UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2006

OR

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

Commission file number: 1-14569

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

 

333 Clay Street, Suite 1600, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

(713) 646-4100

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer  x

Accelerated Filer  o

Non-Accelerated Filer  o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No

At August 2, 2006, there were outstanding 80,994,178 Common Units.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION		3
Item 1.	UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS:	3
Consolidated Balance Sheets: June 30, 2006 and December 31, 2005		3
Consolidated Statements of Operations: For the three months and six months ended June 30, 2006 and 2005		4
Consolidated Statements of Cash Flows: For the six months ended June 30, 2006 and 2005		5
Consolidated Statement of Partners’ Capital: For the six months ended June 30, 2006		6
Consolidated Statements of Comprehensive Income: For the three months and six months ended June 30, 2006 and 2005		7
Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the six months ended June 30, 2006		7
Notes to the Consolidated Financial Statements		8
Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	22
Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	36
Item 4.	CONTROLS AND PROCEDURES	36
PART II. OTHER INFORMATION		38
Item 1.	LEGAL PROCEEDINGS	38
Item 1A.	RISK FACTORS	38
Item 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	41
Item 3.	DEFAULTS UPON SENIOR SECURITIES	41
Item 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	41
Item 5.	OTHER INFORMATION	41
Item 6.	EXHIBITS	42
SIGNATURES		44

 

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PART I. FINANCIAL INFORMATION

Item 1.                                                     UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except units)

		June 30,			December 31,
		2006			2005
		(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	7.6		$	9.6
Trade accounts receivable and other receivables, net		1,917.2			781.0
Inventory		1,155.9			910.3
Other current assets		95.7			104.3
Total current assets		3,176.4			1,805.2
PROPERTY AND EQUIPMENT		2,450.9			2,116.1
Accumulated depreciation		(303.4		)	(258.9		)
		2,147.5			1,857.2
OTHER ASSETS
Pipeline linefill in owned assets		200.4			180.2
Inventory in third party assets		80.4			71.5
Investment in PAA/Vulcan Gas Storage, LLC		124.4			113.5
Goodwill		179.6			47.4
Other, net		109.6			45.3
Total assets		$	6,018.3		$	4,120.3
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities		$	1,850.8		$	1,293.6
Due to related parties		0.2			6.8
Short-term debt		1,188.5			378.4
Other current liabilities		139.9			114.5
Total current liabilities		3,179.4			1,793.3
LONG-TERM LIABILITIES
Long-term debt under credit facilities and other		58.4			4.7
Senior notes, net of unamortized discount of $3.3 and $3.0, respectively		1,196.7			947.0
Other long-term liabilities and deferred credits		57.7			44.6
Total liabilities		4,492.2			2,789.6
COMMITMENTS AND CONTINGENCIES (NOTE 11)
PARTNERS’ CAPITAL
Common unitholders (77,273,248 and 73,768,576 units outstanding at June 30, 2006 and December 31, 2005, respectively)		1,485.6			1,294.1
General partner		40.5			36.6
Total partners’ capital		1,526.1			1,330.7
		$	6,018.3		$	4,120.3

 

The accompanying notes are an integral part of these consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

