**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON,D.C. 20549**

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**FORM 10-Q**

**x**                              QuarterlyReport Pursuant to Section 13 or 15(d) of the Securities Exchange Actof 1934

**Forthe quarterly period ended September 30, 2005**

**OR**

** ̈**                                 TransitionReport Pursuant to Section 13 or 15(d) of the Securities Exchange Actof 1934

**Forthe transition period from              to              **

**CommissionFile Number 1-31345**

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**PACIFIC ENERGY PARTNERS, L.P.**

(Exact name of registrantas specified in its charter)

| **DELAWARE**                                                         | **68-0490580**                        |
|----------------------------------------------------------------------|---------------------------------------|
| (State or other  jurisdiction of incorporation or organization) | (I.R.S. Employer  Identification No.) |

 

**5900 Cherry Avenue**

**Long Beach, CA 90805-4408**

(Address of principalexecutive offices)

**(562) 728-2800**

(Registrant’s telephonenumber, including area code)

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Indicate by check mark whether the registrant: (1) hasfiled all reports required to be filed by Section 13 or 15(d) of theSecurities Exchange Act of 1934 during the preceding 12 months (or forsuch shorter period that the registrant was required to file such reports) and (2) hasbeen subject to such filing requirements for the past90 days. Yes x  No  ̈

Indicate by check mark whether the registrant is anaccelerated filer (as defined in Rule 12b-2 of the ExchangeAct). Yes x  No  ̈

Indicated by check mark whether the registrant is ashell company (as defined in Exchange Act Rule 12b-2). Yes  ̈  No x

There were 31,448,931 ofthe registrant’s Common Units and 7,848,750 of the registrant’s SubordinatedUnits outstanding at September 30, 2005.

 

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**PACIFIC ENERGYPARTNERS, L.P.**

**FORM 10-Q**

**TABLEOF CONTENTS**

|                                        | ** **                                                                                                                                        | **Page** |
|----------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------|----------|
| **PART I. FINANCIAL INFORMATION** |                                                                                                                                              |     |   |
| Item 1.                           | Financial Statements                                                                                                                              |     | 1 |   |
|                                   | Condensed  Consolidated Balance Sheets (Unaudited)—As of September 30, 2005 and  December 31, 2004                                 |     | 1 |   |
|                                   | Condensed  Consolidated Statements of Income (Unaudited)—For the Three and Nine months  Ended September 30, 2005 and 2004               |     | 2 |   |
|                                   | Condensed  Consolidated Statement of Partners’ Capital (Unaudited)—For the Nine months  Ended September 30, 2005                   |     | 3 |   |
|                                   | Condensed  Consolidated Statements of Comprehensive Income (Unaudited)—For the Three and  Nine months Ended September 30, 2005 and 2004 |     | 4 |   |
|                                   | Condensed  Consolidated Statements of Cash Flows (Unaudited)—For the Nine months Ended  September 30, 2005 and 2004                     |     | 5 |   |
|                                   | Notes to Condensed  Consolidated Financial Statements (Unaudited)                                                                                 |     | 6 |   |
| Item 2.                           | Management’s Discussion and  Analysis of Financial Condition and Results of Operations                                                       |     | 27 |   |
| Item 3.                           | Quantitative and Qualitative  Disclosures About Market Risk                                                                                       |     | 47 |   |
| Item 4.                           | Controls and Procedures                                                                                                                           |     | 49 |   |
| **PART II. OTHER INFORMATION**    |                                                                                                                                              |     |
| Item 1.                           | Legal Proceedings                                                                                                                                 |     | 50 |   |
| Item 6.                           | Exhibits                                                                                                                                          |     | 50 |   |
|                                        |                                                                                                                                                   |          |  |  |  |

 

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**PART I. FINANCIAL INFORMATION**

**ITEM1.**                FinancialStatements

**PACIFIC ENERGYPARTNERS, L.P. (Note 1)CONDENSED CONSOLIDATED BALANCE SHEETS(Unaudited)**

| ** **                                                                                                                                  | ** ** | **September 30,**  | ** ** | **December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                                                                                                                  | ** ** | **2005**                | ** ** | **2004**              | ** ** |
| ** **                                                                                                                                  | ** ** | **(in thousands)** | ** ** |
| **ASSETS**                                                                                                                                  |       |                    |       |                  |       |   |   |   |   |
| Current assets:                                                                                                                             |       |                    |       |                  |       |   |   |   |   |
| Cash and cash equivalents                                                                                                                   |       |                    | $          | 25,775                |       |   |   | $ | 23,383 |   |   |
| Crude oil sales receivable                                                                                                                  |       |                    | 98,539     |                  |       |   | 28,609 |   |   |
| Transportation and storage accounts receivable                                                                                              |       |                    | 19,476     |                  |       |   | 20,137 |   |   |
| Canadian goods and services tax receivable                                                                                                  |       |                    | 9,177      |                  |       |   | 7,632 |   |   |
| Insurance proceeds receivable (note 3)                                                                                                      |       |                    | 8,829      |                  |       |   | — |   |   |
| Due from related parties (note 4)                                                                                                           |       |                    | 638        |                  |       |   | — |   |   |
| Crude oil inventory                                                                                                                         |       |                    | 13,919     |                  |       |   | 9,174 |   |   |
| Prepaid expenses                                                                                                                            |       |                    | 7,089      |                  |       |   | 4,159 |   |   |
| Other                                                                                                                                       |       |                    | 3,403      |                  |       |   | 2,451 |   |   |
| Total current assets                                                                                                                        |       |                    | 186,845    |                  |       |   | 95,545 |   |   |
| Property and equipment, net (note 2)                                                                                                        |       |                    | 1,029,619  |                  |       |   | 718,624 |   |   |
| Intangible assets (note 2)                                                                                                                  |       |                    | 217,506    |                  |       |   | 38,026 |   |   |
| Investment in Frontier                                                                                                                      |       |                    | 7,805      |                  |       |   | 7,886 |   |   |
| Other assets, net                                                                                                                           |       |                    | 15,540     |                  |       |   | 9,824 |   |   |
|                                                                                                                                        |       |                    | $          | 1,457,315             |       |   |   | $ | 869,905 |   |   |
| **LIABILITIES  AND PARTNERS’ CAPITAL**                                                                                                 |       |                    |       |                  |       |   |   |   |   |
| Current liabilities:                                                                                                                        |       |                    |       |                  |       |   |   |   |   |
| Accounts payable and accrued liabilities                                                                                                    |       |                    | $          | 46,529                |       |   |   | $ | 14,872 |   |   |
| Accrued crude oil purchases                                                                                                                 |       |                    | 93,013     |                  |       |   | 27,231 |   |   |
| Line 63 oil release reserve (note 3)                                                                                                        |       |                    | 5,411      |                  |       |   | — |   |   |
| Accrued interest                                                                                                                            |       |                    | 5,475      |                  |       |   | 1,124 |   |   |
| Due to related parties (note 4)                                                                                                        |       |                    | —     |                  |       |   | 533 |   |   |
| Derivatives liability—current portion                                                                                                  |       |                    | 1,328      |                  |       |   | 400 |   |   |
| Other                                                                                                                                       |       |                    | 4,452      |                  |       |   | 3,885 |   |   |
| Total current liabilities                                                                                                                   |       |                    | 156,208    |                  |       |   | 48,045 |   |   |
| Senior notes and credit facilities, net (note 5)                                                                                            |       |                    | 539,789    |                  |       |   | 357,163 |   |   |
| Deferred income taxes                                                                                                                       |       |                    | 36,111     |                  |       |   | 34,556 |   |   |
| Environmental liabilities                                                                                                                   |       |                    | 16,125     |                  |       |   | 7,269 |   |   |
| Other liabilities                                                                                                                           |       |                    | 2,331      |                  |       |   | 406 |   |   |
| Total liabilities                                                                                                                           |       |                    | 750,564    |                  |       |   | 447,439 |   |   |
| Commitments and  contingencies (notes 3 and 10)                                                                                             |       |                    |       |                  |       |   |   |   |   |
| Partners’ capital:                                                                                                                     |       |                    |       |                  |       |   |   |   |   |
| Common unitholders (31,448,931 and 19,158,747 units  outstanding at September 30, 2005 and December 31, 2004,  respectively) |       |                    | 651,582    |                  |       |   | 361,427 |   |   |
| Subordinated unitholders (7,848,750 and 10,465,000  units outstanding at September 30, 2005 and December 31, 2004,  respectively) |       |                    | 26,462     |                  |       |   | 41,521 |   |   |
| General Partner interest                                                                                                                    |       |                    | 12,710     |                  |       |   | 6,280 |   |   |
| Undistributed employee long-term incentive  compensation (note 7)                                                                           |       |                    | —     |                  |       |   | 116 |   |   |
| Accumulated other comprehensive income                                                                                                      |       |                    | 15,997     |                  |       |   | 13,122 |   |   |
| Net partners’ capital                                                                                                                  |       |                    | 706,751    |                  |       |   | 422,466 |   |   |
|                                                                                                                                        |       |                    | $          | 1,457,315             |       |   |   | $ | 869,905 |   |   |

 

See accompanying notes to condensed consolidated financial statements.

1

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**PACIFIC ENERGYPARTNERS, L.P. (Note 1)CONDENSED CONSOLIDATED STATEMENTS OF INCOME(Unaudited)**

| ** **                                                                                                                                                                                                     | ** ** | **Three Months Ended  September 30,**                 | ** ** | **Nine Months Ended  September 30,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                                                                                                                                                                     | ** ** | **2005**                                                             | ** ** | **2004**                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                                                                                                                                     | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| Pipeline  transportation revenue                                                                                                                                                                               |       | $                                                                    | 27,283     |                                                | $          | 28,160 |   | $ | 83,067 |   | $ | 79,879 |   |
| Storage and  terminaling revenue                                                                                                                                                                               |       | 9,731                                                                |       | 8,391                                               |       | 30,923 |   | 27,773 |   |
| Pipeline buy/sell  transportation revenue                                                                                                                                                                      |       | 11,683                                                               |       | 7,972                                               |       | 28,905 |   | 11,662 |   |
| Crude oil sales,  net of purchases of $188,901 and $103,192 for the three months ended  September 30, 2005 and 2004 and $425,733 and $278,689 for the nine  months ended September 30, 2005 and 2004 |       | 5,823                                                                |       | 3,568                                               |       | 13,647 |   | 14,436 |   |
| Net revenue                                                                                                                                                                                                    |       | 54,520                                                               |       | 48,091                                              |       | 156,542 |   | 133,750 |   |
| Expenses:                                                                                                                                                                                                      |       |                                                                 |       |                                                |       |   |   |   |   |
| Operating                                                                                                                                                                                                      |       | 25,019                                                               |       | 22,788                                              |       | 72,065 |   | 62,572 |   |
| Line 63 oil release costs (note 3)                                                                                                                                                                             |       | —                                                               |       | —                                              |       | 2,000 |   | — |   |
| General and administrative                                                                                                                                                                                     |       | 4,115                                                                |       | 3,762                                               |       | 12,987 |   | 11,252 |   |
| Accelerated long-term incentive plan compensation  expense (note 7)                                                                                                                                       |       | —                                                               |       | —                                              |       | 3,115 |   | — |   |
| Transaction costs (notes 4 and 8)                                                                                                                                                                              |       | —                                                               |       | —                                              |       | 1,807 |   | — |   |
| Depreciation and amortization                                                                                                                                                                                  |       | 6,560                                                                |       | 6,821                                               |       | 19,695 |   | 17,776 |   |
|                                                                                                                                                                                                           |       | 35,694                                                               |       | 33,371                                              |       | 111,669 |   | 91,600 |   |
| Share of net  income of Frontier                                                                                                                                                                               |       | 516                                                                  |       | 406                                                 |       | 1,363 |   | 1,190 |   |
| Operating income                                                                                                                                                                                               |       | 19,342                                                               |       | 15,126                                              |       | 46,236 |   | 43,340 |   |
| Interest expense                                                                                                                                                                                               |       | (6,237                                                               | )          | (5,234                                              | )          | (17,679 | ) | (13,743 | ) |
| Write-off of  deferred financing cost and interest rate swap termination expense                                                                                                                               |       | —                                                               |       | —                                              |       | — |   | (2,901 | ) |
| Other income                                                                                                                                                                                                   |       | 494                                                                  |       | 219                                                 |       | 1,387 |   | 606 |   |
| Income before  income taxes                                                                                                                                                                                    |       | 13,599                                                               |       | 10,111                                              |       | 29,944 |   | 27,302 |   |
| Income tax expense:                                                                                                                                                                                            |       |                                                                 |       |                                                |       |   |   |   |   |
| Current                                                                                                                                                                                                        |       | (1,411                                                               | )          | (118                                                | )          | (1,898 | ) | (150 | ) |
| Deferred                                                                                                                                                                                                       |       | (22                                                                  | )          | (103                                                | )          | (239 | ) | (57 | ) |
|                                                                                                                                                                                                           |       | (1,433                                                               | )          | (221                                                | )          | (2,137 | ) | (207 | ) |
| Net income                                                                                                                                                                                                     |       | $                                                                    | 12,166     |                                                | $          | 9,890 |   | $ | 27,807 |   | $ | 27,095 |   |
| Net income (loss) for the general partner interest  (note 8)                                                                                                                                                   |       | $                                                                    | 243        |                                                | $          | 198 |   | $ | (1,215 | ) | $ | 542 |   |
| Net income for the limited partner interests                                                                                                                                                                   |       | $                                                                    | 11,923     |                                                | $          | 9,692 |   | $ | 29,022 |   | $ | 26,553 |   |
| Basic net income per limited partner unit                                                                                                                                                                      |       | $                                                                    | 0.39       |                                                | $          | 0.33 |   | $ | 0.97 |   | $ | 0.95 |   |
| Diluted net  income per limited partner unit                                                                                                                                                                   |       | $                                                                    | 0.39       |                                                | $          | 0.33 |   | $ | 0.96 |   | $ | 0.94 |   |
| Weighted average  limited partner units outstanding:                                                                                                                                                           |       |                                                                 |       |                                                |       |   |   |   |   |
| Basic                                                                                                                                                                                                          |       | 30,761                                                               |       | 29,574                                              |       | 30,051 |   | 28,008 |   |
| Diluted                                                                                                                                                                                                        |       | 30,762                                                               |       | 29,682                                              |       | 30,089 |   | 28,125 |   |

 

See accompanying notes to condensed consolidated financial statements.

2

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**PACIFIC ENERGYPARTNERS, L.P. (Note 1)CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL(Unaudited)**

| ** **                                                                      | ** ** | **Limited Partner Units** | ** ** | **Limited Partner Amounts** | ** ** | **General  Partner** | ** ** | **Undistributed  Employee  Long-Term  Incentive** | ** ** | **Accumulated  Other  Comprehensive** | ** ** | ** **       | ** ** |
|---------------------------------------------------------------------------------|------------|-------------------------------------|------------|---------------------------------------|------------|----------------------|------------|---------------------------------------------------|------------|---------------------------------------|------------|------------------|------------|
| ** **                                                                      | ** ** | **Common**                          | ** ** | **Subordinated**                      | ** ** | **Common**           | ** ** | **Subordinated**                                  | ** ** | **Interest**                          | ** ** | **Compensation** | ** ** | **Income** | ** ** | **Total** | ** ** |
| ** **                                                                      | ** ** | **(in thousands)**             | ** ** |
| Balance, December 31, 2004                                                 |       |                                | 19,159     |                                  |       |                 | 10,465     |                                              |       |                                  | $          | 361,427          |       |   |   | $ | 41,521 |   |   |   | $ | 6,280 |   |   |   | $ | 116 |   |   |   | $ | 13,122 |   |   | $ | 422,466 |   |
| Net income (note 8)                                                             |       |                                | —     |                                  |       |                 | —     |                                              |       |                                  | 19,741     |             |       |   | 9,281 |   |   |   | (1,215 | ) |   |   | — |   |   |   | — |   |   | 27,807 |   |
| Distribution to partners                                                        |       |                                | —     |                                  |       |                 | —     |                                              |       |                                  | (29,341    | )                |       |   | (15,959 | ) |   |   | (924 | ) |   |   | — |   |   |   | — |   |   | (46,224 | ) |
| Issuance of common units, net of fees and offering  expenses (note 6) |       |                                | 9,533      |                                  |       |                 | —     |                                              |       |                                  | 289,122    |             |       |   | — |   |   |   | 6,116 |   |   |   | — |   |   |   | — |   |   | 295,238 |   |
| General partner contribution (note 8)                                           |       |                                | —     |                                  |       |                 | —     |                                              |       |                                  | —     |             |       |   | — |   |   |   | 2,407 |   |   |   | — |   |   |   | — |   |   | 2,407 |   |
| Employee compensation under long-term incentive  plan                      |       |                                | —     |                                  |       |                 | —     |                                              |       |                                  | —     |             |       |   | — |   |   |   | — |   |   |   | 2,886 |   |   |   | — |   |   | 2,886 |   |
| Issuance of common units pursuant to long-term  incentive plan (note 7)    |       |                                | 99         |                                  |       |                 | —     |                                              |       |                                  | 1,545      |             |       |   | — |   |   |   | 31 |   |   |   | (3,002 | ) |   |   | — |   |   | (1,426 | ) |
| Exercise of unit options pursuant to long-term  incentive plan                  |       |                                | 42         |                                  |       |                 | —     |                                              |       |                                  | 707        |             |       |   | — |   |   |   | 15 |   |   |   | — |   |   |   | — |   |   | 722 |   |
| Foreign currency translation adjustment                                         |       |                                | —     |                                  |       |                 | —     |                                              |       |                                  | —     |             |       |   | — |   |   |   | — |   |   |   | — |   |   |   | 3,377 |   |   | 3,377 |   |
| Change in fair value of hedging  derivatives                                    |       |                                | —     |                                  |       |                 | —     |                                              |       |                                  | —     |             |       |   | — |   |   |   | — |   |   |   | — |   |   |   | (502 | ) |   | (502 | ) |
| Conversion of subordinated units to common units                                |       |                                | 2,616      |                                  |       |                 | (2,616     | )                                                 |       |                                  | 8,381      |             |       |   | (8,381 | ) |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |
| Balance,  September 30, 2005                                               |       |                                | 31,449     |                                  |       |                 | 7,849      |                                              |       |                                  | $          | 651,582          |       |   |   | $ | 26,462 |   |   |   | $ | 12,710 |   |   |   | $ | — |   |   |   | $ | 15,997 |   |   | $ | 706,751 |   |

 

See accompanying notes to condensed consolidated financial statements.

3

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**PACIFIC ENERGYPARTNERS, L.P. (Note 1)CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVEINCOME(Unaudited)**

| ** **                                         | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|----------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                         | ** ** | **2005**                                             | ** ** | **2004**                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                         | ** ** | **(in thousands)**                              | ** ** |
| Net income                                         |       | $                                                    | 12,166     |                                                | $          | 9,890 |   | $ | 27,807 |   | $ | 27,095 |   |
| Change in fair  value of hedging derivatives       |       | 303                                                  |       | (1,107                                              | )          | (502 | ) | 3,797 |   |
| Change in foreign  currency translation adjustment |       | 5,678                                                |       | 5,313                                               |       | 3,377 |   | 7,742 |   |
| Comprehensive income                               |       | $                                                    | 18,147     |                                                | $          | 14,096 |   | $ | 30,682 |   | $ | 38,634 |   |

 

See accompanying notes to condensed consolidated financial statements.

4

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**PACIFIC ENERGYPARTNERS, L.P. (Note 1)CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS(Unaudited)**

| ** **                                                                         | ** ** | **Nine Months Ended  September 30,** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                                         | ** ** | **2005**                                            | ** ** | **2004** | ** ** |
| ** **                                                                         | ** ** | **(in thousands)**                             | ** ** |
| CASH FLOWS FROM OPERATING  ACTIVITIES                                              |       |                                                |       |   |   |
| Net income                                                                         |       | $                                                   | 27,807     |   | $ | 27,095 |   |
| Adjustments  to reconcile net income to net cash provided by operating activities: |       |                                                |       |   |   |
| Depreciation and amortization                                                      |       | 19,695                                              |       | 17,776 |   |
| Amortization of debt issue costs and debt discount  accretion                      |       | 1,424                                               |       | 1,100 |   |
| Write-off of deferred financing costs                                              |       | —                                              |       | 2,321 |   |
| Non-cash employee compensation under long-term  incentive plan                     |       | 2,886                                               |       | 1,777 |   |
| Deferred tax expense                                                               |       | 239                                                 |       | 57 |   |
| Share of net income of Frontier                                                    |       | (1,363                                              | )          | (1,190 | ) |
| Other non-cash adjustments                                                         |       | 58                                                  |       | — |   |
| Distributions from Frontier, net                                                   |       | 1,317                                               |       | (44 | ) |
| Net changes  in operating assets and liabilities:                                  |       |                                                |       |   |   |
| Crude oil sales receivable                                                         |       | (68,206                                             | )          | (1,704 | ) |
| Transportation and storage accounts receivable                                     |       | 909                                                 |       | (3,318 | ) |
| Insurance proceeds receivable                                                      |       | (8,829                                              | )          | — |   |
| Other current assets and liabilities                                               |       | (6,499                                              | )          | (13,628 | ) |
| Accounts payable and other accrued liabilities                                     |       | 27,354                                              |       | 11,537 |   |
| Accrued crude oil purchases                                                        |       | 64,917                                              |       | 841 |   |
| Line 63 oil release reserve                                                        |       | 5,411                                               |       | — |   |
| Other non-current assets and liabilities                                           |       | (1,465                                              | )          | (400 | ) |
| NET CASH PROVIDED BY OPERATING ACTIVITIES                                          |       | 65,655                                              |       | 42,220 |   |
| CASH FLOWS FROM  INVESTING ACTIVITIES                                              |       |                                                |       |   |   |
| Acquisitions                                                                       |       | (461,165                                            | )          | (139,000 | ) |
| Additions to property and equipment                                                |       | (27,265                                             | )          | (11,522 | ) |
| Other                                                                              |       | —                                              |       | (621 | ) |
| NET CASH USED IN INVESTING ACTIVITIES                                              |       | (488,430                                            | )          | (151,143 | ) |
| CASH FLOWS FROM  FINANCING ACTIVITIES                                              |       |                                                |       |   |   |
| Issuance of common units, net of fees and offering  expenses                       |       | 289,122                                             |       | 125,881 |   |
| Capital contributions from the general partner                                     |       | 8,569                                               |       | 2,708 |   |
| Net proceeds from senior notes offering                                            |       | 170,997                                             |       | 241,086 |   |
| Repayment of term loan                                                             |       | —                                              |       | (225,000 | ) |
| Proceeds from credit facilities                                                    |       | 203,291                                             |       | 157,924 |   |
| Repayment of credit facilities                                                     |       | (195,661                                            | )          | (145,453 | ) |
| Deferred financing costs                                                           |       | (4,676                                              | )          | (1,388 | ) |
| Distributions to partners                                                          |       | (46,224                                             | )          | (41,800 | ) |
| Issuance of common units pursuant to exercise of unit  options                     |       | 707                                                 |       | — |   |
| Related parties                                                                    |       | (1,171                                              | )          | (206 | ) |
| NET CASH PROVIDED BY FINANCING ACTIVITIES                                          |       | 424,954                                             |       | 113,752 |   |
| Effect of translation adjustment on cash                                           |       | 213                                                 |       | — |   |
| NET INCREASE IN CASH AND CASH EQUIVALENTS                                          |       | 2,392                                               |       | 4,829 |   |
| CASH AND CASH EQUIVALENTS, beginning of reporting  period                          |       | 23,383                                              |       | 9,699 |   |
| CASH AND CASH  EQUIVALENTS, end of reporting period                                |       | $                                                   | 25,775     |   | $ | 14,528 |   |

 

See accompanying notes to condensed consolidated financial statements.

