**UNITEDSTATESSECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON,D.C. 20549**

 

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**FORM 10-Q**

 
| ý | **Quarterly  Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of  1934** |
|--------|----------------------------------------------------------------------------------------------------|

 

**Forthe quarterly period ended March 31, 2005**

**OR**

** **
| o | **Transition  Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of  1934** |
|---|-----------------------------------------------------------------------------------------------------|

 

**Forthe transition period from             to             **

 

Commission File Number **1-313345**

 

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**PACIFICENERGY PARTNERS, L.P.**

(Exact name ofregistrant as specified in its charter)

 

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

 

**5900Cherry Avenue**

**LongBeach, CA 90805-4408**

(Address ofprincipal executive offices)

 

**(562) 728-2800**

(Registrant’stelephone number, including area code)

 

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

 

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

 

                There were 19,258,330 of the registrant’s CommonUnits and 10,465,000 of the registrant’s Subordinated Units outstanding atMarch 31, 2005.

 

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

 

**FORM 10-Q**

 

**TABLEOF CONTENTS**

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

 

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**PART I. FINANCIAL INFORMATION**

**ITEM 1****.Financial Statements**

**PACIFIC ENERGYPARTNERS, L.P. (Note 1)**

**CONDENSED CONSOLIDATED BALANCE SHEETS**

**(Unaudited)**

 
| ** **                                                                                                                   | ** ** | **March 31,**       | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------|------------|---------------------|------------|------------------|------------|
| ** **                                                                                                                   | ** ** | **2005**            | ** ** | **2004**         | ** ** |
| ** **                                                                                                                   | ** ** | **(in  thousands)** | ** ** |
|                                                                                                                         |       |                |       |             |       |
| **ASSETS**                                                                                                                   |       |                |       |             |       |
| Current assets:                                                                                                              |       |                |       |             |       |
| Cash and cash equivalents                                                                                                    |       | $                   | 22,097     |             | $          | 23,383 |   |
| Crude oil sales receivable                                                                                                   |       | 51,999              |       | 28,609           |       |
| Transportation and storage accounts receivable                                                                               |       | 21,997              |       | 20,137           |       |
| Canadian goods and services tax receivable                                                                                   |       | 7,595               |       | 7,632            |       |
| Insurance proceeds receivable (note 2)                                                                                       |       | 11,495              |       | —           |       |
| Due from related parties (note 3)                                                                                            |       | 128                 |       | —           |       |
| Crude oil inventory                                                                                                          |       | 26,449              |       | 9,174            |       |
| Prepaid expenses                                                                                                             |       | 4,928               |       | 4,159            |       |
| Other                                                                                                                        |       | 3,654               |       | 2,451            |       |
| Total current assets                                                                                                         |       | 150,342             |       | 95,545           |       |
| Property and equipment, net                                                                                                  |       | 715,580             |       | 718,624          |       |
| Investment in Frontier                                                                                                       |       | 8,200               |       | 7,886            |       |
| Other assets, net                                                                                                            |       | 45,968              |       | 47,850           |       |
|                                                                                                                         |       | $                   | 920,090    |             | $          | 869,905 |   |
|                                                                                                                         |       |                |       |             |       |
| **LIABILITIES AND PARTNERS’ CAPITAL**                                                                                   |       |                |       |             |       |
| Current liabilities:                                                                                                         |       |                |       |             |       |
| Accounts payable and accrued liabilities                                                                                     |       | $                   | 17,273     |             | $          | 15,127 |   |
| Accrued crude oil purchases                                                                                                  |       | 65,493              |       | 27,231           |       |
| Line 63 oil release reserve (note 2)                                                                                         |       | 13,496              |       | —           |       |
| Accrued interest                                                                                                             |       | 5,538               |       | 1,124            |       |
| Due to related parties (note 3)                                                                                         |       | —              |       | 533              |       |
| Derivatives liability—current portion                                                                                   |       | 1,410               |       | 400              |       |
| Other                                                                                                                        |       | 5,930               |       | 3,630            |       |
| Total current liabilities                                                                                                    |       | 109,140             |       | 48,045           |       |
| Senior notes and credit facilities, net (note 4)                                                                             |       | 356,369             |       | 357,163          |       |
| Deferred income taxes                                                                                                        |       | 34,248              |       | 34,556           |       |
| Environmental liabilities                                                                                                    |       | 7,022               |       | 7,269            |       |
| Other liabilities                                                                                                            |       | 340                 |       | 406              |       |
| Total liabilities                                                                                                            |       | 507,119             |       | 447,439          |       |
| Commitments and contingencies (notes 2 and 8)                                                                                |       |                |       |             |       |
| Partners’ capital:                                                                                                      |       |                |       |             |       |
| Common unitholders (19,258,330 and 19,158,747 units outstanding at  March 31, 2005 and December 31, 2004, respectively) |       | 356,708             |       | 361,427          |       |
| Subordinated unitholders (10,465,000 units outstanding at March 31,  2005 and December 31, 2004)                        |       | 38,096              |       | 41,521           |       |
| General Partner interest                                                                                                     |       | 6,714               |       | 6,280            |       |
| Undistributed employee long-term incentive compensation (note  5)                                                            |       | —              |       | 116              |       |
| Accumulated other comprehensive income                                                                                       |       | 11,453              |       | 13,122           |       |
| Net partners’ capital                                                                                                   |       | 412,971             |       | 422,466          |       |
|                                                                                                                         |       | $                   | 920,090    |             | $          | 869,905 |   |
|                                                                                                                         |       |                |       |             |       |

See accompanying notes to condensedconsolidated financial statements.

 

1

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**PACIFIC ENERGY PARTNERS, L.P. (Note 1)**

**CONDENSED CONSOLIDATED STATEMENTS OF INCOME**

**(Unaudited)**

 
| ** **                                                                                                    | ** ** | **Three Months Ended March 31,**            | ** ** |
|---------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                                                                    | ** ** | **2005**                                    | ** ** | **2004** | ** ** |
| ** **                                                                                                    | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| Pipeline transportation revenue                                                                               |       | $                                           | 28,037     |   | $ | 24,727 |   |
| Storage and terminaling revenue                                                                               |       | 10,322                                      |       | 10,123 |   |
| Pipeline buy/sell transportation revenue                                                                      |       | 9,106                                       |       | — |   |
| Crude oil sales, net of purchases of $114,391 and $81,115 for the  three months ended March 31, 2005 and 2004 |       | 1,782                                       |       | 4,812 |   |
| Net revenue                                                                                                   |       | 49,247                                      |       | 39,662 |   |
| Expenses:                                                                                                     |       |                                        |       |   |   |
| Operating                                                                                                     |       | 21,754                                      |       | 18,917 |   |
| Line 63 oil release costs (note 2)                                                                            |       | 2,000                                       |       | — |   |
| General and administrative                                                                                    |       | 5,172                                       |       | 3,854 |   |
| Accelerated long-term incentive plan compensation expense (note 5)                                            |       | 3,115                                       |       | — |   |
| Transaction costs (notes 3 and 6)                                                                             |       | 1,807                                       |       | — |   |
| Depreciation and amortization                                                                                 |       | 6,529                                       |       | 5,242 |   |
|                                                                                                          |       | 40,377                                      |       | 28,013 |   |
| Share of net income of Frontier                                                                               |       | 357                                         |       | 393 |   |
| Operating income                                                                                              |       | 9,227                                       |       | 12,042 |   |
| Interest expense                                                                                              |       | (5,598                                      | )          | (4,126 | ) |
| Other income                                                                                                  |       | 353                                         |       | 161 |   |
| Income before income taxes                                                                                    |       | 3,982                                       |       | 8,077 |   |
| Income tax (expense) recovery:                                                                                |       |                                        |       |   |   |
| Current                                                                                                       |       | (732                                        | )          | — |   |
| Deferred                                                                                                      |       | 171                                         |       | — |   |
|                                                                                                          |       | (561                                        | )          | — |   |
| Net income                                                                                                    |       | $                                           | 3,421      |   | $ | 8,077 |   |
| Net income (loss) for the general partner interest (note 6)                                                   |       | $                                           | (1,702     | ) | $ | 162 |   |
| Net income for the limited partner interests                                                                  |       | $                                           | 5,123      |   | $ | 7,915 |   |
|                                                                                                          |       |                                        |       |   |   |
| Basic net income per limited partner unit                                                                     |       | $                                           | 0.17       |   | $ | 0.32 |   |
| Diluted net income per limited partner unit                                                                   |       | $                                           | 0.17       |   | $ | 0.31 |   |
|                                                                                                          |       |                                        |       |   |   |
| Weighted average limited partner units outstanding:                                                           |       |                                        |       |   |   |
| Basic                                                                                                         |       | 29,655                                      |       | 24,999 |   |
| Diluted                                                                                                       |       | 29,673                                      |       | 25,149 |   |

 

See accompanying notes tocondensed consolidated financial statements.

 

2

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**PACIFIC ENERGY PARTNERS, L.P. (Note 1)**

**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, 2004                                             |       | 19,159                     |       | 10,465                       |       | $           | 361,427    |                | $          | 41,521            |       | $                | 6,280      |   | $ | 116 |   | $ | 13,122 |   | $ | 422,466 |   |
| Net income (note  6)                                                         |       | —                     |       | —                       |       | 3,315       |       | 1,808               |       | (1,702            | )          | —           |       | — |   | 3,421 |   |
| Distribution to  partners                                                    |       | —                     |       | —                       |       | (9,579      | )          | (5,233              | )          | (302              | )          | —           |       | — |   | (15,114 | ) |
| General partner  contribution (note 6)                                       |       | —                     |       | —                       |       | —      |       | —              |       | 2,407             |       | —           |       | — |   | 2,407 |   |
| Employee  compensation under long-term incentive plan                        |       | —                     |       | —                       |       | —      |       | —              |       | —            |       | 2,886            |       | — |   | 2,886 |   |
| Issuance of  common units pursuant to long-term incentive plan (note 5) |       | 99                         |       | —                       |       | 1,545       |       | —              |       | 31                |       | (3,002           | )          | — |   | (1,426 | ) |
| Foreign currency  translation adjustment                                     |       | —                     |       | —                       |       | —      |       | —              |       | —            |       | —           |       | (537 | ) | (537 | ) |
| Change in fair  value of hedging derivatives                                 |       | —                     |       | —                       |       | —      |       | —              |       | —            |       | —           |       | (1,132 | ) | (1,132 | ) |
| Balance, March  31, 2005                                                     |       | 19,258                     |       | 10,465                       |       | $           | 356,708    |                | $          | 38,096            |       | $                | 6,714      |   | $ | — |   | $ | 11,453 |   | $ | 412,971 |   |

 

See accompanying notes tocondensed consolidated financial statements.

 

3

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**PACIFIC ENERGYPARTNERS, L.P. (Note 1)**

**CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOM****E**

**(Unaudited)**

 

 
|                                                   | ** ** | **Three Months Ended March 31,** | ** ** |
|---------------------------------------------------|------------|----------------------------------|------------|
| ** **                                        | ** ** | **2005**                         | ** ** | **2004** | ** ** |
| ** **                                        | ** ** | **(in thousands)**               | ** ** |
|                                              |       |                             |       |   |   |
| Net income                                        |       | $                                | 3,421      |   | $ | 8,077 |   |
| Change in fair value of hedging derivatives       |       | (1,132                           | )          | (4,236 | ) |
| Change in foreign currency translation adjustment |       | (537                             | )          | — |   |
| Comprehensive income                              |       | $                                | 1,752      |   | $ | 3,841 |   |

 

See accompanying notes tocondensed consolidated financial statements.

 

4

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**PACIFIC ENERGY PARTNERS, L.P.(Note 1)**

**CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS**

**(Unaudited)**

 
| ** **                                                                         | ** ** | **Three Months Ended March 31,** | ** ** |
|------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                         | ** ** | **2005**                         | ** ** | **2004** | ** ** |
| ** **                                                                         | ** ** | **(in thousands)**               | ** ** |
| CASH FLOWS FROM OPERATING ACTIVITIES                                               |       |                             |       |   |   |
| Net income                                                                         |       | $                                | 3,421      |   | $ | 8,077 |   |
| Adjustments to reconcile net income to net cash provided by operating  activities: |       |                             |       |   |   |
| Depreciation and amortization                                                      |       | 6,529                            |       | 5,242 |   |
| Amortization of debt issue costs                                                   |       | 459                              |       | 311 |   |
| Non-cash portion of employee compensation under long-term  incentive plan          |       | 1,545                            |       | 659 |   |
| Deferred tax benefit                                                               |       | (171                             | )          | — |   |
| Share of net income of Frontier                                                    |       | (357                             | )          | (393 | ) |
| Distributions from Frontier, net                                                   |       | —                           |       | 289 |   |
|                                                                               |       | 11,426                           |       | 14,185 |   |
| Net changes in operating assets and liabilities:                                   |       |                             |       |   |   |
| Crude oil sales receivable                                                         |       | (23,327                          | )          | 5,556 |   |
| Transportation and storage accounts receivable                                     |       | (1,832                           | )          | 676 |   |
| Insurance proceeds receivable                                                      |       | (11,495                          | )          | — |   |
| Crude oil inventory                                                                |       | (17,246                          | )          | (2,995 | ) |
| Other current assets and liabilities                                               |       | (1,681                           | )          | 422 |   |
| Accounts payable and other accrued liabilities                                     |       | 8,716                            |       | 1,319 |   |
| Accrued crude oil purchases                                                        |       | 38,176                           |       | (5,981 | ) |
| Line 63 oil release reserve                                                        |       | 13,496                           |       | — |   |
| Other non-current assets and liabilities                                           |       | (301                             | )          | — |   |
|                                                                               |       | 4,506                            |       | (1,003 | ) |
| NET CASH PROVIDED BY OPERATING ACTIVITIES                                          |       | 15,932                           |       | 13,182 |   |
|                                                                               |       |                             |       |   |   |
| CASH FLOWS FROM INVESTING ACTIVITIES                                               |       |                             |       |   |   |
| Additions to property and equipment                                                |       | (4,389                           | )          | (2,413 | ) |
| Acquisition deposit                                                                |       | —                           |       | (9,920 | ) |
| Other                                                                              |       | 129                              |       | — |   |
| NET CASH USED IN INVESTING ACTIVITIES                                              |       | (4,260                           | )          | (12,333 | ) |
|                                                                               |       |                             |       |   |   |
| CASH FLOWS FROM FINANCING ACTIVITIES                                               |       |                             |       |   |   |
| Issuance of common units, net of fees and offering expenses                        |       | —                           |       | 114,250 |   |
| Capital contributions from the general partner                                     |       | 2,438                            |       | 2,443 |   |
| Proceeds from note payable to bank                                                 |       | 26,833                           |       | 16,500 |   |
| Repayment of long-term debt                                                        |       | (25,854                          | )          | (89,500 | ) |
| Deferred financing costs                                                           |       | (600                             | )          | (175 | ) |
| Distributions to partners                                                          |       | (15,114                          | )          | (12,390 | ) |
| Related parties                                                                    |       | (661                             | )          | 156 |   |
| NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES                                |       | (12,958                          | )          | 31,284 |   |
|                                                                               |       |                             |       |   |   |
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                               |       | (1,286                           | )          | 32,133 |   |
| CASH AND CASH EQUIVALENTS, beginning of reporting period                           |       | 23,383                           |       | 9,699 |   |
| CASH AND CASH EQUIVALENTS, end of reporting period                                 |       | $                                | 22,097     |   | $ | 41,832 |   |

 

See accompanying notes tocondensed consolidated financial statements.

