PPX PPL Capital Funding Inc

Pacific Energy Partners, L.P. (NYSE:PPX) ("Pacific Energy" or the "Partnership") announced that net income for the three months ended December 31, 2005, was $11.8 million, or $0.30 per limited partner unit, compared to net income of $8.6 million, or $0.29 per limited partner unit, for the three months ended December 31, 2004. Recurring net income for the three months ended December 31, 2005 was $12.3 million, or $0.31 per limited partner unit, compared to recurring net income of $9.4 million, or $0.31 per limited partner unit, in the fourth quarter of 2004. Recurring net income for the fourth quarter of 2005 excludes a $0.5 million write-down of an idle Pacific Terminals property and recurring net income for the fourth quarter of 2004 also excludes a similar write-down of $0.8 million. All per unit amounts in the text of this news release are reported on a diluted basis. On January 20, 2006, Pacific Energy declared a cash distribution of $0.555 per unit for the fourth quarter of 2005, or $2.22 per unit annualized. This distribution is 8.3% greater than the distribution declared for the quarter ended September 30, 2005, and 11.0% greater than the distribution declared for the quarter ended December 31, 2004. The distribution will be paid on February 14, 2006, to holders of record as of January 31, 2006. Distributable cash flow to the limited partners for the fourth quarter of 2005 was $19.1 million. On a diluted, weighted average basis, there were 39,298,000 limited partner units outstanding during the fourth quarter of 2005, which is approximately 32% more than in the fourth quarter of 2004. The increase in units outstanding is attributable to the equity offerings Pacific Energy completed for the financing of the acquisition of assets from Valero L.P. The results for the quarter ended December 31, 2005, reflect the addition of assets acquired from Valero L.P., increased margins for Pacific Marketing and Transportation ("PMT"), increased tank utilization for Pacific Terminals and increased pipeline volumes in the Rocky Mountains. These increases were partially offset by lower pipeline volumes and higher pipeline repair expense on the West Coast, as well as lower revenues on the Rangeland Pipeline system. Recurring net income for the year ended December 31, 2005, was $47.0 million, or $1.42 per limited partner unit, compared with $39.4 million, or $1.36 per limited partner unit, for the year ended December 31, 2004. "We had an excellent year in 2005, as evidenced by our distribution growth of 11%, particularly after considering the cost of rain-related repairs in Southern California and Alberta," stated Irv Toole, President and CEO. "Both of our strategic business units continue to grow and the refined products storage and pipeline assets we acquired from Valero L.P. in September 2005 have met all of our expectations. We are extremely excited about the prospects for continued growth through acquisition as well as internal growth projects of approximately $106 million scheduled for 2006." OPERATING RESULTS BY SEGMENT WEST COAST BUSINESS UNIT Operating income was $18.4 million for the three months ended December 31, 2005, compared to $11.0 million in the corresponding period in 2004. The largest portion of this increase was associated with the addition of the Northern California and East Coast terminals that were acquired on September 30, 2005, from Valero L.P. Margins for PMT were greater in the fourth quarter of 2005 compared to the fourth quarter of 2004. In addition, certain crude oil contracts that were acquired on July 1, 2005, have added to the business. Pacific Terminals' storage facilities had a higher rate of utilization during the 2005 quarter than in the fourth quarter of 2004. West Coast pipeline volumes to Los Angeles destinations for the three months ended December 31, 2005, were approximately 23% lower than in the fourth quarter of 2004. During the 2005 quarter, volumes were impacted by refinery issues in Los Angeles, as well as declines in San Joaquin Valley (SJV) and Outer Continental Shelf (OCS) production. The effect on revenue of the decline in Los Angeles delivered volumes was partially offset by increased tariffs, as well as higher Bakersfield area deliveries. In addition, in the fourth quarter of 2004, Northern California refinery maintenance resulted in the shift of some volume south to the Los Angeles area. Pacific Energy continued to incur costs for pipeline repairs associated with last winter's record rainfall: $0.4 million of pipeline repair costs and $2.5 million of sustaining capital expenditures were incurred in the fourth quarter of 2005. ROCKY MOUNTAIN BUSINESS UNIT Operating income was $7.3 million for the three months ended December 31, 2005, compared to $6.8 million in the corresponding period of 2004. The Rocky Mountain Products Pipeline, formerly Valero L.P.'s West Pipeline, provided additional pipeline income for the quarter. In addition, increased crude oil demand by Salt Lake City refiners, as well as increased tariff rates, helped drive higher pipeline revenues. In Canada, higher