EX-99.1 2 v173539_ex99-1.htm
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
RECORD FOURTH QUARTER AND FULL-YEAR 2009 RESULTS

RADNOR, PA (BusinessWire) February 10, 2010 – Penn Virginia Resource Partners, L.P. (NYSE: PVR) today reported financial and operational results for the three months and year ended December 31, 2009 and provided initial full-year 2010 guidance.

Fourth Quarter 2009 Highlights
Fourth quarter 2009 highlights and results, with comparisons to fourth quarter 2008 results, included the following:
 
 
·
Record quarterly distributable cash flow (DCF), a non-GAAP (generally accepted accounting principles) measure, of $48.3 million, as compared to $35.0 million in the prior year quarter;
 
 
·
Record adjusted net income, a non-GAAP measure which excludes the effects of the non-cash change in derivatives fair value and impairments, of $32.4 million, or $0.49 per limited partner unit, as compared to $20.6 million, or $0.28 per limited partner unit, in the prior year quarter;
 
 
·
Net income of $23.6 million, or $0.33 per limited partner unit, as compared to $15.9 million, or $0.19 per limited partner unit;
 
 
·
Coal production by lessees of 8.5 million tons, as compared to 8.7 million tons;
 
 
·
Coal royalties revenue, net of coal royalties expense, of $28.6 million, or $3.38 per ton, as compared to $32.4 million, or $3.72 per ton;
 
 
·
Quarterly natural gas midstream system throughput volumes of 27.9 billion cubic feet (Bcf), or 303 million cubic feet (MMcf) per day, as compared to 29.8 Bcf, or 324 MMcf per day;
 
 
·
Midstream gross margin, prior to the cash impact of derivatives, of $34.5 million, or $1.23 per thousand cubic feet (Mcf), as compared to $20.1 million, or $0.68 per Mcf; and
 
 
·
Midstream gross margin, adjusted for the cash impact of midstream derivatives, of $35.9 million, or $1.29 per Mcf, as compared to $17.6 million, or $0.59 per Mcf.

Reconciliations of non-GAAP financial measures to GAAP-based measures appear in the financial tables later in this release.

Management Comment
A. James Dearlove, Chief Executive Officer of PVR, said, “We are pleased to report that distributable cash flow generated by our two business segments increased by $11.1 million, or 30 percent, over the third quarter of 2009 and was $13.3 million, or 38 percent, higher than the fourth quarter of 2008.

“The significant improvement in quarterly results was due to much higher fractionation, or frac, spreads for PVR Midstream due to higher natural gas liquids (NGLs) prices and continued low natural gas costs.  We also enjoyed a full quarter’s benefit from the acquisition of a processing plant and expanded capacity in our largest system, the Panhandle system, which allows us to process gas volumes which were previously being bypassed and processed by third parties.  We anticipate system throughput and processed volumes will increase in 2010 as producers’ drilling activity increases as the result of an ongoing recovery in natural gas prices compared to relatively low 2009 levels.

 
 
 
 
“Coal royalties revenue, net of coal royalties expense, which accounted for approximately 83 percent of the Coal and Natural Resource Management segment’s fourth quarter revenues, was slightly higher as compared to the third quarter of 2009 but was 12 percent lower than the prior year quarter.  Other revenues, while 13 percent higher as compared to the third quarter, was 28 percent lower than the prior year quarter due to a year-over-year decrease in the prices of timber and natural gas.”

Fourth Quarter 2009 Results
DCF for the fourth quarter of 2009 of $48.3 million was $13.3 million, or 38 percent higher, than the $35.0 million of DCF in the fourth quarter of 2008 primarily due to:
 
 
·
an $18.3 million increase in natural gas midstream segment gross margin (adjusted for the cash impact of midstream derivatives) due to higher frac spreads and increased processing volumes; and
 
 
·
a $1.4 million decrease in other capital expenditures.
 