5

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**PACIFICENERGY PARTNERS, L.P.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTSSeptember 30, 2005(Unaudited)**

**1.**   SUMMARYOF SIGNIFICANT ACCOUNTING POLICIES

**Basis ofPresentation**

Pacific Energy Partners, L.P. and its subsidiaries(the “Partnership”), was, during the period of this report, engaged principallyin the business of gathering, transporting, storing and distributing crude oiland related products in California and the Rocky Mountain region, whichincludes Alberta, Canada. The Partnership generated revenue primarily bycharging tariff rates for transporting crude oil and related products on itspipelines and by leasing storage capacity. The Partnership also buys and sellscrude oil, activities that are complementary to the Partnership’s pipeline transportationbusiness. During the period covered by this report, the Partnership operatedprimarily in California, Colorado, Montana, Wyoming and Utah in the UnitedStates, and in Alberta, Canada. On September 30, 2005, the Partnership,through two of its wholly owned subsidiaries, acquired certain refined productsand crude oil terminal assets in the San Francisco, California andPhiladelphia, Pennsylvania areas, and a refined products pipeline and terminalassets in the U.S. Rocky Mountains. See also “Note 2—Acquisitions”.

The Partnership conducts its business through twobusiness segments: the West Coast Business Unit and the Rocky Mountain BusinessUnit.

The Partnership is managed by its general partner,Pacific Energy GP, LP, a Delaware limited partnership (the “GeneralPartner”), which, prior to its conversion to a limited partnership on March 3,2005, was Pacific Energy GP, Inc., a corporation owned 100% by asubsidiary of The Anschutz Corporation (“TAC”). On March 3, 2005, TAC soldall of its interest in Pacific Energy GP, Inc. to LB Pacific, LP (“LBP”),which was formed by the Lehman Brothers Merchant Banking Group (“LBMB”) inconnection with the purchase (see “Note 4—Related Party Transactions”). PacificEnergy GP, LP is managed by its general partner, Pacific Energy Management LLC,a Delaware limited liability company, thus the officers and Board of Directorsof PEM manages the business affairs of the Partnership and its General Partner.

The unaudited condensed consolidated financialstatements have been prepared in accordance with accounting principlesgenerally accepted in the United States of America for interim financialreporting and with Securities and Exchange Commission (“SEC”) regulations.Accordingly, these statements have been condensed and do not include all of theinformation and footnotes required for complete financial statements. Thesestatements involve the use of estimates and judgments where appropriate. In theopinion of management, all adjustments, consisting of normal recurring accrualsconsidered necessary for a fair presentation, have been included. The resultsof operations for the three and nine months ended September 30, 2005 arenot necessarily indicative of the results of operations for the full year. Allsignificant intercompany balances and transactions have been eliminated duringthe consolidation process.

The condensed consolidated financial statementsinclude the ownership and results of operations of the Rangeland system,including the Mid-Alberta Pipeline (“MAPL”), since the acquisition of thoseassets on May 11, 2004 and June 30, 2004, respectively.

These financial statementsshould be read in conjunction with the Partnership’s audited consolidatedfinancial statements and notes thereto included in the Partnership’s annualreport on Form 10-K for the 

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yearended December 31, 2004. Certain prioryear balances in the accompanying condensed consolidated financial statementshave been reclassified to conform to the current year presentation.

**Income Taxes**

The Partnership and its U.S. and Canadian subsidiariesare not taxable entities in the U.S. and are not subject to U.S. federal orstate income taxes, as the tax effect of operations is passed through to itsunitholders. The Partnership’s Canadian subsidiaries are taxable entities inCanada and are subject to Canadian federal and provincial income taxes andother Canadian income taxes. In addition, monies repatriated by the Partnershipfrom Canada into the U.S. may subject the Partnership to withholding taxes.

Income taxes are accountedfor under the asset and liability method. Under this method, deferred taxassets and liabilities are recognized for the future tax consequencesattributable to differences between the financial statement carrying amounts ofexisting assets and liabilities and their respective tax bases, and operatingloss and tax credit carryforwards. Deferred tax assets and liabilities aremeasured using enacted tax rates expected to apply to taxable income in theyears in which those temporary differences are expected to be recovered orsettled. The effect on deferred tax assets and liabilities of a change in taxrates is recognized in operations in the period that includes the enactmentdate. The Partnership intends to repatriate its Canadian subsidiaries’ earningsin the future and accordingly has recorded a provision for Canadian withholdingtaxes.

**Net Income per Unit**

Basic net income per limited partner unit isdetermined by dividing net income after deducting the amount allocated to thegeneral partner interest, by the weighted average number of outstanding limitedpartner units.

Dilutednet income per limited partner unit is calculated in the same manner as basicnet income per limited partner unit above, except that the weighted averagenumber of outstanding limited partner units is increased to include thedilutive effect of outstanding options and restricted units by application ofthe treasury stock method. Following is a reconciliation of the basic weightedaverage outstanding limited partner units to diluted weighted average limitedpartner units.

| ** **                                      | ** ** | **Three Months Ended  September 30,**     | ** ** | **Nine Months Ended   September 30,** | ** ** |
|-------------------------------------------------|------------|----------------------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                      | ** ** | **    2005    ** | ** ** | **    2004    **  | ** ** | **    2005    ** | ** ** | **    2004    ** | ** ** |
| ** **                                      | ** ** | **(in thousands)**                                  | ** ** |
| Basic weighted  average limited partner units   |       |                                                     | 30,761     |                                                      |       |   | 29,574 |   |   |   | 30,051 |   |   |   | 28,008 |   |   |
| Effect of  restricted units                     |       |                                                     | —     |                                                      |       |   | 93 |   |   |   | 25 |   |   |   | 102 |   |   |
| Effect of options                               |       |                                                     | 1          |                                                      |       |   | 15 |   |   |   | 13 |   |   |   | 15 |   |   |
| Diluted weighted average  limited partner units |       |                                                     | 30,762     |                                                      |       |   | 29,682 |   |   |   | 30,089 |   |   |   | 28,125 |   |   |

 

**Allocation of NetIncome**

Net income is allocated tothe Partnership’s general partner and limited partners based on theirrespective interest in the Partnership. The Partnership’s general partner isalso directly charged with specific costs that it assumed in connection withits acquisition by LBP and for which neither the Partnership nor the limitedpartners are responsible (see “Note 8—Allocation of Net Income”).

**New AccountingPronouncements**

In December 2004, the Financial AccountingStandards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123(revised December 2004), *Share-Based Payment*(“SFAS123R”). This Statement is a revision of SFAS No. 123. SFAS 123Restablishes standards for the accounting of 

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transactions in which anentity exchanges its equity instruments for goods or services. SFAS 123R iseffective for the Partnership as of the beginning of the first annual reportingperiod that begins after June 15, 2005. The Partnership has not yetdetermined the impact of the adoption of SFAS 123R on the Partnership’sconsolidated financial statements.

In December 2004, the FASB issued Statement ofFinancial Accounting Standards No. 153, *Exchanges ofNonmonetary Assets* (“SFAS 153”). SFAS 153 addresses the measurementof exchanges of certain nonmonetary assets (except for certain exchanges ofproducts or property held for sale in the ordinary course of business). Itamends APB Opinion No. 29, *Accounting for NonmonetaryExchanges,* and requires that nonmonetary exchanges be accounted forat the fair value of the assets exchanged, with gains or losses beingrecognized, if the fair value is determinable within reasonable limits and thetransaction has commercial substance. The Statement is effective for fiscalperiods beginning after June 15, 2005. The Partnership does not expect theadoption of SFAS 153 to have a material impact on its financial statements.

On March 30, 2005 the FASB issued FASBInterpretation No. 47, *Accounting for ConditionalAsset Retirement Obligations*(“FIN 47”), to clarify the term*conditional asset retirement obligation* as that term isused in FASB Statement No. 143, *Accounting for AssetRetirement Obligations.* The Interpretation also clarifies when anentity has sufficient information to reasonably estimate the fair value of anasset retirement obligation. FIN 47 is effective for the Partnership no laterthan the end of fiscal years ending after December 15, 2005. ThePartnership is in the process of determining the impact of FIN 47 on itsfinancial statements.

In May 2005,the FASB issued Statement of Financial Accounting Standards No. 154, *Accounting Changes and Error Corrections* (“SFAS 154”). SFAS154 replaces APB No. 20, *Accounting Changes*,and FASB Statement No. 3, *Reporting Changes inInterim Financial Statements.* The Statement changes the accountingfor, and reporting of, a change in accounting principle. SFAS 154 requiresretrospective application to prior period’s financial statements of voluntarychanges in accounting principle and changes required by new accountingstandards when the standard does not include specific transition provisions,unless it is impracticable to do so. SFAS 154 is effective for accountingchanges and corrections of errors in fiscal years beginning after December 15,2005. If required, the Partnership will apply the provisions of SFAS 154 infuture periods.

In September 2005, the Emerging Issues Task Force(“EITF”) issued Issue No. 04-13 (“EITF 04-13”), *Accounting for Purchases and Sales of Inventory with the SameCounterparty*. The issues addressed by the EITF are (i) thecircumstances under which two or more exchange transactions involving inventorywith the same counterparty should be viewed as a single exchange transactionfor the purposes of evaluating the effect of APB No. 29; and (ii) whetherthere are circumstances under which nonmonetary exchanges of inventory withinthe same line of business should be recognized at fair value. EITF 04-13is effective for new arrangements entered into in the reporting periodsbeginning after March 15, 2006, and to all inventory transactions that arecompleted after December 15, 2006, for arrangements entered into prior to March 15,2006. The Partnership is in the process of determining the impact of EITF 04-13on its financial statements, but does not expect it to have a material impacton its financial statements.

**2.   ACQUISITIONS**

***Acquisition OfAssets From Valero, L.P.***

On September 30, 2005, the Partnership completedits purchase of certain terminal and pipeline assets (the “Valero Acquisition”)from various subsidiaries of Valero, L.P. (the “Sellers”) for an aggregatepurchase price of $455.0 million, plus approximately $12.0 million for theassumption of certain legal, environmental and operating liabilities and $3.4million for closing costs. Valero, L.P. was required to divest these assetspursuant to an order from the Federal Trade Commission in connection with its 

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acquisition of the Kanebgroup of companies. The purchased assets consist of (i) the Martinezterminal and Richmond terminal in the San Francisco, California area, (ii) theNorth Philadelphia and South Philadelphia terminals and the Paulsboro, NewJersey terminal in the Philadelphia, Pennsylvania area, and (iii) a 550-milerefined products pipeline with four terminals in the U.S. Rocky Mountains.

The Martinez and Richmond terminals currently have 4.1million barrels of combined storage capacity. The terminals handle refinedproducts, blend stocks and crude oil, and are connected to a network of ownedand third-party pipelines that carry crude oil and light products to and fromarea refineries. These terminals also receive and deliver crude oil and lightproducts by marine vessel or barge. The Richmond terminal has a rail spur fordelivery and receipt of light products and a truck rack for product delivery.

The North Philadelphia, the South Philadelphia and thePaulsboro, New Jersey terminals handle refined products and have a combinedstorage capacity of 3.1 million barrels. The terminals receive product viaconnections to third party pipelines and have truck racks for deliveries. TheNorth Philadelphia and Paulsboro terminals can also deliver and receiveproducts by marine vessel or barge.

The 550-mile refined products pipeline system,known as the West Pipeline System, consists of 550 miles of pipeline extendingfrom Casper, Wyoming east to Rapid City, South Dakota and south to ColoradoSprings, Colorado. There are products terminals at Rapid City, South Dakota,Cheyenne, Wyoming and Denver and Colorado Springs, Colorado with a combinedstorage capacity of 1.7 million barrels. The West Pipeline System has varioussegments with different receipt and delivery points.

The majority of the West Pipeline System wasconstructed in 1948, with extensions to Rapid City, South Dakota and Fountain,Colorado, added in the 1960’s.****TheSouth Philadelphia Terminal was constructed in 1938, the Richmond and Paulsboroterminals were constructed in 1953, and the Martinez and North Philadelphiaterminals were constructed in 1973.****Additionaltankage has been constructed and pipeline system and terminal improvements haveoccurred over the years since their initial startup.

The Partnership intends to fully integrate theoperations, maintenance, marketing and business development of the WestPipeline System with its existing pipeline activities in the Rocky MountainBusiness Unit. It intends to similarly integrate the San Francisco areaterminals and Philadelphia area terminals with its existing pipeline andterminal activities in its West Coast Business Unit.

The Partnership did not acquire accounting software orhardware with the acquired assets. The Partnership intends to develop oracquire software associated with the complex task of volumetric and revenueaccounting for the acquired assets, and will use its existing financialaccounting software for other accounting functions. In addition, thePartnership is not acquiring the pipeline control center or the software andother operating systems required for the West Pipeline System, and will developand install new operating systems that will be operated out of its Long Beachpipeline control center. The Seller has agreed to provide all of theseaccounting, control center and operating services to the Partnership on atransition basis.

The acquired assets comprise only a portion of thetotal pipeline and terminal assets owned and operated by the Sellers in NorthAmerica. The Sellers have other substantial pipeline and terminal assets thatthe Partnership did not acquire that are, or have been, operated and managed bythe Seller’s existing management team and operating and marketing staff. Theacquired assets have not been operated historically as a separate division orsubsidiary. The Sellers, and prior to its merger with Valero, L.P., KanebPipeline Partners, L.P. (“Kaneb”), operated these assets as part of its moreextensive transportation and terminalling and refined products operations. As aresult, neither the Sellers nor Kaneb maintained complete and separatefinancial statements for these assets as an independent business unit. ThePartnership intends to make significant changes to the assets in the future,which may result in significant operating differences and revenues generated. Additionally,differences in the Partnership’s operating and 

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marketing approach mayresult in it obtaining different productivity levels, results of operations andrevenues than those historically achieved by the Sellers and Kaneb.

Prior to closing the acquisition, the Partnership,pursuant to its agreement with the Sellers, made conditional offers ofemployment to the Sellers’ employees directly involved in the operation of theacquired assets. The Partnership hired 76 of these employees, including certainfield level managerial and supervisory employees, operators, technicians, andengineers/project coordinators. The Partnership intends to hire additionalaccounting, environmental, engineering, pipeline controllers and technicalstaff to support the acquired assets.

The acquisition will be accounted for as anacquisition of assets, and not as an acquisition of a continuing businessoperation.

The Valero Acquisition was consummated effective at11:59 p.m. on September 30, 2005 and no amount was earned andincluded in the statements of income for the three and nine months ended September 30,2005. The Partnership has engaged an independent appraiser to complete anappraisal of the fair values of the acquired assets, and is completing itsreview and determination of the fair values of the assets acquired andliabilities assumed. Accordingly, the allocation of the purchase price issubject to revision. Based upon the preliminary estimates, the purchase priceis being allocated to land and related improvements, depreciable pipelines andrelated equipment, storage tanks and related equipment, truck racks, rights ofway, amortizable intangible assets and other properties. The Partnershipanticipates depreciating the pipeline and tankage over forty years, otherproperty and equipment over three to twenty years, and amortizable intangibleassets over their estimated lives of up to 40 years. The Partnership is alsocompleting its assessment of the $12.0 million of assumed liabilities, andaccordingly its initial estimate is subject to revision, including theliability associated with one legal action pending against one of the Sellersthat the Partnership agreed to assume (See “Note 10—Contingencies”).

The Valero Acquisition wasfunded through a combination of the proceeds from a private placement of 4.3million common units, a public equity offering of 5.2 million common units, aprivate placement of $175 million of senior unsecured notes, and borrowingsunder the Partnership’s new revolving credit facility (See “Note 5—Long-termDebt” and “Note 6—Partner’s Capital” for further discussion on these financingarrangements).

***Purchase Of Crude Oil and Contracts***

On July 1, 2005,Pacific Marketing and Transportation LLC, a wholly owned subsidiary of thePartnership, purchased certain crude oil contracts and crude oil inventoriesfor approximately $3.8 million plus contingent payments over the next three andone half years based on specified performance criteria.

**3.   LINE 63 OIL RELEASE RESERVE**

On March 23, 2005, a release of approximately3,400 barrels of crude oil occurred on Line 63 when it was severed as a resultof a landslide induced by heavy rainfall in the Pyramid Lake area of LosAngeles County. Over the period March 2005 through March 2006, thePartnership expects to incur an estimated total of $19.5 million for oilcontainment and clean-up of the impacted areas, future monitoring costs,potential third-party claims and penalties, and other costs, excluding pipelinerepair costs. As of September 30, 2005, the Partnership had incurredapproximately $14.1 million of the total expected costs related to the oilrelease for work performed through that date. Additionally, the Partnershipexpensed $0.7 million for the repair of Line 63 and expects to incur $1.7million of Line 63 capital improvements of which $0.8 million has been incurredthrough September 30, 2005.

The Partnership has a pollution liability insurancepolicy with a $2.0 million deductible that covers containment and clean-upcosts, third-party claims and penalties. The insurance carrier has, subject tothe 

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terms of the insurancepolicy, acknowledged coverage of the incident and is processing and payinginvoices related to the clean-up. The Partnership believes that, subject to the$2.0 million deductible, it will be entitled to recover substantially all ofits clean-up costs and any third-party claims associated with the release. ThePartnership’s insurance coverage will not cover the cost to repair the pipeline.As of September 30, 2005, the Partnership has recovered $8.7 million frominsurance and recorded a receivable of $8.8 million for insurance recoveries itdeems probable.

The Partnership recorded $2.0 million in net costs in “Line63 oil release costs” in the accompanying condensed consolidated financialstatements for the nine months ended September 30, 2005. The $2.0 millionnet oil release costs consist of the $19.5 million of accrued costs relating tothe release, net of insurance recovery of $8.7 million and accrued insurancereceipts of $8.8 million.

The foregoing estimatesare based on facts known at the time of estimation and the Partnership’sassessment of the ultimate outcome. Among the many uncertainties that impactthe estimates are the necessary regulatory approvals for, and potentialmodification of, remediation plans, the ongoing assessment of the impact ofsoil and water contamination, changes in costs associated with environmentalremediation services and equipment, and the possibility of third-party legalclaims giving rise to additional expenses. Therefore, no assurance can be madethat costs incurred in excess of this provision, if any, would not have amaterial adverse effect on the Partnership’s financial condition, results ofoperations, or cash flows, though the Partnership believes that most, if notall, of any such excess cost, to the extent attributable to clean-up andthird-party claims, would be recoverable through insurance. As new informationbecomes available in future periods, the Partnership may change its provisionand recovery estimates.

**4.   RELATED PARTY TRANSACTIONS**

**Lehman Brothers, Inc.**

In connection with thepurchase and the associated financing of the Valero Acquisition including theprivate equity offering, public equity offering, debt offering and new creditfacility, Lehman Brothers, Inc. and its affiliates provided advisory andunderwriting services to the Partnership. Additionally, an affiliate of LehmanBrothers, Inc. is a participant in the syndicate that provided thePartnership’s new senior secured credit facility. These agreements with LehmanBrothers, Inc. were reviewed and approved by the Conflicts Committee ofthe Board of Directors and the fees charged were customary for the types ofservices provided. For the three and nine months ended September 30, 2005,the Partnership incurred $9.8 million in fees with Lehman Brothers, Inc.and its affiliates, a portion of which was paid to non-affiliated financialinstitutions in the syndication of the New Credit Facility and in the publicoffering of equity.

**Sale of TheAnschutz Corporation’s Interest in the Partnership**

On March 3, 2005, TAC sold all of its interest inPacific Energy GP, Inc. to LBP, which was formed by LBMB in connectionwith the purchase. The acquisition by LBP (the “LB Acquisition”) included the100% ownership interest in Pacific Energy GP, Inc., which owned (i) the2% general partner interest in the Partnership and the incentive distributionrights, and (ii) 10,465,000 subordinated units of the Partnership whichrepresented a 34.6% limited partner interest in the Partnership. Immediatelyprior to the closing of the LB Acquisition, Pacific Energy GP, Inc. wasconverted to Pacific Energy GP, LLC, a Delaware limited liability company; andimmediately after the closing of the LB Acquisition, Pacific Energy GP, LLC wasconverted to Pacific Energy GP, LP (the “General Partner”). Immediatelyfollowing the consummation of the LB Acquisition, the General Partnerdistributed the 10,465,000 subordinated units of the Partnership to LBP.

In connection with the conversion of the Partnership’sGeneral Partner to a limited partnership, the General Partner ceased to have aboard of directors, and is now managed by its general partner, Pacific 

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Energy Management LLC, aDelaware limited liability company (“PEM” or the “Managing General Partner”),which is 100% owned by LBP. PEM has a board of directors (the “Board ofDirectors” or “Board”) that manages the business and affairs of PEM and, thus,indirectly manages the business and affairs of the General Partner and thePartnership. All of the officers and employees of Pacific Energy GP, Inc.were transferred to fill the same positions with PEM, and the PEM Boardestablished the same committees as had been maintained by Pacific Energy GP, Inc.prior to the LB Acquisition. PEM also adopted Pacific Energy GP, Inc.’sgovernance guidelines and its compensation structure and employee benefitsplans and policies.

Additionally, on March 21,2005, an affiliate of First Reserve Corporation (“First Reserve”) acquired fromLBMB a 30% partnership interest in LBP. LBMB and its affiliates continue to owna 70% partnership interest in LBP.

**Cost Reimbursements**

***Managing GeneralPartner:***   The Partnership’s Managing GeneralPartner employs all U.S.-based employees. All employee expenses incurred by theManaging General Partner on behalf of the Partnership are charged back to thePartnership.

***Special Agreement:***   OnMarch 3, 2005, Douglas L. Polson, previously the Chairman of the Board ofDirectors of Pacific Energy GP, Inc., entered into a Special Agreement anda Consulting Agreement with PEM. In accordance with the Special Agreement, Mr. Polsonresigned as Chairman of the Board of Directors of Pacific Energy GP, Inc.effective March 3, 2005. Mr. Polson was paid approximately $0.9million, representing accrued salary through March 3, 2005, accrued butunused vacation and payment in satisfaction of other obligations under hisemployment agreement. The severance portion of this payment was recorded as anexpense in “Transaction costs” in the accompanying condensed consolidatedincome statements (see “Note 8—Allocation of Net Income”). LBP reimbursed thisamount, which was recorded as a partner’s capital contribution. Pursuant to theConsulting Agreement, Mr. Polson has agreed to perform advisory servicesto PEM from time to time as shall be mutually agreed between Mr. Polsonand the Chief Executive Officer of PEM. In consideration for Mr. Polson’s servicesunder the Consulting Agreement, which has a one-year term, Mr. Polson willreceive a monthly consulting fee of $12,500 and reimbursement of all reasonablebusiness expenses incurred or paid by Mr. Polson in the course ofperforming his duties thereunder.

***LBP and TAC:***   LBPand TAC reimbursed the Partnership for certain other costs relating to the LBAcquisition. These included $1.2 million for the Consent Solicitation (asdefined and further described in “Note 5—Long-Term Debt”, below) and $0.3million for legal and other expenses (also see “Note 8—Allocation of Net Income”).

**Other Related PartyTransactions**

***Revenue fromRelated Parties:***   Rocky Mountain PipelineSystem LLC (“RMPS”), a subsidiary of the Partnership, receives an operating feeand a management fee from Frontier Pipeline Company (“Frontier”) in connectionwith time spent by RMPS management and for other services related to Frontier’spipeline’s activities. The Partnership owns a 22.2% interest in Frontier, whichis not consolidated in the Partnership’s financial statements. RMPS received$0.2 million and $0.3 million for each of the three months ended September 30,2005 and 2004 and $0.6 million and $0.5 million for each of the nine monthsended September 30, 2005 and 2004, respectively.