revenues resulted from increased location differentials and higher volumes transported south to the U.S. The higher revenues were reduced however for the correction of a billing error, identified by Pacific Energy, related to one of its buy/sell customers, which had occurred since the time of the acquisition of Rangeland in May 2004. The billing error amounted to approximately $2.4 million pre-tax. The new receiving terminal and pump station in Edmonton, which will provide direct access to supplies of synthetic and other types of crude oil, should begin operations by the end of February 2006. To further meet the increasing crude oil demand in Salt Lake City, including increasing demand for heavy Canadian crude oil and Canadian synthetic crude oil, Pacific Energy is finalizing its plans to construct a new 16-inch pipeline from the terminus of Frontier Pipeline near Evanston, Wyoming to the Salt Lake City refining complex. This expansion will occur in two phases, the first taking place in 2006. Pacific Energy has obtained the necessary permits for the initial phase of the expansion and is currently working with shippers to finalize the project. Once the first phase is completed, additional capacity will be available immediately, and the second phase will be constructed in 2007. In January 2006, Pacific Energy acquired the assets of La Barge Trucking, Inc., a Wyoming crude oil trucking company, with 9 trucks, 27 trailer units and 13 employees. The La Barge operation has been integrated with Pacific Energy's existing crude oil trucking business in the Rocky Mountain region, providing additional trucking services to handle increasing production in the region. FULL YEAR RESULTS For the year ended December 31, 2005, net income was $39.6 million, or $1.25 per limited partner unit, compared to $35.7 million, or $1.23 per limited partner unit for the year ended December 31, 2004. Recurring net income for the year ended December 31, 2005, was $47.0 million, or $1.42 per limited partner unit, compared with $39.4 million, or $1.36 per limited partner unit, for the year ended December 31, 2004. Recurring net income for the year ended December 31, 2005, excludes a $2.0 million expense for the insurance deductible associated with the remediation of the Pyramid Lake oil release on Line 63, a $3.1 million expense related to the accelerated vesting of restricted units under Pacific Energy's long-term incentive plan as a result of the change in control attributable to the purchase of Pacific Energy's general partner by LB Pacific, LP, a $1.8 million expense as a result of the general partner purchase transaction (an item that was required to be recorded as a partnership expense with the general partner's payment of the item recorded as a capital contribution), and a $0.5 million write-down of an idle Pacific Terminals property. Recurring net income for the year ended December 31, 2004, excludes a $2.9 million write-off of deferred financing costs and a $0.8 million write-down of an idle Pacific Terminals property. Recurring net income for 2005 reflects the benefit of a full year of operations for the Rangeland system, which was acquired in May 2004, and the acquisition of the Rocky Mountain Products Pipeline and the Northern California and East Coast terminals, on September 30, 2005. In addition, Pacific Energy realized higher pipeline volumes in the Rocky Mountains, higher margins and new contracts at PMT, and higher storage and terminaling revenues for Pacific Terminals. Partially offsetting these increases were lower West Coast pipeline volumes, repairs and maintenance expense associated with earth movement and stream erosion problems caused by the record rainfall in Southern California and Alberta, and unscheduled repairs of two Pacific Terminals tanks. General and administrative expense increased as a result of growth of the Partnership. Increased interest expense reflects the debt portion of financing the acquisitions. In March 2005, Pacific Energy experienced an oil release on Line 63 in northern Los Angeles County, which was caused by a rain-induced landslide. In addition, record rainfall in Southern California caused stream erosion and earth movement, exposing the Partnership's pipelines in multiple locations. The total costs associated with the oil recovery and restoration effort for the oil release are now estimated at $26 million, of which Pacific Energy is paying $2.0 million for its insurance deductible. On August 1, 2005, we initiated a temporary surcharge of $0.10 per barrel on Line 63 long haul tariff rates to recover the repair costs and insurance deductible. As a result of the repairs related to the record rainfall in California last winter and in Alberta last summer, which were not insured, a total of $3.0 million or $0.09 per limited partner unit was expensed during 2005. In addition, $4.5 million of sustaining capital was incurred. The Partnership expects to incur an additional $1.1 million of expense in 2006 to complete the repairs in California. For full year 2005, distributable cash flow to the limited partners was $66.8 million. On a diluted