Exhibit 99.1
Penn Virginia Resource Partners, L.P.
Three Radnor Corporate Center, Suite 300, 100 Matsonford Road, Radnor, PA 19087
FOR IMMEDIATE RELEASE
| | |
| Contact: | | James W. Dean, Vice President, Investor Relations |
| | Ph: (610) 687-8900 Fax: (610) 687-3688 E-Mail:invest@pennvirginia.com |
PENN VIRGINIA RESOURCE PARTNERS, L.P.
ANNOUNCES THIRD QUARTER 2008 RESULTS
RADNOR, PA (BusinessWire) November 5, 2008 –Penn Virginia Resource Partners, L.P. (NYSE: PVR) today reported financial and operational results for the three months ended September 30, 2008 and provided an update of full-year 2008 guidance.
Third Quarter 2008 Highlights
Third quarter 2008 highlights and results, with comparisons to third quarter 2007 results, included the following:
| | • | | Distributable cash flow (DCF), a non-GAAP (generally accepted accounting principles) measure, of $29.4 million, as compared to $31.9 million; |
| | • | | Operating income of $40.0 million, as compared to $31.8 million; |
| | • | | Adjusted net income, a non-GAAP measure, of $16.3 million, or $0.20 per limited partner unit, as compared to $24.0 million, or $0.44 per limited partner unit; |
| | • | | Quarterly record net income of $44.6 million, or $0.60 per limited partner unit, as compared to $16.7 million, or $0.29 per limited partner unit; |
| | • | | Coal production by lessees of 8.5 million tons, as compared to a quarterly record 8.8 million tons; |
| | • | | Quarterly record average coal royalties per ton of $3.92 ($3.67 net of coal royalties expense), as compared to $2.76 ($2.65 net of coal royalties expense); |
| | • | | Quarterly record coal and natural resource management segment revenues of $41.7 million ($39.5 million net of coal royalties expense), as compared to $28.4 million ($27.4 million net of coal royalties expense); |
| | • | | Quarterly record natural gas midstream system throughput volumes of 27.7 Bcf, or 302 million cubic feet (MMcf) per day, as compared to 17.8 Bcf, or 194 MMcf per day; and |
| | • | | Midstream gross margin of $30.0 million, or $1.08 per thousand cubic feet (Mcf), as compared to $24.2 million, or $1.35 per Mcf. |
Reconciliations of non-GAAP financial measures to GAAP-based measures appear in the financial tables later in this release.
DCF for the third quarter of 2008 of $29.4 million was eight percent lower than DCF in the third quarter of 2007 due to:
| | • | | a $9.4 million increase in cash paid to settle derivatives; |
| | • | | a $3.8 million “make-whole” payment related to the early repayment of senior unsecured notes; |
| | • | | a $2.4 million increase in interest expense; and |
| | • | | a $1.1 million increase in maintenance capital expenditures. |
These decreases to DCF were partially offset by:
| | • | | an $11.5 million increase in operating income, prior to depreciation, depletion and amortization (DD&A) expense, from the coal and natural resource management segment (PVR Coal & Natural Resource Management), primarily due to increased average coal royalties; and |
| | • | | a $3.0 million increase in operating income, prior to DD&A expense, from the natural gas midstream segment (PVR Midstream), primarily due to increased system throughput volumes as a result of plant expansions, acquisitions and increased production by local producers. |
Compared to record DCF of $40.2 million in the second quarter of 2008, DCF in the third quarter of 2008 decreased by $10.8 million, or 27 percent. This sequential decrease was primarily due to:
| | • | | a $4.4 million increase in cash paid to settle derivatives; |
| | • | | a $3.9 million decrease in PVR Midstream operating income, prior to DD&A expense, primarily due to the impacts of Hurricane Ike upon the processing gross margin; |
| | • | | the $3.8 million make-whole payment; and |
| | • | | a $1.7 million increase in interest expense. |
These decreases to DCF were partially offset by a $3.6 million increase in PVR Coal & Natural Resource Management operating income, prior to DD&A expense, primarily due to increased average coal royalties.
The $7.7 million, or 32 percent, decrease in adjusted net income as compared to the prior year quarter was primarily due to:
| | • | | the increase in cash paid to settle derivatives; |
| | • | | the make-whole payment; and |
| | • | | the increase in interest expense. |
The decrease was partially offset by an $8.3 million increase in operating income primarily due to an $8.6 million, or 48 percent, increase in operating income from PVR Coal & Natural Resource Management.
The $27.9 million, or 167 percent, increase in net income as compared to the prior year quarter was due to a $26.5 million increase in derivatives income resulting from changes in the valuation of unrealized derivative positions and the increase in operating income, partially offset by the make-whole payment and the increase in interest expense.
Cash Distribution
As previously announced, on November 14, 2008, PVR will pay to unitholders of record as of November 6, 2008 a quarterly cash distribution covering the period of July 1 through September 30, 2008 in the amount of $0.47 per unit, or an annualized rate of $1.88 per unit. On an annualized basis, this represents a $0.04 per unit, or two percent, increase over the annualized distribution of $1.84 per unit paid for the second quarter of 2008 and a nine percent increase over the annualized distribution of $1.72 per unit for the same quarter of 2007.
Management Comment
A. James Dearlove, Chief Executive Officer of PVR, said, “We are pleased to report our results for the third quarter of 2008, which were led by the continued solid performance from our PVR Coal & Natural Resource Management segment. Due to these results and continued confidence in our outlook, we recently increased our quarterly distribution for the seventh consecutive quarter to an annualized distribution of $1.88 per unit, or nine percent higher than the annualized amount in the same quarter a year ago.