***Due from (to) Related Parties:***   Duefrom related parties, which includes payroll related items, consists of $0.6million due from PEM and $0.5 million due to Pacific Energy GP, LP at September 30,2005 and December 31, 2004, respectively.

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**5.   LONG-TERM DEBT**

ThePartnership’s long-term debt obligations are shown below:

| ** **                                                                                                                                                                 | ** ** | **September 30,  2005** | ** ** | **December 31,  2004** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                                                                                 | ** ** | **(in thousands)**      | ** ** |
| $400 million  senior secured revolving credit facility, bearing interest at 6.3% on  September 30, 2005, due September 30, 2010                                  |       |                         | $          | 114,160                     |       |   |   | $ | — |   |   |
| Senior secured  U.S. revolving credit facility, repaid and terminated on September 30,  2005                                                                          |       |                         | —     |                        |       |   | 51,000 |   |   |
| Senior secured  Canadian revolving credit facility repaid and terminated on  September 30, 2005                                                                       |       |                         | —     |                        |       |   | 54,005 |   |   |
| 71¤8% senior  notes, due June 2014, net of unamortized discount of $3,965 and $4,202  and including fair value increases of $1,445 and $2,693, respectively |       |                         | 247,480    |                        |       |   | 248,491 |   |   |
| 61¤4% senior notes, due September 2015,  net of unamortized discount of $797                                                                                |       |                         | 174,203    |                        |       |   | — |   |   |
| Future payment  for MAPL assets, net of unamortized discount of $360 and $480, respectively,  due June 2007                                                           |       |                         | 3,946      |                        |       |   | 3,667 |   |   |
| Long-term debt                                                                                                                                                             |       |                         | $          | 539,789                     |       |   |   | $ | 357,163 |   |   |

 

**$400 million SeniorSecured Credit Facility**

On September 30, 2005, the Partnership enteredinto a new five-year $400 million senior secured revolving credit facility (the“New Credit Facility”) that replaced the Partnership’s previous U.S. andCanadian revolving credit facilities. The New Credit Facility is available forgeneral Partnership purposes, in the U.S. and Canada, including workingcapital, letters of credit and distributions to unitholders (subject to certainlimitations). The New Credit Facility matures on September 30, 2010, andthe Partnership may prepay all loans under the New Credit Facility withoutpremium or penalty. Obligations under the New Credit Facility are guaranteed byall of the subsidiaries of the Partnership except those for which regulatoryapproval is required and are secured by substantially all of the assets of thePartnership, excluding property held by the non-guaranteeing subsidiaries. TheNew Credit Facility is recourse to the Partnership and the guarantors, butnon-recourse to the General Partner.

Subject to certain limited exceptions, indebtednessunder the New Credit Facility bears interest (at the Partnership’s option) ateither (i) the base rate, which is equal to the higher of the prime rateas announced by Bank of America, N.A. or the Federal Funds rate plus 0.50% (orin the case of borrowings under the Canadian sub-facility described below,Canadian US dollar base rate or Canadian prime rate) (each plus an applicablemargin ranging from 0% to 0.75%) or (ii) the Eurodollar rate plus anapplicable margin ranging from 0.75% to 2.00%. The applicable margins fluctuatebased on the Partnership’s credit rating at any given time. In addition, thePartnership will incur a commitment fee which ranges from 0.1875% to 0.5000%per annum on the unused portion of the New Credit Facility.

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Included in the New Credit Facility is a Canadiansub-facility for Rangeland Pipeline Company (“RPC”), one of the Partnership’sCanadian subsidiaries. The Canadian sub-facility currently has a limit ofU.S.$100 million, but can be adjusted from time to time by the Partnership. TheCanadian sub-facility includes an option for RPC to receive loans in eitherU.S. dollars or Canadian dollars.

The New Credit Facility contains certain financialcovenants and covenants limiting the ability of the Partnership to, among otherthings, incur or guarantee indebtedness, change ownership or structure,including mergers, consolidations, liquidations and dissolutions, sell ortransfer assets and properties, and enter into a new line of business. At September 30,2005, the Partnership was in compliance with all such covenants.

As of September 30, 2005, $114.2 million wasoutstanding under the New Credit Facility, including $19.2 million under theCanadian sub-facility, and there was $152.6 million of undrawn availablecredit.

The New Credit Facilitywas entered into with a syndicate of financial institutions, including anaffiliate of Lehman Brothers, Inc., which is an affiliate of LBP (see “Note4—Related Party Transactions”).

**7**1¤8% SeniorNotes, Due June 2014

On June 16,2004, the Partnership and its 100% owned subsidiary, Pacific Energy FinanceCorporation, completed the sale of $250 million of 71¤8%****seniorunsecured notes due June 15, 2014. The notes were sold in a privateoffering to qualified institutional buyers in reliance on Rule 144A underthe Securities Act of 1933 (the “Securities Act”) and to non-U.S. persons underRegulation S of the Securities Act. In October 2004, the notes wereexchanged for new notes with materially identical terms that have beenregistered under the Securities Act but are not listed on any securitiesexchange. The notes were issued at a discount of $4.4 million, resultingin an effective interest rate of 7.375%. Interest payments are due on June 15and December 15 of each year. At any time prior to June 15, 2007, thePartnership has the option to redeem up to 35% of the aggregate principalamount of notes at a redemption price of 107.125% of the principal amount withthe net cash proceeds of one or more equity offerings. The Partnership has the optionto redeem the notes, in whole or in part, at anytime on or after June 15,2009 at the following redemption prices:

| **Year**            | ** ** | ** ** | ** ** | **Percentage** | ** ** |
|---------------------|------------|------------|------------|----------------|------------|
| 2009                |       |       | 103.563    | %              |       |
| 2010                |       |       | 102.375    | %              |       |
| 2011                |       |       | 101.188    | %              |       |
| 2012 and thereafter |       |       | 100.000    | %              |       |

 

The notes are jointly and severally guaranteed bycertain of the Partnership’s subsidiaries, including Pacific Energy Group LLC,Pacific Marketing and Transportation LLC, Pacific Atlantic Terminals LLC, RockyMountain Pipeline System LLC, Ranch Pipeline LLC, PEG Canada GP LLC and PEGCanada, L.P.

The indenture governing the notes contains certaincovenants that, among other things, limit the Partnership’s ability and theability of its restricted subsidiaries to incur or guarantee indebtedness orissue certain types of preferred equity securities; sell assets; paydistributions on, redeem or repurchase Partnership units; or consolidate, mergeor transfer all or substantially all of its assets. At September 30, 2005,the Partnership was in compliance with all such covenants.

Under the Indenturegoverning the Partnership’s 71¤8%senior notes due 2014, the Partnership would have been required to make a “Changeof Control Offer” to the holders of such notes if the LB Acquisition caused arating decline by a credit rating agency. In order to avoid triggering the “Changeof 

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ControlOffer” provision, the Partnership solicited the consent (the “ConsentSolicitation”) of the holders of the 71¤8% notes toamend certain provisions of the Indenture, including an amendment to thedefinition of “Change of Control.” The Consent Solicitation was completed on February 10,2005 with a majority of the holders of the senior notes consenting to theadoption of the proposed amendments, and as such, the proposed amendments wereapproved. Thereafter, a supplemental indenture that incorporated the proposedamendments was executed by the parties to the Indenture. Fees of $0.6 millionpaid to holders of the notes were capitalized and included in “Other assets” inthe accompanying condensed consolidated balance sheet at September 30,2005 and will be amortized over the remaining life of the 71¤8% notes. Othersolicitation-related fees and expenses of approximately $0.6 million areincluded in “Transaction costs” in the accompanying condensed consolidated statementsof income. LBP and TAC reimbursed the Partnership for the entire cost of theConsent Solicitation, which reimbursement is recorded as a partner’s capitalcontribution (see “Note 4—Related Party Transactions”).

**6**1¤4%Senior Notes Due 2015

On September 23, 2005, the Partnership and its100% owned subsidiary, Pacific Energy Finance Corporation, completed the saleof $175 million of 61⁄4% seniorunsecured notes due September 15, 2015. The notes were sold in a privateoffering to qualified institutional buyers in reliance on Rule 144A underthe Securities Act of 1933. The notes were sold for 99.544% of face valueresulting in an effective interest rate of 6.3125% to maturity. Interestpayments are due on March 15 and September 15 of each year, beginningon March 15, 2006.

Thenotes are jointly and severally guaranteed by the same Partnership subsidiariesthat guarantee the 71¤8% seniornotes, due June 2014. At any time prior to September 15, 2008, thePartnership has the option to redeem up to 35% of the aggregate principalamount of notes at a redemption price of 106.25 % of the principal amount withthe net cash proceeds of one or more equity offerings. At any time prior to September 15,2010, the Partnership may redeem some or all of the notes at a price equal to100% of the principal amount, plus a make-whole premium and accrued and unpaidinterest, if any, to the date of redemption. The Partnership will also have theoption to redeem the notes, in whole or in part, at any time on or after September 15,2010 at the following redemption prices:

| **Year**            | ** ** | ** ** | ** ** | **Percentage** | ** ** |
|---------------------|------------|------------|------------|----------------|------------|
| 2010                |       |       | 103.125    | %              |       |
| 2011                |       |       | 102.083    | %              |       |
| 2012                |       |       | 101.042    | %              |       |
| 2013 and thereafter |       |       | 100.000    | %              |       |

 

The indenture governing the notes contains certaincovenants that, among other things, limit the Partnership’s ability and theability of its restricted subsidiaries to incur or guarantee indebtedness orissue certain types of preferred equity securities; sell assets; paydistributions on, redeem or repurchase Partnership units; or consolidate, mergeor transfer all or substantially all of its assets. At September 30, 2005,the Partnership was in compliance with all such covenants.

Net proceeds from the issuance of the notes were$171.0 million after deducting the $0.8 million discount and offeringexpenses of $3.2 million. The net proceeds were used to partially fund theValero Acquisition.

Additionally, thePartnership entered into a registration rights agreement whereby thePartnership agreed, among other things, to file a registration statement with theSEC within 90 days after the issue date of the notes that will enable holdersof the notes to exchange the privately placed notes for publicly registerednotes with substantially identical terms, and to file a shelf registrationstatement for the resale of 

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thenotes in certain circumstances. If the Partnership does not comply with itsobligations under the registration rights agreement, the interest rate of thenotes will increase.

**6.    PARTNERS’ CAPITAL**

**Public EquityOffering**

On September 14,2005, the Partnership sold 4,550,000 common units in an underwritten publicoffering at a price of $32.00 per unit. On September 16, 2005, theunderwriters exercised their over-allotment option and purchased an additional682,500 common units at the same price. Net proceeds from the offering andexercise of the underwriters option, including the General Partner’scontribution of $3.4 million, totaled approximately $163.4 millionafter deducting underwriting fees and offering expenses of $7.4 million.The Partnership used net proceeds from the equity offering to partially fundthe Valero Acquisition.

**Private EquityPlacement**

On September 30,2005, the Partnership sold 4,300,000 common units pursuant to a Common UnitPurchase Agreement with certain institutional investors at a price of $30.75per unit. The Partnership received net proceeds of $131.8 million from the saleof the common units together with the General Partner’s contribution of $2.7million, which were used to partially fund the Valero Acquisition. ThePartnership also entered into a Registration Rights Agreement with theinstitutional investors, whereby the Partnership agreed to file a shelfregistration statement with the SEC for the resale from time to time of theprivately placed common units, such filing to be made within 90 days after theclosing, and for the Partnership thereafter to use commercially reasonableefforts to cause the shelf registration statement to become or be declaredeffective by the SEC within 180 days after the closing date.

**Conversion ofSubordinated Units**

On August 12, 2005,2,616,250 of the Partnership’s subordinated units were converted to commonunits pursuant to terms of the Partnership’s partnership agreement.

**7.   VESTINGOF UNIT GRANTS UNDER LONG-TERM INCENTIVE PLAN**

On March 3, 2005, inconnection with the LB Acquisition and the change in control of the Partnership’sGeneral Partner, all restricted units outstanding under the Partnership’sLong-Term Incentive Plan immediately vested pursuant to the terms of the grants.The Partnership issued 99,583 common units and recognized a compensationexpense of $3.1 million, which is included in “Accelerated long-term incentiveplan compensation expense” in the accompanying condensed consolidatedstatements of income.

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**8.   ALLOCATION OF NET INCOME**

Theallocation of net income between the Partnership’s General Partner and limitedpartners is as follows.

| ** **                                                              | ** ** | **Three Months Ended   September 30,** | ** ** | **Nine Months Ended  September 30,**      | ** ** |
|-------------------------------------------------------------------------|------------|------------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                                              | ** ** | **    2005    **   | ** ** | **    2004    ** | ** ** | **    2005    ** | ** ** | **    2004    ** | ** ** |
| ** **                                                              | ** ** | **(in thousands)**                                    | ** ** |
| Net income                                                              |       | $                                                          | 12,166     |                                                     |       | $ | 9,890 |   |   | $ | 27,807 |   | $ | 27,095 |   |
| Transaction costs  reimbursed by general partner:                       | ** ** | ** **                                                 | ** ** |                                                     |       |   | ** ** | ** ** | ** ** | ** ** | ** ** |
| 71¤8% senior notes consent  solicitation and other costs           |       | —                                                     |       |                                                     | —     |   |   | 893 |   | — |   |
| Severance and other costs                                               |       | —                                                     |       |                                                     | —     |   |   | 914 |   | — |   |
| Total transaction costs reimbursed by general  partner                  |       | —                                                     |       |                                                     | —     |   |   | 1,807 |   | — |   |
| Income before  transaction costs reimbursed by general partner          |       | 12,166                                                     |       |                                                     | 9,890      |   |   | 29,614 |   | 27,095 |   |
| General partner’s  share of income                                 |       | 2                                                          | %          |                                                     | 2          | % |   | 2 | % | 2 | % |
| General partner  allocated share of net income before transaction costs |       | 243                                                        |       |                                                     | 198        |   |   | 592 |   | 542 |   |
| Transaction costs  reimbursed by general  partner                       |       | —                                                     |       |                                                     | —     |   |   | (1,807 | ) | — |   |
| Net income (loss)  allocated to general partner                         |       | $                                                          | 243        |                                                     |       | $ | 198 |   |   | $ | (1,215 | ) | $ | 542 |   |
| Income before transaction costs reimbursed by  general partner          |       | $                                                          | 12,166     |                                                     |       | $ | 9,890 |   |   | $ | 29,614 |   | $ | 27,095 |   |
| Limited partners  share of income                                       |       | 98                                                         | %          |                                                     | 98         | % |   | 98 | % | 98 | % |
| Limited partners  share of net income                                   |       | $                                                          | 11,923     |                                                     |       | $ | 9,692 |   |   | $ | 29,022 |   | $ | 26,533 |   |
| Net income (loss) allocated to general partner                          |       | $                                                          | 243        |                                                     |       | $ | 198 |   |   | $ | (1,215 | ) | $ | 542 |   |
| Net income  allocated to limited partners                               |       | 11,923                                                     |       |                                                     | 9,692      |   |   | 29,022 |   | 26,553 |   |
| Net income                                                              |       | $                                                          | 12,166     |                                                     |       | $ | 9,890 |   |   | $ | 27,807 |   | $ | 27,095 |   |

 

LBP and TAC reimbursed thePartnership for certain costs incurred in connection with the LB Acquisition. ThePartnership was reimbursed $1.2 million for costs incurred in connection withthe Consent Solicitation, $0.3 million of legal and other costs and $0.9million relating to severance costs (see “Note 4—Related Party Transactions”),for a total of $2.4 million. Of the $1.2 million incurred for the consentsolicitation, $0.6 million was capitalized as deferred financing costs and $0.6million was expensed in the three month period ended March 31, 2005.

**9.   SEGMENT INFORMATION**

The Partnership’sbusiness and operations are organized into two business segments: the WestCoast Business Unit and the Rocky Mountain Business Unit. The West CoastBusiness Unit includes: (i) Pacific Pipeline System LLC, owner of Line2000 and Line 63, (ii) Pacific Marketing and Transportation LLC, owner ofthe PMT gathering system, (iii) Pacific Terminals LLC, owner of thePacific Terminals storage and distribution system and (iv) PacificAtlantic Terminals LLC, which was formed for the purpose of holding theCalifornia and East Coast terminal assets the Partnership acquired in theValero Acquisition on September 30, 2005. The Rocky Mountain Business Unitincludes: (i) Rocky Mountain Pipeline System LLC, owner of the Partnership’sinterest in various pipelines that make up the Western Corridor and Salt LakeCity Core systems and the West Pipeline System, which was acquired in theValero Acquisition, 

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(ii) Ranch Pipeline LLC, the owner of a 22.22%partnership interest in Frontier Pipeline Company, and (iii) PEG Canada,L.P. and its Canadian subsidiaries, which own and operate the Rangeland system(for the period since May 11, 2004). Balance sheet information noted belowincludes the assets acquired in the Valero Acquisition, which closed on September 30,2005. There was no income contribution for the three or nine months ended September 30,2005 from the Valero Acquisition. General and administrative costs, whichconsist of executive management, accounting and finance, human resources,information technology, investor relations, legal, and business development,are not allocated to the individual business units. Information regarding thesetwo business units is summarized below:

| ** **                                      | ** ** | **West Coast  Business Unit** | ** ** | **Rocky Mountain  Business Unit** | ** ** | **Intersegment and  Intrasegment  Eliminations** | ** ** | **Total** | ** ** |
|-------------------------------------------------|------------|-----------------------------------------|------------|---------------------------------------------|------------|-------------------------------------------------------|------------|-----------|------------|
| ** **                                      | ** ** | **(in thousands)**                 | ** ** |
| **Three months ended  September 30, 2005** |       |                                    |       |                                        |       |                                                  |       |      |       |   |   |   |   |   |   |
| Business unit  revenue:                         |       |                                    |       |                                        |       |                                                  |       |      |       |   |   |   |   |   |   |
| Pipeline transportation revenue                 |       |                                    | $          | 13,887                                      |       |                                                  |       | $         | 14,887     |   |   |   | $ | (1,491 | ) |   | $ | 27,283 |   |
| Storage and distribution revenue                |       |                                    | 9,731      |                                        |       |                                                  | —     |      |       |   |   |   |   | 9,731 |   |
| Pipeline buy/sell transportation revenue(1)     |       |                                    | —     |                                        |       |                                                  | 11,683     |      |       |   |   |   |   | 11,683 |   |
| Crude oil sales, net of purchases(2)            |       |                                    | 5,690      |                                        |       |                                                  | 163        |      |       |   | (30 | ) |   | 5,823 |   |
| Net revenue                                     |       |                                    | 29,308     |                                        |       |                                                  | 26,733     |      |       |   |   |   |   | 54,520 |   |
| Expenses:                                       |       |                                    |       |                                        |       |                                                  |       |      |       |   |   |   |   |   |   |
| Operating                                       |       |                                    | 16,004     |                                        |       |                                                  | 10,536     |      |       |   | (1,521 | ) |   | 25,019 |   |
| Depreciation and amortization                   |       |                                    | 3,491      |                                        |       |                                                  | 3,069      |      |       |   |   |   |   | 6,560 |   |
| Total expenses                                  |       |                                    | 19,495     |                                        |       |                                                  | 13,605     |      |       |   |   |   |   | 31,579 |   |
| Share of net  income of Frontier                |       |                                    | —     |                                        |       |                                                  | 516        |      |       |   |   |   |   | 516 |   |
| Operating income  from segments(4)              |       |                                    | $          | 9,813                                       |       |                                                  |       | $         | 13,644     |   |   |   |   |   |   | $ | 23,457 |   |
| Business unit  assets(5)                        |       |                                    | $          | 855,191                                     |       |                                                  |       | $         | 551,279    |   |   |   |   |   |   | $ | 1,406,470 |   |
| Capital  expenditures(6)                        |       |                                    | $          | 5,106                                       |       |                                                  |       | $         | 9,403      |   |   |   |   |   |   | $ | 14,509 |   |
| **Three  months ended September 30, 2004** |       |                                    |       |                                        |       |                                                  |       |      |       |   |   |   |   |   |   |
| Business unit revenue:                          |       |                                    |       |                                        |       |                                                  |       |      |       |   |   |   |   |   |   |
| Pipeline transportation revenue                 |       |                                    | $          | 16,985                                      |       |                                                  |       | $         | 12,500     |   |   |   | $ | (1,325 | ) |   | $ | 28,160 |   |
| Storage and distribution revenue                |       |                                    | 8,544      |                                        |       |                                                  | —     |      |       |   | (153 | ) |   | 8,391 |   |
| Pipeline buy/sell transportation revenue(1)     |       |                                    | —     |                                        |       |                                                  | 7,972      |      |       |   |   |   |   | 7,972 |   |
| Crude oil sales, net of purchases(2)            |       |                                    | 3,568      |                                        |       |                                                  | —     |      |       |   |   |   |   | 3,568 |   |
| Net revenue                                     |       |                                    | 29,097     |                                        |       |                                                  | 20,472     |      |       |   |   |   |   | 48,091 |   |
| Expenses:                                       |       |                                    |       |                                        |       |                                                  |       |      |       |   |   |   |   |   |   |
| Operating                                       |       |                                    | 14,309     |                                        |       |                                                  | 9,957      |      |       |   | (1,478 | ) |   | 22,788 |   |
| Depreciation and amortization                   |       |                                    | 3,433      |                                        |       |                                                  | 3,388      |      |       |   |   |   |   | 6,821 |   |
| Total expenses                                  |       |                                    | 17,742     |                                        |       |                                                  | 13,345     |      |       |   |   |   |   | 29,609 |   |
| Share of net  income of Frontier                |       |                                    | —     |                                        |       |                                                  | 406        |      |       |   |   |   |   | 406 |   |
| Operating income  from segments(4)              |       |                                    | $          | 11,355                                      |       |                                                  |       | $         | 7,533      |   |   |   |   |   |   | $ | 18,888 |   |
| Business unit  assets(5)                        |       |                                    | $          | 507,459                                     |       |                                                  |       | $         | 330,830    |   |   |   |   |   |   | $ | 838,289 |   |
| Capital expenditures(6)                         |       |                                    | $          | 1,054                                       |       |                                                  |       | $         | 1,764      |   |   |   |   |   |   | $ | 2,818 |   |

 

