Plains All American Pipeline - 10-Q quarterly report FY

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UNITED STATES SECURITIES AND EXCHANGE
COMMISSION

Washington, D.C. 20549

FORM 10-Q

Commission file number: 1-14569

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

(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 xNo o

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

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

At May 1, 2009, there were outstanding 128,661,645 Common Units.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Basis of Presentation

As used in this Form 10-Q, the terms “Partnership,” “Plains,” “we,” “us,” “our,” “ours” and similar terms refer to Plains All American Pipeline, L.P. and its subsidiaries, unless the context indicates otherwise. References to our “general partner,” as the context requires, include any or all of PAA GP LLC, Plains AAP, L.P. and Plains All American GP LLC.

The accompanying condensed consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2008 Annual Report on Form 10-K. 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.  The condensed balance sheet data as of December 31, 2008 was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.  The results of operations for the three months ended March 31, 2009 should not be taken as indicative of the results to be expected for the full year.

Note 2—Recent Accounting Pronouncements

Standards Adopted as of January 1, 2009

In November 2008, the Emerging Issues Task Force (“EITF”) issued Issue No. 08-06, “Equity Method Investment Accounting Considerations” (“EITF 08-06”). EITF 08-06 addresses certain accounting considerations, including initial measurement, decreases in investment value, and changes in the level of ownership or degree of influence related to equity method investments. We have adopted EITF 08-06 as of January 1, 2009.  Adoption did not have any material impact on our financial position, results of operations or cash flows.

In April 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) No. FAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP No. FAS 142-3”). FSP No. FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142. The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combinations,” and other generally accepted accounting principles. We have adopted the FSP as of January 1, 2009.  Adoption did not have any material impact on our financial position, results of operations or cash flows.

In March 2008, the EITF issued Issue No. 07-04, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships” (“EITF 07-04”). EITF 07-04 addresses the application of the two-class method under SFAS No. 128, “Earnings Per Share” in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions. The two-class method is an earnings allocation formula that determines earnings per unit for each class of common units and participating securities according to participation rights in undistributed earnings. We have adopted EITF 07-04 as of January 1, 2009.  The guidance in this Issue has been applied retrospectively for all financial statement periods presented.  Adoption impacted the net income available to limited partners used in our computation of earnings per unit, but did not impact our net income, distributions to limited partners, financial position, results of operations or cash flows.  See Note 6 for additional disclosure.

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Note 3—Trade Accounts Receivable

At March 31, 2009 and December 31, 2008, we had received approximately $89 million and $66 million, respectively, of advance cash payments from third parties to mitigate credit risk. In addition, we enter into netting arrangements with our counterparties. These arrangements cover a significant part of our transactions and also serve to mitigate credit risk.

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted.  At March 31, 2009 and December 31, 2008, substantially all of our net accounts receivable classified as current assets were less than 60 days past their scheduled invoice date.  Our allowance for doubtful accounts receivable totaled $7 million and $5 million at March 31, 2009 and December 31, 2008, respectively.  Although we consider our allowance for doubtful trade accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

Note 4—Inventory and Linefill

Inventory and linefill consisted of the following (barrels in thousands and dollars in millions, except per barrel amounts):

(1)                           The prices listed represent a weighted average associated with various grades and qualities of crude oil, LPG and refined products and, accordingly, are not comparable to published benchmarks for such products.

Note 5—Debt

Debt consists of the following (in millions):

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(1)          At March 31, 2009 and December 31, 2008, we have classified $235 million and $746 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 Intercontinental Exchange (“ICE”) margin deposits.

(2)          In August 2009, our $175 million 4.75% senior notes will mature.  However, since we have the ability and intent to refinance these notes, they are classified as long-term debt within our balance sheet.

(3)          At March 31, 2009, the aggregate fair value of our fixed-rate senior notes was estimated to be approximately $2,774 million.  Our fixed-rate senior notes are traded among institutions, which trades are routinely published by a reporting service.  Our determination of fair value is based on reported trading activity near quarter end.

