in part on the availability of debt financing and on our ability to periodically use equity financing through the issuance of new common units.
We believe that we will continue to have adequate liquidity to fund future recurring operating and investing activities. Short-term cash requirements, such as operating expenses and quarterly distributions to our general partner and unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for asset acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under credit facilities and the issuance of additional equity and debt securities. Our ability to complete future debt and equity offerings will depend on various factors, including prevailing market conditions, interest rates and our financial condition and credit rating at the time.
Environmental
Surface Mining Valley Fills. Over the course of the last several years, opponents of surface mining have filed three lawsuits challenging the legality of permits authorizing the construction of valley fills for the disposal of coal mining overburden under federal and state laws applicable to surface mining activities. Although two of these challenges were successful in the United States District Court for the Southern District of West Virginia (the “District Court”), the United States Court of Appeals for the Fourth Circuit overturned both of those decisions in Bragg v. Robertson in 2001 and in Kentuckians For The Commonwealth v. Rivenburgh in 2003.
A ruling on July 8, 2004, which was made by the District Court in connection with a third lawsuit, may impair our lessees’ ability to obtain permits that are needed to conduct surface mining operations. In this case, Ohio Valley Environmental Coalition v. Bulen, the District Court determined that the Army Corps of Engineers (the “Corps”) violated the Federal Water Pollution Control Act of 1972, also known as the “Clean Water Act,” and other federal statutes when it issued Nationwide Permit 21. This ruling is currently on appeal, but no decision has been issued by the appeals court as of yet.
In January of 2005, Kentucky Riverkeepers, Inc. and several other groups filed suit in federal district court in Kentucky challenging the legality of Nationwide Permit 21 and seeking to enjoin the Corps from issuing any general permits thereunder for fills associated with coal mining in Kentucky. Should the district court hearing this case follow the reasoning of Ohio Valley Environmental Coalition v. Bulen and similarly enjoin the Corps from issuing general permits for coal mining under that general permit, companies seeking permits under Section 404 of the Clean Water Act in Kentucky may have to file for individual permits that may result in increases in coal mining costs. We do not expect that our lessees would be affected significantly by the outcome in this case.
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Mine Health and Safety Laws. The operations of our lessees are subject to stringent health and safety standards that have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs and reduced productivity. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposes comprehensive health and safety standards on all mining operations. In addition, as part of the Mine Health and Safety Acts of 1969 and 1977, the Black Lung Acts require payments of benefits by all businesses conducting current mining operations to coal miners with black lung or pneumoconiosis and to some beneficiaries of miners who have died from this disease.
Environmental Compliance. The operations of our lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of our coal property leases impose liability for all environmental and reclamation liabilities arising under those laws and regulations on the relevant lessees. The lessees are bonded and have agreed to indemnify us against any and all future environmental liabilities. We regularly visit our leased coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. Management believes that the operations of our coal lessees and our natural gas midstream segment will comply with existing regulations and does not expect any material impact on our financial condition or results of operations.
We have certain reclamation bonding requirements with respect to certain of our unleased and inactive coal properties. As of September 30, 2005 and 2004, our environmental liabilities for coal properties totaled $2.1 million and $1.5 million. Given the uncertainty of when the reclamation area will meet regulatory standards, a change in this estimate could occur in the future.
Clean Air Act. Our midstream operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations govern emissions of pollutants into the air resulting from our activities, such as the activities of our processing plants and compressor stations, and also impose procedural requirements on how we conduct our operations. Such laws and regulations may include requirements that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, strictly comply with the emissions and operational limitations of air emissions permits we are required to obtain, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that such requirements will not materially adversely affect our operations, and we do not expect the requirements to be any more burdensome to us than to any other similarly situated companies.
Resource Conservation and Recovery Act. Our midstream operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws. However, RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy. Unrecovered petroleum product wastes, however, may still be regulated under RCRA as solid waste. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas and NGLs in pipelines may also generate some hazardous wastes. Although we believe it is unlikely that the RCRA exemption will be repealed in the near future, repeal would increase costs for waste disposal and environmental remediation at our facilities.
CERCLA. Our midstream operations could incur liability under the Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA and also known as Super Fund, and comparable state laws, regardless of our fault, in connection with the disposal or other release of hazardous substances or wastes, including those arising out of historical operations conducted prior to the Cantera Acquisition by Cantera, Cantera’s predecessors or third parties on properties formerly owned by Cantera. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of “hazardous substance,” in the course of its ordinary operations Cantera has generated, and we will generate, wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the United States Environmental Protection Agency 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 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. If we were to incur liability under CERCLA, we could be subject to joint and several liability for the costs of cleaning up hazardous substances, for damages to natural resources and for the costs of certain health studies.