		Three Months Ended June 30,						Six Months Ended June 30,
		2006			2005			2006			2005
		(unaudited)						(unaudited)
REVENUES
Crude oil and LPG sales (includes buy/sell transactions of $3,706.1 million in the three months ended June 30, 2005 and $4,717.7 million and $7,125.2 million in the six months ended June 30, 2006 and 2005, respectively)		$	4,635.8		$	6,919.5		$	13,007.8		$	13,337.3
Other gathering, marketing, terminalling and storage revenues		19.2			11.3			35.7			19.5
Pipeline margin activities revenues (includes buy/sell transactions of $40.0 million in the three months ended June 30, 2005 and $45.3 million and $73.6 million in the six months ended June 30, 2006 and 2005, respectively)		173.8			174.9			367.7			332.5
Pipeline tariff activities revenues		63.6			55.0			116.6			109.9
Total revenues		4,892.4			7,160.7			13,527.8			13,799.2
COSTS AND EXPENSES
Crude oil and LPG purchases and related costs (includes buy/sell transactions of $3,583.6 million in the three months ended June 30, 2005 and $4,749.4 million and $6,984.5 million in the six months ended June 30, 2006 and 2005, respectively)		4,494.6			6,804.2			12,733.7			13,138.9
Pipeline margin activities purchases (includes buy/sell transactions of $37.3 million in the three months ended June 30, 2005 and $45.7 million and $68.8 million in the six months ended June 30, 2006 and 2005, respectively)		165.4			167.5			353.7			319.0
Field operating costs		86.6			67.8			168.9			131.6
General and administrative expenses		27.4			26.1			59.2			48.3
Depreciation and amortization		21.3			19.0			42.9			38.1
Total costs and expenses		4,795.3			7,084.6			13,358.4			13,675.9
OPERATING INCOME		97.1			76.1			169.4			123.3
OTHER INCOME/(EXPENSE)
Equity earnings in PAA/Vulcan Gas Storage, LLC		1.1			—			0.9			—
Interest expense (net of capitalized interest of $0.9 million and $0.3 million in the three months and $1.7 million and $1.0 million in the six months ended June 30, 2006 and 2005, respectively)		(18.0		)	(14.3		)	(33.3		)	(28.8		)
Interest income and other income (expense), net		0.1			0.5			0.4			0.6
Income before cumulative effect of change in accounting principle		80.3			62.3			137.4			95.1
Cumulative effect of change in accounting principle		—			—			6.3			—
NET INCOME		$	80.3		$	62.3		$	143.7		$	95.1
NET INCOME-LIMITED PARTNERS		$	71.4		$	57.6		$	128.2		$	86.9
NET INCOME-GENERAL PARTNER		$	8.9		$	4.7		$	15.5		$	8.2
BASIC NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle		$	0.82		$	0.76		$	1.47		$	1.27
Cumulative effect of change in accounting principle		—			—			0.08			—
Net income		$	0.82		$	0.76		$	1.55		$	1.27
DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle		$	0.81		$	0.74		$	1.45		$	1.26
Cumulative effect of change in accounting principle		—			—			0.08			—
Net income		$	0.81		$	0.74		$	1.53		$	1.26
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING		77.0			67.9			75.5			67.7
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING		77.8			69.3			76.3			68.7

 

The accompanying notes are an integral part of these consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

		Six Months Ended
		June 30,
		2006			2005
		(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	143.7		$	95.1
Adjustments to reconcile to cash flows from operating activities:
Depreciation and amortization		42.9			38.1
Cumulative effect of change in accounting principle		(6.3		)	—
SFAS 133 mark-to-market adjustment		3.1			26.3
Long-Term Incentive Plan charge		16.8			10.2
Noncash amortization of terminated interest rate hedging instruments		0.8			0.8
(Gain)/loss on foreign currency revaluation		1.8			(0.9		)
Net cash paid for terminated interest rate hedging instruments		—			(0.9		)
Equity earnings in PAA/Vulcan Gas Storage, LLC		(0.9		)	—
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other		(1,088.8		)	(589.4		)
Inventory		(214.3		)	(351.5		)
Accounts payable and other current liabilities		464.5			311.1
Due to related parties		(6.0		)	7.7
Net cash used in operating activities		(642.7		)	(453.4		)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions (Note 3)		(359.8		)	(14.5		)
Additions to property and equipment		(121.6		)	(86.3		)
Investment in unconsolidated affiliates		(10.0		)	—
Cash paid for linefill in assets owned		(4.8		)	—
Proceeds from sales of assets		3.5			3.4
Net cash used in investing activities		(492.7		)	(97.4		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) on long-term revolving credit facility		54.6			(143.6		)
Net borrowings on working capital revolving credit facility		229.9			71.8
Net borrowings on short-term letter of credit and hedged inventory facility		579.4			575.3
Proceeds from the issuance of senior notes		249.5			149.3
Net proceeds from the issuance of common units (Note 7)		152.4			22.3
Distributions paid to unitholders and general partner (Note 7)		(120.4		)	(92.7		)
Other financing activities		(4.4		)	(5.8		)
Net cash provided by financing activities		1,141.0			576.6
Effect of translation adjustment on cash		(7.6		)	(0.8		)
Net increase (decrease) in cash and cash equivalents		(2.0		)	25.0
Cash and cash equivalents, beginning of period		9.6			13.0
Cash and cash equivalents, end of period		$	7.6		$	38.0
Cash paid for interest, net of amounts capitalized		$	49.7		$	35.8