In April 2009, we completed the issuance of $350 million of 8.75% Senior Notes due May 1, 2019.  The senior notes were sold at 99.994% of face value.  Interest payments are due on May 1 and November 1 of each year, beginning on November 1, 2009.  We used the net proceeds from this offering to reduce outstanding borrowings under our credit facilities, which may be reborrowed to fund future investments and for general partnership purposes.

Letters of Credit

In connection with our crude oil marketing, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil.  At March 31, 2009 and December 31, 2008, we had outstanding letters of credit of approximately $47 million and $51 million, respectively.

Note 6—Net Income per Limited Partner Unit

Basic and diluted net income per unit is determined by dividing our limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period.  Pursuant to EITF 07-04, the limited partners’ interest in net income is calculated by first reducing net income by the distribution pertaining to the current period’s net income, which is to be paid in the subsequent quarter (including the incentive distribution interest in excess of the 2% general partner interest).  Then, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement.  The adoption of EITF 07-04 resulted in a change to our calculation of earnings per unit by using distributions applicable to the period rather than distributions paid in the period (applicable to the previous period).  Also, in accordance with EITF 07-04, earnings per unit for prior periods were recast to conform to this revised calculation.

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three months ended March 31, 2009 and 2008 (amounts in millions, except per unit data):

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(1)         We allocate net income to our general partner based on the distribution paid during the current quarter (including the incentive distribution interest in excess of the 2% general partner interest).  EITF 07-04 requires that the distribution pertaining to the current period’s net income, which is to be paid in the subsequent quarter, be utilized within the earnings per unit calculation.  We reflect the impact of this difference as the Adjustment in accordance with EITF 07-04.

(2)         Our LTIP awards (described in Note 8) that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. 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 No. 128, “Earnings per Share.”

Note 7—Partners’ Capital and Distributions

Noncontrolling Interest in a Subsidiary

During the fourth quarter of 2008, we completed construction on a 93-mile expansion of the Salt Lake City Core Area system from Wahsatch, Utah to Salt Lake City, which has a throughput capacity of approximately 120,000 barrels per day. During February 2009, this pipeline became fully operational.  Pursuant to a master formation agreement, we contributed the pipeline with a book value of approximately $246 million to a newly formed joint venture, SLC Pipeline LLC (“SLC Pipeline”). Holly Energy Partners-Operating, L.P. (“HEP”) contributed approximately $26 million in cash for a 25% ownership in SLC Pipeline.  We own the remaining 75% interest in SLC Pipeline and control the joint venture, and therefore, have consolidated the financial results. 

We account for noncontrolling interests in subsidiaries in accordance with SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 requires all entities to report noncontrolling interests in subsidiaries (formerly referred to as minority interest) as a component of equity in the consolidated financial statements. Noncontrolling interest represents the portion of assets and liabilities in a subsidiary that is owned by a third-party. 

Upon formation of the SLC Pipeline joint venture and in accordance with SFAS 160, we recognized a loss in partners’ capital of approximately $36 million. This loss represents the difference between HEP’s contribution of cash and the book value of its 25% interest in the net assets of SLC Pipeline. As of March 31, 2009, the noncontrolling interest on the balance sheet consists solely of HEP’s interest in the net assets of SLC Pipeline.

Equity Offerings

During the three months ended March 31, 2009, we completed the following equity offering of our common units (in millions, except per unit data):

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(1)  The March 2009 offering of common units was an underwritten transaction that required us to pay a gross spread.

No equity offerings were completed during the three months ended March 31, 2008

Distributions

The following table details the distributions related to the first quarter of 2009 and 2008, net of reductions to the general partner’s incentive distributions (in millions, except per unit amounts):

(1)  Payable to unitholders of record on May 5, 2009, for the period January 1, 2009 through March 31, 2009.

Upon closing of the Pacific and Rainbow acquisitions, our general partner agreed to reduce the amounts due it as incentive distribution. The total reduction in incentive distributions related to these acquisitions is $75 million. Following the distribution in May 2009, the aggregate remaining incentive distribution reductions related to these acquisitions will be approximately $26 million.

