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TABLE OF CONTENTS

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

For the quarterly period ended June 30, 2004

OR

For the transition period from                               to                              

Commission File Number 1-313345

PACIFIC ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

5900 Cherry Avenue
Long Beach, CA 90805-4408
(Address of principal executive offices)

(562) 728-2800
(Registrant's telephone number, including area code)

        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 (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

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

        There were 19,069,948 of the registrant's Common Units and 10,465,000 of the registrant's Subordinated Units outstanding at June 30, 2004.

PACIFIC ENERGY PARTNERS, L.P.

FORM 10-Q

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

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

CONDENSED CONSOLIDATED BALANCE SHEETS

See accompanying notes to condensed consolidated financial statements.

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

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

See accompanying notes to condensed consolidated financial statements.

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

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL

See accompanying notes to condensed consolidated financial statements.

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

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

See accompanying notes to condensed consolidated financial statements.

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying notes to condensed consolidated financial statements.

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PACIFIC ENERGY PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2004

(Unaudited)

1.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

        On July 26, 2002, Pacific Energy Partners, L.P. and its subsidiaries (the "Partnership") completed an initial public offering of common units representing limited partner interests. The Partnership, which was formed by The Anschutz Corporation ("TAC") in February 2002, and its subsidiaries are engaged principally in the business of gathering, transporting, storing and distributing crude oil and related products in California and the Rocky Mountain region of the U.S. and Canada. The Partnership generates revenue primarily by transporting crude oil on its pipelines and by leasing storage capacity. The Partnership also buys, blends and sells crude oil, activities that are complementary to the Partnership's pipeline transportation business. The Partnership operates primarily in California, Colorado, Montana, Wyoming and Utah in the United States and in Alberta, Canada and conducts its business through two regional operating units: West Coast operations and Rocky Mountain operations.

        The Partnership owns 100% of Pacific Energy Group LLC ("PEG"), whose 100% owned subsidiaries consist of: (i) Pacific Pipeline System LLC ("PPS"), owner of Line 2000 and the Line 63 system, (ii) Pacific Terminals LLC ("PT"), owner of the Pacific Terminals storage and distribution system, (iii) Pacific Marketing and Transportation LLC ("PMT"), owner of the PMT gathering and blending system, (iv) Rocky Mountain Pipeline System LLC ("RMPS"), owner of various undivided interests in the pipelines that make up the Western Corridor system, and 100% of the Salt Lake City Core system and AREPI pipeline, and (v) Ranch Pipeline LLC ("RPL"), owner of a 22.22% partnership interest in Frontier Pipeline Company ("Frontier").

        The Partnership owns 100% of PEG Canada GP LLC ("PEG Canada GP"), the general partner of PEG Canada, L.P. ("PEG Canada"), the operating company for the Partnership's Canadian subsidiaries. The Partnership owns 100% of the limited partner interests in PEG Canada, whose 100% subsidiaries consist of (i) Rangeland Pipeline Company ("RPC"), which owns 100% of Aurora Pipeline Company Ltd. ("APC") and a partnership interest in Rangeland Pipeline Partnership ("RPP"), (ii) Rangeland Northern Pipeline Company ("RNPC"), which owns the remaining partnership interest in RPP, and (iii) Rangeland Marketing Company ("RMC"). RPP owns all of the assets that make up the Rangeland and Mid-Alberta pipeline ("MAPL") systems except the Aurora pipeline, which is owned by APC.

        The Partnership owns 100% of Pacific Energy Finance Corporation. Pacific Energy Finance Corporation was organized for the sole purpose of co-issuing the Partnership's 7.125% senior unsecured notes issued in June 2004.

        PPS, PT and PMT comprise the West Coast segment. RMPS, RPL, PEG Canada, RPC, APC, RPP, RNPC and RMC comprise the Rocky Mountain segment. Certain costs of PEG are also included in each segment.

        The general partner of the Partnership is Pacific Energy GP, Inc. ("General Partner"), a wholly owned, indirect subsidiary of TAC. In addition to the 2% general partner interest held by the General Partner, TAC owns 10,465,000 subordinated units of the Partnership.

        On July 31, 2003, PT completed the acquisition of certain storage and pipeline distribution assets for a total purchase price of $173 million. The purchase was funded through $90 million of proceeds from the issuance of additional common units on August 25, 2003, and borrowings under the

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Partnership's revolving credit facility. The consolidated financial statements reflect the ownership and results of operations of PT since the date of acquisition.