 

The accompanying notes are an integral part of these consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in millions)

										Total
							General			Partners’
		Common Units					Partner			Capital
		Units		Amount			Amount			Amount
		(unaudited)
Balance at December 31, 2005		73.8		$	1,294.1		$	36.6		$	1,330.7
Net Income		—		128.2			15.5			143.7
Distributions		—		(105.3		)	(15.1		)	(120.4		)
Issuance of common units		3.5		149.3			3.1			152.4
Other comprehensive income		—		19.3			0.4			19.7
Balance at June 30, 2006		77.3		$	1,485.6		$	40.5		$	1,526.1

 

The accompanying notes are an integral part of these consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

		Three Months Ended June 30,						Six Months Ended June 30,
		2006			2005			2006			2005
		(unaudited)						(unaudited)
Net income		$	80.3		$	62.3		$	143.7		$	95.1
Other comprehensive income/(loss)		19.2			(27.1		)	19.7			(96.9		)
Comprehensive income/(loss)		$	99.5		$	35.2		$	163.4		$	(1.8	)

 

CONSOLIDATED STATEMENT OF
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in millions)

		Net Deferred
		Gain/(Loss) on			Currency
		Derivative			Translation
		Instruments			Adjustments			Total
		(unaudited)
Balance at December 31, 2005		$	(16.6	)	$	87.1		$	70.5
Current period activity:
Reclassification adjustment for settled contracts		(18.9		)	—			(18.9		)
Changes in fair value of outstanding hedge positions		25.0			—			25.0
Currency translation adjustment		—			13.6			13.6
Total period activity		6.1			13.6			19.7
Balance at June 30, 2006		$	(10.5	)	$	100.7		$	90.2

 

The accompanying notes are an integral part of these consolidated financial statements.

7

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Accounting Policies

Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in September 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. and Plains Marketing Canada, L.P. We are engaged in interstate and intrastate crude oil transportation, and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other natural gas related petroleum products. We refer to liquefied petroleum gas and other natural gas related petroleum products collectively as “LPG.” We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key oil producing basins, transportation corridors and at major market hubs in the United States and Canada.  On July 20, 2006, we announced an acquisition that, when completed, will represent our initial entry into the refined products transportation business (See Note 3).  In addition, through our 50% equity ownership in PAA/Vulcan Gas Storage, LLC (“PAA/Vulcan”), we are engaged in the development and operation of natural gas storage facilities. Investments in 50% or less owned affiliates, over which we have significant influence, are accounted for by the equity method. We evaluate our equity investments for impairment in accordance with APB 18: The Equity Method of Accounting for Investments in Common Stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature.

The accompanying consolidated financial statements and related notes present (i) our consolidated financial position as of June 30, 2006 and December 31, 2005, (ii) the results of our consolidated operations for the three months and six months ended June 30, 2006 and 2005, (iii) our consolidated cash flows for the six months ended June 30, 2006 and 2005, (iv) our consolidated changes in partners’ capital for the six months ended June 30, 2006, (v) our consolidated comprehensive income for the three months and six months ended June 30, 2006 and 2005, and (vi) our changes in consolidated accumulated other comprehensive income for the six months ended June 30, 2006. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the Securities and Exchange Commission. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications are made to prior periods to conform to current period presentation. The results of operations for the six months ended June 30, 2006 should not be taken as indicative of the results to be expected for the full year. The consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2005 Annual Report on Form 10-K.

Note 2—Trade Accounts Receivable

The majority of our trade accounts receivable relates to our gathering and marketing activities, which can generally be described as high volume and low margin activities. As is customary in the industry, a portion of these receivables is reflected net of payables to the same counterparty based on contractual agreements. We routinely review our trade accounts receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such uncollected amounts involve billing delays and discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered, received or exchanged. We also attempt to monitor changes in the creditworthiness of our customers as a result of developments related to each customer, the industry as a whole and the general economy. Based on these analyses, as well as our historical experience and the facts and circumstances surrounding certain aged balances, we have established an allowance for doubtful trade accounts receivable as shown below. At June 30, 2006, substantially all of our net trade accounts receivable were less than 60 days past the scheduled invoice date.

