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, Director, Investor Relations |
| | Ph: (610) 687-8900 Fax: (610) 687-3688 E-Mail:invest@pennvirginia.com |
PENN VIRGINIA RESOURCE PARTNERS, L.P.
ANNOUNCES FIRST QUARTER 2008 RESULTS AND
PROVIDES 2008 GUIDANCE UPDATE
RADNOR, PA (BusinessWire) May 7, 2008 –Penn Virginia Resource Partners, L.P. (NYSE: PVR) today reported financial and operational results for the three months ended March 31, 2008 and provided an update of full-year 2008 guidance.
First Quarter 2008 Highlights
First quarter 2008 highlights and results, with comparisons to first quarter 2007 results, included the following:
| | • | | Distributable cash flow (DCF), a non-GAAP (generally accepted accounting principles) measure, of $26.7 million, as compared to $26.0 million; |
| | • | | Operating income of $31.2 million, as compared to $22.3 million; |
| | • | | Adjusted net income, a non-GAAP measure, of $18.4 million, or $0.30 per limited partner unit, as compared to $17.9 million, or $0.33 per limited partner unit; |
| | • | | Record net income of $34.5 million, or $0.55 per limited partner unit, as compared to $16.4 million, or $0.30 per limited partner unit; |
| | • | | Natural gas midstream system throughput volumes of 17.3 Bcf, or 190 MMcf per day, as compared to 15.9 Bcf, or 177 MMcf per day; |
| | • | | Gross midstream processing margin of $25.4 million, or $1.47 per Mcf, as compared to $15.6 million, or $0.98 per Mcf; |
| | • | | Coal production by lessees of 7.6 million tons, as compared to 8.3 million tons; |
| | • | | Coal and natural resource management segment revenues of $30.3 million, as compared to $28.5 million; and |
| | • | | Updated 2008 guidance including increased system throughput volumes, reduced coal royalty tonnage, increased average coal royalties per ton and increased capital expenditures. |
A reconciliation of non-GAAP financial measures appears in the financial tables later in this release.
The DCF for the first quarter of 2008 of $26.7 million was three percent higher than the DCF recorded for the first quarter of 2007, due primarily to higher processing volumes and fractionation or “frac” spreads in the natural gas midstream segment (PVR Midstream). Compared to the fourth quarter of 2007, the DCF in the first quarter of 2008 was lower by $5.7 million. This decrease was primarily due to a $6.9 million decline in operating income at PVR Midstream and a $0.7 million increase in the cash paid to settle derivatives, which were partially offset by a $1.9 million increase in operating income in the coal and natural resource management segment (PVR Coal & NRM). Approximately one-half of the sequential quarterly decrease in PVR Midstream’s operating income was due to lower frac spreads, a small portion of the decrease resulted from a 3-day maintenance shut in related to a third-party liquids takeaway pipeline at the Beaver facility and the balance of the decrease resulted from a change in contract mix from “keep-whole” to “percent-of-proceeds” and various one-time expenses related to adding new volumes in the Texas Panhandle where equipment- and weather-related issues delayed the start up of PVR Midstream’s new Spearman plant.
The $0.5 million, or three percent, increase in adjusted net income as compared to the prior year quarter was primarily due to a $8.9 million, or 40 percent, increase in operating income, partially offset by a $7.5 million increase in cash paid to settle derivatives and $1.2 million increase in net interest expense. The increase in operating income as compared to the prior year quarter was due to a $9.2 million, or 207 percent, increase in operating income from PVR Midstream, partially offset by a $0.3 million, or two percent, decrease in operating income from PVR Coal & NRM.
The $18.1 million, or 110 percent, increase in net income as compared to the prior year quarter was due to the increase in operating income and a $10.4 million decrease in derivatives expense resulting from changes in the valuation of unrealized derivative positions, partially offset by the increase in net interest expense.