 

5

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**PACIFIC ENERGYPARTNERS, L.P.**

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS**

**March 31, 2005**

**(Unaudited)**

 

**1.              SUMMARYOF SIGNIFICANT ACCOUNTING POLICIES**

 

**               ****Basis of Presentation**

 

                Pacific Energy Partners, L.P. and its subsidiaries(the “Partnership”) are engaged principally in the business of gathering,transporting, storing and distributing crude oil and related products inCalifornia and the Rocky Mountain region of the U.S. and Canada. ThePartnership generates revenue primarily by transporting crude oil on itspipelines and by leasing storage capacity. The Partnership also buys, blendsand sells crude oil, activities that are complementary to the Partnership’spipeline transportation business. The Partnership operates primarily inCalifornia, Colorado, Montana, Wyoming and Utah in the United States, and inAlberta, Canada and conducts its business through two regional business segments:the West Coast Business Unit and the Rocky Mountain Business Unit.

 

                We are managed by our generalpartner, Pacific Energy GP, LP, a Delaware limited partnership, which,prior to its conversion to a limited partnership on March 3, 2005, was PacificEnergy GP, Inc., a corporation owned 100% by a subsidiary of The AnschutzCorporation (“TAC”).  On March 3, 2005,TAC sold all of its interest in Pacific Energy GP, Inc. to LB Pacific, LP (“LBP”),which was formed by the Lehman Brothers Merchant Banking Group (“LBMB”) inconnection with the purchase (see “Note 3 — Related Party Transactions”).  Pacific Energy GP, LP is managed by itsgeneral partner, Pacific Energy Management LLC, a Delaware limited liabilitycompany.

 

                The unaudited condensed consolidated financialstatements have been prepared in accordance with accounting principlesgenerally accepted in the United States of America for interim financialreporting and with Securities and Exchange Commission (“SEC”) regulations.Accordingly, these statements have been condensed and do not include all of theinformation and footnotes required for complete financial statements. Thesestatements involve the use of estimates and judgments where appropriate. In theopinion of management, all adjustments, consisting of normal recurring accrualsconsidered necessary for a fair presentation, have been included. The resultsof operations for the three months ended March 31, 2005 are not necessarilyindicative of the results of operations for the full year. All significantintercompany balances and transactions have been eliminated during theconsolidation process.

 

Thecondensed consolidated financialstatements include the ownership and results of operations of the Rangelandsystem, including the Mid-Alberta Pipeline (“MAPL”), since the acquisition ofthose assets on May 11, 2004 and June 30, 2004, respectively.

 

                These financial statements should be read inconjunction with the Partnership’s audited consolidated financial statementsand notes thereto included in the Partnership’s annual report on Form 10-Kfor the year ended December 31, 2004. Certainprior year balances in the accompanying condensed consolidated financialstatements have been reclassified to conform to the current year presentation.

 

                **Income Taxes**

 

                The Partnership and its U.S. and Canadiansubsidiaries are not taxable entities in the U.S. and are not subject to U.S.federal or state income taxes, as the tax effect of operations is passedthrough to its unitholders. The Partnership’s Canadian subsidiaries are taxableentities in Canada and are subject to Canadian federal and provincial incometaxes and other Canadian income taxes. In addition, monies repatriated fromCanada into the U.S. may be subject to withholding taxes.

 

                Income taxes are accounted for under the asset andliability method. Under this method, deferred tax assets and liabilities arerecognized for the future tax consequences attributable to differences betweenthe financial statement carrying amounts of existing 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 on deferred taxassets and liabilities of a change in tax rates is recognized in operations inthe period that includes the enactment date. The Partnership intends to repatriate its Canadian subsidiaries’earnings in the future.  As such, thePartnership records a provision for Canadian withholding taxes on anyrepatriable earnings of its Canadian subsidiaries.

 

**                NetIncome per Unit**

 

                Basic net income per limitedpartner unit is determined by dividing net income after deducting the amountallocated to the general partner interest, by the weighted average number ofoutstanding limited partner units.

 

                Diluted net income per limitedpartner unit is calculated in the same manner as basic net income per limitedpartner unit above, 

 

6

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exceptthat the weighted average number of outstanding limited partner units isincreased to include the dilutive effect of outstanding options and restrictedunits by application of the treasury stock method. Following is areconciliation of the basic weighted average outstanding limited partner unitsto diluted weighted average limited partner units.

 

| ** **                                     | ** ** | **Three Months Ended March 31,** | ** ** |
|------------------------------------------------|------------|----------------------------------|------------|
| ** **                                     | ** ** | **2005**                         | ** ** | **2004** | ** ** |
| ** **                                     | ** ** | **(in thousands)**               | ** ** |
|                                           |       |                             |       |   |   |
| Basic weighted average limited partner units   |       | 29,655                           |       | 24,999 |   |
| Effect of restricted units                     |       | —                           |       | 134 |   |
| Effect of options                              |       | 18                               |       | 16 |   |
| Diluted weighted average limited partner units |       | 29,673                           |       | 25,149 |   |

 

**                Allocation of NetIncome**

 

                Net income is allocated to thePartnership’s general partner and limited partners based on their respectiveinterest in the Partnership.  ThePartnership’s general partner is also directly charged with specific costs thatit has individually assumed and for which the limited partners are notresponsible (see “Note 6—Allocation of Net Income”).

 

**                New AccountingPronouncements**

 

                In December 2004, the FinancialAccounting Standards Board (“FASB”) issued Statement of Financial AccountingStandards No. 123 (revised December 2004), *Share-Based Payment (SFAS123R)*.  This Statement is arevision of SFAS No. 123.  SFAS 123Restablishes standards for the accounting of transactions in which an entityexchanges its equity instruments for goods or services.  SFAS 123R is effective for the Partnership asof the beginning of the first annual reporting period that begins after June15, 2005.  The Partnership has not yetdetermined the impact of the adoption of SFAS 123R on the Partnership’sconsolidated financial statements.

 

                On March 30, 2005 the FASB issued FASB InterpretationNo. 47, **Accountingfor Conditional Asset Retirement Obligations****(FIN 47)**,to clarify the term **conditional asset retirement obligation**as that term is used in FASB Statement No. 143, **Accounting for Asset RetirementObligations**. The Interpretation also clarifies when an entityhas sufficient information to reasonably estimate the fair value of an assetretirement obligation. FIN 47 is effective for the Partnership no later thanthe end of fiscal years ending after December 15, 2005.  The Partnership is in the process ofdetermining the impact of FIN 47 on its financial statements.

 

**2.             LINE 63 OIL RELEASE RESERVE**

 

                OnMarch 23, 2005, a release of approximately 3,400 barrels of crude oil occurredon Line 63 when it was severed as a result of a landslide induced by heavyrainfall in the Pyramid Lake area of Los Angeles County.  Over the period March 2005 throughMarch 2006, the Partnership expects to incur an estimated $13.5 million for oilcontainment and clean-up of the impacted areas, future monitoring costs,potential third-party claims and penalties, and other costs.  As of March 31, 2005, the Partnership hadincurred approximately $3.3 million of the total expected costs related to theoil release for work performed through that date.  Additionally, the Partnership expects toincur approximately $1.0 million to repair the pipeline, which will be expensedas incurred.

 

                The Partnershiphas a pollution liability insurance policy with a $2.0 million deductible thatcovers containment and clean-up costs, third-party claims and penalties.  The insurance carrier has, subject to areservation of certain rights, acknowledged coverage of the incident under thepolicy and has begun processing and paying invoices related to theclean-up.  The Partnership believes that,subject to the $2.0 million deductible, it will be entitled to recoversubstantially all of its clean-up costs and any third party claims associatedwith the release.  The Partnership’sinsurance coverage will not cover the cost to repair the pipeline.  For the three months ended March 31, 2005,the Partnership accrued a receivable of $11.5 million for insurance receipts itdeems probable.

 

                Accrued costsrelating to the release of $13.5 million net of accrued insurance receipt of$11.5 million, or $2.0 million, are recorded in “Line 63 oil release costs” inthe accompanying condensed consolidated statements of income for the threemonths ended March 31, 2005.

 

                The foregoingestimates are 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 and repair plans, the limited amount of data availableat the time of the assessment of the impact of soil and water contamination,the current uncertainty of the geological conditions that will be encounteredduring the repairs of the damaged pipeline, changes in costs associated withenvironmental remediation services and equipment and the possibility of third-

 

7

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party legal claims giving rise to additional expenses. Therefore, noassurance can be made that costs incurred in excess of this provision, if any,would not have a material adverse effect on the Partnership’s financialcondition, results of operations, or cash flows, though the Partnershipbelieves it is likely that most, if not all, of any such excess cost, to theextent attributable to clean-up and third-party claims, would be recoverablethrough insurance. As new information becomes available in future periods, thePartnership may change its provision and recovery estimates.

 

**3.             RELATED PARTYTRANSACTIONS**

 

**                Sale of The Anschutz Corporation’sInterest in the Partnership**

 

                On March 3, 2005, TAC sold allof its interest in Pacific Energy GP, Inc. to LBP, which was formed by LBMB inconnection with the purchase.  Theacquisition by LBP (the “LB Acquisition”) included the 100% ownership interestin Pacific Energy GP, Inc., which owned (i) the 2% general partner interest inthe Partnership and the incentive distribution rights, and (ii) 10,465,000subordinated units of the Partnership representing a 34.6% limited partnerinterest in the Partnership.  Immediatelyprior to the closing of the LB Acquisition, Pacific Energy GP, Inc. wasconverted to Pacific Energy GP, LLC, a Delaware limited liability company; andimmediately after the closing of the LB Acquisition, Pacific Energy GP, LLC wasconverted to Pacific Energy GP, LP (the “General Partner”). Immediatelyfollowing the consummation of the LB Acquisition, the General Partnerdistributed the 10,465,000 subordinated units of the Partnership to LBP.

 

                In connection with theconversion of the Partnership’s General Partner to a limited partnership, theGeneral Partner ceased to have a board of directors, and is now managed by itsgeneral partner, Pacific Energy Management LLC, a Delaware limited liabilitycompany (“PEM” or the “Managing General Partner”), which is 100% owned by LBP.  PEM has a board of directors (the “Board ofDirectors” or “Board”) that manages the business and affairs of PEM and, thus,indirectly manages the business and affairs of the General Partner and thePartnership.  All of theofficers and employees of Pacific Energy GP, Inc. were transferred to fill thesame positions with PEM, and the PEM Board established the same committees ashad been maintained by Pacific Energy GP, Inc. prior to the LB Acquisition. PEMalso adopted Pacific Energy GP, Inc.’s governance guidelines and itscompensation structure and employee benefits plans and policies.

 

                Additionally, on March 21, 2005,an affiliate of First Reserve Corporation (“First Reserve”) acquired from LBMBa 30% partnership interest in LBP. LBMB and its affiliates continue to own a70% partnership interest in LBP.  As aresult of its ownership interest, First Reserve is entitled to and hasnominated one director to the Board of Directors of PEM.  The director nominated by First Reserve wasappointed by LBP to the Board on April 6, 2005.

 

                The Board of Directors of PEM isnow comprised of six of the directors who served on the board of directors ofPacific Energy GP, Inc. prior to the LB Acquisition, together with five newdirectors appointed by LBP.

 

**                Cost Reimbursements**

 

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

 

                ***Special Agreement:***On March 3, 2005, Douglas L. Polson, previously the Chairman of the Board ofDirectors of Pacific Energy GP, Inc., entered into a Special Agreement and aConsulting Agreement with PEM.  Inaccordance with the Special Agreement, Mr. Polson resigned as Chairman of theBoard of Directors of Pacific Energy GP, Inc. effective March 3, 2005.  Mr. Polson was paid approximately $0.9million, representing accrued but unused vacation, accrued salary through March3, 2005 and payment in satisfaction of other obligations under his employmentagreement.  The severance portion of thispayment of approximately $0.9 million was recorded as an expense in “Transactioncosts” in the accompanying condensed consolidated income statements (see “Note6 – Allocation of Net Income”). LBP reimbursed this amount, which was recordedas a partner’s capital contribution.  Pursuant to the Consulting Agreement, Mr.Polson has agreed to perform advisory services to PEM from time to time asshall be mutually agreed between Mr. Polson and the Chief Executive Officer ofPEM. In consideration for Mr. Polson’s services under the Consulting Agreement,which has a one-year term, Mr. Polson will receive 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.

 

                ***LBPacific, LP and TAC:*** LBP and TAC reimbursed the Partnership forcertain other costs relating to the LB Acquisition.  These included $1.2 million for the ConsentSolicitation (as defined and further described in “Note 4—Long-Term Debt”,below) and $0.3 million for legal and other expenses (also see “Note6—Allocation of Net Income”).

