Edgar Filing: PLAINS ALL AMERICAN PIPELINE LP

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)—June 13, 2005

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

(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

Item 7.01. Regulation FD Disclosure

Plains All American Pipeline, L.P. (the “Partnership”) today issued a press release updating its second quarter 2005 guidance and establishing initial quarterly guidance for the third and fourth quarters of 2005. We are furnishing the press release, attached as Exhibit 99.1, pursuant to Item 7.01 of Form 8-K. In accordance with General Instruction B.2. of Form 8-K, the information presented herein under Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities 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.

Update of Second Quarter and Full Year 2005 Guidance and Disclosure of Third and Fourth Quarter 2005 Estimates

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 11 below, we reconcile EBITDA and EBIT to net income for the periods presented. We also 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 on EBITDA, Net Income and Net Income per Limited Partner Unit of our long-term incentive program, revaluations of foreign currency and, to the extent known, gains and losses related to SFAS 133 (primarily non-cash, mark-to-market adjustments).

The following guidance for the three months ending June 30, September 30, and December 31, 2005 and the twelve months ending December 31, 2005 is based on assumptions and estimates that we believe are reasonable given our assessment of historical trends, business cycles and other information reasonably available. However, our assumptions and future performance are both subject to a wide range of business risks and uncertainties and also include projections for several recent acquisitions, 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 June 10, 2005. We undertake no obligation to publicly update or revise any forward-looking statements.

Plains All American Pipeline, L.P.
Operating and Financial Guidance
(in millions, except per unit data)

	Guidance(1)
	Three Months Ended																		Twelve Months Ended
	June 30, 2005						September 30, 2005						December 31, 2005						December 31, 2005
	Low			High			Low			High			Low			High			Low			High
Pipeline
Net revenues		$ 92.0			$ 94.0			$ 95.2			$ 98.0			$ 94.5			$ 96.0			$ 377.2			$ 383.5
Field operating costs		(37.4	)		(35.6	)		(36.4	)		(35.2	)		(36.9	)		(35.8	)		(144.8	)		(140.7	)
General and administrative expenses		(13.2	)		(12.8	)		(13.0	)		(12.2	)		(13.3	)		(12.9	)		(50.8	)		(49.2	)
		41.4			45.6			45.8			50.6			44.3			47.3			181.6			193.6
Gathering, Marketing, Terminalling & Storage
Net revenues		99.0			103.7			73.0			77.0			65.0			71.3			293.8			308.8
Field operating costs		(29.4	)		(28.8	)		(30.4	)		(29.9	)		(30.7	)		(30.4	)		(120.2	)		(118.8	)
General and administrative expenses		(12.1	)		(11.6	)		(12.3	)		(11.6	)		(12.5	)		(12.1	)		(47.7	)		(46.1	)
		57.5			63.3			30.3			35.5			21.8			28.8			125.9			143.9
Segment Profit		98.9			108.9			76.1			86.1			66.1			76.1			307.5			337.5
Depreciation and amortization expense		(19.3	)		(19.1	)		(19.9	)		(19.6	)		(20.4	)		(20.0	)		(78.7	)		(77.8	)
Interest expense		(14.7	)		(14.5	)		(16.3	)		(16.0	)		(17.0	)		(16.6	)		(62.6	)		(61.7	)
Other Income (Expense)		0.3			0.3			—			—			—			—			0.4			0.4
Net Income		$ 65.2			$ 75.6			$ 39.9			$ 50.5			$ 28.7			$ 39.5			$ 166.6			$ 198.4
Net Income to Limited Partners		$ 60.5			$ 70.7			$ 35.7			$ 46.1			$ 24.7			$ 35.3			$ 150.2			$ 181.3
Basic:
Weighted Average Units Outstanding		67.9			67.9			67.9			67.9			67.9			67.9			67.8			67.8
Net Income Per Limited Partner Unit		$ 0.89			$ 1.04			$ 0.53			$ 0.68			$ 0.36			$ 0.52			$ 2.21			$ 2.67
Diluted:
Weighted Average Units Outstanding		69.3			69.3			69.3			69.3			69.3			69.3			69.0			69.0
Net Income Per Limited Partner Unit		$ 0.87			$ 1.02			$ 0.51			$ 0.66			$ 0.36			$ 0.51			$ 2.18			$ 2.63
EBIT		$ 79.9			$ 90.1			$ 56.2			$ 66.5			$ 45.7			$ 56.1			$ 229.2			$ 260.1
EBITDA		$ 99.2			$ 109.2			$ 76.1			$ 86.1			$ 66.1			$ 76.1			$ 307.9			$ 337.9