Cash Distribution
As previously announced, on May 15, 2008, PVR will pay to unitholders of record as of May 5, 2008 a quarterly cash distribution covering the period of January 1 through March 31, 2008 in the amount of $0.45 per unit, or an annualized rate of $1.80 per unit. This annualized distribution represents a $0.04 per unit, or 2.3 percent, increase over the annualized distribution of $1.76 per unit paid in the prior quarter and a 9.8 percent increase over the annualized distribution of $1.64 per unit for the same quarter of 2007.
Management Comment
A. James Dearlove, Chief Executive Officer of PVR, said, “PVR has increased quarterly distributions in the last six consecutive quarters, which reflects both our strong performance and continued confidence in our outlook. Our current annualized distribution of $1.80 per unit is approximately ten percent higher than at the same time a year ago.
“During the first quarter, PVR Midstream’s processing margins were negatively impacted primarily by frac spreads which, although still relatively high, decreased from the fourth quarter of 2007, a shift away from less predictable but higher value keep-whole volumes, and equipment and weather driven start-up delays of PVR Midstream’s new Spearman plant. Nevertheless, we have increased our full-year 2008 system throughput volume guidance for PVR Midstream due to increased processing capacity and expected strong growth in the supply of natural gas volumes in the vicinities of both the Spearman plant and a second newly-constructed processing facility in East Texas. The projected growth in volumes for each of the new plants has led us to begin plans for expansions of both plants, one or both of which may reach capacity by the end of 2008.”
“PVR Coal & NRM had a solid first quarter; however lessee production in Northern Appalachia, the Illinois Basin and the San Juan Basin was impacted by start-up delays, various lessee operational issues and market interruptions. These issues, which for the most part have been resolved, were partially offset by increased lessee production in Central Appalachia. As the production mix changes during the year, the royalty rate per ton will also change reflecting the regional pricing differentials.
We expect approximately half of our lessees’ contracts for market sensitive production, primarily in Central Appalachia and to a lesser extent in the Illinois Basin, to be “rolled over” later in 2008 and into higher priced contracts the effect of which will be felt in 2009 and beyond. The overall market for coal continues to be strong in the first half of 2008 as domestic and export demands remain high.”
Natural Gas Midstream Segment Review
Operating income for PVR Midstream increased 207 percent to $13.7 million from $4.4 million in the prior year quarter. The increase in operating income was primarily the result of higher frac spreads along with an increase in system throughput volumes during the first quarter of 2008 as compared to the prior year quarter. The gross midstream processing margin increased by 63 percent to $25.4 million, or $1.47 per Mcf, from $15.6 million, or $0.98 per Mcf, in the prior year quarter. Adjusted for the cash impact of derivatives, the gross midstream processing margin was $16.9 million, or $0.98 per Mcf, in the first quarter of 2008, up 18 percent from $14.4 million, or $0.90 per Mcf, in the prior year quarter. The year-over-year increase was due to higher frac spreads in the first quarter of 2008. In the fourth quarter of 2007, adjusted
for the cash impact of derivatives, the gross midstream processing margin was $23.1 million, or $1.36 per Mcf. The sequential decrease in gross midstream processing margin was due to lower frac spreads in the first quarter of 2008, a maintenance shut-in related to a third-party liquids takeaway pipeline at the Beaver facility, a shift in contract volume mix towards percent-of-proceeds arrangements, in which producers retain a portion of the frac spread economics, and away from keep-whole arrangements, in which PVR Midstream retains all of the frac spread economics, as well as various one-time expenses related to adding new volumes in the Texas Panhandle where equipment- and weather-related issues delayed the start up of PVR Midstream’s new Spearman plant.
System throughput volumes at PVR’s gas processing plants and gathering systems increased nine percent to 17.3 Bcf, or approximately 190 MMcf per day, in the first quarter of 2008 from 15.9 Bcf, or approximately 177 MMcf per day, in the prior year quarter. The volumes during the first quarter were less than anticipated due to equipment- and weather-related delays in the start up of the new gas processing plants, one in the panhandle of Texas, which was placed into service in the first quarter, and the other in East Texas, which will commence operations later in the second quarter of 2008 although PVR Midstream is receiving processing fees as of April 2008. Expenses other than the cost of midstream gas purchased increased by $1.6 million during the first quarter of 2008 to $13.2 million, primarily due to increased system throughput volumes.
