UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 8-K

 

CURRENT REPORT

Pursuant to Section 13 or 15(d) of The

Securities Exchange Act of 1934

 

Date of Report (Date of earliest event reported)—April 30, 2008

 

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)

 

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

 

 

(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))

 

 

TABLE OF CONTENTS

 

Item 9.01. Financial Statements and Exhibits
Item 2.02 and Item 7.01. Results of Operations and Financial Condition; Regulation FD Disclosure
SIGNATURES
Exhibit Index

 

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Item 9.01. Financial Statements and Exhibits

 

(d)      Exhibit 99.1—Press release dated April 30, 2008

 

Item 2.02 and Item 7.01. Results of Operations and Financial Condition; Regulation FD Disclosure

 

Plains All American Pipeline, L.P. (the “Partnership”) today issued a press release reporting its first quarter 2008 results. We are furnishing the press release, attached as Exhibit 99.1, pursuant to Item 2.02 and Item 7.01 of Form 8-K. Pursuant to Item 7.01, we are providing detailed guidance for financial performance for the second quarter of 2008 exclusive of the pending acquisition of Rainbow Pipe Line Company (“Rainbow”).  All previously issued guidance for any period during 2008 is superseded by the guidance provided today, and is no longer applicable.  The Partnership intends to provide additional guidance for the full year of 2008 following completion of the Rainbow acquisition, which will reflect the anticipated impact of the acquisition as well as other factors that the Partnership expects will affect 2008 results.  In accordance with General Instruction B.2. of Form 8-K, the information presented herein under Item 2.02 and Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.

 

Disclosure of Second Quarter 2008 Guidance

 

EBIT and EBITDA (each as defined below in Note 1 to the “Operating and Financial Guidance” table) are non-GAAP financial measures. Net income and cash flows from operating activities are the most directly comparable GAAP measures to EBIT and EBITDA. In Note 10 below, we reconcile EBITDA and EBIT to net income for the second quarter 2008 guidance period. It is, however, impractical to reconcile EBIT and EBITDA to cash flows from operating activities for the forecasted period. We encourage you to visit our website at www.paalp.com, in particular the section entitled “Non-GAAP Reconciliation,” which presents a historical reconciliation of certain commonly used non-GAAP financial measures, including EBIT and EBITDA. We present EBIT and EBITDA because we believe they provide additional information with respect to both the performance of our fundamental business activities and our ability to meet our future debt service, capital expenditures and working capital requirements. We also believe that debt holders commonly use EBITDA to analyze partnership performance. In addition, we have highlighted the impact of our equity compensation plans and, to the extent known, gains and losses related to SFAS 133 (primarily non-cash, mark-to-market adjustments) on Segment Profit, EBITDA, Net Income and Net Income per Basic and Diluted Limited Partner Unit.

 

The following information for the three months ending June 30, 2008 is based on assumptions and estimates that we believe are reasonable given our assessment of historical trends (modified for recent changes in market conditions), business cycles and other information reasonably available. Our assumptions and future performance, however, are both subject to a wide range of business risks and uncertainties, so no assurance can be provided that actual performance will fall within the guidance ranges. Please refer to the information under the caption “Forward-Looking Statements and Associated Risks” below. These risks and uncertainties, as well as other unforeseeable risks and uncertainties, could cause our actual results to differ materially from those in the following table. The operating and financial guidance provided below is given as of the date hereof, based on information known to us as of April 29, 2008. We undertake no obligation to publicly update or revise any forward-looking statements.

 

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Plains All American Pipeline, L.P.

Operating and Financial Guidance

(in millions, except per unit data)

 

		Actual			Guidance (1)
		Three Months			Three Months Ending
		Ended			June 30, 2008
		March 31, 2008			Low			High
Segment Profit
Net revenues (including equity earnings from unconsolidated entities)		$	361		$	362		$	372
Field operating costs		(144		)	(148		)	(144		)
General and administrative expenses		(40		)	(42		)	(41		)
		177			172			187
Depreciation and amortization expense		(48		)	(49		)	(47		)
Interest expense, net		(42		)	(46		)	(44		)
Income tax benefit (expense)		2			(1		)	—
Other income (expense), net		3			—			—
Net Income		$	92		$	76		$	96
Net Income to Limited Partners		$	67		$	50		$	69
Basic Net Income Per Limited Partner Unit
Weighted Average Units Outstanding		116			116			116
Net Income Per Unit		$	0.58		$	0.43		$	0.60
Diluted Net Income Per Limited Partner Unit
Weighted Average Units Outstanding		117			117			117
Net Income Per Unit		$	0.57		$	0.43		$	0.59
EBIT		$	132		$	123		$	140
EBITDA		$	180		$	172		$	187

