PACIFIC ENERGY PARTNERS LP - 10-Q Quarterly Report

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

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

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,		December 31,
	2005		2004
	(in thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	22,097	$	23,383
Crude oil sales receivable	51,999		28,609
Transportation and storage accounts receivable	21,997		20,137
Canadian goods and services tax receivable	7,595		7,632
Insurance proceeds receivable (note 2)	11,495		—
Due from related parties (note 3)	128		—
Crude oil inventory	26,449		9,174
Prepaid expenses	4,928		4,159
Other	3,654		2,451
Total current assets	150,342		95,545
Property and equipment, net	715,580		718,624
Investment in Frontier	8,200		7,886
Other assets, net	45,968		47,850
	$	920,090	$	869,905

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	17,273	$	15,127
Accrued crude oil purchases	65,493		27,231
Line 63 oil release reserve (note 2)	13,496		—
Accrued interest	5,538		1,124
Due to related parties (note 3)	—		533
Derivatives liability—current portion	1,410		400
Other	5,930		3,630
Total current liabilities	109,140		48,045
Senior notes and credit facilities, net (note 4)	356,369		357,163
Deferred income taxes	34,248		34,556
Environmental liabilities	7,022		7,269
Other liabilities	340		406
Total liabilities	507,119		447,439
Commitments and contingencies (notes 2 and 8)
Partners’ capital:
Common unitholders (19,258,330 and 19,158,747 units outstanding at March 31, 2005 and December 31, 2004, respectively)	356,708		361,427
Subordinated unitholders (10,465,000 units outstanding at March 31, 2005 and December 31, 2004)	38,096		41,521
General Partner interest	6,714		6,280
Undistributed employee long-term incentive compensation (note 5)	—		116
Accumulated other comprehensive income	11,453		13,122
Net partners’ capital	412,971		422,466
	$	920,090	$	869,905

See accompanying notes to condensed consolidated financial statements.

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

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

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

Basic net income per limited partner unit	$	0.17		$	0.32
Diluted net income per limited partner unit	$	0.17		$	0.31

Weighted average limited partner units outstanding:
Basic	29,655			24,999
Diluted	29,673			25,149

See accompanying notes to condensed consolidated financial statements.

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

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(Unaudited)

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

See accompanying notes to condensed consolidated financial statements.

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2005			2004
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	3,421		$	8,077
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	6,529			5,242
Amortization of debt issue costs	459			311
Non-cash portion of employee compensation under long-term incentive plan	1,545			659
Deferred tax benefit	(171		)	—
Share of net income of Frontier	(357		)	(393		)
Distributions from Frontier, net	—			289
	11,426			14,185
Net changes in operating assets and liabilities:
Crude oil sales receivable	(23,327		)	5,556
Transportation and storage accounts receivable	(1,832		)	676
Insurance proceeds receivable	(11,495		)	—
Crude oil inventory	(17,246		)	(2,995		)
Other current assets and liabilities	(1,681		)	422
Accounts payable and other accrued liabilities	8,716			1,319
Accrued crude oil purchases	38,176			(5,981		)
Line 63 oil release reserve	13,496			—
Other non-current assets and liabilities	(301		)	—
	4,506			(1,003		)
NET CASH PROVIDED BY OPERATING ACTIVITIES	15,932			13,182

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(4,389		)	(2,413		)
Acquisition deposit	—			(9,920		)
Other	129			—
NET CASH USED IN INVESTING ACTIVITIES	(4,260		)	(12,333		)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of common units, net of fees and offering expenses	—			114,250
Capital contributions from the general partner	2,438			2,443
Proceeds from note payable to bank	26,833			16,500
Repayment of long-term debt	(25,854		)	(89,500		)
Deferred financing costs	(600		)	(175		)
Distributions to partners	(15,114		)	(12,390		)
Related parties	(661		)	156
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(12,958		)	31,284

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(1,286		)	32,133
CASH AND CASH EQUIVALENTS, beginning of reporting period	23,383			9,699
CASH AND CASH EQUIVALENTS, end of reporting period	$	22,097		$	41,832

See accompanying notes to condensed consolidated financial statements.

PACIFIC ENERGY PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2005

(Unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

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

The unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial reporting and with Securities and Exchange Commission (“SEC”) regulations. Accordingly, these statements have been condensed and do not include all of the information and footnotes required for complete financial statements. These statements involve the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. The results of operations for the three months ended March 31, 2005 are not necessarily indicative of the results of operations for the full year. All significant intercompany balances and transactions have been eliminated during the consolidation process.

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

These financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2004. Certain prior year balances in the accompanying condensed consolidated financial statements have been reclassified to conform to the current year presentation.

Income Taxes

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

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

Net Income per Unit

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

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

except that the weighted average number of outstanding limited partner units is increased to include the dilutive effect of outstanding options and restricted units by application of the treasury stock method. Following is a reconciliation of the basic weighted average outstanding limited partner units to diluted weighted average limited partner units.

	Three Months Ended March 31,
	2005	2004
	(in thousands)

Basic weighted average limited partner units	29,655	24,999
Effect of restricted units	—	134
Effect of options	18	16
Diluted weighted average limited partner units	29,673	25,149

Allocation of Net Income

Net income is allocated to the Partnership’s general partner and limited partners based on their respective interest in the Partnership. The Partnership’s general partner is also directly charged with specific costs that it has individually assumed and for which the limited partners are not responsible (see “Note 6—Allocation of Net Income”).

New Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123 (revised December 2004), Share-Based Payment (SFAS 123R). This Statement is a revision of SFAS No. 123. SFAS 123R establishes standards for the accounting of transactions in which an entity exchanges its equity instruments for goods or services. SFAS 123R is effective for the Partnership as of the beginning of the first annual reporting period that begins after June 15, 2005. The Partnership has not yet determined the impact of the adoption of SFAS 123R on the Partnership’s consolidated financial statements.

