SEC Filing - Plains All American Pipeline

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 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) August 23, 2006

Plains All American Pipeline, L.P.

(Exact name of registrant as specified in its charter)

DELAWARE	1-14569	76-0582150
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

333 Clay Street, Suite 1600 Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code (713) 646-4100

N/A

(Former name or former address, if changed since last report.)

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 9.01 Financial Statements and Exhibits

On June 12, 2006 Plains All American Pipeline, L.P. (the “Partnership”) announced that it had entered into a Purchase Agreement and an Agreement and Plan of Merger, pursuant to which Pacific Energy Partners, L.P. (“PPX”) will be merged into the Partnership. The attached exhibits include the updated pro forma financial statements as of and for the six months ended June 30, 2006 and for the twelve months ended December 31, 2005 for the probable acquisition and the historical financial statements of PPX.

(d) Exhibits

99.1		Unaudited Pro Forma Condensed Combined Financial Statements of Plains All American Pipeline, L.P. as of and for the six months ended June 30, 2006 and for the twelve months ended December 31, 2005.
99.2		Pacific Energy Partners, L.P. Condensed Consolidated Financial Statements (Unaudited) as of June 30, 2006 and for the three and six months ended June 30, 2006 and June 30, 2005.

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 hereunto duly authorized.

	PLAINS ALL AMERICAN PIPELINE, L.P.
Date: August 23, 2006	By:	Plains AAP, L.P., its general partner
	By:	Plains All American GP LLC, its general partner
	By:	/s/ TINA L. VAL
		Name: Tina L. Val
		Title: Vice President—Accounting and Chief Accounting Officer

INDEX TO EXHIBITS

99.1		Unaudited Pro Forma Condensed Combined Financial Statements of Plains All American Pipeline, L.P. as of and for the six months ended June 30, 2006 and for the twelve months ended December 31, 2005.
99.2		Pacific Energy Partners, L.P. Condensed Consolidated Financial Statements (Unaudited) as of June 30, 2006 and for the three and six months ended June 30, 2006 and June 30, 2005.

Exhibit 99.1

Plains All American Pipeline, L.P.

Unaudited Pro Forma Condensed Combined Financial Statements of Plains All American Pipeline, L.P. as of and for the six months ended June 30, 2006 and for the twelve months ended December 31, 2005.

PLAINS ALL AMERICAN PIPELINE, L.P.
INDEX TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

Introduction		F-2
Unaudited Pro Forma Condensed Combined Balance Sheet at June 30, 2006		F-3
Unaudited Pro Forma Condensed Statement of Combined Operations for the Six Months Ended June 30, 2006		F-4
Unaudited Pro Forma Condensed Statement of Combined Operations for the Twelve Months Ended December 31, 2005		F-5
Notes to the Unaudited Pro Forma Condensed Combined Financial Statements		F-6
Pro Forma Sensitivity Analysis		F-11

F-1

PLAINS ALL AMERICAN PIPELINE, L.P.
UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

The following unaudited pro forma condensed combined financial statements give effect to the proposed merger of Pacific Energy Partners, L.P. (“Pacific”) into Plains All American Pipeline, L.P. (“Plains”). The merger-related transactions include:

· The acquisition from LB Pacific, LP and its affiliates (“LB Pacific”) of the general partner interest and incentive distribution rights of Pacific as well as 2,616,250 common units of Pacific and 7,848,750 subordinated units of Pacific for a total of $700 million in cash; and

· The acquisition of the balance of Pacific’s equity through a unit-for-unit merger in which each Pacific unitholder (other than LB Pacific) will receive 0.77 newly issued Plains common units for each Pacific common unit.

Upon consummation of the merger-related transactions, the general partner and limited partner ownership interests in Pacific will be extinguished and Pacific will be merged with and into Plains. Pacific’s operating subsidiaries will be directly or indirectly owned by Plains. The proposed merger-related transactions will be accounted for using the purchase method of accounting. The estimates of fair value of the assets acquired and liabilities assumed are based on preliminary assumptions, pending the completion of an independent appraisal, with any excess of purchase price over the net fair value of assets acquired and liabilities assumed assigned to goodwill.

The following unaudited pro forma condensed statement of combined operations for the six months ended June 30, 2006 and the year ended December 31, 2005 have been prepared as if the transactions described above had taken place on January 1, 2005. The unaudited pro forma condensed combined balance sheet at June 30, 2006 assumes the transactions were consummated on that date.

The unaudited pro forma financial statements should be read in conjunction with and are qualified in their entirety by reference to the notes accompanying such unaudited pro forma financial statements as well as the notes included in the historical financial statements included in the following public filings:

(1) Plains’ Annual Report on Form 10-K for the year ended December 31, 2005;

(2) Plains’ Quarterly Report on Form 10-Q for the quarter ended June 30, 2006;

(3) Pacific’s Annual Report on Form 10-K and Form 10-K/A for the year ended December 31, 2005; and

(4) Pacific’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006.

The unaudited pro forma financial statements are based on assumptions that Plains believes are reasonable under the circumstances and are intended for informational purposes only. They are not necessarily indicative of the results of the actual or future operations or financial condition that would have been achieved had the transactions occurred at the dates assumed (as noted above).

The unaudited pro forma financial statements do not give effect to any anticipated cost savings or other financial benefits expected to result from the merger.

F-2

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET
June 30, 2006
(in millions)

	Plains			Pacific			Pro Forma				Plains
	Historical			Historical			Adjustments				Pro Forma
CURRENT ASSETS
Cash and cash equivalents		$	7.6		$	22.8		$	20.4	(b)		$	30.4
								937.6		(b)
								(217.3		)(b)
								(740.7		)(b)
Trade accounts receivable and other receivables, net		1,917.2			188.3			(9.2		)(c)		2,096.3
Inventory		1,155.9			36.2			3.1		(b)		1,195.2
Other current assets		95.7			7.4			—				103.1
Total current assets		3,176.4			254.7			(6.1		)		3,425.0
PROPERTY AND EQUIPMENT, net		2,147.5			1,237.8			(53.5		)(a)		3,567.5
								235.7		(b)
OTHER ASSETS
Pipeline linefill in owned assets		200.4			—			52.6		(a)		281.0
								28.0		(b)
Inventory in third party assets		80.4			—			0.9		(a)		83.3
								2.0		(b)
Investments in unconsolidated affiliates		124.4			8.3			—				132.7
Goodwill		179.6			—			784.2		(b)		963.8
Other, net		109.6			87.2			27.5		(b)		224.3
Total assets		$	6,018.3		$	1,588.0		$	1,071.3			$	8,677.6
CURRENT LIABILITIES
Accounts payable and accrued liabilities		$	1,850.8		$	187.4		$	(9.2	)(c)		$	2,029.0
Due to related parties		0.2			—			—				0.2
Short-term debt		1,188.5			—			—				1,188.5
Other current liabilities		139.9			17.8			—				157.7
Total current liabilities		3,179.4			205.2			(9.2		)		3,375.4
LONG-TERM LIABILITIES
Long-term debt under credit facilities and other		58.4			—			217.3		(a)		996.0
								937.6		(b)
								(217.3		)(b)
Senior notes, net		1,196.7			—			418.1		(a)		1,636.5
								21.7		(b)
Senior notes and credit facilities, net		—			635.4			(635.4		)(a)		—
Other long-term liabilities and deferred credits		57.7			55.4			7.9		(b)		121.0
Total liabilities		4,492.2			896.0			740.7				6,128.9
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL
Common unitholders		1,485.6			635.7			1,002.2		(b)		2,487.8
								(635.7		)(b)
Subordinated unitholders		—			22.5			(22.5		)(b)		—
General partner		40.5			12.3			20.4		(b)		60.9
								(12.3		)(b)
Undistributed employee long-term incentive compensation		—			0.2			(0.2		)(b)		—
Accumulated other comprehensive income		—			21.3			(21.3		)(b)		—
Total partners’ capital		1,526.1			692.0			330.6				2,548.7
Total Liabilities and Partners’ Capital		$	6,018.3		$	1,588.0		$	1,071.3			$	8,677.6

See notes to unaudited pro forma condensed combined financial statements

F-3

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA CONDENSED STATEMENT OF COMBINED OPERATIONS
For the Six Months Ended June 30, 2006
(in millions, except per unit data)

	Plains Historical				Pacific Historical				Pro Forma Adjustments				Plains Pro Forma
REVENUES		$	13,527.8			$	149.3			$	(15.3	)(d)		$	13,661.8
COSTS AND EXPENSES
Purchases and related costs		13,087.4				—				(14.4		)(d)		13,073.0
Field operating costs		168.9				65.1				(0.9		)(d)		233.1
General and administrative expenses		59.2				12.6				—				71.8
Depreciation and amortization		42.9				20.3				1.2		(a)		66.3
										(20.3		)(e)
										22.2		(f)
Merger costs		—				3.4				—				3.4
Total costs and expenses		13,358.4				101.4				(12.2		)		13,447.6
Share of net income of Frontier		—				0.9				(0.9		)(a)		—
OPERATING INCOME		169.4				48.8				(4.0		)		214.2
OTHER INCOME (EXPENSE)
Equity earnings (loss) in unconsolidated affiliates		0.9				—				0.9		(a)		1.8
Interest expense		(33.3		)		(19.2		)		(21.2		)(g)		(72.5		)
										1.2		(a)
Interest income and other income, net		0.4				0.8				—				1.2
Income from continuing operations before income taxes		137.4				30.4				(23.1		)		144.7
Income tax (expense) benefit:
Current		—				(1.8		)		—		(h)		(1.8		)
Deferred		—				4.5				—		(h)		4.5
Income from continuing operations before cumulative effect of change in accounting principle		137.4				33.1				(23.1		)		147.4
Cumulative effect of change in accounting principle		6.3				—				—				6.3
NET INCOME (LOSS) FROM CONTINUING OPERATIONS		$	143.7			$	33.1			$	(23.1	)		$	153.7
NET INCOME FROM CONTINUING OPERATIONS—LIMITED PARTNERS		$	128.2											$	147.8
NET INCOME FROM CONTINUING OPERATIONS—GENERAL PARTNER		$	15.5											$	5.9
BASIC NET INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT
Basic net income per limited partner unit before cumulative effect of change in accounting principle		$	1.47											$	1.32
Cumulative effect of change in accounting principle per limited partner unit		0.08												0.06
Basic net income from continuing operations per limited partner unit		$	1.55											$	1.38
DILUTED NET INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT
Diluted net income per limited partner unit before cumulative effect of change in accounting principle		$	1.45											$	1.31
Cumulative effect of change in accounting principle per limited partner unit		0.08												0.06
Diluted net income from continuing operations per limited partner unit		$	1.53											$	1.37
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING		75.5								22.3		(b)		97.8
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING		76.3								22.3		(b)		98.6

