**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, 2006**

**OR**

**o**                                 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 AvenueLong Beach, CA 90805-4408**

(Address of principalexecutive offices)

**(562) 728-2800**

(Registrant’s telephonenumber, including area code)

**None**

(Former name, formeraddress and former fiscal year, if changed since last report)

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Indicate by check markwhether the registrant: (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required tofile such reports) and (2) has been subject to such filing requirementsfor the past 90 days. Yes x  No o

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer. See definition of “accelerated filer and largeaccelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  o                 Acceleratedfiler  x                 Non-acceleratedfiler  o

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2of the Exchange Act). Yes o  Nox

Indicatethe number of shares outstanding of each of the issuer’s classes of commonstock, as of the latest practicable date.

| Class              | ** ** | **Outstanding at October 31, 2006** | ** ** |
|--------------------|------------|---------------------------------------------------------|------------|
| Common Units       |       |                                                    | 34,074,032 |   |   |
| Subordinated Units |       |                                                    | 5,232,500  |   |   |

 

 

 

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**PACIFIC ENERGYPARTNERS, L.P.FORM 10-QTABLE OF CONTENTS**

|              | ** ** | ** **                                                                                                                                        | ** ** | **Page** |
|--------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------|
| ** **   | ** ** | **PART I.  FINANCIAL INFORMATION**                                                                                                           |       |     |
| Item 1. |       | Financial  Statements                                                                                                                             |       | 1        |   |
|         |       | Condensed Consolidated Balance Sheets (Unaudited)—As  of September 30, 2006 and December 31, 2005                                  |       | 1        |   |
|         |       | Condensed Consolidated Statements of Income  (Unaudited)—For the Three and Nine Months Ended September 30, 2006 and  2005               |       | 2        |   |
|         |       | Condensed Consolidated Statement of Partners’ Capital  (Unaudited)—For the Nine Months Ended September 30, 2006                    |       | 3        |   |
|         |       | Condensed Consolidated Statements of Comprehensive  Income (Unaudited)—For the Three and Nine Months Ended September 30,  2006 and 2005 |       | 4        |   |
|         |       | Condensed Consolidated Statements of Cash Flows  (Unaudited)—For the Nine Months Ended September 30, 2006 and 2005                      |       | 5        |   |
|         |       | Notes to Condensed Consolidated Financial Statements  (Unaudited)                                                                                 |       | 6        |   |
| Item 2. |       | Management’s Discussion and Analysis of Financial  Condition and Results of Operations                                                       |       | 25       |   |
| Item 3. |       | Quantitative and Qualitative Disclosures About Market  Risk                                                                                       |       | 46       |   |
| Item 4. |       | Controls and Procedures                                                                                                                           |       | 48       |   |
| ** **   | ** ** | **PART II.  OTHER INFORMATION**                                                                                                              |       |     |   |
| Item 1. |       | Legal  Proceedings                                                                                                                                |       | 49       |   |
| Item 1A.     |       | Risk  Factors                                                                                                                                     |       | 50       |   |
| Item 6. |       | Exhibits                                                                                                                                          |       | 51       |   |

 

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**PART I.**   FINANCIALINFORMATION

**ITEM 1.**             FinancialStatements

**PACIFICENERGY PARTNERS, L.P.CONDENSED CONSOLIDATED BALANCE SHEETS(Unaudited)**

| ** **                                                                                                                                            | ** ** | **September 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                                                            | ** ** | **(in thousands)**      | ** ** |
| **ASSETS**                                                                                                                                            | ** ** |                         | ** ** | ** **                  |       |   | ** ** | ** ** |   |
| Current assets:                                                                                                                                       |       |                         |       | ** **                  |       |   |   | ** ** |   |
| Cash and cash equivalents                                                                                                                             |       |                         | $          | 13,715                      | ** ** |   |   | $ | 18,064 | ** ** |   |
| Crude oil sales  receivable                                                                                                                           |       |                         | 153,604    | ** **                  |       |   | 95,952 | ** ** |   |
| Transportation and  storage accounts receivable                                                                                                       |       |                         | 27,268     | ** **                  |       |   | 30,100 | ** ** |   |
| Canadian goods and  services tax receivable                                                                                                           |       |                         | 9,771      | ** **                  |       |   | 8,738 | ** ** |   |
| Insurance proceeds  receivable, net                                                                                                                   |       |                         | 4,581      | ** **                  |       |   | 9,052 | ** ** |   |
| Due from related parties                                                                                                                              |       |                         | 28         | ** **                  |       |   | — | ** ** |   |
| Crude oil and refined  products inventory                                                                                                             |       |                         | 46,012     | ** **                  |       |   | 20,192 | ** ** |   |
| Prepaid expenses                                                                                                                                      |       |                         | 4,451      | ** **                  |       |   | 7,489 | ** ** |   |
| Other                                                                                                                                                 |       |                         | 5,796      | ** **                  |       |   | 2,528 | ** ** |   |
| Total current assets                                                                                                                                  |       |                         | 265,226    | ** **                  |       |   | 192,115 | ** ** |   |
| Property and equipment,  net                                                                                                                          |       |                         | 1,252,750  | ** **                  |       |   | 1,185,534 | ** ** |   |
| Intangible assets, net                                                                                                                                |       |                         | 67,639     | ** **                  |       |   | 69,180 | ** ** |   |
| Investment in Frontier                                                                                                                                |       |                         | 8,651      | ** **                  |       |   | 8,156 | ** ** |   |
| Other assets, net                                                                                                                                     |       |                         | 17,957     | ** **                  |       |   | 21,467 | ** ** |   |
|                                                                                                                                                  |       |                         | $          | 1,612,223                   | ** ** |   |   | $ | 1,476,452 | ** ** |   |
| **LIABILITIES AND PARTNERS’ CAPITAL**                                                                                                            | ** ** |                         | ** ** | ** **                  |       |   | ** ** | ** ** |   |
| Current liabilities:                                                                                                                                  |       |                         |       | ** **                  |       |   |   | ** ** |   |
| Accounts payable and  accrued liabilities                                                                                                             |       |                         | $          | 33,346                      | ** ** |   |   | $ | 42,409 | ** ** |   |
| Accrued crude oil  purchases                                                                                                                          |       |                         | 152,284    | ** **                  |       |   | 96,651 | ** ** |   |
| Line 63 oil release  reserve                                                                                                                          |       |                         | 3,194      | ** **                  |       |   | 5,898 | ** ** |   |
| Accrued interest                                                                                                                                      |       |                         | 7,381      | ** **                  |       |   | 4,929 | ** ** |   |
| Other                                                                                                                                                 |       |                         | 7,955      | ** **                  |       |   | 6,300 | ** ** |   |
| Total current liabilities                                                                                                                             |       |                         | 204,160    | ** **                  |       |   | 156,187 | ** ** |   |
| Senior notes and  credit facilities, net                                                                                                              |       |                         | 669,163    | ** **                  |       |   | 565,632 | ** ** |   |
| Deferred income  taxes                                                                                                                                |       |                         | 32,560     | ** **                  |       |   | 35,771 | ** ** |   |
| Environmental  liabilities                                                                                                                            |       |                         | 14,257     | ** **                  |       |   | 16,617 | ** ** |   |
| Other liabilities                                                                                                                                     |       |                         | 3,159      | ** **                  |       |   | 4,006 | ** ** |   |
| Total liabilities                                                                                                                                     |       |                         | 923,299    | ** **                  |       |   | 778,213 | ** ** |   |
| Commitments and contingencies (note 6)                                                                                                                |       |                         |       | ** **                  |       |   |   | ** ** |   |
| Partners’ capital:                                                                                                                               |       |                         |       | ** **                  |       |   |   | ** ** |   |
| Common unitholders  (34,074,032 and 31,448,931 units issued and outstanding at September 30,  2006 and December 31, 2005, respectively)     |       |                         | 640,232    | ** **                  |       |   | 644,589 | ** ** |   |
| Subordinated unitholders  (5,232,500 and 7,848,750 units issued and outstanding at September 30,  2006 and December 31, 2005, respectively) |       |                         | 14,529     | ** **                  |       |   | 24,758 | ** ** |   |
| General Partner interest                                                                                                                              |       |                         | 12,219     | ** **                  |       |   | 12,535 | ** ** |   |
| Undistributed employee  long-term incentive compensation                                                                                              |       |                         | 467        | ** **                  |       |   | — | ** ** |   |
| Accumulated other  comprehensive income                                                                                                               |       |                         | 21,477     | ** **                  |       |   | 16,357 | ** ** |   |
| Net partners’ capital                                                                                                                            |       |                         | 688,924    | ** **                  |       |   | 698,239 | ** ** |   |
|                                                                                                                                                  |       |                         | $          | 1,612,223                   | ** ** |   |   | $ | 1,476,452 | ** ** |   |

 

See accompanying notes to condensed consolidated financial statements.

1

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**PACIFIC ENERGY PARTNERS, L.P.CONDENSED CONSOLIDATED STATEMENTS OF INCOME(Unaudited)**

| ** **                                                                                                                                                                                                                                | ** ** | **Three Months Ended  September 30,**                 | ** ** | **Nine Months Ended  September 30,** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                                                                                                                                                                                                | ** ** | **2006**                                                             | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                                                                                                                                                                                                | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| Revenues:                                                                                                                                                                                                                                 |       |                                                                 |       |                                                |       |   |   |   |   |
| Pipeline transportation revenue                                                                                                                                                                                                           |       | $                                                                    | 36,995     |                                                | $          | 27,283 |   | $ | 105,652 |   | $ | 83,067 |   |
| Storage and terminaling revenue                                                                                                                                                                                                           |       | 23,467                                                               |       | 9,731                                               |       | 65,420 |   | 30,923 |   |
| Pipeline buy/sell transportation revenue                                                                                                                                                                                                  |       | 10,010                                                               |       | 11,683                                              |       | 31,136 |   | 28,905 |   |
| Crude oil sales, net of purchases of $421,276 and  $188,901 for the three months ended September 30, 2006 and  2005 and $1,031,185 and $425,733 for the nine months ended  September 30, 2006 and 2005 |       | 9,924                                                                |       | 5,823                                               |       | 27,453 |   | 13,647 |   |
|                                                                                                                                                                                                                                      |       | 80,396                                                               |       | 54,520                                              |       | 229,661 |   | 156,542 |   |
| Cost and Expenses:                                                                                                                                                                                                                        |       |                                                                 |       |                                                |       |   |   |   |   |
| Operating (which excludes $586 of compensation  expense for the nine months ended September 30, 2005 reported  in accelerated long-term incentive plan compensation expense)                                          |       | 34,046                                                               |       | 25,019                                              |       | 99,120 |   | 72,065 |   |
| General and administrative (which excludes $2,529 of compensation expense  for the nine months ended September 30, 2005 reported in accelerated  long-term incentive plan compensation expense)                            |       | 5,649                                                                |       | 4,115                                               |       | 18,236 |   | 12,987 |   |
| Depreciation and amortization                                                                                                                                                                                                             |       | 10,398                                                               |       | 6,560                                               |       | 30,692 |   | 19,695 |   |
| Merger costs (note 2)                                                                                                                                                                                                                     |       | 1,112                                                                |       | —                                              |       | 4,529 |   | — |   |
| Accelerated long-term incentive plan compensation  expense (note 7)                                                                                                                                                                  |       | —                                                               |       | —                                              |       | — |   | 3,115 |   |
| Line 63 oil release costs (note 6)                                                                                                                                                                                                        |       | —                                                               |       | —                                              |       | — |   | 2,000 |   |
| Reimbursed general partner transaction costs  (note 5)                                                                                                                                                                               |       | —                                                               |       | —                                              |       | — |   | 1,807 |   |
|                                                                                                                                                                                                                                      |       | 51,205                                                               |       | 35,694                                              |       | 152,577 |   | 111,669 |   |
| Share of net  income of Frontier                                                                                                                                                                                                          |       | 373                                                                  |       | 516                                                 |       | 1,246 |   | 1,363 |   |
| Operating income                                                                                                                                                                                                                          |       | 29,564                                                               |       | 19,342                                              |       | 78,330 |   | 46,236 |   |
| Interest expense                                                                                                                                                                                                                          |       | (10,853                                                              | )          | (6,237                                              | )          | (30,029 | ) | (17,679 | ) |
| Interest and other  income                                                                                                                                                                                                                |       | 720                                                                  |       | 494                                                 |       | 1,455 |   | 1,387 |   |
| Income before  income taxes                                                                                                                                                                                                               |       | 19,431                                                               |       | 13,599                                              |       | 49,756 |   | 29,944 |   |
| Income tax  (expense) benefit:                                                                                                                                                                                                            |       |                                                                 |       |                                                |       |   |   |   |   |
| Current                                                                                                                                                                                                                                   |       | (485                                                                 | )          | (1,411                                              | )          | (2,288 | ) | (1,898 | ) |
| Deferred (note 3)                                                                                                                                                                                                                         |       | 289                                                                  |       | (22                                                 | )          | 4,824 |   | (239 | ) |
|                                                                                                                                                                                                                                      |       | (196                                                                 | )          | (1,433                                              | )          | 2,536 |   | (2,137 | ) |
| Net income                                                                                                                                                                                                                                |       | $                                                                    | 19,235     |                                                | $          | 12,166 |   | $ | 52,292 |   | $ | 27,807 |   |
| Net income (loss) for the general partner interest                                                                                                                                                                                        |       | $                                                                    | 347        |                                                | $          | 243 |   | $ | 720 |   | $ | (1,215 | ) |
| Net income for the limited partner interests                                                                                                                                                                                              |       | $                                                                    | 18,888     |                                                | $          | 11,923 |   | $ | 51,572 |   | $ | 29,022 |   |
| Basic net income per limited partner unit                                                                                                                                                                                                 |       | $                                                                    | 0.48       |                                                | $          | 0.39 |   | $ | 1.31 |   | $ | 0.97 |   |
| Diluted net income per limited partner unit                                                                                                                                                                                               |       | $                                                                    | 0.48       |                                                | $          | 0.39 |   | $ | 1.31 |   | $ | 0.96 |   |
| Weighted average limited partner units outstanding:                                                                                                                                                                                       |       |                                                                 |       |                                                |       |   |   |   |   |
| Basic                                                                                                                                                                                                                                     |       | 39,307                                                               |       | 30,761                                              |       | 39,305 |   | 30,051 |   |
| Diluted                                                                                                                                                                                                                                   |       | 39,321                                                               |       | 30,762                                              |       | 39,332 |   | 30,089 |   |

 

See accompanying notes to condensed consolidated financial statements.

2

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

| ** **                                                                          | ** ** | ** **                          | ** ** | ** **                            | ** ** | ** **  | ** ** | ** **       | ** ** | ** **        | ** ** | **Undistributed** | ** ** | ** **      | ** ** | ** ** | ** ** |
|-------------------------------------------------------------------------------------|------------|-------------------------------------|------------|---------------------------------------|------------|-------------|------------|------------------|------------|-------------------|------------|-------------------|------------|-----------------|------------|------------|------------|
| ** **                                                                          | ** ** | ** **                          | ** ** | ** **                            | ** ** | ** **  | ** ** | ** **       | ** ** | ** **        | ** ** | **Employee**      | ** ** | **Accumulated** | ** ** | ** ** | ** ** |
| ** **                                                                          | ** ** | ** **                          | ** ** | ** **                            | ** ** | ** **  | ** ** | ** **       | ** ** | **General**       | ** ** | **Long-Term**     | ** ** | **Other**       | ** ** | ** ** | ** ** |
| ** **                                                                          | ** ** | **Limited Partner Units** | ** ** | **Limited Partner Amounts** | ** ** | **Partner** | ** ** | **Incentive**    | ** ** | **Comprehensive** | ** ** | ** **        | ** ** |
| ** **                                                                          | ** ** | **Common**                          | ** ** | **Subordinated**                      | ** ** | **Common**  | ** ** | **Subordinated** | ** ** | **Interest**      | ** ** | **Compensation**  | ** ** | **Income**      | ** ** | **Total**  | ** ** |
| ** **                                                                          | ** ** | **(in thousands)**             | ** ** |
| Balance,  December 31, 2005                                                    |       |                                | 31,449     |                                  |       |        | 7,849      |             |       | $                 | 644,589    |              |       | $               | 24,758     |       |       | $ | 12,535 |   |   | $ | — |   |   |   | $ | 16,357 |   |   | $ | 698,239 |   |
| Net income                                                                          |       |                                | —     |                                  |       |        | —     |             |       | 41,917            |       |              | 9,655      |            |       | 720        |       |   | — |   |   |   | — |   |   | 52,292 |   |
| Distribution to  partners                                                           |       |                                | —     |                                  |       |        | —     |             |       | (53,159           | )          |              | (13,264    | )               |       | (2,291     | )          |   | — |   |   |   | — |   |   | (68,714 | ) |
| Employee  compensation under LB Pacific, LP Option Plan                        |       |                                | —     |                                  |       |        | —     |             |       | —            |       |              | —     |            |       | 1,250      |       |   | — |   |   |   | — |   |   | 1,250 |   |
| Employee  compensation under long-term incentive plan                     |       |                                | —     |                                  |       |        | —     |             |       | —            |       |              | —     |            |       | —     |       |   | 782 |   |   |   | — |   |   | 782 |   |
| Issuance of  common units pursuant to long-term incentive plan                      |       |                                | 9          |                                  |       |        | —     |             |       | 265               |       |              | —     |            |       | 5          |       |   | (315 | ) |   |   | — |   |   | (45 | ) |
| Foreign currency  translation adjustment                                            |       |                                | —     |                                  |       |        | —     |             |       | —            |       |              | —     |            |       | —     |       |   | — |   |   |   | 4,908 |   |   | 4,908 |   |
| Change in fair  value of crude oil and foreign currency hedging contracts |       |                                | —     |                                  |       |        | —     |             |       | —            |       |              | —     |            |       | —     |       |   | — |   |   |   | 212 |   |   | 212 |   |
| Conversion of  subordinated units to common units                                   |       |                                | 2,616      |                                  |       |        | (2,616     | )                |       | 6,620             |       |              | (6,620     | )               |       | —     |       |   | — |   |   |   | — |   |   | — |   |
| Balance, September 30,  2006                                                   |       |                                | 34,074     |                                  |       |        | 5,233      |             |       | $                 | 640,232    |              |       | $               | 14,529     |       |       | $ | 12,219 |   |   | $ | 467 |   |   |   | $ | 21,477 |   |   | $ | 688,924 |   |

 

See accompanying notes to condensed consolidated financial statements.

3

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**PACIFIC ENERGY PARTNERS, L.P.CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME(Unaudited)**

| ** **                                                    | ** ** | **Three Months Ended  September  30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|---------------------------------------------------------------|------------|------------------------------------------------------------|------------|------------------------------------------------|------------|
| ** **                                                    | ** ** | **2006**                                                   | ** ** | **2005**                                       | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                    | ** ** | **(in thousands)**                                    | ** ** |
| Net income                                                    |       | $                                                          | 19,235     |                                           | $          | 12,166 |   | $ | 52,292 |   | $ | 27,807 |   |
| Change in fair  value of crude oil and hedging derivatives    |       | 271                                                        |       | 303                                            |       | 531 |   | (502 | ) |
| Change in fair  value of foreign currency hedging derivatives |       | 115                                                        |       | —                                         |       | (319 | ) | — |   |
| Change in foreign  currency translation adjustment            |       | (236                                                       | )          | 5,678                                          |       | 4,908 |   | 3,377 |   |
| Comprehensive income                                          |       | $                                                          | 19,385     |                                           | $          | 18,147 |   | $ | 57,412 |   | $ | 30,682 |   |

 

See accompanying notes to condensed consolidated financial statements.