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The following is a summary of the changes in our allowance for doubtful trade accounts receivable balance (in millions):

 

 

We consider this reserve adequate; however, actual amounts may vary significantly from estimated amounts. The discovery of previously unknown facts or adverse developments affecting one of our counterparties or the industry as a whole could adversely impact our results of operations.

Note 3—Acquisitions

We completed five acquisitions during the first half of 2006 for aggregate consideration of approximately $443 million.  The aggregate consideration includes cash paid, estimated transaction costs and assumed liabilities and net working capital items.  The aggregate purchase price is preliminary pending the resolution of working capital adjustments and the finalization of certain estimated transaction related costs.  These acquisitions include (i) 100% of the equity interests of Andrews Petroleum and Lone Star Trucking, which provide isomerization, fractionation, marketing and transportation services to producers and customers of natural gas liquids (collectively, the “Andrews Acquisition”), (ii) crude oil gathering and transportation assets and related contracts in South Louisiana and (iii) interests in various crude oil pipeline systems in Canada and the U.S. including a 100% interest in the Bay Marchand-to-Ostrica-to-Alliance Pipeline and various interests in the High Island Pipeline System (payment of approximately $68 million was made on July 3, 2006).

The allocation of the purchase price for these acquisitions is preliminary pending the confirmation of the final purchase price and the completion of valuations for certain of the acquisitions.  The preliminary purchase price allocation is as follows (in millions):

 

(1)           Represents the preliminary amount in excess of the fair value of the net assets acquired and is associated with our view of the future results of operations of the businesses acquired based on the strategic location of the assets and the growth opportunities that we expect to realize as we integrate these assets with our existing business strategy.

Pro Forma Data

The following unaudited pro forma data is presented as if the acquisitions, in the aggregate, had occurred as of the beginning of the periods reported (in millions, except per unit amounts):

		Three Months Ended June 30, (1)						Six Months Ended June 30, (1)
		2006			2005			2006			2005
		(unaudited)
Revenues		$	5,176.3		$	7,444.6		$	14,095.6		$	14,367.0
Income before cumulative effect of change in accounting principle		$	88.8		$	70.8		$	154.4		$	112.1
Net income		$	88.8		$	70.8		$	160.7		$	112.1
Basic income before cumulative effect of change in accounting principle per limited partner unit		$	0.93		$	0.88		$	1.69		$	1.52
Diluted income before cumulative effect of change in accounting principle per limited partner unit		$	0.92		$	0.86		$	1.67		$	1.50
Basic net income per limited partner unit		$	0.93		$	0.88		$	1.77		$	1.52
Diluted net income per limited partner unit		$	0.92		$	0.86		$	1.75		$	1.50

 

(1)           The pro forma financial information was prepared based on historical financial information, where available, and in other cases, internally  prepared estimates based on reasonable assumptions concerning historical data.

 

In June 2006, we announced that we had entered into a definitive agreement to acquire Pacific Energy Partners, L.P. (“Pacific Energy”). The total value of the transaction is approximately $2.4 billion, including the assumption of debt and estimated transaction costs, and is expected to close near the end of 2006.  Under the terms of the agreements, we will acquire from LB Pacific, LP and its affiliates the general partner interest and incentive distribution rights of Pacific Energy as well as 2.6 million common units and 7.8 million subordinated units for a total of $700 million in cash.  In addition, we will acquire the balance of Pacific Energy’s equity through a unit-for-unit merger in which each remaining unitholder of Pacific Energy will receive 0.77 newly issued PAA common units for each Pacific Energy common unit. The completion of the transaction remains subject to the approval of the unitholders of PAA and Pacific Energy as well as approvals of certain state utility commissions and the Investment Review Division of Industry Canada.

In July 2006, we completed the acquisition of a 64.35% interest in the Clovelly-to-Meraux (“CAM”) Pipeline system for a total purchase price of approximately $54 million and we announced that we had entered into a definitive agreement to acquire three refined products pipeline systems from Chevron Pipe Line Company for approximately $65 million. The transaction is expected to close in August 2006, subject to customary closing conditions.

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Note 4—Inventory and Linefill

Inventory primarily consists of crude oil and LPG in pipelines, storage tanks and rail cars that is valued at the lower of cost or market, with cost determined using an average cost method. Linefill and minimum working inventory requirements are recorded at historical cost and consist of crude oil and LPG used to fill our pipelines such that when an incremental barrel enters a pipeline it forces a barrel out at another location, as well as the minimum amount of crude oil necessary to operate our storage and terminalling facilities.