 

**                OtherRelated Party Transactions**

## ** **

                ***Revenue from RelatedParties:*** Rocky Mountain Pipeline system (“RMPS”) serves as thecontract operator for certain gas 

 

8

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producing propertiesowned by a subsidiary of TAC in Wyoming and Utah, in exchange for which RMPS isreimbursed its direct costs of operation and is paid an annual fee of$0.3 million as compensation for the time spent by RMPS management and forother overhead services related to their activities.

 

                RMPS also receives an operating fee and managementfee from Frontier Pipeline Company (“Frontier”) in connection with time spentby RMPS management and for other services related to Frontier’s pipeline’sactivities. RMPS received $0.2 million and $0.1 million for the three monthsended March 31, 2005 and 2004, respectively.

 

                ***Expenses Paid to Related Parties:***The Partnershiputilizes the financial accounting system owned and provided by TAC under ashared services arrangement for a fee of $0.1 million per year and TACcharges the Partnership for any out-of-pocket costs it incurs. The fixed annualfee includes all license, maintenance and employee costs associated with thePartnership’s use of the financial accounting system.  The Partnership will continue to use thefinancial accounting system after the close of the LB Acquisition pursuant to atransition services agreement until December 31, 2005, or earlier if elected bythe Partnership.

 

                In January 2003, thePartnership began leasing approximately 4,700 square feet of office space froman affiliate of TAC, for a term of five years at an annual cost of$0.1 million per year.   This spacewas increased to 5,400 square feet in 2004.

 

                ***Duefrom (to) Related Parties:*** Due from related parties consists of $0.1 million due from PEM and $0.5million due to Pacific Energy GP, Inc. at March 31, 2005 and December 31, 2004,respectively.

 

**4.             LONG-TERMDEBT**

 

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

 

| ** **                                                                                                                              | ** ** | **March 31,  2005** | ** ** | **December 31,  2004** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------|------------|------------------------|------------|
| ** **                                                                                                                              | ** ** | **(in thousands)**  | ** ** |
|                                                                                                                                    |       |                |       |                   |       |
| Senior secured U.S. revolving credit facility, bearing interest at  4.4% on March 31, 2005, due July 2007                               |       | $                   | 52,000     |                   | $          | 51,000 |   |
| Senior secured Canadian revolving credit facility, bearing interest  at 4.9% on March 31, 2005, due May 2007                            |       | 53,737              |       | 54,005                 |       |
| Senior notes, net of unamortized discount of $4,125 and including  fair value increase of $1,063, with a coupon of 71/8%, due June 2014 |       | 246,938             |       | 248,491                |       |
| Future payment for MAPL assets, net of unamortized discount of $439,  due June 2007                                                     |       | 3,694               |       | 3,667                  |       |
| Long-term debt                                                                                                                          |       | $                   | 356,369    |                   | $          | 357,163 |   |

 

Under the Indenturegoverning the Partnership’s Senior Notes, the Partnership would have beenrequired to make a “Change of Control Offer” to the note holders if the LBAcquisition would have caused a rating decline. In order to avoid triggeringthe “Change of Control Offer” provision, the Partnership solicited the consent(the “Consent Solicitation”) of the holders of the Senior Notes to amendcertain provisions of the Indenture, including an amendment to the definitionof “Change of Control.”  The ConsentSolicitation commenced on January 28, 2005 and expired on February 10, 2005.During that time, a majority of the holders of the Senior Notes consented tothe adoption of the proposed amendments and as such the proposed amendmentswere approved. Thereafter, a supplemental indenture that incorporated theproposed amendments was executed by the parties to the Indenture. Fees ofapproximately $0.6 million paid to holders of the Senior Notes were capitalizedand included in “Other assets” in the accompanying condensed consolidated balancesheet at March 31, 2005 and will be amortized over the remaining life of theSenior Notes.  Solicitation–related feesand expenses of approximately $0.6 million are included in “Transaction costs”in the accompanying condensed consolidated statements of income. LBP and TACreimbursed the Partnership for the costs of the Consent Solicitation, which arerecorded as a partner’s capital contribution (see “Note 3—Related PartyTransactions”).

 

                Additionally, the U.S. andCanadian revolving credit facilities also contained change of controlprovisions.  The Partnership amended theU.S. and Canadian revolving credit facilities to account for the change incontrol of its General Partner.

 

9

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**5.             VESTING OF UNIT GRANTS UNDER LONG-TERM INCENTIVE PLAN**

 

                OnMarch 3, 2005, in connection with the LB Acquisition and with the change incontrol of the Partnership’s General Partner, all restricted units outstandingunder the Partnership’s Long-Term Incentive Plan immediately vested pursuant tothe terms of the grants.  The Partnershipissued 99,583 common units and recognized a compensation expense of $3.1million, which is included in “Accelerated long-term incentive plancompensation expense” in the accompanying condensed consolidated statements ofincome.

 

**6.             ALLOCATION OF NETINCOME**

 

                The allocation of net incomebetween the Partnership’s general partner and limited partners is as follows.

 

| ** **                                                              | ** ** | **Three Months Ended March 31,** | ** ** |
|-------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                              | ** ** | **2005**                         | ** ** | **2004** | ** ** |
| ** **                                                              | ** ** | **(in thousands)**               | ** ** |
|                                                                    |       |                             |       |   |   |
| Net income                                                              |       | $                                | 3,421      |   | $ | 8,077 |   |
| Transaction costs reimbursed by general partner:                        |       |                             |       |   |   |
| Senior Notes consent solicitation and other costs                       |       | 893                              |       | — |   |
| Severance and other costs                                               |       | 914                              |       | — |   |
| Total transaction costs reimbursed by general partner                   |       | 1,807                            |       | — |   |
| Income before transaction costs reimbursed by general partner           |       | 5,228                            |       | 8,077 |   |
| General partner’s share of income                                  |       | 2                                | %          | 2 | % |
| General partner allocated share of net income before transaction  costs |       | 105                              |       | 162 |   |
| Transaction costs reimbursed by general partner                         |       | (1,807                           | )          | — |   |
| Net income (loss) allocated to general partner                          |       | $                                | (1,702     | ) | $ | 162 |   |
|                                                                    |       |                             |       |   |   |
| Income before transaction costs reimbursed by general partner           |       | $                                | 5,228      |   | $ | 8,077 |   |
| Limited partners share of income                                        |       | 98                               | %          | 98 | % |
| Limited partners share of net income                                    |       | $                                | 5,123      |   | $ | 7,915 |   |
|                                                                    |       |                             |       |   |   |
| Net income (loss) allocated to general partner                          |       | $                                | (1,702     | ) | $ | 162 |   |
| Net income allocated to limited partners                                |       | 5,123                            |       | 7,915 |   |
| Net income                                                              |       | $                                | 3,421      |   | $ | 8,077 |   |
|                                                                    |       |                             |       |   |   |
|                                                                         |            |                                  |            |  |  |  |  |  |

                LBP and TAC reimbursed thePartnership for certain costs incurred in connection with the LBAcquisition.  The Partnership wasreimbursed $1.2 million for costs incurred in connection with the consentsolicitation, $0.3 million of legal and other costs and $0.9 million relatingto severance costs (see “Note 3—Related Party Transactions”), for a total of$2.4 million.  Of the $1.2 millionincurred for the consent solicitation, $0.6 million was capitalized as deferredfinancing costs and $0.6 million was expensed.

 

10

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**7.              SEGMENTINFORMATION**

 

                The Partnership’s business and operations areorganized into two regional business segments: West Coast Business Unit andRocky Mountain Business Unit. The West Coast Business Unit includes: (i)Pacific Pipeline System LLC, owner of Line 2000 and Line 63, (ii) PacificMarketing and Transportation LLC, owner of the PMT gathering and blendingsystem, and (iii) Pacific Terminals LLC, owner of the Pacific Terminals storageand distribution system. The Rocky Mountain Business Unit includes: (i) RockyMountain Pipeline System LLC, owner of the Partnership’s interest in variouspipelines that make up the Western Corridor and Salt Lake City Core systems,(ii) Ranch Pipeline LLC, the owner of a 22.22% partnership interest in FrontierPipeline Company, and (iii) PEG Canada, L.P. and its Canadian subsidiaries,which own and operate the Rangeland system (for the period since May 11,2004). General and administrative costs, which consist of executive management,accounting and finance, human resources, information technology, investorrelations, legal, and business development, are not allocated to the individualbusiness units. Information regarding these two business units is summarizedbelow:

 
| ** **                                  | ** ** | ** **          | ** ** | ** **         | ** ** | **Intersegment and** | ** ** | ** ** | ** ** |
|---------------------------------------------|------------|---------------------|------------|--------------------|------------|----------------------|------------|------------|------------|
| ** **                                  | ** ** | **West Coast**      | ** ** | **Rocky Mountain** | ** ** | **Intrasegment**     | ** ** | ** ** | ** ** |
| ** **                                  | ** ** | **Business Unit**   | ** ** | **Business Unit**  | ** ** | **Eliminations**     | ** ** | **Total**  | ** ** |
| ** **                                  | ** ** | **(in  thousands)** | ** ** |
| **Three months ended March 31, 2005**       |       |                |       |               |       |                 |       |       |       |
| Business unit revenue:                      |       |                |       |               |       |                 |       |       |       |
| Pipeline transportation revenue             |       | $                   | 17,443     |               | $          | 12,456               |       | $          | (1,862     | ) | $ | 28,037 |   |
| Storage and distribution revenue            |       | 10,472              |       | —             |       | (150                 | )          | 10,322     |       |
| Pipeline buy/sell transportation revenue(1) |       | —              |       | 9,106              |       |                 |       | 9,106      |       |
| Crude oil sales, net of purchases(2)        |       | 1,812               |       | —             |       | (30                  | )          | 1,782      |       |
| Net revenue                                 |       | 29,727              |       | 21,562             |       |                 |       | 49,247     |       |
| Expenses:                                   |       |                |       |               |       |                 |       |       |       |
| Operating                                   |       | 14,507              |       | 9,289              |       | (2,042               | )          | 21,754     |       |
| Line 63 oil release costs(3)                |       | 2,000               |       | —             |       |                 |       | 2,000      |       |
| Depreciation and amortization               |       | 3,477               |       | 3,052              |       |                 |       | 6,529      |       |
| Total expenses                              |       | 19,984              |       | 12,341             |       |                 |       | 30,283     |       |
| Share of net income of Frontier             |       | —              |       | 357                |       |                 |       | 357        |       |
| Operating income from segments(4)           |       | $                   | 9,743      |               | $          | 9,578                |       |       |       | $ | 19,321 |   |
| Business unit assets(5)                     |       | $                   | 538,568    |               | $          | 350,600              |       |       |       | $ | 889,168 |   |
| Capital expenditures(6)                     |       | $                   | 750        |               | $          | 2,932                |       |       |       | $ | 3,682 |   |
|                                        |       |                |       |               |       |                 |       |       |       |
| **Three months ended March 31, 2004**       |       |                |       |               |       |                 |       |       |       |
| Business unit revenue:                      |       |                |       |               |       |                 |       |       |       |
| Pipeline transportation revenue             |       | $                   | 15,691     |               | $          | 10,543               |       | $          | (1,507     | ) | $ | 24,727 |   |
| Storage and distribution revenue            |       | 10,223              |       | —             |       | (100                 | )          | 10,123     |       |
| Crude oil sales, net of purchases(2)        |       | 4,812               |       | —             |       |                 |       | 4,812      |       |
| Net revenue                                 |       | 30,726              |       | 10,543             |       |                 |       | 39,662     |       |
| Expenses:                                   |       |                |       |               |       |                 |       |       |       |
| Operating                                   |       | 14,706              |       | 5,818              |       | (1,607               | )          | 18,917     |       |
| Depreciation and amortization               |       | 3,765               |       | 1,477              |       |                 |       | 5,242      |       |
| Total expenses                              |       | 18,471              |       | 7,295              |       |                 |       | 24,159     |       |
| Share of net income of Frontier             |       | —              |       | 393                |       |                 |       | 393        |       |
| Operating income from segments(4)           |       | $                   | 12,255     |               | $          | 3,641                |       |       |       | $ | 15,896 |   |
| Business unit assets(5)                     |       | $                   | 511,254    |               | $          | 123,837              |       |       |       | $ | 635,091 |   |
| Capital expenditures(6)                     |       | $                   | 793        |               | $          | 1,291                |       |       |       | $ | 2,084 |   |

----

(1)                                  Includes the revenue of the Rangeland system, which was acquired on May11, 2004 and June 30, 2004.  Pipelinebuy/sell transportation revenue reflects net revenues of approximately $1.4million on buy/sell transactions with different parties of $20.5 million.  The remaining amount reflects net revenues onbuy/sell transactions with the same party.

(2)                                  The above amountsare net of purchases of $114,391 and $81,115 for 2005 and 2004, respectively.

(3)                                  See “Note 2 — Line63 Oil Release Reserve” for further information.

 

11

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(4)                                  The following is a reconciliationof operating income as stated above to net income:

 

| ** **                                                      | ** ** | **Three Months Ended March 31,** | ** ** |
|-----------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                      | ** ** | **2005**                         | ** ** | **2004** | ** ** |
| ** **                                                      | ** ** | **(in thousands)**               | ** ** |
| **Income Statement Reconciliation**                             |       |                             |       |   |   |
| Operating income from above:                                    |       |                             |       |   |   |
| West Coast Business Unit                                        |       | $                                | 9,743      |   | $ | 12,255 |   |
| Rocky Mountain Business Unit                                    |       | 9,578                            |       | 3,641 |   |
| Operating income before general and administrative expense      |       | 19,321                           |       | 15,896 |   |
| Less: General and administrative expense                        |       | (5,172                           | )          | (3,854 | ) |
| Less: Accelerated long-term incentive plan compensation expense |       | (3,115                           | )          | — |   |
| Less: Transaction costs                                         |       | (1,807                           | )          | — |   |
| Operating income                                                |       | 9,227                            |       | 12,042 |   |
| Interest expense                                                |       | (5,598                           | )          | (4,126 | ) |
| Other income                                                    |       | 353                              |       | 161 |   |
| Income tax expense                                              |       | (561                             | )          | — |   |
| Net income                                                      |       | $                                | 3,421      |   | $ | 8,077 |   |

 

(5)                                  Business unit assetsdo not include assets related to the Partnership’s corporate activity.  As of March 31, 2005 and 2004, corporaterelated assets were $30,922 and $50,449 respectively.