Coal and Natural Resource Management Segment Review
During the first quarter of 2008, operating income for PVR Coal & NRM decreased by two percent to $17.6 million from $17.9 million in the prior year quarter. Revenues increased by six percent to $30.3 million from the prior year quarter primarily due to an 82 percent increase in coal services and other revenues, partially offset by a four percent decrease in coal royalties revenue. Other revenues increased due primarily to acquisitions of forestlands and oil and gas royalties in the second half of 2007. Coal royalties revenue decreased primarily due to a 0.6 million ton, or eight percent, decrease in coal production by PVR’s lessees to 7.6 million tons in the first quarter of 2008, partially offset by a four percent increase in average coal royalties per ton to $3.14 from $3.02 in the prior year quarter. Net of coal royalties expense, average coal royalties per ton remained essentially flat at $2.81 in the first quarter of 2008 as compared to $2.80 in the prior year quarter. The production decrease was primarily attributable to a 0.7 million decrease in Northern Appalachia, which also contributed to the increase in the average coal royalties per ton since Northern Appalachia is a low royalty rate area. Operating expenses increased by 20 percent to $12.7 million due primarily to increases in DD&A, coal royalties and G&A expenses.
Capital Resources and Impact of Derivatives
As of March 31, 2008, PVR’s outstanding borrowings were $413.7 million, including $13.3 million of senior unsecured notes classified as current portion of long-term debt, a slight increase from $411.7 million as of December 31, 2007. Interest expense increased from $3.5 million in the first quarter of 2007 to $4.9 million in the first quarter of 2008 due to the higher weighted average level of outstanding borrowings during the first quarter of 2008 as compared to the prior year quarter.
For the fourth quarter of 2007, derivatives income was $7.8 million, as compared to expense of $2.6 million in the prior year quarter. Cash settlements of derivatives included in these amounts resulted in net cash payments of $9.5 million during the first quarter of 2008, a $7.5 million increase from $2.1 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 processing margin.
See the Guidance Table included in this release for detail of derivative positions as of March 31, 2008.
Guidance for 2008
See the Guidance Table included in this release for updated 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 first quarter 2008 financial and operational results for PVR and Penn Virginia GP Holdings, L.P. (NYSE: PVG), is scheduled for Thursday, May 8, 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 May 22, 2008 at 11:59 p.m. ET by dialing 1-877-660-6853 and using the following replay pass codes: account #286, conference ID #281756. 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 and natural resource properties and related assets and operates a midstream natural gas gathering and processing business. For more information, please visit PVR’s website atwww.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, coal and NGL 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; risks and uncertainties relating to general domestic and international economic (including inflation, interest rates and financial market) 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
(dollars in thousands, except per unit data)
| | | | | | | | |
| | | Three Months Ended
March 31, | |
| | | 2008 | | | 2007 | |
Revenues | | | | | | | | |
Natural gas midstream | | $ | 125,048 | | | $ | 95,318 | |
Coal royalties | | | 23,962 | | | | 25,000 | |
Coal services | | | 1,862 | | | | 1,601 | |
Other | | | 5,942 | | | | 2,281 | |
| | | | | | | | |
Total revenues | | | 156,814 | | | | 124,200 | |
| | | | | | | | |
Expenses | | | | | | | | |
Cost of midstream gas purchased | | | 99,697 | | | | 79,731 | |
Operating | | | 6,793 | | | | 5,514 | |
Taxes other than income | | | 1,072 | | | | 843 | |
General and administrative | | | 6,518 | | | | 5,639 | |
Depreciation, depletion and amortization | | | 11,500 | | | | 10,133 | |
| | | | | | | | |
Total expenses | | | 125,580 | | | | 101,860 | |