Note 8—Equity Compensation Plans

Long-Term Incentive Plans

At March 31, 2009, the following LTIP awards were outstanding (units in millions):

(1)             Upon our February 2007 annualized distribution of $3.20, these LTIP awards satisfied all distribution requirements and will vest upon completion of the respective service period.

(2)             These LTIP awards have performance conditions requiring the attainment of an annualized distribution of between $3.50 and $4.50 and vest upon the later of a certain date or the attainment of such levels. If the performance conditions are not attained, these awards will be forfeited. For purposes of this disclosure, the awards are presented above assuming the distribution levels are attained and that the awards will vest on the earliest date possible regardless of our current assessment of probability.

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(3)             These LTIP awards have performance conditions requiring the attainment of an annualized distribution of between $3.50 and $4.00. Fifty percent of these awards will vest in 2012 regardless of whether the performance conditions are attained. For purposes of this disclosure, the awards are presented above assuming the distribution levels are attained and that the awards will vest on the earliest date possible regardless of our current assessment of probability.

(4)             Approximately 2.2 million of our approximately 4.1 million outstanding LTIP awards also include Distribution Equivalent Rights (“DERs”), of which 1.2 million are currently earned.

(5)             LTIP units outstanding do not include Class B units of Plains AAP, L.P. described below.

Our LTIP activity is summarized in the following table (in millions, except weighted average grant date fair values per unit):

Our accrued liability at March 31, 2009 related to all outstanding LTIP awards and DERs is approximately $64 million, which includes an accrual associated with our assessment that an annualized distribution of $3.75 is probable of occurring. We have not deemed a distribution of more than $3.75 to be probable. At December 31, 2008, the accrued liability was approximately $55 million.

For further discussion of our Long-Term Incentive Plan (“LTIP”) awards, see Note 10 to our Consolidated Financial Statements included in Part IV of our 2008 Annual Report on Form 10-K.

Class B Units of Plains AAP, L.P.

At March 31, 2009, 165,500 Class B units were outstanding, of which 38,500 units were earned. A total of 34,500 units were reserved for future grants. During the three months ended March 31, 2009, 11,500 Class B units were issued to certain members of our senior management. These Class B units become earned in increments of 37.5%, 37.5% and 25% 180 days after us achieving annualized distribution levels of $3.75, $4.00 and $4.50, respectively.  Although the entire economic burden of the Class B units, which are equity classified, is borne solely by Plains AAP, L.P. and does not impact our cash or units outstanding, the intent of the Class B units is to provide a performance incentive and encourage retention for certain members of our senior management. Therefore, we recognize the grant date fair value of the Class B units as compensation expense over the service period. The expense is also reflected as a capital contribution and thus, results in a corresponding credit to Partners’ Capital in our Condensed Consolidated Financial Statements. The total grant date fair value of the 165,500 Class B units outstanding at March 31, 2009 was approximately $34 million of which approximately $1 million was recognized as expense during the three months ended March 31, 2009.

Other Consolidated Equity Compensation Information

We refer to our LTIP Plans and the Class B units collectively as “Equity compensation plans.” The table below summarizes the expense recognized and the value of vestings (settled both in units and cash) related to the equity compensation plans (in millions):

Based on the March 31, 2009 fair value measurement and probability assessment regarding future distributions, we expect to recognize approximately $42 million of additional expense over the life of our outstanding awards related to the remaining unrecognized fair value. This estimate is based on the closing market price of our units of $36.76 at March 31,

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2009. Actual amounts may differ materially as a result of a change in the market price of our units and/or probability assessment regarding future distributions. We estimate that the remaining fair value will be recognized in expense as shown below (in millions):

(1)             Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at March 31, 2009.

(2)             Includes unamortized fair value associated with Class B units of Plains AAP, L.P.

(3)             Includes equity compensation plan fair value amortization for the remaining nine months of 2009.