        On May 11, 2004, subsidiaries of PEG Canada completed the acquisition of all of the outstanding capital stock of RPC, RMC and APC, which owned various components of the Rangeland Pipeline system, for an aggregate cash purchase cost of approximately $116 million. The purchase was funded through a combination of proceeds from the Partnership's March 30, 2004 equity offering and the Partnership's Canadian credit facility. The consolidated financial statements reflect the ownership and results of operations of Rangeland Pipeline system since the date of acquisition.

        On June 30, 2004, a subsidiary of PEG Canada completed the acquisition of the Mid-Alberta Pipeline ("MAPL") pipeline for an aggregate purchase price of approximately $30 million, including capital expenditures of approximately US$3 million to be incurred in the first year for a new initiating pump station, tanks and pipeline connections. The purchase was funded principally from the Partnership's Canadian credit facility. The consolidated financial statements reflect the ownership and results of operations of MAPL pipeline since the date of acquisition.

        The unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial reporting and with Securities and Exchange Commission ("SEC") regulations. Accordingly, these statements have been condensed and do not include all of the information and footnotes required for complete financial statements. These statements involve the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. The results of operations for the three and six months ended June 30, 2004 and 2003 are not necessarily indicative of the results of operations for the full year. The financial data for the three and six months ended June 30, 2004 and 2003 is derived from the Partnership's unaudited condensed consolidated financial statements. The financial data as of December 31, 2003 is derived from the Partnership's audited consolidated financial statements. All significant intercompany balances and transactions have been eliminated during the consolidation process.

        These financial statements should be read in conjunction with the Partnership's audited consolidated financial statements and notes thereto included in the Partnership's annual report on Form 10-K for the year ended December 31, 2003.

Management Estimates

        Preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires that management make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the balance sheet date as well as the reported amounts of revenue and expenses during the reporting period. The actual results could differ significantly from those estimates.

        The Partnership's most significant estimates involve the valuation of individual assets acquired in purchase transactions, the useful lives of property and equipment, the expected costs of environmental remediation, accounting for the potential impact of regulatory proceedings or other actions with shippers on the Partnership's pipelines, and the valuation of inventory, displacement oil and minimum tank inventories.

Revenue Recognition

        Revenue from the Rangeland Pipeline system and the MAPL pipeline is recognized upon delivery of the crude oil, condensate and butane to the customer. Customers who wish to transport product on

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the Rangeland pipelines may either: (i) sell product to RMC at the inlet to the pipeline without repurchasing product from RMC; or (ii) sell product to RMC at an inlet point and repurchase such product at agreed upon delivery points for the price paid at the inlet to the pipeline plus an established location differential on a pre-arranged basis.

Derivative Instruments

        The Partnership uses, on a limited basis, certain derivative instruments (principally futures and options) to hedge its minimal exposure to market price volatility related to its crude oil inventory or future sales of crude oil. Derivatives used to hedge market price volatility related to inventory are generally designated as fair value hedges, and derivatives related to future sale of crude oil are generally designated as cash flow hedges. The Partnership does not engage in speculative derivative activities. Derivative instruments are included in other assets in the accompanying consolidated balance sheets. Changes in the fair value of the Partnership's derivative instruments related to crude oil inventory are recognized in net income. "Crude oil sales, net of purchases" were net of $0.3 and $0.1 million for the three months ended June 30, 2004 and 2003, and $0.5 and $0.3 for the six months ended June 30, 2004 and 2003, respectively, reflecting changes in the fair value of PMT's derivative instruments held for its crude oil marketing activities. Changes in the fair value of the Partnership's derivative instruments related to the future sale of crude oil are deferred and reflected in "accumulated other comprehensive income," a component of partners' capital, until the related revenue is included in the consolidated statements of income. As of June 30, 2004, $0.7 million relating to the changes in the fair value of highly effective derivative instruments was included in "accumulated other comprehensive income" and is expected to be reclassified to earnings in 2004.

        In August and September 2002, PEG entered into three interest rate swap agreements that were to mature in 2009, with notional amounts of $140.0 million, and two interest rate swap transactions that were to mature in 2007, with notional amounts of $30.0 million. The Partnership designated these swaps as a hedge of its exposure to variability in future cash flows attributable to the LIBOR interest payments due on $170.0 million outstanding under PEG's term loan facility. The average swap rate on this $170.0 million of debt was approximately 4.25%, resulting in an all-in interest rate on the $170.0 million of debt of approximately 6.50% (including the applicable margin of 2.25%). In June 2004, in conjunction with the issuance of the 7.125% Senior Notes and the repayment of the term loan, PEG bought back the swaps for a loss of $0.6 million.