See notes to unaudited pro forma condensed combined financial statements

F-4

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA CONDENSED STATEMENT OF COMBINED OPERATIONS
For the Twelve Months Ended December 31, 2005
(in millions, except per unit data)

	Plains Historical			Pacific Historical				Pro Forma Adjustments				Plains Pro Forma
REVENUES	$	31,177.3			$	224.3			$	(12.6	)(d)	$	31,389.0
COSTS AND EXPENSES
Purchases and related costs	30,442.5				—				(11.2		)(d)	30,431.3
Field operating costs	272.5				104.4				(1.4		)(d)	375.5
General and administrative expenses	103.2				18.5				—			121.7
Accelerated long-term incentive plan compensation expense	—				3.1				—			3.1
Line 63 oil release costs	—				2.0				—			2.0
Transaction costs	—				1.8				—			1.8
Depreciation and amortization	83.5				29.4				2.0		(a)	129.8
									(29.4		)(e)
									44.3		(f)
Total costs and expenses	30,901.7				159.2				4.3			31,065.2
Other, net	—				(0.5		)		—			(0.5		)
Share of net income of Frontier	—				1.8				(1.8		)(a)	—
OPERATING INCOME	275.6				66.4				(18.7		)	323.3
OTHER INCOME (EXPENSE)
Equity earnings in unconsolidated affiliates	1.0				—				1.8		(a)	2.8
Interest expense	(59.4		)		(26.7		)		(43.6		)(g)	(127.7		)
									2.0		(a)
Interest income and other income, net	0.6				1.1				—			1.7
Income from continuing operations before income taxes	217.8				40.8				(58.5		)	200.1
Income tax (expense) benefit:
Current	—				(1.3		)		—		(h)	(1.3		)
Deferred	—				0.1				—		(h)	0.1
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	$	217.8			$	39.6			$	(58.5	)	$	198.9
NET INCOME FROM CONTINUING OPERATIONS—LIMITED PARTNERS	$	198.8										$	194.9
NET INCOME FROM CONTINUING OPERATIONS—GENERAL PARTNER	$	19.0										$	4.0
BASIC NET INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT	$	2.77										$	2.07
DILUTED NET INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT	$	2.72										$	2.04
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING	69.3								22.3		(b)	91.6
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING	70.5								22.3		(b)	92.8

See notes to unaudited pro forma condensed combined financial statements

F-5

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

These unaudited pro forma condensed combined financial statements and underlying pro forma adjustments are based upon currently available information and certain estimates and assumptions made by the management of Plains and Pacific; therefore, actual results could differ materially from the pro forma information. However, we believe the assumptions provide a reasonable basis for presenting the significant effects of the transactions noted herein. Plains believes the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma information. Please read “Pro Forma Sensitivity Analysis” for assumptions related to fair value estimates.

The Plains Pro Forma income before cumulative effect of change in accounting principle for the year ended December 31, 2005 includes, as required, the following pro forma adjustments related to the acquisition of the Valero assets that Pacific acquired effective September 30, 2005: (i) depreciation expense for the entire year of approximately $11 million associated with Plains' estimated purchase price allocated to the Valero assets; and (ii) interest expense of approximately $11 million for the entire year on the $175 million 6 1¤4% senior notes issued to fund the asset acquisition. However, since the Valero transaction was an asset acquisition, the Plains Pro Forma income before cumulative effect of change in accounting principle for the year ended December 31, 2005 does not include revenues and related operating expenses for the period prior to the asset acquisition by Pacific. In addition, the Plains Pro Forma income before cumulative effect of change in accounting principle for the year ended December 31, 2005 and the six months ended June 30, 2006 does not include any synergies that Plains expects to achieve as a result of the merger with Pacific.

The merger of Pacific into Plains presented in these pro forma statements has been accounted for using the purchase method of accounting and the purchase price allocation has been estimated in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations.” The total estimated consideration is summarized below (in millions):

Cash payment to LB Pacific	$	700.0
Estimated fair value of Plains common units to be issued in exchange for Pacific common units (see below)	1,002.2
Assumption of Pacific debt (at estimated fair value)	657.1
Estimated transaction costs	40.7
Total consideration	$	2,400.0

F-6

Plains will exchange 0.77 of its common units for each Pacific common unit remaining after Plains’ purchase of 2,616,250 common units owned by LB Pacific. Although cash will be paid for any fractional units as a result of the exchange, such amount is not estimable at this time. Plains currently estimates that the number of Plains common units to be issued in the exchange will be 22,262,030 calculated as follows:

Pacific units outstanding at June 30, 2006
Common units	31,457,782
Subordinated units	7,848,750
Total historical units outstanding at June 30, 2006	39,306,532
Pro forma adjustments to Pacific historical units outstanding:
Plains purchase of subordinated units held by LB Pacific	(7,848,750		)
Plains purchase of common units held by LB Pacific	(2,616,250		)
Issuance of common units for outstanding Pacific restricted unit awards	70,195
Pro forma Pacific common units subject to exchange offer by Plains	28,911,727
Exchange ratio (0.77 Plains common units for each Pacific common unit)	0.77
Pro forma Plains units to be issued to Pacific common unitholders in connection with merger	22,262,030
Average closing price of Plains common units (see below)	$	45.02
Estimated fair value of Plains common units to be issued in exchange for Pacific common units (in millions)	$	1,002.2

In accordance with purchase accounting rules, the pro forma value of the units issued in the exchange is based on the average closing price of Plains common units immediately prior to and after the merger was announced on June 12, 2006. The following table shows the closing prices of Plains common units for the two trading days prior to and after the proposed merger was announced.

June 8, 2006	$	46.30
June 9, 2006	46.10
June 13, 2006	43.88
June 14, 2006	43.81
Average closing price of Plains common units	$	45.02

Upon completion of the proposed merger or shortly thereafter, Plains will obtain a valuation of Pacific’s assets and liabilities in order to develop a definitive allocation of the purchase price. As a result, the final purchase price allocation may result in some amounts being assigned to tangible or amortizable intangible assets apart from goodwill.

F-7

The following table shows Plains’ preliminary purchase price allocation (in millions):

Description	Amount			Average Depreciable Life
PP&E	$	1,420.0			5-40
Inventory	39.3				n/a
Pipeline linefill and inventory in third party assets	83.5				n/a
Intangible assets	96.8				30
Working capital, excluding inventory	13.4				n/a
Other long-term assets and liabilities, net	(37.2		)		n/a
Goodwill (see below)	784.2				n/a
Total	$	2,400.0

To the extent that any amount is assigned to a tangible or finite lived intangible asset, this amount may ultimately be depreciated or amortized (as appropriate) to earnings over the expected period of benefit of the asset. To the extent that any amount remains as goodwill or indefinite lived intangible assets, this amount would not be subject to depreciation or amortization, but would be subject to periodic impairment testing and, if necessary, would be written down to fair value should circumstances warrant.

The following table shows Plains’ preliminary calculation of the estimated pro forma goodwill amount (in millions):

Cash payment to LB Pacific	$	700.0
Estimated fair value of Plains common units to be issued in exchange for Pacific public units	1,002.2
Estimated transaction costs	40.7
Total consideration, excluding debt assumed	1,742.9
Estimated fair value of Pacific’s net assets	958.7
Excess of purchase price over net assets of Pacific preliminarily assigned to goodwill	$	784.2

For an analysis of the sensitivity of pro forma earnings to potential reclassifications of this preliminary goodwill amount to tangible or intangible assets, please read “Pro Forma Sensitivity Analysis” below.

The following table shows Plains’ preliminary calculation of the sources of funding for the acquisition (in millions):

Estimated fair value of Plains common units to be issued in exchange for Pacific common units	$	1,002.2
Plains general partner capital contribution	20.4
Assumption of Pacific debt (at estimated fair value)	657.1
Repayment of Pacific credit facility	(217.3		)
Plains new debt incurred	937.6
Total sources of funding	$	2,400.0

F-8

Pro Forma Adjustments

a. To reclassify certain line items on Pacific’s historical financial statements to conform to Plains’ historical presentation.

b. Records the cash paid, equity exchanged, additional obligations assumed and adjustments to fair value of the assets purchased and liabilities assumed in the merger based on the purchase method of accounting.

c. Reflects the elimination of accounts receivable and accounts payable balances between Plains and Pacific.

d. Reflects the elimination of purchases and sales between Plains and Pacific.

e. To reverse historical depreciation and amortization as recorded by Pacific.

f. Reflects depreciation and amortization on the acquired assets based on the straight-line method of depreciation over average useful lives ranging from 5 to 40 years.

g. Reflects the adjustment to interest expense for (i) the increase in long-term debt of approximately $938 million from a “bridge” credit facility using an average interest rate of 6.0%, (ii) the decrease in long-term debt of approximately $217 million from the repayment of the Pacific credit facility and (iii) the amortization of the premium on the senior notes. The impact to interest expense of a 1¤8% change in interest rates would be approximately $1.4 million per year.

h. The pro forma adjustments to the statements of combined operations have not been tax-effected as the effect on income tax expense is not deemed to be material to the pro forma results of operations.