(6)                                  Capital expendituresdo not include the Pier 400 project and other corporate related capitalexpenditures.  Pier 400 project and othercorporate related capital expenditures were $0.7 million and $0.3 million forthe three months ended March 31, 2005 and 2004, respectively.

 

**8.            CONTINGENCIES**

 

                The Partnership is involved in various regulatorydisputes, litigation and claims arising out of its operations in the normalcourse of business. See also “Note 2—Line 63 Oil Release Reserve”. ThePartnership is not currently a party to any other legal or regulatory proceedings,the resolution of which could be expected to have a material adverse effect onits business, financial condition or results of operations.

 

**9.            SUBSEQUENT EVENT**

 

                On April 22, 2005, thePartnership declared a cash distribution of $0.5125 per limited partner unit,payable on May 13, 2005, to unitholders of record as of May 2, 2005.

 

12

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**10.          SUPPLEMENTAL CONDENSED CONSOLIDATINGFINANCIAL INFORMATION**

 

                Given that certain, but not all subsidiaries of thePartnership are guarantors of the 71/8% Senior Notes, the Partnership is required to presentthe following supplemental condensed consolidating financial information. Forpurposes of the following footnote, the Partnership and its predecessor arereferred to as “Parent.” Rocky Mountain Pipeline System LLC, Pacific Marketingand Transportation LLC, Ranch Pipeline LLC, PEG Canada GP LLC, PEG Canada, L.P.and Pacific Energy Group LLC, the guarantors of the Senior Notes, arecollectively referred to as the “Guarantor Subsidiaries,” and Pacific PipelineSystem LLC, Pacific Terminals LLC, Rangeland Pipeline Company, RangelandMarketing Company, Rangeland Northern Pipeline Company, Rangeland PipelinePartnership and Aurora Pipeline Company, Ltd. are referred to as “Non-GuarantorSubsidiaries.”

 

                The following supplemental condensed consolidatingfinancial information reflects the Parent’s separate accounts, the combinedaccounts of the Guarantor Subsidiaries, the combined accounts of the Parent’sNon-Guarantor Subsidiaries, the combined consolidating adjustments andeliminations and the Parent’s consolidated accounts for the dates and periodsindicated. For purposes of the following condensed consolidating information,the Parent’s investments in its subsidiaries and the Guarantor Subsidiaries’investments in their subsidiaries are accounted for under the equity method ofaccounting:

 
| ** **                                   | ** ** | **Balance Sheet**  | ** ** |
|----------------------------------------------|------------|--------------------|------------|
| ** **                                   | ** ** | **March 31, 2005** | ** ** |
| ** **                                   | ** ** | ** **         | ** ** | **Guarantor** | ** ** | **Non-Guarantor** | ** ** | **Consolidating** | ** ** | ** ** | ** ** |
| ** **                                   | ** ** | **Parent**         | ** ** | **Subsidiaries** | ** ** | **Subsidiaries** | ** ** | **Adjustments** | ** ** | **Total** | ** ** |
| ** **                                   | ** ** | **(in thousands)** | ** ** |
| Assets:                                      |       |               |       |   |   |   |   |   |   |   |   |
| Current assets                               |       | $                  | 31,819     |   | $ | 101,750 |   | $ | 72,272 |   | $ | (55,499 | ) | $ | 150,342 |   |
| Property and equipment                       |       | —             |       | 129,014 |   | 586,566 |   | — |   | 715,580 |   |
| Equity investments                           |       | 357,747            |       | 209,668 |   | — |   | (559,215 | ) | 8,200 |   |
| Intercompany notes receivable                |       | 269,450            |       | 338,574 |   | — |   | (608,024 | ) | — |   |
| Other assets                                 |       | 6,113              |       | 1,814 |   | 38,041 |   | — |   | 45,968 |   |
| Total assets                                 |       | $                  | 665,129    |   | $ | 780,820 |   | $ | 696,879 |   | $ | (1,222,738 | ) | $ | 920,090 |   |
| Liabilities and partners’ capital:      |       |               |       |   |   |   |   |   |   |   |   |
| Current liabilities                          |       | $                  | 5,220      |   | $ | 100,991 |   | $ | 58,428 |   | $ | (55,499 | ) | $ | 109,140 |   |
| Long-term debt                               |       | 246,938            |       | 52,000 |   | 57,431 |   | — |   | 356,369 |   |
| Deferred income taxes                        |       | —             |       | 497 |   | 33,751 |   | — |   | 34,248 |   |
| Intercompany notes payable                   |       | —             |       | 269,450 |   | 338,574 |   | (608,024 | ) | — |   |
| Other liabilities                            |       | —             |       | 135 |   | 7,227 |   | — |   | 7,362 |   |
| Total partners’ capital                 |       | 412,971            |       | 357,747 |   | 201,468 |   | (559,215 | ) | 412,971 |   |
| Total liabilities and partners’ capital |       | $                  | 665,129    |   | $ | 780,820 |   | $ | 696,879 |   | $ | (1,222,738 | ) | $ | 920,090 |   |

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

 

13

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| ** **                                                | ** ** | **Statement of Income**               | ** ** |
|-----------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                | ** ** | **Three Months Ended March 31, 2005** | ** ** |
| ** **                                                | ** ** | ** **                            | ** ** | **Guarantor** | ** ** | **Non-Guarantor** | ** ** | **Consolidating** | ** ** | ** ** | ** ** |
| ** **                                                | ** ** | **Parent**                            | ** ** | **Subsidiaries** | ** ** | **Subsidiaries** | ** ** | **Adjustments** | ** ** | **Total** | ** ** |
| ** **                                                | ** ** | **(in thousands)**                    | ** ** |
|                                                      |       |                                  |       |   |   |   |   |   |   |   |   |
| Net operating revenues                                    |       | $                                     | —     |   | $ | 14,268 |   | $ | 37,021 |   | $ | (2,042 | ) | $ | 49,247 |   |
| Operating expenses                                        |       | —                                |       | (9,968 | ) | (13,828 | ) | 2,042 |   | (21,754 | ) |
| Line 63 oil release costs                                 |       | —                                |       | — |   | (2,000 | ) | — |   | (2,000 | ) |
| General and administrative expense(1)                     |       | —                                |       | (4,618 | ) | (554 | ) | — |   | (5,172 | ) |
| Accelerated long-term incentive plan compensation expense |       | —                                |       | (2,684 | ) | (431 | ) | — |   | (3,115 | ) |
| Transaction costs                                         |       | (893                                  | )          | (914 | ) | — |   | — |   | (1,807 | ) |
| Depreciation and amortization expense                     |       | —                                |       | (1,624 | ) | (4,905 | ) | — |   | (6,529 | ) |
| Share of net income of Frontier                           |       | —                                |       | 357 |   | — |   | — |   | 357 |   |
| Operating income                                          |       | (893                                  | )          | (5,183 | ) | 15,303 |   | — |   | 9,227 |   |
| Interest expense                                          |       | (4,078                                | )          | (679 | ) | (841 | ) | — |   | (5,598 | ) |
| Intercompany interest income (expense)                    |       | —                                |       | 6,271 |   | (6,271 | ) | — |   | — |   |
| Equity earnings                                           |       | 8,384                                 |       | 7,990 |   | — |   | (16,374 | ) | — |   |
| Other income                                              |       | 8                                     |       | 166 |   | 179 |   | — |   | 353 |   |
| Income tax benefit (expense)                              |       | —                                |       | (181 | ) | (380 | ) | — |   | (561 | ) |
| Net income                                                |       | $                                     | 3,421      |   | $ | 8,384 |   | $ | 7,990 |   | $ | (16,374 | ) | $ | 3,421 |   |

----

(1)          General and administrative expense is notcurrently allocated between Guarantor and Non-Guarantor Subsidiaries forfinancial reporting purposes.

 
| ** **                             | ** ** | **Statement of Income**               | ** ** |
|----------------------------------------|------------|---------------------------------------|------------|
| ** **                             | ** ** | **Three Months Ended March 31, 2004** | ** ** |
| ** **                             | ** ** | ** **                            | ** ** | **Guarantor** | ** ** | **Non-Guarantor** | ** ** | **Consolidating** | ** ** | ** ** | ** ** |
| ** **                             | ** ** | **Parent**                            | ** ** | **Subsidiaries** | ** ** | **Subsidiaries** | ** ** | **adjustments** | ** ** | **Total** | ** ** |
| ** **                             | ** ** | **(in thousands)**                    | ** ** |
|                                   |       |                                  |       |   |   |   |   |   |   |   |   |
| Net operating revenues                 |       | $                                     | —     |   | $ | 15,356 |   | $ | 25,913 |   | $ | (1,607 | ) | $ | 39,662 |   |
| Operating expenses                     |       | —                                |       | (9,700 | ) | (10,824 | ) | 1,607 |   | (18,917 | ) |
| General and administrative expense(1)  |       | —                                |       | (3,828 | ) | (26 | ) | — |   | (3,854 | ) |
| Depreciation and amortization expense  |       | —                                |       | (1,595 | ) | (3,647 | ) | — |   | (5,242 | ) |
| Share of net income of Frontier        |       | —                                |       | 393 |   | — |   | — |   | 393 |   |
| Operating income                       |       | —                                |       | 626 |   | 11,416 |   | — |   | 12,042 |   |
| Interest expense                       |       | —                                |       | (4,126 | ) | — |   | — |   | (4,126 | ) |
| Intercompany interest income (expense) |       | —                                |       | 3,747 |   | (3,747 | ) | — |   | — |   |
| Equity earnings                        |       | 8,076                                 |       | 7,710 |   | — |   | (15,786 | ) | — |   |
| Other income                           |       | 1                                     |       | 119 |   | 41 |   | — |   | 161 |   |
| Net income                             |       | $                                     | 8,077      |   | $ | 8,076 |   | $ | 7,710 |   | $ | (15,786 | ) | $ | 8,077 |   |

----

(1)          General and administrative expense is notcurrently allocated between Guarantor and Non-Guarantor Subsidiaries forfinancial reporting purposes.

 

14

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| ** **                                  | ** ** | **Statement of Comprehensive Income** | ** ** |
|---------------------------------------------|------------|---------------------------------------|------------|
| ** **                                  | ** ** | **Three Months Ended March 31, 2005** | ** ** |
| ** **                                  | ** ** | ** **                            | ** ** | **Guarantor** | ** ** | **Non- Guarantor** | ** ** | **Consolidating** | ** ** | ** ** | ** ** |
| ** **                                  | ** ** | **Parent**                            | ** ** | **Subsidiaries** | ** ** | **Subsidiaries** | ** ** | **Adjustments** | ** ** | **Total** | ** ** |
| ** **                                  | ** ** | **(in thousands)**                    | ** ** |
|                                        |       |                                  |       |   |   |   |   |   |   |   |   |
| Net income                                  |       | $                                     | 3,421      |   | $ | 8,384 |   | $ | 7,990 |   | $ | (16,374 | ) | $ | 3,421 |   |
| Change in fair value of hedging derivatives |       | (1,132                                | )          | (1,132 | ) | — |   | 1,132 |   | (1,132 | ) |
| Foreign currency translation adjustment     |       | (537                                  | )          | (537 | ) | (537 | ) | 1,074 |   | (537 | ) |
| Comprehensive income                        |       | $                                     | 1,752      |   | $ | 6,715 |   | $ | 7,453 |   | $ | (14,168 | ) | $ | 1,752 |   |

 

 
| ** **                                  | ** ** | **Statement of Comprehensive Income** | ** ** |
|---------------------------------------------|------------|---------------------------------------|------------|
| ** **                                  | ** ** | **Three Months Ended March 31, 2004** | ** ** |
| ** **                                  | ** ** | ** **                            | ** ** | **Guarantor** | ** ** | **Non- Guarantor** | ** ** | **Consolidating** | ** ** | ** ** | ** ** |
| ** **                                  | ** ** | **Parent**                            | ** ** | **Subsidiaries** | ** ** | **Subsidiaries** | ** ** | **Adjustments** | ** ** | **Total** | ** ** |
| ** **                                  | ** ** | **(in thousands)**                    | ** ** |
|                                        |       |                                  |       |   |   |   |   |   |   |   |   |
| Net income                                  |       | $                                     | 8,077      |   | $ | 8,076 |   | $ | 7,710 |   | $ | (15,786 | ) | $ | 8,077 |   |
| Change in fair value of hedging derivatives |       | (4,236                                | )          | (4,236 | ) | — |   | 4,236 |   | (4,236 | ) |
| Comprehensive income                        |       | $                                     | 3,841      |   | $ | 3,840 |   | $ | 7,710 |   | $ | (11,550 | ) | $ | 3,841 |   |

 