“PVR Coal & Natural Resource Management had another strong quarter, with record operating income primarily as a result of a 10 percent sequential increase in average coal royalties per ton. We continue to benefit from higher coal prices, especially in the Illinois Basin and Northern Appalachia, where average coal royalties per ton increased by 27 percent and 17 percent, respectively, over the second quarter of 2008, as
well as Central Appalachia where the average coal royalties per ton increased 10 percent from $4.75 in the second quarter to $5.23 in the third quarter. The impact, primarily in Central Appalachia and to a lesser extent in the Illinois Basin, of lessee contract renewals at higher prices have improved our average coal royalties per ton and we expect continued strength for the balance of 2008 and into 2009. Accordingly, we have increased guidance for our full-year 2008 average coal royalties per ton while slightly decreasing lessee tonnage guidance.
“During the third quarter, PVR Midstream’s daily system throughput volumes increased 16 percent over the second quarter of 2008, primarily as a result of contributions from the new Spearman and Crossroads processing plants, as well as acquisitions in the Fort Worth Basin and the panhandle of Texas. However, gross margin for PVR Midstream was adversely impacted in the aftermath of Hurricane Ike which forced us to curtail natural gas liquids (NGL) production at two of our processing plants in the third quarter. Hurricane Ike caused no damage to our facilities and all operations were back to normal by mid-October. Despite these issues, we have re-affirmed our full-year 2008 system throughput volume guidance for PVR Midstream.
“As a partnership, we need to have access to capital to continue the growth of our business segments. We recognize that access to the debt and equity capital markets has become much more difficult recently, and we cannot predict when those markets will improve. As of the end of the third quarter, we had approximately $140 million of unused borrowing capacity under our $700 million revolving credit facility, which we believe provides adequate cushion to support our working capital needs and some modest growth opportunities. We are also confident that the fundamental characteristics of our business segments remain strong.”
Coal and Natural Resource Management Segment Review
During the third quarter of 2008, operating income for PVR Coal & Natural Resource Management increased by 48 percent to $26.3 million from $17.7 million in the prior year quarter. Revenues increased by 47 percent from the prior year quarter to $41.7 million primarily due to a 36 percent increase in coal royalties revenue, along with a 109 percent increase in coal services and other revenues. Coal royalties revenue increased primarily due to a 42 percent increase in average coal royalties per ton to a record $3.92 from $2.76 in the prior year quarter, partially offset by a 0.3 million ton, or four percent, decrease in coal production by PVR’s lessees to 8.5 million tons in the third quarter of 2008 from a record 8.8 million tons in the prior year quarter. Other revenues increased primarily due to acquisitions of forestlands and oil and gas royalties at the end of 2007. Net of coal royalties expense, average coal royalties per ton increased $1.02, or 38 percent, to $3.67 in the third quarter of 2008 as compared to $2.65 in the prior year quarter. The lessee production decrease occurred primarily in Northern Appalachia and the Illinois Basin, partially offset by an increase in Central Appalachia. Operating expenses increased by 44 percent to $15.4 million primarily due to increases in DD&A, general and administrative (G&A) and coal royalties expenses.
Compared to the second quarter of 2008, the $2.3 million, or 10 percent, increase in third quarter 2008 segment operating income for PVR Coal & Natural Resource Management was primarily due to a $1.7 million increase in coal royalties revenue resulting from a $0.34, or 10 percent, increase in average coal royalties per ton, partially offset by a 0.3 million ton, or four percent, decrease in lessee coal production. The sequential quarterly lessee production decrease was primarily due to a longwall move in the third quarter at a significant mine in Northern Appalachia and production shortfalls due to adverse geology at significant mines in Central and Northern Appalachia. Other revenues increased by $0.9 million while operating expenses increased by $0.3 million.
Natural Gas Midstream Segment Review
Operating income for PVR Midstream decreased by two percent to $13.7 million from $14.1 million in the prior year quarter. Midstream gross margin increased by 24 percent to $30.0 million, from $24.2 million in the prior year quarter primarily due to the record system throughput volumes. The gross margin increase was more than offset by higher operating and DD&A expenses, primarily due to acquisitions and increased volumes from new plants. Adjusted for the cash impact of derivatives, midstream gross margin was $17.5 million in the third quarter of 2008, down 16 percent from $20.8 million in the prior year quarter.
System throughput volumes at PVR’s gas processing plants and gathering systems increased 55 percent to a record 27.7 Bcf, or approximately 302 MMcf per day, in the third quarter of 2008 from 17.8 Bcf, or approximately 194 MMcf per day, in the prior year quarter. The volumes increased during the third quarter primarily as a result of contributions of two new gas processing plants, the 60 MMcf per day Spearman plant in the panhandle of Texas and the 80 MMcf per day Crossroads plant in East Texas, which were both fully operational by the end of the first and second quarters of 2008, respectively, as well as contributions from gas gathering and transportation assets acquired in the Fort Worth Basin in July 2008 and a pair of recent pipeline asset acquisitions in the panhandle of Texas. Expenses other than the cost of midstream gas increased by $7.1 million in the third quarter of 2008 as compared to the prior year quarter, primarily due to increased system throughput volumes and acquisitions.
Compared to the second quarter of 2008, the $6.6 million, or 33 percent, decrease in third quarter 2008 segment operating income for PVR Midstream was primarily due to a decrease in gross margin to $30.0 million from $32.0 million in the second quarter of 2008, as well as increases of $2.7 million in DD&A expense and a $1.3 million increase in other operating expense related to acquisitions. The decrease in gross margin was due to curtailments of NGL production during the quarter as a result of hurricane-related plant shutdowns by end users of NGLs along the Gulf Coast. The decrease in gross margin was partially offset by higher system throughput volumes resulting from the two new processing plants, as well as the acquisitions in the Fort Worth Basin and panhandle of Texas.
Capital Resources and Impact of Derivatives
As of September 30, 2008, PVR had outstanding borrowings of $558.1 million under its $700 million revolving credit facility. The $146.4 million increase in outstanding borrowings as compared to the $411.7 million as of December 31, 2007 was primarily due to acquisitions and capital expenditures during the first nine months of 2008, partially offset by the net proceeds from a public offering of common units in May 2008. In July 2008, $58.4 million of senior unsecured notes were repaid, resulting in a $3.8 million make-whole payment to noteholders.