Plains Earnings per Limited Partner Unit

Earnings per limited partner unit is determined by dividing net income after deducting the amount allocated to the general partner interest, including its incentive distribution in excess of its 2% interest, by the weighted average number of limited partner units outstanding during the period. Plains’ general partner is entitled to receive incentive distributions if the amount it distributes with respect to any quarter exceeds levels specified in its partnership agreement. Upon closing of the proposed merger, Plains’ general partner has agreed to reduce the amounts due it as incentive distributions commencing with the earlier to occur of (i) the payment date of the first quarterly distribution declared and paid after the closing date that equals or exceeds $0.80 per unit or (ii) the payment date of the second quarterly distribution declared and paid after the closing date. Such adjustment shall be as follows: (i) $5 million per quarter for the first four quarters, (ii) $3.75 million per quarter for the next eight quarters, (iii) $2.5 million per quarter for the next four quarters, and (iv) $1.25 million per quarter for the final four quarters. The total reduction in incentive distributions will be $65 million.

F-9

The following sets forth the computation of basic and diluted earnings per limited partner unit for Plains on a historical and pro forma basis. The net income available to limited partners and the weighted average limited partner units outstanding have been adjusted for instruments considered common unit equivalents.

	Six Months ended June 30, 2006								Year ended December 31, 2005
	Plains Historical				Plains Pro Forma				Plains Historical				Plains Pro Forma
	(in millions, except per unit data)
Numerator for basic and diluted earnings per limited partner unit:
Net income		$	143.7			$	153.7			$	217.8			$	198.9
Less: General partner's incentive distribution paid		(12.9		)		(12.9		)		(15.0		)		(15.0		)
Incentive distribution reduction		—				10.0				—				15.0
Subtotal		130.8				150.8				202.8				198.9
General partner 2% ownership		(2.6		)		(3.0		)		(4.1		)		(4.0		)
Net income available to limited partners		128.2				147.8				198.7				194.9
EITF 03-06 additional general partner's distribution		(11.2		)		(12.5		)		(7.1		)		(5.3		)
Net income available to limited partners under EITF 03-06		$	117.0			$	135.3			$	191.6			$	189.6
Less: Limited partner 98% portion of cumulative effect of change in accounting principle		6.2				6.2				—				—
Limted partner net income before cumulative effect of change in accounting principle		$	110.8			$	129.1			$	191.6			$	189.6
Denominator:
Historical weighted average number of limited partner units outstanding		75.5				75.5				69.3				69.3
Common unit exchange		—				22.3				—				22.3
Denominator for basic earnings per limited partner unit		75.5				97.8				69.3				91.6
Effect of dilutive securities:
Weighted average LTIP units outstanding		0.8				0.8				1.2				1.2
Denominator for diluted earnings per limited partner unit		76.3				98.6				70.5				92.8
Basic net income per limited partner unit before cumulative effect of change in accounting principle		$	1.47			$	1.32			$	2.77			$	2.07
Cumulative effect of change in accounting principle per limited partner unit		0.08				0.06				—				—
Basic net income per limited partner unit		$	1.55			$	1.38			$	2.77			$	2.07
Diluted net income per limited partner unit before cumulative effect of change in accounting principle		$	1.45			$	1.31			$	2.72			$	2.04
Cumulative effect of change in accounting principle per limited partner unit		0.08				0.06				—				—
Diluted net income per limited partner unit		$	1.53			$	1.37			$	2.72			$	2.04

F-10

PRO FORMA SENSITIVITY ANALYSIS

Certain of the pro forma adjustments incorporate Plains’ preliminary estimate of the fair value of the business that Plains is acquiring. Preliminary estimates are that the excess of the purchase price over the preliminary fair values (“excess cost”) may be assigned to non-amortizable other intangible assets or goodwill as opposed to depreciable fixed assets or amortizable intangible assets. Upon completion of the proposed merger or shortly thereafter, Plains will obtain a valuation of Pacific’s assets and liabilities in order to develop a definitive allocation of the purchase price. As a result, the final purchase price allocation may result in some amounts being assigned to tangible or amortizable intangible assets, and this amount may ultimately be depreciated or amortized (as appropriate) to earnings over the expected benefit period of the asset. To the extent that any amount remains as goodwill or indefinite lived intangible assets, this amount would not be subject to depreciation or amortization, but would be subject to periodic impairment testing and, if necessary, would be written down to a lower fair value should circumstances warrant.

The table below shows the potential increase in pro forma depreciation or amortization expense if certain amounts of the goodwill were ultimately assigned to tangible or amortizable intangible assets. For purposes of calculating this sensitivity, Plains has applied the straight-line method of cost allocation over an estimated useful life of 34 years to various fair values. The decrease in annual basic earnings per unit is predicated on the basic earnings per unit determined using the pro forma income from continuing operations amount. The resulting pro forma adjustments are as follows (in millions, except per unit amounts):

For the Six Months Ended June 30, 2006

Estimated Goodwill	Change in Allocation				Average Depreciable Life of Assets		Decrease in Net Income from Continuing Operations				Decrease in Net Income from Continuing Operations per Limited Partner Unit
$784.2	20	%	$	156.8		34		$	(2.3	)		$	(0.01	)
$784.2	40	%	$	313.7		34		$	(4.6	)		$	(0.02	)
$784.2	60	%	$	470.5		34		$	(6.9	)		$	(0.04	)
$784.2	80	%	$	627.4		34		$	(9.2	)		$	(0.05	)
$784.2	100	%	$	784.2		34		$	(11.5	)		$	(0.07	)

Estimated Goodwill	Change in Allocation				Average Depreciable Life of Assets		Decrease in Net Income from Continuing Operations				Decrease in Net Income from Continuing Operations per Limited Partner Unit
$784.2	20	%	$	156.8		34		$	(4.6	)		$	(0.04	)
$784.2	40	%	$	313.7		34		$	(9.2	)		$	(0.08	)
$784.2	60	%	$	470.5		34		$	(13.8	)		$	(0.11	)
$784.2	80	%	$	627.4		34		$	(18.5	)		$	(0.14	)
$784.2	100	%	$	784.2		34		$	(23.1	)		$	(0.19	)

F-11

Exhibit 99.2

Pacific Energy Partners, L.P.

Pacific Energy Partners, L.P. Condensed Consolidated Financial Statements (Unaudited) as of June 30, 2006 and for the three and six months ended June 30, 2006 and June 30, 2005.

TABLE OF CONTENTS

Condensed Consolidated Balance Sheets (Unaudited)—As of June 30, 2006 and December 31, 2005		1
Condensed Consolidated Statements of Income (Unaudited)—For the Three and Six Months Ended June 30, 2006 and 2005		2
Condensed Consolidated Statement of Partners’ Capital (Unaudited)—For the Six Months Ended June 30, 2006		3
Condensed Consolidated Statements of Comprehensive Income (Unaudited)—For the Three and Six Months Ended June 30, 2006 and 2005		4
Condensed Consolidated Statements of Cash Flows (Unaudited)—For the Six Months Ended June 30, 2006 and 2005		5
Notes to Condensed Consolidated Financial Statements (Unaudited)		6

PACIFIC ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,		December 31,
	2006		2005
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	22,823		$	18,064
Crude oil sales receivable	149,674			95,952
Transportation and storage accounts receivable	27,479			30,100
Canadian goods and services tax receivable	5,338			8,738
Insurance proceeds receivable	5,800			9,052
Due from related parties	141			—
Crude oil and refined products inventory	36,193			20,192
Prepaid expenses	3,717			7,489
Other	3,524			2,528
Total current assets	254,689			192,115
Property and equipment, net	1,237,794			1,185,534
Intangible assets, net	69,354			69,180
Investment in Frontier	8,322			8,156
Other assets, net	17,791			21,467
	$	1,587,950		$	1,476,452
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	37,838		$	42,409
Accrued crude oil purchases	145,041			96,651
Line 63 oil release reserve	4,480			5,898
Accrued interest	5,320			4,929
Other	12,459			6,300
Total current liabilities	205,138			156,187
Senior notes and credit facilities, net	635,368			565,632
Deferred income taxes	32,833			35,771
Environmental liabilities	16,572			16,617
Other liabilities	6,006			4,006
Total liabilities	895,917			778,213
Commitments and contingencies (note 6)
Partners’ capital:
Common unitholders (31,457,782 and 31,448,931 units outstanding at June 30, 2006 and December 31, 2005, respectively)	635,706			644,589
Subordinated unitholders (7,848,750 units outstanding at June 30, 2006 and December 31, 2005)	22,474			24,758
General Partner interest	12,295			12,535
Undistributed employee long-term incentive compensation	231			—
Accumulated other comprehensive income	21,327			16,357
Net partners’ capital	692,033			698,239
	$	1,587,950		$	1,476,452

See accompanying notes to condensed consolidated financial statements.