        In connection with the issuance of the 7.125% Senior Notes, the Partnership entered into interest rate swap agreements with an aggregate notional principal amount of $80.0 million to receive interest at a fixed rate of 7.125% and to pay interest at an average variable rate of six month LIBOR plus 1.6681% (set in advance or in arrears depending on the swap transaction). The interest rate swaps matures June 15, 2014 and are generally callable at the same dates and terms as the 7.125% Notes. The Partnership designated these swaps as a hedge of the change in the Senior Notes fair value attributable to changes in the six month LIBOR interest rate. Changes in fair values of the interest rate swaps are recorded into earnings each period. Similarly, changes in the fair value of the underlying $80.0 million of Senior Notes are recorded into earnings each period. The offsetting difference of recording the change in fair value of the interest rate swaps and the change in fair value of $80.0 million Senior Notes into earnings is not expected to have a material impact on earnings as movement in fair value of the interest rate swap and the underlying debt are expected to be highly correlated.

        By using derivative financial instruments to hedge exposures related to changes in market prices and interest rates, the Partnership exposes itself to market risk and credit risk. Market risk is the risk of loss arising from the adverse effect on the value of a financial instrument that results from a change in market prices or interest rates. The market risk associated with price volatility is managed by established parameters that limit the types and degree of market risk that may be undertaken.

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        Credit risk is the risk of loss arising from the failure of the derivative agreement counterparty to perform under the terms of the derivative agreement. When the fair value of a derivative agreement is positive, the counterparty is liable to the Partnership, which creates credit risk for the Partnership. When the fair value of a derivative agreement is negative, the Partnership is liable to the counterparty and, therefore, it creates credit risk for the counterparty. As of June 30, 2004, the counterparties to the Partnership's crude oil hedging activities did not represent a credit risk to the Partnership as the fair value of each derivative agreement was negative.

Foreign Currency Translation

        The financial statements of operating subsidiaries in Canada are measured using the Canadian dollar as the functional currency. Balance sheet amounts are translated at the end of period exchange rate and income statement and cash flow amounts are translated at the average exchange rate for the period. Adjustments from translating these financial statements into U.S. dollars are accumulated in the equity section of the balance sheet under the caption, "accumulated other comprehensive income (loss)."

Income Taxes

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

        Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the Partnership's First Amended and Restated Agreement of Limited Partnership, as amended. Individual unitholders have different investment bases depending upon the timing and price of acquisition of partnership units. Further, each unitholder's tax accounting, which is partially dependent upon the unitholder's tax position, differs from the accounting followed in the condensed consolidated financial statements. Accordingly, the aggregate difference in the basis of the Partnership's net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder's tax attributes in the Partnership is not available to the Partnership.

        In addition to federal and state income taxes, unitholders may be subject to other taxes, such as local, estate, inheritance or intangible taxes which may be imposed by the various jurisdictions in which the Partnership does business or owns property. Individual unitholders will generally have no responsibility to file Canadian tax returns.

        Income taxes are accounted for under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in operations in the period that includes the enactment date.

        Pursuant to FAS No. 109, "Accounting for Income Taxes", in the second quarter of 2004, the Partnership recorded a deferred tax liability of $33.9 million, representing the tax effect of the difference between the amounts paid for shares of RPC, RMC and APC, and the underlying tax basis of the assets.

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Net Income per Unit

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

        Diluted net income per limited partner unit is calculated in the same manner as basic net income per limited partners unit above, except that the weighted average number of outstanding limited partner units is increased to include the dilutive effect of outstanding options and restricted units by application of the treasury stock method. Following is a reconciliation of the basic weighted average outstanding limited partner units to diluted weighted average limited partner units.

Reclassifications

        Certain prior year balances in the accompanying condensed consolidated financial statements have been reclassified to conform to the current year presentation.

Accounting Pronouncements

        In December 2003, the FASB issued FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN46R). FIN46R requires companies to evaluate variable interest entities for specific characteristics to determine whether additional consolidation and disclosure requirements apply. The transition guidance requires the application of FIN 46R to all special-purpose entities (SPEs) no later than the end of the first reporting period ended after December 15, 2003 and immediately to all entities created after January 31, 2003. The adoption of FIN 46R did not have any impact on the Partnership's consolidated financial statements.