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

2. LINE 63 OIL RELEASE RESERVE

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

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

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

The foregoing estimates are based on facts known at the time of estimation and the Partnership’s assessment of the ultimate outcome. Among the many uncertainties that impact the estimates are the necessary regulatory approvals for, and potential modification of, remediation and repair plans, the limited amount of data available at the time of the assessment of the impact of soil and water contamination, the current uncertainty of the geological conditions that will be encountered during the repairs of the damaged pipeline, changes in costs associated with environmental remediation services and equipment and the possibility of third-

party legal claims giving rise to additional expenses. Therefore, no assurance can be made that costs incurred in excess of this provision, if any, would not have a material adverse effect on the Partnership’s financial condition, results of operations, or cash flows, though the Partnership believes it is likely that most, if not all, of any such excess cost, to the extent attributable to clean-up and third-party claims, would be recoverable through insurance. As new information becomes available in future periods, the Partnership may change its provision and recovery estimates.

3. RELATED PARTY TRANSACTIONS

Sale of The Anschutz Corporation’s Interest in the Partnership

On March 3, 2005, TAC sold all of its interest in Pacific Energy GP, Inc. to LBP, which was formed by LBMB in connection with the purchase. The acquisition by LBP (the “LB Acquisition”) included the 100% ownership interest in Pacific Energy GP, Inc., which owned (i) the 2% general partner interest in the Partnership and the incentive distribution rights, and (ii) 10,465,000 subordinated units of the Partnership representing a 34.6% limited partner interest in the Partnership. Immediately prior to the closing of the LB Acquisition, Pacific Energy GP, Inc. was converted to Pacific Energy GP, LLC, a Delaware limited liability company; and immediately after the closing of the LB Acquisition, Pacific Energy GP, LLC was converted to Pacific Energy GP, LP (the “General Partner”). Immediately following the consummation of the LB Acquisition, the General Partner distributed the 10,465,000 subordinated units of the Partnership to LBP.

In connection with the conversion of the Partnership’s General Partner to a limited partnership, the General Partner ceased to have a board of directors, and is now managed by its general partner, Pacific Energy Management LLC, a Delaware limited liability company (“PEM” or the “Managing General Partner”), which is 100% owned by LBP. PEM has a board of directors (the “Board of Directors” or “Board”) that manages the business and affairs of PEM and, thus, indirectly manages the business and affairs of the General Partner and the Partnership. All of the officers and employees of Pacific Energy GP, Inc. were transferred to fill the same positions with PEM, and the PEM Board established the same committees as had been maintained by Pacific Energy GP, Inc. prior to the LB Acquisition. PEM also adopted Pacific Energy GP, Inc.’s governance guidelines and its compensation structure and employee benefits plans and policies.

Additionally, on March 21, 2005, an affiliate of First Reserve Corporation (“First Reserve”) acquired from LBMB a 30% partnership interest in LBP. LBMB and its affiliates continue to own a 70% partnership interest in LBP. As a result of its ownership interest, First Reserve is entitled to and has nominated one director to the Board of Directors of PEM. The director nominated by First Reserve was appointed by LBP to the Board on April 6, 2005.

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

Cost Reimbursements

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

Special Agreement: On March 3, 2005, Douglas L. Polson, previously the Chairman of the Board of Directors of Pacific Energy GP, Inc., entered into a Special Agreement and a Consulting Agreement with PEM. In accordance with the Special Agreement, Mr. Polson resigned as Chairman of the Board of Directors of Pacific Energy GP, Inc. effective March 3, 2005. Mr. Polson was paid approximately $0.9 million, representing accrued but unused vacation, accrued salary through March 3, 2005 and payment in satisfaction of other obligations under his employment agreement. The severance portion of this payment of approximately $0.9 million was recorded as an expense in “Transaction costs” in the accompanying condensed consolidated income statements (see “Note 6 – Allocation of Net Income”). LBP reimbursed this amount, which was recorded as a partner’s capital contribution. Pursuant to the Consulting Agreement, Mr. Polson has agreed to perform advisory services to PEM from time to time as shall be mutually agreed between Mr. Polson and the Chief Executive Officer of PEM. In consideration for Mr. Polson’s services under the Consulting Agreement, which has a one-year term, Mr. Polson will receive a monthly consulting fee of $12,500 and reimbursement of all reasonable business expenses incurred or paid by Mr. Polson in the course of performing his duties thereunder.

LB Pacific, LP and TAC: LBP and TAC reimbursed the Partnership for certain other costs relating to the LB Acquisition. These included $1.2 million for the Consent Solicitation (as defined and further described in “Note 4—Long-Term Debt”, below) and $0.3 million for legal and other expenses (also see “Note 6—Allocation of Net Income”).

Other Related Party Transactions

Revenue from Related Parties: Rocky Mountain Pipeline system (“RMPS”) serves as the contract operator for certain gas

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

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

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

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

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

4. LONG-TERM DEBT

The Partnership’s long-term debt obligations are shown below:

	March 31, 2005		December 31, 2004
	(in thousands)

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

Under the Indenture governing the Partnership’s Senior Notes, the Partnership would have been required to make a “Change of Control Offer” to the note holders if the LB Acquisition would have caused a rating decline. In order to avoid triggering the “Change of Control Offer” provision, the Partnership solicited the consent (the “Consent Solicitation”) of the holders of the Senior Notes to amend certain provisions of the Indenture, including an amendment to the definition of “Change of Control.” The Consent Solicitation commenced on January 28, 2005 and expired on February 10, 2005. During that time, a majority of the holders of the Senior Notes consented to the adoption of the proposed amendments and as such the proposed amendments were approved. Thereafter, a supplemental indenture that incorporated the proposed amendments was executed by the parties to the Indenture. Fees of approximately $0.6 million paid to holders of the Senior Notes were capitalized and included in “Other assets” in the accompanying condensed consolidated balance sheet at March 31, 2005 and will be amortized over the remaining life of the Senior Notes. Solicitation–related fees and expenses of approximately $0.6 million are included in “Transaction costs” in the accompanying condensed consolidated statements of income. LBP and TAC reimbursed the Partnership for the costs of the Consent Solicitation, which are recorded as a partner’s capital contribution (see “Note 3—Related Party Transactions”).