These increases in DCF were partially offset by:
 
 
·
a $6.3 million decrease in coal and natural resource management segment total revenues due to decreases in coal royalties, caused primarily by lower coal prices received by lessees, and reduced levels of oil and gas royalties and other revenue; and
 
 
·
a $0.5 million increase in interest expense (adjusted for the cash impact of interest rate derivatives).
 
DCF in the fourth quarter of 2009 was $11.1 million, or 30 percent, sequentially higher than the $37.2 million of DCF in the third quarter of 2009 primarily due to improved midstream segment gross margin.

The $11.8 million, or 57 percent, increase in adjusted net income as compared to the prior year quarter was primarily due to an $18.3 million increase in operating income from PVR Midstream (adjusted for the cash impact of midstream derivatives), offset in part by a $5.9 million decrease in operating income from PVR Coal & Natural Resource Management (adjusted for impairments) and the $0.7 million increase in interest expense (adjusted for the cash impact of interest rate derivatives).

The $7.7 million, or 48 percent, increase in net income as compared to the prior year quarter was due to a $37.5 million increase in operating income and a $1.1 million decrease in interest and other expenses, partially offset by a $31.0 million increase in derivatives expense resulting from changes in the valuation of unrealized derivative positions.

Full-Year 2009 Results
For the year ended December 31, 2009, DCF was a record $151.7 million, as compared to $129.9 million in 2008.  Operating income was $108.3 million as compared to $115.2 million, which includes a $31.8 million goodwill impairment charge, in 2008.  Adjusted net income, which excludes the effects of the non-cash change in derivatives fair value and impairments, was a fiscal year record $92.4 million, or $1.27 per limited partner unit, as compared to $86.5 million, or $1.28 per limited partner unit, in 2008.  Net income was $65.2 million, or $0.76 per limited partner unit, as compared to $104.5 million, or $1.63 per limited partner unit, in 2008, primarily due to a $36.5 million increase in derivatives expense and the $6.9 million decrease in operating income.  Coal production by lessees was a record 34.3 million tons with average coal royalties per ton of $3.51 ($3.34 net of coal royalties expense) as compared to 33.7 million tons with average coal royalties per ton of $3.65 ($3.36 net of coal royalties expense) in 2008.  Natural gas midstream system throughput volumes were a record 121.3 Bcf, or 332 MMcf per day, with a gross margin of $0.81 per Mcf ($0.90 adjusted for the cash impact of derivatives), as compared to 98.7 Bcf, or 270 MMcf per day, with a gross margin of $1.09 per Mcf ($0.77 adjusted for the cash impact of derivatives).

 
 
 

Cash Distribution
As previously announced, on February 12, 2010, we will pay to unitholders of record as of February 2, 2010 a quarterly cash distribution of $0.47 per unit, or an annualized rate of $1.88 per unit.  The distribution remains unchanged from the distribution paid in the previous quarter.

Coal and Natural Resource Management Segment Review
During the fourth quarter of 2009, operating income for PVR Coal & Natural Resource Management decreased by $7.4 million, or 26 percent, to $21.0 million from $28.4 million in the prior year quarter.  Total revenues, net of coal royalties expense, decreased by $6.2 million, or 15 percent, to $34.6 million from $40.8 million in the prior year quarter primarily due to a $3.8 million, or 12 percent, decrease in coal royalties revenue, net of coal royalties expense, as well as a $1.5 million decrease in other revenues resulting from decreased lessee minimum rental payments and coal transportation (wheelage) fees, and a $0.8 million decrease in oil and gas royalties and timber revenue resulting from lower commodity prices.  As compared to the third quarter of 2009, operating income was one percent lower.  Total revenues, net of coal royalties expense, of $34.6 million was three percent higher as compared to the third quarter of 2009.

Coal royalties revenue, net of coal royalties expense, was 12 percent lower than the prior year quarter, primarily due to a $0.34, or nine percent decrease, in average net coal royalties per ton to $3.38 in the fourth quarter of 2009 as compared to $3.72 in the prior year quarter.  Fourth quarter 2009 lessee production was 0.3 tons, or three percent, lower than the prior year quarter with decreases in Central Appalachia and the Illinois Basin offset by increases in Northern Appalachia and the San Juan Basin.  Operating expenses, excluding coal royalties expense, increased by 10 percent to $13.6 million primarily due to an impairment charge of $1.5 million in the fourth quarter of 2009, partially offset by a net decrease in other operating expenses.

