Edgar Filing: PACIFIC ENERGY PARTNERS LP

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

FORM 10-Q

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

For the quarterly period ended September 30, 2002

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

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)

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

5900 Cherry Avenue
Long Beach, CA 90805
(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 o No ý

The number of the registrant's Common Units held by non-affiliates and outstanding at October 31, 2002 was 8,577,500.

PACIFIC ENERGY PARTNERS, L.P.
Successor to Pacific Energy (Predecessor)

FORM 10-Q
TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Combined Condensed Balance Sheets As of September 30, 2002 (Unaudited) and December 31, 2001 (Audited)	1
	Combined Condensed Statements of Operations (Unaudited)—For the Three Months and Nine Months Ended September 30, 2002 and 2001	2
	Combined Condensed Statements of Partners' Capital (Unaudited)—For the Nine Months Ended September 30, 2002 and 2001	3
	Combined Condensed Statements of Cash Flows (Unaudited)—For the Nine Months Ended September 30, 2002 and 2001	4
	Notes to Combined Condensed Financial Statements (Unaudited)	5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	15
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	27
Item 4.	Controls and Procedures	27
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	28
Item 2.	Changes in Securities and Use of Proceeds	29
Item 6.	Exhibits and Reports on Form 8-K	30

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

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

Successor to Pacific Energy (Predecessor)

COMBINED CONDENSED BALANCE SHEETS

(in thousands)

			September 30, 2002			December 31, 2001
			(Unaudited)
ASSETS
Current assets:
	Cash and cash equivalents		$	20,951		$	9,511
	Crude oil sales receivable			33,491			21,538
	Transportation accounts receivable			11,732			5,770
	Due from related party (note 5)			—			108
	Crude oil inventory			1,210			2,292
	Spare parts inventory			445			445
	Prepaid expenses			3,845			1,684
	Other			552			470

		Total current assets		72,226			41,818
Property and equipment, net				409,982			311,889
Investment in Frontier				8,886			9,444
Due from related parties (note 5)				—			11
Other assets				7,178			11,231

			$	498,272		$	374,393

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
	Accounts payable		$	3,496		$	788
	Accrued crude oil purchases			28,927			22,049
	Provision for right-of-way costs (note 6)			3,248			3,196
	Accrued power costs			1,801			1,634
	Accrued interest payable			2,477			841
	Due to related parties (note 5)			1,089			—
	Provision for loss on rate case litigation (note 10)			—			1,500
	Other			6,772			2,969

		Total current liabilities		47,810			32,977
Long-term debt (note 8)				225,000			181,333
Due to related parties (note 5)				—			122
Derivatives liability (note 3)				6,798			—
Other liabilities (note 10)				2,600			2,600
Accumulated other comprehensive loss				(6,798	)		—
Partners' Capital (net parent investment)				222,862			157,361
Commitments and contingencies (note 10)

			$	498,272		$	374,393

See accompanying notes to combined condensed financial statements.

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

Successor to Pacific Energy (Predecessor)

COMBINED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except per unit amounts)

		Three Months Ended						Nine Months Ended
		September 30, 2002			September 30, 2001			September 30, 2002			September 30, 2001
Pipeline transportation revenue		$	26,602		$	15,966		$	75,391		$	50,220
Crude oil sales, net of purchases of $94,878 and $88,794 for the quarter ended September 30, 2002 and 2001 and $235,948 and $88,794 for the nine months ended September 30, 2002 and 2001, respectively			4,770			4,013			14,904			4,013

Net revenues before operating expenses			31,372			19,979			90,295			54,233

Expenses:
	Operating		12,833			9,902			37,100			24,483
	Transition costs (note 3)		699			114			2,676			114
	General and administrative		2,338			1,001			5,907			3,032
	Depreciation and amortization		4,307			2,809			11,711			8,739

			20,177			13,826			57,394			36,368

Share of net income of Frontier			471			406			966			1,183

Operating income			11,666			6,559			33,867			19,048
Other income			135			122			387			401
Interest income			65			63			314			263
Interest expense			(3,508	)		(2,031	)		(7,398	)		(8,628	)

Net income		$	8,358		$	4,713		$	27,170		$	11,084

Net income for the general partner interest for the period from July 26 through September 30, 2002		$	108

Net income for the limited partner interests for the period from July 26 through September 30, 2002		$	5,305

Weighted average limited partner units for the period from July 26 through September 30, 2002			20,930	*

Net income per limited partner unit		$	0.25

*: Based on 20,930,000 weighted average units outstanding which include 1,865,000 common and 10,465,000 subordinated units held by the General Partner.
See accompanying notes to combined condensed financial statements.

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

Successor to Pacific Energy (Predecessor)

COMBINED CONDENSED STATEMENTS OF PARTNERS' CAPITAL

(Unaudited)

(in thousands)

						Limited Partner Interests								Accumulated Other Comprehensive Loss
			Net Parent Investment			Limited Partner Interests					General Partner Interest
			Net Parent Investment			Units		Amounts			General Partner Interest						Total
Balance, December 31, 2000			$	117,528		—		$	—		$	—		$	—		$	117,528
Capital contributions of members				90,649		—			—			—			—			90,649
Purchase of BP interest in joint venture				(43,607	)	—			—			—			—			(43,607	)
Distributions to members				(22,816	)	—			—			—			—			(22,816	)
Net income for the period of January 1—December 31, 2001				15,607		—			—			—			—			15,607

Balance, December 31, 2001			$	157,361		—		$	—		$	—		$	—		$	157,361
Capital contributions of members				8,770		—			—			—			—			8,770
Distributions to members				(16,000	)	—			—			—			—			(16,000	)
Net income for the period of January 1—July 25, 2002				21,757		—			—			—			—			21,757

Balance, July 26, 2002			$	171,888		—		$	—		$	—		$	—		$	171,888
Formation of limited partnership				(171,888	)	—			—			171,888			—			—
Proceeds from offering of limited partner interests, net				—		20,930	*		150,642	**		—			—			150,642
Distribution to general partner				—		—			—			(105,081	)		—			(105,081	)
Comprehensive loss:
	Net income for the period of July 26—September 30, 2002			—		—			5,305			108			—			5,413
	Change in fair value of interest rate hedging derivatives (note 3)			—		—			—			—			(6,798	)		(6,798	)

		Total comprehensive loss																(1,385	)

Balance, September 30, 2002			$	—		20,930		$	155,947		$	66,915		$	(6,798	)	$	216,064

*: Based on 20,930,000 units issued and outstanding for the period from July 26 through September 30, 2002 which include 1,865,000 common and 10,465,000 subordinated units held by the General Partner.
**: The net proceeds are based on the issuance of 8,600,000 common units to the public.
See accompanying notes to combined condensed financial statements.

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

Successor to Pacific Energy (Predecessor)

COMBINED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

				For the Nine Months Ended
				September 30, 2002			September 30, 2001
Cash flows from operating activities:
	Net income			$	27,170		$	11,084
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			11,711			8,739
		Share of net income of Frontier			(966	)		(1,183	)
		Payment for loss on rate case litigation			(1,500	)		—
		Net Changes in operating assets and liabilities:
			Crude oil sales receivable		(11,953	)		(46,817	)
			Transportation accounts receivable		(5,962	)		162
			Due to related party		1,197			859
			Crude oil inventory		1,082			(8,663	)
			Spare parts inventory		—			459
			Prepaid expenses		(1,861	)		(2,197	)
			Other current and non-current assets		(6,373	)		(468	)
			Accounts payable		2,708			48,758
			Accrued crude oil purchases		6,878			—
			Provision for right-of-way costs		52			—
			Accrued power costs		167			982
			Accrued interest payable		1,636			(3,092	)
			Distributions from Frontier, net		1,337			975
			Other current and non-current liabilities		3,803			5,497

			Net cash provided by operating activities		29,126			15,095
Cash flows from investing activities:
	Additions to property and equipment				(3,461	)		(3,794	)
	Acquisition of pipeline assets				(96,049	)		(9,810	)

			Net cash used in investing activities		(99,510	)		(13,604	)
Cash flows from financing activities:
	Proceeds from note payable to bank				312,000			—
	Repayment of note payable to bank				(268,333	)		—
	Proceeds from issuance of common units				167,700			—
	Common unit issuance and registration costs				(17,058	)		—
	Capital contributions of members				8,770			10,620
	Distributions to members				(16,000	)		(17,199	)
	Distributions to general partner				(105,081	)		—
	Due from related party				(174	)		(1,243	)

			Net cash provided by (used in) financing activities		81,824			(7,822	)
Net increase (decrease) in cash and cash equivalents				$	11,440		$	(6,331	)
Cash and cash equivalents, beginning of period					9,511			12,264

Cash and cash equivalents, end of period				$	20,951		$	5,933

Supplemental disclosure—cash paid for interest during the period				$	4,691		$	11,676

See accompanying notes to combined condensed financial statements.

PACIFIC ENERGY PARTNERS, L.P.

Successor to Pacific Energy (Predecessor)

NOTES TO COMBINED CONDENSED FINANCIAL STATEMENTS

September 30, 2002

(Unaudited)

1. Basis of Presentation

On July 26, 2002, Pacific Energy Partners, L.P. (the "Partnership") completed an initial public offering of common units representing limited partner interests in the Partnership. The Partnership, which was formed by The Anschutz Corporation ("TAC") in February 2002, and its subsidiaries are engaged in gathering, blending, transporting, storing and distributing crude oil.