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We currently own or lease, and Cantera has in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas and NGLs. Although Cantera 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 the properties owned or leased by Cantera or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under Cantera’s control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination, whether from prior owners or operators or other historic activities or spills) or to perform remedial plugging or pit closure operations to prevent future contamination. We have ongoing remediations underway at several sites, but we do not believe that the associated costs will have a material impact on our operations.
Clean Water Act. Our operations can result in discharges of pollutants to waters. The Clean Water Act and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The unpermitted discharge of pollutants such as from spill or leak incidents is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of fill material and certain other activities in wetlands unless authorized by an appropriately issued permit. Any unpermitted release of pollutants, including NGLs or condensates, from our systems or facilities could result in fines or penalties as well as significant remedial obligations.
OSHA. We are subject to the requirements of the Occupational Safety and Health Act, referred to as 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.
Recent Accounting Pronouncements
See Note 14 in the Notes to Consolidated Financial Statements for a description of recent accounting pronouncements.
In August 2005, the Securities and Exchange Commission (“SEC”) issued a complex reform package that is effective December 1, 2005, and requires large registrants to disclose in annual reports material comments from the SEC staff unresolved for more than 180 days. The reform package divides all issuers into four categories and streamlines the shelf registration process. New rules require disclosure of risk factors in annual reports on Form 10-K. Previously disclosed risk factors would be updated quarterly for material changes and reported on Form 10-Q.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are interest rate risk and NGL, natural gas and coal price risks.
We are also indirectly exposed to the credit risk of our lessees. If our lessees become financially insolvent, our lessees may not be able to continue operating or meeting their minimum lease payment obligations. As a result, our coal royalty revenues could decrease due to lower production volumes.
As of September 30, 2005, $82.9 million of our outstanding indebtedness under the Notes carried a fixed interest rate throughout its term. We executed an interest rate derivative transaction in March 2003 to effectively convert the interest rate on one-third of the amount financed under the Notes from a fixed rate of 5.77 percent to a floating rate of LIBOR plus 2.36 percent. The interest rate swap was accounted for as a fair value hedge in compliance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137 and SFAS No. 138. The interest rate swap was settled on June 30, 2005, for $0.8 million. The settlement was paid in cash by us to the counterparty in July 2005.
As of September 30, 2005, $175.0 million of our outstanding indebtedness under the revolving credit facility carried a variable interest rate throughout its term. We executed interest rate derivative transactions in September 2005 to effectively convert the interest rate on $60 million of the amount financed under the revolving credit facility from a LIBOR-based floating rate to a fixed rate of 4.22 percent plus the applicable margin. The interest rate swaps are accounted for as cash flow hedges in compliance with SFAS No. 133.
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When we agreed to acquire Cantera, we wanted to ensure an acceptable return on the investment. This objective was supported by entering into pre-closing commodity price derivative agreements covering approximately 75 percent of the net volume of NGLs expected to be sold from April 2005 through December 2006. Rising commodity prices resulted in a significant change in the market value of those derivative agreements before they qualified for hedge accounting. This change in market value resulted in a $13.9 million noncash charge to earnings for the unrealized loss on these derivatives. Subsequent to the Cantera Acquisition, we formally designated the agreements as cash flow hedges in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Upon qualifying for hedge accounting, changes in the market value of the derivative agreements are accounted for as other comprehensive income or loss to the extent they are effective, rather than as a direct impact on net income. SFAS No. 133 requires us to continue to measure the effectiveness of the derivative agreements in relation to the underlying commodity being hedged, and we will be required to record the ineffective portion of the agreements in our net income for the respective period. During the third quarter of 2005, we reported a $3.6 million net unrealized gain on derivatives for the ineffective portion of the agreements as of September 30, 2005. Cash settlements with the counterparties related to the derivative agreements will occur monthly over the life of the agreements, with PVR receiving a correspondingly higher or lower amount for the physical sale of the commodity over the same period. In addition, we entered into derivative agreements for ethane, propane, crude oil and natural gas to further protect our margins subsequent to the Cantera Acquisition. These derivative agreements have been designated as cash flow hedges. See Note 6 of the Notes to Consolidated Financial Statements for a description of our hedging program and a listing of open derivative agreements and their fair value.