Linefill and minimum working inventory requirements in third party assets are included in “Inventory” (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we reclassify the linefill in third party assets not expected to be liquidated within the succeeding twelve months out of “Inventory,” at average cost, and into “Inventory in Third Party Assets” (a long-term asset), which is reflected as a separate line item within other assets on the consolidated balance sheet.

At June 30, 2006 and December 31, 2005, inventory and linefill consisted of :

		June 30, 2006								December 31, 2005
							Dollar/								Dollar/
		Barrels		Dollars			barrel			Barrels		Dollars			barrel
		(Barrels in thousands and dollars in millions, except dollars per barrel)
Inventory
Crude oil		14,277		$	931.0		$	65.21		13,887		$	755.7		$	54.42
LPG		5,068		219.1			$	43.23		3,649		149.0			$	40.83
Parts and supplies		N/A		5.8			N/A			N/A		5.6			N/A
Inventory subtotal		19,345		1,155.9						17,536		910.3
Inventory in third-party assets
Crude oil		1,275		67.1			$	52.63		1,248		58.6			$	46.96
LPG		318		13.3			$	41.82		318		12.9			$	40.57
Inventory in third-party assets subtotal		1,593		80.4						1,566		71.5
Linefill
Crude oil		6,516		199.5			$	30.62		6,207		179.3			$	28.89
LPG		27		0.9			$	33.33		27		0.9			$	33.33
Linefill subtotal		6,543		200.4						6,234		180.2
Total		27,481		$	1,436.7					25,336		$	1,162.0

 

 

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Note 5—Debt

During May 2006, we completed the sale of $250 million aggregate principal amount of 6.70% Senior Notes due 2036. The notes were sold at 99.82% of face value. Interest payments are due on May 15 and November 15 of each year. The notes are fully and unconditionally guaranteed, jointly and severally, by all of our existing 100% owned subsidiaries, except for subsidiaries which are not significant. We used the proceeds to repay amounts outstanding under our credit facilities and for general partnership purposes.

Below is a description of our debt:

		June 30,			December 31,
		2006			2005
		(in millions)
Short-term debt:
Senior secured hedged inventory facility bearing interest at a rate of 5.7% and 4.8% at June 30, 2006 and December 31, 2005, respectively		$	800.0		$	219.3
Working capital borrowings, bearing interest at a rate of 5.9% and 5.0% at June 30, 2006 and December 31, 2005, respectively (1)		385.3			155.4
Other		3.2			3.7
Total short-term debt		1,188.5			378.4
Long-term debt:
4.75% senior notes due August 2009, net of unamortized discount of $0.5 million and $0.6 million at June 30, 2006 and December 31, 2005, respectively		174.5			174.4
7.75% senior notes due October 2012, net of unamortized discount of $0.2 million and $0.2 million at June 30, 2006 and December 31, 2005, respectively		199.8			199.8
5.63% senior notes due December 2013, net of unamortized discount of $0.5 million and $0.5 million at June 30, 2006 and December 31, 2005, respectively		249.5			249.5
5.25% senior notes due June 2015, net of unamortized discount of $0.6 million and $0.7 million at June 30, 2006 and December 31, 2005, respectively		149.4			149.3
5.88% senior notes due August 2016, net of unamortized discount of $1.0 million and $1.0 million at June 30, 2006 and December 31, 2005, respectively		174.0			174.0
6.70% senior notes due May 2036, net of unamortized discount of $0.5 million at June 30, 2006		249.5			—
Senior notes, net of unamortized discount (2)		1,196.7			947.0
Long-term debt under senior unsecured revolving credit facility and other		58.4			4.7
Total long-term debt (1)(2)		1,255.1			951.7
Total debt		$	2,443.6		$	1,330.1

 

(1) At June 30, 2006 and December 31, 2005, we have classified $385.3 million and $155.4 million, respectively, of borrowings under our senior unsecured revolving credit facility as short-term.  These borrowings are designated as working capital borrowings, must be repaid within one year, and are primarily for hedged LPG and crude oil inventory and New York Mercantile Exchange (“NYMEX”) and International Petroleum Exchange (“IPE”) margin deposits.

