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

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

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

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

Net revenues

Field operating costs

General and administrative expenses

 

 

Depreciation and amortization expense

Interest expense, net

Income tax expense

Other Income (Expense)

 

 

 

Net Income to Limited Partners

Basic Net Income Per Limited Partner Unit:

Weighted Average Units Outstanding

Net Income Per Unit

 

Diluted Net Income Per Limited Partner Unit:

Weighted Average Units Outstanding

Net Income Per Unit

 

 

 

 

LTIP charge

 

 

Adjusted Segment Profit

Transportation

Facilities

Marketing

 

Adjusted EBITDA

 

Adjusted Net Income

 

Adjusted Basic Net Income per Limited Partner Unit

 

Adjusted Diluted Net Income per Limited Partner Unit

 

Bcf

EBIT

EBITDA

Bbls/d

Segment Profit

LTIP

LPG

FX

Business Segments. Prior to the fourth quarter of 2006, we managed our operations through two segments. Due to our growth, especially in the facilities portion of our business (most notably in conjunction with our acquisition of Pacific Energy Partners, L.P. (“Pacific”)), we have revised the manner in which we internally evaluate our segment performance and decide how to allocate resources to our segments. As a result, we now manage our operations through three operating segments: (i) Transportation, (ii) Facilities, and (iii) Marketing.

Transportation. Our transportation segment operations generally consist of fee-based activities associated with transporting crude oil and refined products on pipelines and gathering systems. We generate revenue through a combination of tariffs, third-party leases of pipeline capacity, transportation fees, barrel exchanges and buy/sell arrangements. 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. Actual segment profit could vary materially depending on the level of volumes transported.

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.

Average Daily Volumes (MBbls/d)

Crude Oil

All American

Basin

BOA / CAM

Capline

Line 63 / 2000

Salt Lake City

North Dakota / Trenton

West Texas / New Mexico area systems (1)

Manito

Other

 

 

Refined Products

 

 

 

Average Segment Profit ($/Bbl)

Excluding Selected Items Impacting Comparability

 

The aggregate of multiple systems in the West Texas / New Mexico area.

Mid-point of guidance.

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

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 25.7 billion cubic feet of underground natural gas storage capacity and is constructing an additional 24 Bcf of underground storage capacity.

Operating Data:

Crude Oil, Refined Products and LPG Storage (MMBbls/Month)

 

Natural Gas Storage, net (Bcf/Month)

 

LPG Processing (MBbl/d)

 

 

Facilities Activities Total — Average Capacity (MMBbls/Month)⁽¹⁾

 

 

Average Segment Profit per Barrel ($/Bbl)

Excluding Selected Items Impacting Comparability

 

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 gas to oil ratio; and iii) LPG processing volumes multiplied by the number of days in the month and divided by 1,000 to convert to monthly volumes in millions.

Mid-point of guidance.

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

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 of foreign cargoes at their load port and various other locations in transit;

storage of inventory during contango market conditions;

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

arranging for 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 March 31, 2007 reflect an expected continuation of the current contango market and favorable market conditions (relative to our asset base and business model) generally consistent with the conditions experienced in the fourth quarter of 2006, and a moderately strong market structure for the remaining three quarters of 2007. Unexpected changes in market structure or volatility (or lack thereof) could cause actual results to differ materially from forecasted results.

Average Daily Volumes (MBbls/d)

Crude Oil Lease Gathering

LPG Sales

Waterborne foreign crude imported

 

 

 

Average Segment Profit per Barrel ($/Bbl)

Excluding Selected Items Impacting Comparability

 

Mid-point of guidance.

Segment profit is forecast using the volume assumptions stated above and 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.

Depreciation and Amortization. Depreciation and amortization are forecast 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).

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.