 

Selected Items Impacting Comparability
Equity compensation charge		$		(6	)	$		(8	)	$		(8	)
SFAS 133 mark-to-market adjustment		(5			)	—				—
		$		(11	)	$		(8	)	$		(8	)

 

Excluding Selected Items Impacting Comparability
Adjusted Segment Profit
Transportation		$	92		$	91		$	94
Facilities		32			31			34
Marketing		66			58			67
Other Income (Expense), net		1			—			—
Adjusted EBITDA		$	191		$	180		$	195
Adjusted Net Income		$	103		$	84		$	104
Adjusted Basic Net Income per Limited Partner Unit		$	0.67		$	0.50		$	0.67
Adjusted Diluted Net Income per Limited Partner Unit		$	0.66		$	0.50		$	0.66

 

(1) The projected average foreign exchange rate is $1 CAD to $1 USD. The rate as of April 29, 2008 was $1.01 CAD to $1 USD.

 

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Notes and Significant Assumptions:

 

1.Definitions.

 

Bcf		Billion cubic feet
EBIT		Earnings before interest and taxes
EBITDA		Earnings before interest, taxes and depreciation and amortization expense
Bbls/d		Barrels per day
Segment Profit		Net revenues (including equity earnings, as applicable) less purchases, field operating costs, and segment general and administrative expenses
LTIP		Long-Term Incentive Plan
LPG		Liquefied petroleum gas and other natural gas related petroleum products
FX		Foreign currency exchange
General partner		As the context requires, “general partner” refers to any or all of (i) PAA GP LLC, the owner of our 2% general partner interest, (ii) Plains AAP, L.P., the sole member of PAA GP LLC and owner of our incentive distribution rights and (iii) Plains All American GP LLC, the general partner of Plains AAP, L.P.
Class B units		Class B units of Plains AAP, L.P.

 

2.Business Segments. We manage our operations through three operating segments: (i) Transportation, (ii) Facilities, and (iii) Marketing. The following is a brief explanation of the operating activities for each segment as well as key metrics.

 

a.Transportation. Our transportation segment operations generally consist of fee-based activities associated with transporting crude oil and refined products on pipelines, gathering systems, trucks and barges. We generate revenue through a combination of tariffs, third-party leases of pipeline capacity and transportation fees. We also include in this segment our equity earnings from our investments in the Butte and Frontier pipeline systems, in which we own minority interests, and Settoon Towing, in which we own a 50% interest.

 

Pipeline volume estimates are based on historical trends, anticipated future operating performance and completion of internal growth projects. Volumes are influenced by temporary market-driven storage and withdrawal of oil, maintenance schedules at refineries, production declines and other external factors beyond our control. Segment profit is forecast using the volume assumptions in the table below, priced at forecasted tariff rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation. Actual segment profit could vary materially depending on the level of volumes transported or expenses incurred during the period.

 

The following table summarizes our total pipeline volumes and highlights major systems that are significant either in total volumes transported or in contribution to total transportation segment profit.

 

		Actual			Guidance
		Three Months			Three Months
		Ended			Ending
		March 31, 2008			June 30, 2008
Average Daily Volumes (000 Bbls/d)
All American		46			45
Basin		363			360
Capline		190			225
Line 63 / 2000		162			175
Salt Lake City Area Systems(1)		97			105
West Texas / New Mexico Area Systems(1)		377			370
Manito		69			75
Rangeland		62			55
Refined Products		115			110
Other		1,180			1,190
		2,661			2,710
Trucking		97			100
		2,758			2,810
Average Segment Profit ($/Bbl)
Excluding Selected Items Impacting Comparability		$	0.37		$	0.36	(2)

 

(1) The aggregate of multiple systems in the respective areas.

(2) Mid-point of guidance.

 

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b.Facilities. Our facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products and LPG, as well as LPG fractionation and isomerization services. We generate revenue through a combination of month-to-month and multi-year leases and processing arrangements. This segment also includes our equity earnings from our 50% investment in PAA/Vulcan Gas Storage, LLC which owns and operates approximately 26 Bcf of underground natural gas storage capacity and is constructing an additional 24 Bcf of underground storage capacity.