*Selected Items Impacting Comparability*
LTIP charge(2)		$ (6.2	)		$ (6.2	)		$ (5.9	)		$ (5.9	)		$ (5.9	)		$ (5.9	)		$ (20.2	)		$ (20.2	)
FAS 133 non-cash mark-to-market adjustment		—			—			—			—			—			—			(13.4	)		(13.4	)
FX gain (loss)		0.4			0.4			—			—			—			—			(0.4	)		(0.4	)
		$ (5.8	)		$ (5.8	)		$ (5.9	)		$ (5.9	)		$ (5.9	)		$ (5.9	)		$ (34.1	)		$ (34.1	)



*Excluding Selected Items Impacting Comparability*
Adjusted EBITDA		$ 105.0			$ 115.0			$ 82.0			$ 92.0			$ 72.0			$ 82.0			$ 342.0			$ 372.0
Adjusted Net Income		$ 71.0			$ 81.4			$ 45.8			$ 56.4			$ 34.6			$ 45.4			$ 200.7			$ 232.5
Adjusted Basic Net Income per Limited Partner Unit		$ 0.97			$ 1.13			$ 0.61			$ 0.76			$ 0.45			$ 0.60			$ 2.71			$ 3.16
Adjusted Diluted Net Income per Limited Partner Unit		$ 0.96			$ 1.10			$ 0.60			$ 0.75			$ 0.44			$ 0.59			$ 2.66			$ 3.11

(1) The projected average foreign exchange rate is $1.25 CAD to $1 USD.

(2) If a $2.80 distribution were to be deemed probable, the LTIP charge would increase by $1.4 million, $0.9 million and $0.9 million for the second, third and fourth quarters of 2005, respectively. The correlating impact to earnings per limited partner unit is $(0.02), $(0.01) and $(0.01) for the second, third and fourth quarters of 2005, respectively. See Note 10.

Notes and Significant Assumptions:

1. Definitions.

EBIT		Earnings before interest and taxes
EBITDA		Earnings before interest, taxes and depreciation and amortization expense
Bbl/d		Barrels per day
Segment Profit		Net revenues less purchases, field operating costs, and segment general and administrative expenses
LTIP		Long-Term Incentive Plan
LPG		Liquefied petroleum gas and other petroleum products
FERC		Federal Energy Regulatory Commission
FX		Foreign currency exchange

2. Pipeline Operations. Pipeline volume estimates are based on historical trends, anticipated future operating performance and completion of organic growth projects. Volumes are influenced by temporary market-driven storage and withdrawal of oil, end-user refinery maintenance schedules, field declines and other external factors beyond our control. Actual segment profit could vary materially depending on the level of volumes transported. The following table summarizes our pipeline volumes and breaks out the major systems that are significant either in total volumes transported or in contribution to total net revenue.

	Calendar 2005
	Three Months Ended														Twelve Months
	Actual			Guidance											Ended
	March 31			June 30			September 30				December 31				December 31
Average Daily Volumes (000’s Bbl/d)
All American		54		51				51				51				52
Basin		277		268				270				290				276
Capline		160		143				137				127				142
Cushing to Broome⁽⁴⁾		23		85				80				80				67
West Texas / New Mexico area systems⁽¹⁾		401		407				381				381				393
Other		546		567				587				595				573
		1,461		1,521				1,506				1,524				1,503
Canada⁽²⁾		268		262				271				271				268
		1,729		1,783				1,777				1,795				1,771
Average Segment Profit ($/Bbl)
As Reported		$	0.322	$	0.268	⁽³⁾		$	0.295	⁽³⁾		$	0.277	⁽³⁾		$	0.290	⁽³⁾
Excluding Selected Items Impacting Comparability		$	0.330	$	0.287	⁽³⁾		$	0.312	⁽³⁾		$	0.294	⁽³⁾		$	0.306	⁽³⁾

(1) The aggregate of 10 systems in the West Texas / New Mexico area.

(2) The aggregate of 7 systems.

(3) Mid-point of estimate.

(4) System became operational on March 1, 2005.

Net revenues were forecasted using the volume assumptions in the table above priced at tariff rates currently received, with adjustments where appropriate for estimated escalation in certain rates as allowed by contractual terms. Effective July 1, 2005, common carrier tariffs are permitted to escalate approximately 3.6% in accordance with FERC regulated guidelines. However, in certain instances,

contractual arrangements or market forces may not allow us to realize the benefit of these permitted escalations. To illustrate the impact volume changes may have on segment profit, the following table provides a volume sensitivity analysis of three systems representing approximately 30% of total pipeline net revenues.