Natural Gas Midstream Segment Review
During the fourth quarter, operating income for PVR Midstream increased $45.0 million to $16.2 million from an operating loss of $28.8 million in the prior year quarter.  Adjusted for the cash impact of derivatives and impairments, operating income increased from $0.5 million in the prior year quarter to $17.6 million. Midstream gross margin increased by 71 percent to $34.5 million, or $1.23 per Mcf, from $20.1 million, or $0.68 per Mcf, in the prior year quarter primarily due to an increase in the price of NGLs, partially offset by a six percent decrease in system throughput volumes.  Adjusted for the cash impact of derivatives, midstream gross margin was $35.9 million, or $1.29 per Mcf, up 104 percent from $17.6 million, or $0.59 per Mcf, in the prior year quarter and up 28 percent from $28.1 million, or $0.94 per Mcf, in the third quarter of 2009.

During the fourth quarter of 2009, processed volumes at our plants increased relative to the prior year period due to contributions from recent expansions and acquisitions, helping to drive higher gross margins for the segment.  Despite the increase in processed volumes, system throughput volumes decreased six percent to 27.9 Bcf, or approximately 303 MMcf per day, in the fourth quarter of 2009 from 29.8 Bcf, or approximately 324 MMcf per day, in the prior year quarter.  The decrease in non-processed volumes was primarily the result of reduced drilling in late 2009 by producers as the result of low gas prices during 2009.  Other expenses decreased by $29.4 million to $21.3 million, due to a $31.8 million impairment charge in the fourth quarter of 2008, partially offset by a $1.7 million increase in depreciation, depletion and amortization and operating expenses resulting from expansions.

Capital Resources and Impact of Derivatives
As of December 31, 2009, we had outstanding borrowings of $620.1 million under our $800 million revolving credit facility and $8.7 million of cash and equivalents, with remaining borrowing capacity of $178.3 million.  The $52.0 million increase in outstanding borrowings as compared to the $568.1 million outstanding as of December 31, 2008 was primarily due to 2009 expansion capital expenditures.  Interest expense decreased from $7.3 million in the fourth quarter of 2008 to $6.2 million in the fourth quarter of 2009 due to decreased interest rates, offset in part by the higher level of outstanding borrowings during the quarter as compared to the prior year quarter.

 
 
 

For the fourth quarter of 2009, derivatives expense was $7.7 million, as compared to derivatives income of $23.3 million in the prior year quarter.  Cash settlements of derivatives included in these amounts resulted in net cash payments of $1.1 million during the fourth quarter of 2009 related to commodity and interest rate derivatives, as compared to $5.2 million of net cash payments in the prior year quarter, a $4.1 million improvement.  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 December 31, 2009.

Initial Guidance for 2010
See the Guidance Table included in this release for initial guidance estimates for full-year 2010.  These estimates, including capital expenditure plans, are meant to provide guidance only and are subject to revision as our operating environment changes.

Conference Call
A joint conference call and webcast for PVR and Penn Virginia GP Holdings, L.P. (NYSE: PVG), during which management will discuss fourth quarter 2009 financial and operational results, is scheduled for Thursday, February 11, 2010 at 1:00 p.m. ET.  Prepared remarks by A. James Dearlove, Chairman and Chief Executive Officer, will be followed by a question and answer period.  Investors and analysts may participate via phone by dialing 1-866-630-9986 five to ten minutes before the scheduled start of the conference call, or via webcast by logging on to our website, www.pvresource.com, or PVG’s website, www.pvgpholdings.com, at least 15 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 for two weeks by dialing 1-888-203-1112 (international: 1-719-457-0820) and using the following replay code: 9994822.  An on-demand replay of the conference call will be available for two weeks at our website.