 

Segment profit is forecast using the volume assumptions in the table below, priced at forecasted rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation.

 

		Actual			Guidance
		Three Months			Three Months
		Ended			Ending
		March 31, 2008			June 30, 2008
Operating Data
Crude oil, refined products and LPG storage (MMBbls/Mo.)		45			47
Natural Gas Storage (Bcf/Mo.)		13			13
LPG Processing (MBbl/d)		15			20
Facilities Activities Total 1
Avg. Capacity (MMBbls/Mo.)		47			50
Segment Profit per Barrel ($/Bbl)
Excluding Selected Items Impacting Comparability		$	0.23		$	0.22	(2)

 

(1) Calculated as the sum of: (i) crude oil, refined products and LPG storage capacity; (ii) natural gas storage capacity divided by 6 to account for the 6:1 mcf of gas to barrel of crude oil ratio; and (iii) LPG processing volumes multiplied by the number of days in the period and divided by 1,000  and the number of months in the period to convert to monthly capacity in millions.

(2) Mid-point of guidance.

 

c.Marketing. Our marketing segment operations generally consist of the following merchant activities:

 

·  the purchase of U.S. and Canadian crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities, as well as the purchase of foreign cargoes at their load port and various other locations in transit;

 

·  the storage of inventory during contango market conditions and the seasonal storage of LPG;

 

·  the purchase of refined products and LPG from producers, refiners and other marketers;

 

·  the resale or exchange of crude oil, refined products and LPG at various points along the distribution chain to refiners or other resellers to maximize profits; and

 

·  the transportation of crude oil, refined products and LPG on trucks, barges, railcars, pipelines and ocean-going vessels to our terminals and third-party terminals.

 

The level of profit in the marketing segment is influenced by overall market structure and the degree of volatility in the crude oil market as well as variable operating expenses. Forecasted operating results for the three-month period ending June 30, 2008 reflect our expectation of a backwardated market structure and weather-related seasonal variations in LPG sales. Unexpected changes in market structure or volatility (or lack thereof) could cause actual results to differ materially from forecasted results.

 

We forecast segment profit using the volume assumptions stated below, as well as estimates of unit margins, field operating costs, G&A expenses and carrying costs for contango inventory, based on current and anticipated market conditions. Field operating costs do not include depreciation. Realized unit margins for any given lease-gathered barrel could vary significantly based on a variety of factors including location, quality and contract structure.

 

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		Actual			Guidance
		Three Months			Three Months
		Ended			Ending
		March 31, 2008			June 30, 2008
Average Daily Volumes (MBbl/d)
Crude Oil Lease Gathering		680			685
LPG Sales		136			66
Refined Products		20			20
Waterborne foreign crude imported		74			74
		910			845
Segment Profit per Barrel ($/Bbl)
Excluding Selected Items Impacting Comparability		$	0.79		$	0.81	(1)

 

(1) Mid-point of guidance.

 

3.		Depreciation and Amortization. We forecast depreciation and amortization based on our existing depreciable assets, forecasted capital expenditures and projected in-service dates. Depreciation is computed using the straight-line method over estimated useful lives, which range from 3 years (for office furniture and equipment) to 40 years (for certain pipelines, crude oil terminals and facilities) and includes gains and losses on the sale of assets.
4.		Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”). The guidance presented above does not include assumptions or projections with respect to potential gains or losses related to derivatives accounted for under SFAS 133, as there is no accurate way to forecast these potential gains or losses. The potential gains or losses related to these derivatives (primarily mark-to-market adjustments) could cause actual net income to differ materially from our projections.
5.		Capital Expenditures and Acquisitions. Although acquisitions constitute a key element of our growth strategy, the forecasted results and associated estimates do not include any forecasts for acquisitions that may be made after the date hereof. Capital expenditures for expansion projects are forecasted to be approximately $380 million during calendar 2008, of which $124 million was spent in the first quarter. Following are some of the more notable projects and forecasted expenditures for the year:

 

		Calendar 2008
		(in millions)
Expansion Capital
· Patoka tankage		$	43
· Kerrobert facility		36
· Paulsboro tankage		30
· Fort Laramie Tank Expansion		22
· West Hynes tankage		13
· Edmonton tankage and connections		12
· Bumstead expansion		10
· Pier 400(1)		10
· Other Projects(2)		204
		380
Maintenance Capital		60
Total Projected Capital Expenditures (excluding acquisitions)		$	440

 

(1) This project requires approval from a number of city and state regulatory agencies in California. Accordingly, the timing and amount of  additional costs, if any, related to Pier 400 are not certain at this time.