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| ** **                                     | ** ** | **West Coast  Business Unit** | ** ** | **Rocky Mountain  Business Unit** | ** ** | **Intersegment and  Intrasegment  Eliminations** | ** ** | **Total** | ** ** |
|------------------------------------------------|------------|-----------------------------------------|------------|---------------------------------------------|------------|-------------------------------------------------------|------------|-----------|------------|
| ** **                                     | ** ** | **(in thousands)**                 | ** ** |
| **Nine months ended  September 30, 2005** |       |                                    |       |                                        |       |                                                  |       |      |       |   |   |   |   |   |   |
| Business unit  revenue:                        |       |                                    |       |                                        |       |                                                  |       |      |       |   |   |   |   |   |   |
| Pipeline transportation revenue                |       |                                    | $          | 46,525                                      |       |                                                  |       | $         | 41,348     |   |   |   | $ | (4,806 | ) |   | $ | 83,067 |   |
| Storage and distribution revenue               |       |                                    | 31,073     |                                        |       |                                                  | —     |      |       |   | (150 | ) |   | 30,923 |   |
| Pipeline buy/sell transportation revenue(1)    |       |                                    | —     |                                        |       |                                                  | 28,905     |      |       |   |   |   |   | 28,905 |   |
| Crude oil sales, net of purchases(2)           |       |                                    | 13,368     |                                        |       |                                                  | 369        |      |       |   | (90 | ) |   | 13,647 |   |
| Net revenue                                    |       |                                    | 90,966     |                                        |       |                                                  | 70,622     |      |       |   |   |   |   | 156,542 |   |
| Expenses:                                      |       |                                    |       |                                        |       |                                                  |       |      |       |   |   |   |   |   |   |
| Operating                                      |       |                                    | 46,507     |                                        |       |                                                  | 30,604     |      |       |   | (5,046 | ) |   | 72,065 |   |
| Line 63 oil release costs(3)                   |       |                                    | 2,000      |                                        |       |                                                  | —     |      |       |   |   |   |   | 2,000 |   |
| Depreciation and amortization                  |       |                                    | 10,497     |                                        |       |                                                  | 9,198      |      |       |   |   |   |   | 19,695 |   |
| Total expenses                                 |       |                                    | 59,004     |                                        |       |                                                  | 39,802     |      |       |   |   |   |   | 93,760 |   |
| Share of net  income of Frontier               |       |                                    | —     |                                        |       |                                                  | 1,363      |      |       |   |   |   |   | 1,363 |   |
| Operating income  from segments(4)             |       |                                    | $          | 31,962                                      |       |                                                  |       | $         | 32,183     |   |   |   |   |   |   | $ | 64,145 |   |
| Business unit  assets(5)                       |       |                                    | $          | 855,191                                     |       |                                                  |       | $         | 551,279    |   |   |   |   |   |   | $ | 1,406,470 |   |
| Capital  expenditures(6)                       |       |                                    | $          | 6,790                                       |       |                                                  |       | $         | 14,870     |   |   |   |   |   |   | $ | 21,660 |   |
| **Nine  months ended September 30, 2004** |       |                                    |       |                                        |       |                                                  |       |      |       |   |   |   |   |   |   |
| Business unit revenue:                         |       |                                    |       |                                        |       |                                                  |       |      |       |   |   |   |   |   |   |
| Pipeline transportation revenue                |       |                                    | $          | 49,170                                      |       |                                                  |       | $         | 34,847     |   |   |   | $ | (4,138 | ) |   | $ | 79,879 |   |
| Storage and distribution revenue               |       |                                    | 28,126     |                                        |       |                                                  | —     |      |       |   | (353 | ) |   | 27,773 |   |
| Pipeline buy/sell transportation revenue(1)    |       |                                    | —     |                                        |       |                                                  | 11,662     |      |       |   |   |   |   | 11,662 |   |
| Crude oil sales, net of purchases(2)           |       |                                    | 14,436     |                                        |       |                                                  | —     |      |       |   |   |   |   | 14,436 |   |
| Net revenue                                    |       |                                    | 91,732     |                                        |       |                                                  | 46,509     |      |       |   |   |   |   | 133,750 |   |
| Expenses:                                      |       |                                    |       |                                        |       |                                                  |       |      |       |   |   |   |   |   |   |
| Operating                                      |       |                                    | 43,197     |                                        |       |                                                  | 23,866     |      |       |   | (4,491 | ) |   | 62,572 |   |
| Depreciation and amortization                  |       |                                    | 10,833     |                                        |       |                                                  | 6,943      |      |       |   |   |   |   | 17,776 |   |
| Total expenses                                 |       |                                    | 54,030     |                                        |       |                                                  | 30,809     |      |       |   |   |   |   | 80,348 |   |
| Share of net  income of Frontier               |       |                                    | —     |                                        |       |                                                  | 1,190      |      |       |   |   |   |   | 1,190 |   |
| Operating income  from segments(4)             |       |                                    | $          | 37,702                                      |       |                                                  |       | $         | 16,890     |   |   |   |   |   |   | $ | 54,592 |   |
| Business unit  assets(5)                       |       |                                    | $          | 507,459                                     |       |                                                  |       | $         | 330,830    |   |   |   |   |   |   | $ | 838,289 |   |
| Capital expenditures(6)                        |       |                                    | $          | 2,590                                       |       |                                                  |       | $         | 6,243      |   |   |   |   |   |   | $ | 8,833 |   |

----

(1)          Includes the revenue ofthe Rangeland system, which was acquired on May 11, 2004 and June 30,2004. Pipeline buy/sell transportation revenue reflects net revenues ofapproximately $2.5 million on gross revenues for buy/sell transactions of $77.5million with different parties for the three months ended September 30,2005 and net revenues of approximately $4.6 million on gross revenues forbuy/sell transactions of $126.0 million for the nine months ended September 30,2005. The remaining amount reflects net revenues on buy/sell transactions withthe same party.

(2)          The above amounts arenet of purchases of $188,901 and $103,192 for the three months ended September 30,2005 and 2004 and $425,733 and $278,689 for the nine months ended September 30,2005 and 2004, respectively.

(3)          See “Note 3—Line 63 OilRelease Reserve” for further information.

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(4)          Thefollowing is a reconciliation of operating income as stated above to netincome:

| ** **                                                                       | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|----------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                                       | ** ** | **2005**                                             | ** ** | **2004**                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                       | ** ** | **(in thousands)**                              | ** ** |
| **Income Statement Reconciliation**                                              |       |                                                 |       |                                                |       |   |   |   |   |
| Operating income from  above:                                                    |       |                                                 |       |                                                |       |   |   |   |   |
| West Coast Business Unit                                                         |       | $                                                    | 9,813      |                                                | $          | 11,355 |   | $ | 31,962 |   | $ | 37,702 |   |
| Rocky Mountain Business  Unit                                                    |       | 13,644                                               |       | 7,533                                               |       | 32,183 |   | 16,890 |   |
| Operating income from  segments                                                  |       | 23,457                                               |       | 18,888                                              |       | 64,145 |   | 54,592 |   |
| Less: General and  administrative expense                                        |       | 4,115                                                |       | 3,762                                               |       | 12,987 |   | 11,252 |   |
| Less: Accelerated  long-term incentive plan compensation expense                 |       | —                                               |       | —                                              |       | 3,115 |   | — |   |
| Less: Transaction costs                                                          |       | —                                               |       | —                                              |       | 1,807 |   | — |   |
| Operating income                                                                 |       | 19,342                                               |       | 15,126                                              |       | 46,236 |   | 43,340 |   |
| Interest expense                                                                 |       | (6,237                                               | )          | (5,234                                              | )          | (17,679 | ) | (13,743 | ) |
| Write-off of deferred  financing cost and interest rate swap termination expense |       | —                                               |       | —                                              |       | — |   | (2,901 | ) |
| Other income                                                                     |       | 494                                                  |       | 219                                                 |       | 1,387 |   | 606 |   |
| Income before income  taxes                                                      |       | 13,599                                               |       | 10,111                                              |       | 29,944 |   | 27,302 |   |
| Income tax expense                                                               |       | (1,433                                               | )          | (221                                                | )          | (2,137 | ) | (207 | ) |
| Net income                                                                       |       | $                                                    | 12,166     |                                                | $          | 9,890 |   | $ | 27,807 |   | $ | 27,095 |   |

 

(5)          Businessunit assets do not include assets related to the Partnership’s parent levelactivities. As of September 30, 2005 and 2004, parent level related assetswere $50,845 and $29,651 respectively.

(6)          Capitalexpenditures do not include the Pier 400 project and other parent-level relatedcapital expenditures. Pier 400 project and other parent-level related capitalexpenditures were $2,878 and $808 for the three months ended September 30,2005 and 2004 and $5,605 and $2,689 for the nine months ended September 30,2005 and 2004, respectively.

**10.   CONTINGENCIES**

In August 2005, RangelandPipeline Company (“RPC”), a wholly-owned subsidiary of the Partnership, learnedthat a Statement of Claim was filed by Desiree Meier and Robert Meier in theAlberta Court of Queen’s Bench, Judicial District of Red Deer, naming RPC asdefendant, and alleging personal injury and property damage caused by analleged release of petroleum substances onto plaintiff’s land from a pipelineowned and operated by RPC. The claim seeks Cdn$1 million in general damages,Cdn$2 million in special damages, and, in addition, unspecified amounts forpunitive, exemplary and aggravated damages, costs and interest. The Statementof Claim has not been served on RPC, so RPC has not been required to file ananswer. RPC believes the claim is without merit, and intends to vigorouslydefend against it.

In connection with the Valero Acquisition, we haveassumed defense of Support Terminals Services, Inc. (“ST Services”) in alawsuit filed in New Jersey state court in 2003 by ExxonMobil Corporation (“ExxonMobil”).We have also assumed any liability that might be imposed on ST Services as aresult of the suit. In the suit, ExxonMobil seeks $400,000 for remediationcosts it has paid, from GATX Corporation, Kinder Morgan Liquid Terminals, thesuccessor in interest to GATX Terminals Corporation, and ST Services.ExxonMobil also seeks a ruling imposing liability for any future remediation onthe same defendants. These costs are associated with the Paulsboro, New Jerseyterminal that was acquired by us. ExxonMobil claims that the costs are relatedto releases at the site subsequent to its sale of the terminal to GATX in 1990and that any remaining remediation requirements are the responsibility of GATXCorporation, Kinder Morgan, and ST Services.

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The Partnership isinvolved in various other regulatory disputes, litigation and claims arisingout of its operations in the normal course of business (see also “Note 3—Line63 Oil Release Reserve”). The Partnership is not currently a party to any legalor regulatory proceedings the resolution of which could be expected to have amaterial adverse effect on its business, financial condition, liquidity orresults of operations.

**11.   SUBSEQUENTEVENTS**

On October 21, 2005,the Partnership declared a cash distribution of $0.5125 per limited partnerunit, payable on November 14, 2005, to unitholders of record as ofOctober 31, 2005.

**12.**   SUPPLEMENTALCONDENSED CONSOLIDATING FINANCIAL INFORMATION

Certain of the Partnership’s 100% owned subsidiarieshave issued unconditional guarantees of the 71¤8% senior notesdue 2014 and the 61¤4% senior notesdue 2015 (the “Senior Notes”). These guarantees are full, unconditional, andjoint and several. Given that certain, but not all subsidiaries of thePartnership are guarantors of its Senior Notes, the Partnership is required topresent the following supplemental condensed consolidating financialinformation. For purposes of the following footnote, the Partnership isreferred to as “Parent.” Rocky Mountain Pipeline System LLC, Pacific Marketingand Transportation LLC, Pacific Atlantic Terminals LLC, Ranch Pipeline LLC, PEGCanada GP LLC, PEG Canada, L.P. and Pacific Energy Group LLC, the guarantors ofthe Senior Notes, are collectively referred to as the “Guarantor Subsidiaries,”and Pacific Pipeline System LLC, Pacific Terminals LLC, Rangeland PipelineCompany, Rangeland Marketing Company, Rangeland Northern Pipeline Company,Rangeland Pipeline Partnership and Aurora Pipeline Company, Ltd. are referredto as “Non-Guarantor Subsidiaries.”

Thefollowing supplemental condensed consolidating financial information reflectsthe Parent’s separate accounts, the combined accounts of the GuarantorSubsidiaries, the combined accounts of the Parent’s Non-Guarantor Subsidiaries,the combined consolidating adjustments and eliminations and the Parent’sconsolidated accounts for the dates and periods indicated. For purposes of thefollowing condensed consolidating information, the Parent’s investments in itssubsidiaries and the Guarantor Subsidiaries’ investments in their subsidiariesare accounted for under the equity method of accounting:

| ** **                                   | ** ** | **Balance Sheet  September 30, 2005** | ** ** |
|----------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                   | ** ** | **Parent**                                           | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **Total** | ** ** |
| ** **                                   | ** ** | **(in thousands)**                              | ** ** |
| Assets:                                      |       |                                                 |       |   |   |   |   |   |   |   |   |   |   |
| Current assets                               |       | $                                                    | 150,140    |   | $ | 154,017 |   |   | $ | 120,395 |   |   | $ | (237,707 | ) | $ | 186,845 |   |
| Property and equipment                       |       | —                                               |       | 429,949 |   |   | 599,670 |   |   | — |   | 1,029,619 |   |
| Equity investments                           |       | 409,373                                              |       | 221,461 |   |   | — |   |   | (623,029 | ) | 7,805 |   |
| Intercompany notes  receivable               |       | 658,313                                              |       | 341,171 |   |   | — |   |   | (999,484 | ) | — |   |
| Intangible assets                            |       | —                                               |       | 179,227 |   |   | 38,279 |   |   | — |   | 217,506 |   |
| Other assets                                 |       | 15,540                                               |       | — |   |   | — |   |   | — |   | 15,540 |   |
| Total assets                                 |       | $                                                    | 1,233,366  |   | $ | 1,325,825 |   |   | $ | 758,344 |   |   | $ | (1,860,220 | ) | $ | 1,457,315 |   |
| Liabilities and partners’ capital:      |       |                                                 |       |   |   |   |   |   |   |   |   |   |   |
| Current liabilities                          |       | $                                                    | 9,932      |   | $ | 247,362 |   |   | $ | 136,621 |   |   | $ | (237,707 | ) | $ | 156,208 |   |
| Long-term debt                               |       | 516,683                                              |       | — |   |   | 23,106 |   |   | — |   | 539,789 |   |
| Deferred income taxes                        |       | —                                               |       | 873 |   |   | 35,238 |   |   | — |   | 36,111 |   |
| Intercompany notes  payable                  |       | —                                               |       | 658,313 |   |   | 341,171 |   |   | (999,484 | ) | — |   |
| Other liabilities                            |       | —                                               |       | 9,904 |   |   | 8,552 |   |   | — |   | 18,456 |   |
| Total partners’ capital                 |       | 706,751                                              |       | 409,373 |   |   | 213,656 |   |   | (623,029 | ) | 706,751 |   |
| Total liabilities and partners’ capital |       | $                                                    | 1,233,366  |   | $ | 1,325,825 |   |   | $ | 758,344 |   |   | $ | (1,860,220 | ) | $ | 1,457,315 |   |

 

21

----

 

| ** **                                          | ** ** | **Balance Sheet  December 31, 2004** | ** ** |
|-----------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                          | ** ** | **Parent**                                          | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **Total** | ** ** |
| ** **                                          | ** ** | **(in thousands)**                             | ** ** |
| Assets:                                             |       |                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Current assets                                      |       | $                                                   | 14,869     |   |   | $ | 80,320 |   |   |   | $ | 41,948 |   |   | $ | (41,592 | ) | $ | 95,545 |   |
| Property and equipment                              |       | —                                              |       |   | 129,496 |   |   |   | 589,128 |   |   | — |   | 718,624 |   |
| Equity investments                                  |       | 366,148                                             |       |   | 194,787 |   |   |   | — |   |   | (553,049 | ) | 7,886 |   |
| Intercompany notes receivable                       |       | 283,550                                             |       |   | 338,884 |   |   |   | — |   |   | (622,434 | ) | — |   |
| Other assets                                        |       | 7,223                                               |       |   | 1,993 |   |   |   | 38,634 |   |   | — |   | 47,850 |   |
| Total assets                                        |       | $                                                   | 671,790    |   |   | $ | 745,480 |   |   |   | $ | 669,710 |   |   | $ | (1,217,075 | ) | $ | 869,905 |   |
| Liabilities and  partners’ capital:            |       |                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Current liabilities                                 |       | $                                                   | 833        |   |   | $ | 44,177 |   |   |   | $ | 44,627 |   |   | $ | (41,592 | ) | $ | 48,045 |   |
| Long-term debt                                      |       | 248,491                                             |       |   | 51,000 |   |   |   | 57,672 |   |   | — |   | 357,163 |   |
| Deferred income taxes                               |       | —                                              |       |   | 470 |   |   |   | 34,086 |   |   | — |   | 34,556 |   |
| Intercompany notes payable                          |       | —                                              |       |   | 283,550 |   |   |   | 338,884 |   |   | (622,434 | ) | — |   |
| Other liabilities                                   |       | —                                              |       |   | 135 |   |   |   | 7,540 |   |   | — |   | 7,675 |   |
| Total partners’ capital                        |       | 422,466                                             |       |   | 366,148 |   |   |   | 186,901 |   |   | (553,049 | ) | 422,466 |   |
| Total liabilities  and partners’ capital  |       | $                                                   | 671,790    |   |   | $ | 745,480 |   |   |   | $ | 669,710 |   |   | $ | (1,217,075 | ) | $ | 869,905 |   |

 

| ** **                                | ** ** | **Statement of Income  Three Months Ended September 30, 2005** | ** ** |
|-------------------------------------------|------------|---------------------------------------------------------------------------------------------------|------------|
| ** **                                | ** ** | **Parent**                                                                                        | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **Total** | ** ** |
| ** **                                | ** ** | **(in thousands)**                                                                           | ** ** |
| Net operating  revenues                   |       | $                                                                                                 | —     |   |   | $ | 20,740 |   |   |   | $ | 35,301 |   |   |   | $ | (1,521 | ) |   | $ | 54,520 |   |
| Operating  expenses                       |       | —                                                                                            |       |   | (11,171 | ) |   |   | (15,369 | ) |   |   | 1,521 |   |   | (25,019 | ) |
| General and administrative  expense(1)    |       | —                                                                                            |       |   | (3,594 | ) |   |   | (521 | ) |   |   | — |   |   | (4,115 | ) |
| Depreciation and  amortization expense    |       | —                                                                                            |       |   | (1,633 | ) |   |   | (4,927 | ) |   |   | — |   |   | (6,560 | ) |
| Share of net  income of Frontier          |       | —                                                                                            |       |   | 516 |   |   |   | — |   |   |   | — |   |   | 516 |   |
| Operating income                          |       | —                                                                                            |       |   | 4,858 |   |   |   | 14,484 |   |   |   | — |   |   | 19,342 |   |
| Interest expense                          |       | (4,630                                                                                            | )          |   | (818 | ) |   |   | (789 | ) |   |   | — |   |   | (6,237 | ) |
| Intercompany  interest income   (expense) |       | —                                                                                            |       |   | 6,639 |   |   |   | (6,639 | ) |   |   | — |   |   | — |   |
| Equity earnings                           |       | 16,585                                                                                            |       |   | 6,115 |   |   |   | — |   |   |   | (22,700 | ) |   | — |   |
| Other income                              |       | 211                                                                                               |       |   | 180 |   |   |   | 103 |   |   |   | — |   |   | 494 |   |
| Income tax expense                        |       | —                                                                                            |       |   | (398 | ) |   |   | (1,035 | ) |   |   | — |   |   | (1,433 | ) |
| Net income                                |       | $                                                                                                 | 12,166     |   |   | $ | 16,576 |   |   |   | $ | 6,124 |   |   |   | $ | (22,700 | ) |   | $ | 12,166 |   |

----

(1)          Generaland administrative expense is not currently allocated between Guarantor andNon-Guarantor Subsidiaries for financial reporting purposes.

22

----

 

| ** **                               | ** ** | **Statement of Income  Three Months Ended September 30, 2004** | ** ** |
|------------------------------------------|------------|---------------------------------------------------------------------------------------------------|------------|
| ** **                               | ** ** | **Parent**                                                                                        | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  adjustments** | ** ** | **Total** | ** ** |
| ** **                               | ** ** | **(in thousands)**                                                                           | ** ** |
| Net operating  revenues                  |       | $                                                                                                 | —     |   |   | $ | 16,068 |   |   |   | $ | 33,501 |   |   |   | $ | (1,478 | ) |   | $ | 48,091 |   |
| Operating  expenses                      |       | —                                                                                            |       |   | (10,190 | ) |   |   | (14,076 | ) |   |   | 1,478 |   |   | (22,788 | ) |
| General and  administrative expense(1)   |       | —                                                                                            |       |   | (3,311 | ) |   |   | (451 | ) |   |   | — |   |   | (3,762 | ) |
| Depreciation and  amortization expense   |       | —                                                                                            |       |   | (1,668 | ) |   |   | (5,153 | ) |   |   | — |   |   | (6,821 | ) |
| Share of net  income of Frontier         |       | —                                                                                            |       |   | 406 |   |   |   | — |   |   |   | — |   |   | 406 |   |
| Operating income                         |       | —                                                                                            |       |   | 1,305 |   |   |   | 13,821 |   |   |   | — |   |   | 15,126 |   |
| Interest expense                         |       | (3,894                                                                                            | )          |   | (489 | ) |   |   | (851 | ) |   |   | — |   |   | (5,234 | ) |
| Intercompany  interest income  (expense) |       | —                                                                                            |       |   | 5,946 |   |   |   | (5,946 | ) |   |   | — |   |   | — |   |
| Equity earnings                          |       | 13,798                                                                                            |       |   | 7,158 |   |   |   | — |   |   |   | (20,956 | ) |   | — |   |
| Other income  (expense)                  |       | (14                                                                                               | )          |   | 151 |   |   |   | 82 |   |   |   | — |   |   | 219 |   |
| Income tax  (expense) benefit            |       | —                                                                                            |       |   | (273 | ) |   |   | 52 |   |   |   | — |   |   | (221 | ) |
| Net income                               |       | $                                                                                                 | 9,890      |   |   | $ | 13,798 |   |   |   | $ | 7,158 |   |   |   | $ | (20,956 | ) |   | $ | 9,890 |   |

----

(1)          Generaland administrative expense is not currently allocated between Guarantor andNon-Guarantor Subsidiaries for financial reporting purposes.

| ** **                                                 | ** ** | **Statement of Income  Nine Months Ended September 30, 2005** | ** ** |
|------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------|------------|
| ** **                                                 | ** ** | **Parent**                                                                                       | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **Total** | ** ** |
| ** **                                                 | ** ** | **(in thousands)**                                                                          | ** ** |
| Net operating  revenues                                    |       | $                                                                                                | —     |   |   | $ | 55,085 |   |   |   | $ | 106,503 |   |   |   | $ | (5,046 | ) |   | $ | 156,542 |   |
| Operating  expenses                                        |       | —                                                                                           |       |   | (31,461 | ) |   |   | (45,650 | ) |   |   | 5,046 |   |   | (72,065 | ) |
| Line 63 oil  release costs                                 |       | —                                                                                           |       |   | — |   |   |   | (2,000 | ) |   |   | — |   |   | (2,000 | ) |
| General and administrative  expense(1)                |       | —                                                                                           |       |   | (11,420 | ) |   |   | (1,567 | ) |   |   | — |   |   | (12,987 | ) |
| Accelerated  long-term incentive plan compensation expense |       | —                                                                                           |       |   | (2,675 | ) |   |   | (440 | ) |   |   | — |   |   | (3,115 | ) |
| Transaction costs                                          |       | (893                                                                                             | )          |   | (914 | ) |   |   | — |   |   |   | — |   |   | (1,807 | ) |
| Depreciation and  amortization expense                     |       | —                                                                                           |       |   | (4,893 | ) |   |   | (14,802 | ) |   |   | — |   |   | (19,695 | ) |
| Share of net  income of Frontier                           |       | —                                                                                           |       |   | 1,363 |   |   |   | — |   |   |   | — |   |   | 1,363 |   |
| Operating income                                           |       | (893                                                                                             | )          |   | 5,085 |   |   |   | 42,044 |   |   |   | — |   |   | 46,236 |   |
| Interest expense                                           |       | (12,925                                                                                          | )          |   | (2,322 | ) |   |   | (2,432 | ) |   |   | — |   |   | (17,679 | ) |
| Intercompany  interest income (expense)                    |       | —                                                                                           |       |   | 19,051 |   |   |   | (19,051 | ) |   |   | — |   |   | — |   |
| Equity earnings                                            |       | 41,397                                                                                           |       |   | 19,691 |   |   |   | — |   |   |   | (61,088 | ) |   | — |   |
| Other income                                               |       | 228                                                                                              |       |   | 780 |   |   |   | 379 |   |   |   | — |   |   | 1,387 |   |
| Income tax  expense                                        |       | —                                                                                           |       |   | (888 | ) |   |   | (1,249 | ) |   |   | — |   |   | (2,137 | ) |
| Net income                                                 |       | $                                                                                                | 27,807     |   |   | $ | 41,397 |   |   |   | $ | 19,691 |   |   |   | $ | (61,088 | ) |   | $ | 27,807 |   |

----

(1)          Generaland administrative expense is not currently allocated between Guarantor andNon-Guarantor Subsidiaries for financial reporting purposes.