Capital Expenditures and Acquisitions. 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 acquisition that may be made after the date hereof. Capital expenditures for expansion projects are forecasted to be approximately $500 million during calendar 2007. Following are some of the more notable projects and projected expenditures for the year:

Expansion Capital

•  St. James, Louisiana storage facility

•  Salt Lake City Expansion

•  Patoka Tankage

•  Cheyenne Pipeline

•  Martinez Terminal

•  Cushing Tankage — Phase VI

•  Paulsboro Expansion

•  West Hynes Tanks

•  Kerrobert Tankage

•  Fort Laramie Tank Expansion

•  High Prairie Rail Terminal

•  Pier 400

•  Other Projects

 

 

Maintenance Capital

 

Total Projected Capital Expenditures (excluding acquisitions)

 

Capital Structure. This guidance is based on our capital structure as of December 31, 2006. The Partnership’s policy is to finance acquisitions and major growth capital projects with at least 50% equity or cash flow in excess of distributions. As a result of our 2006 equity financing activities in combination with our projected 2007 cash flow in excess of distributions, we have substantially pre-funded the required equity financing associated with our 2007 expansion capital program.

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.

Annual 2007 interest expense is expected to be between $164 million and $168 million, assuming an average long-term debt balance of approximately $2.8 billion during the period. Included in the effective cost of debt are projected interest payments, as well as 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 does not include interest on borrowings for contango inventory. We treat those costs as carrying costs of crude oil and include it as part of the purchase price of crude oil.

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.

Numerator for basic and diluted earnings per limited partner unit:

Net Income

General partner’s incentive distribution

General partner’s incentive distribution reduction

 

 

General partner 2% ownership

 

Net Income available for limited partners

 

Denominator:

Denominator for basic earnings per limited partner unit-weighted average number of limited partner units

Effect of dilutive securities:

Weighted average LTIP units

 

Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units

 

Basic net income per limited partner unit

 

Diluted net income per limited partner unit

 

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 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 $3.20 per unit, our general partner’s distribution is forecast to be approximately $87.1 million annually, of which $81.5 million is attributed to the incentive distribution rights. However, in conjunction with the Pacific acquisition, the general partner agreed to reduce the amounts due it as incentive distributions. The reduction will be effective for five years, as follows: (i) $5 million per quarter for the first four quarters, (ii) $3.75 million per quarter for the next eight quarters, (iii) $2.5 million per quarter for the next four quarters, and (iv) $1.25 million per quarter for the final four quarters. The total reduction in incentive distributions will be $65 million. As such, total incentive distributions to the general partner in 2007 will be reduced by $20.0 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. Each $0.05 per unit annual increase in the distribution over $3.20 per unit decreases net income available for limited partners by approximately $5.4 million ($0.05 per unit) on an annualized basis.

Long-term Incentive Plans. The majority of grants outstanding under our Long-Term Incentive Plans contain vesting criteria that are based on a combination of performance benchmarks and service period. The grants will 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 2007 to May 2012 and minimum annualized distribution levels range from $2.60 to $4.00. For some awards, a percentage of any remaining units will vest on a date certain in 2011 or 2012.

We have reached the annualized distribution level of $3.20 and, accordingly, for grants that vest at annualized distribution levels of $3.20 or less, guidance includes an accrual over the corresponding service period at an assumed market price of $53.80 per unit as well as the fair value associated with awards that will vest on a date certain. For 2007, the guidance includes approximately $35.3 million of expense associated with these grants. The next annualized distribution threshold that would affect the vesting accrual is $3.50 and at this time, it has not been deemed probable. If achievement of the $3.50 performance threshold is deemed probable at any point during 2007, then the total LTIP charge for 2007 would increase by approximately $7.7 million, all other factors remaining constant.

In May 2007, we anticipate that approximately 0.7 million units will vest totaling $37.8 million using the assumed $53.80 unit price above.

The actual amount of LTIP expense amortization in any given year will be directly influenced by our unit price at the end of each reporting period and the amount of amortization in the early years as well as new unit grants. Therefore, actual net income could differ materially from our projections.

Reconciliation of EBITDA and EBIT to Net Income. The following table reconciles the 2007 guidance ranges for EBITDA and EBIT to net income.

EBITDA

Depreciation and amortization

 

EBIT

 

Interest expense

Income tax expense

 

Net Income

 

our failure to successfully integrate the business operations of Pacific or our failure to successfully integrate any future acquisitions;

the failure to realize the anticipated cost savings, synergies and other benefits of the merger with Pacific;

the success of our risk management activities;

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;

failure to implement or capitalize on planned internal growth projects;

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 main lines and other factors affecting demand for various grades of crude oil, refined products and natural gas and resulting changes in pricing conditions or transmission 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;

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

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.

 

 

 

 

 

Date: February 22, 2007

 

 

 

 

99.1