(2) At June 30, 2006, the aggregate fair value of our fixed rate senior notes is estimated to be approximately $1,180.1 million.

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In July 2006, we amended our senior unsecured revolving credit facility to increase the aggregate capacity from $1.0 billion to $1.6 billion and the sub-facility for Canadian borrowings from $400 million to $600 million.  The amended facility can be expanded to $2.0 billion, subject to additional lender commitments, and has a final maturity of July 2011.

Also, in July 2006, we entered into a $1.0 billion acquisition bridge facility for the cash portion of the Pacific Energy acquisition.  Funding under the bridge facility will occur substantially contemporaneously with closing of the acquisition.  The bridge facility has a final maturity date that is the earlier of two years from the date of closing the acquisition or July 2009. The bridge facility has a mandatory reduction of commitments or prepayment requirements following certain public or private debt offerings and asset sales.  Borrowings under the bridge facility will bear interest at a rate similar to our senior unsecured revolving credit facility.

During August 2006, we entered into treasury locks with large creditworthy financial institutions. A treasury lock is a financial derivative instrument that enables the company to lock in the U.S. Treasury Note rate, typically in anticipation of a debt issuance.  The treasury locks have a notional principal amount of $200 million and an average effective interest rate of 4.97%.  The treasury locks mature in November 2006.

Note 6—Earnings Per Limited Partner Unit

Basic and diluted net income per limited partner unit is determined by dividing net income available to limited partners by the weighted average number of limited partner units outstanding during the period.  To calculate net income available to limited partners, income is first allocated to the general partner based on the amount of incentive distributions and the remainder is allocated between the limited partners and the general partner based on percentage ownership in the Partnership.  EITF No. 03-06 ("EITF 03-06"), "Participating Securities and the Two-Class Method under FASB Statement No. 128," addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock.  EITF 03-06 provides that in any accounting period where our aggregate net income exceeds our aggregate distribution for such period, we are required to present earnings per unit as if all of the earnings for the period were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective.  EITF 03-06 does not impact our overall net income or other financial results, however, for periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner unit.

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The following sets forth the computation of basic and diluted earnings per limited partner unit.

		Three Months Ended June 30,						Six Months Ended June 30,
		2006			2005			2006			2005
		(in millions, except per unit data)						(in millions, except per unit data)
Numerator:
Net income		$	80.3		$	62.3		$	143.7		$	95.1
Less: General partner’s incentive distribution paid		(7.4		)	(3.5		)	(12.9		)	(6.4		)
Subtotal		72.9			58.8			130.8			88.7
General partner 2% ownership		(1.5		)	(1.2		)	(2.6		)	(1.8		)
Net income available to limited partners		71.4			57.6			128.2			86.9
EITF 03-06 additional general partner’s distribution		(8.2		)	(6.2		)	(11.2		)	(0.6		)
Net income available to limited partners under EITF 03-06		$	63.2		$	51.4		$	117.0		$	86.3
Less: Limited partner 98% portion of cumulative effect of change in accounting principle		—			—			6.2			—
Limted partner net income before cumulative effect of change in accounting principle		$	63.2		$	51.4		$	110.8		$	86.3
Denominator:
Basic earnings per limited partner unit (weighted average number of limited partner units outstanding)		77.0			67.9			75.5			67.7
Effect of dilutive securities:
Weighted average LTIP units outstanding (1)		0.8			1.4			0.8			1.0
Diluted earnings per limited partner unit (weighted average number of limited partner units outstanding)		77.8			69.3			76.3			68.7
Basic net income per limited partner unit before cumulative effect of change in accounting principle		$	0.82		$	0.76		$	1.47		$	1.27
Cumulative effect of change in accounting principle per limited partner unit		—			—			0.08
Basic net income per limited partner unit		$	0.82		$	0.76		$	1.55		$	1.27
Diluted net income per limited partner unit before cumulative effect of change in accounting principle		$	0.81		$	0.74		$	1.45		$	1.26
Cumulative effect of change in accounting principle per limited partner unit		—			—			0.08
Diluted net income per limited partner unit		$	0.81		$	0.74		$	1.53		$	1.26

 

(1)             Our LTIP units described in Note 8 are considered dilutive securities except for those units which only vest upon certain performance conditions being met. The dilutive securities are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in SFAS 128, "Earnings per Share." 