2.    ACQUISITIONS

Rangeland

        On May 11, 2004, the Partnership completed the acquisition of all of the outstanding shares of Rangeland Pipeline Company ("RPC"), Rangeland Marketing Company ("RMC") and Aurora Pipeline Company Ltd. ("APC"), the corporations that owned various components of the Rangeland Pipeline System from BP Canada Energy Company ("BP"). The Rangeland Pipeline System is located in the province of Alberta, Canada. The acquisition price for shares of RPC, RMC and APC was Cdn$130 million plus approximately Cdn$29 million for linefill, working capital, transaction costs and transition capital expenditures. The aggregate purchase cost was approximately U.S. $116 million and was funded through a combination of proceeds from our March 30, 2004 equity offering and a Cdn$45 million borrowing from a new Cdn$100 million revolving credit facility in Canada. The acquisition was accounted for as an acquisition of assets.

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        The majority of the Rangeland Pipeline System was constructed in 1966 with smaller portions being built as early as 1955 and certain pump stations built as late as 1971. The Partnership anticipates depreciating the pipeline over forty years from the purchase date.

        Pursuant to a transportation service agreement between RMC, RPC and APC, RMC has contracted for the rights to the entire capacity of the Rangeland pipeline. Customers who wish to transport product on the Rangeland pipelines may, therefore, either: (i) sell product to RMC at the inlet to the pipeline without repurchasing product from RMC; or (ii) sell product to RMC at an inlet point and repurchase such product at agreed upon delivery points for the price paid at the inlet to the pipeline plus an established location differential. RMC owns the buy/sell contracts with customers, which were assumed with the purchase, but the marketing function was conducted by employees of BP to whom we were not able to and did not offer employment.

        The Rangeland Pipeline System has historically been operated without regard to maximizing either pipeline throughput or profitability; rather, it was operated as an integral part of a larger marketing and trading oriented enterprise. Similarly the MAPL Pipeline, which the Partnership also purchased (see below), was not operated with regard to maximizing pipeline operations or profitability; it was operated as a cost center in a larger enterprise. The Partnership intends to make significant changes to the revenue-generating capability of both systems by combining and integrating fully all of its Canadian and U.S. Rocky Mountain pipeline systems under common management, by expanding the throughput capacity of the MAPL system and by connecting into other pipelines and establishing a new pump station and receiving terminal in Edmonton, Alberta. This new facility will be able to access additional sources of Canadian crude oil, which will allow the Partnership to participate in the projected increase in production of Canadian synthetic crude oil.

        In effect, the Partnership is converting what has been primarily a gathering system for crude oil, condensate and butane in southern Alberta into a main line transportation system that will be able to transport multiple grades of conventional and synthetic crude oils from the Edmonton oil hub to U.S. Rocky Mountain refining centers.

        Until April 2003, the assets comprising the Rangeland Pipeline System were held by three legal entities: BP, APC and BP Canada Energy Resources Company ("BPR"). In April 2003, in order to facilitate their sale, BPR formed RPC and RMC, and transferred their Rangeland pipeline and marketing related assets to the newly formed entities. APC, which contains only a short segment of pipeline and de minimis other assets, liabilities, revenues and expenses, remained unchanged. None of RPC, RMC or APC ever had any employees of their own. All operations and administrative and technical support functions associated with the Rangeland pipeline system, including field services and operations, executive management, marketing, engineering, environmental, risk management, payroll, treasury, human resources and legal remained with BPR and BP. These included services provided by approximately ninety BP employees who also provided varying amounts of support for BP's other pipelines.

        Although the RPC and RMC legal entities were formed in April 2003, revenues, expenses, and other financial measures continued to be included within the financial statements of BPR and BP. Financial statements for RPC, RMC and Aurora were not maintained on a current basis.

        Upon closing of the purchase transaction, BP terminated employees directly involved in the operation of the Rangeland pipeline, including field-level supervisors, and the Partnership hired those who accepted an offer of employment. Except for one former marketing person (who had not been directly involved with marketing of the Rangeland Pipeline System for several years), no members of senior management, and no financial, marketing or technical personnel who had been associated with the management and support of the Rangeland system were made available by BP for possible employment with the Partnership following the completion of this acquisition. Consequently, the Partnership hired its own marketing, accounting and technical staff, which are located in its new

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Calgary office or in Olds, Alberta. The Partnership also utilizes its existing executive and support staff in Long Beach, California and Denver, Colorado to provide management oversight and administrative and technical support for the Alberta assets.

        The Partnership also did not acquire accounting software or computer hardware with the purchase. The Partnership was able, however, to acquire as part of the transaction, the Supervisory Control and Data Acquisition (SCADA) system necessary to operate the pipeline. Subsequent to the closing, the Partnership acquired software associated with the complex task of volumetric and revenue accounting from the seller for no additional consideration. The Partnership will use its existing financial accounting software for other accounting functions.