TAC, through Pacific Energy GP, Inc., an indirect, wholly-owned subsidiary of TAC and the general partner of the Partnership (the "General Partner"), conveyed to the Partnership its ownership interests in Pacific Energy Group LLC ("PEG"), whose subsidiaries consist of (i) Pacific Pipeline System LLC ("PPS"), owner of Line 2000 and the Line 63 system, (ii) Pacific Marketing and Transportation LLC ("PMT"), (iii) Rocky Mountain Pipeline System LLC ("RMP"), owner of the Western Corridor system and the Salt Lake City Core system assets purchased from an affiliate of BP plc on March 1, 2002, (iv) Anschutz Ranch East Pipeline LLC ("AREPI"), owner of AREPI pipeline and successor to Anschutz Ranch East Pipeline, Inc., and (v) Ranch Pipeline LLC ("RPL"), the owner of a 22.22% partnership interest in Frontier Pipeline Company ("Frontier") and successor to Ranch Pipeline, Inc., in exchange for: (i) the continuation of its 2% general partner interest in the Partnership; (ii) incentive distribution rights (as defined in its partnership agreement); (iii) 1,865,000 common units; (iv) 10,465,000 subordinated units; and (v) the right to receive from the Partnership on the closing of the initial public offering a portion of the net proceeds from borrowings under PEG's term loan facility.

PPS, PMT, AREPI, RMP and RPL, each subsidiaries of PEG, collectively, constitute the Partnership's predecessor, which is referred to herein as "Pacific Energy (Predecessor)" or the "Predecessor". The financial data and results of operations of PPS, PMT, AREPI, RMP and RPL, are presented on a combined basis as the financial data and results of operations of the Partnership, the successor to Pacific Energy (Predecessor). The transfer of ownership interests in the entities that constitute Pacific Energy (Predecessor) to the Partnership represented a reorganization of entities under common control and was recorded at historical cost.

The unaudited combined condensed financial statements present the Partnership as a single entity, separate from TAC, during the periods presented. The 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 by accounting principles 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 nine months ended September 30, 2002 are not necessarily indicative of the results of operations for the full year. The financial data for the year ended December 31, 2001 is derived from the audited combined financial statements of Pacific Energy (Predecessor). The financial data for the three months and nine months ended September 30, 2002 and 2001 is derived from the unaudited combined financial statements of Pacific Energy (Predecessor), through July 25, 2002 and for the Partnership thereafter.

These financial statements should be read in conjunction with the Partnership's audited combined financial statements and notes thereto included in the Partnership's registration statement on Form S-1, as amended, (SEC File No.: 333-84812) dated July 22, 2002.

2. Description of Business History

PEG was formed in August 2001, and at September 30, 2002 owned 100% of PPS, PMT, RMP, AREPI and RPL. PPS owns and operates Line 2000 and the Line 63 system. Line 2000 is a 130-mile crude oil pipeline that extends from Kern County in the San Joaquin Valley of California to the Los Angeles Basin where it has direct and indirect connections to various refineries and terminal facilities. Line 2000 has permitted annual average throughput capacity of 130,000 barrels per day ("bpd").

In 1999, ARCO Midcon, formerly ARCO Pipe Line Company ("APL"), exchanged its Line 63 system assets for a 26.5% ownership interest in PPS and a note of $63.6 million. On June 7, 2001, APL made a capital contribution of $63.6 million to PPS. PPS Holding Company, a wholly owned subsidiary of TAC and an affiliate of the Partnership ("Holding"), then purchased APL's ownership interest in PPS for $47.0 million in cash and PPS repaid the $63.6 million note. This purchase of an additional ownership interest resulted in negative goodwill of $37.8 million, which was allocated proportionately to reduce property, plant and equipment of PPS.

The Line 63 system includes a 107-mile crude oil pipeline capable of shipping approximately 105,000 bpd from the San Joaquin Valley to various refineries and delivery points in the Los Angeles Basin. The Line 63 system also includes approximately 1.2 million barrels of storage capacity as well as various gathering and distribution lines in the San Joaquin Valley, crude oil distribution lines in the Los Angeles Basin and a distribution facility located in the Los Angeles Basin.

PMT was formed in June 2001, in connection with the purchase of certain assets in the San Joaquin Valley from EOTT Energy Operating Limited Partnership for approximately $14.4 million. The assets acquired consist of 122 miles of intrastate crude oil gathering pipelines and six storage and blending facilities with approximately 254,000 barrels of storage capacity and blending capacity of up to 65,000 bpd as well as a base stock of crude oil. The purchase price was allocated among the fair values of the assets acquired and no goodwill resulted from this acquisition. The purchase price is subject to adjustment pursuant to a defined calculation based on gross margin for the 24 months following the acquisition. Depending on the amount of this cash flow, the purchase price could decrease by up to $1.5 million or increase by up to $7.5 million. Based on such cash flows through September 30, 2002, management does not presently expect that any additional consideration will be paid.

RMP was formed in December 2001 in connection with the March 1, 2002 acquisition of certain pipeline and related assets located in the Rocky Mountain region from an affiliate of BP plc for approximately $107.0 million. The assets acquired consist of various ownership interests in 1,925 miles of intrastate and interstate crude oil transportation pipelines, 209 miles of gathering pipelines and 29 storage tanks with approximately 1.4 million barrels of storage capacity. The purchase price was allocated among the fair values of the assets acquired, and no goodwill resulted from this acquisition.

AREPI, which was transferred to PEG on July 12, 2002 in preparation for the Partnership's initial public offering, owns and operates a 42-mile crude oil pipeline with a throughput capacity of approximately 52,500 bpd. This pipeline originates 21 miles south of Evanston, Wyoming at Ranch Station, Utah where it connects with the Frontier pipeline (discussed below) and terminates at Kimball Junction, Utah, where it connects with a ChevronTexaco pipeline that serves the Salt Lake City refineries.

RPL, which was transferred to PEG on March 1, 2002 in preparation for the Partnership's initial public offering, owns a 22.22% partnership interest in Frontier, a Wyoming general partnership, which owns Frontier pipeline. RPL owned a 12.5% partnership interest in Frontier until December 2001 at

which time it acquired an additional 9.72% partnership interest from an affiliate of BP plc for $8.6 million. Frontier pipeline is a 290-mile pipeline with a throughput capacity of approximately 62,200 bpd that originates in Casper, Wyoming and delivers crude oil to AREPI pipeline and the Salt Lake City Core system.

3. Significant Accounting Policies

Revenue Recognition

Transportation revenue is recognized when the transported crude oil volumes are delivered to a tariff destination point.

The California Public Utilities Commission ("CPUC") regulates PPS's common carrier crude oil pipeline operations. Tariffs on Line 2000 are market-based, meaning such tariffs are established based on market considerations subject to certain contractual constraints. Tariffs on Line 63 are cost-of-service based, meaning such tariffs are developed based on the various costs to operate and maintain the pipeline as well as a charge for depreciation of the capital investment in the pipeline and an authorized rate of return.

AREPI is a common carrier pursuant to the regulations of the Federal Energy Regulatory Commission ("FERC"). AREPI transports crude oil under various cost-based tariffs at published rates, depending on the type and quality of the crude oil.

RMP is an interstate and intrastate common carrier pipeline, and its tariffs are regulated by the FERC and the Wyoming Public Service Commission, respectively.

Crude oil sales are recognized when the crude oil is delivered to the purchaser.

Transition Costs

Transition costs include one-time costs incurred by us in connection with the transition of the operations of acquired assets from the seller to us and one-time payments made to BP and EOTT to provide certain interim operations support and financial system services related to the acquisitions of BP's Western Corridor system and the Salt Lake City Core system assets and EOTT's gathering and blending assets.

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 sales of crude oil. The Partnership does not engage in speculative derivative activities of any kind. Derivative instruments are included in other assets in the accompanying balance sheets. Changes in the fair value of the Partnership's derivatives related to crude oil sales are recognized in net income. For the nine months ended September 30, 2002, operating expenses include $226,000 related to changes in the fair value of PMT's derivative instruments for its marketing activities and pipeline transportation revenues are net of $184,000 related to changes in the fair value of PPS's derivative instruments for its pipeline loss allowance inventory.

recorded in other comprehensive losses, a component of partners' capital, but not reflected in the combined condensed statements of operations. For the nine months ended September 30, 2002, other comprehensive losses include $6.8 million related to the effective portion of derivative losses due to changes in the fair market value of these swap agreements.

Environmental Remediation

The Partnership accrues environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable in the future and may be reasonably estimated. These accruals are undiscounted and are based on information currently available, existing technology, the estimated timing of remedial actions, related inflation assumptions and enacted laws and regulations.

Accounting Pronouncements

On July 30, 2002, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 146 ("SFAS 146"), "Accounting for Costs Associated with Exit or Disposal Activities". SFAS 146 nullifies Emerging Issues Task Force ("EITF") Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." It requires that a liability be recognized for those costs only when the liability is incurred, that is, when it meets the definition of a liability in the FASB's conceptual framework. SFAS 146 also establishes fair value as the objective for initial measurement of liabilities related to exit or disposal activities. SFAS 146 is effective for exit or disposal activities that are initiated after December 31, 2002, with earlier adoption encouraged. The Partnership does not expect that the adoption of SFAS 146 will have a material impact on its financial position or results of operations.