Note 7—Partners’ Capital and Distributions

Direct Placements of Common Units

We completed the following equity offerings of our common units during the six months ended June 30, 2006 and 2005, respectively.  In addition, we completed an offering in the third quarter of 2006.  See Note 10 “Related Party Transactions.”

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				Gross			Proceeds			GP						Net
Period		Units		Unit Price			from Sale			Contribution			Costs			Proceeds
		(in millions, except per unit amounts)
July/August 2006		3,720,930		$	43.00		$	160.0		$	3.3		$	0.1		$	163.2
March/April 2006		3,504,672		$	42.80		$	151.0		$	2.0		$	0.6		$	152.4
February 2005		575,000		$	38.13		$	21.9		$	0.5		$	0.1		$	22.3

 

Distributions

The following table details the distributions we have declared and paid in the six months ended June 30, 2006 and 2005 (in millions, except per unit amounts):

		Common			GP									Distribution
		Units			Incentive			2%			Total			per unit
May 15, 2006		$	54.6		$	7.4		$	1.1		$	63.1		$	0.7075
February 14, 2006		50.7			5.6			1.0			57.3			$	0.6875
2006 total		$	105.3		$	13.0		$	2.1		$	120.4
May 13, 2005		$	43.3		$	3.5		$	0.9		$	47.7		$	0.6375
February 14, 2005		41.2			3.0			0.8			45.0			$	0.6125
2005 total		$	84.5		$	6.5		$	1.7		$	92.7

 

On July 14, 2006, we declared a cash distribution of $0.7250 per unit on our outstanding common units. The distribution is payable on August 14, 2006, to unitholders of record on August 4, 2006, for the period April 1, 2006, through June 30, 2006. The total distribution to be paid is approximately $69 million, with approximately $59 million to be paid to our common unitholders and approximately $1 million and $9 million to be paid to our general partner for its general partner and incentive distribution interests, respectively.

Note 8—Long-Term Incentive Plans

Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan and the 2005 Long-Term Incentive Plan, collectively referred to as our Long-Term Incentive Plans (“LTIP”), for employees and directors of our general partner and its affiliates who perform services for us.  Awards contemplated by our LTIP include phantom units, restricted units, unit appreciation rights and unit options, as determined by the compensation committee or the board of directors (each an “Award”). Under our LTIP, up to 4.4 million units may be issued in satisfaction of Awards.  Certain Awards may also include distribution equivalent rights (“DERs”) at the discretion of the compensation committee or the board of directors.  Subject to applicable vesting criteria, a DER entitles the grantee to a cash payment equal to cash distributions paid on an outstanding common unit. Upon vesting, certain of the Awards may be settled in common units or equivalent cash value at the election of our general partner. Our general partner will be entitled to reimbursement by us for any costs incurred in settling obligations under our LTIP.

As of June 30, 2006, there were approximately 2.2 million unvested phantom units outstanding with a weighted average grant-date fair value of approximately $32.22 per unit.  In addition, approximately 1.6 million of these Awards include DERs. Approximately 1.5 million of the Awards vest over a six-year period (with performance accelerators), while the remaining awards vest over time only if certain performance conditions are met and are forfeited after six years if the performance conditions are not met. The DERs vest over time (with performance accelerators) and terminate with the vesting or forfeiture of the related phantom units.

In addition, four of our six non-employee directors each have received an LTIP award of 5,000 units. These awards vest annually in 25% increments (1,250 units each). The Awards have an automatic re-grant feature such that as they vest, an equivalent amount is granted. For the other two non-employee directors, any

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director compensation is assigned to the entity that designated them as directors. In those cases, no LTIP award was granted, but in lieu thereof, an equivalent cash payment is made.

We adopted Statement of Financial Accounting Standards No.123(R) (revised 2004), “Share Based Payment” (“SFAS 123(R)”) on January 1, 2006 (See Note 13 for a discussion of recent accounting pronouncements). Under SFAS 123(R) the fair value of the Awards, which are subject to liability classification, is calculated based on the market price of our units at the balance sheet date adjusted for (i) the present value of any distributions that are probable of occurring on the underlying units over the vesting period that will not be received by the award recipients and (ii) an estimated forfeiture rate when appropriate. This fair value is then expensed over the period the Awards are earned. In addition, we recognize compensation expense for DER payments in the period the payment is earned.