4

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**PACIFIC ENERGY PARTNERS, L.P.CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS(Unaudited)**

| ** **                                                                         | ** ** | **Nine  Months Ended   September 30,** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **2006**                                                        | ** ** | **2005** | ** ** |
| ** **                                                                         | ** ** | **(in thousands)**                                         | ** ** |
| CASH FLOWS FROM OPERATING ACTIVITIES                                               |       |                                                            |       |   |   |
| Net income                                                                         |       | $                                                               | 52,292     |   | $ | 27,807 |   |
| Adjustments to reconcile net income to net cash  provided by operating activities: |       |                                                            |       |   |   |
| Depreciation and  amortization                                                     |       | 30,692                                                          |       | 19,695 |   |
| Amortization of debt  issue costs                                                  |       | 1,847                                                           |       | 1,424 |   |
| Non-cash employee  compensation under long-term incentive plan                     |       | 782                                                             |       | 2,886 |   |
| Non-cash employee  compensation under the LB Pacific, LP Option Plan               |       | 1,250                                                           |       | — |   |
| Deferred tax expense  (benefit)                                                    |       | (4,824                                                          | )          | 239 |   |
| Share of net income of  Frontier                                                   |       | (1,246                                                          | )          | (1,363 | ) |
| Other adjustments                                                                  |       | (1,665                                                          | )          | 58 |   |
| Distributions from  Frontier, net                                                  |       | 622                                                             |       | 1,317 |   |
| Net changes in operating  assets and liabilities:                                  |       |                                                            |       |   |   |
| Crude oil sales  receivable                                                        |       | (55,829                                                         | )          | (68,206 | ) |
| Transportation and  storage accounts receivable                                    |       | 3,161                                                           |       | 909 |   |
| Insurance proceeds  receivable                                                     |       | 6,695                                                           |       | (8,829 | ) |
| Crude oil and  refined products inventory                                          |       | (25,508                                                         | )          | (2,742 | ) |
| Other current  assets and liabilities                                              |       | (3,771                                                          | )          | (3,757 | ) |
| Accounts payable  and other accrued liabilities                                    |       | (5,076                                                          | )          | 27,354 |   |
| Accrued crude oil  purchases                                                       |       | 54,400                                                          |       | 64,917 |   |
| Line 63 oil  release reserve                                                       |       | (4,929                                                          | )          | 5,411 |   |
| Other non-current  assets and liabilities                                          |       | 598                                                             |       | (1,465 | ) |
| NET CASH PROVIDED  BY OPERATING ACTIVITIES                                         |       | 49,491                                                          |       | 65,655 |   |
| CASH FLOWS FROM INVESTING ACTIVITIES                                               |       |                                                            |       |   |   |
| Acquisitions                                                                       |       | (2,365                                                          | )          | (461,165 | ) |
| Additions to property and  equipment                                               |       | (67,522                                                         | )          | (27,265 | ) |
| Additions to pipeline  linefill and minimum tank inventory                         |       | (16,106                                                         | )          | —- |   |
| Other                                                                              |       | 181                                                             |       | —- |   |
| NET CASH USED IN  INVESTING ACTIVITIES                                             |       | (85,812                                                         | )          | (488,430 | ) |
| CASH FLOWS FROM FINANCING  ACTIVITIES                                              |       |                                                            |       |   |   |
| Issuance of common units,  net of fees and offering expenses                       |       | —                                                          |       | 289,122 |   |
| Capital contributions  from the general partner                                    |       | —                                                          |       | 8,569 |   |
| Proceeds from credit  facilities                                                   |       | 182,094                                                         |       | 203,291 |   |
| Net proceeds from senior  notes offering                                           |       | —                                                          |       | 170,997 |   |
| Repayment of credit  facilities                                                    |       | (81,463                                                         | )          | (195,661 | ) |
| Deferred financing costs                                                           |       | —                                                          |       | (4,676 | ) |
| Distributions to partners                                                          |       | (68,714                                                         | )          | (46,224 | ) |
| Issuance of common units  pursuant to exercise of unit options                     |       | —                                                          |       | 707 |   |
| Related parties                                                                    |       | (28                                                             | )          | (1,171 | ) |
| NET CASH PROVIDED  BY FINANCING ACTIVITIES                                         |       | 31,889                                                          |       | 424,954 |   |
| Effect of exchange rates  on cash                                                  |       | 83                                                              |       | 213 |   |
| NET INCREASE  (DECREASE) IN CASH AND CASH EQUIVALENTS                              |       | (4,349                                                          | )          | 2,392 |   |
| CASH AND CASH  EQUIVALENTS, beginning of reporting period                          |       | 18,064                                                          |       | 23,383 |   |
| CASH AND CASH  EQUIVALENTS, end of reporting period                                |       | $                                                               | 13,715     |   | $ | 25,775 |   |

 

See accompanying notes to condensed consolidated financial statements.

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**PACIFIC ENERGY PARTNERS, L.P.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTSSeptember 30, 2006(Unaudited)**

**1.**   SUMMARYOF SIGNIFICANT ACCOUNTING POLICIES

**Basis ofPresentation**

Pacific Energy Partners, L.P. and its subsidiaries(collectively, the “Partnership”) are engaged principally in the business ofgathering, transporting, storing and distributing crude oil, refined productsand other related products. The Partnership generates revenue primarily bytransporting such commodities on its pipelines, by leasing storage capacity inits storage tanks, and by providing other terminaling services. The Partnershipalso buys and sells crude oil, activities that are generally complementary toits other crude oil operations. The Partnership conducts its business throughtwo business units, the West Coast Business Unit, which includes activities inCalifornia and the Philadelphia, Pennsylvania area, and the Rocky MountainBusiness Unit, which includes activities in five Rocky Mountain states andAlberta, Canada.

The Partnership is managed by its general partner,Pacific Energy GP, LP, a Delaware limited partnership, which is managed byits general partner, Pacific Energy Management LLC (“PEM”), a Delaware limitedliability company. Thus, the officers and board of directors of PEM manage thebusiness affairs of Pacific Energy GP, LP and the Partnership. References tothe “General Partner” refer to Pacific Energy GP, LP and/or PEM, as the contextindicates; and “Board of Directors” refers to the board of directors of PEM.

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 nine months ended September 30, 2006 are notnecessarily 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 assets acquired fromValero, L.P., since the acquisition of these assets on September 30, 2005.The assets acquired from Valero, L.P. have been integrated into our West Coastand Rocky Mountain Business Units as Pacific Atlantic Terminals and the RockyMountain Products Pipeline.

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 and Form 10-K/A for the year ended December 31,2005. Certain prior year balances in theaccompanying condensed consolidated financial statements have been reclassifiedto conform to the current year presentation.

**New AccountingPronouncements**

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

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transactions in which anentity exchanges its equity instruments for goods or services. SFAS 123Ris effective for the Partnership as of the beginning of the first interimperiod or annual reporting period that begins after June 15, 2005. Theadoption of SFAS 123R on January 1, 2006 did not have a materialimpact on the Partnership’s consolidated financial statements. See Notes 5 and7 to the condensed consolidated financial statements for more details onshare-based compensation.

In September 2005, the Emerging Issues Task Force(“EITF”) issued Issue No. 04-13 (“EITF 04-13”), *Accounting for Purchases and Sales of Inventory withthe Same Counterparty*. 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 adoption of EITF 04-13 did not have a material impact on thePartnership’s consolidated financial statements.

In June 2006, the FASB issued FASB InterpretationNo. 48 (“FIN 48”), *Accounting for Uncertaintyin Income Taxes*. This Interpretation prescribes a recognitionthreshold and measurement attribute for the financial statement recognition andmeasurement of a tax position taken or expected to be taken in a tax return.This Interpretation also provides guidance on derecognition, classification,interest and penalties, accounting in interim periods, disclosure, andtransition. FIN 48 will apply to the Partnership’s Canadian subsidiaries, whichare taxable entities in Canada. The Partnership is in the process ofdetermining the impact of FIN 48 on its financial statements, but does notexpect it to have a material impact. FIN 48 is effective for the Partnership asof the beginning of the first fiscal year beginning on January 1, 2007.

In June 2006, the EITF issued Issue No. 06-3(“EITF 06-3”), *How Taxes Collected fromCustomers and Remitted to Governmental Authorities Should Be Presented in theIncome Statement (That Is, Gross versus Net Presentation).* Theissues addressed by the EITF are (i) whether the scope of this Issueshould include (a) all nondiscretionary amounts assessed by governmentalauthorities, (b) all nondiscretionary amounts assessed by governmentalauthorities in connection with a transaction with a customer, or (c) onlysales, use, and value added taxes, and (ii) how taxes assessed by agovernmental authority within the scope of this issue should be presented inthe income statement (that is, gross versus net presentation). EITF 06-3is effective for interim and annual financial periods beginning after December 15,2006. The Partnership is in the process of determining the impact of EITF 06-3on its financial statements, but does not expect it to have a material impact.

In September 2006, the FASB issued Statement ofFinancial Accounting Standards No. 157, *Fair ValueMeasurements (“SFAS 157”).*SFAS 157 defines fair value, establishesa framework for measuring fair value in generally accepted accountingprinciples, and expands disclosures about fair value measurements. SFAS 157applies under other accounting pronouncements that require or permit fair valuemeasurements in those accounting pronouncements. Accordingly, SFAS 157 does notrequire any new fair value measurements. However, the Partnership is in theprocess of determing what impact the application of SFAS 157 will have on itscurrent fair value practices. The Partnership does not expect the applicationof SFAS 157 to have a material impact. SFAS 157 is effective for financialstatements issued for fiscal years beginning after November 15, 2007.

In September 2006, theSecurities and Exchange Commission issued Staff Accounting Bulletin No. 108,*Considering the Effects of Prior Year Misstatementswhen Quantifying Misstatements in Current year Financial Statements*(“SAB 108”), which provides interpretive guidance on how the effects of thecarryover or reversal of prior year misstatements should be considered inquantifying a current year misstatement. The guidance is effective for fiscal years beginning after November 15,2006 and it allows a one-time 

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transitionalcumulative effect adjustment to beginning-of-year retained earnings at thefirst fiscal year ending after November 15, 2006 for errors that were notpreviously deemed material, but are material under the guidance in SAB 108. ThePartnership is currently evaluating the impact, if any, of adopting SAB 108 onits consolidated financial statements.

**2.**   PROPOSEDMERGER WITH PLAINS ALL AMERICAN PIPELINE, L.P.

On June 12, 2006, the Partnership announced thatit had entered into an Agreement and Plan of Merger with Plains All AmericanPipeline, L.P. (“PAA”), Plains AAP, L.P., Plains All American GP LLC (“PAA GPLLC”), PEM, and Pacific Energy GP, LP, pursuant to which the Partnership willbe merged with and into PAA. In the merger, each common unitholder of thePartnership, except LB Pacific, LP (“LB Pacific”), the owner of thePartnership’s General Partner, will receive 0.77 common units of PAA for eachcommon unit of the Partnership that the unitholder owns. In addition, pursuantto a purchase agreement between LB Pacific and PAA, PAA will acquire from LBPacific the general partner interest and incentive distribution rights of thePartnership, as well as 5,232,500 common units and 5,232,500 subordinatedunits, for total consideration of $700 million in cash. The merger agreementwas unanimously approved by the Board of Directors of PEM, as well as by theboard of directors of PAA’s general partner.

Each of the Partnership and PAA made customaryrepresentations, warranties and covenants in the merger agreement, which aredescribed in the joint proxy statement/prospectus filed by the Partnership andPAA with the Securities and Exchange Commission (the “SEC”). The merger issubject to the satisfaction or waiver of certain conditions, including thereceipt of various regulatory approvals or the expiration of various regulatorywaiting periods, all of which approvals or waiting periods have been obtained,and the adoption and approval of the merger agreement and the merger by theholders of at least a majority of the Partnership’s outstanding common units(excluding common units held by LB Pacific) and outstanding subordinatedunits, each voting as a separate class. The merger agreement and the mergermust also be adopted and approved by the holders of at least a majority of PAA’soutstanding common units.

The Partnership’s and PAA’s special meetings ofunitholders to consider the merger agreement and the merger are scheduled tooccur on November 9, 2006. Although the Partnership and PAA cannot be surewhen all of the conditions to the merger will be satisfied, the parties expectto complete the merger on November 15, 2006 (assuming the proposals areapproved by the unitholders and all other conditions to closing are satisfied).

During the three and ninemonths ended September 30, 2006, the Partnership incurred approximately$1.1 million and $4.5 million, respectively, in costs directly relating to themerger for investment banking fees, legal fees and other transaction costs.Approximately $0.7 million of investment banking fees were paid to affiliatesof Lehman Brothers Inc., an affiliate of the General Partner (see “Note 5—Related Party Transactions”). Thesecosts are included in the condensed consolidated statements of income under thecaption “Merger costs”.

**3.**   INCOMETAXES

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. However, the Partnership’s Canadian subsidiaries are taxableentities in Canada and are subject to Canadian federal and provincial incometaxes. In addition, inter-company interest payments and repatriation of fundsthrough dividend payments are subject to withholding tax.

Income taxes for the Partnership’s Canadiansubsidiaries are accounted for under the asset and liability method. Under thismethod, deferred tax assets and liabilities are recognized for the future taxconsequences attributable to differences between the financial statement carryingamounts of existing 

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assets and liabilities andtheir respective tax bases, and operating loss and tax credit carryforwards.Deferred tax assets and liabilities are measured using enacted tax ratesexpected to apply to taxable income in the years in which those temporarydifferences are expected to be recovered or settled. The effect of a change intax rates on deferred tax assets and liabilities is recognized in operations inthe period that includes the enactment date. The Partnership intends to repatriateits Canadian subsidiaries’ earnings in the future and accordingly has recordeda provision for Canadian withholding taxes.

In the second quarter of2006, the Canadian and Alberta governments enacted legislation which willreduce federal and provincial income taxes. The Partnership adjusted the futureincome tax rates used in the estimates of deferred tax assets and liabilitiesand recognized a $4.6 million deferred tax benefit in the quarter ended June 30,2006.

**4.**   NETINCOME PER LIMITED PARTNER UNIT

Net income is allocated to the Partnership’s GeneralPartner and limited partners based on their respective interests in thePartnership. The Partnership’s General Partner is also directly charged withspecific costs that it has individually assumed and for which the limitedpartners are not responsible.

Basic net income per limited partner unit isdetermined by dividing net income, after adding back costs and deductingcertain amounts allocated to the General Partner (including incentivedistribution payments in excess of its 2% ownership interest), by the weightedaverage number of outstanding limited partner units.

Diluted net income perlimited partner unit is calculated in the same manner as basic net income perlimited partner unit above, except that the weighted average number ofoutstanding limited partner units is increased to include the dilutive effectof outstanding options, if any, and restricted units by application of thetreasury stock method.

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Setforth below is the computation of net income allocated to limited partners andnet income per basic and diluted limited partner unit. The table also shows thereconciliation of basic average limited partner units to diluted weightedaverage limited partner units.

| ** **                                            | ** ** | **Three Months Ended   September 30,** | ** ** | **Nine Months Ended  September30,** | ** ** |
|-------------------------------------------------------|------------|------------------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                            | ** ** | **2006**                                                   | ** ** | **2005**                                      | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                            | ** ** | **(in thousands)**                                    | ** ** |
| **Numerator:**                                        | ** ** | ** **                                                 | ** ** | ** **                                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net income allocated to  limited partners:            |       |                                                       |       |                                          |       |   |   |   |   |
| Net income                                            |       | $                                                          | 19,235     |                                          | $          | 12,166 |   | $ | 52,292 |   | $ | 27,807 |   |
| Costs allocated to the  general partner(1):           |       |                                                       |       |                                          |       |   |   |   |   |
| LB Pacific Option Plan expense                        |       | 370                                                        |       | —                                        |       | 1,250 |   | — |   |
| Senior Notes consent solicitation and other costs     |       | —                                                     |       | —                                        |       | — |   | 893 |   |
| Severance and other costs                             |       | —                                                     |       | —                                        |       | — |   | 914 |   |
| Total costs allocated to the general partner          |       | 370                                                        |       | —                                        |       | 1,250 |   | 1,807 |   |
| Income before  costs allocated to the general partner |       | 19,605                                                     |       | 12,166                                        |       | 53,542 |   | 29,614 |   |
| Less: general partner incentive distributions         |       | (331                                                       | )          | —                                        |       | (917 | ) | — |   |
|                                                  |       | 19,274                                                     |       | 12,166                                        |       | 52,625 |   | 29,614 |   |
| Less: General  partner 2% ownership                   |       | (386                                                       | )          | (243                                          | )          | (1,053 | ) | (592 | ) |
| Net income for  the limited partners                  |       | $                                                          | 18,888     |                                          | $          | 11,923 |   | $ | 51,572 |   | $ | 29,022 |   |
| **Denominator:**                                      | ** ** | ** **                                                 | ** ** | ** **                                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Basic weighted  average limited partner units         |       | 39,307                                                     |       | 30,761                                        |       | 39,305 |   | 30,051 |   |
| Effect of  restricted units                           |       | 14                                                         |       | —                                        |       | 27 |   | 25 |   |
| Effect of options                                     |       | —                                                     |       | 1                                             |       | — |   | 13 |   |
| Diluted weighted  average limited partner units       |       | 39,321                                                     |       | 30,762                                        |       | 39,332 |   | 30,089 |   |
| Basic net income  per limited partner unit            |       | $                                                          | 0.48       |                                          | $          | 0.39 |   | $ | 1.31 |   | $ | 0.97 |   |
| Diluted net income per  limited partner unit          |       | $                                                          | 0.48       |                                          | $          | 0.39 |   | $ | 1.31 |   | $ | 0.96 |   |

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(1)          See“Note 5—Related Party Transactions” for a description of transaction costsreimbursed by the General Partner.

**5.**   RELATEDPARTY TRANSACTIONS

**Cost Reimbursements**

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

***LB Pacific, LPOption Plan:*****  **LBPacific, LP (“LB Pacific”), the owner of the Partnership’s General Partner, hasadopted an option plan for certain officers, directors, employees, advisors,and consultants of PEM, LB Pacific, and their affiliates. Under the plan,participants may be granted options to acquire partnership interests in LBPacific. The Partnership is not obligated to pay any amounts to LB Pacific forthe benefits granted or paid to any participants under the plan, althoughgenerally accepted accounting principles require that the Partnership record anexpense in its financial statements for benefits granted to employees of PEM orthe Partnership who provide services to the Partnership, with a correspondingincrease in the General Partner’s capital account.

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The option plan is administered by the board ofdirectors of LB Pacific GP, LLC, the general partner of LB Pacific. The terms,conditions, performance goals, restrictions, limitations, forfeiture, vestingor exercise schedule, and other provisions of grants under the plan, as well aseligibility to participate, are determined by the board of directors of LBPacific GP, LLC. The board of directors of LB Pacific GP, LLC may determine togrant options under the plan to participants containing such terms as the boardof LB Pacific GP, LLC shall determine. Options will have an exercise price thatmay not be less than the fair market value of the units on the date of grant.

Information concerning the plan and grants is sharedby LB Pacific, LP with the General Partner’s Compensation Committee and Boardof Directors, and considered in determining the long term incentivecompensation paid by the Partnership to participants in the plan.

In January 2006,LB Pacific granted options representing a maximum 24% interest in LB Pacific(assuming all options vest and are exercised), which options vest over a periodof 10 years from the date of grant (except in limited circumstances such as achange in control), to certain officers and key employees of PEM and thePartnership. The grants, qualified as equity-classified awards, had a grantdate fair value of $8.6 million. The fair value of the options wasdetermined using valuation techniques that included the discounted presentvalue of estimated future cash flows for LB Pacific and fundamental analysis.It was measured using the Black-Scholes option pricing model with the followingassumptions:

| Expected  volatility      |   | 21.86 | %      |
|---------------------------|--------|-------|--------|
| Expected dividend  yield  |   | 0     | %      |
| Expected term (in  years) |   | 10    |   |
| Risk-free rate            |   | 4.37  | %      |

 

For the three and nine months ended September 30,2006, the Partnership recognized $0.4 million and $1.3 million in compensationexpense relating to the LB Pacific options and recorded a capital contributionfrom the General Partner for the same amounts. At September 30, 2006, allgranted LB Pacific options remained outstanding. At September 30,2006, there was $7.3 million of total unrecognized compensation cost related tononvested options granted under the plan, which cost was expected to berecognized over the remaining period of 9.25 years. Upon the close of theproposed merger with PAA, the options will become immediately exercisable.Total unrecognized compensation expense on the closing date will be immediatelyrecognized in the income statement.

***LB Pacific, LP and Anschutz:***   Priorto March 3, 2005, the General Partner was owned by The AnschutzCorporation (“Anschutz”). On March 3, 2005, Anschutz sold its interest inthe Partnership, including its interest in the General Partner, to LB Pacific.In connection with the sale of Anschutz’s interest in the Partnership to LBPacific, LB Pacific and Anschutz reimbursed the Partnership for certain costsincurred in connection with the acquisition. The Partnership was reimbursed$1.2 million for costs incurred in connection with the consent solicitation,$0.3 million of legal and other costs, and $0.9 million relating to severancecosts, for a total of $2.4 million. Of the $2.4 million total incurred, $1.8million was expensed, as shown on the income statement as “reimbursed generalpartner transaction costs,” and $0.6 million of the consent solicitation costswere capitalized as deferred financing costs.

***Special Agreement:***   OnMarch 3, 2005, Douglas L. Polson, previously the Chairman of the Board ofDirectors, entered into a Special Agreement and a Consulting Agreement withPEM. In accordance with the Special Agreement, Mr. Polson resigned asChairman of the Board of Directors effective March 3, 2005. Mr. Polsonwas paid approximately $0.9 million, representing accrued salary through March 3,2005, accrued but unused vacation, and payment in satisfaction of otherobligations under his employment agreement. The latter portion of this paymentwas recorded as an expense in “Reimbursed general partner transaction costs” inthe accompanying condensed consolidated income statements. LB Pacificreimbursed this amount, which was recorded as a partner’s capital contribution.Pursuant to the Consulting 

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Agreement, Mr. Polsonagreed to perform advisory services to PEM from time to time as mutually agreedbetween Mr. Polson and the Chief Executive Officer of PEM. Inconsideration for Mr. Polson’s services under the Consulting Agreement,which had a one-year term, Mr. Polson received a monthly consulting fee of$12,500 and reimbursement of all reasonable business expenses incurred or paidby Mr. Polson in the course of performing his duties thereunder.