Additionally, the U.S. and Canadian revolving credit facilities also contained change of control provisions. The Partnership amended the U.S. and Canadian revolving credit facilities to account for the change in control of its General Partner.

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

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

6. ALLOCATION OF NET INCOME

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

	Three Months Ended March 31,
	2005			2004
	(in thousands)

Net income	$	3,421		$		8,077
Transaction costs reimbursed by general partner:
Senior Notes consent solicitation and other costs	893			—
Severance and other costs	914			—
Total transaction costs reimbursed by general partner	1,807			—
Income before transaction costs reimbursed by general partner	5,228			8,077
General partner’s share of income	2		%	2			%
General partner allocated share of net income before transaction costs	105			162
Transaction costs reimbursed by general partner	(1,807		)	—
Net income (loss) allocated to general partner	$	(1,702	)	$		162

Income before transaction costs reimbursed by general partner	$	5,228		$		8,077
Limited partners share of income	98		%	98			%
Limited partners share of net income	$	5,123		$		7,915

Net income (loss) allocated to general partner	$	(1,702	)	$	162
Net income allocated to limited partners	5,123			7,915
Net income	$	3,421		$		8,077

LBP and TAC reimbursed the Partnership for certain costs incurred in connection with the LB Acquisition. The Partnership was reimbursed $1.2 million for costs incurred in connection with the consent solicitation, $0.3 million of legal and other costs and $0.9 million relating to severance costs (see “Note 3—Related Party Transactions”), for a total of $2.4 million. Of the $1.2 million incurred for the consent solicitation, $0.6 million was capitalized as deferred financing costs and $0.6 million was expensed.

7. SEGMENT INFORMATION

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

					Intersegment and
	West Coast		Rocky Mountain		Intrasegment
	Business Unit		Business Unit		Eliminations			Total
	(in thousands)
Three months ended March 31, 2005
Business unit revenue:
Pipeline transportation revenue	$	17,443	$	12,456	$	(1,862	)	$	28,037
Storage and distribution revenue	10,472		—		(150		)	10,322
Pipeline buy/sell transportation revenue(1)	—		9,106					9,106
Crude oil sales, net of purchases(2)	1,812		—		(30		)	1,782
Net revenue	29,727		21,562					49,247
Expenses:
Operating	14,507		9,289		(2,042		)	21,754
Line 63 oil release costs(3)	2,000		—					2,000
Depreciation and amortization	3,477		3,052					6,529
Total expenses	19,984		12,341					30,283
Share of net income of Frontier	—		357					357
Operating income from segments(4)	$	9,743	$	9,578				$	19,321
Business unit assets(5)	$	538,568	$	350,600				$	889,168
Capital expenditures(6)	$	750	$	2,932				$	3,682

Three months ended March 31, 2004
Business unit revenue:
Pipeline transportation revenue	$	15,691	$	10,543	$	(1,507	)	$	24,727
Storage and distribution revenue	10,223		—		(100		)	10,123
Crude oil sales, net of purchases(2)	4,812		—					4,812
Net revenue	30,726		10,543					39,662
Expenses:
Operating	14,706		5,818		(1,607		)	18,917
Depreciation and amortization	3,765		1,477					5,242
Total expenses	18,471		7,295					24,159
Share of net income of Frontier	—		393					393
Operating income from segments(4)	$	12,255	$	3,641				$	15,896
Business unit assets(5)	$	511,254	$	123,837				$	635,091
Capital expenditures(6)	$	793	$	1,291				$	2,084

(1) Includes the revenue of the Rangeland system, which was acquired on May 11, 2004 and June 30, 2004. Pipeline buy/sell transportation revenue reflects net revenues of approximately $1.4 million on buy/sell transactions with different parties of $20.5 million. The remaining amount reflects net revenues on buy/sell transactions with the same party.

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

(3) See “Note 2 — Line 63 Oil Release Reserve” for further information.

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

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

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

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

8. CONTINGENCIES

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

9. SUBSEQUENT EVENT

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

10. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

The following supplemental condensed consolidating financial information reflects the Parent’s separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of the Parent’s Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations and the Parent’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent’s investments in its subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for under the equity method of accounting:

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

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

	Statement of Income
	Three Months Ended March 31, 2005
				Guarantor			Non-Guarantor			Consolidating
	Parent			Subsidiaries			Subsidiaries			Adjustments			Total
	(in thousands)

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

(1) General and administrative expense is not currently allocated between Guarantor and Non-Guarantor Subsidiaries for financial reporting purposes.

	Statement of Income
	Three Months Ended March 31, 2004
			Guarantor			Non-Guarantor			Consolidating
	Parent		Subsidiaries			Subsidiaries			adjustments			Total
	(in thousands)

Net operating revenues	$	—	$	15,356		$	25,913		$	(1,607	)	$	39,662
Operating expenses	—		(9,700		)	(10,824		)	1,607			(18,917		)
General and administrative expense(1)	—		(3,828		)	(26		)	—			(3,854		)
Depreciation and amortization expense	—		(1,595		)	(3,647		)	—			(5,242		)
Share of net income of Frontier	—		393			—			—			393
Operating income	—		626			11,416			—			12,042
Interest expense	—		(4,126		)	—			—			(4,126		)
Intercompany interest income (expense)	—		3,747			(3,747		)	—			—
Equity earnings	8,076		7,710			—			(15,786		)	—
Other income	1		119			41			—			161
Net income	$	8,077	$	8,076		$	7,710		$	(15,786	)	$	8,077

(1) General and administrative expense is not currently allocated between Guarantor and Non-Guarantor Subsidiaries for financial reporting purposes.