weighted average basis, there were 32,414,000 limited partner units outstanding. PIER 400 Pacific Energy continues to advance the Pier 400 deepwater import terminal project in the environmental permitting process. Issuance of the draft environmental impact study is anticipated in the first quarter of 2006, at which time a public comment period will commence. Other approvals or permits which Pacific Energy needs to obtain are approvals from the Board of Harbor Commissioners and the City of Los Angeles, and a permit to construct from the South Coast Air Quality Management District. Pacific Energy expects to have these permits and approvals necessary to begin construction early in the fourth quarter of 2006. Once those permits have been obtained, the construction period will commence. Pacific Energy expects that it will take approximately 16 months to complete the project after construction begins. LOOKING FORWARD For the full year ending December 31, 2006, Pacific Energy is forecasting net income of $1.55 to $1.70 per unit. For the first quarter ending March 31, 2006, Pacific Energy is forecasting net income of $0.33 to $0.39 per unit. Included in this guidance is EBITDA (earnings before interest, taxes, depreciation and amortization) for the first quarter of 2006 of $31 million to $36 million and EBITDA for the full year ending December 31, 2006 of $142 million to $151 million. For the full year, Pacific Energy is budgeting total capital expenditures of $120 million, including $106 million for expansion projects, $6 million for transition capital projects, and $8 million to $9 million for sustaining capital projects. The expansion capital relates to numerous projects that will increase cash flow beginning in 2006. There will be $23 million of expansion capital associated with the recently acquired Valero L.P. assets. For Pacific Terminals, Pacific Energy expects to invest $11 million for the refurbishment of 600,000 barrels of additional storage and new infrastructure to increase its pumping capacity and operating efficiency. In the Rocky Mountains, $4 million is budgeted for the completion of new tankage associated with the transport of synthetic crude oil, and $32 million for the first phase of the Salt Lake City expansion, as discussed above. Lastly, for Pier 400 Pacific Energy expects to expend $21 million for the completion of the permitting process, acquisition of additional emission credits and engineering. The capital associated with Pier 400 does not include any construction capital, which will be added later in the year upon completion of permitting. OTHER MATTERS Pacific Energy will host a conference call at 2:00 p.m. ET (11:00 a.m. PT) on Thursday, February 2, 2006, to discuss the results of the fourth quarter and full year 2005 and the guidance for 2006. The dial in number for the live call is 800-446-2782 or 847-413-3235, and the passcode is 13739514. The call will be available one hour after the end of the conference call and will be replayed for one week by dialing 888-843-8996 or 630-652-3044 and using 13739514 as the passcode. The call will also be available both live and via replay on the Pacific Energy Partners, L.P. website at www.PacificEnergy.com. About Pacific Energy: Pacific Energy Partners, L.P. is a master limited partnership headquartered in Long Beach, California. Pacific Energy is engaged principally in the business of gathering, transporting, storing and distributing crude oil, refined products and other related products. Pacific Energy generates revenues by transporting such commodities on its pipelines, by leasing capacity in its storage facilities and by providing other terminaling services. Pacific Energy also buys and sells crude oil, activities that are generally complementary to its crude oil operations. Pacific Energy conducts its business through two business units, the West Coast Business Unit, which includes activities in California and the Philadelphia, PA area, and the Rocky Mountain Business Unit, which includes activities in five Rocky Mountain states and Alberta, Canada. This news release may include "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. All statements other than statements of historical fact included or incorporated herein may constitute forward-looking statements. Although Pacific Energy believes that the forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that may affect Pacific Energy's operations and financial performance. Among the factors that could cause results to differ materially are those risks discussed in Pacific Energy's filings with the Securities and Exchange Commission, including its Annual Report on Form 10-K for the year ended December 31, 2004. The estimates associated with the oil release are based on facts known at the time of estimation and the Partnership's assessment of the ultimate outcome. Among the many uncertainties that impact the estimates are the necessary regulatory approvals for and potential modification of remediation plans, changes in costs associated with environmental remediation services and equipment and the possibility of third party legal