PACIFIC ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended June 30,								Six Months Ended June 30,
	2006				2005				2006				2005
	(in thousands, except per unit amounts)
Revenues:
Pipeline transportation revenue		$	34,800			$	27,747			$	68,657			$	55,784
Storage and terminaling revenue		21,867				10,870				41,953				21,192
Pipeline buy/sell transportation revenue		11,427				8,116				21,126				17,222
Crude oil sales, net of purchases of $353,590 and $122,442 for the three months ended June 30, 2006 and 2005 and $609,909 and $236,833 for the six months ended June 30, 2006 and 2005		10,720				6,042				17,529				7,824
		78,814				52,775				149,265				102,022
Cost and Expenses:
Operating (which excludes $586 of compensation expense for the six months ended June 30, 2005 reported in accelerated long-term incentive plan compensation expense)		31,655				25,292				65,074				47,046
General and administrative (which excludes $2,529 of compensation expense for the six months ended June 30, 2005 reported in accelerated long-term incentive plan compensation expense)		5,714				3,700				12,587				8,872
Depreciation and amortization		10,292				6,606				20,294				13,135
Merger costs (note 2)		3,417				—				3,417				—
Accelerated long-term incentive plan compensation expense (note 7)		—				—				—				3,115
Line 63 oil release costs (note 6)		—				—				—				2,000
Reimbursed general partner transaction costs (note 5)		—				—				—				1,807
		51,078				35,598				101,372				75,975
Share of net income of Frontier		475				490				873				847
Operating income		28,211				17,667				48,766				26,894
Interest expense		(10,088		)		(5,844		)		(19,176		)		(11,442		)
Interest and other income		292				540				735				893
Income before income taxes		18,415				12,363				30,325				16,345
Income tax (expense) benefit:
Current		(1,409		)		245				(1,803		)		(487		)
Deferred (note 3)		4,437				(388		)		4,535				(217		)
		3,028				(143		)		2,732				(704		)
Net income		$	21,443			$	12,220			$	33,057			$	15,641
Net income (loss) for the general partner interest		$	392			$	244			$	373			$	(1,458	)
Net income for the limited partner interests		$	21,051			$	11,976			$	32,684			$	17,099
Basic and diluted net income per limited partner unit		$	0.54			$	0.40			$	0.83			$	0.58
Weighted average limited partner units outstanding:
Basic		39,307				29,723				39,304				29,689
Diluted		39,314				29,742				39,322				29,708

See accompanying notes to condensed consolidated financial statements.

PACIFIC ENERGY PARTNERS, L.P.
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, 2005		31,449		7,849		$	644,589			$	24,758			$	12,535			$	—			$	16,357		$	698,239
Net income		—		—		26,158				6,526				373				—				—			33,057
Distribution to partners		—		—		(35,306		)		(8,810		)		(1,498		)		—				—			(45,614		)
Employee compensation under LB Pacific, LP option plan		—		—		—				—				880				—				—			880
Employee compensation under long-term incentive plan		—		—		—				—				—				546				—			546
Issuance of common units pursuant to long-term incentive plan		9		—		265				—				5				(315		)		—			(45		)
Foreign currency translation adjustment		—		—		—				—				—				—				5,144			5,144
Change in fair value of crude oil and foreign currency hedging contracts		—		—		—				—				—				—				(174		)	(174		)
Balance, June 30, 2006		31,458		7,849		$	635,706			$	22,474			$	12,295			$	231			$	21,327		$	692,033

See accompanying notes to condensed consolidated financial statements.

PACIFIC ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended June 30,								Six Months Ended June 30,
	2006				2005				2006				2005
	(in thousands)
Net income		$	21,443			$	12,220			$	33,057			$	15,641
Change in fair value of crude oil and hedging derivatives		—				327				260				(806		)
Change in fair value of foreign currency hedging derivatives		(488		)		—				(434		)		—
Change in foreign currency translation adjustment		5,413				(1,765		)		5,144				(2,301		)
Comprehensive income		$	26,368			$	10,782			$	38,027			$	12,534

See accompanying notes to condensed consolidated financial statements.

PACIFIC ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Six Months Ended June 30,
	2006				2005
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	33,057			$	15,641
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		20,294				13,135
Amortization of debt issue costs		1,222				937
Non-cash of employee compensation under long-term incentive plan		546				2,886
Non-cash employee compensation under the LB Pacific, LP Option Plan		880				—
Deferred tax expense (benefit)		(4,535		)		217
Share of net income of Frontier		(873		)		(847		)
Other adjustments		(1,649		)		98
Distributions from Frontier, net		622				650
Net changes in operating assets and liabilities:
Crude oil sales receivable		(52,795		)		(8,819		)
Transportation and storage accounts receivable		2,723				1,699
Insurance proceeds receivable		5,476				(6,705		)
Crude oil and refined products inventory		(15,693		)		963
Other current assets and liabilities		11,752				1,079
Accounts payable and other accrued liabilities		(3,034		)		9,638
Accrued crude oil purchases		47,204				11,113
Line 63 oil release reserve		(3,643		)		4,981
Other non-current assets and liabilities		534				(522		)
NET CASH PROVIDED BY OPERATING ACTIVITIES		42,088				46,144
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions		(2,365		)		—
Additions to property and equipment		(42,524		)		(9,877		)
Additions to pipeline linefill and minimum tank inventory		(16,419		)		—
Other		168				(98		)
NET CASH USED IN INVESTING ACTIVITIES		(61,140		)		(9,975		)
CASH FLOWS FROM FINANCING ACTIVITIES
Capital contributions from the general partner		—				2,438
Proceeds from credit facilities		130,409				66,283
Repayment of credit facilities		(60,950		)		(64,326		)
Deferred financing costs		—				(600		)
Distributions to partners		(45,614		)		(30,658		)
Related parties		(141		)		(686		)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		23,704				(27,549		)
Effect of exchange rates on cash		107				74
NET INCREASE IN CASH AND CASH EQUIVALENTS		4,759				8,694
CASH AND CASH EQUIVALENTS, beginning of reporting period		18,064				23,383
CASH AND CASH EQUIVALENTS, end of reporting period		$	22,823			$	32,077

See accompanying notes to condensed consolidated financial statements.

PACIFIC ENERGY PARTNERS, L.P.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2006
(Unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Pacific Energy Partners, L.P. and its subsidiaries (collectively, the “Partnership”) are engaged principally in the business of gathering, transporting, storing and distributing crude oil, refined products and other related products. The Partnership generates revenue primarily by transporting such commodities on its pipelines, by leasing storage capacity in its storage tanks, and by providing other terminaling services. The Partnership also buys and sells crude oil, activities that are generally complementary to its other crude oil operations. The Partnership conducts its business through two business units, the West Coast Business Unit, which includes activities in California and the Philadelphia, Pennsylvania area, and the Rocky Mountain Business Unit, which includes activities in five Rocky Mountain states and Alberta, Canada.

The Partnership is managed by its general partner, Pacific Energy GP, LP, a Delaware limited partnership, which is managed by its general partner, Pacific Energy Management LLC (“PEM”), a Delaware limited liability company. Thus, the officers and board of directors of PEM manage the business affairs of Pacific Energy GP, LP and the Partnership. References to the “General Partner” refer to Pacific Energy GP, LP and/or PEM, as the context indicates: and “Board of Directors” refers to the board of directors of PEM.

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 six months ended June 30, 2006 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 assets acquired from Valero, L.P., since the acquisition of these assets on September 30, 2005. The assets acquired from Valero, L.P. have been integrated into our West Coast and Rocky Mountain Business Units as the Pacific Atlantic Terminals and the Rocky Mountain Products Pipeline.

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, 2005. Certain prior year balances in the accompanying condensed consolidated financial statements have been reclassified to conform to the current year presentation.

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 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 interim period or annual reporting period that begins after June 15, 2005. The adoption of SFAS 123R on January 1, 2006 did not have a material impact on the Partnership’s consolidated financial statements. See Notes 4 and 7 to the condensed consolidated financial statements for more details on share-based compensation.

In September 2005, the Emerging Issues Task Force (“EITF”) issued Issue No. 04-13 (“EITF 04-13”), Accounting for Purchases and Sales of Inventory with the Same Counterparty. The issues addressed by the EITF are (i) the circumstances under which two or more exchange transactions involving inventory with the same counterparty should be viewed as a single exchange transaction for the purposes of evaluating the effect of APB No. 29; and (ii) whether there are circumstances under which nonmonetary exchanges of inventory within the same line of business should be recognized at fair value. EITF 04-13 is effective for new arrangements entered into in the reporting periods beginning after March 15, 2006, and to all inventory transactions that are completed after December 15, 2006, for arrangements entered into prior to March 15, 2006. The adoption of EITF 04-13 did not have a material impact on the Partnership’s consolidated financial statements.

In June 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes. This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 will apply to the Partnership’s Canadian subsidiaries, which are taxable entities in Canada. The Partnership is in the process of determining the impact of FIN 48 on its financial statements, but does not expect it to have a material impact. FIN 48 is effective for the Partnership as of the beginning of the first fiscal year beginning on January 1, 2007.

In June 2006, the EITF issued Issue No. 06-3 (“EITF 06-3), How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation). The issues addressed by the EITF are (i) whether the scope of this Issue should include (a) all nondiscretionary amounts assessed by governmental authorities, (b) all nondiscretionary amounts assessed by governmental authorities in connection with a transaction with a customer, or (c) only sales, use, and value added taxes, and (ii) how taxes assessed by a governmental authority within the scope of this issue should be presented in the income statement (that is, gross versus net presentation). EITF 06-3 is effective for interim and annual financial periods beginning after December 15, 2006. The Partnership is in the process of determining the impact of EITF 06-3 on its financial statements, but does not expect it to have a material impact.

2. PROPOSED MERGER WITH PLAINS ALL AMERICAN PIPELINE, L.P.

On June 12, 2006, the Partnership announced that it had entered into an Agreement and Plan of Merger with Plains All American Pipeline, L.P. (“PAA”), Plains AAP, L.P., a Delaware limited partnership, Plains All American GP LLC (“PAA GP LLC”), PEM, and Pacific Energy GP, LP, pursuant to which the Partnership will be merged with and into PAA. In the merger, each common unitholder of the Partnership, except LB Pacific, LP (“LB Pacific”), the owner of the Partnership’s General Partner, will receive 0.77 common units of PAA for each common unit of the Partnership that the unitholder owns. In addition, pursuant to a purchase agreement between LB Pacific and PAA, PAA will acquire from LB Pacific the general partner interest and incentive distribution rights of the Partnership as well as 2,616,250 common units and 7,848,750 subordinated units for total consideration of $700 million in cash. The merger agreement was unanimously approved by the Board of Directors of PEM, as well as by the PAA GP LLC board of directors.

If the proposed transaction is ultimately consummated, the general partner and limited partner interests in the Partnership will be extinguished and the Partnership will cease to exist as a separate legal

entity. The Partnership’s operating subsidiaries will be directly or indirectly owned by PAA. PAA’s management team and board of directors will continue in their current roles and manage the combined company. The merger is expected to close in the fourth quarter of 2006.