******
 
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 about us, visit our website 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; our ability to access external sources of capital; any impairment writedowns of our assets; 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; 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); and other risks set forth in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC, including our Annual Report on Form 10-K for the year ended December 31, 2008.  Many of the factors that will determine our future results are beyond the ability of management to control or predict.  Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof.  We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

 
 
 

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS - unaudited
(dollars in thousands, except per unit data)

   
Three Months Ended
    
Year Ended
  
   
December 31,
    
December 31,
  
   
2009
    
2008
    
2009
    
2008
  
Revenues
                  
     Natural gas midstream
   $ 155,907     $ 118,875     $ 504,789     $ 720,002  
     Coal royalties
     29,987       33,923       120,435       122,834  
     Coal services
     1,830       1,837       7,332       7,355  
     Other
     7,177       8,350       24,148       31,389  
Total revenues
     194,901       162,985       656,704       881,580  
                                 
Expenses
                                
     Cost of midstream gas purchased
     121,454       98,752       406,583       612,530  
     Coal royalties expense
     1,388       1,500       5,768       9,534  
     Operating
     6,785       6,624       29,343       23,143  
     Taxes other than income
     1,586       1,241       4,794       4,258  
     General and administrative
     6,747       6,567       30,168       26,906  
     Impairments
     1,511       31,801       1,511       31,801  
     Depreciation, depletion and amortization
     18,264       16,844       70,235       58,166  
Total expenses
     157,735       163,329       548,402       766,338  
                                 
Operating income (loss)
     37,166       (344 )     108,302       115,242  
                                 
Other income (expense)
                                
     Interest expense
     (6,167 )     (7,306 )     (24,653 )     (24,672 )
     Interest income and other
     311       326       1,280       (2,907 )
     Derivatives
     (7,709 )     23,261       (19,714 )     16,837  
                                 
Net income
   $ 23,601     $ 15,937     $ 65,215     $ 104,500  
                                 
Allocation of net income:
                                
     General partner's interest in net income
   $ 6,386     $ 6,233     $ 24,962     $ 23,715  
     Limited partners' interest in net income
   $ 17,215     $ 9,704     $ 40,253     $ 80,785  
                                 
Basic and diluted net income per limited partner unit
   $ 0.33     $ 0.19     $ 0.76     $ 1.63  
                                 
Weighted average units outstanding, basic and diluted (in thousands)
     51,799       51,799       51,799       49,495  
                                 
                                 
Other data:
                                
                                 
Distributions to limited partners (per unit) - (a)
   $ 0.47     $ 0.47     $ 1.88     $ 1.85  
Distributions paid
   $ 30,877     $ 30,877     $ 123,508     $ 111,076  
Distributable cash flow (non-GAAP) - (b)
   $ 48,304     $ 34,996     $ 151,725     $ 129,915  
                                 
Coal and natural resource management segment:
                                
     Coal royalty tons (in thousands)
     8,456       8,715       34,330       33,690  
     Average coal royalties ($ per ton)
   $ 3.55     $ 3.89     $ 3.51     $ 3.65  
     Average net coal royalties ($ per ton) - (c)
   $ 3.38     $ 3.72     $ 3.34     $ 3.36  
                                 
Natural gas midstream segment:
                                
     System throughput volumes (MMcf)
     27,902       29,768       121,335       98,683  
     Gross margin (in thousands)
   $ 34,453     $ 20,123     $ 98,206     $ 107,472  

(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 subsequent page for the calculation and description of distributable cash flow.
(c)
The average net coal royalties per ton deducts coal royalties expense, which is incurred primarily in Central Appalachia.    