claims giving rise to additional expenses. Therefore, no assurance can be made that costs incurred in excess of the estimated costs, if any, would not have a material adverse effect on the Partnership's financial condition, results of operations, or cash flows, although the Partnership believes it is likely that most, if not all, of any such excess cost, to the extent attributable to clean-up and third-party claims, would be recoverable through insurance. As new information becomes available in future periods, the Partnership may change its expense accrual and recovery estimates. The forward-looking statements in this news release include Pacific Energy's forecasts of net earnings and EBITDA, which are inherently uncertain and based upon assumptions of management as to future market conditions, including the demand for products we transport, regulatory and legal conditions, the non-occurrence of environmental risks and certain other assumptions that may vary significantly from those assumed. The Partnership is undertaking no obligation to update its forecasts of net earnings and EBITDA. For additional information about Pacific Energy, please visit its website at www.PacificEnergy.com. -0- *T PACIFIC ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (Amounts in thousands, except per unit amounts) Three Months Ended Year Ended December 31, December 31, -------------------- --------------------- 2005 2004 2005 2004 --------- -------- --------- --------- Operating revenues: Pipeline transportation revenue $ 33,581 $ 28,516 $ 116,648 $ 108,395 Storage and terminaling revenue 21,063 9,804 51,986 37,577 Pipeline buy/sell transportation revenue 6,766 6,978 35,671 18,640 Crude oil sales, net of purchases 6,350 2,351 19,997 16,787 --------- -------- --------- --------- Net revenues 67,760 47,649 224,302 181,399 --------- -------- --------- --------- Expenses: Operating 32,332 22,714 104,397 85,286 General and administrative 5,485 4,148 18,472 15,400 Accelerated long-term incentive plan compensation expense -- -- 3,115 -- Line 63 oil release costs -- -- 2,000 -- Transaction costs(1) -- -- 1,807 -- Depreciation and amortization 9,711 6,397 29,406 24,173 --------- -------- --------- --------- Total expenses 47,528 33,259 159,197 124,859 --------- -------- --------- --------- Share of net income of Frontier 394 138 1,757 1,328 Write-down of idle properties (450) (800) (450) (800) --------- -------- --------- --------- Operating income 20,176 13,728 66,412 57,068 Net interest expense (9,041) (5,466) (26,720) (19,209) Write-off of deferred financing costs and interest rate swap termination expense -- -- -- (2,901) Other income (expense) (268) 426 1,119 1,032 --------- -------- --------- --------- Income before income tax expense 10,867 8,688 40,811 35,990 --------- -------- --------- --------- Income tax (expense) benefit: Current 646 (176) (1,252) (326) Deferred 328 122 89 65 --------- -------- --------- --------- 974 (54) (1,163) (261) --------- -------- --------- --------- Net income $ 11,841 $ 8,634 $ 39,648 $ 35,729 --------- -------- --------- --------- --------- -------- --------- --------- Net income (loss) for the general partner interest(2) $ 237 $ 173 $ (978) $ 715 --------- -------- --------- --------- --------- -------- --------- --------- Net income for the limited partner interests(2) $ 11,604 $ 8,461 $ 40,626 $ 35,014 --------- -------- --------- --------- --------- -------- --------- --------- Weighted average units outstanding: Basic 39,298 29,593 32,381 28,406 Diluted 39,298 29,665 32,414 28,488 --------- -------- --------- --------- Basic and diluted net income per limited partner unit $ 0.30 $ 0.29 $ 1.25 $ 1.23 --------- -------- --------- --------- --------- -------- --------- --------- (1) Pursuant to an Ancillary Agreement, our general partner reimbursed us $1.8 million for costs incurred in connection with the sale of our general partner. Generally accepted accounting principles require us to record an expense with the reimbursement shown as a partner's capital contribution. (2) See "General Partner and Limited Partners Allocation of Net Income" schedule included herein. PACIFIC ENERGY PARTNERS, L.P. (Unaudited) (In thousands) CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, ------------------------ 2005 2004 --------- --------- Cash flows from operating activities: Net income $ 39,648 $ 35,729 Depreciation, amortization, non-cash employee compensation under long-term incentive plan, deferred income taxes, loss on disposal and Frontier(1) adjustment 34,010 26,349 Non-cash write-off of deferred financing costs -- 2,321 Write-down of idle properties 450 800 Net changes in operating assets and liabilities 1,676 (7,973) --------- --------- Net cash provided by operating activities 75,784 57,226 --------- --------- Cash flows from investing activities: Acquisitions (462,553) (138,701) Net additions to property and equipment (51,717) (16,520) Other 1,519 (731) --------- --------- Net cash used in investing activities (512,751) (155,952) --------- --------- Cash flows from financing activities: Issuance of common units, net of fees and