Each of the Partnership and PAA made customary representations, warranties and covenants in the merger agreement, including covenants restricting the Partnership’s ability to initiate or continue any discussions with any other person with respect to a business combination while the merger is pending or to engage in any of those discussions unless the failure to do so would be reasonably likely to constitute a violation of fiduciary duties. The merger agreement may be terminated by the Partnership and/or PAA in specified circumstances, and provides that upon termination of the merger agreement in circumstances involving a competing proposal to acquire the Partnership or PAA, the parties are required to pay one another termination fees of up to $40 million. The merger is subject to the satisfaction or waiver of certain conditions, including, among others:

· the adoption and approval of the merger agreement and the merger by the affirmative vote of the holders of at least a majority of the Partnership’s outstanding common units (excluding common units held by LB Pacific) and at least a majority of the Partnership’s outstanding subordinated units, each voting as a separate class;

· the adoption and approval of the merger agreement and the merger by the affirmative vote of the holders of at least a majority of PAA’s outstanding common units, and the approval of the issuance of PAA common units pursuant to the merger agreement by the affirmative vote of the holders of at least a majority of PAA’s outstanding common units;

· receipt of required regulatory approvals, including pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approvals of Canadian governmental authorities, the Federal Communications Commission, the Public Utilities Commission of the state of California and the Public Service Commission of the state of Wyoming (see “Note 9—Subsequent Events”);

· the continued effectiveness of PAA’s registration statement on Form S-4 to register the PAA common units to be issued in the merger, and the approval for listing on the New York Stock Exchange of such PAA common units;

· the absence of any decree, order, injunction or law that prohibits the merger or makes the merger unlawful; and

· the consummation of the transactions contemplated by the purchase agreement between PAA and LB Pacific.

Each of PAA and LB Pacific made customary representations, warranties and covenants in the purchase agreement. The purchase agreement may be terminated by LB Pacific or PAA upon or after termination of the merger agreement, and may be terminated at any time by the mutual written agreement of LB Pacific and PAA. In addition, the purchase agreement is subject to customary closing conditions, including satisfaction of all conditions specified in the merger agreement.

During the three and six months ended June 30, 2006, the Partnership incurred approximately $3.4 million in costs directly relating to the merger for investment banking fees, legal fees, and other transaction costs. Approximately $0.7 million of investment banking fees were payable to affiliates of Lehman Brothers Inc., an indirect partial owner of the General Partner (see “Note 5—Related Party Transactions”). These costs are included in the condensed consolidated statements of income under the caption “Merger costs”.

3. 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. However, the Partnership’s Canadian subsidiaries are taxable entities in Canada and are subject to Canadian federal and provincial income taxes. In addition, inter-company interest payments and repatriation of funds through dividend payments are subject to withholding tax.

Income taxes for the Partnership’s Canadian subsidiaries 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 of a change in tax rates on deferred tax assets and liabilities is recognized in operations in the period that includes the enactment date. The Partnership intends to repatriate its Canadian subsidiaries’ earnings in the future and accordingly has recorded a provision for Canadian withholding taxes.

During the quarter ended June 30, 2006, the Canadian and Alberta governments enacted legislation which will reduce federal and provincial income taxes. The Partnership adjusted the future income tax rates used in the estimates of deferred tax assets and liabilities and recognized a $4.6 million deferred tax benefit during the three and six months ended June 30, 2006.

4. NET INCOME PER LIMITED PARTNER UNIT

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.

Basic net income per limited partner unit is determined by dividing net income, after adding back costs and deducting certain amounts allocated to the General Partner (including incentive distribution payments in excess of its 2% ownership 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, if any, and restricted units by application of the treasury stock method.

Set forth below is the computation of net income allocated to limited partners and net income per basic and diluted limited partner unit. The table also shows the reconciliation of basic average limited partner units to diluted weighted average limited partner units.

	Three Months Ended June 30,								Six Months Ended June 30,
	2006				2005				2006				2005
	(in thousands)
Numerator:
Net income allocated to limited partners:
Net income		$	21,443			$	12,220			$	33,057			$	15,641
Costs allocated to the general partner(1):
LBP Option Plan cost		369				—				880				—
Senior Notes consent solicitation and other costs		—				—				—				893
Severance and other costs		—				—				—				914
Total costs allocated to the general partner		369				—				880				1,807
Income before costs allocated to the general partner		21,812				12,220				33,937				17,448
Less: general partner incentive distributions		(331		)		—				(586		)		—
		21,481				12,220				33,351				17,448
Less: General partner 2% ownership		(430		)		(244		)		(667		)		(349		)
Net income for the limited partners		$	21,051			$	11,976			$	32,684			$	17,099
Denominator:
Basic weighted average limited partner units		39,307				29,723				39,304				29,689
Effect of restricted units		7				—				18				—
Effect of options		—				19				—				19
Diluted weighted average limited partner units		39,314				29,742				39,322				29,708
Basic and diluted net income per limited partner unit		$	0.54			$	0.40			$	0.83			$	0.58

(1) See “Note 5—Related Party Transactions” for a description of transaction costs reimbursed by the General Partner.

5. RELATED PARTY TRANSACTIONS

Cost Reimbursements

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

LB Pacific, LP Option Plan: LB Pacific, LP (“LBP”), the owner of the Partnership’s General Partner, has adopted an option plan for certain officers, directors, employees, advisors, and consultants of PEM, LBP, and their affiliates. Under the plan, participants may be granted options to acquire partnership interests in LBP. The Partnership is not obligated to pay any amounts to LBP for the benefits granted or paid to any participants under the plan, although generally accepted accounting principles require that the Partnership record an expense in its financial statements for benefits granted to employees of PEM or the Partnership who provide services to the Partnership, with a corresponding increase in the General Partner’s capital account.

The option plan is administered by the board of directors of LB Pacific GP, LLC, the general partner of LBP. The terms, conditions, performance goals, restrictions, limitations, forfeiture, vesting or exercise schedule, and other provisions of grants under the plan, as well as eligibility to participate are determined by the board of directors of LB Pacific GP, LLC. The board of directors of LB Pacific GP, LLC may determine to grant options under the plan to participants containing such terms as the board of LB Pacific GP, LLC shall determine. Options will have an exercise price that may not be less than the fair market value of the units on the date of grant.

The board of directors of LB Pacific GP, LLC may terminate or amend the unit option plan at any time with respect to units for which a grant has not yet been made. However, no change may be made that would materially impair the rights of a participant with respect to an outstanding grant without the consent of the participant.

Information concerning the plan and grants is shared by LB Pacific, LP with the General Partner’s Compensation Committee and Board of Directors, and considered in determining the long term incentive compensation paid by the Partnership to participants in the plan.

In January 2006, LBP granted options representing a maximum 24% interest in LBP (assuming all options vest and are exercised), which options vest over a period of 10 years from the date of grant (except in limited circumstances such as a change in control), to certain officers and key employees of PEM and the Partnership. The grants, qualified as equity-classified awards, had a grant date fair value of $8.6 million. The fair value of the options was determined using valuation techniques that included the discounted present value of estimated future cash flows for LBP and fundamental analysis. It was measured using the Black-Scholes option pricing model with the following assumptions:

Expected volatility	21.86	%
Expected dividend yield	0	%
Expected term (in years)	10
Risk-free rate	4.37	%

For the three and six months ended June 30, 2006, the Partnership recognized $0.4 million and $0.9 million in compensation expense relating to the LBP options and recorded a capital contribution from the General Partner for the same amounts. At June 30, 2006, all granted LBP options remained outstanding. At June 30, 2006, there was $7.7 million of total unrecognized compensation cost related to nonvested options granted under the plan which cost was expected to be recognized over the remaining period of 9.5 years. Upon the close of the proposed merger with PAA, the options will become immediately exercisable. Total unrecognized compensation expense on the closing date will be immediately recognized in the income statement.

LB Pacific, LP and Anschutz: Prior to March 3, 2005, the General Partner was owned by The Anschutz Corporation (“Anschutz”). On March 3, 2005, Anschutz sold its interest in the Partnership, including its interest in the General Partner, to LBP. In connection with the sale of Anschutz’s interest in the Partnership to LBP, LBP and Anschutz reimbursed the Partnership for certain costs incurred in connection with the 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, for a total of $2.4 million. Of the $2.4 million total incurred, $1.8 million was expensed, as shown on the income statement as “reimbursed general partner transaction costs”, and $0.6 million of the consent solicitation costs were capitalized as deferred financing costs.

Special Agreement: On March 3, 2005, Douglas L. Polson, previously the Chairman of the Board of Directors 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 effective

March 3, 2005. Mr. Polson was paid approximately $0.9 million, representing accrued salary through March 3, 2005, accrued but unused vacation and payment in satisfaction of other obligations under his employment agreement. The latter portion of this payment was recorded as an expense in “Reimbursed general partner transaction costs” in the accompanying condensed consolidated income statements. LBP reimbursed this amount, which was recorded as a partner’s capital contribution. Pursuant to the Consulting Agreement, Mr. Polson agreed to perform advisory services to PEM from time to time as mutually agreed between Mr. Polson and the Chief Executive Officer of PEM. In consideration for Mr. Polson’s services under the Consulting Agreement, which had a one-year term, Mr. Polson received 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.

Lehman Brothers, Inc.

Lehman Brothers, Inc. is deemed to be an affiliate of the Partnership’s General Partner through a 59% ownership interest in LBP, which is controlled by Lehman Brothers Holdings Inc., the parent entity of Lehman Brothers, Inc. Lehman Brothers, Inc. acted as financial advisor to LBP and the Partnership in connection with the proposed merger and the transactions related to the merger (see Note 2—Proposed Merger With Plains All American, L.P.). Lehman Brothers, Inc. delivered an opinion to the Board of Directors to the effect that, as of the date of its opinion and based on and subject to various assumptions made, the aggregate consideration to be offered to all of the holders of the partnership interests in the Partnership in the proposed transaction is fair to such holders. The agreement with Lehman Brothers, Inc. was reviewed and approved by the Conflicts Committee of the Board of Directors and the fees charged were customary for the type of services provided. For the three and six months ended June 30, 2006, the Partnership incurred $0.7 million in fees with Lehman Brothers, Inc. The Partnership has agreed to pay Lehman Brothers, Inc. an additional $7.7 million success fee contingent on the successful consummation of the merger.