15

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| ** **                                                                         | ** ** | **Statement of Cash Flows**           | ** ** |
|------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                         | ** ** | **Three Months Ended March 31, 2005** | ** ** |
| ** **                                                                         | ** ** | ** **                            | ** ** | **Guarantor** | ** ** | **Non-Guarantor** | ** ** | **Consolidating** | ** ** | ** ** | ** ** |
| ** **                                                                         | ** ** | **Parent**                            | ** ** | **Subsidiaries** | ** ** | **Subsidiaries** | ** ** | **Adjustments** | ** ** | **Total** | ** ** |
| ** **                                                                         | ** ** | **(in thousands)**                    | ** ** |
|                                                                               |       |                                  |       |   |   |   |   |   |   |   |   |
| CASH FLOWS FROM OPERATING ACTIVITIES:                                              |       |                                  |       |   |   |   |   |   |   |   |   |
| Net income                                                                         |       | $                                     | 3,421      |   | $ | 8,384 |   | $ | 7,990 |   | $ | (16,374 | ) | $ | 3,421 |   |
| Adjustments to reconcile net income to net cash provided by operating  activities: |       |                                  |       |   |   |   |   |   |   |   |   |
| Equity earnings                                                                    |       | (8,384                                | )          | (7,990 | ) | — |   | 16,374 |   | — |   |
| Distributions from subsidiaries                                                    |       | 15,114                                |       | 12,673 |   | — |   | (27,787 | ) | — |   |
| Depreciation, amortization and other                                               |       | 157                                   |       | 2,984 |   | 4,864 |   | — |   | 8,005 |   |
| Net changes in operating assets and liabilities                                    |       | 3,915                                 |       | 1,840 |   | 74 |   | (1,323 | ) | 4,506 |   |
| NET CASH PROVIDED BY OPERATING ACTIVITIES                                          |       | 14,223                                |       | 17,891 |   | 12,928 |   | (29,110 | ) | 15,932 |   |
| CASH FLOWS FROM INVESTING ACTIVITIES                                               |       |                                  |       |   |   |   |   |   |   |   |   |
| Additions to property, equipment and other                                         |       | —                                |       | (1,091 | ) | (3,169 | ) | — |   | (4,260 | ) |
| Intercompany                                                                       |       | (914                                  | )          | — |   | — |   | 914 |   | — |   |
| NET CASH USED IN INVESTING ACTIVITIES                                              |       | (914                                  | )          | (1,091 | ) | (3,169 | ) | 914 |   | (4,260 | ) |
| NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES                                |       | (14,894                               | )          | (18,276 | ) | (7,984 | ) | 28,196 |   | (12,958 | ) |
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                               |       | (1,585                                | )          | (1,476 | ) | 1,775 |   | — |   | (1,286 | ) |
| CASH AND CASH EQUIVALENTS, beginning of reporting period                           |       | 2,713                                 |       | 17,523 |   | 3,147 |   | — |   | 23,383 |   |
| CASH AND CASH EQUIVALENTS, end of reporting period                                 |       | $                                     | 1,128      |   | $ | 16,047 |   | $ | 4,922 |   | $ | — |   | $ | 22,097 |   |
|                                                                                    |            |                                       |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

16

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| ** **                                                                         | ** ** | **Statement of Cash Flows**           | ** ** |
|------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                         | ** ** | **Three Months Ended March 31, 2004** | ** ** |
| ** **                                                                         | ** ** | ** **                            | ** ** | **Guarantor** | ** ** | **Non-Guarantor** | ** ** | **Consolidating** | ** ** | ** ** | ** ** |
| ** **                                                                         | ** ** | **Parent**                            | ** ** | **Subsidiaries** | ** ** | **Subsidiaries** | ** ** | **Adjustments** | ** ** | **Total** | ** ** |
| ** **                                                                         | ** ** | **(in thousands)**                    | ** ** |
|                                                                               |       |                                  |       |   |   |   |   |   |   |   |   |
| CASH FLOWS FROM OPERATING ACTIVITIES:                                              |       |                                  |       |   |   |   |   |   |   |   |   |
| Net income                                                                         |       | $                                     | 8,077      |   | $ | 8,076 |   | $ | 7,710 |   | $ | (15,786 | ) | $ | 8,077 |   |
| Adjustments to reconcile net income to net cash provided by operating  activities: |       |                                  |       |   |   |   |   |   |   |   |   |
| Equity earnings                                                                    |       | (8,076                                | )          | (7,710 | ) | — |   | 15,786 |   | — |   |
| Distributions from subsidiaries                                                    |       | 12,390                                |       | 10,997 |   | — |   | (23,387 | ) | — |   |
| Depreciation, amortization and other                                               |       | —                                |       | 2,461 |   | 3,647 |   | — |   | 6,108 |   |
| Net changes in operating assets and liabilities                                    |       | —                                |       | (3,059 | ) | 2,628 |   | (572 | ) | (1,003 | ) |
| NET CASH PROVIDED BY OPERATING ACTIVITIES                                          |       | 12,391                                |       | 10,765 |   | 13,985 |   | (23,959 | ) | 13,182 |   |
| CASH FLOWS FROM INVESTING ACTIVITIES                                               |       |                                  |       |   |   |   |   |   |   |   |   |
| Acquisition deposit                                                                |       | —                                |       | (9,920 | ) | — |   | — |   | (9,920 | ) |
| Additions to property, equipment and other                                         |       | —                                |       | (1,620 | ) | (793 | ) | — |   | (2,413 | ) |
| Intercompany                                                                       |       | (117,061                              | )          | — |   | — |   | 117,061 |   | — |   |
| NET CASH USED IN INVESTING ACTIVITIES                                              |       | (117,061                              | )          | (11,540 | ) | (793 | ) | 117,061 |   | (12,333 | ) |
| NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES                                |       | 104,005                               |       | 25,722 |   | (5,341 | ) | (93,102 | ) | 31,284 |   |
| NET DECREASE IN CASH AND CASH EQUIVALENTS                                          |       | (665                                  | )          | 24,947 |   | 7,851 |   | — |   | 32,133 |   |
| CASH AND CASH EQUIVALENTS, beginning of reporting period                           |       | 746                                   |       | 8,603 |   | 350 |   | — |   | 9,699 |   |
| CASH AND CASH EQUIVALENTS, end of reporting period                                 |       | $                                     | 81         |   | $ | 33,550 |   | $ | 8,201 |   | $ | — |   | $ | 41,832 |   |

 

17

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**ITEM 2****.Management’s Discussion and Analysis of Financial Condition and Results ofOperations**

 

                References in this quarterly report on Form 10-Qto “Pacific Energy Partners,” “Partnership,” “we,” “ours,” “us” or like termsrefer to Pacific Energy Partners, L.P. and its subsidiaries.

 

**Forward-LookingStatements**

 

                The information in this quarterly report onForm 10-Q contains forward-looking statements within the meaning ofSection 27A of the Securities Act of 1933, and Section 21E of theSecurities Exchange Act of 1934. These forward-looking statements areidentified as any statements that do not relate strictly to historical orcurrent 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 ofsuch terms or other similar terminology. In particular, statements express orimplied, regarding our future results of operations or our ability to generatesales, income or cash flow or to make distributions to unitholders are forward-lookingstatements. Forward-looking statements are not guarantees of performance.Such statements are based on management’s current plans, expectations,estimates, assumptions and beliefs concerning future events impacting us andtherefore involve risks and uncertainties. Future actions, conditions or eventsand future 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 the forward-lookingstatements in this quarterly report on Form 10-Q are subject to all of therisks and uncertainties, many of which are beyond our control, incident togathering, transporting, storing, and distributing crude oil and other relatedproducts and buying, gathering, blending and selling crude oil. For a moredetailed description of these and other factors that may affect the forward-lookingstatements, please read “Risk Factors” contained in our annual report onForm 10-K for the year ended December 31, 2004, as well as otherfilings with the SEC. The risk factors could cause our actual results to differmaterially from those contained in any forward-looking statement. Youshould not put undue reliance on these forward-looking statements. Wedisclaim any obligation to announce publicly the result of any revision to anyof the forward-looking statements to reflect future events ordevelopments.

 

**Introduction**

 

                The followingdiscussion of the financial condition and results of operations of PacificEnergy Partners, L.P. should be read together with the condensed consolidatedfinancial statements and the notes thereto set forth elsewhere in this report.The discussion set forth in this section pertains to our unauditedcondensed consolidated balance sheets, statements of income, statements of cashflows and statement of partners’ capital.

 

                This reporton Form 10-Q should be read in conjunction with our annual report on Form 10-Kfor the year ended December 31, 2004.

 

**Overview**

 

                Weare a publicly traded limited partnership engaged principally in the businessof gathering, transporting, storing and distributing crude oil and relatedproducts in California and the Rocky Mountain region of the U.S. and inAlberta, Canada.  We conduct our businessthrough two regional business segments: the West Coast Business Unit and theRocky Mountain Business Unit. We generate revenue primarily by charging tariff ratesfor transporting crude oil on our pipelines and by leasing storagecapacity.  We also buy, blend and sellcrude oil, activities that are complementary to our pipeline transportationbusiness.

 

***Recent Developments***

 

***                Line63 Crude Oil Release***

 

                OnMarch 23, 2005, a release of approximately 3,400 barrels of crude oil occurredon Line 63 when it was severed as a result of a landslide induced by heavyrainfall in the Pyramid Lake area of Los Angeles County.  Over the period March 2005 throughMarch 2006, we expect to incur an estimated total of $13.5 million for oilcontainment and clean-up of the impacted areas, future monitoring costs,potential third-party claims and penalties, and other costs.  Through March 31, 2005, we had incurred approximately$3.3 million of the total expected oil release costs for work performed throughsuch date.

 

                We have apollution liability insurance policy with a $2.0 million deductible, and theinsurance carrier has, subject to a reservation of certain rights, acknowledgedcoverage of the incident under the policy and has begun processing and payinginvoices related to the clean-up. Although we believe we are entitled, subject to the $2.0 milliondeductible, to recover substantially all of 

 

18

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our clean-up costs and third-party claims associated with the release,there is no absolute assurance that this will be the case.  In the first quarter of 2005, we have accrueda receivable of $11.5 million for insurance receipts that we deem probable. Asnew information becomes available in future periods, our initial estimates ofcosts and recoveries may change.

 

                Accrued costsrelating to the release of $13.5 million, net of accrued insurance receipts of$11.5 million, or $2.0 million, is recorded in “Line 63 oil release costs” inthe accompanying condensed consolidated statements of income.

 

                In addition, weexpect to incur approximately $1.0 million in 2005 for the costs of repairingLine 63.  These costs, which are notcovered by our insurance, will be expensed as incurred during the remainder of2005.

 

On April 18, 2005, we received the necessary approvalsto begin the repair of Line 63, and the first phase of the repair operation wascompleted on April 25, 2005, and Line 63 was returned to operation. During thetime the pipeline was out of service, we transferred significant volumes oflight crude oil, on a temporary basis, from Line 63 to Line 2000, to mitigatethe impact on customers and limit the potential loss of revenue.  We also asked our customers to shift volumesof OCS crude oil from Line 63 to Line 2000.

 

The Partnership has filed an application with theCalifornia Public Utilities Commission to implement a temporary surcharge onits Line 63 tariff rates to recover its costs relating to this release togetherwith other costs incurred or to be incurred as a result of problems caused byrain-induced earth movement and stream erosion.

 

***                Saleof The Anschutz Corporation’s Interest in the Partnership***

 

                OnMarch 3, 2005, The Anschutz Corporation completed the sale of its 36.6%interest in the Partnership to LB Pacific, LP (“LBP”), an entity formed byLehman Brothers Merchant Banking Group (“LBMB”).  The acquisition by LBP (the “LB Acquisition”)included the purchase of  a 100%ownership interest in Pacific Energy GP, Inc. (predecessor of Pacific EnergyGP, LP), which owned (i) a 2% general partner interest in the Partnership andthe incentive distribution rights, and (ii) 10,465,000 subordinated units ofthe Partnership representing a 34.6% limited partner interest.  Immediately prior to the closing of the LBAcquisition, Pacific Energy GP, Inc. was converted to Pacific Energy GP, LLC, aDelaware limited liability company; and immediately after the closing of the LBAcquisition, Pacific Energy GP, LLC was converted to Pacific Energy GP, LP, aDelaware limited partnership (together with its predecessors, the “GeneralPartner”).  The general partner ofPacific Energy GP, LP is Pacific Energy Management LLC, a Delaware limitedliability company (“PEM” or the “Managing General Partner”), which is 100%owned by LBP.Immediately following the closing of the LB Acquisition, our General Partnerdistributed the 10,465,000 subordinated units of the Partnership to LBP.

 

                In connection with theconversion of our General Partner to a limited partnership, our General Partnerceased to have a board of directors, and is now managed by PEM, its generalpartner. PEM has a board of directors (the “Board of Directors” or “Board”)that manages the business and affairs of PEM and, thus, indirectly manages thebusiness and affairs of our General Partner and the Partnership.  The Board of Directors is comprised of elevendirectors, six of whom served on the Board of Directors of our General Partnerprior to the LB Acquisition, together with five new directors appointed by LBP.All of the officers and employees of ourGeneral Partner were transferred to the same positions with PEM, and the Boardestablished the same committees as had been maintained by our General Partnerprior to the LB Acquisition.  PEM alsoadopted our General Partner’s governance guidelines and its compensationstructure and employee benefit plans and policies.

 

                Additionally, on March 21, 2005,an affiliate of First Reserve Corporation acquired a 30% minority interest inLBP from LBMB.  LBMB and its affiliateswill continue to own a 70% controlling interest in LBP.  As a result of this investment in LBP, FirstReserve was entitled to nominate one director to the Board of Directors of PEM.The director nominated by First Reserve, who was one of the five new directorsappointed by LBP, was appointed to the Board on April 6, 2005.

 

                Pursuantto an Ancillary Agreement, LBP and The Anschutz Corporation reimbursed us theamount of $2.4 million for the cost of a consent solicitation to the holders ofour Senior Notes to amend the indenture governing the Senior Notes, and forseverance and other costs incurred in connection with the sale of our GeneralPartner.  The Partnership was required bygenerally accepted accounting principles to record $0.6 million as capitalizeddeferred financing costs and $1.8 million as an expense.  The reimbursements were recorded as a partner’scapital contribution.

 

                OnMarch 3, 2005, in connection with the change in control of the our GeneralPartner, all restricted units outstanding under the Long-Term Incentive Planimmediately vested pursuant to the terms of the grants.  The Partnership issued 99,583 common unitsand recorded a compensation expense of $3.1 million.

 

***BusinessFundamentals***

 

***                PipelineTransportation***

 

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

 

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

 

19

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                The tariff rates we charge on Line 2000 and theLine 63 system are regulated by the California Public Utilities Commission(the “CPUC”). Tariffs on Line 2000 are established based on marketconsiderations, subject to certain contractual limitations. Tariffs onLine 63, which are cost-of-service based tariffs, are based upon the coststo operate and maintain the pipeline, as well as charges for the depreciationof the capital investment in the pipeline and the authorized rate of return.The tariff rates charged on our U.S. Rocky Mountain pipelines are regulated byeither the FERC or the Wyoming Public Service Commission, generally under acost-of-service approach.