offering expenses 289,284 125,881 Capital contribution from the general partner 8,569 2,720 Net proceeds from senior notes offering 170,889 240,932 Repayment of term loan -- (225,000) Proceeds from credit facilities 283,502 140,922 Repayment of credit facilities (249,466) (115,253) Deferred financing costs (4,573) (1,227) Distributions to partners (66,775) (56,518) Issuance of common units pursuant to exercise of unit option 707 -- Related parties (533) (47) --------- --------- Net cash provided by financing activities 431,604 112,410 Effect of exchange rate changes on cash 44 -- --------- --------- Net increase (decrease) in cash and cash equivalents (5,319) 13,684 Cash and cash equivalents, beginning of year 23,383 9,699 --------- --------- Cash and cash equivalents, end of year $ 18,064 $ 23,383 --------- --------- --------- --------- (1) Net Cash received from (paid to) Frontier was $1,317 and $(44) for the years ended December 31, 2005 and 2004, respectively. SELECTED BALANCE SHEET DATA December 31, -------------------------- 2005 2004 ---------- ---------- Current assets(1) $ 192,115 $ 95,545 Total assets $1,476,452 $ 869,905 Current liabilities $ 156,187 $ 48,045 Long-term debt $ 565,632 $ 357,163 Partners' capital $ 698,239 $ 422,466 (1) Current assets includes cash balances of $18,064 and $23,383 at December 31, 2005 and 2004, respectively. PACIFIC ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND OPERATING HIGHLIGHTS BY SEGMENT Three Months Ended December 31, 2005 (Unaudited) (In thousands) West Coast Rocky Intersegment Total Operations Mountain and Operations Intrasegment Eliminations(1) ----------- ---------- --------------- -------- Three Months Ended December 31, 2005: Segment revenue: Pipeline transportation revenue $ 16,481 $ 18,723 $ (1,623) $33,581 Storage and terminaling revenue 21,063 -- 21,063 Pipeline buy/sell transportation revenue -- 6,766 6,766 Crude oil sales, net of purchases 6,441 5 (96) 6,350 ---------- --------- ------- Net revenue 43,985 25,494 67,760 ---------- --------- ------- Segment expenses: Operating expense 19,730 14,321 (1,719) 32,332 Depreciation and amortization 5,430 4,281 9,711 ---------- --------- ------- Total expenses 25,160 18,602 42,043 ---------- --------- ------- Share of net income of Frontier -- 394 394 ---------- --------- ------- Write-down of idle property(2) (450) -- (450) ---------- --------- ------- Operating income(3) $ 18,375 $ 7,286 $25,661 ---------- --------- ------- ---------- --------- ------- Operating Data (barrels per day, in thousands) Line 2000 and Line 63 pipeline volume 116.1 Rangeland pipeline system: Sundre - North 20.1 Sundre - South 52.5 Western Corridor system volume 27.0 Salt Lake City Core system volume 119.3 Rocky Mountain Products pipeline(4) 60.2 Frontier pipeline volume 50.0 Three Months Ended December 31, 2004: Segment revenue: Pipeline transportation revenue $ 18,003 $ 12,284 $ (1,771) $28,516 Storage and terminaling revenue 9,954 -- (150) 9,804 Pipeline buy/sell transportation revenue -- 6,978 6,978 Crude oil sales, net of purchases 2,471 -- (120) 2,351 ---------- --------- ------- Net revenue 30,428 19,262 47,649 ---------- --------- ------- Segment expenses: Operating expense 15,000 9,755 (2,041) 22,714 Depreciation and amortization 3,591 2,806 6,397 ---------- --------- ------- Total expenses 18,591 12,561 29,111 ---------- --------- ------- Share of net income of Frontier -- 138 138 ---------- --------- ------- Write-down of idle property(2) (800) -- (800) ---------- --------- ------- Operating income(3) $ 11,037 $ 6,839 $17,876 ---------- --------- ------- ---------- --------- ------- Operating Data (barrels per day, in thousands) Line 2000 and Line 63 pipeline volume 151.7 Rangeland pipeline system: Sundre - North 19.9 Sundre - South 48.8 Western Corridor system volume 21.2 Salt Lake City Core system volume 112.3 Frontier pipeline volume 44.1 (1) Eliminations are required to account for revenue on services provided by one subsidiary to another. (2) Represents a write-down to fair market value of idle property that is expected to be sold. (3) General and administrative expense and certain other items are not allocated to segments. See "Reconciliation of Operating Income by Segment to Condensed Consolidated Statements of Income" included herein. (4) Rocky Mountain Products Pipeline was purchased on September 30, 2005 as part of the acquisition of assets from Valero, L.P. PACIFIC ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND OPERATING HIGHLIGHTS BY SEGMENT Year Ended December 31, 2005 (Unaudited) (In thousands) West Coast Rocky Intersegment Total Operations Mountain and Operations Intrasegment Eliminations(1) ---------- ---------- --------------- --------- Year Ended December 31, 2005: Segment revenue: Pipeline transportation revenue $ 63,006 $ 60,071 $ (6,429) $116,648 Storage and terminaling revenue 52,136 -- (150) 51,986 Pipeline buy/sell transportation revenue -- 35,671 35,671 Crude oil sales, net of purchases 19,809 374 (186) 19,997 --------- --------- -------- Net revenue 134,951 96,116 224,302 --------- --------- -------- Segment expenses: Operating expense 66,237 44,925 (6,765) 104,397 Line 63 oil release costs 2,000 -- 2,000 Depreciation and amortization 15,927 13,479 29,406 --------- --------- -------- Total expenses 84,164 58,404 135,803 --------- --------- -------- Share of net income of Frontier -- 1,757 1,757 --------- --------- -------- Write-down of idle property(2) (450) -- (450) --------- --------- -------- Operating income(3) $ 50,337 $ 39,469 $ 89,806 --------- --------- -------- --------- --------- -------- Operating Data (barrels per day, in thousands) Line 2000 and Line 63 pipeline volume 119.6 Rangeland pipeline system:(4) Sundre - North 21.0 Sundre - South 47.1 Western Corridor system volume 24.7 Salt Lake City Core system volume 119.6 Rocky Mountain Products pipeline(5) 60.2 Frontier pipeline volume 47.3 Year Ended December 31, 2004: Segment revenue: Pipeline transportation revenue $ 67,173 $ 47,131 $ (5,909) $108,395 Storage and terminaling revenue 38,080 -- (503) 37,577 Pipeline buy/sell transportation revenue -- 18,640 18,640 Crude oil sales, net of purchases 16,907 -- (120) 16,787 ---------- --------- -------- Net revenue 122,160 65,771 181,399 ---------- --------- -------- Segment expenses: Operating expense 58,197 33,621 (6,532) 85,286 Depreciation and amortization 14,424 9,749 24,173 ---------- --------- -------- Total expenses 72,621 43,370 109,459 ---------- --------- -------- Share of net income of Frontier -- 1,328 1,328 ---------- --------- -------- Write-down of idle property(2) (800) -- (800) ---------- --------- -------- Operating income(3) $ 48,739 $ 23,729 $ 72,468 ---------- --------- -------- ---------- --------- -------- Operating Data (barrels per day, in thousands) Line 2000 and Line 63 pipeline volume 141.2 Rangeland pipeline system:(4) Sundre - North 21.0 Sundre - South 48.1 Western Corridor system volume 20.2 Salt Lake City Core system volume 115.1 Frontier pipeline volume 47.4 (1) Eliminations are required to account for revenue on services provided by one subsidiary to another. (2) Represents a write-down to fair market value of idle property that is expected to be sold. (3) General and administrative expense and certain other items are not allocated to segments. See "Reconciliation of Operating Income by Segment to Condensed Consolidated Statements of Income" included herein. (4) Rangeland Pipeline System was purchased on May 11, 2004 and the Mid Alberta Pipeline (MAPL) was purchased on June 30, 2004. (5) Rocky Mountain Products Pipeline was purchased on September 30, 2005 as part of the acquisition of assets from Valero, L.P. PACIFIC ENERGY PARTNERS, L.P. (Unaudited) (Amounts in thousands, except per unit amounts) RECONCILIATION OF OPERATING INCOME BY SEGMENT TO CONDENSED CONSOLIDATED STATEMENTS OF INCOME Three Months Ended Year Ended December 31, December 31, ------------------- -------------------- 2005 2004 2005 2004 -------- -------- -------- --------- Operating income by segment: West Coast $ 18,375 $ 11,037 $ 50,337 $ 48,739 Rocky Mountain 7,286 6,839 39,469 23,729 -------- -------- -------- --------- 25,661 17,876 89,806 72,468 General expenses and other income/(expense):(1) General and administrative expense (5,485) (4,148) (18,472) (15,400) Accelerated long-term incentive plan compensation expense(2) -- -- (3,115) -- Transaction costs(3) -- -- (1,807) -- Interest expense (9,041) (5,466) (26,720) (19,209) Write-off of deferred financing cost and interest rate swap termination expense(4) -- -- -- (2,901) Other income (268) 426 1,119 1,032 Income tax (expense) benefit 974 (54) (1,163) (261) -------- -------- -------- --------- Net income $ 11,841 $ 8,634 $ 39,648 $ 35,729 -------- -------- -------- --------- -------- -------- -------- --------- GENERAL PARTNER AND LIMITED PARTNERS ALLOCATION OF NET INCOME Three Months Ended Year Ended December 31, December 31, ------------------- -------------------- 2005 2004 2005 2004 -------- -------- -------- --------- Net income $ 11,841 $ 8,634 $ 39,648 $ 35,729 -------- -------- -------- --------- Transaction costs reimbursed by general partner: Senior notes consent solicitation and other costs -- -- 893 -- Severance costs -- -- 914 -- -------- -------- -------- --------- Total transaction costs reimbursed by general partner -- -- 1,807 -- -------- -------- -------- --------- Income before transaction costs reimbursed by general partner 11,841 8,634 41,455 35,729 General partner's share of income 2% 2% 2% 2% -------- -------- -------- --------- General partner allocated share of net income before transaction costs 237 173 829 715 Transaction costs reimbursed by general partner(3) -- -- (1,807) -- -------- -------- -------- --------- Net income (loss) allocated to general partner $ 237 $ 173 $ (978) $ 715 -------- -------- -------- --------- -------- -------- -------- --------- Income before transaction costs reimbursed by general partner $ 11,841 $ 8,634 $ 41,455 $ 35,729 Limited partners' share of income 98% 98% 98% 98% -------- -------- -------- --------- Limited partners' share of net income $ 11,604 $ 8,461 $ 40,626 $ 35,014 -------- -------- -------- --------- -------- -------- -------- --------- Net