 
 
 

CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited
(in thousands)

   
December 31,
    
December 31,
  
   
2009
    
2008
  
             
Assets
            
     Cash and cash equivalents
   $ 8,659     $ 9,484  
     Accounts receivable
     82,321       73,267  
     Derivative assets
     1,331       30,431  
     Other current assets
     4,468       4,263  
         Total current assets
     96,779       117,445  
     Property, plant and equipment, net
     900,844       895,119  
     Other long-term assets
     210,437       206,255  
          Total assets
   $ 1,208,060     $ 1,218,819  
                 
Liabilities and Partners' Capital
                
     Accounts payable and accrued liabilities
   $ 70,405     $ 71,186  
     Deferred income
     3,839       4,842  
     Derivative liabilities
     11,251       13,585  
         Total current liabilities
     85,495       89,613  
     Derivative liabilities
     4,285       6,915  
     Other long-term liabilities
     21,673       23,509  
     Long-term debt
     620,100       568,100  
     Partners' capital
     476,507       530,682  
          Total liabilities and partners' capital
   $ 1,208,060     $ 1,218,819  
 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)

   
Three Months Ended
    
Year Ended
  
   
December 31,
    
December 31,
  
   
2009
    
2008
    
2009
    
2008
  
Cash flows from operating activities
            
Net income
   $ 23,601     $ 15,937     $ 65,215     $ 104,500  
Adjustments to reconcile net income to
                                
net cash provided by operating activities:
                                
Depreciation, depletion and amortization
     18,264       16,844       70,235       58,166  
Impairments
     1,511       31,801       1,511       31,801  
Commodity derivative contracts:
                                
Total derivative losses (gains)
     8,466       (21,909 )     22,700       (11,357 )
Cash receipts (payments) to settle derivatives for the period
     (1,135 )     (5,187 )     3,000       (38,466 )
Noncash interest expense
     1,242       1,150       4,391       2,693  
Equity earnings, net of distributions received
     (81 )     1,191       (2,537 )     (224 )
Other
     196       198       765       (1,408 )
Changes in operating assets and liabilities
     (8,517 )     4,383       (5,308 )     (6,529 )
Net cash provided by operating activities
     43,547       44,408       159,972       139,176  
                                 
Cash flows from investing activities
                                
Acquisitions, net of cash acquired
     (70 )     (7,345 )     (29,580 )     (260,376 )
Additions to property, plant and equipment
     (7,316 )     (16,750 )     (51,097 )     (71,652 )
Other
     275       (658 )     1,147       998  
Net cash used in investing activities
     (7,111 )     (24,753 )     (79,530 )     (331,030 )
                                 
Cash flows from financing activities
                                
Proceeds from equity issuance
     -       -       -       141,084  
Distributions to partners
     (31,043 )     (30,877 )     (124,009 )     (111,076 )
Proceeds from borrowings, net
     (8,000 )     10,000       52,000       156,000  
Other
     -       -       (9,258 )     (4,200 )
Net cash provided by (used in) financing activities
     (39,043 )     (20,877 )     (81,267 )     181,808  
                                 
Net decrease in cash and cash equivalents
     (2,607 )     (1,222 )     (825 )     (10,046 )
Cash and cash equivalents - beginning of period
     11,266       10,706       9,484       19,530  
Cash and cash equivalents - end of period
   $ 8,659     $ 9,484     $ 8,659     $ 9,484  
 
 
 
 

PENN VIRGINIA RESOURCE PARTNERS, L.P.
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands, except per unit data)

   
Three Months Ended
    
Year Ended
  
   
December 31,
    
December 31,
  
   
2009
    
2008
    
2009
    
2008
  
                         
Reconciliation of GAAP "Net income" to Non-GAAP
                        
"Distributable cash flow"
                        
Net income
   $ 23,601     $ 15,937     $ 65,215     $ 104,500  
Depreciation, depletion and amortization
     18,264       16,844       70,235       58,166  
Impairments
     1,511       31,801       1,511       31,801  
Commodity derivative contracts:
                                
Derivative losses included in operating income
     -       1,352       -       5,480  
Derivative losses included in other income
     8,466       (23,261 )     22,700       (16,837 )
Cash receipts (payments) to settle derivatives for the period
     (1,135 )     (5,187 )     3,000       (38,466 )
Equity earnings from joint venture, net of distributions
     (81 )     1,191       (2,537 )     (224 )
Other capital expenditures
     (2,322 )     (3,681 )     (8,399 )     (14,505 )
                                 