Mid Alberta Pipeline

        On June 30, 2004, the Partnership completed the acquisition of the MAPL Pipeline from Imperial Oil. The MAPL pipeline is located in Alberta, Canada. The acquisition price for MAPL was Cdn$31.5 million, of which Cdn$5.0 million will be payable in three years. In addition to MAPL pipeline, the Partnership acquired linefill for Cdn$5.0 million and expects to incur approximately Cdn$4.0 million for transaction costs and first-year capital expenditures. The aggregate purchase price, including linefill, transaction costs and first-year construction costs will be approximately U.S. $30.2 million, most of which, was funded from our existing Canadian credit facility.

        The first section of MAPL pipeline was constructed in 1960 and other sections were constructed in 1985 and 1994. The Partnership anticipates depreciating the pipeline over forty years from the acquired date.

        Imperial Oil did not make any of its employees available for possible employment with the Partnership following the completion of the acquisition. In connection with purchase, the Partnership entered into a two-year transitional services agreement with Imperial Oil whereby Imperial Oil will provide necessary services to operate the initiating pump station and the control center and software that control movements through the MAPL pipeline. The Partnership has the right to cancel the transitional services agreement at any time. The Partnership expects to assume all MAPL pipeline operations and transfer MAPL operations to the Partnership's Rangeland control center after its initiation facilities in Edmonton are constructed and operational.

        The Partnership did not acquire accounting software or computer hardware with the purchase. The complex task of volumetric and revenue accounting will be consolidated with the accounting process currently in place for the Rangeland Pipeline system. The Partnership will use its existing financial accounting software for other accounting functions.

        The acquisition of MAPL was accounted for as an acquisition of assets.

Purchase Price Allocations

        The acquisitions of Rangeland and MAPL have been accounted for by the purchase method of accounting pursuant to Statement of Financial Accounting Standards ("FAS") No. 141, "Business Combinations" and, accordingly the consolidated statements of income include the results of Rangeland and MAPL from their acquisition dates. Based upon independent appraisals of the fair values of the acquired assets, the Partnership is completing its review and determination of the fair values of the assets acquired and liabilities assumed. Accordingly, the allocation of the purchase price is subject to revision. Based upon the preliminary estimates, the purchase price is being allocated to depreciable pipelines and related equipment, crude oil inventory, pipeline linefill, and rights of way, as well as to amortizable intangible assets. In addition to the cash purchase price and related acquisition costs, the Partnership assumed an environmental liability of approximately $2.2 million, and pursuant to FAS 109, Accounting for Income Taxes the Partnership recorded a deferred tax liability of $33.9 million,

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representing the tax effect of the difference between the amounts paid for shares of RPC, RMC and APC, and the underlying tax basis of the assets.

4.    INVESTMENT IN FRONTIER PIPELINE COMPANY

        RPL owns a 22.22% partnership interest in Frontier, which is accounted for by the equity method of accounting. Under the equity method, the investment is initially recorded at cost and subsequently adjusted to recognize the investor's share of distributions and net income or loss of the investee as they occur. Recognition of any such loss is generally limited to the total of the investor's investment in, advances to, commitments and guarantees for the investee.

        The summarized balance sheets of Frontier at June 30, 2004 and December 31, 2003, and the statements of income for the three and six months ended June 30, 2004 and 2003 are presented below:

Balance Sheets

Statements of Income

        The unamortized portion of the excess cost over the Partnership's share of net assets of Frontier is $6.8 million and $6.9 million at June 30, 2004 and December 31, 2003, respectively. This excess cost over the Partnership's share of net assets represents the difference between the historical cost and the fair value of property and equipment at acquisition dates. The Partnership is amortizing this excess cost over the life of the related property and equipment.

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5.    LONG-TERM DEBT

        The Partnership's long-term debt obligations at June 30, 2004 and December 31, 2003 are shown below:

Senior Secured U.S. Revolving Credit Facility and Term Loan

        PEG is the borrower under the U.S. revolving credit facility. The revolving credit facility is a $200.0 million facility that is available for general partnership purposes, including working capital, letters of credit and distributions to unitholders, and to finance future acquisitions. Borrowings under the revolving credit facility are limited by various financial covenants in the credit agreement. The revolving credit facility also has a borrowing sublimit of $45.0 million for working capital, letters of credit and partnership distributions to unitholders. At June 30, 2004, $38.0 million was outstanding under the revolving credit facility. No letters of credit were issued as of that date.

        The revolving credit facility matures on July 26, 2007, at which time all outstanding amounts will be due and payable.