Other Related Party Transactions

RMPS 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 activities. RMPS received $0.2 million for each of the three months ended June 30, 2006 and 2005 and $0.4 million for each of the six months ended June 30, 2006 and 2005, respectively. The Partnership owns a 22.22% partnership interest in Frontier.

6. CONTINGENCIES

Line 63 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 caused by heavy rainfall in the Pyramid Lake area of Los Angeles County. Over the period March 2005 through anticipated completion in June 2007, the Partnership expects to incur an estimated total of $25.5 million for oil containment and clean-up of the impacted areas, future monitoring costs, potential third-party claims and penalties, and other costs, excluding pipeline repair costs. As of June 30, 2006, the Partnership had incurred approximately $21.1 million of the total expected remediation costs related to the oil release for work performed through that date. The Partnership estimates that the $4.4 million of remaining remediation cost will be incurred before June 2007.

The Partnership has a pollution liability insurance policy with a $2.0 million per-occurrence deductible that covers containment and clean-up costs, third-party claims and certain penalties. The insurance carrier has, subject to the terms of the insurance policy, acknowledged coverage of the incident and is 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. As of June 30, 2006, the Partnership has recovered $17.7 million from insurance and recorded receivables of $5.8 million for future insurance recoveries it deems probable.

On or about March 17, 2006, Pacific Pipeline System LLC (“PPS”), a subsidiary of the Partnership, was served with a four count misdemeanor action by the state of California, which alleges that PPS violated various state statutes by depositing oil or substances harmful to wildlife into the environment and by the willful and intentional discharge of pollution into state waters. The Partnership estimates that the maximum fine and penalties that could be assessed for these actions is approximately $0.9 million in the aggregate. The Partnership believes, however, that certain of the alleged violations are without merit and intends to defend against them, and that mitigating factors should otherwise reduce the amounts of any potential fines or penalties that might be assessed. At this time, the Partnership cannot reasonably determine the outcome of these allegations. The estimated range of possible fines or penalties including amounts not covered by insurance is between $0 and $0.9 million.

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 plans, the ongoing assessment of the impact of soil and water contamination, 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 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. In March 2006, A.M. Best Company, an insurance company rating agency, announced it had downgraded the financial strength rating assigned to the Partnership’s insurance carrier, Quanta Specialty Lines Company, including its parent and affiliates. The downgrade was from an “A” to a “B++, under review with negative implications.” During the second quarter of 2006, Quanta announced that their Board of Directors decided to cease underwriting or seeking new business and to place most of its remaining specialty insurance and reinsurance lines into orderly run-off. On June 7, 2006 A. M. Best further downgraded Quanta from B++ to B. Subsequent to this downgrading, Quanta was removed from A. M. Best’s interactive rating process, at Quanta’s request. Based on management’s further analysis of Quanta’s financial condition, the Partnership believes that Quanta will continue to meet its obligations relating to the Line 63 oil release, although there can be no assurance that this will be the case. As new information becomes available in future periods, the Partnership may change its provision and recovery estimates.

Product Contamination

In June 2006, approximately 44,000 barrels of a customer’s product at our Martinez terminal was contaminated. The Partnership has insurance coverage for the damage or loss of its customers’ products while in its care, custody and control at certain of its terminals subject to a $0.1 million per-occurrence deductible. The Partnership recognized a loss of $0.2 million to cover the insurance deductible and other associated costs. At this time, the Partnership believes all other estimated net costs related to the contamination of the property will be covered under the insurance policy, and has accrued for the insurance deductible and other costs of $0.2 million, which is included in “Other current liabilities” in the accompanying condensed consolidated balance sheet. The estimated range of total net costs is from $0.2 million to $0.8 million.

Litigation

On June 15, 2006, a lawsuit was filed in the Superior court of California, County of Los Angeles, entitled Kosseff v. Pacific Energy, et al, case no. BC 3544016. The plaintiff alleges that he is a unitholder of

Partnership and seeks to represent a class comprising all of the Partnership’s unitholders. The complaint names as defendants the Partnership and certain of the officers and directors of Pacific’s general partner, and asserts claims of self-dealing and breach of fiduciary duty in connection with the pending merger with PAA and related transactions. Among other allegations, the plaintiff alleges that (1) the proposed transaction was the product of a flawed process that would result in the sale of the Partnership at an unfairly low price, (2) subsequent quarterly financial results for the Partnership would have had a material positive impact on the Partnership’s common unit price had the proposed transaction not been announced, and thus the premium being offered to the Partnership’s unitholders was manufactured by the defendants based on the timing of the announcement of the proposed transaction, (3) because of various conflicts of interest, the defendants have acted to better their own interests at the expense of the Partnership’s public unitholders, (4) the defendants favored the proposed transaction in order to secure accelerated vesting of equity compensation under change in control provisions in contracts they have with the Partnership, and (5) the defendants were assured that Lehman Brothers Inc. “would rubber-stamp the transaction as fair and, for that reason Lehman [Brothers Inc.] was hand-picked by the defendants to issue the so-called ‘fairness opinion’.” The plaintiff seeks injunctive relief against completing the merger or, if the merger is completed, rescission of the merger, other equitable relief, and recovery of the plaintiff’s costs and attorneys’ fees. The Partnership believes that the lawsuit is without merit and intends to defend against it vigorously. There can be no assurance that additional claims may not be made or filed, the substance of which may be similar to the allegations described above or that otherwise might arise from, or in connection with, the merger agreement and the transaction it contemplates.

In August, 2005, Rangeland Pipeline Company (“RPC”), a wholly-owned subsidiary of the Partnership, learned that a Statement of Claim was filed by Desiree Meier and Robert Meier in the Alberta Court of Queen’s Bench, Judicial District of Red Deer, naming RPC as defendant, and alleging personal injury and property damage caused by an alleged release of petroleum substances onto plaintiff’s land by a prior owner and operator of the pipeline that is currently owned and operated by the Partnership. The claim seeks Cdn$1 million (approximately U.S.$0.9 million at June 30, 2006) in general damages, Cdn$2 million (approximately U.S.$1.8 million at June 30, 2006) in special damages, and, in addition, unspecified amounts for punitive, exemplary and aggravated damages, costs and interest. RPC believes the claim is without merit, and intends to vigorously defend against it. RPC also believes that certain of the claims, if successfully proven by the plaintiffs, would be liabilities retained by the pipeline’s prior owner under the terms of the agreement whereby the Partnership acquired the pipeline in question.

In connection with the acquisition of assets from Valero, L.P. in September 2005, the Partnership assumed responsibility for the defense of a lawsuit filed in 2003 against Support Terminals Services, Inc. (“ST Services”) by ExxonMobil Corporation (“ExxonMobil”) in New Jersey state court. The Partnership has also assumed any liability that might be imposed on ST Services as a result of the suit. In the suit, ExxonMobil seeks reimbursement of approximately $400,000 for remediation costs it has incurred, from GATX Corporation, Kinder Morgan Liquid Terminals, the successor in interest to GATX Terminals Corporation, and ST Services. ExxonMobil also seeks a ruling imposing liability for any future remediation and related liabilities on the same defendants. These costs are associated with the Paulsboro, New Jersey terminal that was acquired by the Partnership on September 30, 2005. ExxonMobil claims that the costs and future remediation requirements are related to releases at the site subsequent to its sale of the terminal to GATX in 1990 and that, therefore, any remaining remediation requirements are the responsibility of GATX Corporation, Kinder Morgan and ST Services. The Partnership believes the claims against ST Services are without merit, and intend to vigorously defend against them.

In 2001, Big West Oil Company and Chevron Products Company (the “Complainants”) filed complaints against Frontier Pipeline Company (“Frontier”) with the Federal Energy Regulatory Commission (“FERC”) challenging rates contained in joint tariffs in which Frontier was a participating carrier and rates contained in local tariffs filed by Frontier. On February 18, 2004, the FERC found against

Frontier on certain of the Complainants’ claims and ordered Frontier to pay reparations to Complainants in the aggregate amount of approximately $4.2 million, plus interest, which Frontier paid in August 2004. On October 5, 2004, Frontier filed a petition for review of the FERC’s reparations orders in the U.S. Court of Appeals for the D.C. Circuit, and on May 26, 2006 the Court of Appeals held that the FERC’s reparation ruling was inconsistent with applicable law, and thus vacated the FERC’s order and remanded the matter back to the FERC for further consideration consistent with the Court of Appeals’ decision. On July 25, 2006, Frontier filed a motion asking the FERC to dismiss the reparations complaints of the Complainants on the grounds that their complaints fail to state claims that can be sustained consistent with the ruling of the Court of Appeals. Frontier’s motion also asked the FERC to order the refund by the Complainants of the reparations previously paid by Frontier, plus interest. The Complainants have not yet responded to Frontier’s motion and no action on the motion has been taken by the FERC. If Frontier prevails on its motion or in any remand proceeding conducted by the FERC, it would be entitled to repayment in the amount of $5.4 million, plus interest thereon from August 23, 2004. The Partnership owns 22.22% of Frontier. Although the Partnership believes Frontier’s motion to dismiss the complaints, as well as the defenses it would assert in a remand proceeding before the FERC, are meritorious, the Partnership cannot predict the outcome of any such actions, and has not recorded any amount for this contingency.

The Partnership is involved in various other regulatory disputes, litigation and claims arising out of its operations in the normal course of business. The Partnership is not currently a party to any legal or regulatory proceedings the resolution of which could be expected to have a material adverse effect on its business, financial condition, liquidity or results of operations.