Volume Sensitivity Analysis
			% of			Incr (Decr)
	Incr (Decr)		System			in Annualized
System	in Volume		Total			Segment Profit
	(Bbls/d)					(in millions)
All American		5,000		10	%		$	3.2
Basin		20,000		7	%		$	1.7
Capline		10,000		7	%		$	1.5

3. Gathering, Marketing, Terminalling and Storage Operations. The degree of volatility in the crude oil market influences the level of profit in the GMT&S segment. This impact is partially responsible for the 109% increase in projected second quarter segment profit per barrel (excluding the effect of SFAS 133, FX gain or loss and LTIP) over the first quarter. Our guidance for the second half of the year assumes that the level of volatility in the oil markets will subside over the remainder of the year.

LPG volumes are influenced by seasonal demands with higher volumes used in the winter months primarily for heating and decreasing during the summer months.

	Calendar 2005
	Three Months Ended														Twelve Months
	Actual			Guidance											Ended
	March 31			June 30			September 30				December 31				December 31
Average Daily Volumes (000’s Bbl/d)
Crude Oil Lease Gathering		622		635				640				645				636
LPG		84		35				50				80				62
		706		670				690				725				698
Segment Profit per Barrel
As Reported		$	0.257	$	0.991	⁽¹⁾		$	0.518	⁽¹⁾		$	0.379	⁽¹⁾		$	0.529	⁽¹⁾
Excluding Selected Items Impacting Comparability		$	0.497	$	1.036	⁽¹⁾		$	0.566	⁽¹⁾		$	0.425	⁽¹⁾		$	0.624	⁽¹⁾

(1) Mid-point of estimate.

Segment profit is forecast using the volume assumptions stated above and estimates of unit margins, operating expenses, G&A and carrying costs for contango inventory based on current and anticipated market conditions. Realized unit margins for any given lease-gathered barrel could vary significantly based on a variety of factors including location, quality and contract structure. Based on our mid-point projected segment profit per barrel for the third quarter of 2005, a 15,000 Bbl/d variance in lease gathering volumes would impact segment profit by approximately $2.8 million on an annualized basis. A $0.01 variance in the aggregate average per-barrel margin would impact segment profit by approximately $2.5 million on an annualized basis.

4. Depreciation & Amortization. Depreciation and amortization is forecast based on our existing depreciable assets and forecast capital expenditures. Depreciation is computed using the straight-line method over estimated useful lives, which range from 3 years (for office property and equipment) to 50 years (for certain pipelines, crude oil terminals and facilities).

5. Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). The forecast presented above does not include assumptions or projections with respect to potential gains or losses related to SFAS 133, as there is no accurate way to forecast these potential gains or losses. The potential gains or losses related to SFAS 133 (primarily non-cash, mark-to-market adjustments) could cause actual net income to differ materially from our projections.

6. Acquisitions and Capital Expenditures. Although acquisitions constitute a key element of our growth strategy, the forecasted results and associated estimates do not include any assumptions or forecasts for any material acquisition that may be made after the date hereof. Capital expenditures for expansion projects are forecast to be approximately $180 million during calendar 2005, a $60 million increase over the April 28, 2005 guidance. This increase is primarily due to the recently announced construction of a St. James, Louisiana storage facility with a total project cost of approximately $70 million, of which approximately $21 with be spent in 2005. Also included in the increase are expenditures related to numerous organic growth projects. Following are some of the more notable projects to be undertaken in 2005 and the estimated expenditures for the year.

	Calendar 2005
	(In Millions)
· St. James, Louisiana storage facility		$ 21
· Trenton pipeline expansion		$ 34
· Capital projects associated with the Link acquisition		$ 18
· NW Alberta fractionator		$ 16
· Cushing Phase V expansion		$ 13
· Kerrobert Tank expansion		$ 9
· Shell South Louisiana Asset Acquisition		$ 8

During the three months ended March 31, 2005, approximately $45 million of the forecasted $180 million of expansion capital was spent in accordance with the project commitments.

Capital expenditures for maintenance projects are forecast to be approximately $19 million during 2005, of which approximately $4 million was spent in the first quarter.

7. Capital Structure. The guidance is based on our projected capital structure as of March 31, 2005, and gives effect to the issuance in May 2005 of $150 million of 5.25% senior notes due 2015, the proceeds of which were used to repay existing bank indebtedness.

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

Calendar 2005 interest expense is expected to be between $61.7 million and $62.6 million, assuming an average long-term debt balance of approximately $1.0 billion and an all-in average rate of approximately 6.4%. While interest on floating rate debt is based on a forward one-year LIBOR index curve of 3.5%, over 90% of our projected average long-term debt balance has an average fixed interest rate of 6.1%. Included in the effective cost of debt are not only current cash payments, but also commitment fees, amortization of long-term debt discounts, and deferred amounts associated with terminated interest rate hedges. The amortization of deferred amounts associated with terminated interest rate hedges results in a non-cash component to interest expense of approximately $1.6 million per year (approximately $400,000 per quarter). Approximately 73% of these deferred amounts will be completely amortized by the fourth quarter of 2006. The remainder will be amortized over the next nine years.