**Lehman Brothers, Inc.**

Lehman Brothers, Inc. is deemed to be anaffiliate of the Partnership’s General Partner through a 59% ownership interestin LB Pacific, which is controlled by Lehman Brothers Holdings Inc., the parententity of Lehman Brothers, Inc. Lehman Brothers, Inc. acted asfinancial advisor to LB Pacific and the Partnership in connection with theproposed merger and the transactions related to the merger (see Note 2—ProposedMerger With Plains All American, L.P.). As part of its services, LehmanBrothers, Inc. delivered an opinion to the Board of Directors to theeffect that, as of the date of its opinion and based on and subject to variousassumptions made, the aggregate consideration to be offered to all of theholders of the partnership interests in the Partnership in the proposed mergertransaction is fair to such holders. The agreement with Lehman Brothers, Inc.was reviewed and approved by theConflicts Committee of the Board of Directors and the fees charged werecustomary for the type of services provided. The Partnership incurred $0.7million in fees with Lehman Brothers, Inc. for the nine months ended September 30,2006, none of which was incurred in the three months ended September 30,2006. The Partnership has agreed to pay Lehman Brothers, Inc. anadditional $7.7 million success fee contingent on the successful consummationof the merger.

In connection with thepurchase and the associated financing of the Partnership’s purchase of certainterminal and pipeline assets from Valero, L.P. in September 2005,including a private equity offering, public equity offering, debt offering andnew credit facility, Lehman Brothers, Inc. and its affiliates providedadvisory and underwriting services to the Partnership. Additionally, anaffiliate of Lehman Brothers, Inc. is a participant in the syndicate thatprovided the Partnership’s new senior secured credit facility. These agreementswith Lehman Brothers, Inc. were reviewed and approved by the ConflictsCommittee of the Board of Directors and the fees charged were customary for thetypes of services 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.

**Other Related PartyTransactions**

RMPS receives an operatingfee and management fee from Frontier Pipeline Company (“Frontier”) inconnection with time spent by RMPS management and for other services related toFrontier’s activities. RMPS received $0.2 million for each of the three monthsended September 30, 2006 and 2005 and $0.6 million for each of the ninemonths ended September 30, 2006 and 2005, respectively. The Partnershipowns a 22.22% partnership interest in Frontier.

**6.**   CONTINGENCIES

**Line 63 Oil Release**

In March 2005, a release of approximately 3,400barrels of crude oil occurred on the Partnership’s Line 63 when it was severedas a result of a landslide caused by heavy rainfall in the Pyramid Lake area ofLos Angeles County. Over the period March 2005 through anticipatedcompletion in June 2007, the Partnership expects to incur an estimatedtotal of $25.5 million for oil containment and clean-up of the impacted areas,future monitoring costs, potential third-party claims and penalties, and othercosts, excluding pipeline repair costs. As of September 30, 2006, thePartnership had incurred 

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approximately 22.3 illionof the total expected remediation costs related to the oil release for workperformed through that date. The Partnership estimates that the $3.2 million ofremaining remediation cost will substantially be incurred before June 2007.

In March 2006, Pacific Pipeline System LLC (“PPS”),a subsidiary of the Partnership, was served with a four count misdemeanoraction by the state of California, which alleges that PPS violated variousstate statutes by depositing oil or substances harmful to wildlife into theenvironment and by the willful and intentional discharge of pollution intostate waters. The Partnership estimates that the maximum fine and penaltiesthat could be assessed for these actions is approximately $0.9 million inthe aggregate. The Partnership believes, however, that certain of the allegedviolations are without merit and intends to defend against them, and thatmitigating factors should otherwise reduce the amounts of any potential finesor penalties that might be assessed. At this time, the Partnership cannotreasonably determine the outcome of these allegations. The estimated range ofpossible fines or penalties including amounts not covered by insurance isbetween $0 and $0.9 million.

The Partnership has a pollution liability insurancepolicy with a $2.0 million per-occurrence deductible that covers containmentand clean-up costs, third-party claims and certain penalties. The insurancecarrier has, subject to the terms of the insurance policy, acknowledgedcoverage of the incident and is processing and paying invoices related to theclean-up. The Partnership believes that, subject to the $2.0 million deductible,it will be entitled to recover substantially all of its clean-up costs and anythird-party claims associated with the release. As of September 30, 2006,the Partnership has recovered $18.6 millionfrom insurance and recorded net receivables of $4.6million for future insurance recoveries it deems probable.

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 of operations,or cash flows, though the Partnership believes that most, if not all, of anysuch excess cost, to the extent attributable to clean-up and third-partyclaims, would be recoverable through insurance. In March 2006, A.M.Best Company, an insurance company rating agency, announced it had downgradedthe financial strength rating assigned to the Partnership’s insurance carrier,Quanta Specialty Lines Company, including its parent and affiliates. Thedowngrade was from an “A” to a “B++, under review with negative implications.”During the second quarter of 2006, Quanta announced that their Board ofDirectors decided to cease underwriting or seeking new business and to placemost of its remaining specialty insurance and reinsurance lines into orderlyrun-off. On June 7, 2006 A. M. Best further downgraded Quanta from B++ toB. Subsequent to this downgrading, Quanta was removed from A. M. Best’sinteractive rating process, at Quanta’s request. Based on management’s furtheranalysis of Quanta’s financial condition, the Partnership believes that Quantawill continue to meet its obligations relating to the Line 63 oil release,although there can be no assurance that this will be the case. As newinformation becomes available in future periods, the Partnership may change itsprovision and recovery estimates.

**ProductContamination**

In June 2006,approximately 44,000 barrels of a customer’s product at our Martinez terminalwas contaminated. The Partnership has insurance coverage for the damage or lossof its customers’ products while in its care, custody and control at certain ofits terminals subject to a $0.1 million per-occurrence deductible. ThePartnership recognized a loss of $0.2 million to cover the insurance deductibleand other associated costs. At this time, the Partnership believes costsrelated to the contamination of the property will be covered under theinsurance policy, and has accrued an estimated $1.1 million in total costs,which 

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isincluded in “Other current liabilities” in the accompanying condensedconsolidated balance sheet. The Partnership has recorded a receivable of $0.9million for future insurance recoveries it deems probable.

**Litigation**

On June 15, 2006, a lawsuit was filed in theSuperior court of California, County of Los Angeles, entitled *Kosseff v. Pacific Energy, et al,* case no. BC 3544016. Theplaintiff alleged that he was a unitholder of the Partnership and he sought torepresent a class comprising all of the Partnership’s unitholders. Thecomplaint named as defendants the Partnership and certain of the officers anddirectors of the Partnership’s general partner, and asserted claims ofself-dealing and breach of fiduciary duty in connection with the pending mergerwith PAA and related transactions. The plaintiff sought injunctive reliefagainst completing the merger or, if the merger was completed, rescission ofthe merger, other equitable relief, and recovery of the plaintiff’s costs andattorneys’ fees. On September 14, 2006, the Partnership and the otherdefendants entered into a memorandum of settlement with the plaintiff to settlethe lawsuit. As part of the settlement, the Partnership and the otherdefendants deny all allegations of wrongdoing and maintain that they arewilling to settle the lawsuit solely because the settlement would eliminate theburden and expense of further litigation. The settlement is subject tocustomary conditions, including court approval. As part of the settlement, thePartnership will, subject to the consummation of the merger, pay $475,000 tothe plaintiff’s counsel for their fees and expenses, and incur approximately$0.1 to $0.2 million for costs of mailing materials to unitholders. If finallyapproved by the court, the settlement will resolve all claims that were orcould have been brought on behalf of the proposed settlement class in theactions being settled, including all claims relating to the merger, the mergeragreement and any disclosure made by the Partnership in connection with themerger. The settlement will not change any of the terms or conditions of themerger. The Partnership will record the settlement amount and associated costsupon completion of the merger.

In August, 2005, Rangeland Pipeline Company (“RPC”), awholly-owned subsidiary of the Partnership, learned that a Statement ofClaim was filed by Desiree Meier and Robert Meier in the Alberta Court of Queen’sBench, Judicial District of Red Deer, naming RPC as defendant, and allegingpersonal injury and property damage caused by an alleged release of petroleumsubstances onto plaintiff’s land by a prior owner and operator of the pipelinethat is currently owned and operated by the Partnership. The claim seeksCdn$1 million (approximately U.S.$0.9 million at September 30,2006) in general damages, Cdn$2 million (approximatelyU.S.$1.8 million at September 30, 2006) in special damages, and, inaddition, unspecified amounts for punitive, exemplary and aggravated damages,costs and interest. RPC believes the claim is without merit, and intendsto vigorously defend against it. RPC also believes that certain of the claims,if successfully proven by the plaintiffs, would be liabilities retained by thepipeline’s prior owner under the terms of the agreement whereby the Partnershipacquired the pipeline in question.

In connection with the acquisition of assets fromValero, L.P. in September 2005, the Partnership assumed responsibility forthe defense of a lawsuit filed in 2003 against Support Terminals Services, Inc.(“ST Services”) by ExxonMobil Corporation (“ExxonMobil”) in New Jersey statecourt. The Partnership has also assumed any liability that might be imposed onST Services as a result of the suit. In the suit, ExxonMobil seeksreimbursement of approximately $400,000 for remediation costs it has incurred,from GATX Corporation, Kinder Morgan Liquid Terminals, the successor ininterest to GATX Terminals Corporation, and ST Services. ExxonMobil also seeksa ruling imposing liability for any future remediation and related liabilitieson the same defendants. These costs are associated with the Paulsboro, NewJersey terminal that was acquired by the Partnership on September 30,2005. ExxonMobil claims that the costs and future remediation requirements arerelated to releases at the site subsequent to its sale of the terminal to GATXin 1990 and that, therefore, any remaining remediation requirements are theresponsibility of GATX Corporation, Kinder Morgan and ST Services. ThePartnership believes the claims against ST Services are without merit, andintends to vigorously defend against them.

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In 2001, Big West Oil Company and Chevron ProductsCompany (the “Complainants”) filed complaints against Frontier Pipeline Company(“Frontier”) with the Federal Energy Regulatory Commission (“FERC”) challengingrates contained in joint tariffs in which Frontier was a participating carrierand rates contained in local tariffs filed by Frontier. On February 18,2004, the FERC found against Frontier on certain of the Complainants’ claimsand ordered Frontier to pay reparations to Complainants in the aggregate amountof approximately $4.2 million, plus interest, which Frontier paid in August 2004.On October 5, 2004, Frontier filed a petition for review of the FERC’sreparations orders in the U.S. Court of Appeals for the D.C. Circuit, and on May 26,2006 the Court of Appeals held that the FERC’s reparation ruling wasinconsistent with applicable law, and thus vacated the FERC’s order andremanded the matter back to the FERC for further consideration consistent withthe Court of Appeals’ decision. On July 25, 2006, Frontier filed a motionasking the FERC to dismiss the reparations complaints of the Complainants onthe grounds that their complaints fail to state claims that can be sustainedconsistent with the ruling of the Court of Appeals. Frontier’s motion alsoasked the FERC to order the refund by the Complainants of the reparationspreviously paid by Frontier, plus interest. The Complainants have, in aresponse to Frontier’s motion, asserted for various reasons that the FERCshould essentially reinstate its original ruling that ordered Frontier to payreparations to the Complainants. No action on the motions has been taken by theFERC. If Frontier prevails on its motion or in any remand proceeding conductedby the FERC, it would be entitled to repayment in the amount of $5.4 million,plus interest thereon from August 23, 2004. The Partnership owns 22.22% of Frontier. Although the Partnershipbelieves Frontier’s motion to dismiss the complaints, as well as the defensesit would assert in a remand proceeding before the FERC, are meritorious, thePartnership cannot predict the outcome of any such actions, and has notrecorded any amount for this contingency.

The Partnership isinvolved in various other regulatory disputes, litigation and claims arisingout of its operations in the normal course of business. The Partnership is notcurrently a party to any legal or regulatory proceedings the resolution ofwhich could be expected to have a material adverse effect on its business,financial condition, liquidity or results of operations.

**7.**   RESTRICTEDUNITS

A restricted unit is a “phantom” unit under thePartnership’s long term incentive compensation plan. A phantom unit entitlesthe grantee to receive a common unit upon the vesting of the phantom unit**.**The Partnership intends the issuance ofthe restricted units under the plan to serve as a means of incentivecompensation for performance and not primarily as an opportunity to participatein the equity appreciation of the common units. Therefore, plan participantswill not pay any consideration for the common units they receive, and thePartnership will receive no remuneration for such units.

15

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In January 2006 andMay 2006, the General Partner awarded 89,110restricted units to key employees and outside directors that vest over athree-year period, beginning on March 1, 2006 and March 1, 2007,respectively. The number of units to be delivered to key employees in any year,if any, will be based on accomplishment of performance targets (measured bydistributable cash flow) for the previous calendar year, subject to theCompensation Committee’s authority to subsequently adjust performance targets asit may deem appropriate, in its discretion. Restricted unit activity during thenine months ended September 30, 2006 is as follows:

| ** **                              | ** ** | **Number of  Units** | ** ** | **Weighted  Average Grant  Date Fair Value** | ** ** |
|-----------------------------------------|------------|---------------------------|------------|-------------------------------------------------------------|------------|
| ** **                              | ** ** | ** **                | ** ** | **(in thousands)**                                     | ** ** |
| Outstanding at  January 1, 2006    |       |                      | —     |                                                        |       |   | $ | — |   |   |
| Changes during the year:                |       |                      |       |                                                        |       |   |   |   |   |
| Granted                                 |       |                      | 89,110     |                                                        |       |   | 2,759 |   |   |
| Vested                                  |       |                      | (10,439    | )                                                           |       |   | (314 | ) |   |
| Forfeited                               |       |                      | (5,430     | )                                                           |       |   | (164 | ) |   |
| Outstanding at  September 30, 2006 |       |                      | 73,241     |                                                        |       |   | $ | 2,281 |   |   |

 

Compensation expense recognized for outstandingrestricted units is based on grant date fair value of the common units to beawarded to the grantee upon vesting of the phantom unit, adjusted for theexpected target performance level for each year. For the three and nine monthsended September 30, 2006, the Partnership incurred $0.2 million and $0.8 million, respectively, in compensation expense for restrictedunits it deemed probable of achieving the performance criteria, including theamount for the first vesting of these awards which occurred on March 1,2006.

The outstanding unit grants include change of controlprovisions that require immediate vesting of units in the event of a change incontrol of the Partnership or its General Partner. Upon the close of theproposed merger with PAA, all outstanding restricted units will immediatelyvest pursuant to the terms of the grants, and any remaining unamortizedcompensation expense will be immediately recognized.

On March 3, 2005, inconnection with LB Pacific’s acquisition of the Partnership’s General Partner,all restricted units then outstanding under the Partnership’s Long-TermIncentive Plan immediately vested pursuant to the terms of the grants. ThePartnership issued 99,583 common units and recognized a compensation expense of$3.1 million, which is included in “Accelerated long-term incentive plancompensation expense” in the accompanying condensed consolidated statements ofincome. Of the total $3.1 million, the compensation expense categorization was$0.6 million for operating personnel and $2.5 million for general andadministrative personnel.

**8.**   SEGMENTINFORMATION

The Partnership’s business and operations areorganized into two business segments: the West Coast Business Unit and theRocky Mountain Business Unit. The West Coast Business Unit includes: (i) PacificPipeline System LLC, owner of Line 2000 and Line 63, (ii) PacificMarketing and Transportation LLC (West Coast Business Unit operations), ownerof the PMT gathering system and marketer of crude oil, (iii) PacificTerminals LLC, owner of the Pacific Terminals storage and distribution system,and (iv) Pacific Atlantic Terminals LLC, owner of the San Francisco andPhiladelphia area terminals, which were acquired on September 30, 2005.The Rocky Mountain Business Unit includes: (i) Rocky Mountain PipelineSystem LLC, owner of the Partnership’s interest in various pipelines that makeup the Western Corridor and Salt Lake City Core systems, and the Rocky MountainProducts Pipeline, which was acquired on September 30, 2005, (ii) RanchPipeline LLC, the owner of a 22.22% partnership interest in Frontier PipelineCompany, (iii) PEG Canada, L.P. and its Canadian subsidiaries, which ownand operate the Rangeland system, and 

16

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(iv) PacificMarketing and Transportation LLC (Rocky Mountain Business Unit operations), amarketer of crude oil.

Generaland administrative costs, which consist of executive management, accounting andfinance, human resources, information technology, investor relations, legal,and business development, are not allocated to the individual business units.Information regarding these two 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, 2006** |       |                                |       |                                    |       |                                                  |       |      |       |   |   |   |   |   |   |
| Revenues:                                       |       |                                |       |                                    |       |                                                  |       |      |       |   |   |   |   |   |   |
| Pipeline transportation revenue                 |       |                                | $          | 18,224                                  |       |                                                  |       | $         | 21,500     |   |   |   | $ | (2,729 | ) |   | $ | 36,995 |   |
| Storage and terminaling revenue                 |       |                                | 23,467     |                                    |       |                                                  | —     |      |       |   |   |   |   | 23,467 |   |
| Pipeline buy/sell transportation revenue(1)     |       |                                | —     |                                    |       |                                                  | 10,010     |      |       |   |   |   |   | 10,010 |   |
| Crude oil sales, net of purchases(2)            |       |                                | 9,494      |                                    |       |                                                  | 572        |      |       |   | (142 | ) |   | 9,924 |   |
| Net revenue                                     |       |                                | 51,185     |                                    |       |                                                  | 32,082     |      |       |   |   |   |   | 80,396 |   |
| Expenses:                                       |       |                                |       |                                    |       |                                                  |       |      |       |   |   |   |   |   |   |
| Operating                                       |       |                                | 21,505     |                                    |       |                                                  | 15,412     |      |       |   | (2,871 | ) |   | 34,046 |   |
| Depreciation and amortization                   |       |                                | 5,528      |                                    |       |                                                  | 4,870      |      |       |   |   |   |   | 10,398 |   |
| Total expenses                                  |       |                                | 27,033     |                                    |       |                                                  | 20,282     |      |       |   |   |   |   | 44,444 |   |
| Share of net  income of Frontier                |       |                                | —     |                                    |       |                                                  | 373        |      |       |   |   |   |   | 373 |   |
| Operating income  from segments(3)              |       |                                | $          | 24,152                                  |       |                                                  |       | $         | 12,173     |   |   |   |   |   |   | $ | 36,325 |   |
| Total business  unit assets(4)                  |       |                                | $          | 915,707                                 |       |                                                  |       | $         | 643,935    |   |   |   |   |   |   | $ | 1,559,642 |   |
| Capital expenditures(5)                         |       |                                | $          | 8,008                                   |       |                                                  |       | $         | 12,628     |   |   |   |   |   |   | $ | 20,636 |   |
| **Three  months ended September 30, 2005** |       |                                |       |                                    |       |                                                  |       |      |       |   |   |   |   |   |   |
| Revenues:                                       |       |                                |       |                                    |       |                                                  |       |      |       |   |   |   |   |   |   |
| Pipeline transportation revenue                 |       |                                | $          | 13,887                                  |       |                                                  |       | $         | 14,887     |   |   |   | $ | (1,491 | ) |   | $ | 27,283 |   |
| Storage and terminaling 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(3)              |       |                                | $          | 9,813                                   |       |                                                  |       | $         | 13,644     |   |   |   |   |   |   | $ | 23,457 |   |
| Total business  unit assets(4)                  |       |                                | $          | 855,191                                 |       |                                                  |       | $         | 551,279    |   |   |   |   |   |   | $ | 1,406,470 |   |
| Capital expenditures(5)                         |       |                                | $          | 5,106                                   |       |                                                  |       | $         | 9,403      |   |   |   |   |   |   | $ | 14,509 |   |

 