7. RESTRICTED UNITS

A restricted unit is a “phantom” unit under the Partnership’s long term incentive compensation plan. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit. The Partnership intends the issuance of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and the Partnership will receive no remuneration for such units.

In January 2006 and May 2006, the General Partner awarded 89,110 restricted units to key employees and outside directors that vest over a three-year period, beginning on March 1, 2006 and March 1, 2007, respectively. The number of units to be delivered to key employees in any year, if any, will be based on accomplishment of performance targets (measured by distributable cash flow) for the previous calendar year, subject to the Compensation Committee’s authority to subsequently adjust performance targets as it may deem appropriate, in its discretion. Restricted unit activity during the six months ended June 30, 2006 is as follows:

	Number of Units			Weighted Average Grant Date Fair Value
Outstanding at January 1, 2006		—			$	—
Changes during the year:
Granted		89,110			2,759
Vested		(10,439	)		(314		)
Forfeited		(5,430	)		(164		)
Outstanding at June 30, 2006		73,241			$	2,281

Compensation expense recognized for outstanding restricted units is based on grant date fair value of the common units to be awarded to the grantee upon vesting of the phantom unit, adjusted for the expected target performance level for each year. For the three and six months ended June 30, 2006, the

Partnership incurred $0.2 million and $0.5 million, respectively, in compensation expense for restricted units it deemed probable of achieving the performance criteria, including the amount for the first vesting of these awards which occurred on March 1, 2006.

The outstanding unit grants include change of control provisions that require immediate vesting of units in the event of a change in control of the Partnership or its General Partner. Upon the close of the proposed merger with PAA, all outstanding restricted units will immediately vest pursuant to the terms of the grants, and any remaining unamortized compensation expense will be immediately recognized.

On March 3, 2005, in connection with LBP’s acquisition of the Partnership’s General Partner, all restricted units then 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. Of the total $3.1 million, the compensation expense categorization was $0.6 million for operating personnel and $2.5 million for general and administrative personnel.

8. SEGMENT INFORMATION

The Partnership’s business and operations are organized into two business segments: the West Coast Business Unit and the 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 (West Coast Business Unit operations), owner of the PMT gathering system and marketer of crude oil, (iii) Pacific Terminals LLC, owner of the Pacific Terminals storage and distribution system, and (iv) Pacific Atlantic Terminals LLC, owner of the San Francisco and Philadelphia area terminals, which were acquired on September 30, 2005. 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, and the Rocky Mountain Products Pipeline, which was acquired on September 30, 2005, (ii) Ranch Pipeline LLC, the owner of a 22.22% partnership interest in Frontier Pipeline Company, (iii) PEG Canada, L.P. and its Canadian subsidiaries, which own and operate the Rangeland system, and (iv) Pacific Marketing and Transportation LLC (Rocky Mountain Business Unit operations), a marketer of crude oil.

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:

	West Coast Business Unit			Rocky Mountain Business Unit			Intersegment and Intrasegment Eliminations				Total
	(in thousands)
Three months ended June 30, 2006
Revenues:
Pipeline transportation revenue		$	16,696		$	20,422		$	(2,318	)	$	34,800
Storage and terminaling revenue		21,867			—						21,867
Pipeline buy/sell transportation revenue(1)		—			11,427						11,427
Crude oil sales, net of purchases(2)		9,195			1,648			(123		)	10,720
Net revenue		47,758			33,497						78,814
Expenses:
Operating		20,263			13,833			(2,441		)	31,655
Depreciation and amortization		5,507			4,785						10,292
Total expenses		25,770			18,618						41,947
Share of net income of Frontier		—			475						475
Operating income from segments(3)		$	21,988		$	15,354					$	37,342
Total business unit assets(4)		$	20,546		$	55,884					$	76,430
Capital expenditures(5)		$	10,017		$	5,869					$	15,886
Three months ended June 30, 2005
Revenues:
Pipeline transportation revenue		$	15,194		$	14,006		$	(1,453	)	$	27,747
Storage and terminaling revenue		10,870			—						10,870
Pipeline buy/sell transportation revenue(1)		—			8,116						8,116
Crude oil sales, net of purchases(2)		5,866			206			(30		)	6,042
Net revenue		31,930			22,328						52,775
Expenses:
Operating		15,996			10,779			(1,483		)	25,292
Depreciation and amortization		3,529			3,077						6,606
Total expenses		19,525			13,856						31,898
Share of net income of Frontier		—			490						490
Operating income from segments(3)		$	12,405		$	8,962					$	21,367
Total business unit assets(4)		$	501,990		$	342,420					$	844,410
Capital expenditures(5)		$	934		$	2,535					$	3,469

	West Coast Business Unit			Rocky Mountain Business Unit			Intersegment and Intrasegment Eliminations				Total
	(in thousands)
Six months ended June 30, 2006
Revenues:
Pipeline transportation revenue		$	33,859		$	39,290		$	(4,492	)	$	68,657
Storage and terminaling revenue		41,953			—						41,953
Pipeline buy/sell transportation revenue(1)		—			21,126						21,126
Crude oil sales, net of purchases(2)		16,506			1,288			(265		)	17,529
Net revenue		92,318			61,704						149,265
Expenses:
Operating		41,695			28,136			(4,757		)	65,074
Depreciation and amortization		11,006			9,288						20,294
Total expenses		52,701			37,424						85,368
Share of net income of Frontier		—			873						873
Operating income from segments(3)		$	39,617		$	25,153					$	64,770
Total business unit assets(4)		$	904,689		$	627,275					$	1,531,964
Capital expenditures(5)		$	21,627		$	11,685					$	33,312
Six months ended June 30, 2005
Revenues:
Pipeline transportation revenue		$	32,638		$	26,461		$	(3,315	)	$	55,784
Storage and terminaling revenue		21,342			—			(150		)	21,192
Pipeline buy/sell transportation revenue(1)		—			17,222						17,222
Crude oil sales, net of purchases(2)		7,678			206			(60		)	7,824
Net revenue		61,658			43,889						102,022
Expenses:
Operating		30,503			20,068			(3,525		)	47,046
Line 63 oil release costs(6)		2,000			—						2,000
Depreciation and amortization		7,006			6,129						13,135
Total expenses		39,509			26,197						62,181
Share of net income of Frontier		—			847						847
Operating income from segments(3)		$	22,149		$	18,539					$	40,688
Total business unit assets(4)		$	501,990		$	342,420					$	844,410
Capital expenditures(5)		$	1,684		$	5,467					$	7,151

(1) Pipeline buy/sell transportation revenue reflects net revenues of approximately $4.3 million on buy/sell transactions with different parties of $112.8 million for the three months ended June 30, 2006 and net revenues of approximately $6.8 million on buy/sell transactions with different parties of $161.1 million for the six months ended June 30, 2006. The remaining amount reflects net revenues on buy/sell transactions with the same party.

(2) The above amounts are net of purchases of $353.6 million and $122.4 million for the three months ended June 30, 2006 and 2005 and $609.9 million and $236.8 million for the six months ended June 30, 2006 and 2005, respectively.

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2006				2005				2006				2005
	(in thousands)
Income Statement Reconciliation
Operating income from above:
West Coast Business Unit		$	21,988			$	12,405			$	39,617			$	22,149
Rocky Mountain Business Unit		15,354				8,962				25,153				18,539
Operating income from segments		37,342				21,367				64,770				40,688
Less: General and administrative expense		(5,714		)		(3,700		)		(12,587		)		(8,872		)
Less: Merger costs		(3,417		)		—				(3,417		)		—
Less: Accelerated long-term incentive plan compensation expense		—				—				—				(3,115		)
Less: Reimbursed general partner transaction costs		—				—				—				(1,807		)
Operating income		28,211				17,667				48,766				26,894
Interest expense		(10,088		)		(5,844		)		(19,176		)		(11,442		)
Other income		292				540				735				893
Income tax benefit (expense)		3,028				(143		)		2,732				(704		)
Net income		$	21,443			$	12,220			$	33,057			$	15,641

(4) Business unit assets do not include assets related to the Partnership’s parent level activities. As of June 30, 2006 and 2005, parent level related assets were $56.0 and $39.9 respectively.

(5) Segment capital expenditures do not include parent level capital expenditures. Parent level capital expenditures were $2.5 million and $2.0 million for the three months ended June 30, 2006 and 2005 and $9.2 million and $2.7 million for the six months ended June 30, 2006 and 2005, respectively.

(6) 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 caused by heavy rainfall in northern Los Angeles County. As a result of the release, the Partnership recorded $2.0 million net oil release costs in the first quarter of 2005, consisting of what it now estimates to be $25.5 million of accrued costs relating to the release, net of insurance recovery of $17.7 million to June 30, 2006 and accrued insurance receipts of $5.8 million.

9. SUBSEQUENT EVENTS

On July 17, 2006, the Partnership declared a cash distribution of $0.5675 per limited partner unit, payable on August 14, 2006, to unitholders of record as of August 1, 2006.

On August 1, 2006, the Partnership and PAA announced that the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, for the proposed merger expired on July 31, 2006. In addition, PAA has received a “no issues” letter from the Canadian Competitive Bureau and notice that the accompanying waiting period under the Competition Act has expired. These expirations satisfy certain of the closing conditions contained in the merger agreement (see “Note 2—Proposed Merger With Plains All American Pipeline, L.P.”).

10. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Certain of the Partnership’s 100% owned subsidiaries have issued full, unconditional, and joint and several guarantees of the 71¤8% senior notes due 2014 and the 61¤4% senior notes due 2015 (the “Senior Notes”). Given that certain, but not all subsidiaries of the Partnership are guarantors of its Senior Notes, the Partnership is required to present the following supplemental condensed consolidating financial

information. For purposes of the following footnote, the Partnership is referred to as “Parent”, while the “Guarantor Subsidiaries” are Rocky Mountain Pipeline System LLC, Pacific Marketing and Transportation LLC, Pacific Atlantic Terminals LLC, Ranch Pipeline LLC, PEG Canada GP LLC, PEG Canada, L.P. and Pacific Energy Group LLC, and “Non-Guarantor Subsidiaries” are 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.