23

----

 

| ** **                                                                        | ** ** | **Statement of Income  Nine Months Ended September 30, 2004** | ** ** |
|-----------------------------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------|------------|
| ** **                                                                        | ** ** | **Parent**                                                                                       | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  adjustments** | ** ** | **Total** | ** ** |
| ** **                                                                        | ** ** | **(in thousands)**                                                                          | ** ** |
| Net operating  revenues                                                           |       | $                                                                                                | —     |   |   | $ | 49,283 |   |   |   | $ | 88,958 |   |   |   | $ | (4,491 | ) |   | $ | 133,750 |   |
| Operating  expenses                                                               |       | —                                                                                           |       |   | (29,928 | ) |   |   | (37,135 | ) |   |   | 4,491 |   |   | (62,572 | ) |
| General and  administrative expense(1)                                       |       | —                                                                                           |       |   | (10,529 | ) |   |   | (723 | ) |   |   | — |   |   | (11,252 | ) |
| Depreciation and  amortization expense                                       |       | —                                                                                           |       |   | (4,911 | ) |   |   | (12,865 | ) |   |   | — |   |   | (17,776 | ) |
| Share of net  income of Frontier                                                  |       | —                                                                                           |       |   | 1,190 |   |   |   | — |   |   |   | — |   |   | 1,190 |   |
| Operating income                                                                  |       | —                                                                                           |       |   | 5,105 |   |   |   | 38,235 |   |   |   | — |   |   | 43,340 |   |
| Interest expense                                                                  |       | (4,648                                                                                           | )          |   | (7,909 | ) |   |   | (1,186 | ) |   |   | — |   |   | (13,743 | ) |
| Write-off of  deferred financing costs and interest rate swap termination expense |       | —                                                                                           |       |   | (2,901 | ) |   |   | — |   |   |   | — |   |   | (2,901 | ) |
| Intercompany  interest income (expense)                                           |       | —                                                                                           |       |   | 14,564 |   |   |   | (14,564 | ) |   |   | — |   |   | — |   |
| Equity earnings                                                                   |       | 31,752                                                                                           |       |   | 22,732 |   |   |   | — |   |   |   | (54,484 | ) |   | — |   |
| Other income  (expense)                                                           |       | (9                                                                                               | )          |   | 434 |   |   |   | 181 |   |   |   | — |   |   | 606 |   |
| Income tax  (expense) benefit                                                     |       | —                                                                                           |       |   | (273 | ) |   |   | 66 |   |   |   | — |   |   | (207 | ) |
| Net income                                                                        |       | $                                                                                                | 27,095     |   |   | $ | 31,752 |   |   |   | $ | 22,732 |   |   |   | $ | (54,484 | ) |   | $ | 27,095 |   |

----

(1)          Generaland administrative expense is not currently allocated between Guarantor andNon-Guarantor Subsidiaries for financial reporting purposes.

24

----

 

| ** **                                                                         | ** ** | **Statement of Cash Flows  Nine Months Ended September 30, 2005** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **Parent**                                                                                                | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-  Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **Total** | ** ** |
| ** **                                                                         | ** ** | **(in thousands)**                                                                                   | ** ** |
| CASH FLOWS FROM  OPERATING ACTIVITIES:                                             |       |                                                                                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Net income                                                                         |       | $                                                                                                         | 27,807     |   |   | $ | 41,397 |   |   |   | $ | 19,691 |   |   |   | $ | (61,088 | ) |   | $ | 27,807 |   |
| Adjustments to  reconcile net income to net cash provided by operating activities: |       |                                                                                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Equity earnings                                                                    |       | (41,397                                                                                                   | )          |   | (19,691 | ) |   |   | — |   |   |   | 61,088 |   |   | — |   |
| Distributions from subsidiaries                                                    |       | 46,224                                                                                                    |       |   | 31,888 |   |   |   | — |   |   |   | (78,112 | ) |   | — |   |
| Depreciation, amortization and other                                               |       | 514                                                                                                       |       |   | 8,645 |   |   |   | 15,097 |   |   |   | — |   |   | 24,256 |   |
| Net changes in  operating assets and liabilities                                   |       | 8,877                                                                                                     |       |   | 9,601 |   |   |   | 1,948 |   |   |   | (6,834 | ) |   | 13,592 |   |
| NET CASH PROVIDED  BY OPERATING ACTIVITIES                                         |       | 42,025                                                                                                    |       |   | 71,840 |   |   |   | 36,736 |   |   |   | (84,946 | ) |   | 65,655 |   |
| CASH FLOWS FROM  INVESTING ACTIVITIES                                              |       |                                                                                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Acquisition                                                                        |       | —                                                                                                    |       |   | (457,352 | ) |   |   | — |   |   |   | — |   |   | (457,352 | ) |
| Additions to property, equipment and other                                         |       | —                                                                                                    |       |   | (14,729 | ) |   |   | (16,349 | ) |   |   | — |   |   | (31,078 | ) |
| Intercompany                                                                       |       | (465,633                                                                                                  | )          |   | — |   |   |   | — |   |   |   | 465,633 |   |   | — |   |
| NET CASH USED IN  INVESTING ACTIVITIES                                             |       | (465,633                                                                                                  | )          |   | (472,081 | ) |   |   | (16,349 | ) |   |   | 465,633 |   |   | (488,430 | ) |
| NET CASH PROVIDED  BY (USED IN) FINANCING ACTIVITIES                               |       | 427,090                                                                                                   |       |   | 395,844 |   |   |   | (17,293 | ) |   |   | (380,687 | ) |   | 424,954 |   |
| Effect of translation adjustment                                                   |       | —                                                                                                    |       |   | — |   |   |   | 213 |   |   |   | — |   |   | 213 |   |
| NET INCREASE  (DECREASE) IN CASH AND CASH  EQUIVALENTS                             |       | 3,482                                                                                                     |       |   | (4,397 | ) |   |   | 3,307 |   |   |   | — |   |   | 2,392 |   |
| CASH AND CASH  EQUIVALENTS, beginning of reporting period                          |       | 2,713                                                                                                     |       |   | 17,523 |   |   |   | 3,147 |   |   |   | — |   |   | 23,383 |   |
| CASH AND CASH  EQUIVALENTS, end of reporting period                                |       | $                                                                                                         | 6,195      |   |   | $ | 13,126 |   |   |   | $ | 6,454 |   |   |   | $ | — |   |   | $ | 25,775 |   |

 

25

----

 

| ** **                                                                         | ** ** | **Statement of Cash Flows  Nine Months Ended September 30, 2004** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **Parent**                                                                                                | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-  Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **Total** | ** ** |
| ** **                                                                         | ** ** | **(in thousands)**                                                                                   | ** ** |
| CASH FLOWS FROM  OPERATING ACTIVITIES:                                             |       |                                                                                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Net income                                                                         |       | $                                                                                                         | 27,095     |   |   | $ | 31,752 |   |   |   | $ | 22,732 |   |   |   | $ | (54,484 | ) |   | $ | 27,095 |   |
| Adjustments to reconcile  net income to net cash provided by operating activities: |       |                                                                                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Equity earnings                                                                    |       | (31,752                                                                                                   | )          |   | (22,732 | ) |   |   | — |   |   |   | 54,484 |   |   | — |   |
| Distributions from subsidiaries                                                    |       | 41,800                                                                                                    |       |   | 35,012 |   |   |   | — |   |   |   | (76,812 | ) |   | — |   |
| Depreciation, amortization and other                                               |       | 176                                                                                                       |       |   | 8,127 |   |   |   | 12,837 |   |   |   | — |   |   | 21,140 |   |
| Net changes in  operating assets and liabilities                                   |       | 4,550                                                                                                     |       |   | (10,783 | ) |   |   | (6,893 | ) |   |   | 7,111 |   |   | (6,015 | ) |
| NET CASH PROVIDED  BY OPERATING ACTIVITIES                                         |       | 41,869                                                                                                    |       |   | 41,376 |   |   |   | 28,676 |   |   |   | (69,701 | ) |   | 42,220 |   |
| CASH FLOWS FROM  INVESTING ACTIVITIES                                              |       |                                                                                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Acquisitions                                                                       |       | —                                                                                                    |       |   | — |   |   |   | (139,000 | ) |   |   | — |   |   | (139,000 | ) |
| Additions to property, equipment and other                                         |       | —                                                                                                    |       |   | (7,633 | ) |   |   | (4,510 | ) |   |   | — |   |   | (12,143 | ) |
| Intercompany                                                                       |       | (369,675                                                                                                  | )          |   | (96,267 | ) |   |   | — |   |   |   | 465,942 |   |   | — |   |
| NET CASH USED IN  INVESTING ACTIVITIES                                             |       | (369,675                                                                                                  | )          |   | (103,900 | ) |   |   | (143,510 | ) |   |   | 465,942 |   |   | (151,143 | ) |
| NET CASH PROVIDED  BY (USED IN) FINANCING ACTIVITIES                               |       | 328,210                                                                                                   |       |   | 63,622 |   |   |   | 118,161 |   |   |   | (396,241 | ) |   | 113,752 |   |
| NET DECREASE IN CASH  AND CASH EQUIVALENTS                                         |       | 404                                                                                                       |       |   | 1,098 |   |   |   | 3,327 |   |   |   | — |   |   | 4,829 |   |
| CASH AND CASH  EQUIVALENTS, beginning of reporting period                          |       | 746                                                                                                       |       |   | 8,603 |   |   |   | 350 |   |   |   | — |   |   | 9,699 |   |
| CASH AND CASH  EQUIVALENTS, end of reporting period                                |       | $                                                                                                         | 1,150      |   |   | $ | 9,701 |   |   |   | $ | 3,677 |   |   |   | $ | — |   |   | $ | 14,528 |   |

 

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**ITEM2.**                Management’sDiscussion and Analysis of Financial Condition and Results of Operations

References in thisquarterly report on Form 10-Q to “Pacific Energy Partners,” “Partnership,”“we,” “ours,” “us” or like terms refer to Pacific Energy Partners, L.P. and itssubsidiaries.

**Forward-Looking Statements**

The information in this quarterly report on Form 10-Qcontains forward-looking statements within the meaning of Section 27Aof the Securities Act of 1933, and Section 21E of the Securities ExchangeAct of 1934. These forward-looking statements are identified as anystatements that do not relate strictly to historical or current facts,including statements that use terms such as “anticipate,” “assume,” “believe,” “estimate,”“expect,” “forecast,” “intend,” “plan,” “position,” “predict,” “project,” or “strategy”or the negative connotation or other variations of such terms or other similarterminology. In particular, statements express or implied, regarding our futureresults of operations or our ability to generate sales, income or cash flow orto make distributions to unitholders are forward-looking statements.Forward-looking statements are not guarantees of performance. Suchstatements are based on management’s current plans, expectations, estimates,assumptions and beliefs concerning future events impacting us and thereforeinvolve risks and uncertainties. Future actions, conditions or events andfuture results of operations may differ materially from those expressed inthese forward-looking statements. Many of the factors that will determinethese results are beyond our ability to control or predict.

We caution you that theforward-looking statements in this quarterly report on Form 10-Q aresubject to all of the risks and uncertainties, many of which are beyond ourcontrol, incident to gathering, transporting, storing, and distributing crudeoil, refined products and other related products, and buying and selling crudeoil. For a more detailed description of these and other factors that may affectthe forward-looking statements, please read “Risk Factors” contained inour annual report on Form 10-K for the year ended December 31, 2004,our Prospectus Supplement filed pursuant to Rule 424(b)(5) on September 9, 2005, as well asother filings with the SEC. The risk factors could cause our actual results todiffer materially from those contained in any forward-looking statement.You should not put undue reliance on these forward-looking statements. Wedisclaim any obligation to announce publicly the result of any revision to anyof the forward-looking statements to reflect future events ordevelopments.

**Introduction**

The following discussion of the financial conditionand results of operations of Pacific Energy Partners, L.P. should be readtogether with the condensed consolidated financial statements and the notesthereto set forth elsewhere in this report. The discussion set forth in thissection pertains to our unaudited condensed consolidated balance sheets,statements of income, statements of cash flows and statement of partners’capital.

This report on Form 10-Qshould be read in conjunction with our annual report on Form 10-K for theyear ended December 31, 2004.

**Overview**

We are a publicly traded limited partnership that was,during the period of this report, engaged principally in the business ofgathering, transporting, storing and distributing crude oil and relatedproducts in California and the Rocky Mountain region of the U.S. and inAlberta, Canada. We generated revenue primarily by charging tariff rates fortransporting crude oil on our pipelines and by leasing storage capacity. Wealso buy and sell crude oil, activities that are complementary to our pipelinetransportation business (see “Recent Developments—Acquisition of Assets fromValero, L.P.” below). We conduct our business through two business segments:the West Coast Business Unit and the Rocky Mountain Business Unit.

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We are managed by ourgeneral partner, Pacific Energy GP, LP (“General Partner”), which is in turnmanaged by its general partner, Pacific Energy Management LLC (“PEM or “ManagingGeneral Partner”). PEM has a board of directors that manages the business andaffairs of PEM and, thus, indirectly manages the business and affairs of ourGeneral Partner and the Partnership.

***Recent Developments***

***Acquisition of Assets from Valero, L.P.***

On September 30, 2005, we completed the purchaseof certain terminal and pipeline assets (the “Valero Acquisition”) from SupportTerminals Operating Partnership, L.P., Kaneb Pipe Line Operating Partnership,L.P. and Shore Terminals LLC (the “Sellers”) for an aggregate purchase price ofapproximately $455 million, plus $12.0 million for the assumption of certainenvironmental and operating liabilities and $3.4 million for closing costs. Valero,L.P. was required to divest these assets pursuant to an order from the FederalTrade Commission in connection with its acquisition of the Kaneb group ofcompanies. The assets purchased consist of (i) the Martinez terminal andRichmond terminal in the San Francisco, California area, (ii) the NorthPhiladelphia and South Philadelphia terminals and the Paulsboro, New Jerseyterminal in the Philadelphia, Pennsylvania area, and (iii) a 550-milerefined products pipeline with four terminals in the U.S. Rocky Mountains.

The Martinez and Richmond terminals currently have 4.1million barrels of combined storage capacity. The terminals handle refinedproducts, blend stocks and crude oil, and are connected to a network of ownedand third-party pipelines that carry crude oil and light products to and fromarea refineries. These terminals also receive and deliver crude oil and lightproducts by marine vessel or barge. The Richmond terminal has a rail spur fordelivery and receipt of light products and a truck rack for product delivery.

The North Philadelphia, the South Philadelphia and thePaulsboro, New Jersey terminals handle refined products and have a combinedstorage capacity of 3.1 million barrels. The terminals receive product viaconnections to third party pipelines and have truck racks for deliveries. TheNorth Philadelphia and Paulsboro terminals can also deliver and receiveproducts by marine vessel or barge.

The 550-mile refined products pipeline system, knownas the West Pipeline System, consists of 550 miles of pipeline extendingfrom Casper, Wyoming east to Rapid City, South Dakota and south to ColoradoSprings, Colorado. There are products terminals at Rapid City, South Dakota,Cheyenne, Wyoming and Denver and Colorado Springs, Colorado with a combinedstorage capacity of 1.7 million barrels. The West Pipeline System has varioussegments with different receipt and delivery points. The trunk line of thepipeline system has a current throughput capacity that ranges fromapproximately 35,000 to 40,000 barrels per day, depending on the segment.

We funded the ValeroAcquisition through a combination of proceeds from a private placement of 4.3 millioncommon units, a public equity offering of 5.2 million common units, a privateplacement of $175 million of senior unsecured notes and borrowings under ournew revolving credit facility (see below for a discussion of these newfinancing arrangements).

***Equity and Debt Offerings***

On September 14, 2005, we sold 4,550,000 commonunits at a public offering price of $32.00 per unit. On September 16,2005, the underwriters exercised their over-allotment option and purchased anadditional 682,500 common units at the same price. Net proceeds from theoffering and exercise of the underwriters option, including our General Partner’scontribution of $3.4 million, totaled approximately $163.4 million afterdeducting underwriting fees and offering expenses of $7.4 million. We usednet proceeds from the equity offering to partially fund the Valero Acquisition.

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On September 30, 2005, we sold 4,300,000 units pursuantto a Common Unit Purchase Agreement with certain institutional investors at aprice of $30.75 per unit. We received net proceeds of $131.8 million for thesale of the common units, including our General Partner’s contribution of $2.7million, which were used to partially fund the Valero Acquisition. We alsoentered into a Registration Rights Agreement with the institutional investors,whereby we agreed to file a registration statement with the SEC for the resalefrom time to time of the privately placed common units, such filing to be madewithin 90 days after the closing, and for the Partnership thereafter to usecommercially reasonable efforts to cause the shelf registration statement tobecome or be declared effective by the SEC within 180 days after the closingdate.

On September 23,2005, we completed the sale of $175 million of 61¤4% seniorunsecured notes due September 15, 2015. The notes were sold in a privateoffering to qualified institutional buyers in reliance on Rule 144A underthe Securities Act of 1933. The notes were sold for 99.544% of face valueresulting in an effective interest rate of 6.3125% to maturity. Net proceeds of$171.0 million from the sale of the notes, after deducting $0.8 milliondiscount and offering expenses of $3.2 million, were used to partially fund theValero Acquisition. Additionally, thePartnership entered into a registration rights agreement whereby it agreed,among other things, to file a registration statement with the SEC within 90days after the issue date of the notes enabling holders of the notes toexchange the privately placed notes for publicly registered notes withsubstantially identical terms, and to file a shelf registration statement forthe resale of the notes in certain circumstances. If the Partnership does notcomply with its obligations under the registration rights agreement, theinterest rate of the notes will increase.

***New Revolving Credit Facility***

On September 30, 2005, we entered into a newfive-year $400 million senior secured revolving credit facility (the “NewCredit Facility”) that replaced our previous U.S. and Canadian revolving creditfacilities. The New Credit Facility is available for general partnershippurposes in the U.S. and Canada, including working capital, letters of creditand distributions to unitholders (subject to certain limitations). The NewCredit Facility matures on September 30, 2010, and we may prepay all loansunder the New Credit Facility without premium or penalty. Obligations under theNew Credit Facility are guaranteed by all of our subsidiaries except those forwhich regulatory approval is required and are secured by substantially all ofour assets, excluding property held by the non-guaranteeing subsidiaries. TheNew Credit Facility is recourse to us and the guarantors, but non-recourse toour General Partner.

Included in the New CreditFacility is a Canadian sub-facility. The Canadian sub-facility currently has alimit of U.S.$100 million, but can be adjusted from time to time by us. TheCanadian sub-facility includes an option for us to receive loans in either U.S.dollars or Canadian dollars.

***Purchase of Crude Oil and Contracts***

On July 1, 2005, wepurchased certain crude oil contracts and crude oil inventories forapproximately $3.8 million plus contingent payments over the next three and onehalf years based on specified performance criteria. The assets were purchasedby the Partnership’s Pacific Marketing and Transportation (“PMT”) subsidiary.

***Line 63 Crude Oil Release***

On March 23, 2005, a release of approximately3,400 barrels of crude oil occurred on Line 63 when it was severed as a resultof a landslide induced by heavy rainfall in the Pyramid Lake area of LosAngeles County. Over the period March 2005 through March 2006, weexpect to incur an estimated total of $19.5 million for oil containmentand clean-up of the impacted areas, future monitoring costs, potentialthird-party claims and penalties, and other costs, excluding pipeline repaircosts. Through September 30, 

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2005, we had incurredapproximately $14.1 million of the total expected oil release costs for workperformed through such date.

We have a pollution liability insurance policy with a$2.0 million deductible, and the insurance carrier has, subject to the terms ofthe insurance policy, acknowledged coverage of the incident and is processingand paying invoices related to the clean-up. Although we believe we areentitled, subject to the $2.0 million deductible, to recover substantially allof our clean-up costs and third-party claims associated with the release, thereis no absolute assurance that this will be the case. As of September 30,2005, we have recovered $8.7 million from insurance and accrued a receivable of$8.8 million for insurance receipts we deem probable. As new informationbecomes available in future periods, our initial estimates of costs andrecoveries may change.

We recorded $2.0 million in net costs in “Line 63 oilrelease costs” in the accompanying condensed consolidated statements of incomefor the nine months ended September 30, 2005. The $2.0 million net oilrelease costs consist of $19.5 million of accrued costs relating to therelease, net of insurance recovery of $8.7 and accrued insurance receipts of$8.8 million.

On April 18, 2005, we received the necessaryapprovals to begin the repair of Line 63, and Line 63 was returned tooperation. During the time the pipeline was out of service, we transferredsignificant volumes of light crude oil, on a temporary basis, from Line 63 toLine 2000, to mitigate the impact on customers and limit the potential loss ofrevenue. We also asked our customers to shift volumes of OCS crude oil fromLine 63 to Line 2000. The permanent repair of Line 63 was completed in October 2005.We expensed $0.7 million, all in the second quarter, for the repair of Line 63and expect to incur $1.7 million of Line 63 capital improvements in the thirdand fourth quarters of 2005.

On July 21, 2005, theCalifornia Public Utilities Commission (“CPUC”) approved our request toimplement a temporary surcharge of $0.10 per barrel on our Line 63 long-haultariff rates to recover our costs relating to this release together with othercosts incurred or to be incurred as a result of problems caused by rain-inducedearth movement and stream erosion. The surcharge was effective on August 1,2005. We are required under the terms of the CPUC decision that approved thesurcharge to substantiate in subsequent filings with the CPUC the actual costsincurred by us as a result of the Line 63 damage and our entitlement to thesurcharge amounts received by us.

***Sale of The Anschutz Corporation’s Interest in thePartnership***

On March 3, 2005, The Anschutz Corporationcompleted the sale of its 36.6% interest in the Partnership to LB Pacific, LP (“LBP”),an entity formed by Lehman Brothers Merchant Banking Group (“LBMB”). Theacquisition by LBP (the “LB Acquisition”) included the purchase of a 100%ownership interest in Pacific Energy GP, Inc. (predecessor of PacificEnergy GP, LP), which owned (i) a 2% general partner interest in the Partnershipand the incentive distribution rights, and (ii) 10,465,000 subordinatedunits of the Partnership which represented a 34.6% limited partner interest. Immediatelyprior to the closing of the LB Acquisition, Pacific Energy GP, Inc. wasconverted to Pacific Energy GP, LLC, a Delaware limited liability company; andimmediately after the closing of the LB Acquisition, Pacific Energy GP, LLC wasconverted to Pacific Energy GP, LP, a Delaware limited partnership (togetherwith its predecessors, the “General Partner”). The general partner of PacificEnergy GP, LP is Pacific Energy Management LLC, a Delaware limited liabilitycompany (“PEM” or the “Managing General Partner”), which is 100% owned by LBP.Immediately following the closing of the LB Acquisition, our General Partnerdistributed the 10,465,000 subordinated units of the Partnership to LBP.

In connection with the conversion of our GeneralPartner to a limited partnership, our General Partner ceased to have a board ofdirectors, and is now managed by PEM, its general partner. PEM has a board ofdirectors (the “Board of Directors” or “Board”) that manages the business andaffairs of PEM and, thus, indirectly manages the business and affairs of ourGeneral Partner and the Partnership. All of 

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the officers and employeesof our General Partner were transferred to the same positions with PEM, and theBoard established the same committees as had been maintained by our GeneralPartner prior to the LB Acquisition. PEM also adopted our General Partner’sgovernance guidelines and its compensation structure and employee benefit plansand policies.

Pursuant to an Ancillary Agreement, LBP and TheAnschutz Corporation reimbursed us $2.4 million, which represents the costincurred by us in connection with a consent solicitation prepared and deliveredto the holders of our 71¤8%senior notes, due 2014 to approve certain amendments to the governingindenture, and for severance and other costs incurred in connection with thesale of our General Partner. We were required by generally accepted accountingprinciples to record $0.6 million as capitalized deferred financing costs and$1.8 million as an expense. The reimbursements were recorded as the GeneralPartner’s capital contribution.