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Note 9—Derivatives and Risk Management Activities

We identify the risks that underlie our core business activities and utilize risk management activities to mitigate those risks when we determine there is value in doing so.  We use various derivative instruments to (i) manage our exposure to commodity price risk, as well as to optimize our profits, (ii) manage our exposure to interest rate risk and (iii) manage our exposure to currency exchange rate risk. Our policy is to use derivative instruments only for risk management purposes.  Our risk management policies and procedures are designed to monitor interest rates, currency exchange rates, NYMEX, ICE and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity to help ensure that our hedging activities address our risks. Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategies 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 used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items.  A discussion of our derivative activities by risk category follows.

Commodity Price-Risk

Our core business activities contain certain commodity price related risks that we manage in various ways, including the utilization of derivative instruments.  Our policy is generally (i) to purchase only product for which we have a market, (ii) to structure our sales contracts so that price fluctuations do not materially affect the segment profit we earn, and (iii) not to acquire and hold physical inventory, futures contracts or other derivative products for the purpose of speculating on outright commodity price changes.  Subsequent to year end 2008, our risk management committee eliminated the 500,000 barrel controlled trading program discussed in our 2008 Form 10-K.  In that regard, the committee modified our risk management policies and procedures to better reflect our operating requirements and clarify provisions regarding intra-month activities to maintain a balanced position, which modifications are incorporated into the following discussion.  Although we seek to maintain a position that is substantially balanced within our marketing activities, we purchase crude and LPG from thousands of locations and may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery variances, as well as logistical issues associated with inclement weather conditions and other uncontrollable events that occur within each month. In connection with our efforts to maintain a balanced position, our personnel are authorized to purchase or sell an aggregate limit of up to 800,000 barrels of crude oil and LPG relative to the volumes originally scheduled for such month, based on interim information.  The purpose of these purchases and sales is to manage risk as opposed to establishing a risk position. When unscheduled physical inventory builds or draws do occur, they are monitored constantly and managed to a balanced position over a reasonable period of time.

The material commodity related risks inherent in our business activities can be summarized into the following general categories:

Commodity Purchase and Sales— In the normal course of our marketing operations, we purchase and sell crude oil, LPG, and refined products.  We use derivatives to manage the associated risks and to optimize profits.  As of March 31, 2009, material net derivative positions related to these activities included:

·      An approximate 265,000 barrel per day net long position (total net of  7.9 million barrels) associated with our crude oil activities, which will be unwound ratably during April 2009.

·      A short position averaging approximately 20,000 barrels per day (total of 4.7 million barrels) of calendar spread call options for the period May 2009 through December 2009.  These positions involve no outright price exposure, but instead represent potential offsetting purchases and sales between time periods (first month versus second month for example).

·      An average of 4,000 barrels per day (total of 2.4 million barrels) of butane/WTI spread positions, which hedge specific butane sales contracts that are based on a percentage of WTI and continue through 2010.

·      Approximately 9,500 barrels per day on average (total of 6.0 million barrels) of crude oil basis differential hedges, which run through 2010.

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Storage Capacity Utilization— We own approximately 55 million barrels of crude oil and refined products storage tanks that are not used in our transportation operations.  These storage tanks may be leased to third parties or utilized in our own marketing activities, including for the storage of inventory in a contango market. For capacity allocated to our marketing operations we have utilization risk if the market structure is backwardated. As of March 31, 2009, we used derivates to manage the risk of not utilizing approximately 3.0 million barrels per month of storage capacity through 2011.  These positions are a combination of calendar spread options  and NYMEX futures contracts.    These positions involve no outright price exposure, but instead represent potential offsetting purchases and sales between time periods (first month versus second month for example).

Inventory Storage —At times, we elect to purchase and store crude oil, LPG and refined products inventory in conjunction with our marketing activities.  These activities primarily relate to the seasonal storage of LPG inventories and contango market storage activities.  When we purchase and store barrels, we enter into physical sales contracts or use derivatives to mitigate price risk associated with the inventory.  As of March 31, 2009, we had approximately 10 million barrels of hedged inventory.

Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit.  We utilize derivative instruments to hedge a portion of the anticipated sales of the allowance oil that is to be collected under our tariffs.  As of March 31, 2009, we had entered into derivative positions to manage the risk associated with the anticipated sale of an average of approximately 1,900 barrels per day from April 2009 through December 2012.  These derivatives consisted of a net short position of approximately 1.3 million barrels and a net long put option position of approximately 1.3 million barrels.  In addition, we were long approximately 1.3 million barrels of call options for the same time period which provide upside price participation.

Diluent Purchases— We use diluent in our Canadian crude oil operations and have used derivative instruments to hedge the anticipated forward purchases of diluents.  As of March 31, 2009, we had an average of 4,500 barrels per day of natural gasoline/WTI spread positions (approximately 3.7 million barrels) that run through mid 2011.

The derivative instruments we use consist primarily of futures, options and swaps traded on the NYMEX, ICE and in over-the-counter transactions, including commodity swap and option contracts entered into with financial institutions and other energy companies.  All of our commodity derivatives that qualify for hedge accounting are designated as cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred into AOCI and recognized in revenues or purchases and related costs in the periods during which the underlying physical transactions occur. We have determined that substantially all of our physical purchase and sale agreements qualify for the normal purchase and sale exclusion and thus are not subject to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”). Physical transactions that are derivatives and are ineligible, or become ineligible, for the normal purchase and sale treatment (e.g. due to changes in settlement provisions) are recorded on the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues.

Interest Rate Risk Hedging

We use interest rate derivatives to hedge interest rate risk associated with anticipated debt issuances and in certain cases, outstanding debt instruments.  The derivative instruments we use consist primarily of interest rate swaps and treasury locks.  As of March 31, 2009, AOCI includes deferred losses that relate to terminated interest rate swaps and treasury locks that were designated for hedge accounting.  These terminated interest rate swaps and treasury locks were cash settled in connection with the issuance and refinancing of debt agreements over the previous five years. The deferred loss related to these instruments is being amortized to interest expense over the original terms of the forecasted debt instruments.

As of March 31, 2009, our outstanding interest rate derivatives consist of 4 interest rate swaps by which we receive fixed interest payments and pay floating-rate interest payments based on six-month LIBOR plus an average spread of 1.67% on a quarterly basis.  The swaps have a combined notional amount of $80 million with a fixed rate of 7.13% and terminate in 2014. Beginning on June 15, 2009, the swaps are subject to a call option whereby our counterparties have the right to call the swaps for a fee of $3 million.  Our outstanding interest rate swaps are not designated for hedge accounting.   However, the interest rate swaps serve as an economic hedge in the event that market interest rates decline below the fixed interest rate of the underlying debt.

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Amounts recognized in AOCI during the three months ended March 31, 2009 are as follows (in millions):

We do not enter into master netting agreements with our derivative counterparties, nor do we offset the assets and liabilities associated with the fair value of our derivatives with amounts we have recognized related to our right to receive or our obligation to pay cash collateral. When we deposit cash collateral with our brokers, we recognize a broker receivable, which is a component of our accounts receivable. The account equity in our brokerage accounts is a combination of our cash balance and the fair value of our open derivatives within our brokerage account.  When our account equity is less than our initial margin requirement we are required to post margin.  At March 31, 2009, we did not have a broker receivable because the fair value of our open derivatives exceeded our initial margin requirements. Our broker receivable was approximately $81 million as of December 31, 2008.  At March 31, 2009 and 2008, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings.

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2009. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels.

The determination of the fair values above incorporates various factors required under SFAS 157. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit) but also the impact of our nonperformance risk on our liabilities. The fair value of our commodity derivatives, interest rate derivatives and foreign currency derivatives includes adjustments for credit risk. We measure credit risk by deriving a probability of default from market observed credit default swap spreads as of the measurement date. The probability of default is applied to the net credit exposure of each of our counterparties and includes a recovery rate adjustment. The recovery rate is an estimate of what would

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ultimately be recovered through a bankruptcy proceeding in the event of default. There were no changes to any of our valuation techniques during the period.