	Statement of Comprehensive Income
	Three Months Ended March 31, 2005
				Guarantor			Non- Guarantor			Consolidating
	Parent			Subsidiaries			Subsidiaries			Adjustments			Total
	(in thousands)

Net income	$	3,421		$	8,384		$	7,990		$	(16,374	)	$	3,421
Change in fair value of hedging derivatives	(1,132		)	(1,132		)	—			1,132			(1,132		)
Foreign currency translation adjustment	(537		)	(537		)	(537		)	1,074			(537		)
Comprehensive income	$	1,752		$	6,715		$	7,453		$	(14,168	)	$	1,752

	Statement of Comprehensive Income
	Three Months Ended March 31, 2004
				Guarantor			Non- Guarantor		Consolidating
	Parent			Subsidiaries			Subsidiaries		Adjustments			Total
	(in thousands)

Net income	$	8,077		$	8,076		$	7,710	$	(15,786	)	$	8,077
Change in fair value of hedging derivatives	(4,236		)	(4,236		)	—		4,236			(4,236		)
Comprehensive income	$	3,841		$	3,840		$	7,710	$	(11,550	)	$	3,841

	Statement of Cash Flows
	Three Months Ended March 31, 2005
					Guarantor				Non-Guarantor				Consolidating
	Parent				Subsidiaries				Subsidiaries				Adjustments			Total
	(in thousands)

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

	Statement of Cash Flows
	Three Months Ended March 31, 2004
				Guarantor			Non-Guarantor			Consolidating
	Parent			Subsidiaries			Subsidiaries			Adjustments			Total
	(in thousands)

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

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 contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are identified as any statements that do not relate strictly to historical or current facts, including statements that use terms such as “anticipate,” “assume,” “believe,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “position,” “predict,” “project,” or “strategy” or the negative connotation or other variations of such terms or other similar terminology. In particular, statements express or implied, regarding our future results of operations or our ability to generate sales, income or cash flow or to make distributions to unitholders are forward-looking statements. Forward-looking statements are not guarantees of performance. Such statements are based on management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve risks and uncertainties. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict.

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, transporting, storing, and distributing crude oil and other related products and buying, gathering, blending and selling crude oil. For a more detailed description of these and other factors that may affect the forward-looking statements, please read “Risk Factors” contained in our annual report on Form 10-K for the year ended December 31, 2004, as well as other filings with the SEC. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. You should not put undue reliance on these forward-looking statements. We disclaim any obligation to announce publicly the result of any revision to any of the forward-looking statements to reflect future events or developments.

Introduction

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

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

Overview

We are a publicly traded limited partnership engaged principally in the business of gathering, transporting, storing and distributing crude oil and related products in California and the Rocky Mountain region of the U.S. and in Alberta, Canada. We conduct our business through two regional business segments: the West Coast Business Unit and the Rocky Mountain Business Unit. We generate revenue primarily by charging tariff rates for transporting crude oil on our pipelines and by leasing storage capacity. We also buy, blend and sell crude oil, activities that are complementary to our pipeline transportation business.

Recent Developments

Line 63 Crude Oil Release

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

We have a pollution liability insurance policy with a $2.0 million deductible, and the insurance carrier has, subject to a reservation of certain rights, acknowledged coverage of the incident under the policy and has begun processing and paying invoices related to the clean-up. Although we believe we are entitled, subject to the $2.0 million deductible, to recover substantially all of

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

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

In addition, we expect to incur approximately $1.0 million in 2005 for the costs of repairing Line 63. These costs, which are not covered by our insurance, will be expensed as incurred during the remainder of 2005.

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

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

Sale of The Anschutz Corporation’s Interest in the Partnership

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

In connection with the conversion of our General Partner to a limited partnership, our General Partner ceased to have a board of directors, and is now managed by PEM, its general partner. PEM has a board of directors (the “Board of Directors” or “Board”) that manages the business and affairs of PEM and, thus, indirectly manages the business and affairs of our General Partner and the Partnership. The Board of Directors is comprised of eleven directors, six of whom served on the Board of Directors of our General Partner prior to the LB Acquisition, together with five new directors appointed by LBP. All of the officers and employees of our General Partner were transferred to the same positions with PEM, and the Board established the same committees as had been maintained by our General Partner prior to the LB Acquisition. PEM also adopted our General Partner’s governance guidelines and its compensation structure and employee benefit plans and policies.

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

Pursuant to an Ancillary Agreement, LBP and The Anschutz Corporation reimbursed us the amount of $2.4 million for the cost of a consent solicitation to the holders of our Senior Notes to amend the indenture governing the Senior Notes, and for severance and other costs incurred in connection with the sale of our General Partner. The Partnership was required by generally accepted accounting principles to record $0.6 million as capitalized deferred financing costs and $1.8 million as an expense. The reimbursements were recorded as a partner’s capital contribution.

On March 3, 2005, in connection with the change in control of the our General Partner, all restricted units outstanding under the Long-Term Incentive Plan immediately vested pursuant to the terms of the grants. The Partnership issued 99,583 common units and recorded a compensation expense of $3.1 million.

Business Fundamentals

Pipeline Transportation

We generate pipeline transportation revenue by charging tariff rates for transporting crude oil on our common carrier pipelines. The fundamental items impacting our pipeline transportation revenue are the volume of crude oil or throughput that we transport on our pipelines, and our tariff rates. Throughput on our pipelines fluctuates based on the volume of crude oil available for transport on our pipelines, the demand for refined products, refinery or pipeline downtime and the availability of alternate sources of crude oil for the refineries we serve.