Distributable cash flow (a)
   $ 48,304     $ 34,996     $ 151,725     $ 129,915  
                                 
Distribution to partners:
                                
                                 
Limited partner units
   $ 24,345     $ 24,345     $ 97,380     $ 89,207  
General partner interest
     497       497       1,988       1,820  
Incentive distribution rights (b)
     6,035       6,035       24,140       20,049  
                                 
Total cash distribution paid during period
   $ 30,877     $ 30,877     $ 123,508     $ 111,076  
                                 
Total cash distribution paid per unit during period
   $ 0.47     $ 0.47     $ 1.88     $ 1.82  
                                 
Reconciliation of GAAP "Net income" to Non-GAAP
                                
"Net income as adjusted"
                                
Net income
   $ 23,601     $ 15,937     $ 65,215     $ 104,500  
Adjustments for derivatives:
                                
Derivative losses included in operating income
     -       1,352       -       5,480  
Derivative (gains) losses included in other income
     8,466       (23,261 )     22,700       (16,837 )
Cash receipts (payments) to settle derivatives for the period
     (1,135 )     (5,187 )     3,000       (38,466 )
Adjustment for impairments
     1,511       31,801       1,511       31,801  
                                 
Net income, as adjusted (c)
   $ 32,443     $ 20,642     $ 92,426     $ 86,478  
                                 
Allocation of net income, as adjusted:
                                
General partner's interest in net income, as adjusted
   $ 6,563     $ 6,327     $ 25,506     $ 23,355  
Limited partners' interest in net income, as adjusted
   $ 25,880     $ 14,315     $ 66,920     $ 63,123  
                                 
Net income, as adjusted, per limited partner unit, basic and diluted
   $ 0.49     $ 0.28     $ 1.27     $ 1.28  

(a)
Distributable cash flow represents net income plus depreciation, depletion and amortization expenses, plus impairments, plus (minus) derivative losses (gains) included in operating income and other income, plus (minus) cash received (paid) for derivative settlements, minus equity earnings in joint ventures, plus cash distributions from joint ventures, minus other capital expenditures.  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 by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of publicly traded partnerships.  Distributable cash flow is presented because we believe 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 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.

(c)
Net income, as adjusted, represents net income adjusted to exclude the effects of non-cash changes in the fair value of derivatives.  We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies in the natural gas midstream industry.  We use 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.
 
 
 
 

QUARTERLY SEGMENT INFORMATION - unaudited
(in thousands)

   
Coal and
Natural
Resource
Management
    
Natural Gas
Midstream
    
Consolidated
  
Three months ended December 31, 2009
                  
                   
Revenues
                  
     Natural gas midstream
   $ -     $ 155,907     $ 155,907  
     Coal royalties
     29,987       -       29,987  
     Coal services
     1,830       -       1,830  
     Timber
     1,371       -       1,371  
     Oil and gas royalties
     688       -       688  
     Other
     2,149       2,969       5,118  
        Total revenues
     36,025       158,876       194,901  
Expenses
                        
     Cost of midstream gas purchased
     -       121,454       121,454  
     Coal royalties expense
     1,388       -       1,388  
     Other operating
     692       6,093       6,785  
     Taxes other than income
     558       1,028       1,586  
     General and administrative
     3,107       3,640       6,747  
     Impairments
     1,511       -       1,511  
     Depreciation, depletion and amortization
     7,773       10,491       18,264  
       Total expenses
     15,029       142,706       157,735  
                         
Operating income
   $ 20,996     $ 16,170     $ 37,166  
                         
Additions to property and equipment and acquisitions
   $ 206     $ 7,180     $ 7,386  
 
 
   
Coal and
Natural
Resource
Management
    
Natural Gas
Midstream
    
Consolidated
  
Three months ended December 31, 2008
                  
                   
Revenues
                  
     Natural gas midstream
   $ -     $ 118,875     $ 118,875  
     Coal royalties
     33,923       -       33,923  
     Coal services
     1,837       -       1,837  
     Timber
     1,615       -       1,615  
     Oil and gas royalties
     1,259       -       1,259  
     Other
     3,683       1,793       5,476  
        Total revenues
     42,317       120,668       162,985  
Expenses
                        