On March 3, 2005, in connection with the changein control of our General Partner, all restricted units outstanding under theLong-Term Incentive Plan immediately vested pursuant to the terms of the grants.As a result, we issued 99,583 common units and recorded a compensation expenseof $3.1 million.

Because the LBAcquisition, together with other market activity, resulted in a change inownership of more than 50% of the Partnership within a one year period, federalincome tax laws require a modification to the Partnership’s 2005 taxableincome. The modification will result in a reduction in depreciation for 2005.The reduction in depreciation in 2005 will lead to additional depreciationbecoming available for recognition in future years. The modification of taxableincome will not have any impact on the Partnership’s consolidated financialstatements. For unitholders that purchased units in our 2002 initial publicoffering, or 2003 or 2004 equity offerings, we estimate that the amount oftaxable income for the years 2005 through 2008 will be less than 20% of thecash distributions made to unitholders. For investors that bought units in ourrecent public equity offering, we estimate that for the years 2005 through2008, taxable income to such unit holders will be less than 10% of the cashdistributions made to unitholders.

***Business Fundamentals***

***Pipeline Transportation***

We generate pipeline transportation revenue bycharging tariff rates for transporting crude oil on our common carrierpipelines. The fundamental items impacting our pipeline transportation revenueare the volume of crude oil, or throughput, that we transport on our pipelines,and our tariff rates. Throughput on our pipelines fluctuates based on thevolume of crude oil available for transport on our pipelines, the demand forrefined products, refinery or pipeline downtime and the availability ofalternate sources of crude oil for the refineries we serve.

Our shippers determine the amount of crude oil wetransport on our pipelines, but we influence these volumes through the leveland type of service we provide and the rates we charge. Our rates need to becompetitive to transportation alternatives, which are mostly other pipelines.

The tariff rates we charge on Line 2000 and theLine 63 system are regulated by the CPUC. Tariffs on Line 2000 areestablished based on market considerations, subject to certain contractuallimitations. Tariffs on Line 63, which are cost-of-service based tariffs,are based upon the costs to operate and maintain the pipeline, as well ascharges for the depreciation of the capital investment in the pipeline and theauthorized rate of return. The tariff rates charged on our U.S. Rocky Mountainpipelines are regulated by either the Federal Energy Regulatory Commission (“FERC”)or the Wyoming Public Service Commission, generally under a cost-of-serviceapproach.

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Following arerecent tariff rates increases on our pipelines:

·        EffectiveAugust 1, 2005, we implemented a temporary surcharge of $0.10 per barrelon our Line 63 long-haul tariff rates to recover our costs relating to the oilrelease (see “Line 63 Crude Oil Release” above) together with other costsincurred or to be incurred as a result of rain-induced earth movement andstream erosion.

·        OnJuly 1, 2005 we increased the tariff rates on our U.S. Rocky Mountainpipelines by 3.6% based on the FERC index adjustment.

·        OnMay 1, 2005 we increased the tariff rates on our Line 2000 byapproximately 4.8%.

·        EffectiveNovember 1, 2004, we increased the tariff rates on our Line 63 system by9.5%. This increase was the first for Line 63 since 2001.

·        OnMay 1, 2004, we increased the tariff rates on Line 2000 by approximately6%. This index is reviewed annually.

These tariff rate increases on our West Coastpipelines partially mitigate the impact of declining throughput.

The availability of crude oil for transportation onour pipelines is dependent, in part, on the amount of drilling and enhancedrecovery activity in the production fields we serve in our West Coastoperations and in parts of our Rocky Mountain operations. With the passage oftime, production of crude oil in an individual well naturally declines, whichcan in the short term, be offset in whole or in part, by additional drilling orthe implementation of recovery enhancement measures. In the San Joaquin Valleyand in the California Outer Continental Shelf (“OCS”), total production isgenerally declining.

In the Rocky Mountains,our pipelines are connected to Canadian sources of crude oil, and in 2004 wecompleted the acquisition of the Rangeland system, giving us greater access tosignificant supplies of Canadian crude oil, including synthetic crude oil,which we believe will replace any long term U.S. Rocky Mountain productiondeclines and meet growing demand in the U.S. Rocky Mountain region. We expectour initiating pump station in Edmonton, as well as a connection to a thirdparty pipeline providing access to synthetic crude oil, to be completed in thefourth quarter of 2005. It appears in recent months that production in the U.S.Rocky Mountains may be increasing with the increased amount of natural gasrelated drilling, which results in increased volumes of crude oil andcondensate. We believe, however, that the longer term production of crude oilin the U.S. Rocky Mountains will resume its historical decline.

***Storage and Distribution***

We provide storage and distribution services torefineries in the Los Angeles Basin through our Pacific Terminals (“PT”)storage and distribution system. The fundamental items impacting our storageand distribution revenue are the amount of storage capacity we have underlease, the lease rates for that capacity and the length of each lease. Demandfor crude oil storage capacity tends to be more stable over time, and leasesfor crude oil storage capacity are usually long term (more than one year).Demand for storage capacity for other dark products is less stable, and variesdepending on, among other things, refinery production runs and maintenanceactivities. Leases for dark products storage capacity are usually short term(less that one year). One of our business goals is to convert a number of darkproducts tanks to more flexible crude oil service (which can also accommodateother dark products); we are in the process of one such tank conversion andplan to convert a second tank in 2006.

While PT’s rates areregulated by the CPUC, the CPUC has authorized PT to establish its rates basedon market conditions through negotiated contracts.

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***Pipeline Buy/Sell Transportation***

Throughput on our Rangeland system, which was acquiredin the second quarter of 2004, varies with many of the same factors describedin “Pipeline Transportation” above. In addition, following completion of ourEdmonton initiation station, scheduled for the fourth quarter of 2005,throughput will vary with our success in attracting new supplies of syntheticcrude oil to our system.

We are making significant changes to the revenue-generatingcapability of the Rangeland system by (i) combining and fully integratingall of our Canadian and U.S. Rocky Mountain pipeline assets under commonmanagement, (ii) establishing connections with other pipelines, therebyexpanding the throughput capacity of the Rangeland system, and (iii) constructinga pump station and receiving terminal in Edmonton, Alberta. The development ofthe new receiving terminal and pump station, which will provide access tosynthetic and other types of Canadian crude oil, continues to progress. Constructionof this facility is expected to be completed in the fourth quarter of 2005, andadditional tanks along the pipeline corridor are scheduled to be complete inthe first quarter of 2006.

The Rangeland system operates as a proprietary systemand, therefore, we take title to the crude oil that is gathered andtransported. Pursuant to a transportation service agreement between two of oursubsidiaries, Rangeland Marketing Company (“RMC”) and Rangeland PipelinePartnership, RMC controls the entire capacity of Rangeland pipeline. Customerswho wish to transport product on Rangeland pipeline must either: (i) sellproduct to RMC at an inlet point and repurchase such product at agreed upondelivery points for the price paid at the inlet to the pipeline plus anestablished location differential; or (ii) sell product to RMC at theinlet to the pipeline without repurchasing product from RMC.

Virtually all of the pipelines that comprise theRangeland system are subject to the jurisdiction of the Alberta EnergyUtilities Board (“EUB”). A short segment of the Rangeland system that connectsto the Western Corridor system at the U.S.-Canadian border is subject tothe jurisdiction of the Canadian National Energy Board (“NEB”). Neither the EUBnor the NEB will generally review rates set by a crude oil pipeline operatorunless it receives a complaint relating to transportation rates.

Effective December 1,2004, we increased the location differentials on the Rangeland pipeline by anaverage of 10.8%.

***Gathering and Marketing***

Through our PMT subsidiary, we purchase, gather, andresell crude oil principally in California’s San Joaquin Valley and in theRocky Mountain area in the vicinity of our pipelines. Beginning in the thirdquarter of 2005, we also selectively purchase and resell crude oil in otherareas as well, although this is not a focus area of the Partnership

In California, our PMT gathering system is aproprietary intrastate operation that is not regulated by the CPUC or the FERC.It is complementary to our pipeline transportation business. The Californiagathering network effectively extends our pipeline network to capture suppliesof crude oil for transportation on our trunk pipelines to Los Angeles thatmight not otherwise be shipped through our pipelines. In the U.S. and CanadianRocky Mountain area, PMT facilitates transportation on our Canadian and U.S.Rocky Mountain pipelines by purchasing crude oil from Canada for resale in thePADD IV (Rocky Mountain) market place.

The contribution of ourPMT gathering operations is, for several reasons, a variable part of ourincome. First, it varies with the price differential between the cost of thevarying grades of crude oil that PMT buys for use in its gathering operations,and the price of the crude oil it sells. Costs and sales prices are generallyimpacted by crude oil prices, as well as by local supply and demand forces,including regulations affecting refined product specifications. Second, itvaries with the price differential between 

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crudeoil purchased on one price basis and sold on another price basis. Finally, itvaries with the volumes gathered. We seek to control these variations throughour risk management policy, which provides specific guidelines for our crudeoil marketing and hedging activities and requires oversight by our seniormanagement.

***Assets Acquiredfrom Valero, L.P.***

*West Pipeline System.**  *The West Pipeline System that weacquired from Valero is a common carrier petroleum products pipeline andterminals network. The system will generate revenues through transportationtariffs for volumes of petroleum products it ships. These tariffs varydepending upon where the product originates and, where ultimate delivery occurs.All transportation rates are market-based rates or published tariffs filed withthe FERC and other state agencies. The products terminals on the pipelinesystem also will earn revenues by providing additional services.

*Pacific AtlanticTerminals.**  *TheMartinez, Richmond, Paulsboro and Philadelphia terminals that we purchased fromValero are product (and, in the case of Martinez, crude oil) storage andterminaling facilities that will generate revenues primarily from fees that wecharge customers for storage, throughput and other services.

***Acquisitions andNew Projects***

We intend to continue topursue acquisitions and new projects for development of additional midstreamassets, including pipeline, storage and terminal facilities for both crude oiland refined products. We also intend to expand principally by acquisition intothe natural gas storage and transportation businesses. We expect theacquisitions and new projects to be accretive to our cash flow and complementour existing businesses. We expect to fund acquisitions and new projects with acombination of debt and additional Partnership units, including common units.We expect to maintain a debt to total capitalization ratio of approximately 50%over time.

***Operating Expenses***

A substantial portion ofthe operating expenses we incur, including the cost of field and supportpersonnel, maintenance, control systems, telecommunications, rights-of-way andinsurance, varies little with changes in throughput. Certain of our costs do,however, vary with throughput, the most material being the cost of power usedto run pump stations along our pipelines. Major maintenance costs can also varydepending on a particular asset’s age and/or regulatory requirements, such asmandatory inspections at defined intervals. Unanticipated costs can include thecosts of cleanup of any release of oil to the extent not covered by insurance,and repairs caused by severe weather as we have experienced in California andAlberta, Canada this year.

We do not have anyemployees, except in Canada. Our Managing General Partner provides employees toconduct our U.S. operations. We and our Managing General Partner collectivelyemploy approximately 400 individuals who directly support our operations. Weconsider employee relations to be good. None of these employees are subject toa collective bargaining agreement, except for eight employees at our Paulsboro,New Jersey terminal, who are members of USW District 10-286 (Steel Workers),with whom we expect to execute a collective bargaining agreement that will endon October 1, 2009. Our Managing General Partner does not conduct anybusiness other than with respect to the Partnership. All expenses incurred byour Managing General Partner are charged to us. Please read “Note 4—Related Party Transactions” in the footnotesto the condensed consolidated financial statement.

***Impact of ForeignExchange Rates***

Assets and liabilities ofour Canadian subsidiaries are translated to U.S. dollars using the applicable exchangerate as of the end of a reporting period. Revenues, expenses and cash flow aretranslated using 

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theaverage exchange rate during the reporting period. The reported cash flow ofour Canadian operations is based on the U.S. dollar equivalent of such amountsmeasured in Canadian dollars. The results of our Canadian operations anddistributions from our Canadian subsidiaries to the Partnership may vary inU.S. dollar terms based on fluctuations in currency exchange rates irrespectiveof our Canadian subsidiaries’ underlying operating results. In addition, theamount of monies we repatriate from Canada will vary with fluctuations incurrency exchange rates and may impact the cash available for distribution toour unitholders.

**CriticalAccounting Policies and Estimates**

Ourconsolidated financial statements are prepared in conformity with accountingprinciples generally accepted in the United States, which require management tomake estimates and assumptions that affect the reported amounts of the assetsand liabilities and disclosures of contingent assets and liabilities as of thedate of the balance sheet, as well as the reported amounts of revenue andexpenses during the reporting period. We routinely make estimates and judgmentsabout the carrying value of our assets and liabilities that are not readilyapparent from other sources. Such estimates and judgments are evaluated andmodified as necessary on an ongoing basis. We believe that of our significantaccounting policies (see “Note 1, Significant Accounting Policies,” to ourconsolidated financial statements in our annual report on Form 10-K forthe year ended December 31, 2004) and estimates, the following may involvea higher degree of judgment and complexity:

·       Weroutinely apply the provisions of purchase accounting when recording ouracquisitions. Application of purchase accounting requires that we estimate thefair value of the individual assets acquired and liabilities assumed (includingenvironmental remediation liabilities). Additionally, we must determine whetheran acquisition is considered to be a business or a set of net assets becauseexcess purchase price can only be allocated to goodwill in a businesscombination. The valuation of the fair value of the assets involves a number ofjudgments and estimates. In our major acquisitions to date, we have engaged anoutside valuation firm to provide us with an appraisal report, which weutilized in determining the purchase price allocation. The allocation of thepurchase price to different asset classes impacts the depreciation expense wesubsequently record. The principal assets we have acquired to date areproperty, pipelines, storage tanks and equipment.

·       Wedepreciate the components of our property and equipment on a straight-linebasis over the estimated useful lives of the assets. The estimates of theassets’ useful lives require our judgment and our knowledge of the assets beingdepreciated. When necessary, the assets’ useful lives are revised and theimpact on depreciation is treated on a prospective basis.

·       Weaccrue an estimate of the undiscounted costs of environmental remediation forwork at identified sites where an assessment has indicated it is probable thatcleanup costs are or will be required and may be reasonably estimated. In makingthese estimates, we consider information that is currently available, existingtechnology, enacted laws and regulations, and our estimates of the timing ofthe required remedial actions. We may use outside environmental consultants toassist us in making these estimates. We also are required to estimate theamount of any probable recoveries, including insurance recoveries. In addition,generally accepted accounting principles require us to establish liabilitiesfor the costs of asset retirement obligations when the retirement date isdeterminable. We will record such liabilities only when such date isdeterminable.

·       Fromtime to time, a shipper or group of shippers may initiate a regulatoryproceeding or other action, challenging the tariffs we charge or have charged.In such cases, we assess the proceeding on an ongoing basis as to its likelyoutcome, in order to determine whether to accrue for a future expense. We useoutside regulatory lawyers and financial experts to assist us in theseassessments.

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·       Our inventory of crude oilfor our PMT gathering operations, our Canadian operations and any inventoryearned through our tariffs for the transportation of crude oil in our commoncarrier pipelines is carried on our books at the lower of cost or market value,unless it is hedged, in which case it is carried at market. On any unhedgedportion, we are exposed to the potential for a write-down to market value.

**Results of Operations**

Internally, in our analysis of operating results, weconsider the impact of unusual items that we believe affect comparabilitybetween periods. We also believe that providing a discussion and analysis ofour results that is comparable year over year, provides a more accurate andthorough analysis of our results of operations. We have provided areconciliation of net income to the results of our operations, excluding thoseunusual items, in our analyses below. Following is a discussion of each of theunusual items that impacted the results of our operations.

*Oilrelease on Line 63.**  *As a result of the March 23, 2005 release ofcrude oil from PPS’s Line 63, we recorded $2.0 million net oil releasecosts in the first quarter of 2005, consisting of $19.5 million of accruedcosts relating to the release, net of insurance recovery of $8.7 million andaccrued insurance receipt of $8.8 million. The discussion in “Recent Developments” describes the nature of theseestimates and the potential for these estimates to increase or decrease infuture periods.

*Acceleratedlong-term incentive plan compensation expense.**  *On March 3, 2005, in connection with the changein control of our General Partner, all restricted units outstanding under theLong-term Incentive Plan immediately vested. As a result, we recognized $3.1million in compensation expense in the first quarter of 2005.

*Transactioncosts.**  *Pursuantto an Ancillary Agreement, LBP and The Anschutz Corporation reimbursed us $2.4million for the cost incurred in connection with a consent solicitationprepared and delivered to the holders of our 71¤8%****senior notes to approve certain amendments to the governingindenture and for severance and other costs incurred in connection with thesale of our General Partner. We were required by generally accepted accountingprinciples to record $0.6 million as capitalized deferred financing costs and$1.8 million as an expense, both in the first quarter of 2005. Thereimbursements were recorded as a partner’s capital contribution.

*Write-off of deferredfinancing cost and interest rate swap termination expense.**  *In the second quarter of 2004, we recorded an expenserelated to the unamortized portion of deferred financing costs of $2.3 millionfor our term loan, which was repaid in 2004, and incurred $0.6 million ofexpense to terminate related interest rate swaps.

***Three Months Ended September 30, 2005 Compared toThree Months Ended September 30, 2004***

***Summary***

Net income for the three months ended September 30,2005 was $12.2 million, or $0.39 per diluted limited partner unit, compared to$9.9 million, or $0.33 per diluted limited partner unit, for the three monthsended September 30, 2004.

The result of operationsfor the three months end September 30, 2005 reflects the benefit of (i) increasedpipeline volumes in the Rocky Mountains, (ii) higher tank utilization andadditional storage capacity for Pacific Terminals and (iii) higherlocation differentials on the Rangeland system and greater marketing income. Theseincreases were partly offset by (i) tank maintenance on our PacificTerminals storage and distribution system and (ii) lower volumes on ourWest Coast pipelines.

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***Segment Information***

Thefollowing is a discussion of segment operating income. Segment operating incomedoes not include general and administrative expenses, accelerated long-termincentive compensation plan expense and transaction costs as these items arenot allocated to the West Coast and Rocky Mountain business units.

| ** **                 | ** ** | **Three Months  Ended September 30,** | ** ** | ** **                                                           | ** ** | ** **                                                           | ** ** |
|----------------------------|------------|------------------------------------------------------|------------|----------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|
| **West Coast**        | ** ** | ** **                                           | ** ** | **     2005     ** | ** ** | **     2004     ** | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                 | ** ** | **(In thousands)**                              | ** ** | ** **                                                           | ** ** |
| Operating income           |       |                                                 | $          | 9,813                                                                |       |                                                                 |       | $ | 11,355 |   |   | $ | (1,542 | ) |   | (14 | )% |   |
| Operating data:            |       |                                                 |       |                                                                 |       |                                                                 |       |   |   |   |   |   |   |   |   |
| Pipeline  throughput (bpd) |       |                                                 | 104.4      |                                                                 |       |                                                                 | 139.7      |   |   | (35.3 | ) |   | (25 | )% |   |
|                            |            |                                                      |            |                                                                      |            |                                                                      |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

Forthe three months ended September 30, 2005, operating income was $9.8million, compared to $11.4 million for the three months ended September 30,2004. West Coast pipeline volumes for the three months ended September 30,2005 were approximately 25% lower than the third quarter of 2004 because in2005 there was (i) diversion by our customers of some volumes north to SanFrancisco, reducing the supply of crude oil available to be moved south to LosAngeles, (ii) refinery maintenance in the L.A. Basin, which resulted inlower volumes moving south to Los Angeles, (iii) lower OCS production dueto maintenance activities, and (iv) natural production decline of SanJoaquin Valley crude and OCS crude oil. These conditions were partially offsetby increased tariffs on our pipelines, higher operating income on our PacificTerminals storage and distribution system resulting from higher lease fees,increased tank utilization and an increase in tank storage capacity. Increasesin revenues on our Pacific Terminals storage and distribution system werepartially offset by higher tank maintenance costs.

| ** **                  | ** ** | **Three Months  Ended September 30,** | ** ** | ** **                                                           | ** ** | ** **                                                           | ** ** |
|-----------------------------|------------|------------------------------------------------------|------------|----------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|
| **Rocky Mountains**    | ** ** | ** **                                           | ** ** | **     2005     ** | ** ** | **     2004     ** | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                  | ** ** | **(In thousands)**                              | ** ** | ** **                                                           | ** ** |
| Operating income            |       |                                                 | $          | 13,644                                                               |       |                                                                 |       | $ | 7,533 |   |   | $ | 6,111 |   |   | 81 | % |   |
| Operating data (bpd):       |       |                                                 |       |                                                                 |       |                                                                 |       |   |   |   |   |   |   |   |   |
| Rangeland  pipeline system: |       |                                                 |       |                                                                 |       |                                                                 |       |   |   |   |   |   |   |   |   |
| Sundre—North           |       |                                                 | 19.3       |                                                                 |       |                                                                 | 21.8       |   |   | (2.5 | ) |   | (11 | )% |   |
| Sundre—South           |       |                                                 | 48.1       |                                                                 |       |                                                                 | 46.8       |   |   | 1.3 |   |   | 3 | % |   |
| Western Corridor system     |       |                                                 | 26.8       |                                                                 |       |                                                                 | 23.1       |   |   | 3.7 |   |   | 16 | % |   |
| Salt Lake City Core system  |       |                                                 | 125.6      |                                                                 |       |                                                                 | 122.6      |   |   | 3.0 |   |   | 2 | % |   |
| Frontier pipeline           |       |                                                 | 49.6       |                                                                 |       |                                                                 | 51.4       |   |   | (1.8 | ) |   | (4 | )% |   |
|                             |            |                                                      |            |                                                                      |            |                                                                      |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

For the three months ended September 30, 2005,operating income was $13.6 million, compared to $7.5 million for the threemonths ended September 30, 2004. Increased market share for pipelineshipments of crude oil to Billings, Montana and increased demand by the SaltLake City, Utah refineries helped drive higher pipeline volumes on the U.S.Rocky Mountain systems. We also increased some tariffs on July 1, 2005. Rangeland’soperating income increased due to higher location differentials, higherpipeline volumes moving south and increased marketing income. Frontier pipelinevolumes decreased in the third quarter of 2005 over the same period in 2004,because of reduced volumes of synthetic crude oil.

During the quarter ended September, 30, 2005,management identified a control deficiency related to the accounting forinventory and cost of goods sold for our Rangeland pipeline since itsacquisition in May 2004. This deficiency resulted in an understatement of“Pipeline buy/sell transportation revenue” (revenue is presented net of cost ofgoods sold) and a corresponding understatement of the inventory balance inprior quarters. Although this deficiency resulted in an error in priorquarters, management assessed the 

37

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materiality of the impacton the second, third and fourth quarters of 2004 and the first and secondquarters of 2005 and concluded that this error was not material to thepreviously issued historical financial statements, nor was the cumulativecorrection material to the third quarter 2005 financial statements. In thequarter ended September 30, 2005, the cumulative correction resulted in anincrease to the Rocky Mountain Business Unit’s pre-tax income of $1.2 million (resultingin a $0.7 million after tax increase to the Partnership’s net income). Therewas no impact to the Partnership’s cash flow from operating activities for anyof the prior quarters or for the quarter ended September 30, 2005. Managementconcluded that this control deficiency was not a material weakness due to theexistence of compensating controls. Management has implemented new proceduresto fully remediate the control deficiency.