 

                On May 1, 2004, we increased the tariff rates on Line2000 by approximately 6%, based on a contractually agreed index of costchanges.  This index is reviewedannually. In April 2005, the CPUC approved an increase of approximately 4.8% inthe tariff rate on Line 2000 effective May 1, 2005. Effective November 1, 2004,we increased the tariff rates on our Line 63 system by 9.5%.  This increase was the first for Line 63 since2001.  These tariff rate increases partiallymitigate the impact of declining throughput.

 

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

 

InMarch 2005, Shell Oil completed the sale of its Bakersfield refinery to FlyingJ, Inc.  We believe we are wellpositioned to benefit from the refinery’s continued operation and we are workingwith Flying J to deliver additional volumes of crude oil to the Bakersfieldrefinery and deliver volumes from the refinery south to the Los Angeles Basin.

 

                In the Rocky Mountains, our pipelines are connectedto Canadian sources of crude oil, and in 2004 we completed the acquisition ofthe Rangeland system, giving us greater access to significant supplies ofCanadian crude oil, including synthetic crude oil, which we believe willreplace any long term U.S. Rocky Mountain production declines and meet growingdemand in the U.S. Rocky Mountain region. It appears in recent months that production in the U.S. Rocky Mountainsmay be increasing with the increased amount of natural gas related drilling,which results in increased volumes of crude oil and condensate.  We believe, however, that the longer termproduction of crude oil will resume its historical decline.

 

***                Storage and Distribution***

 

                We provide storage and distribution services torefineries in the Los Angeles Basin through our Pacific Terminals (“PT”)storage and distribution system. The fundamental items impacting our storageand distribution revenue are the amount of storage capacity we have underlease, the lease rates for that capacity and the length of each lease. Demandfor crude oil storage capacity tends to be more stable over time, and leasesfor crude oil storage capacity are usually long term (more than one year).Demand for storage capacity for other dark products is less stable, and variesdepending on, among other things, refinery production runs and maintenanceactivities. Leases for dark products storage capacity are usually short term(less that one year). One of our business goals is to convert a number of darkproducts tanks to more flexible crude oil service (which can also accommodateother dark products); we currently await permit approvals for one such tankconversion and plan to convert a second tank in 2005.

 

                While PT’s rates are regulated by the CPUC, the CPUChas authorized PT to establish its rates based on market conditions throughnegotiated contracts.

 

***                Pipeline Buy/Sell Transportation***

 

                Throughput on our Rangeland system, which wasacquired in the second quarter of 2004, varies with many of the same factorsdescribed in “Pipeline Transportation” above. In addition, following completion of our Edmonton initiation station,scheduled for completion in the fourth quarter of 2005, throughput will varywith our success in attracting new supplies of synthetic crude oil to oursystem.

 

We are making significantchanges to the revenue-generating capability of the Rangeland system by(i) combining and fully integrating all of our Canadian and U.S. Rocky Mountainpipeline assets under common management, (ii) establishing connections withother pipelines, thereby expanding the throughput capacity of the Rangelandsystem, and (iii) constructing a pump station and receiving terminal inEdmonton, Alberta.  The development ofthe new receiving terminal and pump station, which will provide access tosynthetic and other types of Canadian crude oil, continues to progress.  Construction of this facility, together withadditional tanks along the pipeline corridor, is expected to be complete by thefourth quarter of 2005.

 

20

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                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 the inlet tothe pipeline without repurchasing product from RMC.

 

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

 

                Effective December 1, 2004, we increased the locationdifferentials on the Rangeland pipeline by an average of 10.8%.

 

***Gathering and Blending***

 

                Through our Pacific Marketing and Transportation (“PMT”)subsidiary, we purchase, gather, blend and resell crude oil in California’s SanJoaquin Valley. Our PMT gathering and blending system is a proprietaryintrastate operation that is not regulated by the CPUC or the FERC. It iscomplementary to our West Coast pipeline transportation business. The gatheringnetwork effectively extends our pipeline network to capture supplies of crudeoil for transportation on our trunk pipelines to Los Angeles that might nototherwise be shipped through our pipelines.

 

                The contribution of our PMT gathering and blendingoperations is, for several reasons, a variable part of our income. First, itvaries with the price differential between the cost of the varying grades ofcrude oil and natural gasoline that PMT buys for use in its blendingoperations, and the price of the blended crude oil it sells. Costs and salesprices are generally impacted by crude oil prices, as well as by local supplyand demand forces, including regulations affecting refined productspecifications. Second, it varies with the price differential between crude oilpurchased on one price basis and sold on a different price basis. Finally, itvaries with the volumes gathered and blended. We seek to control thesevariations through our risk management policy, which provides specificguidelines for our crude oil marketing and hedging activities and requiresoversight by our senior management.

 

                Our blending margins are a function of the cost ofthe heavy and light crude oils and natural gasoline that we buy and blend,relative to the price of the blended crude oil we sell.  Blending margins exceeded their historicalaverages in the first eight months of 2004; however, since September 2004,blending margins have been below their historical averages.  Since September 2004, foreign imports ofcrude oil into the Los Angeles Basin have been highly discounted relative toWest Texas Intermediate (“WTI”) prices, which reduced demand for and prices oflocal California crude oil, including crude oil gathered and blended by us inthe San Joaquin Valley. As the demand for and price of our blended crude oilhas fallen, we have taken action to cancel certain purchase contracts and toreduce the volume we gather, blend and sell. In addition, margins on one particular contract declined as the differencebetween purchases made on a WTI price basis and sales made on a West Coastprice basis deviated from historical norms over the period from September 2004through March 2005. This contract expired on March 31, 2005.

 

***                Acquisitions and New Projects***

 

                We intend to continue to pursue acquisitions and newprojects for development of additional midstream assets, including pipeline,storage and terminal facilities. We also intend to expand, principally byacquisition, into the refined product and natural gas storage andtransportation businesses.  We expect theacquisitions and new projects to be accretive to our cash flow and complementour existing businesses. We expect to fund acquisitions and new projects with acombination of debt and additional Partnership units, including common units.We expect to maintain a debt to total capitalization ratio of approximately 50%over time.

 

***Operating Expenses***

 

                A substantial portion of the operating expenses weincur, including the cost of field and support personnel, maintenance, controlsystems, telecommunications, rights-of-way and insurance, varies little withchanges in throughput. Certain of our costs do, however, vary with throughput,the most material being the cost of power used to run pump stations along ourpipelines. Major maintenance costs can also vary depending on a particularasset’s age and/or regulatory requirements, such as mandatory inspections atdefined intervals. Unanticipated costs can include the costs of cleanup of anyrelease of oil to the extent not covered by insurance.

 

***Employees***

 

                We do not have any employees, except in Canada.  Our Managing General Partner providesemployees to conduct our U.S. operations. We and our Managing General Partner collectively employ approximately315 individuals who directly support our 

 

21

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operations. We consideremployee relations to be good. None of these employees are subject to acollective bargaining agreement. Our Managing General Partner does not conductany business other than with respect to the Partnership. All expenses incurredby our Managing General Partner are charged to us. Please read “Note 3 - Related Party Transactions” in the footnotes tothe condensed consolidated financial statement.

 

***                Impact of Foreign Exchange Rates***

 

                Assets and liabilities of our Canadian subsidiariesare translated to U.S. dollars using the applicable exchange rate as of the endof a reporting period. Revenues, expenses and cash flow are translated usingthe average exchange rate during the reporting period. The reported cash flowof our Canadian operations is based on the U.S. dollar equivalent of suchamounts measured in Canadian dollars. The results of our Canadian operationsand distributions from our Canadian subsidiaries to the Partnership may vary inU.S. dollar terms based on fluctuations in currency exchange rates irrespectiveof our Canadian subsidiaries’ underlying operating results.  In addition, the amount of monies werepatriate from Canada will vary with fluctuations in currency exchange ratesand may impact the cash available for distribution to our unitholders.

 

**Critical Accounting Policies andEstimates**

 

                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 and expensesduring the reporting period. We routinely make estimates and judgments aboutthe carrying value of our assets and liabilities that are not readily apparentfrom other sources. Such estimates and judgments are evaluated and modified asnecessary on an ongoing basis. We believe that of our significant accountingpolicies (see “Note 1, Significant Accounting Policies,” to our consolidatedfinancial statements in our annual report on Form 10-K for the year endedDecember 31, 2004) and estimates, the followingmay involve 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. Thevaluation of the fair value of the assets involves a number of judgments andestimates. In our major acquisitions to date, we have engaged an outsidevaluation firm to provide us with an appraisal report, which we utilized indetermining the purchase price allocation. The allocation of the purchase priceto different asset classes impacts the depreciation expense we subsequentlyrecord. The principal assets we have acquired to date are property, pipelines,storage tanks and equipment.

 

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

 

                                                •              Weaccrue an estimate of the undiscounted costs of environmental remediation forwork at identified sites where an assessment has indicated it is probable thatcleanup costs are or will be required and may be reasonably estimated. 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 to estimate the amountof any probable recoveries, including insurance recoveries.  In addition, generally accepted accountingprinciples require us to establish liabilities for the costs of assetretirement obligations when the retirement date is determinable. We will recordsuch liabilities only when such date is determinable.

 

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

 

                                                •              Ourinventory of crude oil for our PMT gathering and blending operations, ourCanadian operations and any inventory earned through our tariffs for thetransportation of crude oil in our common carrier pipelines is carried on ourbooks at the lower of cost or market value, unless it is hedged, in which caseit is carried at market. On any unhedged portion, we are exposed to the potentialfor a write-down to market value.

 

22

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**Results of Operations**

 

***Three Months Ended March 31, 2005 Compared to ThreeMonths Ended March 31, 2004***

 

***Summary***

 

Netincome for the three months ended March 31, 2005 was $3.4 million, or $0.17 perdiluted limited partner unit compared, to $8.1 million, or $0.31 per dilutedlimited partner unit, for the three months ended March 31, 2004.

 

                Netincome for the three months ended March 31, 2005 includes the operations of theRangeland system after its acquisition on May 11, 2004 and its expansion byacquisition of the MAPL pipeline on June 30, 2004.

 

*               *Internally, in our analysis of operating results, we consider the impactof unusual items that we believe affect comparability between periods.  We also believe that providing a discussionand analysis of our results that is comparable year over year, provides a moreaccurate and thorough analysis of our results of operations.  We have also provided a reconciliation of netincome to the results of our operations, excluding those unusual items, in thetable below.  Following is a discussionof each of the unusual items that impacted the results of our operations.

 

*                OilRelease on Line 63.*  On March 23, 2005, a release ofapproximately 3,400 barrels of crude oil occurred on PPS’s Line 63 as a resultof a landslide induced by heavy rainfall in northern Los Angeles County.  As discussed in “RecentDevelopments” above, for the three months ended March 31, 2005, we accrued$13.5 million to remediate the area, together with related costs.  Additionally, we have recorded $11.5 in receivables for amounts we believe to be recoverable under ourinsurance policy.  The net expenserecorded was $2.0 million.  Thediscussion in “Recent Developments” describes the nature of these estimates andthe potential for these estimates to increase or decrease in future periods.

 

*Accelerated long-term incentiveplan compensation expense. *On March 3, 2005, in connection with the change in control of our GeneralPartner, all restricted units outstanding under the Long-term Incentive Planimmediately vested.  As a result, for thethree months ended March 31, 2005, we recognized $3.1 million in compensationexpense.

 

*Transaction costs.*  Pursuant to an AncillaryAgreement, LBP and The Anschutz Corporation reimbursed us $2.4 million for thecost of a consent solicitation to the holders of our Senior Notes to amend theindenture governing the Senior Notes and for severance and other costs incurredin connection with the sale of our General Partner. The Partnership was required by generally accepted accounting principlesto record $0.6 million as capitalized deferred financing costs and $1.8 millionas an expense. The reimbursements wererecorded as a partner’s capital contribution.

 

                The following table is reconciliation of net incometo the results of our operations, excluding the items mentioned above:

 
| ** **                                                | ** ** | **Three Months Ended March 31,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-----------------------------------------------------------|------------|----------------------------------|------------|------------|------------|------------|------------|
| ** **                                                | ** ** | **2005**                         | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                                | ** ** | **(In thousands)**               | ** ** | ** ** | ** ** |
| Net income                                                |       | $                                | 3,421      |       | $          | 8,077      |       | $ | (4,656 | ) | -58 | % |
| Add: Line 63 oil release costs                            |       | 2,000                            |       | —     |       | 2,000      |       | — |   |
| Accelerated long-term incentive plan compensation expense |       | 3,115                            |       | —     |       | 3,115      |       | — |   |
| Transaction costs                                         |       | 1,807                            |       | —     |       | 1,807      |       | — |   |
|                                                      |       | $                                | 10,343     |       | $          | 8,077      |       | $ | 2,266 |   | 28 | % |
|                                                      |       |                             |       |       |       |       |       |   |   |
| Diluted weighted average limited partner units            |       | 29,673                           |       | 25,149     |       | 4,524      |       | 18 | % |

 

                The improvement in the results of operations,excluding the effect of the unusual items mentioned above, reflects the benefitof (i) higher pipeline transportation revenues on the West Coast and RockyMountain pipelines, (ii) the operations of the Rangeland system acquiredin May 2004, and (iii) cost savings for Pacific Terminals.  These increases were partially offset bysignificantly lower gathering and blending margins, which were below average inthe three months ended March 31, 2005 and above average in the three monthsended March 31, 2004.  There were 29.7million weighted average limited partner units outstanding in the three monthsended March 31, 2005, approximately 18% more limited partner units than the25.0 million weighted average units outstanding in the three months ended March31, 2004, due to the sale of additional common units to partially fund theacquisition of the Rangeland system, including the MAPL pipeline.

 

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**                *Segment Information***

 

                Thefollowing is a discussion of segment operating income.  Segment operating income does not includegeneral and administrative expenses, accelerated long-term incentivecompensation plan expense and transaction costs as these items are notallocated to the West Coast and Rocky Mountain business units.