| | | | | | | | |
Operating income | | | 31,234 | | | | 22,340 | |
| | |
Other income (expense) | | | | | | | | |
Interest expense | | | (4,932 | ) | | | (3,547 | ) |
Interest income and other | | | 462 | | | | 287 | |
Derivatives | | | 7,776 | | | | (2,647 | ) |
| | | | | | | | |
Net income | | $ | 34,540 | | | $ | 16,433 | |
| | | | | | | | |
Allocation of net income: | | | | | | | | |
General partner’s interest in net income | | $ | 4,627 | | | $ | 2,494 | |
Limited partners’ interest in net income | | $ | 29,913 | | | $ | 13,939 | |
| | |
Basic and diluted net income per limited partner unit | | $ | 0.55 | | | $ | 0.30 | |
| | |
Weighted average units outstanding, basic and diluted (in thousands) | | | 46,106 | | | | 46,106 | |
| | |
Other data: | | | | | | | | |
| | |
Distributions to limited partners (per unit) - (a) | | $ | 0.45 | | | $ | 0.41 | |
Distributions paid | | $ | 24,718 | | | $ | 21,029 | |
Distributable cash flow (non-GAAP) - (b) | | $ | 26,744 | | | $ | 26,038 | |
| | |
Coal and natural resource management segment: | | | | | | | | |
Coal royalty tons (in thousands) | | | 7,640 | | | | 8,284 | |
Average coal royalties ($ per ton) | | $ | 3.14 | | | $ | 3.02 | |
Average net coal royalties ($ per ton) - (c) | | $ | 2.81 | | | $ | 2.80 | |
Natural gas midstream segment: | | | | | | | | |
System throughput volumes (MMcf) | | | 17,287 | | | | 15,900 | |
Gross processing margin (in thousands) | | $ | 25,351 | | | $ | 15,587 | |
| (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 our general partner. |
| (b) - | See previous 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
(in thousands)
| | | | | | |
| | | March 31,
2008 | | December 31,
2007 |
| | | (unaudited) | | |
Assets | | | | | | |
Cash | | $ | 8,329 | | $ | 19,530 |
Receivables | | | 93,665 | | | 78,888 |
Derivative assets | | | 3,779 | | | 1,212 |
Other current assets | | | 4,176 | | | 4,104 |
| | | | | | |
Total current assets | | | 109,949 | | | 103,734 |
Property, plant and equipment, net | | | 740,652 | | | 731,282 |
Derivative assets | | | 419 | | | — |
Other long-term assets | | | 95,232 | | | 96,263 |
| | | | | | |
Total assets | | $ | 946,252 | | $ | 931,279 |
| | | | | | |
Liabilities and Partners’ Capital | | | | | | |
Accounts payable and accrued liabilities | | $ | 92,508 | | $ | 76,236 |
Current portion of long-term debt | | | 13,269 | | | 12,561 |
Deferred income | | | 2,383 | | | 2,958 |
Derivative liabilities | | | 29,338 | | | 41,733 |
| | | | | | |
Total current liabilities | | | 137,498 | | | 133,488 |
Derivative liabilities | | | 4,808 | | | 1,315 |
Other long-term liabilities | | | 26,670 | | | 26,047 |
Long-term debt | | | 400,479 | | | 399,153 |
Partners’ capital | | | 376,797 | | | 371,276 |
| | | | | | |
Total liabilities and partners’ capital | | $ | 946,252 | | $ | 931,279 |
| | | | | | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
| | | | | | | | |
| | | Three Months Ended
March 31, | |
| | | 2008 | | | 2007 | |
Operating Activities | | | | | | | | |
Net income | | $ | 34,540 | | | $ | 16,433 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | |
Depreciation, depletion and amortization | | | 11,500 | | | | 10,133 | |
Commodity derivative contracts: | | | | | | | | |
Total derivative losses | | | (6,668 | ) | | | 3,490 | |
Cash payments to settle derivatives for the period | | | (9,522 | ) | | | (2,072 | ) |
Noncash interest expense | | | 164 | | | | 165 | |
Equity earnings, net of distributions received | | | (360 | ) | | | (233 | ) |
Other | | | (309 | ) | | | — | |
Changes in operating assets and liabilities | | | (499 | ) | | | (4,398 | ) |
| | | | | | | | |
Net cash provided by operating activities | | | 28,846 | | | | 23,518 | |
| | | | | | | | |
Investing Activities | | | | | | | | |
Acquisitions, net of cash acquired | | | (20 | ) | | | (339 | ) |
Additions to property, plant and equipment | | | (17,650 | ) | | | (7,002 | ) |
Other | | | 341 | | | | 43 | |
| | | | | | | | |
Net cash used in investing activities | | | (17,329 | ) | | | (7,298 | ) |
| | | | | | | | |
Financing Activities | | | | | | | | |
Distributions to partners | | | (24,718 | ) | | | (21,029 | ) |
Proceeds from borrowings, net | | | 2,000 | | | | 5,000 | |