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

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

On May 1, 2004, we increased the tariff rates on Line 2000 by approximately 6%, based on a contractually agreed index of cost changes. This index is reviewed annually. In April 2005, the CPUC approved an increase of approximately 4.8% in the tariff rate on Line 2000 effective May 1, 2005. Effective November 1, 2004, we increased the tariff rates on our Line 63 system by 9.5%. This increase was the first for Line 63 since 2001. These tariff rate increases partially mitigate the impact of declining throughput.

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

In March 2005, Shell Oil completed the sale of its Bakersfield refinery to Flying J, Inc. We believe we are well positioned to benefit from the refinery’s continued operation and we are working with Flying J to deliver additional volumes of crude oil to the Bakersfield refinery and deliver volumes from the refinery south to the Los Angeles Basin.

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

Storage and Distribution

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

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

Pipeline Buy/Sell Transportation

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

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

The Rangeland system operates as a proprietary system and, therefore, we take title to the crude oil that is gathered and transported. Pursuant to a transportation service agreement between two of our subsidiaries, Rangeland Marketing Company (“RMC”) and Rangeland Pipeline Partnership, RMC controls the entire capacity of Rangeland pipeline. Customers who wish to transport product on Rangeland pipeline must either: (i) sell product to RMC at an inlet point and repurchase such product at agreed upon delivery points for the price paid at the inlet to the pipeline plus an established location differential; or (ii) sell product to RMC at the inlet to the pipeline without repurchasing product from RMC.

Virtually all of the pipelines that comprise the Rangeland system are subject to the jurisdiction of the Alberta Energy Utilities Board (“EUB”). A short segment of the Rangeland system that connects to the Western Corridor system at the U.S.- Canadian border is subject to the jurisdiction of the Canadian National Energy Board (“NEB”). Neither the EUB nor the NEB will generally review rates set by a crude oil pipeline operator unless it receives a complaint relating to transportation rates.

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

Gathering and Blending

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

The contribution of our PMT gathering and blending operations is, for several reasons, a variable part of our income. First, it varies with the price differential between the cost of the varying grades of crude oil and natural gasoline that PMT buys for use in its blending operations, and the price of the blended crude oil it sells. Costs and sales prices are generally impacted by crude oil prices, as well as by local supply and demand forces, including regulations affecting refined product specifications. Second, it varies with the price differential between crude oil purchased on one price basis and sold on a different price basis. Finally, it varies with the volumes gathered and blended. We seek to control these variations through our risk management policy, which provides specific guidelines for our crude oil marketing and hedging activities and requires oversight by our senior management.

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

Acquisitions and New Projects

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

Operating Expenses

A substantial portion of the operating expenses we incur, including the cost of field and support personnel, maintenance, control systems, telecommunications, rights-of-way and insurance, varies little with changes in throughput. Certain of our costs do, however, vary with throughput, the most material being the cost of power used to run pump stations along our pipelines. Major maintenance costs can also vary depending on a particular asset’s age and/or regulatory requirements, such as mandatory inspections at defined intervals. Unanticipated costs can include the costs of cleanup of any release of oil to the extent not covered by insurance.

Employees

We do not have any employees, except in Canada. Our Managing General Partner provides employees to conduct our U.S. operations. We and our Managing General Partner collectively employ approximately 315 individuals who directly support our

operations. We consider employee relations to be good. None of these employees are subject to a collective bargaining agreement. Our Managing General Partner does not conduct any business other than with respect to the Partnership. All expenses incurred by our Managing General Partner are charged to us. Please read “Note 3 - Related Party Transactions” in the footnotes to the condensed consolidated financial statement.

Impact of Foreign Exchange Rates

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

Critical Accounting Policies and Estimates

Our consolidated 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 revenue 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 1, Significant Accounting Policies,” to our consolidated financial statements in our annual report on Form 10-K for the year ended December 31, 2004) and estimates, the following may involve a higher degree of judgment and complexity:

• 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 and liabilities assumed. The valuation of the fair value of the assets involves a number of judgments and estimates. In our major acquisitions to date, we have engaged an outside valuation firm to provide us with an appraisal report, which we utilized in determining the purchase price allocation. The allocation of the purchase price to different asset classes impacts the depreciation expense we subsequently record. The principal assets we have acquired to date are property, pipelines, storage tanks and equipment.

• 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 accrue an estimate of the undiscounted costs of environmental remediation for work at identified sites where an assessment has indicated it is probable that cleanup costs are or will be required 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 may use outside environmental consultants to assist us in making these estimates. We also are required to estimate the amount of any probable recoveries, including insurance recoveries. In addition, generally accepted accounting principles require us to establish liabilities for the costs of asset retirement obligations when the retirement date is determinable. We will record such liabilities only when such date is determinable.

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

• Our inventory of crude oil for our PMT gathering and blending operations, our Canadian operations and any inventory earned through our tariffs for the transportation of crude oil in our common carrier pipelines is carried on our books at the lower of cost or market value, unless it is hedged, in which case it is carried at market. On any unhedged portion, we are exposed to the potential for a write-down to market value.

Results of Operations

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

Summary

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

Net income for the three months ended March 31, 2005 includes the operations of the Rangeland system after its acquisition on May 11, 2004 and its expansion by acquisition of the MAPL pipeline on June 30, 2004.

Internally, in our analysis of operating results, we consider the impact of unusual items that we believe affect comparability between periods. We also believe that providing a discussion and analysis of our results that is comparable year over year, provides a more accurate and thorough analysis of our results of operations. We have also provided a reconciliation of net income to the results of our operations, excluding those unusual items, in the table below. Following is a discussion of each of the unusual items that impacted the results of our operations.

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

Accelerated long-term incentive plan compensation expense. On March 3, 2005, in connection with the change in control of our General Partner, all restricted units outstanding under the Long-term Incentive Plan immediately vested. As a result, for the three months ended March 31, 2005, we recognized $3.1 million in compensation expense.