17

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| ** **                                     | ** ** | **West Coast  Business  Unit** | ** ** | **Rocky  Mountain  Business Unit** | ** ** | **Intersegment and  Intrasegment  Eliminations** | ** ** | **Total** | ** ** |
|------------------------------------------------|------------|-------------------------------------|------------|-----------------------------------------|------------|-------------------------------------------------------|------------|-----------|------------|
| ** **                                     | ** ** | **(in thousands)**             | ** ** |
| **Nine months ended  September 30, 2006** |       |                                |       |                                    |       |                                                  |       |      |       |   |   |   |   |   |   |
| Revenues:                                      |       |                                |       |                                    |       |                                                  |       |      |       |   |   |   |   |   |   |
| Pipeline transportation revenue                |       |                                | $          | 52,083                                  |       |                                                  |       | $         | 60,790     |   |   |   | $ | (7,221 | ) |   | $ | 105,652 |   |
| Storage and terminaling revenue                |       |                                | 65,420     |                                    |       |                                                  | —     |      |       |   |   |   |   | 65,420 |   |
| Pipeline buy/sell transportation revenue(1)    |       |                                | —     |                                    |       |                                                  | 31,136     |      |       |   |   |   |   | 31,136 |   |
| Crude oil sales, net of purchases(2)           |       |                                | 26,000     |                                    |       |                                                  | 1,860      |      |       |   | (407 | ) |   | 27,453 |   |
| Net revenue                                    |       |                                | 143,503    |                                    |       |                                                  | 93,786     |      |       |   |   |   |   | 229,661 |   |
| Expenses:                                      |       |                                |       |                                    |       |                                                  |       |      |       |   |   |   |   |   |   |
| Operating                                      |       |                                | 63,200     |                                    |       |                                                  | 43,548     |      |       |   | (7,628 | ) |   | 99,120 |   |
| Depreciation and amortization                  |       |                                | 16,534     |                                    |       |                                                  | 14,158     |      |       |   |   |   |   | 30,692 |   |
| Total expenses                                 |       |                                | 79,734     |                                    |       |                                                  | 57,706     |      |       |   |   |   |   | 129,812 |   |
| Share of net  income of Frontier               |       |                                | —     |                                    |       |                                                  | 1,246      |      |       |   |   |   |   | 1,246 |   |
| Operating income  from segments(3)             |       |                                | $          | 63,769                                  |       |                                                  |       | $         | 37,326     |   |   |   |   |   |   | 101,095 |   |
| Total business  unit assets(4)                 |       |                                | $          | 915,707                                 |       |                                                  |       | $         | 643,935    |   |   |   |   |   |   | $ | 1,559,642 |   |
| Capital  expenditures(5)                       |       |                                | $          | 29,635                                  |       |                                                  |       | $         | 24,313     |   |   |   |   |   |   | $ | 53,948 |   |
| **Nine  months ended September 30, 2005** |       |                                |       |                                    |       |                                                  |       |      |       |   |   |   |   |   |   |
| Revenues:                                      |       |                                |       |                                    |       |                                                  |       |      |       |   |   |   |   |   |   |
| Pipeline transportation revenue                |       |                                | $          | 46,525                                  |       |                                                  |       | $         | 41,348     |   |   |   | $ | (4,806 | ) |   | $ | 83,067 |   |
| Storage and terminaling 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(6)                   |       |                                | 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(3)             |       |                                | $          | 31,962                                  |       |                                                  |       | $         | 32,183     |   |   |   |   |   |   | $ | 64,145 |   |
| Total business  unit assets(4)                 |       |                                | $          | 855,191                                 |       |                                                  |       | $         | 551,279    |   |   |   |   |   |   | $ | 1,406,470 |   |
| Capital expenditures(5)                        |       |                                | $          | 6,790                                   |       |                                                  |       | $         | 14,870     |   |   |   |   |   |   | $ | 21,660 |   |

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(1)          Pipeline buy/selltransportation revenue reflects net revenues of approximately $3.4 million and$2.5 million on buy/sell transactions with different parties of $95.6 millionand $77.5 million for the three months ended September 30, 2006 and 2005,respectively and net revenues of approximately $10.2 million and $4.6 millionon buy/sell transactions with different parties of $257.2 million and $126.0million for the nine months ended September 30, 2006 and 2005,respectively. The remaining amount reflects net revenues on buy/selltransactions with the same party.

(2)          The above amounts arenet of purchases of $421.3 million and $188.9 million for the three monthsended September 30, 2006 and 2005 and $1,031.2 million and $425.7 millionfor the nine months ended September 30, 2006 and 2005, respectively.

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

| ** **                                                       | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|------------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                       | ** ** | **2006**                                             | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                       | ** ** | **(in thousands)**                              | ** ** |
| **Income Statement Reconciliation**                    |       |                                                 |       |                                                |       |   |   |   |   |
| Operating income from  above:                                    |       |                                                 |       |                                                |       |   |   |   |   |
| West Coast Business Unit                                         |       | $                                                    | 24,152     |                                                | $          | 9,813 |   | $ | 63,769 |   | $ | 31,962 |   |
| Rocky Mountain Business Unit                                     |       | 12,173                                               |       | 13,644                                              |       | 37,326 |   | 32,183 |   |
| Operating income from segments                                   |       | 36,325                                               |       | 23,457                                              |       | 101,095 |   | 64,145 |   |
| Less: General and  administrative expense                        |       | 5,649                                                |       | 4,115                                               |       | 18,236 |   | 12,987 |   |
| Less: Merger  costs                                              |       | 1,112                                                |       | —                                              |       | 4,529 |   | — |   |
| Less: Accelerated  long-term incentive plan compensation expense |       | —                                               |       | —                                              |       | — |   | 3,115 |   |
| Less: Reimbursed  general partner transaction costs              |       | —                                               |       | —                                              |       | — |   | 1,807 |   |
| Operating income                                                 |       | 29,564                                               |       | 19,342                                              |       | 78,330 |   | 46,236 |   |
| Interest expense                                                 |       | (10,853                                              | )          | (6,237                                              | )          | (30,029 | ) | (17,679 | ) |
| Other income                                                     |       | 720                                                  |       | 494                                                 |       | 1,455 |   | 1,387 |   |
| Income tax  benefit (expense)                                    |       | (196                                                 | )          | (1,433                                              | )          | 2,536 |   | (2,137 | ) |
| Net income                                                       |       | $                                                    | 19,235     |                                                | $          | 12,166 |   | $ | 52,292 |   | $ | 27,807 |   |

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(4)          Businessunit assets do not include assets related to the Partnership’s parent levelactivities. As of September 30, 2006 and 2005, parent level related assetswere $52.6 million and $50.8 million, respectively.

(5)          Segmentcapital expenditures do not include parent level capital expenditures. Parentlevel capital expenditures were $4.4 million and $2.9 million for the threemonths ended September 30, 2006 and 2005 and $13.6 million and $5.6million for the nine months ended September 30, 2006 and 2005,respectively.

(6)          OnMarch 23, 2005, a release of approximately 3,400 barrels of crude oiloccurred on PPS’s Line 63 as a result of a landslide caused by heavy rainfallin northern Los Angeles County. As a result of the release, the Partnershiprecorded $2.0 million net oil release costs in the first quarter of 2005,consisting of what it now estimates to be $25.5 million of accrued costsrelating to the release, net of insurance recovery of $18.6 million to September 30,2006 and accrued insurance receipts of $4.6 million.

**9.**   SUBSEQUENT EVENTS

On October 20, 2006,the Partnership declared a cash distribution of $0.5675 per limited partnerunit, payable on November 13, 2006, to unitholders of record as of October 31,2006.

**10.** SUPPLEMENTALCONDENSED CONSOLIDATING FINANCIAL INFORMATION

Certain of the Partnership’s100% owned subsidiaries have issued full, unconditional, and joint and severalguarantees of the 71¤8%senior notes due 2014 and the 61¤4%senior notes due 2015 (the “Senior Notes”). Given that certain, but not allsubsidiaries of the Partnership are guarantors of its Senior Notes, thePartnership is required to present the following supplemental condensedconsolidating financial information. For purposes of the following footnote,the Partnership is referred to as “Parent”, while the “Guarantor Subsidiaries”are Rocky Mountain Pipeline System LLC, Pacific Marketing and TransportationLLC, Pacific Atlantic Terminals LLC, Ranch Pipeline LLC, PEG Canada GP LLC, 

19

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PEG Canada,L.P. and Pacific Energy Group LLC, and “Non-Guarantor Subsidiaries” are PacificPipeline System LLC, Pacific Terminals LLC, Rangeland Pipeline Company,Rangeland Marketing Company, Rangeland Northern Pipeline Company, RangelandPipeline Partnership and Aurora Pipeline Company, Ltd.

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, 2006** | ** ** |
|----------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                   | ** ** | **Parent**                                           | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **Total** | ** ** |
| ** **                                   | ** ** | **(in thousands)**                              | ** ** |
| Assets:                                      |       |                                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Current assets                               |       | $                                                    | 102,469    |   |   | $ | 214,172 |   |   |   | $ | 90,023 |   |   |   | $ | (141,438 | ) |   | $ | 265,226 |   |
| Property and equipment                       |       | —                                               |       |   | 628,308 |   |   |   | 624,442 |   |   |   | — |   |   | 1,252,750 |   |
| Equity investments                           |       | 514,163                                              |       |   | 213,942 |   |   |   | — |   |   |   | (719,454 | ) |   | 8,651 |   |
| Intercompany notes  receivable               |       | 658,364                                              |       |   | 343,831 |   |   |   | — |   |   |   | (1,002,195 | ) |   | — |   |
| Intangible assets                            |       | —                                               |       |   | 28,982 |   |   |   | 38,657 |   |   |   | — |   |   | 67,639 |   |
| Other assets                                 |       | 11,624                                               |       |   | — |   |   |   | 6,333 |   |   |   | — |   |   | 17,957 |   |
| Total assets                                 |       | $                                                    | 1,286,620  |   |   | $ | 1,429,235 |   |   |   | $ | 759,455 |   |   |   | $ | (1,863,087 | ) |   | $ | 1,612,223 |   |
| Liabilities and partners’  capital:     |       |                                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Current liabilities                          |       | $                                                    | 8,061      |   |   | $ | 247,636 |   |   |   | $ | 89,901 |   |   |   | $ | (141,438 | ) |   | $ | 204,160 |   |
| Long-term debt                               |       | 589,529                                              |       |   | — |   |   |   | 79,634 |   |   |   | — |   |   | 669,163 |   |
| Deferred income taxes                        |       | —                                               |       |   | 1,233 |   |   |   | 31,327 |   |   |   | — |   |   | 32,560 |   |
| Intercompany notes  payable                  |       | —                                               |       |   | 658,364 |   |   |   | 343,831 |   |   |   | (1,002,195 | ) |   | — |   |
| Other liabilities                            |       | 106                                                  |       |   | 7,839 |   |   |   | 9,471 |   |   |   | — |   |   | 17,416 |   |
| Total partners’ capital                 |       | 688,924                                              |       |   | 514,163 |   |   |   | 205,291 |   |   |   | (719,454 | ) |   | 688,924 |   |
| Total liabilities and partners’ capital |       | $                                                    | 1,286,620  |   |   | $ | 1,429,235 |   |   |   | $ | 759,455 |   |   |   | $ | (1,863,087 | ) |   | $ | 1,612,223 |   |

 

| ** **                                   | ** ** | **Balance Sheet  December 31, 2005** | ** ** |
|----------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                   | ** ** | **Parent**                                          | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **Total** | ** ** |
| ** **                                   | ** ** | **(in thousands)**                             | ** ** |
| Assets:                                      |       |                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Current assets                               |       | $                                                   | 104,989    |   |   | $ | 139,457 |   |   |   | $ | 81,846 |   |   |   | $ | (134,177 | ) |   | $ | 192,115 |   |
| Property and equipment                       |       | —                                              |       |   | 583,330 |   |   |   | 602,204 |   |   |   | — |   |   | 1,185,534 |   |
| Equity investments                           |       | 429,802                                             |       |   | 197,239 |   |   |   | — |   |   |   | (618,885 | ) |   | 8,156 |   |
| Intercompany notes  receivable               |       | 661,313                                             |       |   | 340,905 |   |   |   | — |   |   |   | (1,002,218 | ) |   | — |   |
| Intangible assets                            |       | —                                              |       |   | 31,220 |   |   |   | 37,960 |   |   |   | — |   |   | 69,180 |   |
| Other assets                                 |       | 13,426                                              |       |   | — |   |   |   | 8,041 |   |   |   | — |   |   | 21,467 |   |
| Total assets                                 |       | $                                                   | 1,209,530  |   |   | $ | 1,292,151 |   |   |   | $ | 730,051 |   |   |   | $ | (1,755,280 | ) |   | $ | 1,476,452 |   |
| Liabilities and partners’  capital:     |       |                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Current liabilities                          |       | $                                                   | 5,389      |   |   | $ | 191,516 |   |   |   | $ | 93,459 |   |   |   | $ | (134,177 | ) |   | $ | 156,187 |   |
| Long-term debt                               |       | 505,902                                             |       |   | — |   |   |   | 59,730 |   |   |   | — |   |   | 565,632 |   |
| Deferred income taxes                        |       | —                                              |       |   | 582 |   |   |   | 35,189 |   |   |   | — |   |   | 35,771 |   |
| Intercompany notes  payable                  |       | —                                              |       |   | 661,313 |   |   |   | 340,905 |   |   |   | (1,002,218 | ) |   | — |   |
| Other liabilities                            |       | —                                              |       |   | 8,938 |   |   |   | 11,685 |   |   |   | — |   |   | 20,623 |   |
| Total partners’ capital                 |       | 698,239                                             |       |   | 429,802 |   |   |   | 189,083 |   |   |   | (618,885 | ) |   | 698,239 |   |
| Total liabilities and partners’ capital |       | $                                                   | 1,209,530  |   |   | $ | 1,292,151 |   |   |   | $ | 730,051 |   |   |   | $ | (1,755,280 | ) |   | $ | 1,476,452 |   |

 

20

----

| ** **                              | ** ** | **Statement of Income  Three Months Ended September 30, 2006** | ** ** |
|-----------------------------------------|------------|---------------------------------------------------------------------------------------------------|------------|
| ** **                              | ** ** | **Parent**                                                                                        | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **Total** | ** ** |
| ** **                              | ** ** | **(in thousands)**                                                                           | ** ** |
| Net operating  revenues                 |       | $                                                                                                 | —     |   |   | $ | 42,362 |   |   |   | $ | 40,905 |   |   |   | $ | (2,871 | ) |   | $ | 80,396 |   |
| Operating  expenses                     |       | —                                                                                            |       |   | (20,625 | ) |   |   | (16,292 | ) |   |   | 2,871 |   |   | (34,046 | ) |
| General and  administrative expense(1)  |       | (2                                                                                                | )          |   | (5,050 | ) |   |   | (597 | ) |   |   | — |   |   | (5,649 | ) |
| Merger costs                            |       | —                                                                                            |       |   | (1,112 | ) |   |   | — |   |   |   | — |   |   | (1,112 | ) |
| Depreciation and  amortization expense  |       | —                                                                                            |       |   | (5,138 | ) |   |   | (5,260 | ) |   |   | — |   |   | (10,398 | ) |
| Share of net  income of Frontier        |       | —                                                                                            |       |   | 373 |   |   |   | — |   |   |   | — |   |   | 373 |   |
| Operating income                        |       | (2                                                                                                | )          |   | 10,810 |   |   |   | 18,756 |   |   |   | — |   |   | 29,564 |   |
| Interest expense                        |       | (9,532                                                                                            | )          |   | (40 | ) |   |   | (1,281 | ) |   |   | — |   |   | (10,853 | ) |
| Intercompany  interest income (expense) |       | —                                                                                            |       |   | 7,391 |   |   |   | (7,391 | ) |   |   | — |   |   | — |   |
| Equity earnings                         |       | 28,856                                                                                            |       |   | 10,578 |   |   |   | — |   |   |   | (39,434 | ) |   | — |   |
| Other income                            |       | (87                                                                                               | )          |   | 396 |   |   |   | 411 |   |   |   | — |   |   | 720 |   |
| Income tax  (expense) benefit           |       | —                                                                                            |       |   | (279 | ) |   |   | 83 |   |   |   | — |   |   | (196 | ) |
| Net income                              |       | $                                                                                                 | 19,235     |   |   | $ | 28,856 |   |   |   | $ | 10,578 |   |   |   | $ | (39,434 | ) |   | $ | 19,235 |   |

----

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

| ** **                              | ** ** | **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) benefit           |       | —                                                                                            |       |   | (398 | ) |   |   | (1,035 | ) |   |   | — |   |   | (1,433 | ) |
| Net income                              |       | $                                                                                                 | 12,166     |   |   | $ | 16,576 |   |   |   | $ | 6,124 |   |   |   | $ | (22,700 | ) |   | $ | 12,166 |   |

----

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

21

----

 

| ** **                              | ** ** | **Statement of Income  Nine Months Ended September 30, 2006** | ** ** |
|-----------------------------------------|------------|--------------------------------------------------------------------------------------------------|------------|
| ** **                              | ** ** | **Parent**                                                                                       | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **Total** | ** ** |
| ** **                              | ** ** | **(in thousands)**                                                                          | ** ** |
| Net operating  revenues                 |       | $                                                                                                | —     |   |   | $ | 118,892 |   |   |   | $ | 118,397 |   |   |   | $ | (7,628 | ) |   | $ | 229,661 |   |
| Operating  expenses                     |       | —                                                                                           |       |   | (59,507 | ) |   |   | (47,241 | ) |   |   | 7,628 |   |   | (99,120 | ) |
| General and  administrative expense(1)  |       | (3                                                                                               | )          |   | (16,423 | ) |   |   | (1,810 | ) |   |   | — |   |   | (18,236 | ) |
| Merger costs                            |       | —                                                                                           |       |   | (4,529 | ) |   |   | — |   |   |   | — |   |   | (4,529 | ) |
| Depreciation and  amortization expense  |       | —                                                                                           |       |   | (15,207 | ) |   |   | (15,485 | ) |   |   | — |   |   | (30,692 | ) |
| Share of net  income of Frontier        |       | —                                                                                           |       |   | 1,246 |   |   |   | — |   |   |   | — |   |   | 1,246 |   |
| Operating income                        |       | (3                                                                                               | )          |   | 24,472 |   |   |   | 53,861 |   |   |   | — |   |   | 78,330 |   |
| Interest expense                        |       | (26,534                                                                                          | )          |   | (181 | ) |   |   | (3,314 | ) |   |   | — |   |   | (30,029 | ) |
| Intercompany  interest income (expense) |       | —                                                                                           |       |   | 21,912 |   |   |   | (21,912 | ) |   |   | — |   |   | — |   |
| Equity earnings                         |       | 79,218                                                                                           |       |   | 33,519 |   |   |   | — |   |   |   | (112,737 | ) |   | — |   |
| Other income                            |       | (389                                                                                             | )          |   | 987 |   |   |   | 857 |   |   |   | — |   |   | 1,455 |   |
| Income tax  benefit (expense)           |       | —                                                                                           |       |   | (1,491 | ) |   |   | 4,027 |   |   |   | — |   |   | 2,536 |   |
| Net income                              |       | $                                                                                                | 52,292     |   |   | $ | 79,218 |   |   |   | $ | 33,519 |   |   |   | $ | (112,737 | ) |   | $ | 52,292 |   |

----

(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 | ) |
| General and administrative  expense(1)                          |       | —                                                                                           |       |   | (11,420 | ) |   |   | (1,567 | ) |   |   | — |   |   | (12,987 | ) |
| Accelerated long-term  incentive plan compensation expense |       | —                                                                                           |       |   | (2,675 | ) |   |   | (440 | ) |   |   | — |   |   | (3,115 | ) |
| Line 63 oil release  costs                                      |       | —                                                                                           |       |   | — |   |   |   | (2,000 | ) |   |   | — |   |   | (2,000 | ) |
| Reimbursed general  partner 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 benefit  (expense)                                   |       | —                                                                                           |       |   | (888 | ) |   |   | (1,249 | ) |   |   | — |   |   | (2,137 | ) |
| Net income                                                      |       | $                                                                                                | 27,807     |   |   | $ | 41,397 |   |   |   | $ | 19,691 |   |   |   | $ | (61,088 | ) |   | $ | 27,807 |   |