Proceeds from issuance of units | | | — | | | | 860 | |
| | | | | | | | |
Net cash used in financing activities | | | (22,718 | ) | | | (15,169 | ) |
| | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | (11,201 | ) | | | 1,051 | |
Cash and cash equivalents - beginning of period | | | 19,530 | | | | 11,440 | |
| | | | | | | | |
Cash and cash equivalents - end of period | | $ | 8,329 | | | $ | 12,491 | |
| | | | | | | | |
PENN VIRGINIA RESOURCE PARTNERS, L.P.
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands, except per unit data)
| | | | | | | | |
| | | Three Months Ended
March 31, | |
| | | 2008 | | | 2007 | |
Reconciliation of GAAP “Net income” to Non-GAAP | | | | | | | | |
“Distributable cash flow” | | | | | | | | |
Net income | | $ | 34,540 | | | $ | 16,433 | |
Depreciation, depletion and amortization | | | 11,500 | | | | 10,133 | |
Commodity derivative contracts: | | | | | | | | |
Derivative losses included in operating income | | | 1,108 | | | | 843 | |
Derivative losses (gains) included in other income | | | (7,776 | ) | | | 2,647 | |
Cash payments to settle derivatives for the period | | | (9,522 | ) | | | (2,072 | ) |
Maintenance capital expenditures | | | (3,106 | ) | | | (1,946 | ) |
| | | | | | | | |
Distributable cash flow (Note 1) | | $ | 26,744 | | | $ | 26,038 | |
| | | | | | | | |
Distribution to Partners: | | | | | | | | |
Limited partner units | | $ | 20,287 | | | $ | 18,443 | |
General partner interest | | | 414 | | | | 376 | |
Incentive distribution rights (Note 2) | | | 4,017 | | | | 2,210 | |
| | | | | | | | |
Total cash distribution paid during period | | $ | 24,718 | | | $ | 21,029 | |
| | | | | | | | |
Total cash distribution paid per unit during period | | $ | 0.44 | | | $ | 0.40 | |
| | | | | | | | |
Reconciliation of GAAP “Net income” to Non-GAAP | | | | | | | | |
“Net income as adjusted” | | | | | | | | |
Net income as reported | | $ | 34,540 | | | $ | 16,433 | |
Adjustments for derivatives: | | | | | | | | |
Derivative losses included in operating income | | | 1,108 | | | | 843 | |
Derivative losses (gains) included in other income | | | (7,776 | ) | | | 2,647 | |
Cash payments to settle derivatives for the period | | | (9,522 | ) | | | (2,072 | ) |
| | | | | | | | |
Net income, as adjusted (Note 3) | | $ | 18,350 | | | $ | 17,851 | |
| | | | | | | | |
Allocation of net income, as adjusted: | | | | | | | | |
General partner’s interest in net income, as adjusted | | $ | 4,304 | | | $ | 2,523 | |
Limited partners’ interest in net income, as adjusted | | $ | 14,046 | | | $ | 15,328 | |
Net income, as adjusted, per limited partner unit, basic and diluted (Note 3) | | $ | 0.30 | | | $ | 0.33 | |
| | | | | | | | |
Reconciliation of GAAP “Net income per limited partner unit” reflecting the impact of EITF 03-06 to Non-GAAP “Adjusted net income per limited partner unit” | | | | | | | | |
Net income per limited partner unit, basic and diluted | | $ | 0.55 | | | $ | 0.30 | |
Impact of theoretical distribution of earnings pursuant to EITF 03-06 | | | 0.10 | | | | — | |
| | | | | | | | |
Adjusted net income per limited partner unit, basic and diluted (Note 4) | | $ | 0.65 | | | $ | 0.30 | |
| | | | | | | | |
Note 1 - Distributable cash flow represents net income plus depreciation, depletion and amortization expense, plus derivative losses (gains) included in operating income and other income, plus cash paid for derivative settlements, and minus maintenance capital expenditures. Maintenance capital expenditures are capital expenditures (as defined by GAAP) which are not expansion capital expenditures. 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 a significant liquidity metric which is an indicator of our ability to generate cash flows at a level that can sustain or support an increase in quarterly cash distributions paid to our partners. Distributable cash flow is also the quantitative standard used throughout the investment community with respect to publicly-traded partnerships. Distributable cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flow from operating, investing or financing activities, as an indicator of cash flows, as a measure of liquidity or as an alternative to net income.