***Statement of Income—Discussion and Analysis***

| ** **                                | ** ** | **Three Months  Ended September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-------------------------------------------|------------|------------------------------------------------------|------------|------------|------------|------------|------------|
| **Revenues**                              | ** ** | ** **                                           | ** ** | **2005**   | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                | ** ** | **(In thousands)**                              | ** ** | ** ** | ** ** |
| Pipeline  transportation revenue          |       | $                                                    | 27,283     |       | $          | 28,160     |       | $ | (877 | ) |   | (3 | )% |   |
| Storage and  distribution revenue         |       | 9,731                                                |       | 8,391      |       | 1,340      |       |   | 16 | % |   |
| Pipeline buy/sell  transportation revenue |       | 11,683                                               |       | 7,972      |       | 3,711      |       |   | 47 | % |   |
| Crude oil sales, net of  purchases:       |       |                                                 |       |       |       |       |       |   |   |   |   |
| Crude oil sales                           |       | 194,724                                              |       | 106,760    |       | 87,964     |       |   | 82 | % |   |
| Crude oil purchases                       |       | (188,901                                             | )          | (103,192   | )          | 85,709     |       |   | 83 | % |   |
| Crude oil sales, net of purchases         |       | 5,823                                                |       | 3,568      |       | 2,255      |       |   | 63 | % |   |
| Net revenue                               |       | $                                                    | 54,520     |       | $          | 48,091     |       | $ | 6,429 |   |   | 13 | % |   |
|                                           |            |                                                      |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

Increased pipeline transportationrevenues were realized by our U.S. Rocky Mountain pipelines. Volumes onthe U.S. Rocky Mountain pipelines were higher due to increased demand byrefineries in Billings, Montana, Casper, Wyoming and Salt Lake City, Utah arearefineries. Our West Coast pipelines had lower revenues compared to the prior yearfor several reasons, as noted above. The reduction in volumes on our West Coastpipeline was partially offset by increased tariff rates that were implementedin the fourth quarter of 2004 on Line 63, in the second quarter of 2005 forLine 2000, and a temporary surcharge implemented in the third quarter of 2005for Line 63 to recover rain-related repair costs and our costs for the PyramidLake oil release. 

Storage and distribution revenue is higher than theprior year due to higher lease fees, increased tank utilization and an increasein storage capacity (an idle 72,000 barrel tank was put back into service atthe end of the third quarter of 2004).

Pipeline buy/sell transportation revenues of $11.7million is higher than the prior year because of higher location differentialscharged on the Rangeland pipelines and higher volumes being transported southto the Canadian border. In December 2004, we increased the locationdifferentials on the Rangeland pipeline by an average of 10.8%.

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The increasein net crude oil sales for the three months ended September 30, 2005 was theresult of additional contracts acquired on July 1, 2005 as well as fromincreased margin gathering activities in our West Coast operations. Additionally,in 2004, margins on one particular contract declined as the difference betweenpurchases made on a WTI price basis and sales on a West Coast price basisdeviated from historical norms over the period from September 2004 throughMarch 2005. This contract expired on March 31, 2005.

| ** **                             | ** ** | **Three Months  Ended September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|----------------------------------------|------------|------------------------------------------------------|------------|------------|------------|------------|------------|
| **Expenses**                           | ** ** | ** **                                           | ** ** | **2005**   | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                             | ** ** | **(In thousands)**                              | ** ** | ** ** | ** ** |
| Operating  expenses                    |       | $                                                    | 25,019     |       | $          | 22,788     |       | $ | 2,231 |   |   | 10 | % |   |
| General and  administrative expense    |       | 4,115                                                |       | 3,762      |       | 353        |       |   | 9 | % |   |
| Depreciation and  amortization expense |       | 6,560                                                |       | 6,821      |       | (261       | )          |   | (4 | )% |   |
|                                   |       | $                                                    | 35,694     |       | $          | 33,371     |       | $ | 2,323 |   |   | 7 | % |   |
|                                        |            |                                                      |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

Operating expenses increased forseveral reasons. First, we had higher tank maintenance costs on ourPacific Terminals storage and distribution system and a greater number of majormaintenance projects elsewhere. Second, we experienced higher power andtrucking costs, both of which were incurred to generate increased revenues.

Increases in general and administrative expenseresulted from our corporate development activities and from increased crude oilmarketing, which were partially offset by the absence of an expense for thelong term incentive plan. 

Depreciationand amortization expense decreased primarily because of assets that have nowbeen fully depreciated.

| ** **                                  | ** ** | **Three Months  Ended September 30,** | ** ** | ** **                                   | ** ** | ** **                                   | ** ** |
|---------------------------------------------|------------|------------------------------------------------------|------------|----------------------------------------------|------------|----------------------------------------------|------------|
| **Other Income and Expense** | ** ** | ** **                                           | ** ** | **   2005   ** | ** ** | **   2004   ** | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                  | ** ** | **(In thousands)**                              | ** ** | ** **                                   | ** ** |
| Share of net  income of Frontier            |       |                                                 | $          | 516                                          |       |                                         |       | $ | 406 |   |   | $ | 110 |   |   | 27 | % |   |
| Interest expense                            |       |                                                 | $          | 6,237                                        |       |                                         |       | $ | 5,234 |   |   | $ | 1,003 |   |   | 19 | % |   |
| Other income                                |       |                                                 | $          | 494                                          |       |                                         |       | $ | 219 |   |   | $ | 275 |   |   | 126 | % |   |
| Income tax  expense                         |       |                                                 | $          | 1,433                                        |       |                                         |       | $ | 221 |   |   | $ | 1,212 |   |   | 548 | % |   |
|                                             |            |                                                      |            |                                              |            |                                              |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

The increase in our share of Frontier’s net income wasmainly attributable to lower operating costs at Frontier. 

The increase in interest expense was due to additionalborrowings incurred to fund our profit generating capital spending projects. Inaddition, we completed a senior notes offering to partially fund theacquisition of assets from Valero, L.P. on September 23, 2005 and, pending theclosing of the acquisition, temporarily invested the proceeds, which resultedin increased other income as noted below. Our weighted average borrowingsduring the three months ended September 30, 2005 were $352 millioncompared to $335 million in the corresponding period in 2004. In addition,floating interest rates were higher in 2005, which resulted in a weightedaverage interest rate of 7.0% for the three months ended September 30, 2005compared to a weighted average interest rate of 5.8% for the correspondingperiod in 2004.

Other income of $0.5 million for the period ended September30, 2005 was $0.3 million greater than the corresponding period in 2004 due toincreased interest income and other items.

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Income tax expense is afunction of the income of our Canadian subsidiaries, which are taxable entities.In addition, certain kinds of repatriation of funds into the U.S. subject thePartnership to Canadian withholding tax.

***Nine Months Ended September 30, 2005 Compared to NineMonths Ended September 30, 2004***

***Summary***

Net income for the nine months ended September 30,2005 was $27.8 million, or $0.96 per diluted limited partner unit, compared to$27.1 million, or $0.94 per diluted limited partner unit, for the nine monthsended September 30, 2004.

Net income for the nine months ended September 30,2005 includes nine months of operations of the Rangeland system. The Rangelandsystem was acquired on May 11, 2004 and expanded by the acquisition of the MAPLpipeline on June 30, 2004.

Followingis a reconciliation of net income to the results of our operations, excluding unusualitems mentioned above:

| ** **                                                                            | ** ** | **Nine Months  Ended September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|---------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|------------|------------|------------|------------|
| ** **                                                                            | ** ** | **2005**                                            | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                                                            | ** ** | **(In thousands)**                             | ** ** | ** ** | ** ** |
| Net income                                                                            |       | $                                                   | 27,807     |       | $          | 27,095     |       | $ | 712 |   |   | 3 | % |   |
| Add:  Line  63 oil release costs                                            |       | 2,000                                               |       | —     |       | 2,000      |       |   | — |   |   |
| Accelerated long-term incentive compensation expense                             |       | 3,115                                               |       | —     |       | 3,115      |       |   | — |   |   |
| Transaction costs                                                                     |       | 1,807                                               |       | —     |       | 1,807      |       |   | — |   |   |
| Write-off of deferred financing cost and interest rate  swap termination expense |       | —                                              |       | 2,901      |       | (2,901     | )          |   | — |   |   |
|                                                                                  |       | $                                                   | 34,729     |       | $          | 29,996     |       | $ | 4,733 |   |   | 16 | % |   |
| Diluted weighted average limited partner units                                        |       | 30,051                                              |       | 28,125     |       | 1,926      |       |   | 7 | % |   |

 

The improvement in the results of operations,excluding the effect of the unusual items mentioned above, reflects the benefitof (i) the operations of the Rangeland system acquired in May 2004, (ii) higherpipeline transportation revenues on the Rocky Mountain pipelines, and (iii) higherstorage and distribution revenues on our Pacific Terminal systems.

These increases were partially offset by (i) lowergathering margins, which were below average for the nine months ended September30, 2005 and above average in the nine months ended September 30, 2004, (ii) unscheduledrepairs and maintenance associated with earth movement and stream erosionproblems caused by heavy rainfall in Southern California during the early partof 2005, and (iii) unscheduled repairs for our Pacific Terminals storagefacilities in 2005. The lower margins on our West Coast gathering activitieswere due to competitive pricing pressures as a result of cheaper foreign crudeentering the West Coast markets. 

There were 30.1 millionweighted average limited partner units outstanding in the nine months ended September30, 2005, approximately 7% more limited partner units than the 28.1 millionweighted average units outstanding in the nine months ended September 30, 2004,primarily due to the sale in mid-September 2005 of additional common units topartially fund the acquisition of assets from Valero, L.P. on September 30,2005.

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***Segment Information***

The followingis a discussion of segment operating income. Segment operating income does notinclude general and administrative expenses, accelerated long-term incentivecompensation plan expense and transaction costs as these items are notallocated to the West Coast and Rocky Mountain business units.

| ** **                     | ** ** | **Nine Months  Ended September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|--------------------------------|------------|-----------------------------------------------------|------------|------------|------------|------------|------------|
| **West Coast**            | ** ** | ** **                                          | ** ** | **2005**   | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                     | ** ** | **(In thousands)**                             | ** ** | ** ** | ** ** |
| Operating income               |       | $                                                   | 31,962     |       | $          | 37,702     |       | $ | (5,740 | ) |   | (15 | )% |   |
| Add: Line 63 oil  release cost |       | 2,000                                               |       | —     |       | 2,000      |       |   | — |   |   |
|                           |       | $                                                   | 33,962     |       | $          | 37,702     |       | $ | (3,740 | ) |   | (10 | )% |   |
| Operating data:                |       |                                                |       |       |       |       |       |   |   |   |   |
| Pipeline  throughput (bpd)     |       | 120.8                                               |       | 137.6      |       | (16.8      | )          |   | (12 | )% |   |
|                                |            |                                                     |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

For the nine monthsended September 30, 2005, operating income excluding the effect of the $2.0 millionexpense for the Line 63 oil release was $34.0 million, compared to $37.7million for the nine months ended September 30, 2004. The reasons for thedecrease were as follows:

·       WestCoast pipeline volumes for the nine months ended September 30, 2005 wereapproximately 12% lower than the same period in 2004. During the nine monthsended September 30, 2005, volumes were impacted by Los Angeles area refinerymaintenance and lower San Joaquin Valley and OCS production, resulting in lowervolumes moving south to Los Angeles. There were $2.4 million ofunscheduled repairs and maintenance associated with earth movement and streamerosion problems at various locations along both Line 63 and Line 2000, causedby heavy rainfall in Southern California. The revenue effect of lower volumeswas offset by incremental revenue from increased tariffs on Line 63 beginningNovember 1, 2004, on Line 2000 beginning May 1, 2005, and on Line 63 beginningAugust 2005 from a temporary surcharge to recover the rain-related repair costsand our Pyramid Lake oil release costs.

·       PMTgathering margins were also lower in 2005 due to pricing pressures fromdiscounted crude oil imports and margins on one particular contract whichexpired on March 31, 2005.

Storageand distribution revenues were higher during the nine months ended September30, 2005, due to higher rates of tank utilization and 72,000 barrels ofadditional tank capacity being made available as a result of an idle tank beingput into service at the end of the third quarter of 2004. These increasedrevenues were partially offset by increased tank maintenance costs.

| ** **                  | ** ** | **Nine Months  Ended September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-----------------------------|------------|-----------------------------------------------------|------------|------------|------------|------------|------------|
| **Rocky Mountains**    | ** ** | ** **                                          | ** ** | **2005**   | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                  | ** ** | **(In thousands)**                             | ** ** | ** ** | ** ** |
| Operating income            |       | $                                                   | 32,183     |       | $          | 16,890     |       | $ | 15,293 |   |   | 91 | % |   |
| Operating data (bpd):       |       |                                                |       |       |       |       |       |   |   |   |   |
| Rangeland  pipeline system: |       |                                                |       |       |       |       |       |   |   |   |   |
| Sundre—North           |       | 21.3                                                |       | 21.6       |       | (0.3       | )          |   | (1 | )% |   |
| Sundre—South           |       | 45.3                                                |       | 47.6       |       | (2.3       | )          |   | (5 | )% |   |
| Western Corridor system     |       | 24.0                                                |       | 19.6       |       | 4.4        |       |   | 22 | % |   |
| Salt Lake City Core system  |       | 119.8                                               |       | 116.1      |       | 3.7        |       |   | 3 | % |   |
| Frontier pipeline           |       | 46.4                                                |       | 48.5       |       | (2.1       | )          |   | (4 | )% |   |
|                             |            |                                                     |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

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For the nine months ended September30, 2005, operating income was $32.2 million, compared to $16.9 million for thenine months ended September 30, 2004. The increase included the results of theRangeland system, which was acquired on May 11, 2004. In addition, increasedmarket share for pipeline shipments of crude oil to Billings, Montana, andincreased demand by the Salt Lake City, Utah, refineries, helped drive higherpipeline volumes on the U.S. Rocky Mountain systems other than Frontierpipeline. Frontier pipeline volumes in 2005 were affected by a shortage ofsynthetic crude oil supply caused by a fire at a Suncor Energy, Inc. facilityin December 2004. Shippers have now replaced these volumes with other types ofcrude oil and volumes returned to more normal levels in the second quarter ofthis year.

***Statement of Income—Discussion and Analysis***

| ** **                                | ** ** | **Nine Months  Ended September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-------------------------------------------|------------|-----------------------------------------------------|------------|------------|------------|------------|------------|
| **Revenues**                              | ** ** | ** **                                          | ** ** | **2005**   | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                | ** ** | **(In thousands)**                             | ** ** | ** ** | ** ** |
| Pipeline  transportation revenue          |       | $                                                   | 83,067     |       | $          | 79,879     |       | $ | 3,188 |   |   | 4 | % |   |
| Storage and  distribution revenue         |       | 30,923                                              |       | 27,773     |       | 3,150      |       |   | 11 | % |   |
| Pipeline buy/sell  transportation revenue |       | 28,905                                              |       | 11,662     |       | 17,243     |       |   | 148 | % |   |
| Crude oil sales, net of  purchases:       |       |                                                |       |       |       |       |       |   |   |   |   |
| Crude oil sales                           |       | 439,380                                             |       | 293,125    |       | 146,255    |       |   | 50 | % |   |
| Crude oil purchases                       |       | (425,733                                            | )          | (278,689   | )          | 147,044    |       |   | 53 | % |   |
| Crude oil sales, net of purchases         |       | 13,647                                              |       | 14,436     |       | (789       | )          |   | (5 | )% |   |
| Net revenue                               |       | $                                                   | 156,542    |       | $          | 133,750    |       | $ | 22,792 |   |   | 17 | % |   |
|                                           |            |                                                     |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

Increased pipeline transportationrevenues were realized by our U.S. Rocky Mountain pipelines. Volumes onthe U.S. Rocky Mountain pipelines were higher due to increased demand byrefineries in Billings, Montana, Casper, Wyoming and Salt Lake City, Utah arearefineries. The revenue effect of lower volumes on the West Coast pipelines waspartly offset by higher tariffs.

Storage and distribution revenues were higher than thesame period in 2004 due to higher rates of tank utilization and increasedcapacity being made available as a result of a 72,000 barrel idle tank beingput into operation during the third quarter of 2004.

The increase in pipeline buy/sell transportationrevenues of $17.2 million reflects a full nine months of operations of theRangeland system, which was acquired on May 11, 2004, as well as anincrease in location differentials on December 1, 2004.

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Thedecrease in net crude oil sales for the nine months ended September 30,2005 was primarily the result of lower margin gathering activities in our WestCoast operations, particularly due to competitive pricing pressures fromcheaper foreign crude entering the West Coast markets. Additionally, margins onone particular contract declined as the difference between purchases made on aWTI price basis deviated from historical norms over the period from September 2004through March 2005. This contract expired on March 31, 2005. Higheroil prices increased gross sales and purchases values. In addition, we acquiredadditional crude oil contracts on July 1, 2005.

| ** **                                                 | ** ** | **Nine Months  Ended September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------------------------------------------------------|------------|-----------------------------------------------------|------------|------------|------------|------------|------------|
| **Expenses**                                               | ** ** | ** **                                          | ** ** | **2005**   | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                                 | ** ** | **(In thousands)**                             | ** ** | ** ** | ** ** |
| Operating  expenses                                        |       | $                                                   | 72,065     |       | $          | 62,572     |       | $ | 9,493 |   |   | 15 | % |   |
| Line 63 oil  release costs                                 |       | 2,000                                               |       | —     |       | 2,000      |       |   | — |   |   |
| General and  administrative expense                        |       | 12,987                                              |       | 11,252     |       | 1,735      |       |   | 15 | % |   |
| Accelerated  long-term incentive plan compensation expense |       | 3,115                                               |       | —     |       | 3,115      |       |   | — |   |   |
| Transaction costs                                          |       | 1,807                                               |       | —     |       | 1,807      |       |   | — |   |   |
| Depreciation and  amortization expense                     |       | 19,695                                              |       | 17,776     |       | 1,919      |       |   | 11 | % |   |
|                                                       |       | $                                                   | 111,669    |       | $          | 91,600     |       | $ | 20,069 |   |   | 22 | % |   |
|                                                            |            |                                                     |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

The increase in operating expense was relatedprimarily to the acquisition of the Rangeland system on May 11, 2004. Operatingexpenses in the West Coast were also higher as a result of $2.4 million ofunscheduled repairs and maintenance and expenses on Line 2000 and Line 63resulting from earth movements and creek washouts caused by heavy rains. Inaddition, tank maintenance expense was greater for Pacific Terminals in 2005.

The Line 63 oil release costs are discussed in “RecentDevelopments” above.

The increase in general and administrative expense wasassociated with the integration and operation of the Rangeland acquisition andcertain expensed costs for the Pier 400 project (see “Capital Requirements”below for a discussion of the Pier 400 Project). These items were notapplicable in the corresponding period of 2004. In addition, we incurred morecosts for acquisition evaluations in 2005. These increases were partly offsetby reduced costs for the Long Term Incentive Plan included in general andadministrative expense.

Transaction costs are discussed in “RecentDevelopments” above.

On March 3, 2005, in connection with the changein control of the General Partner, all restricted units outstanding under theLong-term Incentive Plan immediately vested. For the nine months ended September 30,2005, we recognized $3.1 million in compensation expense as a result.

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Theincrease in depreciation and amortization includes $2.3 million fordepreciation on the Rangeland system. This increase was partly offset by lowerdepreciation on other assets reflecting assets that have now been fullydepreciated.

| ** **                                                                            | ** ** | **Nine Months  Ended September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|---------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|------------|------------|------------|------------|
| **Other Income and Expense**                                           | ** ** | ** **                                          | ** ** | **2005**   | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                                                            | ** ** | **(In thousands)**                             | ** ** | ** ** | ** ** |
| Share of net  income of Frontier                                                      |       | $                                                   | 1,363      |       | $          | 1,190      |       | $ | 173 |   |   | 15 | % |   |
| Interest expense                                                                      |       | $                                                   | 17,679     |       | $          | 13,743     |       | $ | 3,936 |   |   | 29 | % |   |
| Write-off of deferred financing cost and interest  rate swap termination expense |       | $                                                   | —     |       | $          | 2,901      |       | $ | (2,901 | ) |   | — |   |   |
| Other income                                                                          |       | $                                                   | 1,387      |       | $          | 606        |       | $ | 781 |   |   | 129 | % |   |
| Income tax  expense                                                                   |       | $                                                   | 2,137      |       | $          | 207        |       | $ | 1,930 |   |   | 932 | % |   |
|                                                                                       |            |                                                     |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

The increase in our share of Frontier’s net income wasmainly attributable to lower operating costs at Frontier.

The increase in interest expense was due to borrowingsincurred to partially fund the acquisition of the Rangeland system and due tohigher floating interest rates. Our weighted average borrowings during the ninemonths ended September 30, 2005 were $359 million compared to$304 million in the corresponding period in 2004. In addition, floatinginterest rates were higher in 2005, which resulted in a weighted averageinterest rate of 6.6% for the period ended September 30, 2005 compared toa weighted average interest rate of 5.8% for the corresponding period in 2004.

The write-off of deferred financing cost and interestrate swap termination expense are discussed in “Results of Operations” above.

Other income of $1.4 million for the period ended September 30,2005 was $0.8 million greater than the corresponding period in 2004 due toincreased interest income and other items.

The increase in income taxexpense for the nine months ended September 30, 2005 relates to the incomeof the Rangeland system acquired on May 11, 2004. Our Canadiansubsidiaries are taxable entities and certain kinds of repatriation of fundsinto the U.S. are subject to Canadian withholding tax.

**Liquidityand Capital Resources**

We believe that cash generated from operations,together with our cash balance and our unutilized borrowing capacity, will besufficient to meet our planned distributions, our working capital requirementsand our anticipated sustaining capital expenditures in the next three years.

We intend to finance our future acquisitions anddevelopment projects, including our Pier 400 project, with issuances ofdebt and equity securities. We expect to maintain a debt to totalcapitalization ratio of approximately 50% over time.

We have received approval from the CPUC to sellsurplus Pacific Terminals properties, which we believe are worth approximately$10 million. We expect to close on the sale of the first of these properties inNovember 2005 for net proceeds of $1.6 million, an amount approximatelyequal to its book value.

Our ability to satisfy our debt service obligations,fund planned capital expenditures, make acquisitions, develop projects and paydistributions to our unitholders will depend upon our future operatingperformance. Our operating performance is primarily dependent on the volume ofcrude oil and refined products transported through our pipelines and the volumeleased in our storage tanks as described in “Overview” above. Our operatingperformance is also affected by prevailing economic 

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conditions in the crudeoil and refined products industry and financial, business and other factors,some of which are beyond our control, which could significantly impact futureresults.

We expect, subject toBoard approval, to increase our cash distribution to unitholders by $0.0425 perunit for the fourth quarter of 2005 to $0.555 per unit per quarter, or $2.22per unit annually, as a result of the acquisition of assets from Valero, L.P.and the expected completion of our Edmonton, Alberta, initiating station in thefourth quarter of 2005.

***Operating,Investing and Financing Activities***

| ** **                                           | ** ** | **Nine months  Ended September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------------------------------------------------|------------|-----------------------------------------------------|------------|------------|------------|------------|------------|
| ** **                                           | ** ** | **2005**                                            | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                           | ** ** | **(In thousands)**                             | ** ** | ** ** | ** ** |
| Net cash provided  by operating activities           |       | $                                                   | 65,655     |       | $          | 42,220     |       | $ | 23,435 |   |   | 56 | % |   |
| Net cash used in  investing activities               |       | (488,430                                            | )          | (151,143   | )          | (337,287   | )          |   | (223 | )% |   |
| Net cash provided by  (used in) financing activities |       | 424,954                                             |       | 113,752    |       | 311,202    |       |   | 274 | % |   |
|                                                      |            |                                                     |            |            |            |            |            |  |  |  |  |  |  |  |

 

***Net cash provided by operating activities***

The increase in the net cash from operating activitiesof $23.4 million, or 56%, was primarily the result of a decrease in cashused for working capital.