Forward-Looking Statements
Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions related thereto) are forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements which are also forward-looking statements. These statements use forward-looking words such as “may,” “will,” “anticipate,” “believe,” “expect,” “project” or other similar words. These statements discuss goals, intentions and expectations as to future trends, plans, events, results of operations or financial condition or state other “forward looking” information.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that assumed facts or bases almost always vary from actual results, and the differences between assumed facts or bases and actual results can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this report and the documents we have incorporated by reference. These statements reflect our current views with respect to future events and are subject to various risks, uncertainties and assumptions including, but not limited, to the following:
| • | our ability to generate sufficient cash from our midstream and coal businesses to pay the minimum quarterly distribution to our general partner and our unitholders; |
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| • | energy prices generally and specifically, the respective prices of natural gas, NGLs and coal; |
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| • | the relationship between natural gas and NGL prices; |
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| • | the relationship between the price of coal and the prices of natural gas and oil; |
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| • | the volatility of commodity prices for coal, natural gas and NGLs; |
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| • | the projected supply of and demand for coal, natural gas and NGLs; |
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| • | the ability to successfully integrate and manage our new midstream business; |
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| • | the ability to acquire new coal reserves on satisfactory terms; |
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| • | the price for which new coal reserves can be acquired; |
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| • | the ability to lease new and existing coal reserves; |
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| • | the ability to continually find and contract for new sources of natural gas supply; |
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| • | the ability to retain our existing or acquire new midstream customers; |
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| • | the ability of our coal lessees to produce sufficient quantities of coal on an economic basis from our reserves; |
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| • | the ability of our coal lessees to obtain favorable contracts for coal produced from our reserves; |
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| • | competition among producers in the coal industry generally and among midstream companies; |
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| • | exposure to the credit risk of our coal lessees and our midstream customers; |
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| • | the experience and financial condition of our coal lessees, including their ability to satisfy their royalty, environmental, reclamation and other obligations to us and others; |
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| • | the ability to expand our midstream business by constructing new gathering systems, pipelines and processing facilities on an economic basis and in a timely manner; |
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| • | the extent to which the amount and quality of actual coal production differs from estimated recoverable proved coal reserves; |
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| • | unanticipated geological problems; |
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| • | the dependence of our midstream business on having connections to third party pipelines; |
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| • | availability of required materials and equipment; |
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| • | the occurrence of unusual weather or operating conditions, including force majeure events; |
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| • | the failure of our coal infrastructure or our coal lessees’ mining equipment or processes to operate in accordance with specifications or expectations; |
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| • | delays in anticipated start-up dates of our coal lessees’ mining operations and related coal infrastructure projects; |
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| • | environmental risks affecting the mining of coal reserves and the production, gathering and processing of natural gas; |
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| • | the timing of receipt of necessary governmental permits by our coal lessees; |
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| • | the risks associated with having or not having price risk management programs; |
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| • | labor relations and costs; |
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| • | accidents; |
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| • | changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters; |
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| • | uncertainties relating to the outcome of litigation regarding permitting of the disposal of coal overburden; |
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| • | risks and uncertainties relating to general domestic and international economic (including inflation and interest rates) and political conditions (including the impact of potential terrorist attacks); |
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| • | coal handling joint venture operations; |
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| • | changes in financial market conditions; and |
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| • | other risk factors as detailed in the our Annual Report on Form 10-K for the year ended December 31, 2004. |
Many of such factors are beyond our ability to control or predict. Readers are cautioned not to put undue reliance on forward-looking statements.
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While we periodically reassess material trends and uncertainties affecting our results of operations and financial condition in connection with the preparation of Management’s Discussion and Analysis of Results of Operations and Financial Condition and certain other sections contained in our quarterly, annual and other reports filed with the Securities and Exchange Commission, we do not undertake any obligation to review or update any particular forward-looking statement, whether as a result of new information, future events or otherwise.
Item 4. Controls and Procedures
(a) Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information relating to the Partnership and its consolidated subsidiaries is made known to the officers who certify the Partnership’s financial reports. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. In addition, since the Partnership acquired its natural gas midstream business on March 3, 2005, our ability to effectively apply our disclosure controls and procedures to the acquired business is inherently limited by the short period of time we have had to evaluate those midstream operations since the acquisition.
The Partnership, under the supervision and with the participation of its management, including its principal executive officer and principal financial officer, performed an evaluation of the design and operation of the Partnership’s disclosure controls and procedures (as defined in Securities and Exchange Act Rule 13a-15(e)) as of the end of the period covered by this report. Based on that evaluation, the Partnership’s principal executive officer and principal financial officer concluded that such disclosure controls and procedures are effective to ensure that material information relating to the Partnership, including its consolidated subsidiaries, was accumulated and communicated to the Partnership’s management and made known to the principal executive officer and principal financial officer, during the period for which this periodic report was being prepared.
(b) Changes in Internal Control over Financial Reporting
No changes were made in the Partnership’s internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, except that we are in the process of evaluating the controls in the newly acquired natural gas midstream business and integrating the segment into our existing internal control structure.
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PART II. Other Information
Items 1, 2, 3, 4 and 5 are not applicable and have been omitted.
Item 6. Exhibits
12 | Statement of Computation of Ratio of Earnings to Fixed Charges Calculation. |
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31.1 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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31.2 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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32.1 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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32.2 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| PENN VIRGINIA RESOURCE PARTNERS, L.P. |
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Date: November 3, 2005 | By: | /s/ Frank A. Pici |
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| | Frank A. Pici, Vice President and |
| | Chief Financial Officer |
| | |
| | |
Date: November 3, 2005 | By: | /s/ Forrest W. McNair |
| |
|
| | Forrest W. McNair, Vice President and |
| | Controller |
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