Note 2 - In accordance with our 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.
Note 3 - Net income as adjusted represents net income excluding any gains or losses on derivatives and reflects cash settlements received (paid). Net income as adjusted per limited partner unit represents the limited partners’ interest in net income as adjusted after the general partner’s interest has been allocated. We believe “net income as adjusted” provides a useful measure which excludes the impact of mark-to-market accounting.
Note 4 - 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. The 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 the Partnership in a prudent manner. Accordingly, the distributions we have 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, we intend to continue to present “adjusted net income per limited partner unit,” as reflected in the table above, which is consistent with our 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 the Partnership Agreement, Partnership 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 the Partnership. Adjusted net income per limited partner unit is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others.
Our method of computing adjusted net income per limited partner unit may not be the same method used to compute similar measures reported by other companies and may be computed differently by us 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 March 31, 2008 | | | | | | | | | |
| | | |
Revenues | | | | | | | | | |
Natural gas midstream | | $ | — | | $ | 125,048 | | $ | 125,048 |
Coal royalties | | | 23,962 | | | — | | | 23,962 |
Coal services | | | 1,862 | | | — | | | 1,862 |
Timber | | | 1,584 | | | — | | | 1,584 |
Oil and gas royalties | | | 1,234 | | | — | | | 1,234 |
Other | | | 1,652 | | | 1,472 | | | 3,124 |
| | | | | | | | | |
Total revenues | | | 30,294 | | | 126,520 | | | 156,814 |
| | | | | | | | | |
Expenses | | | | | | | | | |
Cost of midstream gas purchased | | | — | | | 99,697 | | | 99,697 |
Coal royalties expense | | | 2,512 | | | — | | | 2,512 |
Other operating | | | 231 | | | 4,050 | | | 4,281 |
Taxes other than income | | | 371 | | | 701 | | | 1,072 |
General and administrative | | | 3,185 | | | 3,333 | | | 6,518 |
Depreciation, depletion and amortization | | | 6,413 | | | 5,087 | | | 11,500 |
| | | | | | | | | |
Total expenses | | | 12,712 | | | 112,868 | | | 125,580 |
| | | | | | | | | |
Operating income | | $ | 17,582 | | $ | 13,652 | | $ | 31,234 |
| | | | | | | | | |
Additions to property and equipment and acquisitions | | $ | 48 | | $ | 17,622 | | $ | 17,670 |
| | | |
| | | Coal and Natural
Resource
Management | | Natural Gas
Midstream | | Consolidated |
Three Months Ended March 31, 2007 | | | | | | | | | |
| | | |
Revenues | | | | | | | | | |
Natural gas midstream | | $ | — | | $ | 95,318 | | $ | 95,318 |
Coal royalties | | | 25,000 | | | — | | | 25,000 |
Coal services | | | 1,601 | | | — | | | 1,601 |
Timber | | | 179 | | | — | | | 179 |
Oil and gas royalties | | | 277 | | | — | | | 277 |
Other | | | 1,427 | | | 398 | | | 1,825 |
| | | | | | | | | |
Total revenues | | | 28,484 | | | 95,716 | | | 124,200 |
| | | | | | | | | |
Expenses | | | | | | | | | |
Cost of midstream gas purchased | | | — | | | 79,731 | | | 79,731 |
Coal royalties expense | | | 1,783 | | | — | | | 1,783 |
Other operating | | | 372 | | | 3,359 | | | 3,731 |
Taxes other than income | | | 323 | | | 520 | | | 843 |
General and administrative | | | 2,616 | | | 3,023 | | | 5,639 |
Depreciation, depletion and amortization | | | 5,490 | | | 4,643 | | | 10,133 |
| | | | | | | | | |
Total expenses | | | 10,584 | | | 91,276 | | | 101,860 |
| | | | | | | | | |
Operating income | | $ | 17,900 | | $ | 4,440 | | $ | 22,340 |
| | | | | | | | | |
Additions to property and equipment and acquisitions | | $ | 1,336 | | $ | 6,005 | | $ | 7,341 |
PENN VIRGINIA RESOURCE PARTNERS, L.P.