income (loss) allocated to general partner $ 237 $ 173 $ (978) $ 715 Net income allocated to limited partners 11,604 8,461 40,626 35,014 -------- -------- -------- --------- Net income $ 11,841 $ 8,634 $ 39,648 $ 35,729 -------- -------- -------- --------- -------- -------- -------- --------- (1) General and administrative expenses, accelerated long-term incentive plan expense, transaction costs, interest expense, write-off of deferred financing costs and interest rate swap termination expense, other income and income tax expense are not allocated among the West Coast and Rocky Mountain business units. (2) On March 3, 2005, in connection with the change in control of the Partnership's general partner, all restricted units outstanding under the Long-Term Incentive Plan became immediately vested pursuant to the terms of the grants. The Partnership recognized accelerated compensation expense of $3.1 million relating to the vesting. (3) Pursuant to an Ancillary Agreement, our general partner reimbursed us $1.8 million for costs incurred in connection with the sale of our general partner. Generally accepted accounting principles require us to record an expense with the reimbursement shown as a partner's capital contribution. (4) In June 2004, in connection with the repayment of our term loan, we had a $2.3 million non-cash write-down of deferred financing costs and incurred a $0.6 million cash expense to terminate related interest rate swaps. PACIFIC ENERGY PARTNERS, L.P. RECONCILIATION OF NET INCOME TO RECURRING NET INCOME(1) (Unaudited) (Amounts in thousands, except per unit amounts) Three Months Ended Year Ended December 31, December 31, ----------------------- ---------------------- 2005 2004 2005 2004 ---------- ---------- ---------- --------- Net income $ 11,841 $ 8,634 $ 39,648 $ 35,729 Add: Line 63 oil release costs(2) -- -- 2,000 -- Add: Accelerated long-term incentive plan compensation expense(3) -- -- 3,115 -- Add: Transaction costs(4) -- -- 1,807 -- Add: Write-off of deferred financing cost and interest rate swap termination expense(5) -- -- -- 2,901 Add: Write-down of idle properties(6) 450 800 450 800 ---------- ---------- ---------- --------- Recurring net income 12,291 9,434 47,020 39,430 Recurring net income for the general partner interest 246 189 940 789 ---------- ---------- ---------- --------- Recurring net income for the limited partner interest $ 12,045 $ 9,245 $ 46,080 $ 38,641 ---------- ---------- ---------- --------- ---------- ---------- ---------- --------- Basic and diluted recurring net income per limited partner unit $ 0.31 $ 0.31 $ 1.42 $ 1.36 ---------- ---------- ---------- --------- ---------- ---------- ---------- --------- (1) Recurring net income is a non-GAAP financial measure. This measure is used to more precisely compare year over year net income by eliminating one-time, non-recurring charges. You should not consider Recurring Net Income as an alternative to net income, income before taxes, cash flow from operations, or any other measure of financial performance presented in accordance with accounting principles generally accepted in the United States. Our Recurring Net Income may not be comparable to similarly titled measures of other entities. (2) On March 23, 2005, there was an oil release of approximately 3,400 barrels in northern Los Angeles County. Although this event involved an outlay of cash, we believe these costs are unusual and are not indicative of the Partnership's recurring earnings. (3) On March 3, 2005, in connection with the change in control of the Partnership's general partner, all restricted units outstanding under the Long-Term Incentive Plan became immediately vested pursuant to the terms of the grants. The Partnership recognized accelerated compensation expense of $3.1 million relating to the vesting. (4) Pursuant to an Ancillary Agreement, our general partner reimbursed us $1.8 million for costs incurred in connection with the sale of our general partner. Generally accepted accounting principles require us to record an expense with the reimbursement shown as a partner's capital contribution. (5) In June 2004, in connection with the repayment of our term loan, we had a $2.3 million non-cash write-down of deferred financing costs and incurred a $0.6 million cash expense to terminate related interest rate swaps. (6) Represents a write-down to fair market value of idle properties that are expected to be sold. PACIFIC ENERGY PARTNERS, L.P. RECONCILIATION OF NET INCOME TO DISTRIBUTABLE CASH FLOW(1) (Unaudited) (Amounts in thousands) Three Months Ended Year Ended December 31, December 31, ----------------------- ---------------------- 2005 2004 2005 2004 ---------- ---------- ---------- --------- Net income $ 11,841 $ 8,634 $ 39,648 $ 35,729 Depreciation and amortization 9,711 6,397 29,406 24,173 Amortization of debt issue costs and accretion of discount on long-term debt 603 441 2,027 1,537 Non-cash employee compensation under long-term incentive plan -- (244) 1,429 857 Write-off of deferred financing costs(2) -- -- -- 2,321 Write-down of idle property(3) 450 800 450 800 Loss