 

(2) Primarily pipeline connections, upgrades and truck stations, new tank construction and refurbishing, and carry-over of projects started in 2007; including the Salt Lake City pipeline for which estimated costs have increased approximately $50 million over previous estimates primarily due to weather related factors and adverse soil conditions.

 

6.    Capital Structure. This guidance is based on our capital structure as of March 31, 2008, as modified by the issuance on April 23, 2008, of $600 million of 6.50% senior notes due 2018.  The net proceeds from the offering were used to reduce

 

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       outstanding borrowings under certain credit facilities which may be re-borrowed to fund our capital program, including the acquisition of the Rainbow Pipe Line Company and other acquisitions, and for general partnership purposes.

 

7.    Interest Expense. Debt balances are projected based on estimated cash flows, current distribution rates, forecasted capital expenditures for maintenance and expansion projects, expected timing of collections and payments, and forecasted levels of inventory and other working capital sources and uses.

 

Included in interest expense are commitment fees, amortization of long-term debt discounts or premiums, deferred amounts associated with terminated interest-rate hedges and interest on short-term debt for non-contango inventory (primarily hedged LPG inventory and New York Mercantile Exchange and IntercontinentalExchange margin deposits). Interest expense is net of amounts capitalized for major expansion capital projects and does not include interest on borrowings for contango inventory. We treat interest on contango-related borrowings as carrying costs of crude oil and include it as part of the purchase price of crude oil.

 

8.     Net Income per Unit. Basic net income per limited partner unit is calculated by dividing net income allocated to limited partners by the basic weighted average units outstanding during the period.

 

		Three Months Ending
		June 30, 2008
		Low			High
		(in millions, except per unit amounts)
Numerator for basic and diluted earnings per limited partner unit:
Net Income		$	76		$	96
General partners incentive distribution		(29		)	(29		)
General partners incentive distribution reduction		4			4
		51			71
General partner 2% ownership		(1		)	(2		)
Net income available to limited partners		$	50		$	69
Denominator:
Denominator for basic earnings per limited partner unit-weighted average number of limited partner units		116			116
Effect of dilutive securities: Weighted average LTIP units		1			1
Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units		117			117
Basic net income per limited partner unit		$	0.43		$	0.60
Diluted net income per limited partner unit		$	0.43		$	0.59

 

Net income allocated to limited partners is impacted by the income allocated to the general partner and the amount of the incentive distribution paid to the general partner. The amount of income allocated to our limited partner interests is 98% of the total partnership income after deducting the amount of the general partner’s incentive distribution. Based on our current annualized distribution rate of $3.46 per unit and current units outstanding, our general partner’s distribution is forecast to be approximately $124 million annually, of which approximately $116 million is attributed to the incentive distribution rights. In conjunction with the Pacific acquisition, however, the general partner agreed to reduce the amounts due it as incentive distributions. The reduction is effective for five years, as follows: (i) $5 million per quarter for the first four quarters beginning with the February 2007 distribution, (ii) $3.75 million per quarter for the following eight quarters, (iii) $2.5 million per quarter for the following four quarters, and (iv) $1.25 million per quarter for the final four quarters. The aggregate reduction in incentive distributions will be $65 million and the total reduction during 2008 will be $15 million. The relative amount of the incentive distribution varies directionally with the number of units outstanding and the level of the distribution on the units. Based on the current number of units outstanding, each $0.05 per unit annual increase in the distribution over $3.46 per unit decreases net income available for limited partners by approximately $6 million ($0.05 per unit) on an annualized basis.

 

9.