In April 2002, the FASB issued Statement of Financial Accounting Standards No. 145, ("SFAS 145"), "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". The rescission of FASB Statement No. 4, "Reporting Gains and Losses from Extinguishment of Debt," ("Statement 4") and FASB Statement No 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements", which amended Statement 4, will affect income statement classification of gains and losses from extinguishment of debt. Upon adoption, enterprises must reclassify prior period items that do not meet the extraordinary item classification criteria in Accounting Principles Bulletin No. 30, "Reporting the Results of Operations". The provisions of SFAS 145 related to the rescission of Statement 4 are applicable in fiscal years beginning after May 15, 2002, with early application encouraged. The provisions of SFAS 145 related to FASB Statement No. 13, "Accounting for Leases," are effective for transactions occurring after May 15, 2002, with early application encouraged. All other provisions of SFAS 145 are effective for financial statements issued on or after May 15, 2002, with early application encouraged. The Partnership does not expect that the adoption of SFAS 145 will have a material impact on its financial position or results from operations.

Effective January 1, 2002, the Partnership adopted Statement of Financial Accounting Standards No. 144 ("SFAS 144"), "Accounting for the Impairment or Disposal of Long-Lived Assets," which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. While SFAS 144 supersedes Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," it retains many of the fundamental provisions of that statement. The adoption of this standard did not have a material impact on the Partnership's financial position or results of operations in 2002.

The Partnership also adopted Statement of Financial Accounting Standards No. 141 ("SFAS 141"), "Business Combinations," and Statement of Financial Accounting Standards No. 142 ("SFAS 142"), "Goodwill and Other Intangible Assets" on January 1, 2002. SFAS 141 requires that the purchase

method be used for all business combinations initiated after June 30, 2001. SFAS 142 requires that goodwill no longer be amortized to earnings, but instead be reviewed for impairment. The adoption of these standards did not have a material impact on the Partnership's financial position or results of operations in 2002.

In August 2001, the FASB issued Statement of Financial Accounting Standards No. 143 ("SFAS 143"), "Accounting for Asset Retirement Obligations". This statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which the liability is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard is effective for fiscal years beginning after June 15, 2002, with earlier adoption encouraged. The Partnership is currently evaluating the effect of adopting SFAS 143 on its financial position and results of operations.

4. Pending Acquisition

In February 2002, Holding, the General Partner's parent company, entered into an asset purchase agreement to acquire the crude oil terminal and pipeline assets of Edison Pipeline & Terminal Company ("EPTC"), a division of Southern California Edison Company (the "EPTC Assets") for approximately $158.2 million, plus potential increases for certain pre-closing adjustments, estimated to be $5.0 million to $10.0 million. This acquisition is subject to approval of the CPUC and the satisfaction of other conditions and is not expected to close until the first quarter of 2003. The EPTC Assets are located in the Los Angeles Basin. The purchase agreement was assigned to Pacific Terminals LLC, a wholly owned subsidiary of Holding. Pursuant to that certain Omnibus Agreement dated July 26, 2002, by and among the Partnership, Holding and certain other parties, Holding will contribute Pacific Terminals LLC to the Partnership prior to the completion of the acquisition of the EPTC Assets. The Partnership intends to finance this acquisition with a combination of proceeds from the issuance of additional units, including common units, and borrowings under PEG's revolving credit facility (see Note 8, Long-term Debt).

5. Related Party Transactions

A subsidiary of TAC is a shipper on Line 2000 and is charged published tariff rates. The Partnership charged this subsidiary approximately $1.8 million during the nine months ended September 30, 2002 and $171,000 during the nine months ended September 30, 2001. This subsidiary entered into agreements with a third party to purchase crude oil, ship it on Line 2000, and sell it in the Los Angeles Basin. The amounts included in accounts receivable were $293,000 at September 30, 2002 and $75,000 at December 31, 2001. As an original sponsor of the Line 2000 project, TAC and its subsidiaries qualify for participating shipper tariff rates on the pipeline.

An affiliate of TAC is a shipper on AREPI pipeline and is charged published tariff rates. The Partnership charged this affiliate transportation fees of $23,000 during the nine months ended September 30, 2002 and $26,000 during the nine months ended September 30, 2001.

APL owned a 26.5% ownership interest in PPS from May 1, 1999 through June 7, 2001 and was a related party of the Partnership during this period. The Partnership has entered into various agreements with APL whereby APL has provided operating services to the Partnership and leased facility space from the Partnership. The Partnership and APL also share certain facilities that support the operations of both companies. The cost of operating the shared facilities are allocated based on the percentage benefit obtained by each of the Partnership and APL. The Partnership paid APL $190,000 during the nine months ended September 30, 2002, and $184,000 for the nine months ended

September 30, 2001. The Partnership received $138,000 from APL during the nine months ended September 30, 2002 and $137,000 for the nine months ended September 30, 2001.

Prior to April 1, 2002, TAC employed various personnel who worked directly on AREPI pipeline and provided other executive, accounting and administrative support. These employees continue to provide services to AREPI pipeline, but are now employed by the General Partner. For the nine months ended September 30, 2002, TAC charged the Partnership approximately $46,000 for salaries of the pipeline-related personnel and for various support services. For the nine months ended September 30, 2001, TAC charged the Partnership approximately $135,000 for salaries of the pipeline-related personnel and for various support services.

On December 31, 2001, AREPI declared and paid dividends to TAC of $2.9 million. These dividends represented the amount of receivables due from TAC and its subsidiaries immediately prior to the dividends. For the nine months ended, September 30, 2002, PEG paid distributions to TAC of $16.0 million.

PEG serves as the contract operator for Anschutz Wahsatch Gathering System, Inc. ("AWGS"), a wholly owned subsidiary of TAC that owns a natural gas gathering system in Wyoming. PEG provides executive and operating support required for AWGS. AWGS reimburses PEG for the salary and benefit costs incurred by the direct assigned field operating and maintenance personnel related to AWGS operations. In addition, AWGS pays an annual management fee of $300,000 to reimburse PEG for the portion of time spent by management and for other services, such as purchasing and engineering, as well as for other corporate overhead incurred by PEG related to AWGS activities. During the nine months ended September 30, 2002, PEG earned $225,000 in management fees, all of which was included in accounts receivable as of September 30, 2002.

RMP is the operator of Frontier pipeline and performs certain management services on behalf of Frontier and earns management fees of $48,000 monthly, as adjusted for changes in the Producers' Price Index for industrial commodities and changes in the annual average wage for field personnel. During the nine months ended September 30, 2002, RMP earned $431,000 in management fees.

At December 31, 2001 and July 26, 2002, TAC was providing letter-of-credit support for PMT activities totaling approximately $21.3 million and $15.8 million, respectively. PMT reimbursed TAC for its cost of providing these letters of credit. Following the formation of the Partnership, such letters of credit were replaced by letters of credit under the Partnership's $200.0 million revolving credit facility, which at September 30, 2002, totaled $15.6 million.

6. Right-of-Way Obligations

Pursuant to an easement agreement, Union Pacific Corporation ("UPC") provides the Partnership with access to its right-of-way for a portion of Line 2000 in return for an annual fee. The Partnership paid UPC fees under this agreement of $1.7 million during the nine months ended September 30, 2002. The agreement provides for an easement, subject to a rental revision every five years based on a prescribed formula. The annual rental was subject to this revision on March 31, 2002. As of November 14, 2002, the rental revision had not been finalized. TAC owns less than 3% of UPC.

7. Partners' Capital

On July 26, 2002, the Partnership completed its initial public offering of 8,600,000 common units representing limited partner interests at a price of $19.50 per common unit. Total proceeds from the sale of the 8,600,000 units were $167.7 million, before offering costs and underwriting commissions. Concurrent with the closing of the initial public offering, PEG, the Partnership's operating company, entered into a $425.0 million credit agreement with a syndicate of financial institutions led by Fleet National Bank, that provides for a five-year $200.0 million senior secured revolving credit facility and a

seven-year $225.0 million senior secured term loan facility. On July 26, 2002, PEG borrowed $225.0 million under the term loan facility. The $200.0 million revolving credit facility is currently undrawn except for the letters of credit totaling $15.6 million at September 30, 2002. (See Note 8, Long-term Debt)

A summary of the proceeds received from these two transactions and the use of those proceeds is as follows (in millions):

*Proceeds received:*
	Sale of common units		$	167.7
	Borrowing under term loan facility			225.0

		Total proceeds received	$	392.7

*Use of proceeds from sale of common units:*
	Underwriting discount		$	11.5
	Professional fees and other offering costs			2.5
	Repayment of debt			153.7

		Total use of proceeds from the sale of common units		167.7

*Use of proceeds from term loan facility:*
	Debt issuance costs and related expenses			5.3
	Repayment of debt			114.6
	Distribution to General Partner			105.1

		Total use of proceeds from term loan facility		225.0

		Total use of proceeds	$	392.7

8. Long-term Debt

The Partnership's long-term debt obligations at December 31, 2001, shown below, were refinanced in July 2002 in connection with the Partnership's initial public offering of common units and its borrowing under PEG's $225.0 million term loan facility (in millions):

	September 30, 2002		December 31, 2001
Note Payable to Citibank	$	—	$	176.4
Note Payable to Affiliate		—		4.9
Senior Secured Term Loan Facility		225.0		—

	$	225.0	$	181.3

The $200.0 million revolving credit facility is available for general partnership purposes, including working capital, letters of credit and distributions to unitholders and to finance future acquisitions, including the pending acquisition of the EPTC Assets (see Note 4, Pending Acquisition). The revolving credit facility has a borrowing sublimit of $45.0 million for working capital, letters of credit and partnership distributions to unitholders.

The revolving credit facility matures on July 26, 2007, at which time all outstanding amounts will be due and payable. The Partnership will be required to amortize amounts outstanding under the term loan facility on a quarterly basis at 1% per annum, beginning in 2005 with the first quarterly payment due September 2005. A 97% balloon payment will be due at maturity in July 2009.