 

| ** **                    | ** ** | **Three Months Ended March 31,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-------------------------------|------------|----------------------------------|------------|------------|------------|------------|------------|
| **West  Coast**               | ** ** | **2005**                         | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                    | ** ** | **(In thousands)**               | ** ** | ** ** | ** ** |
|                          |       |                             |       |       |       |       |       |   |   |
| Operating income              |       | $                                | 9,743      |       | $          | 12,255     |       | $ | (2,512 | ) | -20 | % |
| Add: Line 63 oil release cost |       | 2,000                            |       | —     |       | 2,000      |       | — |   |
|                          |       | $                                | 11,743     |       | $          | 12,255     |       | $ | (512 | ) | -4 | % |
| Operating data:               |       |                             |       |       |       |       |       |   |   |
| Pipeline throughput (bpd)     |       | 138.5                            |       | 133.6      |       | 4.9        |       | 4 | % |

 

                For the three months ended March 31, 2005, operatingincome excluding the effect of the net accrual of $2.0 million for the Line 63oil release costs, was $11.7 million, compared to $12.3 million for the threemonths ended March 31, 2004.   West Coastpipeline volumes for the three months ended March 31, 2005 were approximately4% higher than the first quarter of 2004. During the first quarter of 2004,volumes were impacted by a significant amount of Los Angeles area refinerymaintenance, resulting in lower volumes moving south to Los Angeles. For thethree months ended March 2005, the Partnership also experienced incrementalrevenue from increased tariffs on Line 63 and Line 2000 implemented in 2004.During the three months ended March 2005, Pacific Terminals also experiencedincreased storage revenues due to higher rates of tank utilization and costsavings in vapor recovery costs due to the installation of vaportreating equipment that was installed at the end of 2004. These increases inoperating income were offset by additional costs incurred to address earth movementand stream erosion problems at other locations along both Line 63 and Line2000, caused by heavy rainfall. PMTgathering and blending margins were also lower in the first quarter of 2005 dueto pricing pressures from steeply discounted crude oil imports and theinterruption of a scheduled sale due to the Line 63 crude oil release.  We consider this gathering and blendingactivity to be complementary to our pipeline transportation operations.

 

| ** **                 | ** ** | **Three Months ended March 31,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|----------------------------|------------|----------------------------------|------------|------------|------------|------------|------------|
| **Rocky Mountains**        | ** ** | **2005**                         | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                 | ** ** | **(In thousands)**               | ** ** | ** ** | ** ** |
|                       |       |                             |       |       |       |       |       |   |   |
| Operating income           |       | $                                | 9,578      |       | $          | 3,641      |       | $ | 5,937 |   | 163 | % |
| Operating data (bpd):      |       |                             |       |       |       |       |       |   |   |
| Rangeland pipeline system: |       |                             |       |       |       |       |       |   |   |
| Sundre—North          |       | 21.4                             |       | —     |       |       |       | — |   |
| Sundre—South          |       | 48.2                             |       | —     |       |       |       | — |   |
| Western Corridor system    |       | 22.5                             |       | 16.0       |       | 6.5        |       | 41 | % |
| Salt Lake City Core system |       | 108.7                            |       | 105.9      |       | 2.8        |       | 3 | % |
| Frontier pipeline          |       | 38.3                             |       | 43.9       |       | (5.6       | )          | -13 | % |
|                            |            |                                  |            |            |            |            |            |  |  |  |  |  |

 

                For the three months ended March 31, 2005, operatingincome was $9.6 million compared, to $3.6 million for the three months endedMarch 31, 2004.   The increase includedthe results of the Rangeland system which was acquired in the second quarter of2004.  In addition, increased marketshare for pipeline shipments of crude oil to Billings, Montana and increaseddemand by the Salt Lake City, Utah, refineries, helped drive higher pipelinevolumes on the U.S. Rocky Mountain systems other than Frontier pipeline.  Frontier pipeline volumes in 2005 wereaffected by a shortage of synthetic crude oil supply caused by a fire at aSuncor Energy, Inc. facility in December 2004. Shippers have now replaced thesevolumes with other types of crude oil and volumes are expected to return tonormal levels in the second quarter of this year.

 

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***Statement ofIncome—Discussion and Analysis***

 

| ** **                               | ** ** | **Three months ended March 31,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------------------------------------|------------|----------------------------------|------------|------------|------------|------------|------------|
| **Revenues**                             | ** ** | **2005**                         | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                               | ** ** | **(In thousands)**               | ** ** | ** ** | ** ** |
|                                     |       |                             |       |       |       |       |       |   |   |
| Pipeline transportation revenue          |       | $                                | 28,037     |       | $          | 24,727     |       | $ | 3,310 |   | 13 | % |
| Storage and distribution revenue         |       | 10,322                           |       | 10,123     |       | 199        |       | 2 | % |
| Pipeline buy/sell transportation revenue |       | 9,106                            |       | —     |       | 9,106      |       | — |   |
| Crude oil sales, net of purchases:       |       |                             |       |       |       |       |       |   |   |
| Crude oil sales                          |       | 116,173                          |       | 85,927     |       | 30,246     |       | 35 | % |
| Crude oil purchases                      |       | (114,391                         | )          | (81,115    | )          | 33,276     |       | 41 | % |
| Crude oil sales, net of purchases        |       | 1,782                            |       | 4,812      |       | (3,030     | )          | -63 | % |
|                                     |       |                             |       |       |       |       |       |   |   |
| Net revenue                              |       | $                                | 49,247     |       | $          | 39,662     |       | $ | 9,585 |   | 24 | % |

 

                Increasedpipeline transportation revenues were realized by both our West Coast and U.S. Rocky Mountain pipelines. Highervolumes and increased tariff rates increased West Coast revenues. Volumes onthe U.S. Rocky Mountain pipelines were higher due to increased demand byrefineries in Billings, Montana, Casper, Wyoming and Salt Lake City, Utah arearefineries.

 

                Storage and distribution revenues on the PacificTerminals storage and distribution system were marginally higher compared tothe same period in 2004 due to an increase in storage rates per barrel.

 

                Pipeline buy/sell transportation revenues of $9.1million reflect the revenues of the Rangeland system, which was acquired onMay 11, 2004.

 

                The decrease in net crude oil sales for the threemonths ended March 31, 2005 was primarily the result of lower margin blendingactivities in our West Coast operations, particularly due to competitivepricing pressures as a result of cheaper foreign crude entering the West Coastmarkets. Higher oil prices increased gross sales and purchases values. Weconsider this gathering and blending activity to be complementary to ourpipeline transportation operations.

 

| ** **                                                | ** ** | **Three Months ended March  31,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-----------------------------------------------------------|------------|----------------------------------------|------------|------------|------------|------------|------------|
| **Expenses**                                              | ** ** | **2005**                               | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                                                | ** ** | **(In thousands)**                     | ** ** | ** ** | ** ** |
|                                                      |       |                                   |       |       |       |       |       |   |   |
| Operating expenses                                        |       | $                                      | 21,754     |       | $          | 18,917     |       | $ | 2,837 |   | 15 | % |
| Line 63 oil release costs                                 |       | 2,000                                  |       | —     |       | 2,000      |       | — |   |
| General and administrative expense                        |       | 5,172                                  |       | 3,854      |       | 1,318      |       | 34 | % |
| Transaction costs                                         |       | 1,807                                  |       | —     |       | 1,807      |       | — |   |
| Accelerated long-term incentive plan compensation expense |       | 3,115                                  |       | —     |       | 3,115      |       | — |   |
| Depreciation and amortization                             |       | 6,529                                  |       | 5,242      |       | 1,287      |       | 25 | % |
|                                                      |       | $                                      | 40,377     |       | $          | 28,013     |       | $ | 12,364 |   | 44 | % |

 

                The increase in operating expense wasrelated primarily to the acquisition of the Rangeland system on May 11,2004.  Operating expenses in the West Coastwere also higher as a result of unscheduled repairs and maintenance andpipeline relocation expenses on Line 2000 and Line 63 resulting from earthmovements and creek washouts caused by recent heavy rains.

 

*               *TheLine 63 oil release costs are discussed in “Recent Developments” above.

 

                The increase in general and administrative expensewas associated with the integration of the Rangeland acquisition, certainexpensed costs for the Pier 400 project and costs for compliance with theSarbanes-Oxley Act.  These items were notapplicable in the corresponding period of 2004.

 

                Transaction costs are discussed in “RecentDevelopments” above.

 

                OnMarch 3, 2005, in connection with the change in control of the General Partner,all restricted units outstanding under the Long-term Incentive Plan immediatelyvested.  For the three months ended March31, 2005, we recognized $3.1 million in compensation expense as a result.

 

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                The increase in depreciation and amortizationincludes $1.5 million for depreciation on the Rangeland system.  These increases were partly offset by lowerdepreciation on other assets reflecting assets that have now been fullydepreciated.

 

| ** **                      | ** ** | **Three Months ended March 31,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|---------------------------------|------------|---------------------------------------|------------|------------|------------|------------|------------|
| **Other  Income and Expense**   | ** ** | **2005**                              | ** ** | **2004**   | ** ** | **Change** | ** ** | **Percent** | ** ** |
| ** **                      | ** ** | **(In thousands)**                    | ** ** | ** ** | ** ** |
|                            |       |                                  |       |       |       |       |       |   |   |
| Share of net income of Frontier |       | $                                     | 357        |       | $          | 393        |       | $ | (36 | ) | -9 | % |
|                            |       |                                  |       |       |       |       |       |   |   |
| Interest expense                |       | $                                     | 5,598      |       | $          | 4,126      |       | $ | 1,472 |   | 35 | % |
|                            |       |                                  |       |       |       |       |       |   |   |
| Other income                    |       | $                                     | 353        |       | $          | 161        |       | $ | 192 |   | 119 | % |
|                            |       |                                  |       |       |       |       |       |   |   |
| Income tax expense              |       | $                                     | 561        |       | $          | —     |       | $ | 561 |   | — |   |

 

                Thedecrease in our share of Frontier’s net income was mainly attributable todecreased pipeline volumes as a result of a shortage of synthetic crude supply caused by a fireat a Suncor Energy, Inc. facility in December 2004. Shippers have now replaced thesevolumes with other types of crude oil and volumes are expected to return tonormal levels in the second quarter of the year.

 

                The increase in interest expense was due to borrowingsincurred to partially fund the acquisition of the Rangeland system. Ourweighted average borrowings during the three months ended March 31, 2005were $358 million compared to $304 million in the correspondingperiod in 2004. In addition, floating interest rates were higher in 2005, at aweighted average interest rate of 6.3% for the period ended March 31, 2005compared to a weighted average interest rate of 5.5% for the correspondingperiod in 2004.

 

                Other income of $0.4 million for the period endedMarch 31, 2005 was $0.2 million greater than the corresponding period in 2004due to increased interest income and other items.

 

                The income tax expense for the three months endedMarch 31, 2005 relates to the income of the Rangeland system acquired in thesecond quarter of 2004.  Our Canadiansubsidiaries are taxable entities, and certain kinds of repatriation of fundsinto the U.S. are subject to Canadian withholding tax.  Additionally, we recorded deferred tax liabilitiesin connection with the purchase of our Canadian subsidiaries, which we recoverperiodically in earnings.

 

**Liquidity and Capital Resources**

 

                We believe that cash generated from operations,together with our cash balance and our unutilized borrowing capacity, will besufficient to meet our planned distributions, our working capital requirements,our remaining costs for the Line 63 oil release remediation and related costs,and our anticipated sustaining capital expenditures in the next threeyears.  We expect to extend or replaceour revolving credit facilities, which mature in mid-2007.

 

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

 

                We have filed an application with the CPUC to sellsurplus Pacific Terminals properties, which we believe are worth approximately$10 million.

 

                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 transported through our pipelines and the capacity leased in ourstorage tanks as described in “Overview” above. Our operating performance isalso affected by prevailing economic conditions in the crude oil industry andfinancial, business and other factors, some of which are beyond our control,which could significantly impact future results.

 

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

 

| ** **                                          | ** ** | **Three Months Ended March 31,** | ** ** | ** ** | ** ** |
|-----------------------------------------------------|------------|----------------------------------|------------|------------|------------|
| ** **                                          | ** ** | **2005**                         | ** ** | **2004**   | ** ** | **Change** | ** ** |
| ** **                                          | ** ** | **(In thousands)**               | ** ** |
| ** **                                          | ** ** | **(unaudited)**                  | ** ** |
|                                                |       |                             |       |       |       |   |   |
| Net cash provided by operating activities           |       | $                                | 15,932     |       | $          | 13,182 |   | $ | 2,750 |   |
| Net cash used in investing activities               |       | (4,260                           | )          | (12,333    | )          | 8,073 |   |
| Net cash provided by (used in) financing activities |       | (12,958                          | )          | 31,284     |       | (44,242 | ) |
|                                                     |            |                                  |            |            |            |  |  |  |  |  |

*** ***

***                Netcash provided by operating activities***

 

                The increase in the net cashfrom operating activities of $2.8 million, or 21%, was the result of the Rangelandsystem’s contribution to operating income, together with a decrease in cashused for working capital, partially offset by the cash portion of theaccelerated vesting of units under the Long-term Incentive Plan and transactioncosts.

 

                Net cash from operatingactivities for the three months ended March 31, 2005 was increased byapproximately $4.5 million by working capital changes.  Increases in accounts payable and otheraccrued liabilities and accrued crude oil purchases more than offset an increasein crude oil inventory and crude oil sales receivables.  There was a significant increase in ourinventory of crude oil for PMT, reflecting the deferral of a sale due to thedowntime on Line 63 caused by the oil release and due to the timing of othersales.  The deferred delivery was made inApril 2005 and other sales are occurring in the second quarter to reduce theinventory to a more normal level.  Thesales pricing was either fixed or inventory balances were hedged at the end ofMarch to eliminate any significant price risk.

 

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

 

                Capital expenditures were $4.4million in the first quarter of 2005, of which $0.2 million related tosustaining capital projects, $2.3 million related to transition projects, $1.2million related to expansion and $0.7 million was for our continued developmentof the Pier 400 Project. Capital expenditures for the three months ended March31, 2004 were $2.4 million of which $0.5 million related to sustainingcapital projects, $0.1 million related to the transition of the PacificTerminals storage and distribution system, and $1.8 million related toexpansion.  The 2004 period also includes$9.9 million related to a deposit paid and acquisition costs incurred for theRangeland system and MAPL assets.