Net cash from operatingactivities for the nine months ended September 30, 2005 was increased byapproximately $20.3 million by working capital changes. Increases in accountspayable and other accrued liabilities and accrued crude oil purchases more thanoffset an increase in crude oil sales receivables.

***Net cash used in investing activities***

On September 30, 2005, we purchased certainterminal and pipeline assets from various subsidiaries of Valero, L.P. for anaggregate purchase of $455.0 million plus transaction costs of approximately$3.4 million, of which approximately $1.0 million was accrued at September 30,2005. Separately, we also purchased certain crude oil contracts and crude oil inventories for approximately $3.8million plus contingent payments over the next three and one half years basedon specified performance criteria. Capital expenditures were $27.3million in the nine months ended September 30, 2005, of which $3.1 millionrelated to sustaining capital projects, $6.2 million related to transitionprojects, $13.1 million related to expansion and $4.9 million was for ourcontinued development of the Pier 400 Project.

The amount of cash used ininvesting activities in 2004 relates primarily to our acquisition anddevelopment activities. The 2004 period includes $139.0 million related to theacquisition of the Rangeland system, including the MAPL pipeline. Capitalexpenditures for the nine months ended September 30, 2004 were $11.5million of which $1.5 million related to sustaining capital projects,$1.2 million related primarily to the transition of the Pacific Terminalsstorage and distribution system and the Rangeland pipeline system,$6.3 million related to expansion and $2.5 million was for development ofthe Pier 400 Project.

***Net cash provided by and used in financing activities***

Cash provided by financing activities for the ninemonths ended September 30, 2005 include net proceeds of $295.2 million,including our General Partner contribution of $6.1 million, from our public andprivate equity offerings, $171.0 million net proceeds from the offering of our 61¤4%senior notes, and net proceeds of $114.2 million under our new revolving creditfacility. During the nine months ended September 30, 2005, we incurred netborrowings of $64.3 million under our previous U.S. and Canadian revolvingcredit facilities. In September 2005, we repaid in full the outstandingbalance of $171.0 million 

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under our previous U.S.and Canadian revolving credit facilities. Cash provided by financing activitiesfor the nine months ended September 30, 2005 also include distributions of$46.2 million which were made to the limited partners and the General Partnerand a $2.4 million contribution from TAC and LBP, to reimburse us for certaincosts incurred in connection with the LB Acquisition.

The amount of cashprovided by financing activities in 2004 of $113.8 million includes (i) netproceeds of $128.6 million from our equity offerings completed in March andApril, 2004, which were used principally to partly fund our acquisition of theRangeland system, (ii) $241.1 million net proceeds from the offering ofour 71¤8% senior notes, which wereused in part to repay our $225 million term loan, (iii) net proceeds of$11.1 million under our revolving credit facilities, and (iv) $41.8million in distributions to the limited and general partner interests.

***Capital Requirements***

Generally, ourtransportation and storage operations require investment to upgrade or enhanceexisting operations and to meet environmental and operational regulations. Ourcapital requirements consist primarily of:

·       sustainingcapital expenditures to replace partially or fully depreciated assets in orderto maintain the existing operating capacity or efficiency of our assets andextend their useful lives;

·       transitionalcapital expenditures to integrate acquired assets into our existing operations;and

·       expansioncapital expenditures to expand or increase the efficiency of the existingoperating capacity of our assets, whether through construction or acquisition,such as placing new storage tanks in service to increase our storagecapabilities and revenue, and adding new pump stations or pipeline connectionsto increase our transportation throughput and revenue.

We have forecasted totalcapital expenditures for our existing operations of $53 million for 2005,including $10 million for the Pier 400 Project, $27 million forexpansion projects, $8 million relating to the transition of the Rangelandsystem, $3 million for other transition capital projects, and$5 million for sustaining capital projects.

***Pier 400***

We continue with our efforts to develop a deepwaterpetroleum import terminal at Pier 400 and Terminal Island in the Port ofLos Angeles (“POLA”) to handle marine receipts of crude oil and refineryfeedstocks. As currently envisioned, the project would include a deep waterberth, high capacity transfer infrastructure and storage tanks, with a pipelinedistribution system that will connect to various customers, some directly, andsome through our Pacific Terminals storage and distribution system. We wouldconstruct the storage tanks and transfer infrastructure, including a largediameter pipeline system for receiving bulk petroleum liquids from marinevessels. If successful, this project will allow us to increase ourparticipation in the Los Angeles basin marine import business, which is growingas a result of a decline in both California production and imports from Alaska.

We initiated the environmental review and permittingfor the Pier 400 project in June 2004 and expect to have the permitsnecessary for construction to begin in the second half of 2006. We entered intoa project development agreement with two subsidiaries of Valero EnergyCorporation that defines the facilities that we are to construct in the POLA. Weand Valero Energy Corporation have also signed a terminaling services agreementwith a 30-year, 50,000 bpd volume commitment from Valero EnergyCorporation to support the terminal. These agreements are subject to thesatisfaction of various conditions, including the execution of additionalproject related agreements and the achievement of certain project milestones,some of which have not been satisfied. We are negotiating these additional 

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agreements and anextension of the project milestones with Valero, and we expect to reach anagreement. Negotiations for long-term commitments with additional customers areprogressing.

Final construction of the Pier 400 Project is subjectto the completion of a land lease agreement with the POLA, receipt ofenvironmental and other approval, securing additional customer commitments,updating engineering and project cost estimates, ongoing feasibilityevaluation, and financing. A final decision to proceed is expected to be madein the first half of 2006. We expect construction of the Pier 400 terminalto be completed and placed in service in late 2007.

We have capitalizedapproximately $15.4 million on the Pier 400 project through September 30,2005, including $4.9 million for the nine months ended September 30, 2005.These expenditures include $7.3 million for emission reduction credits, anasset that is re-saleable if the project does not proceed. We anticipatefunding the remaining pre-construction costs through the second quarter of 2006from our revolving credit facility. Construction of the Pier 400 terminalis expected to be financed through a combination of debt and proceeds from theissuance of additional partnership units, including common units.

***Debt Obligations***

At September 30, 2005, our debt obligationsinclude: (i) $114.2 million on our new senior secured revolvingcredit facility, including $19.2 million under the Canadian sub-facility, (ii) $247.5 millionon our 71¤8% senior notes, due June 2014, (iii) $174.2 millionon our 61¤4% senior notes,due September 2015, and (iv) Cdn$4.6 million(U.S.$3.9 million) payable to the seller of the MAPL assets. For furtherdiscussion of these debt obligations see “Note 5—Long-term Debt” to theaccompanying condensed consolidated financial statements.

As of September 30,2005, $152.6 million of undrawn credit was available under the new seniorsecured revolving credit facility. With the consent of the administrative agentunder the new revolving credit facility, we can increase credit availability upto an additional $116.4 million, based upon pro-forma EBITDA from futureacquisitions.

**Off-Balance Sheet Arrangements**

As of September 30,2005, we had standby letters of credit outstanding of $16.8 million forsecuring crude oil purchases and the MAPL note, both of which are reflected asliabilities on the balance sheet.

**Accounting Pronouncements**

In December 2004, the Financial AccountingStandards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123(revised December 2004), *Share-Based Payment*(“SFAS123R”). This Statement is a revision of SFAS No. 123. SFAS 123Restablishes standards for the accounting for transactions in which an entityexchanges its equity instruments for goods or services. SFAS 123R is effectivefor the Partnership as of the beginning of the first annual reporting periodthat begins after June 15, 2005. The Partnership has not yet determinedthe impact of the adoption of SFAS 123R on the Partnership’s consolidatedfinancial statements.

In December 2004, the FASB issued Statement ofAccounting Standards No. 153, *Exchanges of NonmonetaryAssets* (“SFAS 153”). SFAS 153 addresses the measurement of exchangesof certain nonmonetary assets (except for certain exchanges of products orproperty held for sale in the ordinary course of business). It amends APBOpinion No. 29, *Accounting for NonmonetaryExchanges*, and requires that nonmonetary exchanges be accounted forat the fair value of the assets exchanged, with gains or losses beingrecognized, if the fair value is determinable within reasonable limits and thetransaction has commercial substance. The Statement is effective for fiscalperiods beginning after June 15, 2005. The 

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Partnership does notexpect the adoption of SFAS 153 to have a material impact on its financialstatements.

On March 30, 2005 the FASB issued FASBInterpretation No. 47, *Accounting for ConditionalAsset Retirement Obligations*(“FIN 47”), to clarify the term *conditional asset retirement obligation* as that term is usedin FASB Statement No. 143, *Accounting for AssetRetirement Obligations*. The Interpretation also clarifies when anentity has sufficient information to reasonably estimate the fair value of anasset retirement obligation. FIN 47 is effective for the Partnership no laterthan the end of fiscal years ending after December 15, 2005. ThePartnership is in the process of determining the impact of FIN 47 on itsconsolidated financial statements.

In May 2005The FASB issued Statement of Accounting Standards No. 154, *Accounting Changes and Error Corrections* (“SFAS 154”). SFAS154 replaces APB No. 20, *Accounting Changes,*and FASB Statement No. 3, *Reporting Changes inInterim Financial Statements.* The Statement changes the accountingfor, and reporting of, a change in accounting principle. SFAS 154 requiresretrospective application to prior period’s financial statements of voluntarychanges in accounting principle and changes required by new accountingstandards when the standard does not include specific transition provisions,unless it is impracticable to do so. SFAS 154 is effective for accountingchanges and corrections of errors in fiscal years beginning after December 15,2005. If required, the Partnership will apply the provisions of SFAS 154in future periods.

In September 2005, the Emerging Issues Task Force(“EITF”) issued Issue No. 04-13 (“EITF 04-13”), *Accounting for Purchases and Sales of Inventory with the SameCounterparty*. The issues addressed by the EITF are (i) thecircumstances under which two or more exchange transactions involving inventorywith the same counterparty should be viewed as a single exchange transactionfor the purposes of evaluating the effect of APB No. 29; and (ii) whetherthere are circumstances under which nonmonetary exchanges of inventory withinthe same line of business should be recognized at fair value. EITF 04-13is effective for new arrangements entered into in the reporting periodsbeginning after March 15, 2006, and to all inventory transactions that arecompleted after December 15, 2006, for arrangements entered into prior to March 15,2006. The Partnership is in the process of determining the impact of EITF 04-13on its financial statements, but does not expect it to have a material impacton its financial statements.

**ITEM 3.**                Quantitativeand Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adversechanges in market rates and prices. The principal market risks to which we areexposed are interest rate risk and crude oil price risk. Debt we incur underour credit facilities bears variable interest at the applicable base or primerate, a rate based on Eurodollar or a rate based on Canadian Bankers’Acceptances. We have used and will continue to use from time to time derivativeinstruments to hedge our exposure to variable interest rates. In addition, wehave entered into swap agreements to convert a portion of our fixed rate seniornotes into floating rate debt based on LIBOR.

We use, on a limitedbasis, certain derivative instruments (principally futures and options) tohedge our exposure to market price volatility related to our inventory orfuture sales of crude oil. We do not enter into speculative derivativeactivities of any kind. The fair market values of these derivative instrumentsare included in “Other current assets” in the accompanying consolidated balancesheets. In our gathering operations we purchase crude oil for subsequenttransportation and resale primarily in the Los Angeles Basin. Changes in thefair value of our derivative instruments related to the fair value hedge ofcrude oil inventory are recognized in net income. For the nine months ended September 30,2005 and 2004, “crude oil sales, net of purchases” were net of$1.7 million and $2.3 million in losses, respectively, reflecting changesin the fair value of derivative instruments in our gathering operations. Losseson derivatives were generally offset by gains in physical crude oil inventorypositions. In addition, changes in 

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the fairvalue of our derivative instruments related to the forecasted sale of crudeoil, which qualify as cash flow hedges for accounting purposes, are deferredand reflected in “accumulated other comprehensive income,” a component ofpartners’ capital, until the related revenue is recognized in the consolidatedstatements of income. We expect to reclassify a net amount of $0.7 million ofexisting gains and losses into earnings over the next 12 months. For existinghedges, the maximum length of time over which we are hedging our exposure tofuture cash flows for forecasted transactions is 15 months. As of September 30,2005, $0.5 million relating to the changes in the fair value of derivativeinstruments was included in “accumulated other comprehensive income.” In September 2005,we hedged a portion of our forecasted 2006 sales of crude oil by entering intocashless collars. Changes in price within the collar range are expensed and theeffective portion of any price change outside of the collar range will bedeferred and reflected in “accumulated other comprehensive income”.

In connection with our 71¤8% senior notes, due June 2014, we enteredinto interest rate swap agreements with an aggregate notional principal amountof $80.0 million to receive interest at a fixed rate of 71¤8% and to payinterest at an average variable rate of six month LIBOR plus 1.6681% (set inadvance or in arrears depending on the swap transaction). The interest rateswaps mature on June 15, 2014 and are callable at the same dates and termsas the 71¤8% senior notes. We designated these swaps as ahedge of the change in the 71¤8% seniornotes fair value attributable to changes in the six month LIBOR interest rate.Changes in fair values of the interest rate swaps are recorded into earningseach period. Similarly, changes in the fair value of the underlying$80.0 million of the 71¤8% seniornotes, which are expected to be offsetting to changes in the fair value of theinterest swaps, are recorded into earnings each period. At September 30,2005 we recorded an increase of $1.4 million in the fair value of interest rateswaps with an equal offsetting entry to the $80.0 million of 71¤8% senior notes. As of September 30, 2005, weassessed the hedge effectiveness of this interest rate swap and noted that nogain or loss from measuring ineffectiveness was required to be recognized.

We are subject to risksresulting from interest rate fluctuations as the interest cost on our creditfacilities and the $80 million interest swap on the 71¤8% senior notes are basedon variable rates. If the LIBOR or Canadian Bankers’ Acceptance discount rateswere to increase 1.0% for the remainder of 2005 as compared to the rate at September 30,2005, our interest expense for the remainder of 2005 would increase $0.5million based on our outstanding debt at September 30, 2005.

**Fair Value of Financial Instruments**

The carrying amount andfair values of financial instruments are as follows:

| ** **                      | ** ** | **September 30, 2005** | ** ** | **December 31, 2004** | ** ** |
|---------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| ** **                      | ** ** | **Carrying  Value**              | ** ** | **Fair  Value**                 | ** ** | **Carrying  Value** | ** ** | **Fair  Value** | ** ** |
| ** **                      | ** ** | **(in thousands)**          | ** ** |
| Crude oil hedging  futures      |       | $                                | 1,444      |                            | $          | 1,444 |   | $ | 400 |   | $ | 400 |   |
| Fair value  interest rate swaps |       | 1,445                            |       | 1,445                           |       | 2,693 |   | 2,693 |   |
| Long-term debt                  |       | 539,789                          |       | 554,637                         |       | 357,163 |   | 373,265 |   |
|                                 |            |                                  |            |                                 |            |  |  |  |  |  |  |  |  |

 

As of September 30, 2005 and December 31,2004, the carrying amounts of items comprising current assets and currentliabilities approximate fair value due to the short-term maturities of theseinstruments. The carrying amounts of the revolving credit facilities approximatefair value primarily because the interest rates fluctuate with prevailingmarket rates. The interest rate on the 71¤8% seniornotes, due June 2014, and the 61¤4% senior notes, due September 2015,are fixed, except for $80 million which is subject to an interest rate swapagreement, and the fair value is determined from a broker’s price quotes at September 30,2005 and December 31, 2004.

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The carrying amount ofderivative financial instruments represents the fair value as these instrumentsare recorded on the balance sheet at their fair value under SFAS 133. Ourfair values of crude oil hedging futures are based on****Reutersquoted market prices on the NYMEX. Interest rate swaps’ fair values are basedon the prevailing market price at which the positions could be liquidated.

**ITEM 4.**                Controlsand Procedures

***Disclosure Controls and Procedures***

We have established disclosure controls and proceduresto ensure that material information relating to us, including our consolidatedsubsidiaries, is made known to the officers who certify our financial reportsand to other members of our senior management and our Board of Directors. Indesigning and evaluating the disclosure controls and procedures, managementrecognizes that any controls and procedures, no matter how well designed andoperated, can provide only reasonable assurance of achieving the desiredcontrol objectives, and management is required to apply its judgment inevaluating the cost-benefit relationship of possible controls and procedures.

Based on their evaluationas of September 30, 2005, our principal executive officer and principalfinancial officer have concluded that, as of the end of the period covered bythis report, our disclosure controls and procedures (as defined in Rules 13a-15(e) and15d-15(e) under the Securities Exchange Act of 1934 (the “ExchangeAct”) are effective to ensure that the information required to be disclosed byus in the reports we file or submit under the Exchange Act is recorded,processed, summarized and reported within the time periods specified in SEC rules andforms.

***Internal Control Over Financial Reporting***

Our management, includingthe Chief Executive Officer and Chief Financial Officer, have evaluated ourinternal control over financial reporting (as defined in Rules 13a-15(f)and 15d-15(f) under the Exchange Act) as of September 30, 2005, and haveconcluded that there has not been any change during our most recent fiscalquarter that has materially affected, or is reasonably likely to materiallyaffect, our internal control over financial reporting.

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**PART II. OTHER INFORMATION**

**ITEM 1.**                LegalProceedings

In connection with the Valero Acquisition, we haveassumed defense of Support Terminals Services, Inc. (“ST Services”) in alawsuit filed in New Jersey state court in 2003 by ExxonMobil Corporation (“ExxonMobil”).We have also assumed any liability that might be imposed on ST Services as aresult of the suit. In the suit, ExxonMobil seeks $400,000 for remediationcosts it has paid, from GATX Corporation, Kinder Morgan Liquid Terminals, thesuccessor in interest to GATX Terminals Corporation, and ST Services.ExxonMobil also seeks a ruling imposing liability for any future remediation onthe same defendants. These costs are associated with the Paulsboro, New Jerseyterminal that was acquired by us. ExxonMobil claims that the costs are relatedto releases at the site subsequent to its sale of the terminal to GATX in 1990and that any remaining remediation requirements are the responsibility of GATXCorporation, Kinder Morgan, and ST Services.

See also discussion oflegal proceedings in “Note 10—Contingencies” in the accompanying condensedconsolidated financial statements.

**ITEM 6.**                Exhibits

Thefollowing documents are filed as exhibits to this quarterly filing:
| Exhibit Number       | ** ** | ** **                                                                                                                                                                                                                                                                                                             | ** ** | **Description** |
|---------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------|
| Exhibit 4.3          |       | Registration Rights  Agreement, dated September 23, 2005, among the Issuers and the Initial  Purchasers (Incorporated by reference to Pacific Energy Partners, L.P.’s  Form 8-K filed on September 28, 2005, Exhibit 4.3)                                                                     |
| Exhibit 10.1         |       | Credit Agreement,  dated as of September 30, 2005, among Pacific Energy Partners L.P.,  Rangeland Pipeline Company, Bank of America, NA and other lenders party  thereto (Incorporated by reference to Pacific Energy Partners, L.P.’s  Form 8-K filed on October 6, 2005, Exhibit 10.1) |
| Exhibit 10.2         |       | Registration  Rights Agreement, dated September 30, 2005, among Pacific Energy  Partners L.P. and the Purchasers (Incorporated by reference to Pacific Energy  Partners, L.P.’s Form 8-K filed on August 11, 2005,  Exhibit A to Exhibit 10.1)                                           |
| *  Exhibit 12.1      |       | Statement of  Computation of Ratio of Earnings to Fixed Charges                                                                                                                                                                                                                                                        |
| *  Exhibit 31.1      |       | Certification of  Principal Executive Officer of Pacific Energy Management LLC, General Partner  of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P.,  as required by Rule 13a-14(a) of the Securities Exchange Act  of 1934                                                     |
| *  Exhibit 31.2      |       | Certification of  Principal Financial Officer of Pacific Energy Management LLC, General Partner  of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P.,  as required by Rule 13a-14(a) of the Securities Exchange Act  of 1934                                                     |
| †  Exhibit 32.1 |       | Certification of  Chief Executive Officer of Pacific Energy Management LLC, General Partner of  Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P.,  pursuant to 18 U.S.C. §1350                                                                                                             |
| † Exhibit 32.2  |       | Certification of Chief  Financial Officer of Pacific Energy Management LLC, General Partner of  Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., pursuant  to 18 U.S.C. §1350                                                                                                             |

----

*                    Filedherewith.

†                    Not consideredto be “filed” for purposes of Section 18 of the Securities Exchange Act of1934 or otherwise subject to the liabilities of that section.

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**SIGNATURES**

Pursuantto the requirements of the Securities Exchange Act of 1934, the registrant hasduly caused this report to be signed on its behalf by the undersigned thereuntoduly authorized.

|            | **PACIFIC ENERGY PARTNERS, L.P.** |
|------------|-----------------------------------|
| ** ** | **By:**                           | **PACIFIC ENERGY GP, LP, its General Partner** |
| ** ** | ** **                        | **By:** | **PACIFIC ENERGY MANAGEMENT LLC,  its General Partner** |
|       |                              | By: | /s/ IRVIN  TOOLE, JR. |
|       |                              |   | Irvin  Toole, Jr. |
|       |                              |   | *President,  Chief Executive Officer and Director  (Principal Executive Officer)  November 14, 2005* |
|       |                              | By: | /s/ GERALD  A. TYWONIUK |
|       |                              |   | Gerald A.  Tywoniuk |
|       |                              |   | *Senior Vice  President, Chief Financial  Officer and Treasurer  (Principal Financial and Accounting Officer)  November 14, 2005* |
|            |                                   |  |  |  |  |

 

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**EXHIBIT INDEX**
| Exhibit Number       | ** ** | ** **                                                                                                                                                                                                                                                                                                             | ** ** | **Description** |
|---------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------|
| Exhibit 4.3          |       | Registration Rights  Agreement, dated September 23, 2005, among the Issuers and the Initial  Purchasers (Incorporated by reference to Pacific Energy Partners, L.P.’s  Form 8-K filed on September 28, 2005, Exhibit 4.3)                                                                     |
| Exhibit 10.1         |       | Credit Agreement,  dated as of September 30, 2005, among Pacific Energy Partners L.P.,  Rangeland Pipeline Company, Bank of America, NA and other lenders party  thereto (Incorporated by reference to Pacific Energy Partners, L.P.’s  Form 8-K filed on October 6, 2005, Exhibit 10.1) |
| Exhibit 10.2         |       | Registration  Rights Agreement, dated September 30, 2005, among Pacific Energy  Partners L.P. and the Purchasers (Incorporated by reference to Pacific Energy  Partners, L.P.’s Form 8-K filed on August 11, 2005,  Exhibit A to Exhibit 10.1)                                      |
| *  Exhibit 12.1      |       | Statement of  Computation of Ratio of Earnings to Fixed Charges                                                                                                                                                                                                                                                        |
| *  Exhibit 31.1      |       | Certification of  Principal Executive Officer of Pacific Energy Management LLC, General Partner  of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P.,  as required by Rule 13a-14(a) of the Securities Exchange Act  of 1934                                                     |
| *  Exhibit 31.2      |       | Certification of  Principal Financial Officer of Pacific Energy Management LLC, General Partner  of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P.,  as required by Rule 13a-14(a) of the Securities Exchange Act  of 1934                                                     |
| †  Exhibit 32.1 |       | Certification of  Chief Executive Officer of Pacific Energy Management LLC, General Partner of  Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P.,  pursuant to 18 U.S.C. §1350                                                                                                             |
| † Exhibit 32.2  |       | Certification of Chief  Financial Officer of Pacific Energy Management LLC, General Partner of  Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P.,  pursuant to 18 U.S.C. §1350                                                                                                             |

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*                    Filedherewith.

†                    Not consideredto be “filed” for purposes of Section 18 of the Securities Exchange Act of1934 or otherwise subject to the liabilities of that section.

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