on disposal of idle property 220 -- 220 -- Transaction costs(4) -- -- 1,807 -- Deferred income tax expense (benefit) (328) (122) (89) (65) Sustaining capital expenditures (2,997) (493) (6,067) (1,953) ---------- ---------- ---------- --------- Distributable cash flow(5) 19,500 15,413 68,831 63,399 Less net (increase) decrease in operating assets and liabilities (11,916) (1,301) 1,676 (7,973) Less share of income of Frontier (394) (138) (1,757) (1,328) Add net distributions from Frontier (deduct contributions to Frontier) -- -- 1,317 (44) Less non-cash employee compensation under long-term incentive plan added (deducted) above -- 244 (1,429) (857) Employee compensation under long-term incentive plan -- 299 2,886 2,076 Less transaction costs -- -- (1,807) -- Add other non-cash adjustments (58) -- -- -- Add sustaining capital expenditures 2,997 493 6,067 1,953 ---------- ---------- ---------- --------- Net cash provided by operating activities $ 10,129 $ 15,010 $ 75,784 $ 57,226 ---------- ---------- ---------- --------- ---------- ---------- ---------- --------- General partner interest in distributable cash flow $ 390 $ 308 $ 2,049 $ 1,764 Limited partner interest in distributable cash flow 19,110 15,105 66,782 61,635 ---------- ---------- ---------- --------- Total distributable cash flow $ 19,500 $ 15,413 $ 68,831 $ 63,399 ---------- ---------- ---------- --------- ---------- ---------- ---------- --------- (1) Distributable Cash Flow provides additional information for evaluating our ability to make the minimum quarterly distribution and is presented solely as a supplemental measure. You should not consider Distributable Cash Flow as an alternative to net income, income before taxes, cash flow from operations, or any other measure of financial performance presented in accordance with accounting principles generally accepted in the United States. Our Distributable Cash Flow may not be comparable to similarly titled measures of other entities. Additional information regarding distributable cash flow is included in our annual report on Form 10-K for the year ended December 31, 2004. (2) In June 2004, in connection with the repayment of our term loan, we had a $2.3 million non-cash write-down of deferred financing cots and incurred a $0.6 million cash expense to terminate related interest rate swaps. (3) Represents a write-down to fair market value of idle property that is expected to be sold. (4) Pursuant to an Ancillary Agreement, our general partner reimbursed us $1.8 million for costs incurred in connection with the sale of our general partner. Generally accepted accounting principles require us to record an expense with the reimbursement shown as a partner's capital contribution. (5) For the year ended December 31, 2005, distributable cash flow has been reduced by $2.0 of oil release costs and $1.9 million of cash costs associated with the accelerated vesting of units. For year ended December 31, 2004, distributable cash flow has been reduced by $0.6 million cash expense to terminate interest rate swaps. PACIFIC ENERGY PARTNERS, L.P. RECONCILIATION OF NET INCOME GUIDANCE TO EBITDA GUIDANCE(1) (Unaudited) (Amounts in millions) Three Months Ended Year Ended March 31, 2006 December 31, 2006 ---------------------- --------------------- Low High Low High ---------- ----------- ---------- ---------- Net income guidance(2) $ 13.3 $ 15.6 $ 63.4 $ 70.0 Add: Depreciation and amortization 9.5 10.0 40.0 41.0 Add: Interest expense(3) 8.7 10.0 38.0 39.0 Add: Income tax expense(4) -- 0.4 1.0 1.0 --------- ---------- --------- --------- Earnings before interest, tax, depreciation and amortization (EBITDA) $ 31.5 $ 36.0 $ 142.4 $ 151.0 --------- ---------- --------- --------- --------- ---------- --------- --------- (1) The guidance for the three months ending March 31, 2006 and for the twelve months ending December 31, 2006 are based on assumptions and estimates that we believe are reasonable given our assessment of historical trends, business cycles and other information reasonably available. However, our assumptions and future performance are both subject to a wide range of business risks and uncertainties so no assurance can be provided that actual performance will fall within the guidance ranges. Please see "Forward-Looking Statements" above. These risks and uncertainties, as well as other unforeseeable risks and uncertainties, could cause our actual results to differ materially from those in the table. This financial guidance is given as of the date hereof, based on information known to us as of February 1, 2006. We undertake no obligation to publicly update or revise any forward-looking statements. (2) Included in the net income guidance for the year ended December 31, 2006, is forecast general and administrative expense of $20 million to $21 million, including non-cash long-term incentive plan expense of $1.5 million. (3) Included for the year ended December 31, 2006, is non-cash interest expense of $2.4 million. (4) Included for the year ended December 31, 2006, is forecast cash tax expense of $3.5 million and a deferred tax benefit of $2.4 million. *T