        Effective December 12, 2003, PEG and its lenders amended the interest rates and other fees under the credit facilities. Subject to certain limited exceptions, indebtedness under the revolving credit facility now bears interest at PEG's option, at either (i) the base rate, which is equal to the higher of the prime rate as announced by Fleet National Bank or the Federal Funds rate plus 0.50% or (ii) LIBOR plus an applicable margin ranging from 0.75% to 2.00%. The applicable margins are subject to change based on the credit rating of the revolving credit facility or, if is not rated, the credit rating of PEG. PEG incurs a commitment fee which ranges from 0.125% to 0.375% per annum on the unused portion of the revolving credit facility.

        As of June 30, 2004, we had available but undrawn credit of $111 million under our U.S. revolving credit facility. This amount could be increased based on an acquired business's earnings before interest, taxes, depreciation and amortization ("EBITDA") with the acceptance of the administrative agent for our credit facilities.

        The U.S. revolving credit facility is guaranteed by the Partnership and certain of PEG's U.S. operating subsidiaries, PEG Canada, PEG Canada GP LLC and Pacific Energy Finance Corporation (collectively, the "Guarantors"). The revolving credit facility is fully recourse to PEG and the guarantors, but non-recourse to the General Partner. Obligations under the revolving credit facility are secured by (i) the assets of the Partnership, (ii) pledges of membership interests in and the assets of PEG and certain of PEG's operating subsidiaries and PEG Canada GP LLC, (iii) pledges of partnership interests in and certain assets of PEG Canada and (iv) pledges of the shares in and the assets of Pacific Energy Finance Corporation; provided, however, that the collateral under the credit agreement does not include shares, partnership interests, limited liability company membership interests

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or other ownership interest, if any, in or assets of Rangeland Pipeline Company, Rangeland Marketing Company, Rangeland Northern Pipeline Company, Rangeland Pipeline Partnership, Aurora Pipeline Company Ltd. or any other entity that is designated by PEG or the Partnership after the date hereof as an "Unrestricted Subsidiary" pursuant to the terms of the credit agreement.

        On June 16, 2004, the Partnership repaid all amounts outstanding under the term loan. Amounts under the term loan that have been repaid may not be re-borrowed.

        Under the credit agreement, PEG is prohibited from declaring dividends or distributions if any event of default, as defined in the credit agreement, occurs or would result from such declaration. In addition, the credit agreement contains certain financial covenants and covenants limiting the ability of PEG and the Guarantors to, among other things, incur or guarantee indebtedness, change ownership or structure, including mergers, consolidations, liquidations and dissolutions, sell or transfer their assets and properties, declare or pay dividends and enter into a new line of business. At June 30, 2004, PEG and Guarantors were in compliance with all such covenants.

Canadian Revolving Credit Facility

        On May 11, 2004, Rangeland Pipeline Company entered into a Canadian revolving credit facility agreement which is guaranteed by certain subsidiaries of PEG Canada. The maximum amount available under the Canadian revolving credit facility is Cdn$75 million, which will be further increased to Cdn$100 million after certain other conditions are satisfied. The Canadian revolving credit facility is secured by liens on all of the property and assets of Rangeland Pipeline Company and of the guarantors of the Canadian revolving credit facility.

        Indebtedness under the Canadian revolving credit facility bears interest, at Rangeland Pipeline Company's option, at either (i) the Canadian prime rate or the U.S. base rate (each plus an applicable margin ranging from 1.00% to 1.625%,) (ii) Bankers' Acceptance discount rates or LIBOR plus an applicable margin ranging from 2.00% to 2.65%. The applicable margins are subject to change based on certain financial ratios.

        The Canadian revolving credit facility matures on May 11, 2007, at which time all outstanding amounts will be due and payable. Amounts outstanding under the credit facility may be repaid at any time prior to maturity.

        The Canadian revolving credit facility is available for general corporate purposes and also provides for the issuance of letters of credit. Borrowings under this facility are limited by various financial covenants that are set forth in the Canadian credit agreement. As of June 30, 2004, Rangeland Pipeline Company was in compliance with all covenants under the Canadian agreement. At June 30, 2004, borrowings totaling Cdn$65.0 million (U.S.$48.7 million) and letters of credit totaling Cdn$5.0 million (U.S.$3.7 million) were outstanding under the Canadian revolving credit facility. As of June 30, 2004, we had available but undrawn credit of Cdn$5.0 million (U.S.$3.7 million) under our Canadian revolving credit facility.