----

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

22

----

| ** **                                                                         | ** ** | **Statement of Cash Flows  Nine Months Ended September 30, 2006** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **Parent**                                                                                                | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **Total** | ** ** |
| ** **                                                                         | ** ** | **(in thousands)**                                                                                   | ** ** |
| CASH FLOWS FROM  OPERATING ACTIVITIES:                                             |       |                                                                                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Net income                                                                         |       | $                                                                                                         | 52,292     |   |   | $ | 79,218 |   |   |   | $ | 33,519 |   |   |   | $ | (112,737 | ) |   | $ | 52,292 |   |
| Adjustments to reconcile  net income to net cash provided by operating activities: |       |                                                                                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Equity earnings                                                                    |       | (79,218                                                                                                   | )          |   | (33,519 | ) |   |   | — |   |   |   | 112,737 |   |   | — |   |
| Distributions from subsidiaries                                                    |       | 68,714                                                                                                    |       |   | 46,418 |   |   |   | — |   |   |   | (115,132 | ) |   | — |   |
| Depreciation, amortization and other                                               |       | 2,941                                                                                                     |       |   | 16,025 |   |   |   | 8,492 |   |   |   | — |   |   | 27,458 |   |
| Net changes in  operating assets and  liabilities                                  |       | 2,267                                                                                                     |       |   | (30,645 | ) |   |   | (1,081 | ) |   |   | (800 | ) |   | (30,259 | ) |
| NET CASH PROVIDED  BY OPERATING ACTIVITIES                                         |       | 46,996                                                                                                    |       |   | 77,497 |   |   |   | 40,930 |   |   |   | (115,932 | ) |   | 49,491 |   |
| CASH FLOWS FROM  INVESTING ACTIVITIES                                              |       |                                                                                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Acquisitions                                                                       |       | —                                                                                                    |       |   | (2,365 | ) |   |   | — |   |   |   | — |   |   | (2,365 | ) |
| Additions to property, equipment and  other                                        |       | (24                                                                                                       | )          |   | (48,371 | ) |   |   | (18,946 | ) |   |   | — |   |   | (67,341 | ) |
| Additions to pipeline linefill and minimum tank inventory                     |       | —                                                                                                    |       |   | (8,128 | ) |   |   | (7,978 | ) |   |   | — |   |   | (16,106 | ) |
| Intercompany                                                                       |       | (84,000                                                                                                   | )          |   | — |   |   |   | — |   |   |   | 84,000 |   |   | — |   |
| NET CASH USED IN  INVESTING ACTIVITIES                                             |       | (84,024                                                                                                   | )          |   | (58,864 | ) |   |   | (26,924 | ) |   |   | 84,000 |   |   | (85,812 | ) |
| NET CASH PROVIDED  BY (USED IN) FINANCING ACTIVITIES                          |       | 35,458                                                                                                    |       |   | (23,136 | ) |   |   | (12,365 | ) |   |   | 31,932 |   |   | 31,889 |   |
| Effect of translation adjustment                                                   |       | —                                                                                                    |       |   | — |   |   |   | 83 |   |   |   | — |   |   | 83 |   |
| NET INCREASE  (DECREASE) IN CASH AND CASH EQUIVALENTS                              |       | (1,570                                                                                                    | )          |   | (4,503 | ) |   |   | 1,724 |   |   |   | — |   |   | (4,349 | ) |
| CASH AND CASH EQUIVALENTS,  beginning of reporting period                          |       | 4,192                                                                                                     |       |   | 12,484 |   |   |   | 1,388 |   |   |   | — |   |   | 18,064 |   |
| CASH AND CASH  EQUIVALENTS, end of reporting period                           |       | $                                                                                                         | 2,622      |   |   | $ | 7,981 |   |   |   | $ | 3,112 |   |   |   | $ | — |   |   | $ | 13,715 |   |

 

23

----

 

| ** **                                                                               | ** ** | **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                                                    |       |                                                                                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Acquisitions                                                                             |       | —                                                                                                    |       |   | (461,165 | ) |   |   | — |   |   |   | — |   |   | (461,165 | ) |
| Additions to property, equipment and other                                               |       | —                                                                                                    |       |   | (10,916 | ) |   |   | (16,349 | ) |   |   | — |   |   | (27,265 | ) |
| 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 |   |

 

24

----

**ITEM 2.**                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-LookingStatements**

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-Qare subject to all of the risks and uncertainties, many of which are beyond ourcontrol, incident to gathering, transporting, storing, and distributing crudeoil and other related products and buying, gathering, blending and sellingcrude oil or related to our pending merger with Plains All American Pipeline,L.P. For a more detailed description of these and other factors that may affectthe forward-looking statements, please read “Item 1A—Risk Factors”contained elsewhere in this report and in our annual report on Form 10-Kand Form 10-K/A for the year ended December 31, 2005, Plains AllAmerican Pipeline, L.P. joint proxy statement/prospectus on Form S-4,which was declared effective by the Securities and Exchange Commission (“SEC”)on September 29, 2006, as well as our other filings with the SEC. The riskfactors could cause our actual results to differ materially from thosecontained in any forward-looking statement. You should not put unduereliance on these forward-looking statements. We disclaim any obligationto announce publicly the result of any revision to any of the forward-lookingstatements to reflect future events or developments.

**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 andForm 10-K/A for the year ended December 31, 2005.

**Overview**

We are a publicly traded partnership engagedprincipally in the business of gathering, transporting, storing, anddistributing crude oil, refined products and other related products. Wegenerate revenue primarily by transporting such commodities on our pipelines,by leasing capacity in our storage tanks, and by providing other terminalingservices. We also buy and sell crude oil, activities that are generallycomplementary to our other crude oil operations. We conduct our businessthrough two business units, the 

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West Coast Business Unit,which includes activities in California and the Philadelphia, Pennsylvaniaarea, and the Rocky Mountain Business Unit, which includes activities in fiveRocky Mountain states and Alberta, Canada.

We are managed by our general partner, Pacific EnergyGP, LP, which is in turn managed by its general partner, Pacific EnergyManagement LLC (“PEM”). Thus, the officers and Board of Directors of PEM managethe business affairs of Pacific Energy GP, LP and the Partnership. Referencesto our “General Partner” refer to Pacific Energy GP, LP and/or PEM, as thecontext indicates.

Our West Coast Business Unit consists of (i) theLine 2000 crude oil pipeline, (ii) the Line 63 crude oil pipeline system, (iii) thePacific Terminals storage and distribution system, (v) the PacificMarketing and Transportation (“PMT”) gathering system and crude oil marketingactivities, and (iv) the Pacific Atlantic terminals, which we acquired on September 30,2005. Line 2000 and Line 63 are the only common carrier pipelines deliveringcrude oil produced in the San Joaquin Valley, in California, and the twoprimary California Outer Continental Shelf producing fields, Point Arguello andSanta Ynez, to the Los Angeles Basin and Bakersfield. The Pacific Terminalsstorage and distribution system is a crude oil and dark products storage andpipeline distribution system located in the Los Angeles Basin, and the PMTgathering system is a proprietary gathering operation in the San JoaquinValley. The Pacific Atlantic terminals consist of the Martinez and Richmondterminals in the San Francisco, California area and the Paulsboro, New Jerseyand Philadelphia area terminals. These terminals are refined product (and, inthe case of Martinez, crude oil) storage and terminaling facilities.Additionally, we are currently seeking permits for the development of adeepwater petroleum import terminal at Pier 400 in the Port ofLos Angeles, which we expect to begin constructing in mid 2007 (see “Liquidityand Capital Resources—Capital Requirements, Pier 400” for further discussion).

Our Rocky MountainBusiness Unit consists of (i) the Rangeland system, (ii) certainundivided interests in the Western Corridor system, (iii) the Salt LakeCity Core system, (iv) our interest in Frontier Pipeline Company, and (v) theRocky Mountain Products Pipeline, which we acquired on September 30, 2005.Our Rocky Mountain crude oil pipeline systems transport crude oil produced inCanada and the U.S. Rocky Mountain region to refineries in Montana,Wyoming, Colorado and Utah. Deliveries are also made to the refining andmarketing center of Edmonton, Alberta through our Rangeland system. Deliveriesof crude oil are made to refineries directly through our pipelines orindirectly through connections with third-party pipelines. The RockyMountain Products Pipeline supplies refined products to the South Dakota,Wyoming and Colorado markets.

**Proposed MergerWith Plains All American Pipeline, L.P.**

On June 12, 2006, we announced that we hadentered into an agreement with Plains All American Pipeline, L.P. (“PAA”),Plains AAP, L.P., Plains All American GP LLC (“PAA GP LLC”), PEM, and PacificEnergy GP, LP, pursuant to which Pacific Energy Partners, L.P. will be mergedwith and into PAA. In the merger, each of our common unitholders, except LBPacific, LP (“LB Pacific”), the owner of our General Partner, will receive 0.77common units of PAA for each Pacific Energy Partners common unit that theunitholder owns. In addition, pursuant to a purchase agreement between LBPacific and PAA, PAA will acquire from LB Pacific the general partner interestand incentive distribution rights of the Partnership as well as 5,232,500common units and 5,232,500 subordinated units of Pacific Energy Partners fortotal consideration of $700 million in cash. The merger agreement wasunanimously approved by the Board of Directors of PEM, as well as by the boardof directors of PAA’s general partner.

Each of us and PAA made customary representations,warranties and covenants in the merger agreement, which are described in thejoint proxy statement/prospectus filed by us and PAA with the SEC. The mergeris subject to the satisfaction or waiver of certain conditions, including thereceipt of various regulatory approvals or the expiration of various regulatorywaiting periods, all of which approvals or 

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waiting periods have beenobtained, and the adoption and approval of the merger agreement and the mergerby the holders of at least a majority of our outstanding common units(excluding common units held by LB Pacific) and outstanding subordinated units,each voting as a separate class. The merger agreement and the merger must alsobe adopted and approved by the holders of at least a majority of PAA’soutstanding common units.

The special meetings ofunitholders of us and PAA to consider the merger agreement and the merger arescheduled to occur on November 9, 2006. Although we and PAA cannot be surewhen all of the conditions to the merger will be satisfied, the parties expectto complete the merger on November 15, 2006 (assuming the proposals areapproved by the unitholders and all other conditions to closing are satisfied).

**Recent BusinessDevelopments**

The Rocky Mountain Business Unit has accomplishedseveral positive initiatives in 2006. The construction of the initiatingfacility for synthetic crude oil in Edmonton, Alberta was completed in March 2006,and initial movements of synthetic crude oil began immediately thereafter. Thisconnection provides direct access to synthetic crude oil in Edmonton fordelivery through our pipeline systems to U.S. Rocky Mountain refineries.In addition, to facilitate the movement and maintain the quality of syntheticcrude oil, four (three 120,000 barrel and one 80,000 barrel) tanks wereconstructed at storage facilities along the Rangeland and Western Corridorsystems.

The Rocky Mountain Business Unit, through one of oursubsidiaries, Rocky Mountain Pipeline System LLC (“RMPS”), is constructing anexpansion of its Salt Lake City Core crude oil pipeline system from theterminus of Frontier Pipeline near Evanston, Wyoming to the Salt Lake City,Utah, refining complex. The new 16-inch pipeline, which will beapproximately 93 miles in length, will be constructed parallel to and sharemuch of the right-of-ways of RMPS’s existing U-Crude pipeline to Salt Lake City.The new pipeline is designed to transport multiple grades of crude oil insegregated batches, including Canadian heavy crude oil and synthetic crude oil.It will provide the capacity necessary to meet increasing crude oil demand inSalt Lake City, for the near-term and well into the future. The new pipeline willbe constructed in two phases. The first phase, which will add 43.5 miles ofpipeline and approximately 12,000 barrels per day of pumping capacity, isexpected to be completed by year end 2006. Construction of the second phase,which will add the remaining 49.6 miles of pipeline, is expected to becompleted in October 2007. Capacity of the completed pipeline will beapproximately 95,000 barrels per day. The total cost for both phases of theproject is expected to be approximately $77 million and is supported by 10-yeartransportation agreements that have been executed with four Salt Lake Cityrefiners.

In addition, RMPS signed a transportation agreementwith Frontier Oil and Refining Company pursuant to which RMPS is constructing a24-inch crude oil pipeline, approximately 10 miles in length, fromGuernsey, Wyoming to RMPS’s Fort Laramie, Wyoming tank farm and a 16-inchcrude oil pipeline, approximately 85 miles in length, from Fort Laramie toFrontier Oil’s Cheyenne refinery, in exchange for Frontier Oil’s ten-year firmcommitment to ship 35,000 barrels per day on the new pipeline and leaseapproximately 300,000 barrels of storage capacity at Fort Laramie. The totalproject cost is estimated to be $59 million. The project began in the secondquarter of 2006 and is expected to be completed in the second quarter of 2007.Initial capacity will be 55,000 barrels per day, which can be expanded to acapacity of 90,000 barrels per day.

In our West Coast Business Unit, we recently completedconstruction of 450,000 barrels of storage capacity at our Martinez terminal. Inaddition, due to strong demand, we increased our capital budget in the thirdquarter of 2006 to provide for the construction of an additional 850,000barrels of storage capacity at the Martinez terminal for completion in 2007. Atour Philadelphia area terminals, we have completed an ethanol expansion projectwhich enabled us to increase our ethanol handling and blending capabilities andincrease our marine receipt capabilities. At Pacific Terminals, we refurbishedand placed 

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in service 300,000 barrelsof black oil storage capacity in the third quarter of 2006 and expect tocomplete refurbishing an additional 300,000 barrels of black oil storage in thefirst quarter of 2007. We are also making infrastructure changes to increasepumping capacity and improve operating efficiencies of various PacificTerminals facilities, which we expect to complete in 2007.

In addition, we continueto develop a deepwater petroleum import terminal at Pier 400 and Terminal Islandin the Port of Los Angeles to handle marine receipts of crude oil and refineryfeedstocks. See “Liquity and Capital Resources—Capital Requirements—Pier 400”for a discussion of the Pier 400 project.

**Conversion ofSubordinated Units**

In August 2006, 2,616,250of the Partnership’s subordinated units were converted to common units pursuantto the terms of the partnership agreement of the Partnership.

**BusinessFundamentals**

***Pipeline Transportation***

We generate pipeline transportation revenue bycharging tariff rates for transporting crude oil and refined products on ourcommon carrier pipelines. The fundamental items impacting our pipelinetransportation revenue are the volume of crude oil and refined products, orthroughput, we transport on our pipelines, and our tariff rates. Throughput onour pipelines fluctuates based on the volume of crude oil and refined productsavailable for transportation on our pipelines, the demand for such products,refinery downtime, the availability of alternate sources of crude oil for therefineries we serve and the availability of refined products from othersources.

Our shippers determine the amount of crude oil andrefined products we transport on our pipelines, but we can influence thesevolumes through the level and type of service we provide and the rates wecharge. Our rates need to be competitive to transportation alternatives, whichare mostly other pipelines.

The tariff rates we charge on Line 2000 and the Line63 system are regulated by the California Public Utilities Commission (“CPUC”).Tariffs on Line 2000 are established based on market considerations, subject tocertain contractual limitations. Tariffs on Line 63, which are cost-of-servicebased tariffs, are based upon the costs to operate and maintain the pipeline,as well as charges for the depreciation of the capital investment in thepipeline and the authorized rate of return. The tariff rates charged on ourU.S. Rocky Mountain crude oil pipelines are regulated by either the FederalEnergy Regulatory Commission (“FERC”) or the Wyoming Public Service Commission(“Wyoming PSC”), generally under a cost-of-service approach. The FERC, WyomingPSC, and the Colorado Public Utilities Commission each regulate various tariffson the Rocky Mountain Products Pipeline, which include both cost and marketbased rates.

Although the tariff rates we charge on the system areregulated, competitive forces may also limit the amount of our filed rates. TheFERC tariff rates are generally adjusted, effective July 1 of each year,by the amount of change in the Producer Price Index for Finished Goods, plus1.3%.

Following arerecent tariff rate increases on our pipelines:

·       In September 2006, wefiled an application with the CPUC requesting a 9.5% tariff increase on Line 63with a proposed effective date of November 1, 2006.

·       On July 1, 2006, weincreased the FERC tariff rates on our U.S. Rocky Mountain crude oil andproducts pipelines by 6.1% based on the FERC index adjustment. In addition,tariff rates on the Reno to Casper/Guersney segment of the line were increasedin a cost of service tariff rate filing.

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·       On May 1, 2006, weincreased the tariff rates on our Line 2000 by approximately 7.1%.

·       Effective August 1,2005, we implemented a temporary surcharge of $0.10 per barrel on ourLine 63 long-haul tariff rates to recover costs relating to the Line63 oil release we experienced in 2005, together with other costs incurred or tobe incurred as a result of rain-related earth movement and stream erosion.

·       On July 1, 2005, weincreased the FERC tariff rates on our U.S. Rocky Mountain crude oil pipelinesby 3.6% based on the FERC index adjustment.

·       On May 1, 2005 weincreased the tariff rates on our Line 2000 by approximately 4.8%.

Tariff rate increases on our West Coast pipelinespartially mitigate the impact of declining throughput on these pipelines.

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.Although this decline can, in the short term, be offset in whole or in part, byadditional drilling or the implementation of recovery enhancement measures, inthe San Joaquin Valley and in the California Outer Continental Shelf, totalproduction is generally declining.

In the Rocky Mountains, our pipelines are connected toU.S. and Canadian sources of crude oil. Our Rangeland system in Alberta givesus access to significant supplies of Canadian crude oil, including syntheticcrude oil, which we believe will replace any long term U.S. Rocky Mountainproduction declines and meet growing demand in the U.S. Rocky Mountain region.In recent months, production in the U.S. Rocky Mountains has increasedwith the increased amount of natural gas related drilling, which results inincreased volumes of crude oil and condensate. We believe, however, that thelonger term production of crude oil in the U.S. Rocky Mountains will resume itshistorical decline.

The Rocky MountainProducts Pipeline acquired in 2005 is a common carrier petroleum productspipeline and terminals network. The system generates revenues throughtransportation tariffs for volumes of petroleum products it ships. Thesetariffs vary depending upon where the product originates and where ultimatedelivery occurs. The products terminals on the pipeline system also earnrevenues by providing additional services.

***Storage and Terminaling***

We provide storage and terminaling services torefineries in the Los Angeles Basin and San Francisco areas in California andin the Philadelphia, Pennsylvania area. The fundamental items impacting our storageand terminaling revenue are the amount of storage capacity we have under lease,the lease rates for that capacity and the length of each lease.

Demand for crude oil storage capacity tends to be morestable over time and leases for crude oil storage capacity are usually longterm (more than one year). Demand for storage capacity for other dark productsis less stable than for crude oil storage and varies depending on, among otherthings, refinery production runs and maintenance activities. Leases for otherdark products storage capacity are usually short term (less that one year).While Pacific Terminals’ rates are subject to regulation by the CPUC, the CPUChas allowed Pacific Terminals to establish rates based on market conditionsthrough negotiated contracts.

The Martinez, Richmond, Paulsboro and Philadelphiaterminals that we purchased in September 2005 are refined product (and, inthe case of Martinez, crude oil) storage and terminaling facilities thatgenerate revenues primarily from fees that we charge customers for storage,throughput and other services. Demand 

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for refined productsstorage capacity, mostly at the Philadelphia area terminals, depends onconnections with refineries and petroleum products pipelines owned and operatedby third parties.

Demand for refined products storage at our SanFrancisco area terminals tends to be stable over time as most of our leasecontracts are evergreen contracts for a year or more. Additionally, the SanFrancisco area terminals are not overly reliant on local area refineryproduction to satisfy the supply of refined products. The San Francisco areaterminals receive a significant volume of imported refined products and crudeoil into the San Francisco harbor. One of our goals is to increase the storagecapacity of our Martinez terminal. We recently completed construction of450,000 barrels of storage, which we placed in service at the end of the thirdquarter of 2006. We also expect to complete construction of an additional850,000 barrels of storage capacity at the Martinez terminal in 2007.

The throughput servicebusiness of our Philadelphia area terminals, which receive products from localrefineries, the U.S. Gulf Coast and New York Harbor, is dependent on the demandfor gasoline and other products in the Philadelphia market. In addition, ourPhiladelphia area terminals provide storage services for local refineries andother marketers.

***Pipeline Buy/Sell Transportation***

Throughput on our Rangeland system varies with many ofthe same factors described in “Pipeline Transportation” above.

We have made significant changes to the revenue-generatingcapability of the Rangeland system, which we acquired in mid-2004, by (i) combiningand fully integrating all of our Canadian and U.S. Rocky Mountain pipelineassets under common management, (ii) establishing connections with otherpipelines, thereby expanding the throughput of the Rangeland system, and (iii) constructinga pump station and receiving terminal in Edmonton, Alberta, which beganoperating in March 2006. The volume of throughput originating at ourEdmonton, Alberta, initiation station will vary with our success in attractingnew supplies of synthetic crude oil to our system.

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 Energy andUtilities 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 1,2005, we increased the location differentials on the Rangeland pipeline by anaverage of 6.9%.

***Gathering Activities and Marketing Business***

Through our PMT subsidiary, we purchase, gather, andresell crude oil, principally in California’s San Joaquin Valley and, to amuch lesser extent, in the Rocky Mountain area in the vicinity of ourpipelines. In the third quarter of 2005, we began selectively purchasing andreselling crude oil in other areas as well, although this is not a primaryfocus.

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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 gatheringsystem effectively extends our pipeline network to capture supplies of crudeoil bound for transportation to Los Angeles that might not otherwise beshipped through our pipelines. In the U.S. and Canadian Rocky Mountain area,PMT facilitates transportation on our Canadian and U.S. Rocky Mountainpipelines by purchasing crude oil from Canada for resale in the Rocky Mountainmarketplace.

The contribution of ourPMT subsidiary is, for several reasons, a variable part of our income. First,it varies with the price differential between the cost of the varying grades ofcrude oil that PMT buys for use in its gathering operations, and the price ofthe crude oil it sells. Costs and sales prices are generally impacted by crudeoil prices, as well as by local supply and demand forces, including regulationsaffecting refined product specifications. Second, it varies with the pricedifferential between crude oil purchased on one price basis and sold on anotherprice basis. Third, it varies with the volumes gathered or purchased for sale.Finally, it varies with the effectiveness of our hedging program. We seek tocontrol these variations through our risk management policy, which providesspecific guidelines for our crude oil marketing and hedging activities andrequires oversight by our senior management.