Equity Compensation Plans. The majority of grants outstanding under our equity compensation plans (LTIP and Class B units) contain vesting criteria that are based on a combination of performance benchmarks and service period. The grants will

 

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		vest in various percentages, typically on the later to occur of specified earliest vesting dates and the dates on which minimum distribution levels are reached. Among the various grants, vesting dates range from May 2008 to May 2012 and minimum annualized distribution levels range from $2.80 to $4.50. For some awards, a percentage of any remaining units will vest on a date certain in 2011 or 2012 and all others are forfeited.
		On April 17, 2008, we declared an annualized distribution of $3.46 payable on May 15, 2008 to our unitholders of record as of May 5, 2008. In addition to achieving the distribution level of $3.46, we have deemed probable that the $3.50 distribution level will be achieved. Accordingly, for grants that vest at annualized distribution levels of $3.50 or less, guidance includes an accrual over the applicable service period at an assumed market price of $47.60 per unit as well as the fair value associated with awards that will vest on a date certain. The actual amount of equity compensation expense amortization in any given period will be directly influenced by (i) our unit price at the end of each reporting period, (ii) our unit price on the date of actual vesting, (iii) the amount of amortization in the early years, (iv) the probability assessment of achieving future distribution rates, and (v) new equity compensation award grants. For example, a $3.00 change in the unit price assumption at June 30, 2008 would change the second quarter equity compensation expense by approximately $4 million — $1 million for the current quarter and $3 million for the life-to-date adjustment to the liability accrued in prior periods. Therefore, actual net income could differ materially from our projections.
		Included in equity compensation expense highlighted in selected items impacting comparability for the second quarter of 2008 is approximately $3 million of expense attributable to the Class B units. Since the economic burden of the Class B units is borne solely by the General Partner and not the Partnership, the expense will be reflected as a capital contribution and thus will result in a corresponding credit to Partners’ Capital in the financial statements of the Partnership.
		The amount of equity compensation expense highlighted in selected items impacting comparability for the second quarter of 2008 excludes the portion of the expense represented by awards that pursuant to their terms, will be settled in cash only ($1 million) and have no impact in the determination of diluted units.
10.		Reconciliation of EBITDA and EBIT to Net Income. The following table reconciles the three month guidance range ending June 30, 2008 for EBITDA and EBIT to net income.

 

		Three Months Ending
		June 30, 2008
		Low			High
		(in millions)
Reconciliation to Net Income
EBITDA		$	172		$	187
Depreciation and amortization		49			47
EBIT		123			140
Interest expense		46			44
Income tax (benefit) expense		1			—
Net Income		$	76		$	96

 

Forward-Looking Statements and Associated Risks

 

All statements included in this report, other than statements of historical fact, are forward-looking statements, including, but not limited to, statements identified by the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast” and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. The absence of these words, however, does not mean that the statements are not forward-looking. These statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:

 

·        failure to implement or capitalize on planned internal growth projects;

 

·        the success of our risk management activities;

 

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·        environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;

 

·        maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;

 

·        abrupt or severe declines or interruptions in outer continental shelf production located offshore California and transported on our pipeline systems;

 

·        shortages or cost increases of power supplies, materials or labor;

 

·        the availability of adequate third-party production volumes for transportation and marketing in the areas in which we operate, and other factors that could cause declines in volumes shipped on our pipelines by us and third-party shippers;

 

·        fluctuations in refinery capacity in areas supplied by our mainlines and other factors affecting demand for various grades of crude oil, refined products and natural gas and resulting changes in pricing conditions or transportation throughput requirements;

 

·        the availability of, and our ability to consummate, acquisition or combination opportunities;

 

·        our access to capital to fund additional acquisitions and our ability to obtain debt or equity financing on satisfactory terms;

 

·        successful integration and future performance of acquired assets or businesses and the risks associated with operating in lines of business that are distinct and separate from our historical operations;

 

·        unanticipated changes in crude oil market structure and volatility (or lack thereof);

 

·        the impact of current and future laws, rulings and governmental regulations;

 

·        the effects of competition;

 

·        continued creditworthiness of, and performance by, our counterparties;

 

·        interruptions in service and fluctuations in tariffs or volumes on third-party pipelines;

 

·        increased costs or lack of availability of insurance:

 

·        fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans;

 

·        the currency exchange rate of the Canadian dollar;

 

·        weather interference with business operations or project construction;

 

·        risks related to the development and operation of natural gas storage facilities;

 

·        general economic, market or business conditions; and

 

·        other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, refined products and liquefied petroleum gas and other natural gas related petroleum products.

 

We undertake no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in our filings with the Securities and Exchange Commission, which information is incorporated by reference herein.

 

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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.
	By:  PAA GP LLC, its general partner
	By:  PLAINS AAP, L. P., its sole member
	By:  PLAINS ALL AMERICAN GP LLC, its general
	partner
Date: April 30, 2008	By:	/s/ PHIL KRAMER
		Name: Phil Kramer
		Title:	Executive Vice President and Chief Financial Officer

 

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