        Rangeland Pipeline Company incurs a commitment or standby fee which ranges from 25% to 35% of the applicable margin, based on the unused portion of the Canadian revolving credit facility. Under the Canadian credit agreement, Rangeland Pipeline Company is prohibited from declaring dividends or making any other distributions or payments to PEG Canada or its affiliates if any default or event of default, as defined in the Canadian credit agreement, occurs or would result from such declaration or payment, or if a material adverse effect, as defined in the Canadian credit agreement, would result from such declaration or payment, or if the distributions and payments would exceed certain limits. The Canadian credit agreement also contains covenants requiring Rangeland Pipeline Company, including its subsidiaries and affiliates, to maintain specified financial ratios. In addition, the Canadian credit agreement contains other restrictive covenants. As of June 30, 2004, Rangeland Pipeline Company was in compliance with all covenants under the Canadian credit agreement.

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Senior Unsecured Notes

        On June 16, 2004, the Partnership and its 100% owned subsidiary Pacific Energy Finance Corporation completed the sale of $250 million of 7.125% senior unsecured notes due June 15, 2014. The notes were issued at a discount of $4.4 million, resulting in an effective interest rate of 7.375%. Interest payments are due on June 15 and December 15 of each year, beginning on December 15, 2004. At any time prior to June 15, 2007, the Partnership will have the option to redeem up to 35% of the aggregate principal amount of notes at a redemption price of 107.125% of the principal amount with the net cash proceeds of one or more equity offering. The Partnership will have the option to redeem the notes, in whole or in part, at anytime on or after June 15, 2009 at the following redemption prices:

        The notes are jointly and severally guaranteed by certain of the partnership's subsidiaries, including PEG, PMT, RMPS, RPL, PEG Canada GP and PEG Canada.

        In addition, the indenture governing the notes contains certain covenants that, among other things, limit the Partnership's ability and the ability of its restricted subsidiaries to incur or guarantee indebtedness or issue certain types of preferred equity securities; sell assets; pay distributions on, redeem or repurchase Partnership units; consolidate, merge or transfer all or substantially all of its assets. At June 30, 2004, the Partnership was in compliance with all such covenants.

        Net proceeds from the issuance of the Notes were $241.1 million after deducting the $4.4 million discount and offering expenses of $4.5 million. The net proceeds were used principally to repay the Partnership's $225 million term loan and to repay $14 million of indebtedness outstanding under our U.S. revolving credit facility.

        In connection with the issuance of the 7.125% Senior Notes, the Partnership entered into interest rate swap agreements with an aggregate notional principal amount of $80 million to receive interest at a fixed rate of 7.125% and to pay interest at an average variable rate of six month LIBOR plus 1.6681% (set in advance or in arrears depending on the swap transaction). See "Note 1—Summary of Significant Accounting Policies" above for further discussion on these interest rate swaps.

Future Payment for MAPL Assets

        In connection with the purchase of MAPL pipeline, the Partnership is obligated to pay the seller Cdn$5.0 million (U.S.$3.7 million) on June 30, 2007. The future payment was discounted at 5%. The carrying value of the future payment was Cdn$4.3 million (U.S.$3.2 million) at June 30, 2004.

6.    WRITE OFF OF DEFERRED FINANCING COSTS AND INTEREST RATE SWAP TERMINATION EXPENSE

        On June 11, 2004, in connection with the repayment of its term loan, the Partnership had a $2.3 million non-cash write-down of deferred financing costs and incurred a $0.6 million cash expense to terminate related interest rate swaps.

7.    PARTNERS' CAPITAL

        On March 30, 2004, the Partnership issued and sold 4,200,000 common units in an underwritten public offering at a price of $28.50. The common units sold in the offering were registered pursuant to the registration statement on SEC Form S-3 filed on August 1, 2003. Net proceeds from the offering,

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including the General Partner's contribution of $2.4 million, totaled approximately $116.7 million after deducting underwriting fees and offering expenses of $5.4 million. The Partnership repaid approximately $10 million in borrowings under its U.S. revolving credit facilities, which were incurred in the first quarter of 2004 to fund the deposit on the Rangeland acquisition, and used approximately $76 million of the net proceeds to fund a portion of the aggregate purchase price of the Rangeland and Mid Alberta pipeline acquisitions. The Partnership utilized the remaining $31 million in net proceeds as follows: (i) $8 million to repay borrowings incurred in the second half of 2003 to fund growth capital expenditures, (ii) $10 million to repay borrowings under its U.S. revolving credit facility to increase availability under that facility to fund 2004 growth capital projects including pre-construction development activities for the Pier 400 Project and establishing a new connection between Frontier pipeline and the Salt Lake City Core System and other growth capital expenditures, and (iii) $13 million to repay borrowings to increase its available borrowing capacity to fund future growth capital projects.