Interest expense increased from $4.7 million in the third quarter of 2007 to $7.1 million in the third quarter of 2008 due to the higher weighted average level of outstanding borrowings during the third quarter of 2008 as compared to the prior year quarter.
For the third quarter of 2008, derivatives income was $15.7 million, as compared to expense of $10.7 million in the prior year quarter. Cash settlements of derivatives included in these amounts resulted in net cash payments of $14.1 million during the third quarter of 2008 as compared to $4.7 million of net cash payments in the prior year quarter. See the Natural Gas Midstream Segment Review in this release for a discussion of the impact of derivatives on PVR Midstream’s gross margin. See the Guidance Table included in this release for details of derivative positions as of September 30, 2008.
Guidance for 2008
See the Guidance Table included in this release for guidance estimates for full-year 2008. These estimates, including capital expenditure plans, are meant to provide guidance only and are subject to revision as PVR’s operating environment changes.
Conference Call
A joint conference call and webcast, during which management will discuss third quarter 2008 financial and operational results for PVR and Penn Virginia GP Holdings, L.P. (NYSE: PVG), is scheduled for Thursday, November 6, 2008 at 1:00 p.m. ET. Prepared remarks by A. James Dearlove, Chief Executive Officer, will be followed by a question and answer period. Investors and analysts may participate via phone by dialing 1-877-407-9205 five to ten minutes before the scheduled start of the conference call, or via webcast by logging on to PVR’s website atwww.pvresource.com at least 20 minutes prior to the scheduled start of the call to download and install any necessary audio software. A telephonic replay of the call will be available until November 20, 2008 at 11:59 p.m. ET by dialing 1-877-660-6853 and using the following replay pass codes: account #286, conference ID #300124. An on-demand replay of the conference call will be available at PVR’s website beginning shortly after the call.
******
Headquartered in Radnor, PA, Penn Virginia Resource Partners, L.P. (NYSE: PVR) is a publicly traded limited partnership formed by Penn Virginia Corporation (NYSE: PVA). PVR manages coal properties and related assets and operates a midstream natural gas gathering and processing business.
For more information about PVR, visit itswebsite at www.pvresource.com.
Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: the volatility of commodity prices for natural gas, NGLs, crude oil and coal; the relationship between natural gas, NGL and coal prices; the projected demand for and supply of natural gas, NGLs and coal; competition among producers in the coal industry generally and among natural gas midstream companies; the extent to which the amount and quality of actual production of our coal differs from estimated recoverable coal reserves; our ability to generate sufficient cash from our businesses to maintain and pay the quarterly distribution to our general partner and our unitholders; the experience and financial condition of our coal lessees and natural gas midstream customers, including our lessees’ ability to satisfy their royalty, environmental, reclamation and other obligations to us and others; operating risks, including unanticipated geological problems, incidental to our coal and natural resource management or natural gas midstream business; our ability to acquire new coal reserves or natural gas midstream assets and new sources of natural gas supply and connections to third-party pipelines on satisfactory terms; our ability to retain existing or acquire new natural gas midstream customers and coal lessees; the ability of our lessees to produce sufficient quantities of coal on an economic basis from our reserves and obtain favorable contracts for such production; the occurrence of unusual weather or operating conditions including force majeure events; delays in anticipated start-up dates of our lessees’ mining operations and related coal infrastructure projects and new processing plants in our natural gas midstream business; environmental risks affecting the mining of coal reserves or the production, gathering and processing of natural gas; the timing of receipt of necessary governmental permits by us or our lessees; hedging results; accidents; changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with respect to emissions levels applicable to coal-burning power generators; uncertainties relating to the outcome of current and future litigation regarding mine permitting; and risks and uncertainties relating to general domestic and international economic (including inflation, interest rates and financial and credit markets) and political conditions (including the impact of potential terrorist attacks).
Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission, including our Annual Report on Form 10-K for the year ended December 31, 2007. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as the result of new information, future events or otherwise.
PENN VIRGINIA RESOURCE PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS - unaudited
(in thousands, except per unit data)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
Revenues | | | | | | | | | | | | | | | | |
Natural gas midstream | | $ | 241,282 | | | $ | 100,370 | | | $ | 601,127 | | | $ | 310,095 | |
Coal royalties | | | 33,308 | | | | 24,426 | | | | 88,911 | | | | 73,455 | |
Coal services | | | 1,815 | | | | 1,955 | | | | 5,518 | | | | 5,648 | |
Other | | | 8,871 | | | | 3,453 | | | | 23,039 | | | | 9,350 | |
| | | | | | | | | | | | | | | | |
Total revenues | | | 285,276 | | | | 130,204 | | | | 718,595 | | | | 398,548 | |
| | | | | | | | | | | | | | | | |
Expenses | | | | | | | | | | | | | | | | |
Cost of midstream gas purchased | | | 211,262 | | | | 76,192 | | | | 513,778 | | | | 251,000 | |
Operating | | | 9,041 | | | | 5,224 | | | | 24,553 | | | | 16,235 | |
Taxes other than income | | | 969 | | | | 666 | | | | 3,017 | | | | 2,112 | |
General and administrative | | | 7,078 | | | | 5,706 | | | | 20,339 | | | | 17,108 | |
Depreciation, depletion and amortization | | | 16,903 | | | | 10,645 | | | | 41,322 | | | | 30,600 | |
| | | | | | | | | | | | | | | | |
Total expenses | | | 245,253 | | | | 98,433 | | | | 603,009 | | | | 317,055 | |
| | | | | | | | | | | | | | | | |