Transaction costs. Pursuant to an Ancillary Agreement, LBP and The Anschutz Corporation reimbursed us $2.4 million for the cost of a consent solicitation to the holders of our Senior Notes to amend the indenture governing the Senior Notes and for severance and other costs incurred in connection with the sale of our General Partner. The Partnership was required by generally accepted accounting principles to record $0.6 million as capitalized deferred financing costs and $1.8 million as an expense. The reimbursements were recorded as a partner’s capital contribution.

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

	Three Months Ended March 31,
	2005		2004		Change			Percent
	(In thousands)
Net income	$	3,421	$	8,077	$	(4,656	)	-58	%
Add: Line 63 oil release costs	2,000		—		2,000			—
Accelerated long-term incentive plan compensation expense	3,115		—		3,115			—
Transaction costs	1,807		—		1,807			—
	$	10,343	$	8,077	$	2,266		28	%

Diluted weighted average limited partner units	29,673		25,149		4,524			18	%

The improvement in the results of operations, excluding the effect of the unusual items mentioned above, reflects the benefit of (i) higher pipeline transportation revenues on the West Coast and Rocky Mountain pipelines, (ii) the operations of the Rangeland system acquired in May 2004, and (iii) cost savings for Pacific Terminals. These increases were partially offset by significantly lower gathering and blending margins, which were below average in the three months ended March 31, 2005 and above average in the three months ended March 31, 2004. There were 29.7 million weighted average limited partner units outstanding in the three months ended March 31, 2005, approximately 18% more limited partner units than the 25.0 million weighted average units outstanding in the three months ended March 31, 2004, due to the sale of additional common units to partially fund the acquisition of the Rangeland system, including the MAPL pipeline.

Segment Information

The following is a discussion of segment operating income. Segment operating income does not include general and administrative expenses, accelerated long-term incentive compensation plan expense and transaction costs as these items are not allocated to the West Coast and Rocky Mountain business units.

	Three Months Ended March 31,
West Coast	2005		2004		Change			Percent
	(In thousands)

Operating income	$	9,743	$	12,255	$	(2,512	)	-20	%
Add: Line 63 oil release cost	2,000		—		2,000			—
	$	11,743	$	12,255	$	(512	)	-4	%
Operating data:
Pipeline throughput (bpd)	138.5		133.6		4.9			4	%

For the three months ended March 31, 2005, operating income excluding the effect of the net accrual of $2.0 million for the Line 63 oil release costs, was $11.7 million, compared to $12.3 million for the three months ended March 31, 2004. West Coast pipeline volumes for the three months ended March 31, 2005 were approximately 4% higher than the first quarter of 2004. During the first quarter of 2004, volumes were impacted by a significant amount of Los Angeles area refinery maintenance, resulting in lower volumes moving south to Los Angeles. For the three months ended March 2005, the Partnership also experienced incremental revenue from increased tariffs on Line 63 and Line 2000 implemented in 2004. During the three months ended March 2005, Pacific Terminals also experienced increased storage revenues due to higher rates of tank utilization and cost savings in vapor recovery costs due to the installation of vapor treating equipment that was installed at the end of 2004. These increases in operating income were offset by additional costs incurred to address earth movement and stream erosion problems at other locations along both Line 63 and Line 2000, caused by heavy rainfall. PMT gathering and blending margins were also lower in the first quarter of 2005 due to pricing pressures from steeply discounted crude oil imports and the interruption of a scheduled sale due to the Line 63 crude oil release. We consider this gathering and blending activity to be complementary to our pipeline transportation operations.

	Three Months ended March 31,
Rocky Mountains	2005		2004		Change			Percent
	(In thousands)

Operating income	$	9,578	$	3,641	$	5,937		163	%
Operating data (bpd):
Rangeland pipeline system:
Sundre—North	21.4		—					—
Sundre—South	48.2		—					—
Western Corridor system	22.5		16.0		6.5			41	%
Salt Lake City Core system	108.7		105.9		2.8			3	%
Frontier pipeline	38.3		43.9		(5.6		)	-13	%

For the three months ended March 31, 2005, operating income was $9.6 million compared, to $3.6 million for the three months ended March 31, 2004. The increase included the results of the Rangeland system which was acquired in the second quarter of 2004. In addition, increased market share for pipeline shipments of crude oil to Billings, Montana and increased demand by the Salt Lake City, Utah, refineries, helped drive higher pipeline volumes on the U.S. Rocky Mountain systems other than Frontier pipeline. Frontier pipeline volumes in 2005 were affected by a shortage of synthetic crude oil supply caused by a fire at a Suncor Energy, Inc. facility in December 2004. Shippers have now replaced these volumes with other types of crude oil and volumes are expected to return to normal levels in the second quarter of this year.

Statement of Income—Discussion and Analysis

	Three months ended March 31,
Revenues	2005			2004			Change			Percent
	(In thousands)

Pipeline transportation revenue	$	28,037		$	24,727		$	3,310		13	%
Storage and distribution revenue	10,322			10,123			199			2	%
Pipeline buy/sell transportation revenue	9,106			—			9,106			—
Crude oil sales, net of purchases:
Crude oil sales	116,173			85,927			30,246			35	%
Crude oil purchases	(114,391		)	(81,115		)	33,276			41	%
Crude oil sales, net of purchases	1,782			4,812			(3,030		)	-63	%

Net revenue	$	49,247		$	39,662		$	9,585		24	%

Increased pipeline transportation revenues were realized by both our West Coast and U.S. Rocky Mountain pipelines. Higher volumes and increased tariff rates increased West Coast revenues. Volumes on the U.S. Rocky Mountain pipelines were higher due to increased demand by refineries in Billings, Montana, Casper, Wyoming and Salt Lake City, Utah area refineries.

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

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

The decrease in net crude oil sales for the three months ended March 31, 2005 was primarily the result of lower margin blending activities in our West Coast operations, particularly due to competitive pricing pressures as a result of cheaper foreign crude entering the West Coast markets. Higher oil prices increased gross sales and purchases values. We consider this gathering and blending activity to be complementary to our pipeline transportation operations.

	Three Months ended March 31,
Expenses	2005		2004		Change		Percent
	(In thousands)

Operating expenses	$	21,754	$	18,917	$	2,837	15	%
Line 63 oil release costs	2,000		—		2,000		—
General and administrative expense	5,172		3,854		1,318		34	%
Transaction costs	1,807		—		1,807		—
Accelerated long-term incentive plan compensation expense	3,115		—		3,115		—
Depreciation and amortization	6,529		5,242		1,287		25	%
	$	40,377	$	28,013	$	12,364	44	%

The increase in operating expense was related primarily to the acquisition of the Rangeland system on May 11, 2004. Operating expenses in the West Coast were also higher as a result of unscheduled repairs and maintenance and pipeline relocation expenses on Line 2000 and Line 63 resulting from earth movements and creek washouts caused by recent heavy rains.

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

The increase in general and administrative expense was associated with the integration of the Rangeland acquisition, certain expensed costs for the Pier 400 project and costs for compliance with the Sarbanes-Oxley Act. These items were not applicable in the corresponding period of 2004.

Transaction costs are discussed in “Recent Developments” above.

On March 3, 2005, in connection with the change in control of the General Partner, all restricted units outstanding under the Long-term Incentive Plan immediately vested. For the three months ended March 31, 2005, we recognized $3.1 million in compensation expense as a result.

The increase in depreciation and amortization includes $1.5 million for depreciation on the Rangeland system. These increases were partly offset by lower depreciation on other assets reflecting assets that have now been fully depreciated.

	Three Months ended March 31,
Other Income and Expense	2005		2004		Change			Percent
	(In thousands)

Share of net income of Frontier	$	357	$	393	$	(36	)	-9	%

Interest expense	$	5,598	$	4,126	$	1,472		35	%

Other income	$	353	$	161	$	192		119	%

Income tax expense	$	561	$	—	$	561		—

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

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

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

The income tax expense for the three months ended March 31, 2005 relates to the income of the Rangeland system acquired in the second quarter of 2004. Our Canadian subsidiaries are taxable entities, and certain kinds of repatriation of funds into the U.S. are subject to Canadian withholding tax. Additionally, we recorded deferred tax liabilities in connection with the purchase of our Canadian subsidiaries, which we recover periodically in earnings.

Liquidity and Capital Resources

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

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

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

Our ability to satisfy our debt service obligations, fund planned capital expenditures, make acquisitions, develop projects and pay distributions to our unitholders will depend upon our future operating performance. Our operating performance is primarily dependent on the volume of crude oil transported through our pipelines and the capacity leased in our storage tanks as described in “Overview” above. Our operating performance is also affected by prevailing economic conditions in the crude oil industry and financial, business and other factors, some of which are beyond our control, which could significantly impact future results.

Operating, Investing and Financing Activities

	Three Months Ended March 31,
	2005			2004			Change
	(In thousands)
	(unaudited)

Net cash provided by operating activities	$	15,932		$	13,182		$	2,750
Net cash used in investing activities	(4,260		)	(12,333		)	8,073
Net cash provided by (used in) financing activities	(12,958		)	31,284			(44,242		)

Net cash provided by operating activities

The increase in the net cash from operating activities of $2.8 million, or 21%, was the result of the Rangeland system’s contribution to operating income, together with a decrease in cash used for working capital, partially offset by the cash portion of the accelerated vesting of units under the Long-term Incentive Plan and transaction costs.

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

Net cash used in investing activities

Capital expenditures were $4.4 million in the first quarter of 2005, of which $0.2 million related to sustaining capital projects, $2.3 million related to transition projects, $1.2 million related to expansion and $0.7 million was for our continued development of the Pier 400 Project. Capital expenditures for the three months ended March 31, 2004 were $2.4 million of which $0.5 million related to sustaining capital projects, $0.1 million related to the transition of the Pacific Terminals storage and distribution system, and $1.8 million related to expansion. The 2004 period also includes $9.9 million related to a deposit paid and acquisition costs incurred for the Rangeland system and MAPL assets.

Net cash provided by and used in financing activities

Distributions of $15.1 million were made to the limited partners and the General Partner during the period ended March 31, 2005. Additionally, TAC and LBP contributed $2.4 million to reimburse us for certain costs incurred in connection with the LB Acquisition. The amount of cash provided by financing activities in 2004, $31.3 million, includes net proceeds of $116.7 million from an equity offering completed on March 30, 2004, which was used to fund a portion of the acquisition of the Rangeland system, net repayment of $73.0 million under our revolving credit facility, and $12.4 million in distributions to the limited and general partner interests.

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:

•	sustaining capital expenditures to replace partially or fully depreciated assets in order to maintain the existing operating capacity or efficiency of our assets and extend their useful lives;

•	transitional capital expenditures to integrate acquired assets into our existing operations; and

•	expansion capital expenditures to expand or increase the efficiency of the existing operating capacity of our assets, whether through construction or acquisition, such as placing new storage tanks in service to increase our storage capabilities and revenue, and adding new pump stations or pipeline connections to increase our transportation throughput and revenue.

We have forecasted total capital expenditures for our existing operations of $34.3 million for the remainder of 2005, including $3.1 million for the Pier 400 Project, $20.2 million for expansion projects, $7.7 million relating to the transition of the Rangeland system, $1.4 million for other transition capital projects, and $1.9 million for sustaining capital projects.

Pier 400

In February 2004, we completed an initial feasibility study for the development of a deepwater petroleum import terminal at Pier 400 and Terminal Island in the Port of Los Angeles (“POLA”) to handle marine receipts of crude oil and refinery feedstocks. We are developing the Pier 400 terminal to participate in the marine import business, which is growing as a result of a decline in imports from Alaska and the local production decline. The Pacific Terminals storage and distribution assets also benefit by the increase in the marine import business.

We initiated the environmental review and permitting for the Pier 400 project in June 2004 and expect to have the permits necessary for construction to begin by the second quarter of 2006. We entered into a project development agreement with two subsidiaries of Valero Energy Corporation (“Valero”) that defines the facilities that we are to construct in the POLA. We and Valero have also signed a terminaling services agreement with a 30-year, 50,000 bpd volume commitment from Valero to support the terminal. These agreements are subject to the satisfaction of various conditions.

If the Pier 400 terminal receives the necessary governmental approvals and is successfully developed, a deepwater berth, high capacity transfer infrastructure and storage tanks will be constructed at Pier 400 and Terminal Island in the POLA, and a pipeline distribution system will be constructed to connect the terminal’s storage tanks to Valero’s Wilmington refinery and to our customers’ facilities in the Los Angeles Basin through our Pacific Terminals storage and distribution system. We would construct the transfer infrastructure, including a large diameter pipeline system for receiving bulk petroleum liquids from marine vessels, and the storage tanks.

Final construction of the Pier 400 project is subject to the completion of a land lease agreement with the POLA, receipt of environmental and other approval, securing additional customer commitments, updating engineering and project cost estimates, ongoing feasibility evaluation, and financing. A final decision to proceed is expected to be made in the first quarter of 2006. We expect construction of the Pier 400 terminal to be completed and placed in service in 2007.

We have capitalized approximately $11.2 million on the Pier 400 project through March 31, 2005, including $0.7 million for the three months ended March 31, 2005. These expenditures include $6.3 million for emission reduction credits, an asset that is re-saleable if the project does not proceed. We anticipate funding pre-construction costs through early-2006 from our revolving credit facility. Construction of the Pier 400 terminal is expected to be financed through a combination of debt and proceeds from the issuance of additional partnership units, including common units.

Debt Obligations

At March 31, 2005, our debt obligations include: (i) $52.0 million on our senior secured U.S. revolving credit facility, (ii) Cdn$65.0 million (U.S.$53.7 million) on our senior secured Canadian revolving credit facility, (iii) $246.9 million on our 71/8% Senior Notes, due June 2014, and (iv) Cdn$4.5 million (U.S.$3.7 million) payable to the seller of the MAPL assets. For further discussion of these debt obligations see “Note 4—Long-term Debt” to the accompanying condensed consolidated financial statements.

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

Off-Balance Sheet Arrangements

The Partnership has no off-balance sheet arrangements.

Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123 (revised December 2004), Share-Based Payment (SFAS 123R). This Statement is a revision of SFAS No. 123. SFAS 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. SFAS 123R is effective for the Partnership as of the beginning of the first annual reporting period that begins after June 15, 2005. The Partnership has not yet determined the impact of the adoption of SFAS 123R on the Partnership’s consolidated financial statements.

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 bears variable interest at either the applicable base or prime rate, a rate based on LIBOR or a rate based on Canadian Bankers’ Acceptances. We have used and will continue to use from time to time derivative instruments to hedge our exposure to variable interest rates. In addition, we have entered into swap agreements to convert a portion of our fixed rate Senior Notes into floating rate debt based on LIBOR.

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

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

We are subject to risks resulting from interest rate fluctuations as the interest cost on our credit facilities and the $80 million interest swap on the Senior Notes are based on variable rates. If the LIBOR or Canadian Bankers’ Acceptance discount rates were to increase 1.0% for the remainder of 2005 as compared to the rate at December 31, 2004, our interest expense for the remainder of 2005 would increase $1.4 million based on our outstanding debt at March 31, 2005.

Fair Value of Financial Instruments

The carrying amount and fair values of financial instruments are as follows:

	March 31,				December 31,
	2005				2004
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(in thousands)

Crude oil hedging futures	$	1,410	$	1,410	$	400	$	400
Fair value interest rate swaps	1,063		1,063		2,693		2,693
Long-term debt	356,369		366,020		357,163		373,265

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

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


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

Exhibit Number		Description

* Exhibit 31.1		Certification of Principal Executive Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., as required by Rule 13a-14(a) of the Securities Exchange Act of 1934
* Exhibit 31.2		Certification of Principal Financial Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., as required by Rule 13a-14(a) of the Securities Exchange Act of 1934
† Exhibit 32.1		Certification of Chief Executive Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., pursuant to 18 U.S.C. §1350
† Exhibit 32.2		Certification of Chief Financial Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., pursuant to 18 U.S.C. §1350

PACIFIC ENERGY PARTNERS, L.P.
By:			PACIFIC ENERGY GP, LP, its General Partner
By:			PACIFIC ENERGY MANAGEMENT LLC, its General Partner

	By:	/S/ IRVIN TOOLE, JR.
		Irvin Toole, Jr.
		President, Chief Executive Officer
		and Director
		(Principal Executive Officer)
		May 3, 2005

	By:	/S/ GERALD A. TYWONIUK
		Gerald A. Tywoniuk
		Senior Vice President, Chief Financial
		Officer and Treasurer
		(Principal Financial and Accounting Officer)
		May 3, 2005

Exhibit Number		Description

* Exhibit 31.1		Certification of Principal Executive Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., as required by Rule 13a-14(a) of the Securities Exchange Act of 1934
* Exhibit 31.2		Certification of Principal Financial Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., as required by Rule 13a-14(a) of the Securities Exchange Act of 1934
† Exhibit 32.1		Certification of Chief Executive Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., pursuant to 18 U.S.C. §1350
† Exhibit 32.2		Certification of Chief Financial Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., pursuant to 18 U.S.C. §1350