***Operating Expenses***

Many of our operating expenses, including the cost offield and support personnel, maintenance, control systems, telecommunications,rights-of-way and insurance, are relatively fixed and vary little with changesin throughput. Certain of our costs, however, do vary with throughput, the mostmaterial being the cost of power used to operate pump stations along ourpipelines or to operate our terminals. Major maintenance costs can varydepending on a particular asset’s age and also with regulatory requirements,such as mandatory inspections at defined intervals. Unanticipated costs caninclude the costs of cleanup of any oil or product release, to the extent theyare not covered by insurance, and repairs caused by severe weather as weexperienced in California and Alberta, Canada, in 2005.

We do not have anyemployees, except in Canada. Our General Partner provides employees to conductour U.S. operations. We and our General Partner collectively employapproximately 460 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 (SteelWorkers), with whom we have a collective bargaining agreement that will end onOctober 1, 2009. Our General Partner does not conduct any business otherthan with respect to the Partnership. All expenses incurred by our GeneralPartner are charged to us.

***Impact of Foreign Exchange Rates***

Assets and liabilities ofour Canadian subsidiaries are translated to U.S. dollars using the applicableexchange rate as of the end of each reporting period. Revenues, expenses andcash flow are translated using the average exchange rate during the reportingperiod. The reported cash flow of our Canadian operations is based on the U.S.dollar equivalent of such amounts measured in Canadian dollars. The results ofour Canadian operations and distributions from our Canadian subsidiaries to thePartnership may vary in U.S. dollar terms based on fluctuations in currencyexchange rates irrespective of our Canadian subsidiaries’ underlying operatingresults. In addition, the amount of monies we repatriate from Canada will varywith fluctuations in currency exchange rates and may impact the cash availablefor distribution to our unitholders. We have entered into certain foreignexchange contracts to mitigate currency exchange risks (see “Item 3—Quantitativeand Qualitative Disclosures about Market Risk”).

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**Critical Accounting 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 2, Significant Accounting Policies,” to ourconsolidated financial statements in our annual report on Form 10-Kfor the year ended December 31, 2005) and estimates, the following mayinvolve a 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 to be treated as a purchase of a business or a set of netassets because excess purchase price is only allocated to goodwill in abusiness combination. Determination of the fair value of the assets involves anumber of judgments and estimates. In our major acquisitions to date, we haveengaged an outside valuation firm to provide us with an appraisal report, whichwe utilized in determining the purchase price allocation. The allocation of thepurchase price to different asset classes impacts the depreciation andamortization expense we subsequently record. The principal assets we haveacquired to date are property, pipelines, storage tanks and equipment, as wellas intangible assets such as customer relationships and contractual rights.

·       Wedepreciate and amortize the components of our property and equipment andintangible assets on a straight-line basis over the estimated useful lives ofthe assets. The estimates of the assets’ useful lives require our judgment andour knowledge of the assets being depreciated and amortized. When necessary,the assets’ useful lives are revised and the impact on depreciation andamortization is adjusted 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. Inmaking these estimates, we consider information that is currently available,existing technology, enacted laws and regulations, and our estimates of thetiming of the required remedial actions. We may use outside environmentalconsultants to assist us in making these estimates. We also are required toestimate the amount of any probable recoveries, including insurance recoveries.In addition, generally accepted accounting principles require us to establishliabilities for the costs of asset retirement obligations when a legal orcontractual obligation exists to dispose of or restore an asset upon its retirementand the timing and cost of such work is reasonably estimable. We will recordsuch liabilities only when such timing and costs are reasonably determinable.

·       Fromtime to time, a shipper or group of shippers or regulatory body may initiateregulatory proceedings or other actions challenging the tariffs we charge orhave charged. In such cases, we assess the proceeding on an ongoing basis as toits likely outcome in order to determine whether to accrue for a futureexpense. We use outside regulatory lawyers and financial experts to assist usin these assessments.

·       Ourinventory of crude oil for our PMT gathering operations and marketing business,our Canadian operations, any inventory earned through our tariffs for thetransportation of crude oil in our common carrier pipelines and any inventoryof refined products at our terminals is carried in our accounts at the lower ofcost or market value, unless it is hedged, in which case it is carried at 

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market. On anyhedged portion, we are exposed to the potential that our hedges may not beperfectly effective. On any unhedged portion, we are exposed to the potentialfor a write-down to market value. To the extent we owe our customers crude oilor refined products, we are exposed to the potential of additional costs in theevent market prices increase.

**Results of Operations**

Internally, in ouranalysis of operating results, we consider the impact of unusual items that webelieve affect comparability between periods. We also believe that providing adiscussion and analysis of our results that is comparable year over yearprovides a more accurate and thorough analysis of our results of operations. Wehave provided a reconciliation of net income to the results of our operations,excluding those unusual items, in our analyses below. Following is adescription of each of the unusual items that impacted the results of ouroperations.

*Merger costs.**  *On June 12, 2006, we announced that we hadentered into a merger agreement with *Plains* All American Pipeline, L.P.,pursuant to which we will be merged into PAA. For the three and nine monthsended September 30, 2006, we incurred $1.1 million and $4.5 million,respectively, in investment banking fees, legal fees and other transactioncosts directly related to the merger.

*Tax rate adjustments tonet deferred tax liabilities.**  *Duringthe second quarter of 2006, the Canadian and Alberta governments enactedlegislation that will reduce federal and provincial income taxes. We adjustedour estimate of future income tax rates in our estimates of deferred tax assetsand liabilities and recognized a $4.6 million deferred tax benefit in thesecond quarter of 2006.

*Line 63 oil release.**  *On March 23, 2005, a release of approximately3,400 barrels of crude oil occurred on PPS’s Line 63 as a result of a landslidecaused by heavy rainfall in northern Los Angeles County. As a result of therelease, we recorded $2.0 million net oil release costs in the firstquarter of 2005, consisting of what we now estimate to be $25.5 million oftotal costs relating to the release, net of insurance recoveries of$18.6 million to date and accrued future net insurance recoveries of $4.6million at September 30, 2006.

*Accelerated long-termincentive plan compensation expense.**  *On March 3, 2005, in connection with the changein control of our General Partner, all restricted units then outstanding underthe Long-term Incentive Plan immediately vested. As a result, we recorded a$3.1 million compensation expense in the first quarter of 2005.

*Reimbursed general partnertransaction costs.**  *Pursuant to anagreement entered into in connection with the sale of The Anschutz Corporation’s(the owner of our General Partner before March 3, 2005) interest in us, LBPacific, LP and The Anschutz Corporation reimbursed us $2.4 million forthe cost incurred in connection with a consent solicitation prepared anddelivered to the holders of our 71¤8%senior notes to approve certain amendments to the governing indenture and forseverance and other costs incurred in connection with the sale of our GeneralPartner. In accordance with generally accepted accounting principles, werecorded $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 capital contribution to the Partnership byour General Partner.

***Three Months Ended September 30,2006 Compared to Three Months Ended September 30, 2005***

***Summary***

Net income for the threemonths ended September 30, 2006 was $19.2 million, or $0.48 per dilutedlimited partner unit, compared to $12.2 million, or $0.39 per diluted limitedpartner unit, for the three months ended September 30, 2005.

Net income for the three months ended September 30,2006 includes a full quarter of operations of the Pacific Atlantic terminalsand the Rocky Mountain Products Pipeline, which we acquired on September 30,2005.

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Followingis a reconciliation of net income to the results of our operations, excludingthe unusual items mentioned above:

| ** **                                      | ** ** | **Three Months Ended  September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-------------------------------------------------|------------|------------------------------------------------------|------------|------------|------------|------------|------------|
| ** **                                      | ** ** | **2006**                                             | ** ** | **2005**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                      | ** ** | **(In thousands)**                              | ** ** | ** ** | ** ** |
| Net income                                      |       | $                                                    | 19,235     |       | $          | 12,166     |       | $ | 7,069 |   |   | 58 | % |   |
| Add: Merger costs                               |       | 1,112                                                |       | —     |       | 1,112      |       |   | — |   |   |
|                                            |       | $                                                    | 20,347     |       | $          | 12,166     |       | $ | 8,181 |   |   | 67 | % |   |
| Diluted weighted average  limited partner units |       | 39,321                                               |       | 30,762     |       | 8,559      |       |   | 28 | % |   |

 

The improvement in theresults of operations, excluding the effect of the unusual items mentionedabove, reflects the benefit of (i) the operations of the Pacific Atlanticterminals and the Rocky Mountain Products Pipeline acquired on September 30,2005, (ii) higher operating income on our West Coast pipelines, (iii) increasedmargins in our crude oil marketing business, and (iv) higher revenue fromour Pacific Terminals storage facilities. These increases were partially offsetby a decline in Rangeland’s buy/sell transportation revenue. In addition, theincreases in income were partially offset by higher interest expense primarilydue to higher debt levels, and increased general and administrative costs.There were 39.3 million weighted average limited partner units outstanding inthe three months ended September 30, 2006, approximately 28% more limitedpartner units than the 30.8 million weighted average units outstanding in thethree months ended September 30, 2005. The higher debt levels andincreased number of units reflect the funding of the acquisition of the PacificAtlantic terminals and the Rocky Mountain Products Pipeline.

***Segment Information***

Thefollowing is a discussion of segment operating income, which does not includegeneral and administrative expenses, merger costs, accelerated long-termincentive compensation plan expense and reimbursed general partner transactioncosts, as these items are not allocated to the West Coast and Rocky Mountainbusiness units.

| ** **                 | ** ** | **Three Months Ended  September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|----------------------------|------------|------------------------------------------------------|------------|------------|------------|------------|------------|
| **West Coast**        | ** ** | ** **                                           | ** ** | **2006**   | ** ** | **2005**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                 | ** ** | **(In thousands)**                              | ** ** | ** ** | ** ** |
| Operating income           |       | $                                                    | 24,152     |       | $          | 9,813      |       | $ | 14,339 |   |   | 146 | % |   |
| Operating data:            |       |                                                 |       |       |       |       |       |   |   |   |   |
| Pipeline  throughput (bpd) |       | 111.0                                                |       | 104.4      |       | 6.6        |       |   | 6 | % |   |
|                            |            |                                                      |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

West Coast operating income was higher in 2006 due to (i) theresult of operations of the Pacific Atlantic terminals, which were acquired in September 2005,(ii) higher pipeline transportation income, (iii) higher margins inour crude oil marketing business, and (iv) increased utilization, highertank lease rates and lower operating expenses for our Pacific Terminals storagefacilities.

Although there continue to be natural productiondeclines of San Joaquin Valley Crude and Outer Continental Shelf crude oil, theWest Coast pipeline volumes were approximately 6% higher in the third quarterof 2006 than in the corresponding quarter of 2005. In addition, as a result ofa pipeline project completed in October 2005, we realized a substantialincrease in deliveries to Bakersfield refineries, which volumes are notincluded in the statistic above. Additionally, tariff increases on Line 2000and Line 63 increased West Coast pipeline transportation income.

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Crudeoil marketing income was significantly higher in the third quarter of 2006 thanthe corresponding period in 2005. Favorable margins and increased crude oilvolumes in the third quarter of 2006 contributed to the improvement.

| ** **                        | ** ** | **Three Months Ended   September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-----------------------------------|------------|------------------------------------------------------------|------------|------------|------------|------------|------------|
| **Rocky Mountains**          | ** ** | ** **                                                 | ** ** | **2006**   | ** ** | **2005**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                        | ** ** | **(In thousands)**                                    | ** ** | ** ** | ** ** |
| Operating income                  |       | $                                                          | 12,173     |       | $          | 13,644     |       | $ | (1,471 | ) |   | (11 | )% |   |
| Operating data (bpd):             |       |                                                       |       |       |       |       |       |   |   |   |   |
| Rangeland  pipeline system:       |       |                                                       |       |       |       |       |       |   |   |   |   |
| Sundre—North                 |       | 19.7                                                       |       | 19.3       |       | 0.4        |       |   | 2 | % |   |
| Sundre—South                 |       | 48.5                                                       |       | 48.1       |       | 0.4        |       |   | 1 |   |   |
| Western Corridor system           |       | 26.6                                                       |       | 26.8       |       | (0.2       | )          |   | (1 | ) |   |
| Salt Lake City Core system        |       | 126.7                                                      |       | 125.6      |       | 1.1        |       |   | 1 |   |   |
| Frontier pipeline                 |       | 46.2                                                       |       | 49.6       |       | (3.4       | )          |   | (7 | ) |   |
| Rocky Mountain  Products Pipeline |       | 59.2                                                       |       | —     |       | 59.2       |       |   | — |   |   |
|                                   |            |                                                            |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

For the three months endedSeptember 30, 2006, operating income was $12.2 million, compared to $13.6million for the three months ended September 30, 2005. The $1.4 milliondecrease was primarily due to lower operating income for the Rangeland pipelinesystem in Alberta, partially offset by higher volumes on the Western Corridorsystem and the income contribution from the Rocky Mountain Products Pipelinethat was part of the Valero L.P. acquisition. The decrease in Rangeland’s thirdquarter 2006 income was due in part to the absence of an unusual item thatbenefited the 2005 quarter: the correction of an error in the procedures usedto properly account for inventory and cost of goods sold that resulted in anincrease in Rangeland’s pre-tax income in the third quarter 2005 of $1.2million ($0.7 million after tax).

***Statement of Income—Discussionand Analysis***

| ** **                                | ** ** | **Three Months Ended  September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-------------------------------------------|------------|------------------------------------------------------|------------|------------|------------|------------|------------|
| **Revenues**                              | ** ** | ** **                                           | ** ** | **2006**   | ** ** | **2005**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                | ** ** | **(In thousands)**                              | ** ** | ** ** | ** ** |
| Pipeline  transportation revenue          |       | $                                                    | 36,995     |       | $          | 27,283     |       | $ | 9,712 |   |   | 36 | % |   |
| Storage and  terminaling revenue          |       | 23,467                                               |       | 9,731      |       | 13,736     |       |   | 141 |   |   |
| Pipeline buy/sell  transportation revenue |       | 10,010                                               |       | 11,683     |       | (1,673     | )          |   | (14 | ) |   |
| Crude oil sales,  net of purchases:       |       |                                                 |       |       |       |       |       |   |   |   |   |
| Crude oil sales                           |       | 431,200                                              |       | 194,724    |       | 236,476    |       |   | 121 |   |   |
| Crude oil purchases                       |       | (421,276                                             | )          | (188,901   | )          | 232,375    |       |   | 123 |   |   |
| Crude oil sales, net of purchases         |       | 9,924                                                |       | 5,823      |       | 4,101      |       |   | 70 |   |   |
| Net revenue                               |       | $                                                    | 80,396     |       | $          | 54,520     |       | $ | 25,876 |   |   | 47 | % |   |
|                                           |            |                                                      |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

Pipeline transportation revenues in 2006 includerevenues from our Rocky Mountain Products Pipeline, which was acquired in September 2005,and trucking revenues from the purchase of a crude oil trucking business in January 2006.In our West Coast Business Unit, transportation revenue was higher because ofhigher pipeline transportation volumes, higher tariff rates and increaseddeliveries to Bakersfield area refineries.

Storage and terminaling revenue increased in 2006primarily because of the acquisition of the Pacific Atlantic terminals in September 2005.In addition, higher lease rates and greater utilization of our PacificTerminals storage facilities also increased storage and terminaling revenue.

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Pipeline buy/sell transportation revenues decreased in2006 because of the correction of an error in 2005, which increased 2005 pipelinebuy/sell transportation revenues by $1.2 million.

Crudeoil sales net of purchases increased because of higher overall margins. Highercrude oil prices increased gross sales and purchases.

| ** **                          | ** ** | **Three Months Ended  September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-------------------------------------|------------|------------------------------------------------------|------------|------------|------------|------------|------------|
| **Expenses**                        | ** ** | ** **                                           | ** ** | **2006**   | ** ** | **2005**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                          | ** ** | **(In thousands)**                              | ** ** | ** ** | ** ** |
| Operating expenses                  |       | $                                                    | 34,046     |       | $          | 25,019     |       | $ | 9,027 |   |   | 36 | % |   |
| General and  administrative expense |       | 5,649                                                |       | 4,115      |       | 1,534      |       |   | 37 |   |   |
| Depreciation and  amortization      |       | 10,398                                               |       | 6,560      |       | 3,838      |       |   | 59 |   |   |
| Merger costs                        |       | 1,112                                                |       | —     |       | 1,112      |       |   | — |   |   |
|                                |       | $                                                    | 51,205     |       | $          | 35,694     |       | $ | 15,511 |   |   | 43 | % |   |
|                                     |            |                                                      |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

The increase in operating expenses was relatedprimarily to the incremental operations of the Pacific Atlantic terminals andthe Rocky Mountain Products Pipeline, which were acquired in September 2005.

The increase in general and administrative expense wasprimarily associated with the support of newly acquired assets, professionalfees and $0.4 million of costs for the LB Pacific, LP option plan, which we arerequired by generally accepted accounting principles to record as our expenseeven though the plan is funded by LB Pacific, LP and not by the Partnership.

The increase in depreciation and amortization includes$3.3 million for depreciation on the Rocky Mountain Products Pipeline and thePacific Atlantic terminals acquired in September 2005.

Mergercosts are discussed above.

| ** **                                  | ** ** | **Three Months Ended  September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|---------------------------------------------|------------|------------------------------------------------------|------------|------------|------------|------------|------------|
| **Other Income and Expense** | ** ** | ** **                                           | ** ** | **2006**   | ** ** | **2005**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                  | ** ** | **(In thousands)**                              | ** ** | ** ** | ** ** |
| Share of net  income of Frontier            |       | $                                                    | 373        |       | $          | 516        |       | $ | (143 | ) |   | (28 | )% |   |
| Interest expense                            |       | $                                                    | 10,853     |       | $          | 6,237      |       | $ | 4,616 |   |   | 74 |   |   |
| Other income                                |       | $                                                    | 720        |       | $          | 494        |       | $ | 226 |   |   | 46 |   |   |
| Income tax expense  (benefit)               |       | $                                                    | 196        |       | $          | 1,433      |       | $ | (1,237 | ) |   | (86 | ) |   |
|                                             |            |                                                      |            |            |            |            |            |  |  |  |  |  |  |  |  |  |

 

The decrease in our share of Frontier’s net income wasmainly attributed to higher operating costs at Frontier.

The increase in interest expense was due to additionalborrowings incurred to partially fund the acquisition of the Pacific Atlanticterminals and the Rocky Mountain Products Pipeline. Our weighted averageborrowings during the three months ended September 30, 2006 were$650 million compared to $352 million in the corresponding period in2005. Floating interest rates were slightly higher in 2006. Our weightedaverage interest rate was 7.1% for the period ended September 30, 2006,compared to a weighted average interest rate of 7.0% for the correspondingperiod in 2005. Capitalized interest was $0.8 million and $0.2 million for thethree months ended September 30, 2006 and 2005, respectively.

Income tax expense is a function of the income of ourCanadian subsidiaries, which are taxable entities in Canada. In addition,certain kinds of repatriation of funds into the U.S. are subject to Canadianwithholding tax. Income tax expense is lower as a result of lower income fromour Canadian subsidiaries.

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***Nine Months Ended September 30, 2006 Compared toNine Months Ended September 30, 2005***

***Summary***

Net income for the nine months ended September 30,2006 was $52.3 million, or $1.31 per diluted limited partner unit, compared to$27.8 million, or $0.96 per diluted limited partner unit, for the nine monthsended September 30, 2005.

Net income for the nine months ended September 30,2006 includes nine months of operations of the Pacific Atlantic terminals andthe Rocky Mountain Products Pipeline, which were acquired on September 30,2005.

Followingis a reconciliation of net income to the results of our operations, excludingthe unusual items mentioned above:

| ** **                                            | ** ** | **Nine  Months Ended  September 30,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-------------------------------------------------------|------------|-----------------------------------------------------------|------------|------------|------------|------------|------------|
| ** **                                            | ** ** | **2006**                                                  | ** ** | **2005**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                            | ** ** | **(In thousands)**                                   | ** ** | ** ** | ** ** |
| Net income                                            |       | $                                                         | 52,292     |       | $          | 27,807     |       | $ | 24,485 |   |   | 88 | % |   |
| Add: Merger costs                                     |       | 4,529                                                     |       | —     |       | 4,529      |       |   | — |   |   |
| Line 63 oil release costs                             |       | —                                                    |       | 2,000      |       | (2,000     | )          |   | — |   |   |
| Accelerated long-term incentive compensation expense  |       | —                                                    |       | 3,115      |       | (3,115     | )          |   | — |   |   |
| Reimbursed general partner transaction costs          |       | —                                                    |       | 1,807      |       | (1,807     | )          |   | — |   |   |
| Less: Tax rate  adjustments to deferred tax liability |       | (4,560                                                    | )          | —     |       | (4,560     | )          |   | — |   |   |
|                                                  |       | $                                                         | 52,261     |       | $          | 34,729     |       | $ | 17,532 |   |   | 50 | % |   |
| Diluted weighted average  limited partner units       |       | 39,332                                                    |       | 30,089     |       | 9,243      |       |   | 31 | % |   |

 

The improvement in the resultsof operations, excluding the effect of the unusual items mentioned above,reflects the benefit of (i) the operations of the Pacific Atlanticterminals and the Rocky Mountain Products Pipeline acquired in September 2005;(ii) increased margins in our crude oil marketing business, (iii) higherpipeline transportation income in our West Coast Business Unit, and (iv) increasedrevenue from our Pacific Terminals storage facilities. These increases werepartially offset by higher interest expense primarily due to higher debt levelsand increased general and administrative costs. There were 39.3 millionweighted average limited partner units outstanding in the nine months ended September 30,2006, approximately 31% more limited partner units than the 30.1 millionweighted average units outstanding in the nine months ended September 30,2005, due to the sale of additional common units to partially fund theacquisition of the Pacific Atlantic terminals and the Rocky Mountain ProductsPipeline.