Operating income | | | 40,023 | | | | 31,771 | | | | 115,586 | | | | 81,493 | |
| | | | |
Other income (expense) | | | | | | | | | | | | | | | | |
Interest expense | | | (7,060 | ) | | | (4,678 | ) | | | (17,366 | ) | | | (11,842 | ) |
Other | | | (4,153 | ) | | | 299 | | | | (3,233 | ) | | | 931 | |
Derivatives | | | 15,742 | | | | (10,730 | ) | | | (6,424 | ) | | | (20,927 | ) |
| | | | | | | | | | | | | | | | |
Net income | | $ | 44,552 | | | $ | 16,662 | | | $ | 88,563 | | | $ | 49,655 | |
| | | | | | | | | | | | | | | | |
Allocation of net income: | | | | | | | | | | | | | | | | |
General partner’s interest in net income | | $ | 6,309 | | | $ | 3,385 | | | $ | 15,505 | | | $ | 8,819 | |
Limited partners’ interest in net income | | $ | 38,243 | | | $ | 13,277 | | | $ | 73,058 | | | $ | 40,836 | |
Net income per limited partner unit, basic and diluted | | $ | 0.60 | | | $ | 0.29 | | | $ | 1.45 | | | $ | 0.89 | |
Weighted average number of units outstanding, basic and diluted | | | 51,663 | | | | 46,106 | | | | 48,804 | | | | 46,103 | |
| | | | |
Other data: | | | | | | | | | | | | | | | | |
Distributions to limited partners (per unit) - (a) | | $ | 0.47 | | | $ | 0.43 | | | $ | 1.38 | | | $ | 1.26 | |
Distributions paid | | $ | 29,841 | | | $ | 22,873 | | | $ | 80,199 | | | $ | 65,853 | |
Distributable cash flow (non-GAAP) - (b) | | $ | 29,369 | | | $ | 31,902 | | | $ | 96,334 | | | $ | 88,279 | |
Coal and natural resource management segment: | | | | | | | | | | | | | | | | |
Coal royalty tons (in thousands) | | | 8,496 | | | | 8,842 | | | | 24,975 | | | | 25,186 | |
Average coal royalties ($ per ton) | | $ | 3.92 | | | $ | 2.76 | | | $ | 3.56 | | | $ | 2.92 | |
Average net coal royalties ($ per ton) - (c) | | $ | 3.67 | | | $ | 2.65 | | | $ | 3.24 | | | $ | 2.74 | |
Natural gas midstream segment: | | | | | | | | | | | | | | | | |
System throughput volumes (MMcf) | | | 27,744 | | | | 17,844 | | | | 68,915 | | | | 50,763 | |
Gross margin (in thousands) | | $ | 30,020 | | | $ | 24,178 | | | $ | 87,349 | | | $ | 59,095 | |
| | | | |
| (a) | | - | | These quarterly distributions are for the periods shown and are payable within 45 days after the end of each quarter to unitholders of record and to PVR’s general partner. |
| (b) | | - | | See subsequent page for the calculation and description of distributable cash flow. |
| (c) | | - | | The average net coal royalties per ton deducts coal royalties expense, which are incurred primarily in Central Appalachia. |
PENN VIRGINIA RESOURCE PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited
(in thousands)
| | | | | | |
| | | September 30,
2008 | | December 31,
2007 |
Assets | | | | | | |
Cash | | $ | 10,706 | | $ | 19,530 |
Receivables | | | 92,976 | | | 78,888 |
Derivative assets | | | 3,825 | | | 1,212 |
Other current assets | | | 4,792 | | | 4,104 |
| | | | | | |
Total current assets | | | 112,299 | | | 103,734 |
Property, plant and equipment, net | | | 884,737 | | | 731,282 |
Other long-term assets | | | 242,046 | | | 96,263 |
| | | | | | |
Total assets | | $ | 1,239,082 | | $ | 931,279 |
| | | | | | |
Liabilities and partners’ capital | | | | | | |
Accounts payable and accrued liabilities | | $ | 80,351 | | $ | 76,236 |
Current portion of long-term debt | | | — | | | 12,561 |
Deferred income | | | 3,231 | | | 2,958 |
Derivative liabilities | | | 16,988 | | | 41,733 |
| | | | | | |
Total current liabilities | | | 100,570 | | | 133,488 |
Derivative liabilities | | | 2,982 | | | 1,315 |
Other long-term liabilities | | | 30,938 | | | 26,047 |
Long-term debt | | | 558,100 | | | 399,153 |
Partners’ capital | | | 546,492 | | | 371,276 |
| | | | | | |
Total liabilities and partners’ capital | | $ | 1,239,082 | | $ | 931,279 |
| | | | | | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
Cash flows from operating activities | | | | | | | | | | | | | | | | |
Net income | | $ | 44,552 | | | $ | 16,662 | | | $ | 88,563 | | | $ | 49,655 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | | | | | |
Depreciation, depletion and amortization | | | 16,903 | | | | 10,645 | | | | 41,322 | | | | 30,600 | |
Derivative contracts: | | | | | | | | | | | | | | | | |
Total derivative losses (gains) | | | (14,239 | ) | | | 12,034 | | | | 10,552 | | | | 24,359 | |
Cash settlements of derivatives | | | (14,054 | ) | | | (4,702 | ) | | | (33,279 | ) | | | (8,963 | ) |
Noncash interest expense | | | 1,175 | | | | 164 | | | | 1,543 | | | | 494 | |
Equity earnings, net of distributions received | | | (1,409 | ) | | | (255 | ) | | | (1,415 | ) | | | (1,133 | ) |
Other | | | (986 | ) | | | — | | | | (1,607 | ) | | | (198 | ) |
Changes in operating assets and liabilities | | | (10,502 | ) | | | (5,528 | ) | | | (10,912 | ) | | | (8,478 | ) |
| | | | | | | | | | | | | | | | |
Net cash provided by operating activities | | | 21,440 | | | | 29,020 | | | | 94,767 | | | | 86,336 | |
| | | | | | | | | | | | | | | | |
Cash flows from investing activities | | | | | | | | | | | | | | | | |
Acquisitions | | | (156,791 | ) | | | (93,423 | ) | | | (253,031 | ) | | | (145,879 | ) |
Additions to property, plant and equipment | | | (16,062 | ) | | | (10,781 | ) | | | (54,902 | ) | | | (29,655 | ) |
Other | | | 982 | | | | — | | | | 1,657 | | | | 197 | |
| | | | | | | | | | | | | | | | |
Net cash used in investing activities | | | (171,871 | ) | | | (104,204 | ) | | | (306,276 | ) | | | (175,337 | ) |
| | | | | | | | | | | | | | | | |
Cash flows from financing activities | | | | | | | | | | | | | | | | |
Proceeds from issuance partners’ capital | | | — | | | | — | | | | 140,958 | | | | — | |
Distributions to partners | | | (29,841 | ) | | | (22,873 | ) | | | (80,199 | ) | | | (65,853 | ) |
Proceeds from borrowings, net | | | 176,600 | | | | 89,000 | | | | 146,000 | | | | 146,000 | |
Other | | | (3,454 | ) | | | — | | | | (4,074 | ) | | | 860 | |
| | | | | | | | | | | | | | | | |
Net cash provided by financing activities | | | 143,305 | | | | 66,127 | | | | 202,685 | | | | 81,007 | |
| | | | | | | | | | | | | | | | |
Net decrease in cash and cash equivalents | | | (7,126 | ) | | | (9,057 | ) | | | (8,824 | ) | | | (7,994 | ) |
Cash and cash equivalents - beginning of period | | | 17,832 | | | | 12,503 | | | | 19,530 | | | | 11,440 | |
| | | | | | | | | | | | | | | | |
Cash and cash equivalents - end of period | | $ | 10,706 | | | $ | 3,446 | | | $ | 10,706 | | | $ | 3,446 | |
| | | | | | | | | | | | | | | | |
PENN VIRGINIA RESOURCE PARTNERS, L.P.