 

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

 

                Distributions of $15.1 millionwere made to the limited partners and the General Partner during the periodended March 31, 2005.  Additionally, TACand LBP contributed $2.4 million to reimburse us for certain costs incurred inconnection with the LB Acquisition. The amount of cash provided by financingactivities in 2004, $31.3 million, includes net proceeds of $116.7 million froman equity offering completed on March 30, 2004, which was used to fund aportion of the acquisition of the Rangeland system, net repayment of$73.0 million under our revolving credit facility, and $12.4 million indistributions to the limited and general partner interests.

 

***Capital Requirements***

 

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

 
| • | sustaining  capital expenditures to replace partially or fully depreciated assets in  order to maintain the existing operating capacity or efficiency of our assets  and extend their useful lives;                                                                                                                                                                                |
|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                                                                                                                               |
| • | transitional  capital expenditures to integrate acquired assets into our existing  operations; and                                                                                                                                                                                                                                                                                 |
|   |                                                                                                                                                                                                                                                                                                                                                                               |
| • | expansion  capital expenditures to expand or increase the efficiency of the existing  operating capacity of our assets, whether through construction or  acquisition, such as placing new storage tanks in service to increase our  storage capabilities and revenue, and adding new pump stations or pipeline  connections to increase our transportation throughput and revenue. |

 

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                We have forecasted total capitalexpenditures for our existing operations of $34.3 million for the remainder of2005, including $3.1 million for the Pier 400 Project, $20.2 millionfor expansion projects, $7.7 million relating to the transition of theRangeland system, $1.4 million for other transition capital projects, and$1.9 million for sustaining capital projects.

 

***                Pier 400***

 

                In February 2004, we completed an initialfeasibility study for the development of a deepwater petroleum import terminalat Pier 400 and Terminal Island in the Port of Los Angeles (“POLA”) tohandle marine receipts of crude oil and refinery feedstocks. We are developingthe Pier 400 terminal to participate in the marine import business, whichis growing as a result of a decline in imports from Alaska and the localproduction decline.  The PacificTerminals storage and distribution assets also benefit by the increase in themarine import business.

 

We initiated theenvironmental review and permitting for the Pier 400 project in June 2004 andexpect to have the permits necessary for construction to begin by the secondquarter of 2006.  We entered into aproject development agreement with two subsidiaries of Valero EnergyCorporation (“Valero”) that defines the facilities that we are to construct inthe POLA.  We and Valero have also signeda terminaling services agreement with a 30-year, 50,000 bpd volume commitmentfrom Valero to support the terminal. These agreements are subject to the satisfaction of various conditions.

 

                If the Pier 400 terminal receives the necessarygovernmental approvals and is successfully developed, a deepwater berth, highcapacity transfer infrastructure and storage tanks will be constructed atPier 400 and Terminal Island in the POLA, and a pipeline distributionsystem will be constructed to connect the terminal’s storage tanks to Valero’sWilmington refinery and to our customers’ facilities in the Los Angeles Basinthrough our Pacific Terminals storage and distribution system. We wouldconstruct the transfer infrastructure, including a large diameter pipelinesystem for receiving bulk petroleum liquids from marine vessels, and thestorage tanks.

 

                Final construction of the Pier 400 project is subjectto the completion of a land lease agreement with the POLA, receipt ofenvironmental and other approval, securing additional customer commitments,updating engineering and project cost estimates, ongoing feasibilityevaluation, and financing.  A finaldecision to proceed is expected to be made in the first quarter of 2006. Weexpect construction of the Pier 400 terminal to be completed and placed inservice in 2007.

 

                We have capitalized approximately $11.2 million onthe Pier 400 project through March 31, 2005, including $0.7 million for thethree months ended March 31, 2005.  Theseexpenditures include $6.3 million for emission reduction credits, an asset thatis re-saleable if the project does not proceed. We anticipate funding pre-construction costs through early-2006 from ourrevolving credit facility.  Constructionof the Pier 400 terminal is expected to be financed through a combinationof debt and proceeds from the issuance of additional partnership units,including common units.

 

***Debt Obligations***

 

                At March 31, 2005, our debt obligations include:(i) $52.0 million on our senior secured U.S. revolving creditfacility, (ii) Cdn$65.0 million (U.S.$53.7 million) on oursenior secured Canadian revolving credit facility,(iii) $246.9 million on our 71/8% Senior Notes, due June 2014, and(iv) Cdn$4.5 million (U.S.$3.7 million) payable to the seller ofthe MAPL assets. For further discussion of these debt obligations see “Note4—Long-term Debt” to the accompanying condensed consolidated financialstatements.

 

                As of March 31, 2005, $87 million of undrawn creditwas available under the senior secured U.S. revolving credit facility and  Cdn$31 million of undrawn credit wasavailable under the senior secured Canadian revolving credit facility.  With the consent of the administrative agentunder the U.S. revolving credit facility, we can increase credit availabilityunder the U.S. credit facility by up to an additional $62 million, based uponpro-forma EBITDA from future acquisitions.

 

**Off-Balance Sheet Arrangements**

 

                The Partnership has no off-balancesheet arrangements.

 

**Accounting Pronouncements**

 

                In December 2004, the FinancialAccounting Standards Board (“FASB”) issued Statement of Financial AccountingStandards No. 123 (revised December 2004), *Share-Based Payment (SFAS123R)*.  This Statement is arevision 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 effective for the Partnership asof the beginning of the first annual reporting period that begins after June15, 2005.  The Partnership has not yetdetermined the impact of the adoption of SFAS 123R on the Partnership’sconsolidated financial statements.

 

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                On March 30, 2005 the FASB issued FASB InterpretationNo. 47, **Accountingfor Conditional Asset Retirement Obligations****(FIN 47)**,to clarify the term **conditional asset retirement obligation**as that term is used in FASB Statement No. 143, **Accounting for Asset RetirementObligations**. The Interpretation also clarifies when an entityhas sufficient information to reasonably estimate the fair value of an assetretirement obligation. FIN 47 is effective for the Partnership no later thanthe end of fiscal years ending after December 15, 2005.  The Partnership is in the process ofdetermining the impact of FIN 47 on its financial statements.

 

**ITEM 3****.Quantitative and Qualitative Disclosures About Market Risk**

 

                Market risk is the risk of lossarising from adverse changes in market rates and prices. The principal marketrisks to which we are exposed are interest rate risk and crude oil price risk.Debt we incur under our credit facilities bears variable interest at either theapplicable base or prime rate, a rate based on LIBOR or a rate based onCanadian Bankers’ Acceptances. We have used and will continue to use from timeto time derivative instruments to hedge our exposure to variable interestrates.  In addition, we have entered into swap agreements toconvert a portion of our fixed rate Senior Notes into floating rate debt basedon LIBOR.

 

                We use, on a limited basis,certain derivative instruments (principally futures and options) to hedge ourexposure to market price volatility related to our inventory or future sales ofcrude oil. We do not enter into speculative derivative activities of any kind.The fair market values of derivative instruments are included in “Other Assets,net” in the accompanying consolidated balance sheets. In our PMT operations wepurchase crude oil for subsequent blending, transportation and resale primarilyin the Los Angeles Basin. Changes in the fair value of our derivativeinstruments related to crude oil inventory are recognized in net income. Forthe three months ended March 31, 2005 and 2004, “crude oil sales, net ofpurchases” were net of $1.0 million and $0.2 million in losses,respectively, reflecting changes in the fair value of PMT’s derivativeinstruments for its marketing activities. Losseson derivatives were generally offset by gains in physical crude oil inventorypositions. In addition, changes in the fair value of our derivative instrumentsrelated to the future sale of crude oil that qualify as hedges for accountingpurposes are deferred and reflected in “accumulated other comprehensive income,”a component of partners’ capital, until the related revenue is recognized inthe consolidated statements of income. As of March 31, 2005, $1.3 millionrelating to the changes in the fair value of derivative instruments wasincluded in “accumulated other comprehensive income.”

 

                In connection with the issuance of the Senior Notes,we entered into interest rate swap agreements with an aggregate notionalprincipal amount of $80.0 million to receive interest at a fixed rate of 71/8% and to pay interest at an averagevariable rate of six month LIBOR plus 1.6681% (set in advance or in arrearsdepending on the swap transaction). The interest rate swaps matureJune 15, 2014 and are callable at the same dates and terms as the SeniorNotes. We designated these swaps as a hedge of the change in the Senior Notesfair value attributable to changes in the six month LIBOR interest rate.Changes in fair values of the interest rate swaps are recorded into earningseach period. Similarly, changes in the fair value of the underlying$80.0 million of Senior Notes, which are expected to be offsetting tochanges in the fair value of the interest swaps, are recorded into earningseach period.  At March 31, 2005 werecorded an increase of $1.1 million in the fair value of interest rate swapswith an equal offsetting entry to the $80.0 million of Senior Notes. As ofMarch 31, 2005, we measured the hedge effectiveness of this interest rate swapand noted that no gain or loss from ineffectiveness was required to be recognized.

 

                We are subject to risksresulting from interest rate fluctuations as the interest cost on our creditfacilities and the $80 million interest swap on the Senior Notes are based onvariable rates. If the LIBOR or Canadian Bankers’ Acceptance discount rateswere to increase 1.0% for the remainder of 2005 as compared to the rate atDecember 31, 2004, our interest expense for the remainder of 2005 wouldincrease $1.4 million based on our outstanding debt at March 31, 2005.

 

**Fair Value of Financial Instruments**

 

                The carrying amount and fairvalues of financial instruments are as follows:

 

| ** **                     | ** ** | **March 31,**      | ** ** | **December 31,** | ** ** |
|--------------------------------|------------|--------------------|------------|------------------|------------|
| ** **                     | ** ** | **2005**           | ** ** | **2004**         | ** ** |
| ** **                     | ** ** | **Carrying**       | ** ** | **Fair**         | ** ** | **Carrying** | ** ** | **Fair** | ** ** |
| ** **                     | ** ** | **Value**          | ** ** | **Value**        | ** ** | **Value** | ** ** | **Value** | ** ** |
| ** **                     | ** ** | **(in thousands)** | ** ** |
|                           |       |               |       |             |       |   |   |   |   |
| Crude oil hedging futures      |       | $                  | 1,410      |             | $          | 1,410 |   | $ | 400 |   | $ | 400 |   |
| Fair value interest rate swaps |       | 1,063              |       | 1,063            |       | 2,693 |   | 2,693 |   |
| Long-term debt                 |       | 356,369            |       | 366,020          |       | 357,163 |   | 373,265 |   |
|                                |            |                    |            |                  |            |  |  |  |  |  |  |  |  |

 

As of March 31, 2005 and December 31, 2004, thecarrying amounts of items comprising current assets and current liabilitiesapproximate fair value due to the short-term maturities of these instruments.The carrying amounts of the revolving credit facilities 

 

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approximate fair value primarily because the interestrates fluctuate with prevailing market rates. The interest rate on the Senior Notes is fixed and the fair value isdetermined from a broker’s price quote at March 31, 2005 and December 31, 2004.

                The carrying amount of derivative financial instrumentsrepresents the fair value as these instruments are recorded on the balancesheet at their fair value under SFAS 133. The Partnership’s fair values ofcrude oil hedging futures are based on****Reuters quotedmarket prices on the NYMEX.  Interestrate swaps’ fair values are based on the prevailing market price at which thepositions could be liquidated.

 

**ITEM 4****.Controls and Procedures**

 

***                                               ******Disclosure Controls and Procedures***

 

                We haveestablished disclosure controls and procedures to ensure that material informationrelating to the Partnership, including its consolidated subsidiaries, is madeknown to the officers who certify the Partnership’s financial reports and toother members of senior management and the Board of Directors.  In designing and evaluating the disclosurecontrols and procedures, management recognizes that any controls andprocedures, no matter how well designed and operated, can provide onlyreasonable assurance of achieving the desired control objectives, andmanagement is required to apply its judgment in evaluating the cost-benefitrelationship of possible controls and procedures.

 

                Based on their evaluation as of March 31, 2005, theprincipal executive officer and principal financial officer of the Partnershiphave concluded that the Partnership’s disclosure controls and procedures (asdefined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Actof 1934 (the “Exchange Act”) are effective to ensure that the informationrequired to be disclosed by the Partnership in the reports it files or submitsunder the Exchange Act is recorded, processed, summarized and reported withinthe time periods specified in SEC rules and forms.

 

***                                               ******Internal Control Over Financial Reporting***

 

                There has not been any change inour internal control over financial reporting that occurred during ourquarterly period ended March 31, 2005 that has materially affected, or isreasonably likely to materially affect, our internal control over financialreporting.

 

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**PART II****. OTHERINFORMATION**

 

**ITEM 1****.Legal Proceedings**

 

                See discussion of legalproceedings in “Note 8—Contingencies” in the accompanying condensedconsolidated financial statements.

 

**ITEM 6****.Exhibits**

 

                The following documents arefiled 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                                          |

----

*                                         Filed herewith.

 

†                                          Not considered to be“filed” for purposes of Section 18 of the Securities Exchange Act of 1934or otherwise subject to the liabilities of that section.

 

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**SIGNATURES**

 

                Pursuant to the requirements ofthe Securities Exchange Act of 1934, the Partnership has duly caused thisreport to be signed on its behalf by the undersigned thereunto duly 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)* |
|       |                              |   | *May 3, 2005* |
|       |                              |   |   |
|       |                              | By:  | /S/ GERALD A. TYWONIUK |
|       |                              |   | Gerald A. Tywoniuk |
|       |                              |   | *Senior Vice President, Chief Financial* |
|       |                              |   | *Officer and Treasurer* |
|       |                              |   | *(Principal Financial and Accounting Officer)* |
|       |                              |   | *May 3, 2005* |
|            |                                   |  |  |  |

 

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**EXHIBIT INDEX**

 
| **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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*                                         Filed herewith.

 

†                                          Not considered to be“filed” for purposes of Section 18 of the Securities Exchange Act of 1934or otherwise subject to the liabilities of that section.

 

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