The facilities are guaranteed by the Partnership and certain of PEG's operating subsidiaries. The revolving credit facility and the term loan facility are both fully recourse to PEG and the guarantors,

but non-recourse to the General Partner. Obligations under the revolving credit facility and the term loan facility are secured by pledges of membership interests in and the assets of PEG's operating subsidiaries, subject to certain limited exceptions.

Indebtedness under the facilities bear interest at the Partnership'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% (each plus an applicable margin ranging from 0% to 0.50% for the revolving credit facility and ranging from 0.50% to 0.75% for the term loan facility) or (ii) LIBOR plus an applicable margin ranging from 1.25% to 2.50% for the revolving credit facility and ranging from 2.50% to 2.75% for the term loan facility. The applicable margins are subject to change based on the credit rating of the facilities or, if they are not rated, the credit rating of PEG. For a period of time subsequent to the completion of the acquisition of the EPTC Assets, as specified in the credit agreement, the applicable margin will increase by a margin which ranges from 0.375% to 0.625%. PEG will incur a per annum commitment fee margin which ranges from 0.25% to 0.50% in connection with the revolving credit facility. 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 certain of its subsidiaries to, among other things, incur or guarantee indebtedness, change ownership or structure, including consolidations, liquidations and dissolutions and enter into a new line of business.

At September 30, 2002, the Partnership had letters of credit totaling $15.6 million, for PMT activities, which were supported by the Partnership's new $200.0 million revolving credit facility. The details of the debt obligations at December 31, 2001 are set forth in the financial statements and notes thereto contained in the Partnership's registration statement on Form S-1, as amended, filed with the SEC and effective July 22, 2002.

As of September 30, 2002, PEG has entered into five seven-year interest rate swap agreements totaling $140.0 million and two five-year interest rate swap agreements totaling $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 the term loan facility. The average swap rate on this $170.0 million of debt is approximately 4.25% resulting in an all-in interest rate on the $170.0 million of approximately 7.00% (including the current applicable margin of 2.75%). Changes in the fair value of derivatives designated for hedging activities are recorded in other comprehensive losses, a component of partners' capital, but not reflected in the combined condensed statements of operations. For the nine months ended September 30, 2002, other comprehensive losses include $6.8 million related to the effective portion of derivative losses due to changes in the fair market value of these swap agreements.

9. Segment Information

The Partnership's business and operations are organized into two regional operating units: West Coast operations and Rocky Mountain operations. Information regarding these two operating units is summarized below:

		West Coast		Rocky Mountain		Total
		(unaudited) (in thousands)
Nine Months Ended September 30, 2002
Transportation revenues:
	Unaffiliated customers	$	46,435	$	26,693	$	73,128
	Affiliates		1,862		401		2,263
Crude oil sales, net			14,904		—		14,904
Share of net income of Frontier			—		966		966
Depreciation			8,387		3,324		11,711
Operating income			25,156		8,711		33,867
Capital expenditures			2,102		1,359		3,461
Identifiable assets			362,616		135,656		498,272
Nine Months Ended September 30, 2001
Transportation revenues:
	Unaffiliated customers	$	46,186	$	3,846	$	50,032
	Affiliates		171		17		188
Crude oil sales, net			4,013		—		4,013
Share of net income of Frontier			—		1,183		1,183
Depreciation			8,385		354		8,739
Operating income			15,960		3,088		19,048
Capital expenditures			3,740		54		3,794
Identifiable assets			375,327		8,285		383,612

10. Commitments and Contingencies

In March 2002, AREPI settled a rate case litigation matter that was before the FERC. Two shippers had filed complaints challenging rates contained in a joint tariff in which AREPI was a participating joint carrier as well as the rates contained in local tariffs filed by AREPI. AREPI recorded a provision in 2001 of $1.5 million related to this settlement, which was paid in 2002.

The Partnership is subject to numerous federal, state and local laws which regulate the discharge of materials into the environment or that otherwise relate to the protection of the environment. The Partnership currently has known environmental conditions that will require remediation. The accrued liability for environmental remediation for known conditions was $2.6 million at December 31, 2001 and September 30, 2002 and was classified in the combined balance sheets within other liabilities.

The total future costs for environmental remediation activities will depend on, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the technology available and required to meet the various existing legal requirements, the nature and extent of future environmental laws, inflation rates and the determination of the Partnership's liability at multi-party sites, if any, in light of uncertainties with respect to joint and several liability and the number, participation levels and financial viability of other parties.

Although the Partnership may, from time to time, be involved in various litigation and claims arising out of its operations in the normal course of business, the Partnership is not currently a party to

any legal proceedings, the resolution of which the Partnership expects to have a material adverse effect on its business, financial position, results of operations or liquidity.

11. Subsequent Event

On October 18, 2002, the Partnership declared an initial pro-rated cash distribution of $0.3368 per limited partner unit, payable on November 14, 2002 to unitholders of record as of October 31, 2002. This distribution is equivalent to a full-quarter distribution of $0.4625 per limited partner unit pro-rated for the period from July 26, 2002, the date of closing of the initial public offering of common units, through September 30, 2002.

ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

References in this quarterly report on Form 10-Q to "Pacific Energy Partners", "Partnership", "we", "ours", "us" or like terms refer to Pacific Energy Partners, L.P. and its subsidiaries.

Forward-Looking Statements

The information in this quarterly report on Form 10-Q includes forward-looking statements. All statements, other than statements of historical facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in our registration statement on Form S-1, as amended, filed with the Securities and Exchange Commission ("SEC") and effective July 22, 2002.

Forward-looking statements appear in a number of places and include statements with respect to, among other things:

•: forecasts of our ability to make cash distributions on the units;
•: consummation of our pending acquisition of the Edison Pipeline and Terminal Company ("EPTC") assets and any expected benefits associated with that acquisition;
•: future crude oil prices and production;
•: planned capital expenditures and availability of capital resources to fund capital expenditures;
•: future supply of, and demand for, crude oil and refined products;
•: expected throughput for our pipeline systems;
•: our future financial condition or results of operations and our future revenues and expenses;
•: any expected results or benefits associated with our relationship with The Anschutz Corporation ("TAC"); and
•: our business strategy and other plans and objectives for future operations.

We caution you that the forward-looking statements in this quarterly report on Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to gathering, blending, transporting, storing and distributing crude oil. These risks include the risks described in our registration statement on Form S-1, as amended. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

Introduction

The following discussion of the financial condition and results of operations of Pacific Energy Partners, the successor to Pacific Energy (Predecessor) (as defined below) should be read together with the combined financial statements and the notes thereto set forth elsewhere in this report. The discussion set forth in this section pertains to the combined financial position, results of operations and cash flows of, as well as equity investment in, the Partnership and its 100% ownership interest in Pacific Energy Group LLC ("PEG") whose subsidiaries consist of (i) Pacific Pipeline System LLC ("PPS"),

owner of Line 2000 and the Line 63 system, (ii) Pacific Marketing and Transportation LLC ("PMT"), (iii) Rocky Mountain Pipeline System LLC ("RMP"), owner of the Western Corridor system and the Salt Lake City Core system assets purchased from an affiliate of BP plc on March 1, 2002, (iv) Anschutz Ranch East Pipeline LLC ("AREPI"), owner of AREPI pipeline and successor to Anschutz Ranch East Pipeline, Inc., and (v) Ranch Pipeline LLC ("RPL"), the owner of a 22.22% partnership interest in Frontier Pipeline Company ("Frontier") and successor to Ranch Pipeline, Inc. PPS, PMT, RMP, AREPI and RPL, are subsidiaries of PEG and together constitute our predecessor, which is referred to herein as "Pacific Energy (Predecessor)" or the "Predecessor". The financial data and results of operations of each of PPS, PMT, RMP, AREPI and RPL are presented on a combined basis as our financial data and results of operations as successor to Pacific Energy (Predecessor). This discussion does not include any financial data from the EPTC assets we expect to acquire from Southern California Edison Company in the first quarter of 2003.

Overview

We are engaged in the business of gathering, blending, transporting, storing and distributing crude oil. We conduct our business through two regional operating units: West Coast operations and Rocky Mountain operations. Our West Coast operations consist primarily of transporting crude oil produced in the San Joaquin Valley and the California Outer Continental Shelf to refineries and terminal facilities in the Los Angeles Basin and Bakersfield through our two intrastate common carrier crude oil pipelines, Line 2000 and the Line 63 system. Our West Coast operations also include an intrastate proprietary crude oil gathering and blending system located in the San Joaquin Valley, through which we are engaged in the gathering, blending and marketing of crude oil that is generally delivered into our Line 63 system. Our Rocky Mountain operations consist of the Western Corridor system, the Salt Lake City Core system, AREPI pipeline and RPL's interest in Frontier pipeline.

We generate revenues primarily by charging a tariff for transporting crude oil on our pipelines. The amount of revenue we generate depends on the level of these tariff rates and the amount of throughput on our pipelines. The amount of throughput is dependent upon the availability of crude oil in the producing fields and the demand for the crude oil in the refining markets served by our pipelines. Our customers, or shippers, are primarily refiners that purchase crude oil and transport it on our pipelines for ultimate delivery to their refineries. Some of our customers are required to transport minimum volumes of crude oil annually.

The tariff rates are charged to the customer upon delivery of the crude oil to its ultimate delivery point. The tariff rates charged on Line 2000 and Line 63 are regulated by the California Public Utilities Commission. Line 2000 has market-based tariff rates. Competition, as well as certain contractual limitations, determine the tariff rates we charge on Line 2000. Tariff rates on Line 63 are established using a cost-based methodology, which, among other things, allows for a regulated rate of return on the depreciated, historical cost of the assets.