        On April 12, 2004, the underwriters exercised a portion of the over-allotment option granted in connection with the offering of common units on March 30, 2004 and purchased an additional 425,000 common units from the Partnership at a price of $28.50 per unit to cover over allotments. Including the related capital contribution of the General Partner of $247,000, the partnership received net proceeds of $11.8 million after underwriting fees. The Partnership used the $12 million in net proceeds from the exercise of the overallotment option to reduce the balance outstanding under its revolving credit facility pending future investment in capital projects.

8.    RELATED PARTY TRANSACTIONS

        In the ordinary course of its operations, the Partnership engages in various transactions with TAC and its affiliates. These transactions, which are more thoroughly described below, are summarized in the following table for the three and six months ended June 30, 2004 and 2003:

        Related party balances at June 30, 2004 and December 31, 2003 were as follows:

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Revenue from Related Parties

        A subsidiary of TAC was a shipper on Line 2000 and was charged the published tariff rates applicable to "participating shippers" until March 31, 2003, when an agreement between the TAC subsidiary and a third party, the performance of which required the TAC subsidiary to ship on Line 2000, was assigned to PMT for consideration equal to the value of inventory that was transferred to PMT. In addition, a subsidiary of TAC is a shipper on RMPS's pipeline systems and the AREPI pipeline and is charged published tariff rates.

        RMPS serves as the contract operator for certain gas producing properties owned by a subsidiary of TAC in Wyoming and Utah, in exchange for which RMPS is reimbursed 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 for other overhead services related to their activities. In addition, during 2003 and the first quarter of 2004, RMPS's trucking operation hauled water for a TAC subsidiary at rates equivalent to those charged to third parties.

        RMPS also receives a management fee from Frontier Pipeline in connection with time spent by RMPS management and for other services related to the pipeline's activities. RMPS received $0.1 million for each of the three months ended June 30, 2004 and 2003 and $0.3 million for each of the six months ended June 30, 2004 and 2003.

Expenses Paid to Related Parties

        General and Administrative Expense:    In 2002, the Partnership began utilizing the financial accounting system owned and provided by TAC under a shared services arrangement. In addition, the Partnership from time to time utilizes the services of TAC's risk management personnel for acquiring the Partnership's insurance, and the Partnership's surety bonds are issued under TAC's bonding line. Beginning January 2003, TAC began charging the Partnership a fee of $0.1 million per year for these services and continues to charge the Partnership for any out-of-pocket costs it incurs. The fixed annual fee includes all license, maintenance and employee costs associated with the Partnership's use of the financial accounting system.

        Beginning January 2003, and as amended in May 2004, the Partnership leases approximately 5,400 square feet of office space from an affiliate of TAC, for a term of five years at an annual cost of $0.1 million.

        Cost Reimbursements:    The General Partner employs all U.S. based employees. All employee expenses incurred by the General Partner on behalf of the Partnership are charged back to the Partnership.

        The operating and general and administrative cost reimbursement amounts above exclude reimbursements for property, casualty and directors and officers' insurance premiums paid by TAC on behalf of the Partnership, until mid-2003. Beginning with the 2003-2004 insurance policy period, the Partnership incurred these costs directly. In addition, out-of-pocket costs incurred by TAC for the benefit of the Partnership for computer consultants and surety bonds were also reimbursed by the Partnership.

        Other:    The Partnership also reimburses TAC for transportation services, based on a cost-based formula. For the six months ended June 30, 2004, the Partnership reimbursed TAC $0.1 million. No amounts were incurred for the six months ended June 30, 2003.

9.    SEGMENT INFORMATION

        The Partnership's business and operations are organized into two regional operating units: West Coast operations and Rocky Mountain operations. The West Coast operations include PPS, PT and PMT (for the period from July 31, 2003 to June 30, 2004). Rocky Mountain operations include RMPS, RPL and PEG Canada and its Canadian subsidiaries (for the period from May 11, 2004 to June 30,

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2004). The reporting units comprising each segment have been aggregated to reflect how the assets are operated and managed. General and administrative costs, which consist of executive management, accounting and finance, human resources, information technology, investor relations, legal, and marketing and business development, are not allocated to the individual segments. Information regarding these two operating units is summarized below:

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(1)

Includes the revenue of the PT storage and distribution system, which PT acquired on July 31, 2003.

(2)

Includes the revenue of the Canadian subsidiaries, which were acquired on May 11, 2004.

(3)

The above amounts are net of purchases of $94,382 and $88,408 for the three months ended June 30, 2004 and 2003 and $175,497 and $174,700 for the six months ended June 30, 2004, respectively.

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(4)

The following is a reconciliation of operating income as stated above to the statements of income: