UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

DATE OF REPORT (DATE OF EARLIEST EVENT REPORTED)
September 6, 2005

PACIFIC ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware		313345		68-0490580
(State or other jurisdiction of incorporation or organization)		(Commission File Number)		(IRS Employer Identification No.)

5900 Cherry Avenue
Long Beach, CA 90805
(Address of principal executive office)

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

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

ITEM 7.01 REGULATION FD DISCLOSURE

The purpose of this Form 8-K is to communicate changes to Pacific Energy Partners, L.P.’s (the “Partnership”) presentation of EBITDA and Distributable Cash Flow.

The Partnership’s historical presentation of EBITDA (earnings before interest, taxes, depreciation and amortization), as adjusted for certain other non-cash items, disclosed in prior filings required by the Securities Exchange Act of 1934 (“Exchange Act”) and press releases, is consistent with how this measure is calculated pursuant to the Partnership’s revolving credit facilities and bond indenture and consistent with how the Partnership understands debt analysts and rating agencies calculate the measure. Similar to depreciation, certain other non-cash items have historically been added back to net income in arriving at EBITDA used in the Partnership’s credit facilities. Going forward, however, in future Exchange Act filings and press releases, the Partnership will change its presentation of EBITDA to conform to the acronym earning before interest, taxes and depreciation and amortization without adjustment for other non-cash items.

In addition, although the Partnership will continue to reconcile Net Income to Distributable Cash Flow, it will now also reconcile Distributable Cash Flow to Net Cash Provided by Operating Activities, the closest GAAP measure. The Partnership’s calculation of Distributable Cash Flow no longer includes non-recurring items which are expected to result in a cash outlay.

EBITDA

EBITDA is used as a supplemental performance measure by management, and the Partnership believes, by external users of its financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (i) the financial performance of its assets without regard to financing methods, capital structures or historical cost basis; (ii) the ability of its assets to generate cash sufficient to pay interest cost and support the Partnership’s indebtedness; (iii) the Partnership’s operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing and capital structure; and (iv) the viability of projects and the overall rates of return on alternative investment opportunities.

The Partnership defines EBITDA as net income plus interest expense, income tax expense (recovery) and depreciation and amortization expense. Although the Partnership is not a taxable entity, its Canadian subsidiaries are taxable entities. As a result of the acquisition of the Rangeland system, Canadian income tax expense is added to net income in the calculation of EBITDA beginning with the second quarter of 2004.

EBITDA should not be considered an alternative to net income, income before taxes, cash flows from operations, or any other measure of financial performance presented in accordance with GAAP. EBITDA is not intended to represent cash flow. The Partnership’s EBITDA may not be comparable to EBITDA or similarly titled measures of other companies.

A reconciliation from reported net income to EBITDA is as follows:

	Year Ended December 31,						Six Months Ended June 30,
	2004(a)		2003(b)		2002(b)		2005(c)		2004
	(in thousands)

Net income	$	35,729	$	25,029	$	33,574	$	15,641	$	17,205
Interest expense	19,209		17,487		11,634		11,442		8,509
Depreciation and amortization	24,173		18,865		15,919		13,135		10,955
Income tax expense (recovery)	261		—		—		704		(14		)
EBITDA	$	79,372	$	61,381	$	61,127	$	40,922	$	36,655

(a) For the year ended December 31, 2004, EBITDA was reduced by $0.8 million for the write-down of idle property associated with the pending sale of an idle Pacific Terminals property, by $2.9 million for the write-off of deferred financing cost and interest rate swap termination expense and $0.9 million for the non-cash portion of long term incentive compensation plan expense.

(b) For the years ended December 31, 2003 and 2002, EBITDA was reduced by $2.2 million and $0.1 million, respectively, for the non-cash portion of long term incentive compensation plan expense.

(c) For the period ended June 30, 2005, EBITDA was reduced by $6.9 million for certain unusual items, including (i) $3.1 million compensation expense related to the accelerated vesting of the Partnership’s long-term incentive plan resulting from the change in control of the general partner of the Partnership, (ii) $1.8 million for transaction costs associated with the change in control of the general partner of the Partnership that were required to be recorded by generally accepted accounting principles and were reimbursed by the Partnership’s general partner, and (iii) $2.0 million insurance deductible expense relating to the release of approximately 3,400 barrels of crude oil on PPS’s Line 63 when it was severed as a result of a landslide induced by heavy rainfall in northern Los Angeles County.

Distributable Cash Flow

On July 26, 2002, the Partnership completed its initial public offering of common units. Accordingly, distributable cash flow is not presented for 2002. Distributable Cash Flow (“DCF”) is a significant liquidity and performance measure used by management of the Partnership to compare cash flows generated by the Partnership to the cash distributions it makes to its partners. The Partnership believes that investors benefit from having access to the same financial measures being utilized by management. Using this financial measure, management can quickly compute the coverage ratio of cash flows to cash distributions. This is an important financial measure for limited partners of the Partnership since it is an indicator of the Partnership’s success in providing a cash return on their investment. Specifically, this financial measure tells investors whether or not the Partnership is generating cash flows at a level that can sustain or support an increase in its quarterly cash distributions paid to partners. Lastly, DCF is the quantitative standard used throughout the investment community with respect to publicly traded partnerships, because the value of a partnership unit is in part measured by its yield (which in turn is based on the amount of cash distributions a partnership pays to its unitholders). However, DCF is a non-GAAP financial measure and should not be considered as an alternative to net income, cash flow from operations, or any other measure of financial performance presented in accordance with accounting principles generally accepted in the United States. In addition, the Partnership’s DCF may not be comparable to DCF or similarly titled measures of other companies. The GAAP measure most directly comparable to DCF is net cash provided by operating activities.

Several adjustments to DCF are required to reconcile to net cash provided by operating activities. These adjustments include: (i) adding back or subtracting net changes in operating assets and liabilities which are not included in DCF but are considered in net cash provided by operating activities; (ii) subtracting the Partnerhip’s share of Frontier Pipeline Company’s (“Frontier”) net income, which historically has been approximately equivalent to our distributions from Frontier, and adding the Partnership’s share of Frontier’s distributions to the Partnership; (iii) deducting transaction costs reimbursed by the Partnership’s general partner, which are required by GAAP to reduce net cash provided by operating activities; and (v) adding back sustaining capital expenditures which are not deducted in arriving at net cash provided by operating activities.

A calculation of DCF together with a reconciliation of DCF to cash provided by operating activities for the years ended December 31, 2004 and 2003 and the six months ended June 30, 2005 and 2004 is as follows:

	Year Ended December 31,						Six Months Ended June 30,
	2004			2003			2005			2004
	(in thousands)

Net income	$	35,729		$	25,029		$	15,641		$	17,205
Depreciation and amortization	24,173			18,865			13,135			10,955
Amortization of debt issue costs and accretion of discount on long-term debt	1,537			1,028			937			670
Non-cash employee compensation under long-term incentive plan	857			2,199			1,429			1,351
Write-off of deferred financing cost	2,321			—			—			2,321
Write-down of idle property	800			—			—			—
Transaction costs	—			—			1,807			—
Deferred income tax expense (benefit)	(65		)	—			217			(46		)
Sustaining capital expenditures	(1,953		)	(2,149		)	(827		)	(725		)
Distributable cash flow (a)	63,399			44,972			32,339			31,731

Less net (increase) decrease in operating assets and liabilities	(6,754		)	(6,284		)	14,958			(3,075		)
Add share of loss of Frontier (deduct share of income of Frontier)	(1,328		)	162			(847		)	(784		)
Add net distributions from Frontier (deduct contributions to Frontier)	(44		)	1,755			650			668
Less transaction costs	—			—			(1,807		)	—
Add other non-cash adjustments	—			—			98			—
Add sustaining capital expenditures	1,953			2,149			827			725

Net cash provided by operating activities	$	57,226		$	42,754		$	46,218		$	29,265

(a) For the period ended June 30, 2005, distributable cash flow has been reduced by $2.0 million of oil release costs and $1.9 million of cash costs associated with the accelerated vesting of units. For the year ended December 31, 2004 and the six months ended June 30, 2004, distributable cash flow has been reduced by $0.6 million cash expense to terminate interest rate swaps.

The information in Item 7.01 of this report is being furnished, not filed, pursuant to Regulation FD. Accordingly, the information in Item 7.01 of this report will not be incorporated by reference into any registration statement filed by the Partnership under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference.

SIGNATURES

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

	PACIFIC ENERGY PARTNERS, L.P.

		By:	PACIFIC ENERGY GP, LP,
			its general partner

			By:	PACIFIC ENERGY MANAGEMENT LLC,
				its general partner

				By:	/s/ Gerald Tywoniuk
					Gerald Tywoniuk
					Senior Vice President, Chief Financial Officer and Treasurer


Dated: September 6, 2005