GUIDANCE TABLE - unaudited
(dollars and tons in millions)
Penn Virginia Resource Partners, L.P. is providing the following guidance regarding financial and operational expectations for full-year 2008.
| | | | | | | | | | | | |
| | | Actual | | | | | | | | | |
| | | First Quarter
2008 | | | Full-Year
2008 Guidance | |
Coal and Natural Resource Management Segment: | | | | | | | | | | | | |
Coal royalty tons (millions) (Note 1) | | | 7.6 | | | 33.0 | | | - | | 34.5 | |
| | | | |
Revenues: | | | | | | | | | | | | |
Average coal royalties per ton (Note 2) | | $ | 3.14 | | | 2.90 | | | - | | 3.10 | |
Other | | $ | 6.3 | | | 25.00 | | | - | | 27.0 | |
| | | | |
Expenses: | | | | | | | | | | | | |
Cash operating expenses | | $ | 6.3 | | | 21.0 | | | - | | 23.0 | |
Depreciation, depletion and amortization (Note 3) | | $ | 6.4 | | | 30.0 | | | - | | 32.0 | |
| | | | |
Capital expenditures: | | | | | | | | | | | | |
Expansion and acquisitions | | $ | 0.1 | | | 1.5 | | | - | | 3.0 | |
Maintenance capital expenditures | | $ | — | | | 0.2 | | | - | | 0.4 | |
Total segment capital expenditures | | $ | 0.1 | | | 1.7 | | | - | | 3.4 | |
| | | | |
Natural Gas Midstream Segment: | | | | | | | | | | | | |
System Throughput volumes (MMcf per day) (Note 4) | | | 190 | | | 250 | | | - | | 275 | |
| | | | |
Expenses: | | | | | | | | | | | | |
Cash operating expenses | | $ | 8.1 | | | 34.0 | | | - | | 36.0 | |
Depreciation, depletion and amortization | | $ | 5.1 | | | 22.0 | | | - | | 24.0 | |
| | | | |
Capital expenditures: | | | | | | | | | | | | |
Expansion and acquisitions (Note 5) | | $ | 16.4 | | | 80.0 | | | - | | 90.0 | |
Maintenance capital expenditures | | $ | 3.1 | | | 12.0 | | | - | | 14.0 | |
Total segment capital expenditures | | $ | 19.5 | | | 92.0 | | | - | | 104.0 | |
| | | | |
Other: | | | | | | | | | | | | |
Interest expense: | | | | | | | | | | | | |
Average long-term debt outstanding | | $ | 412.5 | | | 450.0 | | | - | | 470.0 | |
Interest rate | | | 5.3 | % | | 5.5 | % | | - | | 6.0 | % |
These estimates are meant to provide guidance only and are subject to revision as PVR’s operating environment changes.