The tariff rates charged on AREPI pipeline and Frontier pipeline are regulated by the Federal Energy Regulatory Commission ("FERC") under a cost-based rate methodology. Pursuant to recent settlements of tariff rate case litigation before the FERC, AREPI and Frontier agreed to reduce certain local tariff rates on AREPI pipeline and Frontier pipeline as well as their respective portions of the post-complaint rates under a joint tariff that had been filed by Express pipeline (which was subsequently cancelled). The FERC and the Wyoming Public Service Commission regulate tariffs on the Western Corridor and Salt Lake City Core systems on a cost-based methodology. We also purchase crude oil produced in the San Joaquin Valley for subsequent blending, transportation and resale primarily in the Los Angeles Basin.

Generally, the operating expenses we incur are relatively unrelated to throughput and include maintenance, insurance, control systems, telecommunications, field and support personnel, rights-of-way

and depreciation. Other operating expenses, such as fuel and power costs to run the various pump stations along our pipelines, fluctuate with throughput.

The Partnership does not have any employees; all employees are employed by our general partner, Pacific Energy GP, Inc. (the "General Partner"). Therefore, all direct general and administrative expenses incurred by our General Partner will be charged to us as incurred. In addition, the General Partner also provides personnel and services to PEG, the contract operator of the Anschutz Wahsatch Gathering System and to RMP, the contract operator for Frontier. TAC will continue to provide certain services to us. All direct and reasonable costs incurred by TAC, on our behalf, will be charged to us.

This report on Form 10-Q should be read in conjunction with the Partnership's registration statement on Form S-1, as amended, filed with the SEC in connection with our initial public offering which closed July 26, 2002. Our registration statement includes a discussion of risk factors to which reference is also made.

Results of Operations

The table below sets forth certain unaudited segment operating results by regional operating unit for the three and nine months ended September 30, 2002 and 2001:

			Three Months Ended September 30,				Nine Months Ended September 30,
			2002		2001		2002		2001
			(Unaudited) (in thousands)
Segment Operating Income
	*West Coast Operations*
	Pipeline transportation revenues:
		Unaffiliated customers	$	15,090	$	14,727	$	46,435	$	46,186
		Affiliates		190		—		1,862		171

	Total pipeline transportation revenues			15,280		14,727		48,297		46,357
	Crude oil sales, net of purchases			4,770		4,013		14,904		4,013

	Net revenues before operating expenses			20,050		18,740		63,201		50,370

	Expenses:
		Operating		7,641		9,553		25,217		23,487
		General and administrative		1,899		837		4,315		2,424
		Transition costs		10		114		126		114
		Depreciation		2,894		2,692		8,387		8,385

	Total expenses			12,444		13,196		38,045		34,410

	Operating income		$	7,606	$	5,544	$	25,156	$	15,960

	*Rocky Mountain Operations*
	Pipeline transportation revenues:
		Unaffiliated customers	$	11,315	$	1,239	$	26,693	$	3,846
		Affiliates		7		—		401		17

	Total pipeline transportation revenues			11,322		1,239		27,094		3,863
	Expenses:
		Operating		5,192		349		11,883		996
		General and administrative		439		164		1,592		608
		Transition costs		689		—		2,550		—
		Depreciation		1,413		117		3,324		354

	Total expenses			7,733		630		19,349		1,958

	Share of net income of Frontier			471		406		966		1,183

	Operating income		$	4,060	$	1,015	$	8,711	$	3,088

		Three Months Ended September 30,		Nine Months Ended September 30,
		2002	2001	2002	2001
		(Unaudited) (bpd, in thousands)
Segment Volumes
	*West Coast Operations*
	Pipeline throughput	153.7	150.8	165.2	155.5
	Gathered and blended volumes	40.5	39.1	40.0	39.1
	*Rocky Mountain Operations*
	Salt Lake City Core system throughput	74.1	—	71.7	—
	Western Corridor system throughput	13.4	—	15.1	—
	AREPI pipeline throughput	46.7	43.3	48.7	40.0
	Frontier pipeline throughput	46.6	40.7	44.2	38.7

Three Months Ended September 30, 2002 Compared to Three Months Ended September 30, 2001

Our combined net income was $8.4 million in the third quarter of 2002 compared with $4.7 million in the third quarter of 2001. The 2002 third quarter results include the benefit of the acquisition of the PMT assets on July 1, 2001 and the acquisition of the Western Corridor system and Salt Lake City Core system assets on March 1, 2002, as well as higher volumes and tariffs on Line 2000 and the Line 63 system.

Pipeline Transportation Revenues. Combined pipeline transportation revenues totaled $26.6 million for the three months ended September 30, 2002 compared to $16.0 million for the comparable period in 2001, an increase of $10.6 million, or 66%. This increase was associated primarily with our Rocky Mountain operations, where revenues increased by $10.1 million compared to the comparable period in 2001 due to revenue generated by the Western Corridor system and the Salt Lake City Core system assets which were acquired on March 1, 2002. In addition, pipeline transportation revenue from our West Coast operations increased by $553,000, compared to the comparable period in 2001. The West Coast pipeline transportation revenue increase was due to an increase in long-haul throughput volumes of approximately 2,900 barrels per day ("bpd"), or 2%, and an increase in average tariff rates. Strong refinery demand for crude oil by the Los Angeles Basin refiners and the absence of any significant refinery or production outages account for the increased volumes compared to 2001.

Crude Oil Sales, net. On July 1, 2001, we acquired the PMT gathering and blending system from EOTT, which generated net revenue before operating expenses for the three months ended September 30, 2002 of $4.8 million on total sales of $99.6 million. For the three months ended September 30, 2001, PMT generated net revenue before operating expenses of $4.0 million on total sales of $92.8 million. We consider this activity to be ancillary to our pipeline transportation operations.

Operating Expenses. Combined operating expenses totaled $12.8 million for the three months ended September 30, 2002 compared to $9.9 million for the comparable period in 2001, an increase of $2.9 million or 29%. Our Rocky Mountain operations had a $4.8 million increase in operating expenses, which was offset by a $1.9 million decrease in operating expenses for our West Coast operations. The increase in operating expenses related to our Rocky Mountain operations was due to the operating expenses associated with the Western Corridor system and the Salt Lake City Core system assets, acquired on March 1, 2002.

General and Administrative Expense. Combined general and administrative ("G&A") expenses were $2.3 million for the three months ended September 30, 2002 compared to $1.0 million for the comparable period in 2001, an increase of $1.3 million, or 130%. G&A expenses associated with our West Coast operations accounted for $1.1 million of this increase and were attributable to several

factors including additional corporate development expenses associated with staff additions to investigate and pursue strategic acquisitions and growth projects and incremental G&A associated with the PMT gathering and blending system. The remainder of the increase is associated with our Rocky Mountain operations, primarily due to the acquisition of the Western Corridor system and the Salt Lake City Core system assets.

Depreciation and Amortization Expenses. Combined depreciation and amortization expense was $4.3 million for the three months ended September 30, 2002, compared to $2.8 million for the comparable period in 2001, an increase of $1.5 million, or 54%. Depreciation expense associated with the Rocky Mountain assets increased by $1.3 million due to the acquisition of the Western Corridor system and the Salt Lake City Core system assets.

Interest Expense. Interest expense was $3.5 million for the three months ended September 30, 2002, compared to $2.0 million for the comparable period in 2001, an increase of $1.5 million, or 75%. This increase was due to larger average daily debt balances as well as higher average borrowing rates partially due to the interest rate swap agreements. The interest rate on outstanding borrowings during the three months ended September 30, 2002 averaged 5.9% compared to 4.6% during the comparable period in 2001. The average daily debt balance was $237.2 million during the three months ended September 30, 2002 as compared to $176.4 million in the comparable period of 2001, due to additional borrowings on March 1, 2002 related to the acquisition of the Western Corridor system and the Salt Lake City Core system assets.

Share of Net Income of Frontier. Our share of net income of Frontier was $471,000 for the three months ended September 30, 2002, compared to $406,000 for the comparable period in 2001. This increase was due to the increase in December 2001 in our ownership interest from 12.5% to 22.22% which offset the effects of lower tariff rates in 2002.

Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30, 2001

Combined net income for the nine-month period ending September 30, 2002 was $27.2 million compared with $11.1 million for the comparable period in 2001. This $16.1 million improvement was due to the ownership of the PMT assets for the full nine-month period in 2002 compared to only three months in 2001 (the assets were acquired on July 1, 2001), and the acquisition of the Western Corridor system and Salt Lake City Core system assets on March 1, 2002, higher volumes and tariffs on Line 2000 and the Line 63 system and lower interest expense.

Pipeline Transportation Revenues. Combined pipeline transportation revenues totaled $75.4 million for the nine months ended September 30, 2002 compared to $50.2 million for the comparable period in 2001, an increase of $25.2 million, or 50%. This increase was associated primarily with our Rocky Mountain operations, where revenues increased by $23.2 million due to revenue generated by the Western Corridor system and the Salt Lake City Core system assets. In addition, pipeline transportation revenue from our West Coast operations increased by $1.9 million compared to the comparable period in 2001. West Coast revenues during the six months ended September 30, 2002 are net of a $2.9 million elimination related to pipeline transportation revenues that were previously charged to EOTT as a third party during the first six months of 2001. The West Coast pipeline transportation revenue increase was due to the increase in long-haul throughput volumes of approximately 9,700 bpd, or 6%, and an increase in average tariff rates. Strong refinery demand for crude oil by the Los Angeles Basin refiners and the absence of any significant refinery or production outages in our delivery market account for the increased volumes compared to 2001.