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands, except per unit data)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
Reconciliation of GAAP “Net income” to Non-GAAP | | | | | | | | | | | | | | | | |
“Distributable cash flow” | | | | | | | | | | | | | | | | |
Net income | | $ | 44,552 | | | $ | 16,662 | | | $ | 88,563 | | | $ | 49,655 | |
Depreciation, depletion and amortization | | | 16,903 | | | | 10,645 | | | | 41,322 | | | | 30,600 | |
Commodity derivative contracts: | | | | | | | | | | | | | | | | |
Derivative losses included in operating income | | | 1,503 | | | | 1,304 | | | | 4,128 | | | | 3,432 | |
Derivative losses (gains) included in other income | | | (15,742 | ) | | | 10,730 | | | | 6,424 | | | | 20,927 | |
Cash settlements of derivatives | | | (14,054 | ) | | | (4,702 | ) | | | (33,279 | ) | | | (8,963 | ) |
Maintenance capital expenditures | | | (3,793 | ) | | | (2,737 | ) | | | (10,824 | ) | | | (7,372 | ) |
| | | | | | | | | | | | | | | | |
Distributable cash flow (a) | | $ | 29,369 | | | $ | 31,902 | | | $ | 96,334 | | | $ | 88,279 | |
| | | | | | | | | | | | | | | | |
Distribution to Partners: | | | | | | | | | | | | | | | | |
| | | | |
Limited partner units | | $ | 23,827 | | | $ | 19,364 | | | $ | 64,862 | | | $ | 56,710 | |
General partner interest | | | 486 | | | | 395 | | | | 1,323 | | | | 1,157 | |
Incentive distribution rights (b) | | | 5,528 | | | | 3,114 | | | | 14,014 | | | | 7,986 | |
| | | | | | | | | | | | | | | | |
Total cash distribution paid during period | | $ | 29,841 | | | $ | 22,873 | | | $ | 80,199 | | | $ | 65,853 | |
| | | | | | | | | | | | | | | | |
Total cash distribution paid per unit during period | | $ | 0.46 | | | $ | 0.42 | | | $ | 1.35 | | | $ | 1.23 | |
| | | | | | | | | | | | | | | | |
Reconciliation of GAAP “Net income” to Non-GAAP | | | | | | | | | | | | | | | | |
“Net income as adjusted” | | | | | | | | | | | | | | | | |
Net income as reported | | $ | 44,552 | | | $ | 16,662 | | | $ | 88,563 | | | $ | 49,655 | |
Adjustments for derivatives: | | | | | | | | | | | | | | | | |
Derivative losses included in operating income | | | 1,503 | | | | 1,304 | | | | 4,128 | | | | 3,432 | |
Derivative losses (gains) included in other income | | | (15,742 | ) | | | 10,730 | | | | 6,424 | | | | 20,927 | |
Cash payments to settle derivatives for the period | | | (14,054 | ) | | | (4,702 | ) | | | (33,279 | ) | | | (8,963 | ) |
| | | | | | | | | | | | | | | | |
Net income as adjusted (c) | | $ | 16,259 | | | $ | 23,994 | | | $ | 65,836 | | | $ | 65,051 | |
| | | | | | | | | | | | | | | | |
Allocation of net income, as adjusted: | | | | | | | | | | | | | | | | |
General partner’s interest in net income, as adjusted | | $ | 5,743 | | | $ | 3,532 | | | $ | 15,050 | | | $ | 9,127 | |
Limited partners’ interest in net income, as adjusted | | $ | 10,516 | | | $ | 20,462 | | | $ | 50,786 | | | $ | 55,924 | |
Net income as adjusted, per limited partner unit, basic and diluted | | $ | 0.20 | | | $ | 0.44 | | | $ | 1.04 | | | $ | 1.21 | |
| | | | | | | | | | | | | | | | |
Reconciliation of GAAP “Net income per limited partner unit” reflecting the impactof EITF 03-06 to Non-GAAP “Adjusted net income per limited partner unit” | | | | | | | | | | | | | | | | |
Net income per limited partner unit, basic and diluted | | $ | 0.60 | | | $ | 0.29 | | | $ | 1.45 | | | $ | 0.89 | |
Impact of theoretical distribution of earnings pursuant to EITF 03-06 | | | 0.14 | | | | — | | | | 0.05 | | | | — | |
| | | | | | | | | | | | | | | | |
Adjusted net income per limited partner unit, basic and diluted (d) | | $ | 0.74 | | | $ | 0.29 | | | $ | 1.50 | | | $ | 0.89 | |
| | | | | | | | | | | | | | | | |
| | | | |
| (a) | | - | | Distributable cash flow represents net income plus depreciation, depletion and amortization expenses, plus derivative losses (gains) included in operating income and other income, less cash paid for derivative settlements, less maintenance capital expenditures. Distributable cash flow is a significant liquidity metric which is an indicator of PVR’s ability to generate cash flows at a level that can sustain or support an increase in quarterly cash distributions paid to its partners. Distributable cash flow is also the quantitative standard used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of publicly traded partnerships. Distributable cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP. Distributable cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities, as an indicator of cash flows, as a measure of liquidity or as an alternative to net income. |
| (b) | | - | | In accordance with PVR’s partnership agreement, incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. |
| (c) | | - | | Net income as adjusted represents net income adjusted to exclude the effects of non-cash changes in the fair value of derivatives. Management believes this presentation is widely used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies in the natural gas midstream industry. Management uses this information for comparative purposes within the industry. Net income as adjusted is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income. |