Long-term debt at December 31, 2005 is projected to be approximately $1.05 billion.

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

period. Basic weighted average units outstanding are projected to average approximately 67.8 million units for 2005.

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. Accordingly, for each $0.05 per unit annual increase in the distribution rate up to $2.70 per unit, net income available for limited partners decreases approximately $1.0 million ($0.02 per unit) on an annualized basis. The amount of income allocated to our limited partnership 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 $2.55 per unit, our general partner’s distribution is forecast to be approximately $17.5 million annually, of which $14.0 million is attributed to the incentive distribution rights. The relative amount of the incentive distribution varies directionally with the number of units outstanding and the level of the distribution on the units.

10. Long-term Incentive Plans. The majority of phantom unit grants outstanding under our 1998 and 2005 Long-Term Incentive Plans contain vesting criteria that are based on a combination of performance benchmarks and service period. The phantom units under the 2005 plan generally vest on the later of 2 years, 4 years or 5 years, or achievement of annualized distribution levels of $2.60, $2.80 and $3.00 per unit, respectively, and the majority of the phantom units have a final service period vesting in 2011. Accordingly, guidance includes i) for phantom units tied to the $2.60 performance level, an accrual over the corresponding service period, generally 2 years, as it has been deemed probable that the $2.60 performance level will be reached, and ii) for the phantom units that are not tied to the $2.60 performance threshold but have a final service period vesting in 2011, a pro rata accrual associated with a six-year service period. For 2005, the guidance includes approximately $20.2 million of principally non-cash expense associated with these phantom units. Management has not completed its probability assessment of reaching future performance thresholds beyond the $2.60 level. If the $2.80 distribution threshold were deemed probable assuming a $42.00 unit price, an additional $1.4 million, $0.9 million and $0.9 million would be charged in the second, third and fourth quarters of 2005, respectively. This additional charge would impact earnings per limited partner unit by $(0.02), $(0.01) and $(0.01) for these periods. The actual amount of LTIP expense amortization in any given year will be directly influenced by fluctuations in our unit price and the amount of amortization in the early years and will also be increased if a determination is made that achievement of any of the remaining performance thresholds is probable.

11. Reconciliation of EBITDA and EBIT to Net Income. The following table reconciles the guidance ranges for EBIT and EBITDA to net income.

	Guidance (In millions)
	Three Months Ended				Three Months Ended				Three Months Ended				Twelve Months Ended
	June 30, 2005				September 30, 2005				December 31, 2005				December 31, 2005
	Low		High		Low		High		Low		High		Low		High
Reconciliation to Net Income
EBITDA		$ 99.2		$ 109.2		$ 76.1		$ 86.1		$ 66.1		$ 76.1		$ 307.9		$ 337.9
Depreciation and amortization		19.3		19.1		19.9		19.6		20.4		20.0		78.7		77.8
EBIT		79.9		90.1		56.2		66.5		45.7		56.1		229.2		260.1
Interest expense		14.7		14.5		16.3		16.0		17.0		16.6		62.6		61.7
Net Income		$ 65.2		$ 75.6		$ 39.9		$ 50.5		$ 28.7		$ 39.5		$ 166.6		$ 198.4

Forward-Looking Statements and Associated Risks

All statements, other than statements of historical fact, included in this report 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. 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:

· the success of our risk management activities;

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

· 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;

· 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 counter-parties;

· declines in volumes shipped on the Basin Pipeline, Capline Pipeline and our other pipelines by third party shippers;

· the availability of adequate third party production volumes for transportation and marketing in the areas in which we operate;

· successful third-party drilling efforts in areas in which we operate pipelines or gather crude oil;

· demand for various grades of crude oil and resulting changes in pricing conditions or transmission throughput requirements;

· fluctuations in refinery capacity in areas supplied by our transmission lines;

· the effects of competition;

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

· the impact of crude oil price fluctuations;

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

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

· weather interference with business operations or project construction;

· the currency exchange rate of the Canadian dollar;

· fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our LTIP plan;

· general economic, market or business conditions; and

· other factors and uncertainties inherent in the marketing, transportation, terminaling, gathering and storage of crude oil and liquified petroleum gas.

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.

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:	PLAINS AAP, L. P., its general partner
	By:	PLAINS ALL AMERICAN GP LLC, its general partner
Date: June 13, 2005	By:	/s/ PHIL KRAMER
		Name:	Phil Kramer
		Title:	Executive Vice President and Chief Financial Officer