Level 1

Included within level 1 of the fair value hierarchy are commodity derivatives that are exchange-traded. Exchange-traded derivative contracts include futures, options and swaps. The fair value of exchange-traded commodity derivatives is based on unadjusted quoted prices in active markets and is therefore classified within level 1 of the fair value hierarchy.

Level 2

Included within level 2 of the fair value hierarchy is a physical commodity supply contract that meets the definition of a derivative but is not excluded from SFAS 133 under the normal purchase and normal sale scope exception. The fair value of this commodity derivative is measured with level 1 inputs for similar but not identical instruments and therefore must be included in level 2 of the fair value hierarchy.

Level 3

Included within level 3 of the fair value hierarchy are (i) commodity derivatives that are not exchange traded, (ii) interest rate derivatives and (iii) foreign currency derivatives, which are described as follows:

·      Commodity Derivatives: Level 3 commodity derivatives include over-the-counter commodity derivatives such as forwards, swaps and options and certain physical commodity contracts. The fair value of our level 3 derivatives is based on either an indicative broker or dealer price quotation or a valuation model. Our valuation models utilize inputs such as price, volatility and correlation and do not involve significant management judgments.

·      Interest Rate Derivatives: Level 3 interest rate derivatives include interest rate swaps. The fair value of our interest rate derivatives is based on indicative broker or dealer price quotations. Broker or dealer price quotations are corroborated with objective inputs including forward LIBOR curves and forward Treasury yields that are obtained from pricing services.

·      Foreign Currency Derivatives: Level 3 foreign currency derivatives include foreign currency swaps, forward exchange contracts and options. The fair value of our foreign currency derivatives is based on indicative broker or dealer price quotations. Broker or dealer price quotations are corroborated with objective inputs including forward CAD/USD forward exchange rates that are obtained from pricing services.

The majority of the derivatives included in level 3 of the fair value hierarchy are classified as level 3 because the broker or dealer price quotations used to measure fair value and the pricing services used to corroborate the quotations are indicative quotations rather than quotations whereby the broker or dealer is ready and willing to transact. However, the fair value of these level 3 derivatives is not based upon significant management assumptions or subjective inputs.

Rollforward of Level 3 Net Liability

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives measured at fair value using inputs classified as level 3 in the fair value hierarchy (in millions):

We believe that a proper analysis of our level 3 gains or losses must incorporate the understanding that these items are generally used to hedge our commodity price risk, interest rate risk and foreign currency exchange risk and are therefore offset by the underlying transactions.

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Note 10—Income Taxes

U.S. Federal and State Taxes

As a master limited partnership, we are not subject to U.S. federal income taxes; rather, the tax effect of our operations is passed through to our unitholders. Although, we are subject to state income taxes in some states, the impact is immaterial.

Canadian Federal and Provincial Taxes

Certain of our Canadian subsidiaries are corporations for Canadian tax purposes, thus their operations are subject to Canadian federal and provincial income taxes. The remainder of our Canadian operations is conducted through an operating limited partnership, which has historically been treated as a flow-through entity for tax purposes. This entity is subject to Canadian legislation passed in June 2007 that imposes entity-level taxes on certain types of flow-through entities. This legislation includes safe harbor guidelines that grandfather certain existing entities (which, we believe, would include us) and delay the effective date of such legislation until 2011 provided that such entities do not exceed the normal growth guidelines. Although we continuously review acquisition opportunities that, if consummated, could cause us to exceed the normal growth guidelines, we believe that we are currently within the normal growth guidelines.