Notes (changes from previous guidance):
| 1. | Reduced tonnage guidance by 0.5-1.0 million tons for lower anticipated production on PVR properties in northern Appalachia and the Illinois Basin, offset in part by higher production in central Appalachia. |
| 2. | Increased by $0.25 to $0.75 per ton to reflect expected higher sales prices by PVR lessees. |
| 3. | Reduced by $1.0 million to reflect expected lower coal royalty tonnage. |
| 4. | System throughput volumes increased 30-45 MMcf per day to reflect new supply of natural gas expected to be added as the year progresses, particularly at the Beaver/Spearman complex in the Texas Panhandle and at the Crossroads plant in east Texas. |
| 5. | Increased to include cost of member interest in Thunder Creek coalbed methane gathering system venture acquired for $52 million in April 2008 and other organic growth projects, primarily in the Beaver/Spearman complex in the Texas Panhandle. |
PENN VIRGINIA RESOURCE PARTNERS, L.P.
DERIVATIVE CONTRACT SUMMARY - unaudited
As of March 31, 2008
| | | | | | | | | | | | | | | | |
| | | Average
Volume Per
Day | | | Weighted Average
Price | | | Weighted Average Price Collars |
| | | | | Additional
Put Option | | Floor | | Ceiling |
Frac spread | | (in MMBtu | ) | | | (per MMBtu | ) | | | | | | | | | |
Second quarter 2008 through fourth quarter 2008 | | 7,824 | | | $ | 5.02 | | | | | | | | | | |
| | | | | |
Ethane sale swap | | (in gallons | ) | | | (per gallon | ) | | | | | | | | | |
Second quarter 2008 through fourth quarter 2008 | | 34,440 | | | $ | 0.4700 | | | | | | | | | | |
| | | | | |
Propane sale swaps | | (in gallons | ) | | | (per gallon | ) | | | | | | | | | |
Second quarter 2008 through fourth quarter 2008 | | 26,040 | | | $ | 0.7175 | | | | | | | | | | |
| | | | | |
Crude oil sale swaps | | (in barrels | ) | | | (per barrel | ) | | | | | | | | | |
Second quarter 2008 through fourth quarter 2008 | | 560 | | | $ | 49.27 | | | | | | | | | | |
| | | | |
Natural gasoline collar | | (in gallons | ) | | | | | | | | | | (per gallon) |
Second quarter 2008 through fourth quarter 2008 | | 6,300 | | | | | | | | | | $ | 1.4800 | | $ | 1.6465 |
| | | | |
Crude oil collar | | (in barrels | ) | | | | | | | | | | (per barrel) |
Second quarter 2008 through fourth quarter 2008 | | 400 | | | | | | | | | | $ | 65.00 | | $ | 75.25 |
| | | | | |
Natural gas sale swaps | | (in MMBtu | ) | | | (per MMBtu | ) | | | | | | | | | |
Second quarter 2008 through fourth quarter 2008 | | 4,000 | | | $ | 6.97 | | | | | | | | | | |
| | | | |
Crude oil three-way collar (1) | | (in barrels | ) | | | | | | | | | | (per barrel) |
First quarter 2009 through fourth quarter 2009 | | 1,000 | | | | | | | $ | 70.00 | | $ | 90.00 | | $ | 119.25 |
Management estimates that excluding the above derivative positions, for every $1.00 per MMBtu decrease or increase in natural gas prices from the $7.50 per MMBtu budgeted 2008 benchmark price, natural gas midstream gross processing margin and operating income for the last nine months in 2008 would increase or decrease, respectively, by approximately $7.2 million. In addition, management also estimates that excluding the above derivative positions, for every $5.00 per barrel increase or decrease in the oil prices from the $80.00 per barrel budgeted 2008 benchmark price, natural gas midstream gross processing margin and operating income for the last nine months of 2008 would increase or decrease, respectively, by approximately $3.2 million. These sensitivities assume that other factors are held constant and inlet volumes remain within the levels projected in the guidance table. These estimated changes in gross margin and operating income exclude the potential cash receipts or payments in settling these derivative positions.
(1) 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.