     Cost of midstream gas purchased
     -       98,752       98,752  
     Coal royalties expense
     1,500       -       1,500  
     Other operating
     918       5,706       6,624  
     Taxes other than income
     565       676       1,241  
     General and administrative
     2,826       3,741       6,567  
     Impairments
     -       31,801       31,801  
     Depreciation, depletion and amortization
     8,072       8,772       16,844  
       Total expenses
     13,881       149,448       163,329  
                         
Operating income (loss)
   $ 28,436     $ (28,780 )   $ (344 )
                         
Additions to property and equipment and acquisitions
   $ 2,084     $ 22,011     $ 24,095  
 
 
 
 

PENN VIRGINIA RESOURCE PARTNERS, L.P.
YEAR-TO-DATE SEGMENT INFORMATION - unaudited
(in thousands)

   
Coal and
Natural
Resource
Management
    
Natural Gas
Midstream
    
Consolidated
  
Year ended December 31, 2009
                  
                   
Revenues
                  
     Natural gas midstream
   $ -     $ 504,789     $ 504,789  
     Coal royalties
     120,435       -       120,435  
     Coal services
     7,332       -       7,332  
     Timber
     5,726       -       5,726  
     Oil and gas royalties
     2,471       -       2,471  
     Other
     8,636       7,315       15,951  
        Total revenues
     144,600       512,104       656,704  
Expenses
                        
     Cost of midstream gas purchased
     -       406,583       406,583  
     Coal royalties expense
     5,768       -       5,768  
     Other operating
     2,892       26,451       29,343  
     Taxes other than income
     1,704       3,090       4,794  
     General and administrative
     13,867       16,301       30,168  
     Impairments
     1,511       -       1,511  
     Depreciation, depletion and amortization
     31,330       38,905       70,235  
       Total expenses
     57,072       491,330       548,402  
                         
Operating income
   $ 87,528     $ 20,774     $ 108,302  
                         
 Additions to property and equipment and acquisitions
   $ 2,252     $ 78,425     $ 80,677  
 
 
   
Coal and
Natural
Resource
Management
    
Natural Gas
Midstream
    
Consolidated
  
Year ended December 31, 2008
                  
                   
Revenues
                  
     Natural gas midstream
   $ -     $ 720,002     $ 720,002  
     Coal royalties
     122,834       -       122,834  
     Coal services
     7,355       -       7,355  
     Timber
     6,943       -       6,943  
     Oil and gas royalties
     5,989       -       5,989  
     Other
     10,206       8,251       18,457  
        Total revenues
     153,327       728,253       881,580  
Expenses
                        
     Cost of midstream gas purchased
     -       612,530       612,530  
     Coal royalties expense
     9,534       -       9,534  
     Other operating
     2,406       20,737       23,143  
     Taxes other than income
     1,680       2,578       4,258  
     General and administrative
     12,606       14,300       26,906  
     Impairments
     -       31,801       31,801  
     Depreciation, depletion and amortization
     30,805       27,361       58,166  
       Total expenses
     57,031       709,307       766,338  
                         
Operating income
   $ 96,296     $ 18,946     $ 115,242  
                         
 Additions to property and equipment and acquisitions
   $ 27,270     $ 304,758     $ 332,028  
 
 
 
 

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 2010.