Note 11—Commitments and Contingencies

Litigation

Pipeline Releases.  In January 2005 and December 2004, we experienced two unrelated releases of crude oil that reached rivers located near the sites where the releases originated. In early January 2005, an overflow from a temporary storage tank located in East Texas resulted in the release of approximately 1,200 barrels of crude oil, a portion of which reached the Sabine River. In late December 2004, one of our pipelines in West Texas experienced a rupture that resulted in the release of approximately 4,500 barrels of crude oil, a portion of which reached a remote location of the Pecos River. In both cases, emergency response personnel under the supervision of a unified command structure consisting of representatives of Plains, the EPA, the Texas Commission on Environmental Quality and the Texas Railroad Commission conducted clean-up operations at each site. Approximately 980 and 4,200 barrels were recovered from the two respective sites. The unrecovered oil was removed or otherwise addressed by us in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately $4 million to $5 million. In cooperation with the

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appropriate state and federal environmental authorities, we have completed our work with respect to site restoration, subject to some ongoing remediation at the Pecos River site. EPA has referred these two crude oil releases, as well as several other smaller releases, to the U.S. Department of Justice (the “DOJ”) for further investigation in connection with a civil penalty enforcement action under the Federal Clean Water Act. We have cooperated in the investigation and are currently involved in settlement discussions with DOJ and EPA. Our assessment is that it is probable we will pay penalties related to the releases. We may also be subjected to injunctive remedies that would impose additional requirements, costs and constraints on our operations. We have accrued our current estimate of the likely penalties as a loss contingency, which is included in the estimated aggregate costs set forth above. We understand that the maximum permissible penalty, if any, that EPA could assess with respect to the subject releases under relevant statutes would be approximately $6.8 million. Such statutes contemplate the potential for substantial reduction in penalties based on mitigating circumstances and factors. We believe that several of such circumstances and factors exist, and thus have been a primary focus in our discussions with the DOJ and EPA with respect to these matters.

SemCrude Bankruptcy.  We will from time to time have claims relating to insolvent suppliers, customers or counterparties, such as the bankruptcy proceedings of SemCrude. As a result of our statutory protections and contractual rights of setoff, substantially all of our pre-petition claims against SemCrude should be satisfied. Certain creditors of SemCrude and its affiliates have challenged our contractual and statutory rights to setoff certain of our payables to the debtor against our receivables from the debtor. The aggregate amount subject to challenge is approximately $62 million. We intend to vigorously defend our contractual and statutory rights.

On November 15, 2006, we completed the Pacific merger. The following is a summary of the more significant matters that relate to Pacific, its assets or operations.

United States of America v. Pacific Pipeline System, LLC (“PPS”).  In March 2005, a release of approximately 3,400 barrels of crude oil occurred on Line 63, subsequently acquired by us in the Pacific merger. The release occurred when the pipeline was severed as a result of a landslide caused by heavy rainfall in the Pyramid Lake area of Los Angeles County. Total projected emergency response, remediation and restoration costs are approximately $26 million, substantially all of which have been incurred and recovered under a pre-existing PPS pollution liability insurance policy.  In September 2008, the EPA filed a civil complaint against PPS, a subsidiary acquired in the Pacific merger, in connection with the Pyramid Lake release. The complaint, which was filed in the Federal District Court for the Central District of California, Civil Action No. CV08-5768DSF(SSX), seeks the maximum permissible penalty under the relevant statutes of approximately $3.7 million. The EPA and DOJ have discretion to reduce the fine, if any, after considering other mitigating factors. Because of the uncertainty associated with these factors, the final amount of the fine that will be assessed for the alleged offenses cannot be ascertained. We may also be subjected to injunctive remedies that would impose additional requirements, costs and constraints on our operations. We will defend against these charges. We believe that several defenses and mitigating circumstances and factors exist that could substantially reduce any penalty or fine that might be imposed by the EPA and DOJ, and intend to pursue discussions with the EPA and DOJ regarding such defenses and mitigating circumstances and factors. Although we have established an estimated loss contingency for this matter, we are presently unable to determine whether the March 2005 spill incident may result in a loss in excess of our accrual for this matter. Discussions with the DOJ on behalf of the EPA to resolve this matter have commenced.