Crude Oil Sales, net. On July 1, 2001, we acquired the PMT gathering and blending assets which generated net revenue before operating expenses for the nine-month period ended September 30, 2002 of $14.9 million on total sales of $250.9 million. For the nine months ended September 30, 2001, PMT

generated net revenue before operating expenses of $4.0 million on total sales of $92.8 million. We consider this activity to be ancillary to our pipeline transportation operations.

Operating Expenses. Combined operating expenses totaled $37.1 million for the nine months ended September 30, 2002 compared to $24.5 million for the comparable period in 2001, an increase of $12.6 million, or 51%. This increase was related primarily to our Rocky Mountain operations where operating expenses increased by $10.9 million due to the acquisition of the Western Corridor system and the Salt Lake City Core system assets. Operating expenses for our West Coast operations increased by $1.7 million. This increase was principally due to field operating, blending, trucking and marketing expenses related to our PMT gathering and blending system.

General and Administrative Expense. Combined G&A expenses were $5.9 million for the nine months ended September 30, 2002 compared to $3.0 million for the comparable period in 2001, an increase of $2.9 million, or 97%. The $1.9 million increase in G&A expenses associated with our West Coast operations related to corporate development expenses and expenses relating to our gathering and blending operations, while the acquisition of the Western Corridor system and the Salt Lake City Core system assets accounts for the increase in our Rocky Mountain operations.

Depreciation Expense. Combined depreciation expense was $11.7 million for the nine months ended September 30, 2002 compared to $8.7 million during the comparable period in 2001, an increase of $3.0 million or 34%. This increase consists of $3.0 million related to the acquisition of the Western Corridor and the Salt Lake City core system assets.

Interest Expense. Interest expense was $7.4 million for the nine months ended September 30, 2002 compared to $8.6 million for the comparable period in 2001, a decrease of $1.2 million or 14%. This decrease was due to lower average borrowing rates during the first nine months of 2002 offset by an increase in the average daily debt balances. The interest rate on outstanding borrowings during the nine months ended September 30, 2002 averaged 4.1% compared to 5.4% for the comparable period in 2001. The average daily debt balance was $239.1 million during the nine months ended September 30, 2002 as compared to $213.0 million in the comparable period of 2001. This increase was due to the additional borrowings on March 1, 2002 of $87.0 million related to the acquisition of the Western Corridor system and the Salt Lake City Core system assets partially offset by the repayment of $63.6 million on June 7, 2001 in conjunction with our acquisition of ARCO Pipe Line Company's 26.5% ownership interest in PPS.

Share of Net Income of Frontier. Our share of Frontier's net income was $966,000 for the nine months ended September 30, 2002 compared to $1.2 million for the comparable period in 2001. This decrease was due to lower tariff revenue and payment of rate case settlement costs by Frontier which were partially offset by the increase in our ownership interest from 12.5% to 22.22% in December 2001.

Liquidity and Capital Resources

Historically, we have satisfied our working capital requirements and funded our capital expenditures with cash generated from operations and affiliate and third-party borrowings. We believe that cash generated from operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated maintenance capital expenditures and scheduled debt payments. We expect to fund any future acquisitions with the proceeds of borrowings under our revolving credit facility and the issuance of additional units. Our ability to satisfy our debt service obligations, fund planned capital expenditures, make acquisitions and pay distributions to our unitholders will depend upon our future operating performance. Our operating performance is primarily dependent on the volume of crude oil we transport, which could be affected by a decrease in the volume of crude oil produced from the oil fields or processed by the refineries served by our pipelines. These factors, which

are affected by prevailing economic conditions in the crude oil industry and financial, business and other factors, some of which are beyond our control, could significantly impact future results.

On October 18, 2002, we declared an initial pro-rated cash distribution of $0.3368 per limited partner unit, payable on November 14, 2002 to unitholders of record as of October 31, 2002. This distribution is equivalent to a full-quarter distribution of $0.4625 per limited partner unit pro-rated for the period from July 26, 2002, the date of closing of the initial public offering of common units, through September 30, 2002.

Operating, Investing and Financing Activities

Net cash provided by operating activities was $29.1 million for the nine months ended September 30, 2002 compared to $15.1 million for the comparable period in 2001, an increase of $14.0 million or 93%. This increase was primarily associated with the increase in net income and changes in certain working capital items primarily related to the acquisition of PMT and the Western Corridor system and Salt Lake City Core system assets as well as increased net income from PPS.

Net cash used in investing activities for the nine months ended September 30, 2002 and 2001 was $99.5 million and $13.6 million, respectively. This increase was primarily associated with the closing of the acquisition of the Western Corridor system and Salt Lake City Core system assets on March 1, 2002. Capital expenditures were $3.5 million for the nine months ended September 30, 2002, of which $1.8 million related to maintenance projects and $1.7 million related to expansion. Capital expenditures were $3.8 million for the nine months ended September 30, 2001, $2.7 million related to maintenance and $1.1 million related to expansion.

Net cash from financing activities consisted of a net source of cash of $81.8 million for the nine months ended September 30, 2002 and a net use of cash of $7.8 million for the nine months ended September 30, 2001. Distributions to members of PEG for the nine months ended September 30, 2002 and 2001 were $16.0 million and $17.2 million, respectively. Capital contributed by members of PEG for the nine months ended September 30, 2002 and 2001 was $8.8 million and $10.6 million, respectively. The $43.7 million in net proceeds from notes payable were used to fund the acquisition of the Western Corridor system and the Salt Lake City Core system assets in March 2002. The $167.7 million in proceeds from the issuance of common units were used to pay underwriting discounts, professional fees and other offering costs and to repay $153.7 million debt. The $225.0 million in proceeds from the term loan facility were used to pay debt issuance costs, repay $114.6 million in debt and to fund distributions of $105.1 million to the General Partner.

Capital Requirements

Generally, our crude oil transportation and storage operations require investment to upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements consist primarily of:

•: maintenance 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; 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 revenues, and adding new pump stations to increase our transportation volumes and revenues.

We have budgeted total maintenance capital expenditures of $5.1 million and expansion capital expenditures of $470,000 for full year 2002.

We expect to complete the acquisition of the EPTC assets in the first quarter of 2003. The purchase price for the EPTC assets is $158.2 million, plus potential increases based on the value of certain pre-closing capital expenditures, displacement oil inventory, prepayments made by the seller relating to the purchased assets and warehouse inventory. We expect that these adjustments will be in the range of $5.0 million to $10.0 million. We intend to finance this acquisition with a combination of proceeds from the issuance of additional units, including common units, and borrowings under our revolving credit facility.

Credit Facilities

In connection with the completion of our initial public offering of common units, PEG, our operating company, entered into a new $425.0 million credit agreement with a syndicate of financial institutions led by Fleet National Bank, that provides for a five-year $200.0 million senior secured revolving credit facility and a seven-year $225.0 million senior secured term loan facility. On July 26, 2002, PEG borrowed $225.0 million under the term loan facility. The $200.0 million revolving credit facility is currently undrawn except for the letters of credit totaling $15.6 million at September 30, 2002.

The revolving credit facility is available for general partnership purposes, including working capital, letters of credit and distributions to unitholders and to finance future acquisitions, including the pending acquisition of the EPTC assets. The revolving credit facility has a borrowing sublimit of $45.0 million for working capital, letters of credit and distributions to unitholders.

The revolving credit facility matures on July 26, 2007, at which time it will terminate and all outstanding amounts will be due and payable. We are required to amortize amounts outstanding under the term loan facility on a quarterly basis at 1% per annum beginning in 2005 with the first quarterly payment due September 2005. A 97% balloon payment will be due at maturity in July 2009.

We may prepay all loans under the revolving credit facility at any time, and all loans under the term loan facility any time following the first anniversary of the closing of the facilities, without premium or penalty. Prepayment of the term loan facility during the first year will result in a 1% premium. Except as otherwise agreed by certain of the lenders, mandatory prepayments and commitment reductions will generally include the net cash proceeds of asset sales not sold in the ordinary course of business and the net proceeds of new senior secured debt offerings, subject to certain exceptions.

The facilities are guaranteed by us and certain of PEG's subsidiaries. The facilities are fully recourse to PEG and the guarantors, but non-recourse to our General Partner. Obligations under the facilities are secured by pledges of membership interests in and assets of PEG's subsidiaries, subject to certain limited exceptions.

Indebtedness under the facilities bear interest at the Partnership'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% (each plus an applicable margin ranging from 0% to 0.50% for the revolving credit facility and ranging from 0.50% to 0.75% for the term loan facility) or (ii) LIBOR plus an applicable margin for the revolving credit facility ranging from 1.25% to 2.50% and the term loan facility ranging from 2.50% to 2.75%. The applicable margins are subject to change based on the credit rating of the facilities or, if they are not rated, the credit rating of PEG. For a period of time, up to 270 days, subsequent to the completion of the acquisition of the EPTC assets, the applicable margin will increase by a margin which ranges from 0.375% to 0.625%. PEG will incur a per annum commitment fee margin which ranges from 0.25% to 0.50% in connection with the revolving credit facility. The credit agreement prevents PEG 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 covenants limiting the ability of PEG and certain of its subsidiaries to, among other things:

•: incur or guarantee indebtedness;
•: change ownership or structure, including consolidations, liquidations and dissolutions;
•: repurchase or redeem units;
•: make certain negative pledges and grant certain liens;
•: sell, transfer, assign or convey assets;
•: make certain loans and investments;
•: enter into a new line of business;
•: transact business with affiliates;
•: enter into agreements restricting loans or distributions made by PEG's subsidiaries to us or PEG; or
•: participate in certain hedging and derivative activities.