   
Actual
              
   
First
Quarter
    
Second
Quarter
    
Third
Quarter
    
Fourth
Quarter
    
YTD
    
Full-Year
  
   
2009
    
2009
    
2009
    
2009
    
2009
    
2010 Guidance
  
                                           
Coal and natural resource management segment:
                                          
Coal royalty tons (millions)
     8.7       8.7       8.4       8.5       34.3       31.0       32.0  
                                                         
Revenues:
                                                        
Average coal royalties per ton
   $ 3.50       3.43       3.56       3.55       3.51       3.30       3.40  
Average coal royalties per ton, net of coal royalty expense
   $ 3.36       3.25       3.37       3.38       3.34       3.15       3.25  
Other
   $ 7.6       5.1       5.4       6.0       24.1       21.0       22.0  
                                                         
Expenses:
                                                        
Cash operating expenses
   $ 5.9       6.6       6.0       5.7       24.2       22.0       22.5  
Depreciation, depletion and amortization
   $ 7.4       8.2       8.0       7.8       31.3       28.5       29.0  
                                                         
Capital expenditures:
                                                        
Expansion and acquisitions
   $ 1.3       0.6       0.1       0.1       2.1       6.0       7.0  
Other capital expenditures
   $ -       -       -       0.2       0.2       0.0       0.5  
Total segment capital expenditures
   $ 1.3       0.6       0.1       0.3       2.3       6.0       7.5  
                                                         
Natural gas midstream segment:
                                                        
System throughput volumes (MMcf per day)
     359       344       324       303       332       350       360  
                                                         
Expenses:
                                                        
Cash operating expenses
   $ 11.8       11.6       11.6       10.8       45.8       55.0       60.0  
Depreciation, depletion and amortization
   $ 9.1       9.5       9.8       10.5       38.9       42.0       44.0  
                                                         
Capital expenditures:
                                                        
Expansion and acquisitions
   $ 11.2       10.3       37.9       5.0       64.4       34.0       42.0  
Other capital expenditures
   $ 3.3       1.4       1.4       2.3       8.4       16.0       18.0  
Total segment capital expenditures
   $ 14.5       11.7       39.3       7.3       72.8       50.0       60.0  
                                                         
Other:
                                                        
Interest expense:
                                                        
End of period total debt outstanding
   $ 595.1       597.1       628.1       620.1                          
Effective Interest rate
     3.9 %     4.2 %     4.2 %     3.9 %                        

These estimates are meant to provide guidance only and are subject to revision as PVR's operating environment changes.

 
 
 

DERIVATIVE CONTRACT SUMMARY - unaudited
As of December 31, 2009

   
Average
Volume
   
Swap
    
Weighted Average Price
  
   
Per Day
    
Price
    
Put (a)
    
Call (b)
  
                         
Crude oil collar
  
(barrels)
          
(per barrel)
  
First quarter 2010 through fourth quarter 2010
     750           $ 70.00     $ 81.25  
                               
Crude oil collar
  
(barrels)
          
(per barrel)
  
First quarter 2010 through fourth quarter 2010
     1,000           $ 68.00     $ 80.00  
                               
Natural gas purchase swap
  
(MMBtu)
    
(MMBtu)
                  
First quarter 2010 through fourth quarter 2010
     5,000     $ 5.815                  
                                 
NGL - natural gasoline collar
  
(gallons)
            
(per gallon)
  
First quarter 2011 through fourth quarter 2011
     60,000             $ 1.55     $ 1.92  
                                 
Crude oil collar
  
(barrels)
            
(per barrel)
  
First quarter 2011 through fourth quarter 2011
     400             $ 75.00     $ 98.50  
                                 
Natural gas purchase swap
  
(MMBtu)
    
(MMBtu)
                  
First quarter 2011 through fourth quarter 2011
     3,000     $ 6.430                  

We estimate that, excluding the derivative positions described above, for every $1.00 MMBtu increase or decrease in  the natural gas price, natural gas midstream gross margin and operating income for 2010 would decrease or increase  by approximately $6.9 million.  In addition, we estimate that for every $5.00 per barrel increase or decrease in the  crude oil price, our natural gas midstream gross margin and operating income for 2010 would increase or decrease by  approximately $11.5 million.  This assumes that crude oil prices, natural gas prices and inlet volumes remain constant  at anticipated levels.  These estimated changes in gross margin and operating income exclude potential cash receipts  or payments in settling these derivative positions.

(a) - Purchased put/floor.
(b) - Sold call/ceiling.