Exxon v. GATX.  This Pacific legacy matter involves the allocation of responsibility for remediation of MTBE (and other petroleum product) contamination at the Pacific Atlantic Terminals LLC (“PAT”) facility at Paulsboro, New Jersey. The

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estimated maximum potential remediation cost ranges up to $10 million. Both Exxon and GATX were prior owners of the terminal. We contend that Exxon and GATX are primarily responsible for the majority of the remediation costs. We are in dispute with Kinder Morgan (as successor in interest to GATX) regarding the indemnity by GATX in favor of Pacific in connection with Pacific’s purchase of the facility. In a related matter, the New Jersey Department of Environmental Protection has brought suit against GATX and Exxon to recover natural resources damages. Exxon and GATX have filed third-party demands against PAT, seeking indemnity and contribution. We are vigorously defending against any claim that PAT is directly or indirectly liable for damages or costs associated with the contamination, which occurred prior to PAT’s ownership.

Other Pacific-Legacy Matters.  Pacific had completed a number of acquisitions that had not been fully integrated prior to the merger with Plains. Accordingly, we have and may become aware of other matters involving the assets and operations acquired in the Pacific merger as they relate to compliance with environmental and safety regulations, which matters may result in mitigative costs or the imposition of fines and penalties.

General.  We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

Environmental

We have in the past experienced and in the future likely will experience releases of crude oil into the environment from our pipeline and storage operations. We also may discover environmental impacts from past releases that were previously unidentified. Although we maintain an inspection program designed to help prevent releases, damages and liabilities incurred due to any such releases from our assets may substantially affect our business. As we expand our pipeline assets through acquisitions, we typically improve on (decrease) the rate of releases from such assets as we implement our procedures, remove selected assets from service and spend capital to upgrade the assets. However, the inclusion of additional miles of pipe in our operations may result in an increase in the absolute number of releases company-wide compared to prior periods. We experienced such an increase in connection with the Pacific acquisition, which added approximately 5,000 miles of pipeline to our operations, and in connection with the purchase of assets from Link in April 2004, which added approximately 7,000 miles of pipeline to our operations. As a result, we have also received an increased number of requests for information from governmental agencies with respect to such releases of crude oil (such as EPA requests under Clean Water Act Section 308), commensurate with the scale and scope of our pipeline operations, including a Section 308 request received in late October 2007 with respect to a 400-barrel release of crude oil, a portion of which reached a tributary of the Colorado River in a remote area of West Texas. See “—Pipeline Releases” above.

At March 31, 2009, our reserve for environmental liabilities totaled approximately $40 million, of which approximately $9 million is classified as short-term and $31 million is classified as long-term. At March 31, 2009, we have recorded receivables totaling approximately $4 million for amounts that are probable of recovery under insurance and from third parties under indemnification agreements.

In some cases, the actual cash expenditures may not occur for three to five years. Our estimates used in these reserves are based on all known facts at the time and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing legal claims giving rise to additional claims. Therefore, although we believe that the reserve is adequate, costs incurred in excess of this reserve may be higher and may potentially have a material adverse effect on our financial condition, results of operations, or cash flows.

Other.  A pipeline, terminal or other facility may experience damage as a result of an accident, natural disaster or terrorist activity. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance covers our assets in amounts considered reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. The overall trend in the environmental insurance industry appears to be a contraction in the breadth and depth of available coverage, while costs, deductibles and retention levels have increased. Absent a material favorable change

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in the environmental insurance markets, this trend is expected to continue as we continue to grow and expand. As a result, we anticipate we will elect to self-insure more of our environmental and wind damage exposures, incorporate higher retention in our insurance arrangements, pay higher premiums or some combination of such actions.

The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. In addition, although we believe that we have established adequate reserves to the extent that such risks are not insured, costs incurred in excess of these reserves may be higher and may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.

Note 12—Operating Segments

We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Marketing. The following table reflects certain financial data for each segment for the periods indicated (in millions):