The credit agreement also contains covenants requiring PEG, including certain of its subsidiaries, to maintain:

•: a ratio of maximum total funded debt to consolidated EBITDA (each as defined in the credit agreement) of up to 4.25:1, stepping down to 4.00:1 at December 31, 2003; this ratio shall remain at 4.25:1 so long as we maintain an investment grade rating from either S&P or Moody's. For nine months following the closing of the acquisitions of the EPTC assets, this ratio will increase to 5.25:1. This ratio will be tested quarterly on a rolling four-quarter basis and upon each incurrence of debt;
•: a maximum of debt to total capital of 70%; and
•: a minimum interest coverage ratio (as defined in the credit agreement) of 3.00:1 to be tested quarterly on a trailing four-quarter basis. For the four quarters following the closing of the acquisitions of the EPTC assets, this ratio will decrease to 2.50:1.

Each of the following is an event of default under the facilities:

•: failure to pay any principal, interest, fees, expenses or other amounts;
•: failure to observe any agreement, security instrument, obligation or covenant included in the credit agreement or in any guaranty, subject to various cure provisions;
•: judgments against us, our General Partner or any of our subsidiaries in excess of certain allowances;
•: default under other indebtedness of PEG and the guarantors of the facilities' indebtedness in excess of a threshold amount;
•: certain ERISA events involving us or our subsidiaries;
•: bankruptcy or insolvency events involving us, our General Partner or our subsidiaries;
•: failure of any representation or warranty to be materially true and correct; and
•: a change of control (as defined in the credit agreement).

attributable to the LIBOR interest payments due on $170.0 million outstanding under the term loan facility. The average swap rate on this $170.0 million of debt is approximately 4.25% resulting in an all-in interest rate on the $170.0 million of approximately 7.00% (including the current applicable margin of 2.75%). Changes in the fair value of derivatives designated for hedging activities are recorded in other comprehensive losses, a component of partners' capital, but not reflected in the combined condensed statements of operations. For the nine months ended September 30, 2002, other comprehensive losses include $6.8 million related to the effective portion of derivative losses due to changes in the fair market value of these swap agreements.

Impact of Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the three and nine months ended September 30, 2002 and 2001.

Environmental Matters

Our transportation and storage operations are subject to extensive regulation under federal, state and local environmental laws concerning, among other things, the generation, handling, transportation and disposal of hazardous materials, and we may be, from time to time, subject to environmental cleanup and enforcement actions.

The accompanying balance sheet includes reserves for environmental costs that relate to existing conditions caused by past operations. Estimates of ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation at most locations, the number of remediation alternatives available, the uncertainty of potential recoveries from third parties and the evolving nature of environmental laws and regulations.

Based on the information presently available, it is the opinion of management that our environmental costs, to the extent they exceed recorded liabilities, will not have a material adverse effect on our financial condition.

Critical Accounting Policies

Our combined condensed financial statements are prepared in conformity with accounting principles generally accepted in the United States, which require management to make estimates and assumptions that affect the reported amounts of the assets and liabilities and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. We routinely make estimates and judgments about the carrying value of our assets and liabilities that are not readily apparent from other sources. Such estimates and judgments are evaluated and modified as necessary on an ongoing basis. We believe that of our significant accounting policies (see Note 3, Significant Accounting Policies, to our combined condensed financial statements), the following may involve a higher degree of judgment and complexity:

•: We accrue an estimate of the costs of environmental remediation for work at identified sites where an assessment has indicated that cleanup costs are probable and may be reasonably estimated. In making these estimates, we consider information that is currently available, existing technology, enacted laws and regulations and our estimates of the timing of the required remedial actions.
•: We depreciate the components of our property and equipment on a straight-line basis over the estimated useful lives of the assets. The estimates of the assets' useful lives require our judgment and our knowledge of the assets being depreciated. When necessary, the assets' useful lives are revised and the impact on depreciation is treated on a prospective basis.

•: We routinely apply the provisions of purchase accounting when recording our acquisitions. Application of purchase accounting requires that we estimate the fair value of the individual assets acquired. The valuation of the fair value of the assets involves a number of judgments and estimates.

Accounting Pronouncements

On July 30, 2002, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 146 ("SFAS 146"), "Accounting for Costs Associated with Exit or Disposal Activities". SFAS 146 nullifies Emerging Issues Task Force ("EITF") Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." It requires that a liability be recognized for those costs only when the liability is incurred, that is, when it meets the definition of a liability in the FASB's conceptual framework. SFAS 146 also establishes fair value as the objective for initial measurement of liabilities related to exit or disposal activities. SFAS 146 is effective for exit or disposal activities that are initiated after December 31, 2002, with earlier adoption encouraged. We do not expect that the adoption of SFAS 146 will have a material impact on its financial position or results of operations.

In April 2002, the FASB issued Statement of Financial Accounting Standards No. 145, ("SFAS 145"), "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". The rescission of FASB Statement No. 4, "Reporting Gains and Losses from Extinguishment of Debt," ("Statement 4") and FASB Statement No 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements", which amended Statement 4, will affect income statement classification of gains and losses from extinguishment of debt. Upon adoption, enterprises must reclassify prior period items that do not meet the extraordinary item classification criteria in Accounting Principles Bulletin No. 30, "Reporting the Results of Operations". The provisions of SFAS 145 related to the rescission of Statement 4 are applicable in fiscal years beginning after May 15, 2002, with early application encouraged. The provisions of SFAS 145 related to FASB Statement No. 13, "Accounting for Leases," are effective for transactions occurring after May 15, 2002, with early application encouraged. All other provisions of SFAS 145 are effective for financial statements issued on or after May 15, 2002, with early application encouraged. We do not expect that the adoption of SFAS 145 will have a material impact on its financial position or results from operations.

Effective January 1, 2002, we adopted Statement of Financial Accounting Standards No. 144 ("SFAS 144"), "Accounting for the Impairment or Disposal of Long-Lived Assets," which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. While SFAS 144 supersedes Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," it retains many of the fundamental provisions of that statement. The adoption of this standard did not have a material impact on our financial position or results of operations in 2002.

We also adopted Statement of Financial Accounting Standards No. 141 ("SFAS 141"), "Business Combinations," and Statement of Financial Accounting Standards No. 142 ("SFAS 142"), "Goodwill and Other Intangible Assets" on January 1, 2002. SFAS 141 requires that the purchase method be used for all business combinations initiated after September 30, 2001. SFAS 142 requires that goodwill no longer be amortized to earnings, but instead be reviewed for impairment. The adoption of these standards did not have a material impact on our financial position or results of operations in 2002.

related asset. Upon settlement of the liability an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard is effective for fiscal years beginning after June 15, 2002, with earlier adoption encouraged. We are currently evaluating the effect of adopting SFAS 143 on its financial position and results of operations.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are interest rate risk and crude oil price risk. Debt we incur under our credit facilities will bear variable interest at either the applicable base rate or a rate based on LIBOR. We have used and will continue to use certain derivative instruments to hedge our exposure to variable interest rates.

Although we generally do not own the crude oil that we transport in our pipelines, we purchase some crude oil in the San Joaquin Valley for subsequent blending, transportation and resale primarily in the Los Angeles Basin. We use, on a limited basis, certain derivative instruments (principally futures and options) to hedge our exposure to market price volatility related to our sales of crude oil. We do not enter into speculative derivative transactions. The derivative instruments are included in other assets in the accompanying balance sheets. Changes in the fair value of our derivatives related to crude oil sales are recognized in net income. For the nine months ended September 30, 2002, operating expenses include $226,000 related to changes in the fair value of PMT's derivative instruments for our marketing activities and pipeline transportation revenues are net of $184,000 related to changes in the fair value of PPS's derivative instruments for our pipeline loss allowance inventory.

ITEM 4. Controls and Procedures

(a) Evaluation of disclosure controls and procedures. Within 90 days before the filing of this Report, Irvin Toole, Jr., our Chief Executive Officer, and John D. Cook, our Controller, evaluated the effectiveness of our disclosure controls and procedures. Based on the evaluation, they believe that:

•: our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and
•: our disclosure controls and procedures were effective to ensure that material information was accumulated and communicated to our management, including our Chief Executive Officer and Controller, as appropriate to allow timely decisions regarding required disclosure.

(b) Changes in internal controls. There have been no significant changes in our internal controls or in other factors that could significantly affect our internal controls subsequent to their evaluation, nor have there been any corrective actions with regard to significant deficiencies or material weaknesses.

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

In January and February 2001, two shippers filed complaints with the FERC challenging the Frontier pipeline and AREPI pipeline portions of joint tariffs filed by Express Pipeline Partnership to which Frontier and AREPI were joint carriers and to rates contained in local tariffs filed by Frontier pipeline and AREPI pipeline.

In January 2002, Frontier reached a partial settlement with the complainants under which Frontier agreed, among other things, to publish reduced local rates, not to index these rates for a period of five years, to reduce its division of the joint tariff rates and to pay the complainants reparations for movements on Frontier pipeline's local rates for the past. The claim for reparations relating to Frontier's portion of the pre-complaint joint tariffs remains to be decided by the FERC.

In March 2002, AREPI reached a settlement with the complainants under which AREPI agreed, among other things, to reduce its local tariff rate and its division of the joint tariff rates and to pay reparations for past movements on the local rate and the rates contained in the joint tariffs. AREPI recorded a provision in 2001 of $1.5 million related to this settlement which was paid in 2002, as well as legal and consulting expenses.