37

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***Segment Information***

Thefollowing is a discussion of segment operating income. Segment operating incomedoes not include general and administrative expenses, merger costs, acceleratedlong-term incentive compensation plan expense and reimbursed general partnertransaction costs, as these items are not allocated to the West Coast and RockyMountain business units.

| ** **                     | ** ** | **Nine  Months Ended  September 30,** | ** ** | ** **              | ** ** | ** ** | ** ** |
|--------------------------------|------------|-----------------------------------------------------------|------------|-------------------------|------------|------------|------------|
| **West Coast**            | ** ** | ** **                                                | ** ** | **2006**                | ** ** | **2005**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                     | ** ** | ** **                                                | ** ** | **(In thousands)** | ** ** | ** ** | ** ** |
| Operating income               |       | $                                                         | 63,769     |                    | $          | 31,962     |       | $ | 31,807 |   |   | 100 | % |   |
| Add: Line 63 oil  release cost |       | —                                                    |       | 2,000                   |       | (2,000     | )          |   | — |   |   |
|                           |       | $                                                         | 63,769     |                    | $          | 33,962     |       | $ | 29,807 |   |   | 88 | % |   |
| Operating data:                |       |                                                      |       |                    |       |       |       |   |   |   |   |
| Pipeline  throughput (bpd)     |       | 112.6                                                     |       | 120.8                   |       | (8.2       | )          |   | (7 | )% |   |

 

West Coast operating income was higher in 2006 due to (i) theresult of operations of the Pacific Atlantic terminals, which were acquired in September 2005,(ii) higher pipeline and transportation income due to increased deliveriesto the Bakersfield, California refineries, higher tariff rates and lower repairand maintenance costs, (iii) increased utilization, greater capacity andhigher lease rates for our Pacific Terminals storage facilities, and (iv) highermargins in our crude oil marketing business. Margins were above average in the2006 period and below average in 2005 in our crude oil marketing business dueto pricing pressures from steeply discounted crude oil imports, and anunfavorable purchase contract that expired on March 31, 2005. The ninemonth period of 2006 also reflects a full period of contribution from certaincrude oil contracts we acquired on July 1, 2005. Partially offsettingthese increases were lower West Coast long-haul pipeline volumes.

Thedecline in West Coast volumes during the nine month period ended September 30,2006 was offset by tariff increases on Line 2000 and Line 63, and increaseddeliveries to the Bakersfield area, which volumes are not included in thestatistic above. Reduced volumes on our West Coast pipelines were caused bylower San Joaquin Valley and Outer Continental Shelf production, third-partyproduction problems, a shift of light crude being transported north to the SanFrancisco Bay area, which had previously been transported south on ourpipelines to the Los Angeles area, and San Francisco area refinery turnaroundsin the first half of 2005. We benefited from those turnarounds in 2005 becausethey increased volumes transported south on our pipelines to Los Angeles arearefineries. Additionally, in 2005 we incurred $1.4 million of rain relatedrepairs.

| ** **                        | ** ** | **Nine Months Ended  September 30,** | ** ** | ** **              | ** ** | ** ** | ** ** |
|-----------------------------------|------------|-----------------------------------------------------|------------|-------------------------|------------|------------|------------|
| **Rocky Mountains**          | ** ** | ** **                                          | ** ** | **2006**                | ** ** | **2005**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                        | ** ** | ** **                                          | ** ** | **(In thousands)** | ** ** | ** ** | ** ** |
| Operating income                  |       | $                                                   | 37,326     |                    | $          | 32,183     |       | $ | 5,143 |   |   | 16 | % |   |
| Operating data  (bpd):            |       |                                                |       |                    |       |       |       |   |   |   |   |
| Rangeland pipeline system:        |       |                                                |       |                    |       |       |       |   |   |   |   |
| Sundre—North                 |       | 21.9                                                |       | 21.3                    |       | 0.6        |       |   | 3 | % |   |
| Sundre—South                 |       | 44.5                                                |       | 45.3                    |       | (0.8       | )          |   | (2 | ) |   |
| Western Corridor system           |       | 26.3                                                |       | 24.0                    |       | 2.3        |       |   | 10 |   |   |
| Salt Lake City Core system        |       | 125.3                                               |       | 119.8                   |       | 5.5        |       |   | 5 |   |   |
| Frontier pipeline                 |       | 46.6                                                |       | 46.4                    |       | 0.2        |       |   | 1 |   |   |
| Rocky Mountain  Products Pipeline |       | 60.3                                                |       | —                  |       | 60.3       |       |   | — |   |   |
|                                   |            |                                                     |            |                         |            |            |            |  |  |  |  |  |  |  |  |  |

 

38

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For the nine months ended September 30,2006, operating income was $37.3 million compared to $32.2 million for thenine months ended September 30, 2005. The increase included the results ofoperations of the Rocky Mountain Products Pipeline, which was acquired in September 2006.Higher volumes and tariffs on our U.S. Rocky Mountain pipelines alsocontributed to increased operating income.

***Statement of Income—Discussionand Analysis***

| ** **                                | ** ** | **Nine Months Ended  September 30,** | ** ** | ** **              | ** ** | ** ** | ** ** |
|-------------------------------------------|------------|-----------------------------------------------------|------------|-------------------------|------------|------------|------------|
| **Revenues**                              | ** ** | ** **                                          | ** ** | **2006**                | ** ** | **2005**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                | ** ** | ** **                                          | ** ** | **(In thousands)** | ** ** | ** ** | ** ** |
| Pipeline  transportation revenue          |       | $                                                   | 105,652    |                    | $          | 83,067     |       | $ | 22,585 |   |   | 27 | % |   |
| Storage and  terminaling revenue          |       | 65,420                                              |       | 30,923                  |       | 34,497     |       |   | 112 |   |   |
| Pipeline buy/sell  transportation revenue |       | 31,136                                              |       | 28,905                  |       | 2,231      |       |   | 8 |   |   |
| Crude oil sales,  net of purchases:       |       |                                                |       |                    |       |       |       |   |   |   |   |
| Crude oil sales                           |       | 1,058,638                                           |       | 439,380                 |       | 619,258    |       |   | 141 |   |   |
| Crude oil purchases                       |       | (1,031,185                                          | )          | (425,733                | )          | 605,452    |       |   | 142 |   |   |
| Crude oil sales, net of purchases         |       | 27,453                                              |       | 13,647                  |       | 13,806     |       |   | 101 |   |   |
| Net revenue                               |       | $                                                   | 229,661    |                    | $          | 156,542    |       | $ | 73,119 |   |   | 47 | % |   |

 

We experienced higher pipeline transportation revenueson most of our pipelines in the nine month period ended September 30, 2006than in the corresponding period of 2005. Pipeline transportation revenues in2006 include revenues from our Rocky Mountain Products Pipeline, which wasacquired in September 2005. In the Rocky Mountains, we experienced highervolumes and tariffs and increased trucking revenues from the purchase of acrude oil trucking business in January 2006. In our West Coast BusinessUnit, pipeline transportation revenue was improved by increased deliveries toBakersfield, California refineries and higher tariffs.

Storage and terminaling revenues increased in the ninemonth period ended September 30, 2006 primarily because of the acquisitionof the Pacific Atlantic terminals in September 2005. Increased utilization,greater capacity and increased lease rates for our Pacific Terminals storage facilitiesalso favorably impacted storage and terminaling revenues.

Pipeline buy/sell transportation revenues increasedbecause of increased location differentials and marketing margins.

39

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Crudeoil sales net of purchases increased because of the purchase of crude oilcontracts in July 2005 and higher margins. Margins were above average in2006 and below average in 2005 in our crude oil marketing business for reasonsdescribed above. Higher crude oil prices increased gross sales and purchases.

| ** **                                                 | ** ** | **Nine Months Ended  Sepotember 30,** | ** ** | ** **              | ** ** | ** ** | ** ** |
|------------------------------------------------------------|------------|------------------------------------------------------|------------|-------------------------|------------|------------|------------|
| **Expenses**                                               | ** ** | ** **                                           | ** ** | **2006**                | ** ** | **2005**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                                 | ** ** | ** **                                           | ** ** | **(In thousands)** | ** ** | ** ** | ** ** |
| Operating  expenses                                        |       | $                                                    | 99,120     |                    | $          | 72,065     |       | $ | 27,055 |   |   | 38 | % |   |
| General and  administrative expense                        |       | 18,236                                               |       | 12,987                  |       | 5,249      |       |   | 40 |   |   |
| Depreciation and  amortization                             |       | 30,692                                               |       | 19,695                  |       | 10,997     |       |   | 56 |   |   |
| Merger costs                                               |       | 4,529                                                |       | —                  |       | 4,529      |       |   | — |   |   |
| Accelerated  long-term incentive plan compensation expense |       | —                                               |       | 3,115                   |       | (3,115     | )          |   | — |   |   |
| Line 63 oil  release costs                                 |       | —                                               |       | 2,000                   |       | (2,000     | )          |   | — |   |   |
| Reimbursed  general partner transaction costs              |       | —                                               |       | 1,807                   |       | (1,807     | )          |   | — |   |   |
|                                                       |       | $                                                    | 152,577    |                    | $          | 111,669    |       | $ | 40,908 |   |   | 37 | % |   |

 

The increase in operating expense was relatedprimarily to the acquisition of the Rocky Mountain Products Pipeline and thePacific Atlantic terminals in September 2005. Operating expenses were alsohigher as a result of higher power costs.

The increase in general and administrative expense wasprimarily associated with the support of newly acquired assets, professionalfees, and $1.3 million in costs for a new LB Pacific, LP option plan, which arerequired by generally accepted accounting principles to be recorded as ourexpense even though the plan is funded by LB Pacific, LP and not by thePartnership.

The increase in depreciation and amortization includes$9.7 million for depreciation on the Pacific Atlantic terminals and the RockyMountain Products Pipeline.

Mergercosts, accelerated long-term incentive plan compensation expense, Line 63 oilrelease costs and reimbursed general partner transaction costs are discussedabove.

| ** **                                  | ** ** | **Nine Months Ended  September 30,** | ** ** | ** **              | ** ** | ** ** | ** ** |
|---------------------------------------------|------------|-----------------------------------------------------|------------|-------------------------|------------|------------|------------|
| **Other Income and Expense** | ** ** | ** **                                          | ** ** | **2006**                | ** ** | **2005**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                  | ** ** | ** **                                          | ** ** | **(In thousands)** | ** ** | ** ** | ** ** |
| Share of net  income of Frontier            |       | $                                                   | 1,246      |                    | $          | 1,363      |       | $ | (117 | ) |   | (9 | )% |   |
| Interest expense                            |       | $                                                   | 30,029     |                    | $          | 17,679     |       | $ | 12,350 |   |   | 70 |   |   |
| Other income                                |       | $                                                   | 1,455      |                    | $          | 1,387      |       | $ | 68 |   |   | 5 |   |   |
| Income tax expense  (benefit)               |       | $                                                   | (2,536     | )                       | $          | 2,137      |       | $ | (4,673 | ) |   | (219 | ) |   |

 

The decrease in our share of Frontier’s net income wasmainly attributable to higher operating costs in the nine months ended September 30,2006.

The increase in interest expense was primarily due toborrowings incurred to partially fund the acquisition of the Rocky MountainProducts Pipeline and the Pacific Atlantic terminals. Our weighted averageborrowings during the nine months ended September 30, 2006 were$617 million, compared to $359 million in the corresponding period in2005. In addition, floating interest rates were higher in 2006. We realized aweighted average interest rate of 7.0% for the nine months ended September 30,2006, compared to a weighted average interest rate of 6.6% for thecorresponding period in 2005. Capitalized interest was $2.6 million and $0.6million for the nine months ended September 30, 2006 and 2005,respectively.

40

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Income tax expense is afunction of the income of our Canadian subsidiaries, which are taxable entitiesin Canada. In addition, certain kinds of repatriation of funds into the U.S.are subject to Canadian withholding tax. In the second quarter of 2006, theCanadian and Alberta governments enacted legislation that will reduce federaland provincial income taxes. We adjusted our estimate of future income taxrates in our estimates of deferred tax assets and liabilities and recognized a$4.6 million deferred tax benefit in the second quarter of 2006.

**Liquidity and CapitalResources**

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 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 of debtand equity securities. We expect to maintain a debt to total capitalizationratio of approximately 50% over time.

On December 23, 2005, we and certain of oursubsidiaries filed a universal shelf registration statement on Form S-3with the SEC to register the issuance and sale, from time to time and in suchamounts as is determined by market conditions and our needs, of up to$1.0 billion of common units of the Partnership and debt securities ofboth the Partnership and certain subsidiaries. This shelf registrationstatement was to allow us to finance new acquisitions and new projects such asour Pier 400 Project.

In 2005, we received approval from the CPUC todismantle certain idle PT assets and sell the underlying land. We sold oneparcel of land in 2005 for $1.9 million, another in the fourth quarter of 2006for $0.4 million, and expect to sell the remaining parcels in 2007. Theremaining parcels of land have an estimated value of approximately$10 million, which exceeds their net 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 conditions in the crude oiland refined products industries and financial, business and other factors, someof which are beyond our control, which could significantly impact futureresults.

The PAA mergeragreement contains covenants which limit us in the conduct of our business,including but not limited to the following:

·       We are limited to anaggregate of $150 million from the issuance of equity securities pendingcompletion of the merger.

·       Our quarterly distributionsare limited to $0.5675 per unit.

·       Weare limited on the size of any potential acquisition and new projectdevelopment.

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

| ** **                                 | ** ** | **Nine Months Ended  September 30,** | ** ** | ** ** | ** ** |
|--------------------------------------------|------------|-----------------------------------------------------|------------|------------|------------|
| ** **                                 | ** ** | **2006**                                            | ** ** | **2005**   | ** ** | **Change** | ** ** |
| ** **                                 | ** ** | **(In thousands)**                             | ** ** |
| Net cash provided  by operating activities |       | $                                                   | 49,491     |       | $          | 65,655 |   | $ | (16,164 | ) |
| Net cash used in  investing activities     |       | (85,812                                             | )          | (488,430   | )          | 402,618 |   |
| Net cash provided by  financing activities |       | 31,889                                              |       | 424,954    |       | (393,065 | ) |
|                                            |            |                                                     |            |            |            |  |  |  |  |  |

 

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***Net cash providedby operating activities***

Net cash from operatingactivities in 2006 was positively impacted by an increase in net income due tothe operations of the Rocky Mountain Products Pipeline and the Pacific Atlanticterminals, which were acquired on September 30, 2005, higher pipelinetransportation revenue, and increased margins in our crude oil marketingbusiness. These increases were partly offset by higher general andadministrative and interest expenses. Also included in net income is a $4.6million non-cash tax rate adjustment for deferred taxes. Offsetting theincrease in net income is an increase in the quantity of crude oil stored forour own account because of contango market conditions (when oil prices forfuture deliveries are higher than for current deliveries). In a contango market,we store crude oil purchased at lower prices in the current month for deliveryat higher prices in future months, and protect such margin through hedging. Inaddition, we experienced a reduction in accounts payable and accruedliabilities in the nine months end September 30, 2006 compared to an increasein the corresponding period of 2005.

***Net cash used ininvesting activities***

We had capitalexpenditures of $67.5 million for the nine months ended September 30,2006, which include (i) $44.2 million for expansion projects (see “CapitalRequirements” below for a list of our projects and forecasted expansionexpenditures in 2006), (ii) $13.3 million for the development of the Pier400 project, (iii) $4.1 million related to sustaining capital projects,and (iv) $5.9 million of transition projects related to the Edmontoninitiation station as well as transition of the Rocky Mountain ProductsPipeline and the Pacific Atlantic terminals to our operations. Additionally, wepaid $16.1 million for pipeline linefill in connection with the start-up of ourEdmonton initiation station and $2.3 million for a trucking business in theU.S. Rocky Mountains.

On September 30,2005, we purchased certain terminal and pipeline assets from varioussubsidiaries of Valero, L.P. for an aggregate purchase of $455.0 million plustransaction costs of approximately $3.4 million, of which approximately $1.0million was accrued at September 30, 2005. Separately, we also purchasedcertain crude oil contracts and crudeoil inventories for approximately $3.8 million plus contingent payments overthe next three and one half years based on specified performance criteria. Capitalexpenditures were $27.3 million in the nine months ended September 30, 2005,of which $3.1 million related to sustaining capital projects, $6.2 millionrelated to transition projects, $13.1 million related to expansion, and $4.9million was for our continued development of the Pier 400 project.

***Net cash providedby (used in) financing activities***

Net cash provided byfinancing activities for the nine months ended September 30, 2006 includesnet borrowings of $100.6 million under our senior secured credit facility, which was used primarilyto fund our expansion capital projects, contango inventory and pipelinelinefill as describe above. We also distributed $68.7 million to our limitedpartners and General Partner during the nine months ended September 30,2006.

Cash provided by financingactivities for the nine months ended September 30, 2005 includes netproceeds of $295.2 million, including our General Partner contribution of $6.1million,  from our public and privateequity offerings, $171.0 million net proceeds from the offering of our 61⁄4% seniornotes, 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 under our previous U.S. and Canadian revolving creditfacilities. Cash provided by financing activities for the nine months ended September 30,2005 also includes distributions of $46.2 million which were made to the limitedpartners and the General Partner and a $2.4 million contribution from TheAnschutz Corporation and LB Pacific, to reimburse us for certain costs incurredin connection with the sale of The Anschutz Corporation’s interest in us.

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***CapitalRequirements***

Generally,our operations require investment to upgrade or enhance existing operations andto meet environmental and operational regulations. Our capital requirementsconsist 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, or adding new pump stations or pipeline connectionsto increase our transportation throughput and revenue.

Weexpect to invest approximately $119 million in total capital expenditures in2006, with approximately $105 million of that total on expansion projects. Ourestimated 2006 expansion capital spending includes the following notableprojects:

| **2006 Forecast Expansion Capital Expenditures**                                                                              | ** ** | ** **             | ** ** | **Estimated to be  incurred in 2006** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                                                                                                                        | ** ** | **(in millions)** | ** ** |
| 2006 portion of  the construction of a new pipeline to Cheyenne, Wyoming                                                                          |       |                   | $          | 24                                                        |       |   |
| Capital projects  associated with the new refined products assets                                                                                 |       |                   | 22         |                                                      |       |
| Completion of  permitting process, engineering and other project development cost for the  Pier 400 project                                       |       |                   | 19         |                                                      |       |
| Phase I of Salt  Lake City expansion                                                                                                              |       |                   | 16         |                                                      |       |
| Reactivation of  storage tanks and infrastructure enhancements at Pacific Terminals                                                               |       |                   | 12         |                                                      |       |
| Completion of  storage tanks for the Rangeland System and Western Corridor pipeline  to facilitate the transportation of synthetic crude oil |       |                   | 6          |                                                      |       |
| Other                                                                                                                                             |       |                   | 6          |                                                      |       |
| Total                                                                                                                                             |       |                   | $          | 105                                                       |       |   |

 

In addition to theexpansion projects above, we expect to incur $7 million for transitionalcapital expenditures and $7 million for sustaining capital expendituresduring 2006.

***Pier 400***

We continue our efforts todevelop a deepwater petroleum import terminal at Pier 400 and Terminal Islandin the Port of Los Angeles (“POLA”) to handle marine receipts of crude oil andrefinery feedstocks. As currently envisioned, the project would include a deepwater berth, high capacity transfer infrastructure and storage tanks, with apipeline distribution system that will connect to various customers, somedirectly, and some through our Pacific Terminals storage and distributionsystem. We would construct the storage tanks and transfer infrastructure,including a large diameter pipeline system for receiving bulk petroleum liquidsfrom marine vessels. If successful, this project will allow us to increase ourparticipation in the Los Angeles basin marine import business, which isgrowing as a result of a decline in both California production and imports fromAlaska.