| (d) | | - | | Net income per limited partner unit, as required by EITF 03-06, is theoretical and pro forma in nature and does not reflect economic probabilities of whether earnings for an accounting period would or could be distributed to unitholders. PVR’s Partnership Agreement does not provide for the distribution of net income. Instead, it provides for the distribution of available cash, which is a contractually defined term that generally means all cash on hand at the end of each quarter after establishment of sufficient cash reserves required to operate PVR in a prudent manner. Accordingly, the distributions PVR has paid historically and will pay in future periods are not impacted by net income per limited partner unit as required by EITF 03-06. |
In addition to net income per limited partner unit as calculated in accordance with EITF 03-06, management intends to continue to present “adjusted net income per limited partner unit,” as reflected in the table above, which is consistent with its presentation of net income per limited partner unit in prior periods. “Adjusted net income per limited partner unit,” as presented in the table above, is defined as net income after deducting the amount allocated to the general partner’s interests, including the managing general partners’ incentive distribution rights, divided by the weighted average number of outstanding limited partner units during the period. As part of this calculation, in accordance with the cash distribution requirements contained in PVR’s Partnership Agreement, PVR’s net income is first allocated to the general partner based on the amount of incentive distributions attributable to the period. The remainder is then allocated between the limited partners and the general partner based on their respective percentage ownership in PVR. Adjusted net income per limited partner unit is used as a supplemental financial measure by its management and by external users of its financial statements, such as investors, commercial banks, research analysts and others. PVR’s method of computing adjusted net income per limited partner unit may not be the same method used to compute similar measures reported by other publicly-traded partnerships and may be computed differently by PVR in different contexts.
PENN VIRGINIA RESOURCE PARTNERS, L.P.
QUARTERLY SEGMENT INFORMATION - unaudited
(in thousands)
| | | | | | | | | |
| | | Coal and Natural
Resource
Management | | Natural Gas
Midstream | | Consolidated |
Three Months Ended September 30, 2008 | | | | | | | | | |
| | | |
Revenues | | | | | | | | | |
Natural gas midstream | | $ | — | | $ | 241,282 | | $ | 241,282 |
Coal royalties | | | 33,308 | | | — | | | 33,308 |
Coal services | | | 1,815 | | | — | | | 1,815 |
Timber | | | 1,911 | | | — | | | 1,911 |
Oil and gas royalties | | | 1,940 | | | — | | | 1,940 |
Other | | | 2,686 | | | 2,334 | | | 5,020 |
| | | | | | | | | |
Total revenues | | | 41,660 | | | 243,616 | | | 285,276 |
| | | | | | | | | |
Expenses | | | | | | | | | |
Cost of midstream gas purchased | | | — | | | 211,262 | | | 211,262 |
Coal royalties expense | | | 2,125 | | | — | | | 2,125 |
Other operating | | | 752 | | | 6,164 | | | 6,916 |
Taxes other than income | | | 373 | | | 596 | | | 969 |
General and administrative | | | 3,321 | | | 3,757 | | | 7,078 |
Depreciation, depletion and amortization | | | 8,794 | | | 8,109 | | | 16,903 |
| | | | | | | | | |
Total expenses | | | 15,365 | | | 229,888 | | | 245,253 |
| | | | | | | | | |
Operating income | | $ | 26,295 | | $ | 13,728 | | $ | 40,023 |
| | | | | | | | | |
Additions to property and equipment and acquisitions | | $ | 497 | | $ | 172,356 | | $ | 172,853 |
| | | | | | | | | |
| | | Coal and Natural
Resource
Management | | Natural Gas
Midstream | | Consolidated |
Three Months Ended September 30, 2007 | | | | | | | | | |
| | | |
Revenues | | | | | | | | | |
Natural gas midstream | | $ | — | | $ | 100,370 | | $ | 100,370 |
Coal royalties | | | 24,426 | | | — | | | 24,426 |
Coal services | | | 1,955 | | | — | | | 1,955 |
Timber | | | 113 | | | — | | | 113 |
Oil and gas royalties | | | 264 | | | — | | | 264 |
Other | | | 1,658 | | | 1,418 | | | 3,076 |
| | | | | | | | | |
Total revenues | | | 28,416 | | | 101,788 | | | 130,204 |
| | | | | | | | | |
Expenses | | | | | | | | | |
Cost of midstream gas purchased | | | — | | | 76,192 | | | 76,192 |
Coal royalties expense | | | 979 | | | — | | | 979 |
Other operating | | | 1,020 | | | 3,225 | | | 4,245 |
Taxes other than income | | | 242 | | | 424 | | | 666 |
General and administrative | | | 2,630 | | | 3,076 | | | 5,706 |
Depreciation, depletion and amortization | | | 5,833 | | | 4,812 | | | 10,645 |
| | | | | | | | | |
Total expenses | | | 10,704 | | | 87,729 | | | 98,433 |
| | | | | | | | | |
Operating income | | $ | 17,712 | | $ | 14,059 | | $ | 31,771 |
| | | | | | | | | |
Additions to property and equipment and acquisitions | | $ | 93,449 | | $ | 10,755 | | $ | 104,204 |
PENN VIRGINIA RESOURCE PARTNERS, L.P.
YEAR-TO-DATE SEGMENT INFORMATION - unaudited
(in thousands)
| | | | | | | | | |
| | | Coal and Natural
Resource
Management | | Natural Gas
Midstream | | Consolidated |
Nine Months Ended September 30, 2008 | | | | | | | | | |
| | | |
Revenues | | | | | | | | | |
Natural gas midstream | | $ | — | | $ | 601,127 | | $ | 601,127 |
Coal royalties | | | 88,911 | | | — | | | 88,911 |
Coal services | | | 5,518 | | | — | | | 5,518 |
Timber | | | 5,328 | | | — | | | 5,328 |
Oil and gas royalties | | | 4,730 | | | — | | | 4,730 |
Other | | | 6,523 | | | 6,458 | | | 12,981 |
| | | | | | | | | |
Total revenues | | | 111,010 | | | 607,585 | | | 718,595 |
| | | | | | | | | |
Expenses | | | | | | | | | |
Cost of midstream gas purchased | | | — | | | 513,778 | | | 513,778 |
Coal royalties expense | | | 8,034 | | | — | | | 8,034 |
Other operating | | | 1,488 | | | 15,031 | | | 16,519 |
Taxes other than income | | | 1,115 | | | 1,902 | | | 3,017 |
General and administrative | | | 9,780 | | | 10,559 | | | 20,339 |
Depreciation, depletion and amortization | | | 22,733 | | | 18,589 | | | 41,322 |
| | | | | | | | | |
Total expenses | | | 43,150 | | | 559,859 | | | 603,009 |
| | | | | | | | | |
Operating income | | $ | 67,860 | | $ | 47,726 | | $ | 115,586 |
| | | | | | | | | |
Additions to property and equipment and acquisitions | | $ | 25,186 | | $ | 282,747 | | $ | 307,933 |
| | | | | | | | | |
| | | Coal and Natural
Resource
Management | | Natural Gas
Midstream | | Consolidated |
Nine Months Ended September 30, 2007 | | | | | | | | | |
| | | |
Revenues | | | | | | | | | |
Natural gas midstream | | $ | — | | $ | 310,095 | | $ | 310,095 |
Coal royalties | | | 73,455 | | | — | | | 73,455 |
Coal services | | | 5,648 | | | — | | | 5,648 |
Timber | | | 530 | | | — | | | 530 |
Oil and gas royalties | | | 847 | | | — | | | 847 |
Other | | | 4,830 | | | 3,143 | | | 7,973 |
| | | | | | | | | |
Total revenues | | | 85,310 | | | 313,238 | | | 398,548 |
| | | | | | | | | |
Expenses | | | | | | | | | |
Cost of midstream gas purchased | | | — | | | 251,000 | | | 251,000 |
Coal royalties expense | | | 4,582 | | | — | | | 4,582 |
Other operating | | | 2,086 | | | 9,567 | | | 11,653 |
Taxes other than income | | | 832 | | | 1,280 | | | 2,112 |
General and administrative | | | 7,989 | | | 9,119 | | | 17,108 |
Depreciation, depletion and amortization | | | 16,643 | | | 13,957 | | | 30,600 |
| | | | | | | | | |
Total expenses | | | 32,132 | | | 284,923 | | | 317,055 |
| | | | | | | | | |
Operating income | | $ | 53,178 | | $ | 28,315 | | $ | 81,493 |
| | | | | | | | | |
Additions to property and equipment and acquisitions | | $ | 146,915 | | $ | 28,619 | | $ | 175,534 |
PENN VIRGINIA RESOURCE PARTNERS, L.P.
GUIDANCE TABLE - unaudited
(dollars and tons in millions)
PVR is providing the following guidance regarding financial and operational expectations for full-year 2008.
| | | | | | | | | | | | | | | | | | | | | |
| | | Actual | | | | |
| | | First Quarter
2008 | | | Second Quarter
2008 | | | Third Quarter
2008 | | | YTD
2008 | | | Full-Year
2008 Guidance | |
Coal and Natural Resource Management Segment: | | | | | | | | | | | | | | | | | | | | | |
Coal royalty tons (millions) (a) | | | 7.7 | | | 8.8 | | | 8.5 | | | 25.0 | | | 33.0 | | | — | | 33.5 | |
| | | | | | | |
Revenues: | | | | | | | | | | | | | | | | | | | | | |
Average coal royalties per ton (b) | | $ | 3.14 | | | 3.58 | | | 3.92 | | | 3.56 | | | 3.55 | | | — | | 3.65 | |
Other (c) | | $ | 6.3 | | | 7.4 | | | 8.4 | | | 22.1 | | | 27.0 | | | — | | 28.0 | |
| | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | | |
Cash operating expenses (d) | | $ | 6.3 | | | 7.5 | | | 6.6 | | | 20.4 | | | 25.5 | | | — | | 26.5 | |
Depreciation, depletion and amortization (e) | | $ | 6.4 | | | 7.5 | | | 8.8 | | | 22.7 | | | 30.0 | | | — | | 31.0 | |
| | | | | | | |
Capital expenditures: | | | | | | | | | | | | | | | | | | | | | |
Expansion and acquisitions (f) | | $ | 0.1 | | | 24.6 | | | 0.5 | | | 25.2 | | | 27.0 | | | — | | 28.0 | |
Maintenance capital expenditures | | $ | — | | | — | | | — | | | — | | | 0.2 | | | — | | 0.3 | |
Total segment capital expenditures | | $ | 0.1 | | | 24.6 | | | 0.5 | | | 25.2 | | | 27.2 | | | — | | 28.3 | |
Natural Gas Midstream Segment: | | | | | | | | | | | | | | | | | | | | | |
System throughput volumes (MMcf per day) | | | 190 | | | 262 | | | 302 | | | 252 | | | 270 | | | — | | 280 | |
| | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | | |
Cash operating expenses (g) | | $ | 8.1 | | | 8.9 | | | 10.5 | | | 27.5 | | | 37.0 | | | — | | 39.0 | |
Depreciation, depletion and amortization (h) | | $ | 5.1 | | | 5.4 | | | 8.1 | | | 18.6 | | | 24.0 | | | — | | 25.5 | |
| | | | | | | |
Capital expenditures: | | | | | | | | | | | | | | | | | | | | | |
Expansion and acquisitions (i) | | $ | 16.4 | | | 86.3 | | | 196.6 | | | 299.3 | | | 325.0 | | | — | | 335.0 | |
Maintenance capital expenditures (j) | | $ | 3.1 | | | 3.9 | | | 3.8 | | | 10.8 | | | 14.0 | | | — | | 15.0 | |
Total segment capital expenditures | | $ | 19.5 | | | 90.2 | | | 200.4 | | | 310.1 | | | 339.0 | | | — | | 350.0 | |
Other: | | | | | | | | | | | | | | | | | | | | | |
Interest expense: | | | | | | | | | | | | | | | | | | | | | |
Average long-term debt outstanding | | $ | 412.5 | | | 411.8 | | | 510.1 | | | 454.3 | | | 485.0 | | | — | | 495.0 | |
Interest rate | | | 5.3 | % | | 4.4 | % | | 4.5 | % | | 4.6 | % | | 4.6 | % | | — | | 4.8 | % |
These estimates are meant to provide guidance only and are subject to revision as PVR’s operating environment changes.
Notes (changes from previous guidance):
| | | | |
(a) | | - | | Decreased tonnage guidance by 0.5 to 1.0 million tons to reflect a longwall movement at a mine in Northern Appalachia and adverse geology at significant mines in Central and Northern Appalachia. |
(b) | | - | | Increased by $0.20 to 0.25 per ton to reflect expected higher coal sales prices received by PVR lessees. |
(c) | | - | | Increased by $0.5 to $1.0 million to reflect higher expected coal services and other revenues. |
(d) | | - | | Increased by $0.5 to $1.0 million to reflect higher expected coal royalties expense. |
(e) | | - | | Reduced the upper end of guidance by $0.5 million to reflect lower expected depreciation, depletion and amortization expense. |
(f) | | - | | Increased by $1.5 million to include higher levels of capital expenditures during the first nine months of 2008. |
(g) | | - | | Increased by $1.0 to $2.0 million to reflect higher expected operating, general and administrative and taxes other than income expenses. |
(h) | | - | | Increased by $0.5 to 1.0 million to reflect higher expected depreciation, depletion and amortization expense. |
(i) | | - | | Increased by $10.0 million to include costs of additional organic growth projects. |
(j) | | - | | Increased by $2.0 to $3.0 million to reflect higher levels of maintenance capital expenditures during the first nine months, as well as the fourth quarter, of 2008. |
PENN VIRGINIA RESOURCE PARTNERS, L.P.
DERIVATIVE CONTRACT SUMMARY - unaudited
As of September 30, 2008
| | | | | | | | | | | | | | | | |
| | | Average
Volume Per
Day | | | Weighted Average
Price | | | Weighted Average Price - Collars |
| | | | Additional
Put Option | | Put | | Call |
Frac spread | | (in MMBtu | ) | | | (per MMBtu | ) | | | | | | | | | |
Fourth quarter 2008 | | 7,824 | | | $ | 5.02 | | | | | | | | | | |
| | | | | |
Ethane sale swaps | | (in gallons | ) | | | (per gallon | ) | | | | | | | | | |
Fourth quarter 2008 | | 34,440 | | | $ | 0.4700 | | | | | | | | | | |
| | | | | |
Propane sale swaps | | (in gallons | ) | | | (per gallon | ) | | | | | | | | | |
Fourth quarter 2008 | | 26,040 | | | $ | 0.7175 | | | | | | | | | | |
| | | | | |
Crude oil sale swaps | | (in barrels | ) | | | (per barrel | ) | | | | | | | | | |
Fourth quarter 2008 | | 560 | | | $ | 49.27 | | | | | | | | | | |
| | | | |
Natural gasoline collars | | (in gallons | ) | | | | | | | | | | (per gallon) |
Fourth quarter 2008 | | 6,300 | | | | | | | | | | $ | 1.4800 | | $ | 1.6465 |
| | | | |
Crude oil collars | | (in barrels | ) | | | | | | | | | | (per barrel) |
Fourth quarter 2008 | | 400 | | | | | | | | | | $ | 65.00 | | $ | 75.25 |
| | | | | |
Natural gas sale swaps | | (in MMBtu | ) | | | (per MMBtu | ) | | | | | | | | | |
Fourth quarter 2008 | | 4,000 | | | $ | 6.97 | | | | | | | | | | |
| | | | |
Crude oil three-way collars (a) | | (in barrels | ) | | | | | | | | | | (per barrel) |
First quarter 2009 through fourth quarter 2009 | | 1,000 | | | | | | | $ | 70.00 | | $ | 90.00 | | $ | 119.25 |
| | | | |
Frac spread collars | | (in MMBtu | ) | | | | | | | | | | (per MMBtu) |
First quarter 2009 through fourth quarter 2009 | | 6,000 | | | | | | | | | | $ | 9.09 | | $ | 13.94 |
Management estimates that, excluding the derivative positions described above, for every $1.00 per MMBtu decrease or increase in the natural gas price, natural gas midstream gross margin and operating income for the last three months of 2008 would increase or decrease by approximately $1.4 million. In addition, management estimates that for every $5.00 per barrel increase or decrease in the oil price, natural gas midstream gross margin and operating income would increase or decrease by approximately $1.8 million. This assumes that crude oil prices, natural gas prices and inlet volumes remain constant at forecasted levels. These estimated changes in gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.
| | | | |
| (a) | | - | | A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes the maximum price that PVR will receive for the contracted commodity volumes. The purchased put establishes the minimum price that PVR will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (i.e., NYMEX) plus the excess of the purchased put strike price over the sold put strike price. |