On March 19, 2002, we filed revised tariffs that reduced the rates we charge for interstate transportation service on the Western Corridor system. On April 15, 2002, Sinclair Oil Corporation ("Sinclair") filed a complaint with the FERC challenging these rates. In its complaint, Sinclair alleges that the reduced rates are unjust and unreasonable. Sinclair also alleges that the revised tariff rates are discriminatory in favor of Conoco, which owns an undivided interest in the pipelines that comprise the Western Corridor system. We are vigorously defending against the claims asserted by Sinclair and have filed a general denial of Sinclair's allegations with the FERC. We have also filed a motion asking the FERC to hold Sinclair's complaint in abeyance pending our filing of an application for market-based rates and the FERC's action thereon. We filed this application on July 22, 2002. Protests to our application for market-based rates were filed with the FERC by Sinclair, Tesoro Refining and Marketing Company, Phillips Petroleum Company and Chevron Products Company. These protests variously allege that our application incorrectly defined the relevant geographic and product markets and that, if such markets are properly defined, we should be found to have market power in those markets.

On March 15, 2002, Sinclair filed a complaint with the Wyoming Public Service Commission ("PSC") alleging that RMP's common stream rules and specifications and RMP's refusal to prohibit certain types of crude oil diluents from the common stream, all in respect of the Big Horn segment of the Western Corridor system, are adverse to Sinclair and the public interest. In pre-hearing evidentiary pleadings filed in October 2002, Sinclair explicitly requested from the PSC an order requiring RMP to segregate certain crude oil types that are objectionable to Sinclair from the common stream. A hearing on Sinclair's complaint was held by the PSC in October 2002, and briefs are to be filed by the parties by January 15, 2003. No decision from the PSC is expected before the end of 2002. RMP intends to continue to vigorously defend against Sinclair's complaint, and while we cannot predict the outcome of this dispute, we do not expect it to have a material adverse effect on our business, financial condition or results of operations.

We are subject to numerous federal, state and local laws which regulate the discharge of materials into the environment or that otherwise relate to the protection of the environment. We currently have known environmental conditions that will require remediation. The accrued liability for environmental remediation for known conditions was $2.6 million at December 31, 2001 and at September 30, 2002 and was classified in the combined balance sheets within other liabilities.

The total future costs for environmental remediation activities will depend on, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the technology available and required to meet the various existing legal requirements, the nature and extent of future environmental laws, inflation rates and the determination of our liability at multi-party sites, if any, in light of uncertainties with respect to joint and several liability, and the number, participation levels and financial viability of other parties.

Although we may, from time to time, be involved in various litigation and claims arising out of its operations in the normal course of business, we are not currently a party to any legal proceedings, the resolution of which we expect to have a material adverse effect on its business, financial position, results of operations or liquidity.

ITEM 2. Changes in Securities and Use of Proceeds

On July 22, 2002, the registration statement on Form S-1 (SEC File No.: 333-84812), as amended, that we filed with the Securities and Exchange Commission relating to our initial public offering became effective. The managing underwriter was Salomon Smith Barney. The closing date of our initial public offering was July 26, 2002 and on that date we sold 8,600,000 common units to the public at a price of $19.50 per common unit, or $167.7 million. The underwriting discount on this sale was approximately $11.5 million. In addition, concurrent with the closing of our initial public offering, PEG borrowed $225.0 million under its term loan facility with Fleet National Bank and other lenders and incurred approximately $5.3 million of debt issuance costs and related expenses. A summary of the proceeds received and use of proceeds is as follows (in millions):

*Proceeds received:*
	Sale of common units		$	167.7
	Borrowing under term loan facility			225.0

		Total proceeds received	$	392.7

*Use of proceeds from sale of common units:*
	Underwriting discount		$	11.5
	Professional fees and other offering costs			2.5
	Repayment of debt			153.7

		Total use of proceeds from the sale of common units		167.7

*Use of proceeds from term loan facility:*
	Debt issuance costs and related expenses			5.3
	Repayment of debt			114.6
	Distributions to General Partner			105.1

		Total use of proceeds from term loan facility		225.0

		Total use of proceeds	$	392.7

On July 26, 2002, as consideration for the contribution of assets and liabilities by the General Partner and its affiliates, we issued to the General Partner 1,865,000 common units and 10,465,000 subordinated units representing limited partner interests as well as rights to receive incentive distributions in an offering exempt from registration under Section 4(2) of the Securities Act of 1933.

ITEM 6. Exhibits and Reports on Form 8-K

(a): The following documents are filed as exhibits to this quarterly filing:

Exhibit Number		Description
Exhibit 3.2		First Amended and Restated Agreement of Limited Partnership of Pacific Energy Partners, L.P. (incorporated by reference to Exhibit 3.2 to Pacific Energy Partners, L.P.'s quarterly report on Form 10-Q for the quarter ended June 30, 2002).
Exhibit 3.7		Second Amended and Restated Operating Agreement of Pacific Energy Group LLC (incorporated by reference to Exhibit 3.7 to Pacific Energy Partners, L.P.'s quarterly report on Form 10-Q for the quarter ended June 30, 2002).
Exhibit 10.1		Credit Agreement (incorporated by reference to Exhibit 10.1 to Pacific Energy Partners, L.P.'s quarterly report on Form 10-Q for the quarter ended June 30, 2002).
Exhibit 10.3		Contribution and Conveyance Agreement (incorporated by reference to Exhibit 10.3 to Pacific Energy Partners, L.P.'s quarterly report on Form 10-Q for the quarter ended June 30, 2002)
Exhibit 10.10		Omnibus Agreement (incorporated by reference to Exhibit 10.10 to Pacific Energy Partners, L.P.'s quarterly report on Form 10-Q for the quarter ended June 30, 2002).

(b): Reports on Form 8-K:

None.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Partnership has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	PACIFIC ENERGY PARTNERS, L.P.
	By:	PACIFIC ENERGY GP, INC. its General Partner
Date: November 14, 2002		By:	/s/ IRVIN TOOLE, JR. Irvin Toole, Jr. President and Chief Executive Officer
Date: November 14, 2002		By:	/s/ JOHN D. COOK John D. Cook Controller (Principal Accounting Officer)

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Irvin Toole, Jr., certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Pacific Energy Partners, L.P.;

2.

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act rules 13a-14 and 15d-14) for the registrant and we have:

a): designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
b): evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
c): presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a): all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b): any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.: The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 14, 2002

/s/ IRVIN TOOLE, JR.

Irvin Toole, Jr.
President and Chief Executive Officer
Pacific Energy GP, Inc.,
General Partner of
Pacific Energy Partners, L.P.

CERTIFICATION OF PRINCIPAL ACCOUNTING OFFICER

I, John D. Cook, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Pacific Energy Partners, L.P.;

2.

3.

4.

a): designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
b): evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
c): presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

a): all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b): any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.: The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 14, 2002

/s/ JOHN D. COOK

John D. Cook
Controller (Principal Accounting Officer)
Pacific Energy GP, Inc.,
General Partner of
Pacific Energy Partners, L.P.

EXHIBIT INDEX

Exhibit Number		Description
Exhibit 3.2		First Amended and Restated Agreement of Limited Partnership of Pacific Energy Partners, L.P. (incorporated by reference to Exhibit 3.2 to Pacific Energy Partners, L.P.'s quarterly report on Form 10-Q for the quarter ended June 30, 2002).
Exhibit 3.7		Second Amended and Restated Operating Agreement of Pacific Energy Group LLC (incorporated by reference to Exhibit 3.7 to Pacific Energy Partners, L.P.'s quarterly report on Form 10-Q for the quarter ended June 30, 2002).
Exhibit 10.1		Credit Agreement (incorporated by reference to Exhibit 10.1 to Pacific Energy Partners, L.P.'s quarterly report on Form 10-Q for the quarter ended June 30, 2002).
Exhibit 10.3		Contribution and Conveyance Agreement (incorporated by reference to Exhibit 10.3 to Pacific Energy Partners, L.P.'s quarterly report on Form 10-Q for the quarter ended June 30, 2002)
Exhibit 10.10		Omnibus Agreement (incorporated by reference to Exhibit 10.10 to Pacific Energy Partners, L.P.'s quarterly report on Form 10-Q for the quarter ended June 30, 2002).

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PACIFIC ENERGY PARTNERS, L.P. Successor to Pacific Energy (Predecessor) FORM 10-Q TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

PACIFIC ENERGY PARTNERS, L.P. (Note 1) Successor to Pacific Energy (Predecessor) COMBINED CONDENSED BALANCE SHEETS (in thousands)
PACIFIC ENERGY PARTNERS, L.P. (Note 1) Successor to Pacific Energy (Predecessor) COMBINED CONDENSED STATEMENTS OF OPERATIONS (Unaudited) (in thousands, except per unit amounts)
PACIFIC ENERGY PARTNERS, L.P. (Note 1) Successor to Pacific Energy (Predecessor) COMBINED CONDENSED STATEMENTS OF PARTNERS' CAPITAL (Unaudited) (in thousands)
PACIFIC ENERGY PARTNERS, L.P. (Note 1) Successor to Pacific Energy (Predecessor) COMBINED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) (in thousands)
PACIFIC ENERGY PARTNERS, L.P. Successor to Pacific Energy (Predecessor) NOTES TO COMBINED CONDENSED FINANCIAL STATEMENTS September 30, 2002 (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 2. Changes in Securities and Use of Proceeds

ITEM 6. Exhibits and Reports on Form 8-K

SIGNATURES
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
CERTIFICATION OF PRINCIPAL ACCOUNTING OFFICER
EXHIBIT INDEX