We have entered into agreements with ConocoPhillipsand two subsidiaries of Valero Energy Corporation that provide long termcustomer commitments to off-load a total of 140,000 bpd of crude oil at thePier 400 dock. The ConocoPhillips and Valero agreements are subject tosatisfaction of various conditions, such as the achievement of various progressmilestones, financing, continued economic viability, and completion of otherancillary agreements related to the project. We are negotiating similar longterm off-loading agreements with other potential customers.

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We have failed to meet certain project milestone datesset forth in our Valero agreements, and we are likely to miss other projectmilestones that are approaching under these agreements. Valero has not givenany indication that it will seek to terminate such agreements. We expect thatongoing negotiations with Valero to extend the milestone dates will besuccessful and that the Valero agreements will remain in effect.

In the first quarter of 2006, we completed an updatedcost estimate for the project. We are estimating that Pier 400 will costapproximately $315 million, which is subject to change depending onvarious factors, including: (i) the final scope of the project and therequirements imposed through the permitting process; and (ii) changes inconstruction costs. This cost estimate assumes the construction of4.0 million barrels of storage. We are in the process of securing theenvironmental and other permits that will be required for the Pier 400 projectfrom a variety of governmental agencies, including the Board of HarborCommissioners, the South Coast Air Quality Management District, variousagencies of the City of Los Angeles, the Los Angeles City Council and the U.S.Army Corps of Engineers. We expect to have the necessary permits in mid 2007.

Final construction of the Pier 400 project is subjectto the completion of a land lease agreement with the POLA, receipt ofenvironmental and other approvals, securing additional customer commitments,updating engineering and project cost estimates, ongoing feasibilityevaluation, and financing. We expect construction of the Pier 400 terminal tobe completed and the facility to be placed in service in the first quarter of2009.

We have capitalized $31.6million on the Pier 400 project through September 30, 2006, including$13.3 million for the nine months ended September 30, 2006. We anticipatefunding the remaining permitting and pre-construction costs in 2006 from ourrevolving credit facility.

***Debt Obligations***

Ourdebt obligations are comprised of:

| ** **                                                                                                                                                                       | ** ** | **September 30,**  | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                                                                                                                                                       | ** ** | **2006**                | ** ** | **2005**              | ** ** |
| ** **                                                                                                                                                                       | ** ** | **(in thousands)** | ** ** |
| $400 million  senior secured credit facility, bearing interest at 6.1% on  September 30, 2006, due September 30, 2010                                                  |       |                    | $          | 244,316               |       |   |   | $ | 140,751 |   |   |
| 71¤8% senior  notes, due June 2014, net of unamortized discount of $3,628 and $3,882  and including fair value increases (decreases) of $(106) and $567,  respectively |       |                    | 246,267    |                  |       |   | 246,684 |   |   |
| 61¤4% senior notes, due September 2015,  net of unamortized discount of $738 and $782, respectively                                                                    |       |                    | 174,262    |                  |       |   | 174,218 |   |   |
| Future payment  for MAPL assets, net of unamortized discount of $165 and $309,  respectively                                                                                |       |                    | 4,318      |                  |       |   | 3,979 |   |   |
| Total long-term debt                                                                                                                                                             |       |                    | $          | 669,163               |       |   |   | $ | 565,632 |   |   |

 

As of September 30,2006, $79 million of undrawn credit was available under the senior securedrevolving credit facility. With the consent of the administrative agent underthe revolving credit facility, we can increase credit availability up to anadditional $58 million, based upon pro-forma EBITDA from future acquisitions.

**Off-Balance SheetArrangements**

As of September 30,2006, we had standby letters of credit outstanding of $18 million for securingcrude oil purchases and the MAPL note, both of which are reflected asliabilities on the balance sheet.

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**AccountingPronouncements**

In December 2004, the Financial AccountingStandards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123(revised December 2005), *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, 2006. The adoption of SFAS 123R on January 1,2006 did not have a material impact on our consolidated financial statements.

In September 2005, the Emerging Issues Task Force(“EITF”) issued Issue No. 04-13 (“EITF 04-13”), *Accounting for Purchases and Sales of Inventory withthe Same Counterparty*. 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 adoption of EITF 04-13 did not have a material impact on ourconsolidated financial statements.

In June 2006, the FASBissued FASB Interpretation No. 48 (“FIN 48”), *Accountingfor Uncertainty in Income Taxes*. This Interpretation prescribesa recognition threshold and measurement attribute for the financial statementrecognition and measurement of a tax position taken or expected to be taken ina tax return. This Interpretation also provides guidance on derecognition,classification, interest and penalties, accounting in interim periods,disclosure, and transition. FIN 48 will apply to the Partnership’s Canadiansubsidiaries, which are taxable entities in Canada, but not to the Partnership.The Partnership is in the process ofdetermining the impact of FIN 48 on its financial statements, but does notexpect it to have a material impact on its financial statements. FIN 48is effective for the Partnership as of the beginning of the first fiscal yearbeginning after January 1, 2007.

In June 2006, the EITFissued Issue No. 06-3 (“EITF 06-3”), *How Taxes Collected from Customers and Remitted to GovernmentalAuthorities Should Be Presented in the Income Statement (That Is, Gross versusNet Presentation).* The issues addressed by the EITF are (i) Whetherthe scope of this Issue should include (a) all nondiscretionary amountsassessed by governmental authorities, (b) all nondiscretionary amountsassessed by governmental authorities in connection with a transaction with acustomer, or (c) only sales, use, and value added taxes and (ii) Howtaxes assessed by a governmental authority within the scope of this Issue(Issue 1) should be presented in the income statement (that is, gross versusnet presentation). EITF 06-3 is effective for interim and annual financialperiods beginning after December 15, 2006. The Partnership is in theprocess of determining the impact of EITF 06-3 on its financialstatements, but does not expect it to have a material impact on its financialstatements.

In September 2006, the FASB issued Statement ofFinancial Accounting Standards No. 157, *Fair ValueMeasurements (“SFAS 157”).*SFAS 157 defines fair value, establishesa framework for measuring fair value in generally accepted accountingprinciples, and expands disclosures about fair value measurements. SFAS 157applies under other accounting pronouncements that require or permit fair valuemeasurements in those accounting pronouncements. Accordingly, SFAS 157 does notrequire any new fair value measurements. However, the Partnership is in theprocess of determing what impact the application of SFAS 157 will have on itscurrent fair value practices, but the Partnership does not expect theapplication of SFAS 157 to have a material impact. SFAS 157 is effective forfinancial statements issued for fiscal years beginning after November 15,2007.

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In September 2006,the Securities and Exchange Commission issued Staff Accounting BulletinNo. 108, *Considering the Effects of Prior YearMisstatements when Quantifying Misstatements in Current year FinancialStatements* (“SAB 108”), which provides interpretive guidance on howthe effects of the carryover or reversal of prior year misstatements should beconsidered in quantifying a current year misstatement. The guidance iseffective for fiscal years beginningafter November 15, 2006 and it allows a one-time transitional cumulativeeffect adjustment to beginning-of-year retained earnings at the first fiscalyear ending after November 15, 2006 for errors that were not previouslydeemed material, but are material under the guidance in SAB 108. The Partnershipis currently evaluating the impact, if any, of adopting SAB 108 on itsconsolidated financial statements.

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

Market risk is the risk ofloss arising from adverse changes in market rates and prices. The principalmarket risks to which we are exposed are commodity price risk, interest raterisk and currency exchange risk. We use derivative financial instruments toreduce our exposure to adverse fluctuations in commodity prices, interest ratesand foreign exchange rates. We formally designate and document the financialinstruments as a hedge of a specific underlying exposure, as well as the riskmanagement objectives and strategies for undertaking the hedge transactions. Weformally assesses, both at the inception and at least quarterly thereafter,whether the financial instruments that are used in hedging transactions areeffective at offsetting changes in either the fair value or cash flows of therelated underlying exposure. All of our derivatives are commonly usedover-the-counter instruments with liquid markets or are traded on theNew York Mercantile Exchange. We do not enter into derivative financialinstruments for trading or speculative purposes.

**Commodity PriceRisk Hedging**

We may use derivatives, principally futures andoptions, to hedge our exposure to market price volatility related to ourinventory or future sales of crude oil. Derivatives used to hedge market pricevolatility related to inventory are generally designated as fair value hedges,and derivatives related to the future sales of crude oil are generallyclassified as cash flow hedges. The values of derivative instruments areincluded in “Other assets” or in “Other current liabilities” in theaccompanying consolidated balance sheets.

Changes in the fair value of our derivativeinstruments related to crude oil inventory are recognized in net income. Forthe nine months ended September 30, 2006 and 2005, “crude oil sales, netof purchases” were net of $0.8 million in gains and $1.7 million in losses,respectively, reflecting changes in the fair value of derivative instrumentsheld as hedges related to crude oil marketing activities. Losses on derivativeswere generally offset by gains in physical crude oil inventory positions. Changesin the fair value of our derivative instruments related to the future sale ofcrude oil are deferred and reflected in “accumulated other comprehensiveincome,” a component of partners’ capital in the balance sheet, until therelated revenue is reflected in the consolidated statements of income. As of September 30,2006, $0.3 million relating to the change in the fair value of highly effectivederivative instruments was included in “accumulated other comprehensive income”and is expected to be reclassified into earnings within one year. Since theseamounts are based on market prices at September 30, 2006, actual amountsto be reclassified will differ and could vary materially as a result of changesin market conditions.

**Interest Rate RiskHedging**

In connection with the issuance of our 71¤8%senior notes due 2014, we entered into interest rate swap agreements with anaggregate notional principal amount of $80.0 million to receive interestat a fixed rate of 71¤8%and to pay interest at an average variable rate of nine month LIBOR plus1.6681% (set in advance or in arrears depending on the swap transaction). Theinterest rate swaps mature June 15, 2014 and are 

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callable at the same datesand terms as the 71¤8%senior notes. We designated these swaps as a hedge of the change in the seniornotes fair value attributable to changes in the nine 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 millionof senior notes, which are expected to be offsetting to changes in the fairvalue of the interest swaps, are recorded into earnings each period. At September 30,2006, we recorded a decrease of $0.1 million in the fair value of interest rateswaps. For the three and nine months ended September 30, 2006, werecognized reductions in interest expense of $0.1 million and $0.1 millionrelated to the difference between the fixed rate and the floating rate ofinterest on the interest rate swaps. For the nine months ended September 30,2006 and 2005, we had an immaterial amount of ineffectiveness relating to theseinterest rate swaps.

We are subject to risksresulting from interest rate fluctuations as the interest cost on our creditfacilities and the $80 million interest swap on the senior notes are basedon variable rates. If our interest rates were to increase 1.0% for theremainder of 2006 as compared to the rate at December 31, 2005, ourinterest expense for the remainder of 2006 would increase $0.8 million based onour outstanding debt balances at September 30, 2006.

**Currency ExchangeRate Risk Hedging**

The purpose of our foreign currency hedging activitiesis to reduce the risk that our cash inflows resulting from interest paymentsfrom our Canadian subsidiaries on intercompany debt will be adversely affectedby changes in the U.S./Canadian exchange rate.

Weentered into forward exchange contracts to hedge receipt of forecasted interestpayments denominated in Canadian dollars. The effective portion of the changein fair value of this contract, which has been designated as a cash flow hedge,is reported in “accumulated other comprehensive income” in the accompanyingbalance sheet and will be reclassified into earnings in “Other income” in thesame period during which the hedged transaction affects earnings. Theineffective portion, if any, of the change in fair value of this instrumentwill be immediately recognized in earnings. These foreign exchange contracts asof September 30, 2006 are as follows:

| ** ** | ** ** | **Canadian dollars** | ** ** | **US dollars** | ** ** | **Average Exchange Rate** | ** ** |
|------------|------------|---------------------------|------------|---------------------|------------|-------------------------------------|------------|
| ** ** | ** ** | **(in thousands)**   | ** ** | ** **          | ** ** |
| 2006       |       |                      | $          | 1,850               |       |                                |       | $ | 1,580 |   |   | Cdn$1.17 to U.S. $1.00 |   |
| 2007       |       |                      | 6,600      |                |       |                                | 5,662      |   |   | Cdn$1.17 to U.S. $1.00 |   |
| 2008       |       |                      | 3,193      |                |       |                                | 2,754      |   |   | Cdn$1.16 to U.S. $1.00 |   |

 

**Credit Risks**

By using derivative financial instruments to hedgeexposures related to changes in commodity prices, interest rates and currencyexchange rates, we expose ourselves to market risk and credit risk. Market riskis the risk of loss arising from the adverse effect on the value of a financialinstrument that results from changes in commodity prices, interest rates orcurrency exchange rates. The market risk associated with price volatility ismanaged by established parameters that limit the types and degree of marketrisk that may be undertaken.

Credit risk is the risk ofloss arising from the failure of the derivative agreement counterparty toperform under the terms of the derivative agreement. When the fair value of aderivative agreement is positive, the counterparty is liable to us, whichcreates credit risk for us. When the fair value of a derivative agreement isnegative, we are liable to the counterparty and, therefore, it creates creditrisk for the counterparty. The counterparties we transact with are large, wellknown companies in the industry or large creditworthy financial institutions.As such, we believe our exposure to counterparty credit risk is low.Nonetheless, there can be no assurance as to the performance of a counterparty.

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**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, 2006, 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, including the Chief Executive Officerand Chief Financial Officer, have evaluated our internal control over financialreporting as of September 30, 2006, and have concluded that there has notbeen any change during our most recent fiscal quarter that has materiallyaffected, or is reasonably likely to materially affect, our internal controlover financial reporting.

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**PART II. OTHERINFORMATION**

**ITEM 1.**                LegalProceedings

See discussion of legal proceedings in “Note 4—Contingencies”in the accompanying condensed consolidated financial statements.

On or about March 17, 2006, one of thePartnership’s subsidiaries, Pacific Pipeline System LLC (“PPS”), was servedwith a four count misdemeanor action, entitled “*The Peopleof the State of California v. Pacific Pipeline System, LLC”*, LosAngeles Superior Court Case No. 6NW01020, which alleges the violation byPPS of two strict liability statutes under the California Fish and Game Codefor the unlawful deposit of oil or substances harmful to wildlife into theenvironment, and violations of two sections of the California Water Code forthe willful and intentional discharge of pollution into state waters. Thesealleged violations relate to the release of crude oil from PPS’s Line 63 intoPyramid Lake (see “Note 4—Contingencies” in the accompanyingcondensed consolidated financial statements). The fines that can be assessedagainst PPS for the violations of the strict liability statutes are based, inlarge measure, on the volume of unrecovered crude oil that was released intothe environment, and, therefore, the maximum fine that can be assessed isestimated to be approximately $870,000, in the aggregate. This amount issubject to downwards adjustment as additional information becomes known withrespect to actual volumes of recovered crude oil, and the State of Californiahas the discretion to further reduce the fine after considering mitigatingfactors such as the fact that the release was not caused by any wrongfulconduct of PPS. Because of the uncertainty associated with these factors, thefinal amount of the fine that will be assessed for the strict liabilityoffenses cannot be ascertained.

The penalties that could be assessed for the allegedCalifornia Water Code violations are also not readily quantifiable, but webelieve the penalties would not exceed $50,000, in the aggregate. We believe,however, that the allegations of Water Code violations are without merit andintend to vigorously defend against them.

On June 15, 2006, alawsuit was filed in the Superior court of California, County of Los Angeles,entitled *Kosseff v. Pacific Energy, et al,* caseno. BC 3544016. The plaintiff alleged that he was a unitholder of thePartnership and he sought to represent a class comprising all of thePartnership’s unitholders. The complaint named as defendants the Partnershipand certain of the officers and directors of the Partnership’s general partner,and asserted claims of self-dealing and breach of fiduciary duty in connectionwith the pending merger with PAA and related transactions. The plaintiff soughtinjunctive relief against completing the merger or, if the merger wascompleted, rescission of the merger, other equitable relief, and recovery ofthe plaintiff’s costs and attorneys’ fees. On September 14, 2006, thePartnership and the other defendants entered into a memorandum of settlementwith the plaintiff to settle the lawsuit. As part of the settlement, thePartnership and the other defendants deny all allegations of wrongdoing andmaintain that they are willing to settle the lawsuit solely because thesettlement would eliminate the burden and expense of further litigation. Thesettlement is subject to customary conditions, including court approval. Aspart of the settlement, the Partnership will, subject to the consummation ofthe merger, pay $475,000 to the plaintiff’s counsel for their fees and expenses,and incur approximately $0.1 to $0.2 million for costs of mailingmaterials to unitholders. If finally approved by the court, the settlement willresolve all claims that were or could have been brought on behalf of theproposed settlement class in the actions being settled, including all claimsrelating to the merger, the merger agreement and any disclosure made by thePartnership in connection with the merger. The settlement will not change anyof the terms or conditions of the merger.

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**ITEM 1A.**        RiskFactors

The risk factors includedin our annual report on Form 10-K for the year ended December 31,2005 have not materially changed with the exception of the addition of riskfactors related to the proposed merger with PAA. Some of the risks which may berelevant to us include:

***BusinessUncertainties and Contractual Restrictions While Merger is Pending******—******Uncertainty***aboutthe effect of the merger on employees, suppliers, partners, regulators andcustomers may have an adverse effect on us. These uncertainties may impair ourability to attract, retain and motivate key personnel until the merger isconsummated, and could cause suppliers, customers and others that deal with usto defer purchases or other decisions concerning us, or seek to change existingbusiness relationships with us. Employee retention may be particularlychallenging while the merger is pending, as employees may experienceuncertainty about their future roles with PAA. In addition, the mergeragreement restricts us from making certain acquisitions and taking other specifiedactions without PAA’s approval. These restrictions could prevent us frompursuing attractive business opportunities that may arise prior to thecompletion of the merger.

***Failure to Complete Merger Could Negatively ImpactStock Price, Future Business and Financial Results******—******Although***wehave agreed that our Board of Directors will, subject to fiduciary exceptions,recommend that our unitholders approve and adopt the merger agreement, there isno assurance that the merger agreement and the merger will be approved, andthere is no assurance that the other conditions to the completion of the mergerwill be satisfied. If the merger is not completed, we will be subject toseveral risks, including the following:

·       we may be required to payPAA a termination fee of $40 million in the aggregate if the merger agreementis terminated under certain circumstances and we enter into or complete analternative transaction;

·       the current market price ofour common units may reflect a market assumption that the merger will occur,and a failure to complete the merger could result in a negative perception bythe stock market of us generally and a resulting decline in the market price ofour common units;

·       certain costs relating tothe merger (such as legal, accounting and financial advisory fees) are payableby us whether or not the merger is completed;

·       there may be substantialdisruption to our business and a distraction of our management and employeesfrom day-to-day operations, because matters related to the merger (includingintegration planning) may require substantial commitments of time andresources, which could otherwise have been devoted to other opportunities thatcould have been beneficial to us;

·       our business could beadversely affected if we are unable to retain key employees or attractqualified replacements; and

·       we would continue to facethe risks that we currently face as an independent company.

There are substantialrisks and uncertainties relating to the pending merger between the Partnershipand PAA and the combined company following the merger. A joint proxystatement/prospectus relating to the merger was filed by the Partnership andPAA and was declared effective by the SEC on September 29, 2006, and wassubsequently sent to unitholders of the Partnership. This joint proxystatement/prospectus includes a discussion of these risks. Investors andsecurity holders are urged to carefully read the joint proxystatement/prospectus because it contains important information, includingdetailed risk factors, regarding the Partnership, PAA and the merger. Investorsand security holders may obtain a free copy of the definitive joint proxystatement/prospectus and other documents containing information about thePartnership and PAA, without charge, at the SEC’s web site at www.sec.gov.Copies of the definitive joint proxy statement/prospectus and the SEC filingsthat are incorporated by reference in the joint 

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proxy statement/prospectusmay also be obtained free of charge by directing a request to the Partnershipor PAA. The Partnership or PAA and the officers and directors of the respectivegeneral partners of the Partnership and PAA may be deemed to be participants inthe solicitation of proxies from their security holders in connection with theproposed transaction. Information about these persons can be found in thePartnership’s or PAA’s respective Annual Reports on Form 10-K and Form 10-K/Afiled with the SEC, and additional information about such persons may beobtained from the joint proxy statement/prospectus. The Partnership urgesunitholders and potential purchasers of its common units to review thesematerials.

**ITEM 6.**                Exhibits

Thefollowing documents are filed as exhibits to this quarterly filing:

| Exhibit  Number    | ** ** | ** **                                                                                                                                                                                                                                                         | ** ** | **Description** |
|-------------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------|
| *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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**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 3, 2006* |
|       | By:                               |   | /s/ GERALD A. TYWONIUK |
|       | * *                          | * * | Gerald A. Tywoniuk *Senior Vice President and Chief Financial Officer  (Principal Financial Officer)  November 3, 2006* |

 

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**EXHIBITINDEX**

| Exhibit Number     | ** ** | ** **                                                                                                                                                                                                                                                    | ** ** | **Description** |   |
|-------------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------|--------|
| *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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