We recognized expense related to our LTIP of approximately $6 and $8 million during the second quarter, and $17 million and $10 million during the first six months of 2006 and 2005, respectively.  Additionally, we have an accrued liability of approximately $35 million associated with our LTIP as of June 30, 2006.

As of June 30, 2006, the weighted average contractual life of our outstanding Awards was approximately five years. Based on the June 30, 2006 fair value measurement, we expect to recognize an additional $56 million of expense over the life of our outstanding Awards related to the remaining unrecognized fair value. This estimate is based on the market price of our limited partner units at the end of the period and actual amounts may differ materially as a result of a change in market price. We estimate that the remaining fair value will be recognized in expense as shown below (in millions):

		LTIP
		Fair Value
Year		Amortization
2006 (1)		$	13.5
2007		19.1
2008		12.9
2009		8.4
2010		2.3
Total		$	56.2

 

(1) Includes LTIP fair value amortization for the remaining six months of 2006.

Note 9—Derivative Instruments and Hedging Activities

We utilize various derivative instruments to (i) manage our exposure to commodity price risk, (ii) engage in a controlled trading program, (iii) manage our exposure to interest rate risk and (iv) manage our exposure to currency exchange rate risk. Our risk management policies and procedures are designed to monitor interest rates, currency exchange rates, NYMEX, IPE and over-the-counter positions, as well as physical volumes, grades, locations and delivery schedules to ensure that our hedging activities address our market risks. Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. We calculate hedge effectiveness on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of the hedged items.

Summary of Financial Impact

The majority of our derivative activity is related to our commodity price risk hedging activities. Through these activities, we hedge our exposure to price fluctuations with respect to crude oil, LPG and natural gas

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as well as with respect to expected purchases, sales and transportation of these commodities. The derivative instruments we use consist primarily of futures and options contracts traded on the NYMEX, IPE and over-the-counter transactions, including commodity swap and option contracts entered into with financial institutions and other energy companies.

The majority of the instruments that qualify for hedge accounting are cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred to Accumulated Other Comprehensive Income (“OCI”) and recognized in revenues or crude oil and LPG purchases and related costs in the periods during which the underlying physical transactions occur. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that is not highly effective (as defined in SFAS No. 133, “Accounting For Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”)) in offsetting changes in cash flows of the hedged items are marked-to-market in revenues each period.

During the first half of 2006, our earnings include a net loss of approximately $8 million resulting from all derivative activities, including the change in fair value of open derivatives and settled derivatives taken to earnings during the period. This loss includes:

a)              A net mark-to-market loss of approximately $3 million (a $1 million and $2 million loss in each of the the first and second quarters of 2006, respectively), which is primarily comprised of the net change in fair value during the period of open derivatives used to hedge price exposure that do not qualify for hedge accounting and

b)             A net loss of approximately $5 million related to settled derivatives taken to earnings during the period. The majority of this net loss is related to cash flow hedges that were recognized in earnings in conjunction with the underlying physical transactions that occurred during the first half of 2006.

The following table summarizes the net assets and liabilities related to the fair value of our open derivative positions on our consolidated balance sheet as of June 30, 2006 and December 31, 2005, respectively (in millions):

		June 30,			December 31,
		2006			2005
Other current assets		$	56.1		$	45.7
Other long-term assets		8.3			5.5
Other current liabilities		(80.4		)	(72.5		)
Other long-term liabilities and deferred credits		(9.6		)	(6.5		)
Net asset (liability)		$	(25.6	)	$	(27.8	)

 

The net liability as of June 30, 2006 includes approximately $20 million of unrealized losses recognized in earnings and $6 million of unrealized losses on effective cash flow hedges that are deferred to OCI. The majority of the $20 million of unrealized losses that have been recognized in earnings relate to activities associated with our storage assets. In general, revenue from storing crude oil is reduced in a backwardated market (when oil prices for future deliveries are lower than for current deliveries) as there is less incentive to store crude oil from month to month. We enter into derivative contracts, including futures and options, that will offset the reduction in revenue by generating offsetting gains in a backwardated market structure. These derivatives do not qualify for hedge accounting because the contracts will not necessarily result in physical delivery.

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