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 June 30, 2006
	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
	(in thousands)
Assets:
Current assets	$	101,891	$	209,268			$	89,380	$	(145,850	)	$	254,689
Property and equipment	—		611,503				626,291		—			1,237,794
Equity investments	485,158		219,253				—		(696,089		)	8,322
Intercompany notes receivable	661,763		343,849				—		(1,005,612		)	—
Intangible assets	—		30,365				38,989		—			69,354
Other assets	12,048		(244		)		5,987		—			17,791
Total assets	$	1,260,860	$	1,413,994			$	760,647	$	(1,847,551	)	$	1,587,950
Liabilities and partners’ capital:
Current liabilities	$	4,295	$	255,930			$	90,763	$	(145,850	)	$	205,138
Long-term debt	562,044		—				73,324		—			635,368
Deferred income taxes	—		1,267				31,566		—			32,833
Intercompany notes payable	—		661,763				343,849		(1,005,612		)	—
Other liabilities	2,488		9,876				10,214		—			22,578
Total partners’ capital	692,033		485,158				210,931		(696,089		)	692,033
Total liabilities and partners’ capital	$	1,260,860	$	1,413,994			$	760,647	$	(1,847,551	)	$	1,587,950

	Balance Sheet December 31, 2005
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
	(in thousands)
Assets:
Current assets	$	104,989	$	139,457		$	81,846	$	(134,177	)	$	192,115
Property and equipment	—		583,330			602,204		—			1,185,534
Equity investments	429,802		197,239			—		(618,885		)	8,156
Intercompany notes receivable	661,313		340,905			—		(1,002,218		)	—
Intangible assets	—		31,220			37,960		—			69,180
Other assets	13,426		—			8,041		—			21,467
Total assets	$	1,209,530	$	1,292,151		$	730,051	$	(1,755,280	)	$	1,476,452
Liabilities and partners’ capital:
Current liabilities	$	5,389	$	191,516		$	93,459	$	(134,177	)	$	156,187
Long-term debt	505,902		—			59,730		—			565,632
Deferred income taxes	—		582			35,189		—			35,771
Intercompany notes payable	—		661,313			340,905		(1,002,218		)	—
Other liabilities	—		8,938			11,685		—			20,623
Total partners’ capital	698,239		429,802			189,083		(618,885		)	698,239
Total liabilities and partners’ capital	$	1,209,530	$	1,292,151		$	730,051	$	(1,755,280	)	$	1,476,452

	Statement of Income Three Months Ended June 30, 2006
	Parent			Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				Total
	(in thousands)
Net operating revenues	$	—			$	41,311			$	39,945			$	(2,442	)	$	78,814
Operating expenses	—				(19,794		)		(14,303		)		2,442			(31,655		)
General and administrative expense(1)	(1		)		(5,163		)		(550		)		—			(5,714		)
Merger costs	—				(3,417		)		—				—			(3,417		)
Depreciation and amortization expense	—				(5,141		)		(5,151		)		—			(10,292		)
Share of net income of Frontier	—				475				—				—			475
Operating income	(1		)		8,271				19,941				—			28,211
Interest expense	(8,894		)		(60		)		(1,134		)		—			(10,088		)
Intercompany interest income (expense)	—				7,352				(7,352		)		—			—
Equity earnings	30,420				15,700				—				(46,120		)	—
Other income	(82		)		254				120				—			292
Income tax (expense) benefit	—				(1,097		)		4,125				—			3,028
Net income	$	21,443			$	30,420			$	15,700			$	(46,120	)	$	21,443

(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 June 30, 2005
	Parent			Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating adjustments				Total
	(in thousands)
Net operating revenues	$	—			$	20,077			$	34,181			$	(1,483	)	$	52,775
Operating expenses	—				(10,322		)		(16,453		)		1,483			(25,292		)
General and administrative expense(1)	—				(3,208		)		(492		)		—			(3,700		)
Depreciation and amortization expense	—				(1,636		)		(4,970		)		—			(6,606		)
Share of net income of Frontier	—				490				—				—			490
Operating income	—				5,401				12,266				—			17,667
Interest expense	(4,217		)		(825		)		(802		)		—			(5,844		)
Intercompany interest income (expense)	—				6,141				(6,141		)		—			—
Equity earnings	16,428				5,586				—				(22,014		)	—
Other income	9				434				97				—			540
Income tax (expense) benefit	—				(309		)		166				—			(143		)
Net income	$	12,220			$	16,428			$	5,586			$	(22,014	)	$	12,220

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

	Statement of Income Six Months Ended June 30, 2006
	Parent			Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				Total
	(in thousands)
Net operating revenues	$	—			$	76,530			$	77,492			$	(4,757	)	$	149,265
Operating expenses	—				(38,882		)		(30,949		)		4,757			(65,074		)
General and administrative expense(1)	(1		)		(11,373		)		(1,213		)		—			(12,587		)
Merger costs	—				(3,417		)		—				—			(3,417		)
Accelerated long-term incentive plan compensation expense	—				—				—				—			—
Line 63 oil release costs	—				—				—				—			—
Reimbursed general partner transaction costs	—				—				—				—			—
Depreciation and amortization expense	—				(10,069		)		(10,225		)		—			(20,294		)
Share of net income of Frontier	—				873				—				—			873
Operating income	(1		)		13,662				35,105				—			48,766
Interest expense	(17,002		)		(141		)		(2,033		)		—			(19,176		)
Intercompany interest income (expense)	—				14,521				(14,521		)		—			—
Equity earnings	50,362				22,941				—				(73,303		)	—
Other income	(302		)		591				446				—			735
Income tax benefit (expense)	—				(1,212		)		3,944				—			2,732
Net income	$	33,057			$	50,362			$	22,941			$	(73,303	)	$	33,057

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

	Statement of Income Six Months Ended June 30, 2005
	Parent			Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating adjustments				Total
	(in thousands)
Net operating revenues	$	—			$	34,345			$	71,202			$	(3,525	)	$	102,022
Operating expenses	—				(20,290		)		(30,281		)		3,525			(47,046		)
General and administrative expense(1)	—				(7,835		)		(1,037		)		—			(8,872		)
Accelerated long-term incentive plan compensation expense	—				(2,675		)		(440		)		—			(3,115		)
Line 63 oil release costs	—				—				(2,000		)		—			(2,000		)
Reimbursed general partner transaction costs	(893		)		(914		)		—				—			(1,807		)
Depreciation and amortization expense	—				(3,260		)		(9,875		)		—			(13,135		)
Share of net income of Frontier	—				847				—				—			847
Operating income	(893		)		218				27,569				—			26,894
Interest expense	(8,295		)		(1,504		)		(1,643		)		—			(11,442		)
Intercompany interest income (expense)	—				12,412				(12,412		)		—			—
Equity earnings	24,812				13,576				—				(38,388		)	—
Other income	17				600				276				—			893
Income tax benefit (expense)	—				(490		)		(214		)		—			(704		)
Net income	$	15,641			$	24,812			$	13,576			$	(38,388	)	$	15,641

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

	Statement of Cash Flows Six Months Ended June 30, 2006
	Parent			Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				Total
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	33,057			$	50,362			$	22,941			$	(73,303	)	$	33,057
Adjustments to reconcile net income to net cash provided by operating activities:
Equity earnings	(50,362		)		(22,941		)		—				73,303			—
Distributions from subsidiaries	45,614				31,523				—				(77,137		)	—
Depreciation, amortization and other	1,912				11,100				3,495				—			16,507
Net changes in operating assets and liabilities	(1,031		)		(20,899		)		13,207				1,247			(7,476		)
NET CASH PROVIDED BY OPERATING ACTIVITIES	29,190				49,145				39,643				(75,890		)	42,088
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions	—				(2,365		)		—				—			(2,365		)
Additions to property, equipment and other	(24		)		(26,856		)		(15,476		)		—			(42,356		)
Additions to pipeline linefill and minimum tank inventory	—				(8,128		)		(8,291		)		—			(16,419		)
Intercompany	(59,000		)		—				—				59,000			—
NET CASH USED IN INVESTING ACTIVITIES	(59,024		)		(37,349		)		(23,767		)		59,000			(61,140		)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	28,489				(8,985		)		(12,690		)		16,890			23,704
Effect of translation adjustment	—				—				107				—			107
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(1,345		)		2,811				3,293				—			4,759
CASH AND CASH EQUIVALENTS, beginning of reporting period	4,192				12,484				1,388				—			18,064
CASH AND CASH EQUIVALENTS, end of reporting period	$	2,847			$	15,295			$	4,681			$	—		$	22,823

	Statement of Cash Flows Six Months Ended June 30, 2005
	Parent			Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				Total
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	15,641			$	24,812			$	13,576			$	(38,388	)	$	15,641
Adjustments to reconcile net income to net cash provided by operating activities:
Equity earnings	(24,812		)		(13,576		)		—				38,388			—
Distributions from subsidiaries	30,658				22,784				—				(53,442		)	—
Depreciation, amortization and other	333				6,519				10,224				—			17,076
Net changes in operating assets and liabilities	(49		)		6,616				10,047				(3,187		)	13,427
NET CASH PROVIDED BY OPERATING ACTIVITIES	21,771				47,155				33,847				(56,629		)	46,144
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, equipment and other	—				(3,752		)		(6,223		)		—			(9,975		)
Intercompany	(914		)		—				—				914			—
NET CASH USED IN INVESTING ACTIVITIES	(914		)		(3,752		)		(6,223		)		914			(9,975		)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(23,067		)		(40,109		)		(20,014		)		55,641			(27,549		)
Effect of translation adjustment	—				—								74			74
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(2,210		)		3,294				7,610				—			8,694
CASH AND CASH EQUIVALENTS, beginning of reporting period	2,713				17,523				3,147				—			23,383
CASH AND CASH EQUIVALENTS, end of reporting period	$	503			$	20,817			$	10,757			$	—		$	32,077