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)

 

333 Clay Street, Suite 1600, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

(713) 646-4100

(Registrant’s telephone number, including area code)

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

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

 

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

At April 24, 2006, there were outstanding 77,273,248 Common Units.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

				Page
PART I. FINANCIAL INFORMATION
Item 1.	UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets: March 31, 2006 and December 31, 2005			3
Consolidated Statements of Operations: For the three months ended March 31, 2006 and 2005			4
Consolidated Statements of Cash Flows: For the three months ended March 31, 2006 and 2005			5
Consolidated Statement of Partners’ Capital: For the three months ended March 31, 2006			6
Consolidated Statements of Comprehensive Income: For the three months ended March 31, 2006 and 2005			7
Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the three months ended March 31, 2006			7
Notes to the Consolidated Financial Statements			8
Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		20
Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		32
Item 4.	CONTROLS AND PROCEDURES		32
PART II. OTHER INFORMATION
Item 1.	LEGAL PROCEEDINGS		34
Item 1a.	RISK FACTORS		34
Item 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		34
Item 3.	DEFAULTS UPON SENIOR SECURITIES		34
Item 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		34
Item 5.	OTHER INFORMATION		34
Item 6.	EXHIBITS		35
SIGNATURES			37

 

 

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PART I. FINANCIAL INFORMATION

Item 1.                        UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except units)

 

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per unit data)

 

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

4

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)

 

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

5

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
(in millions)

 

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

6

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

 

CONSOLIDATED STATEMENT OF
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in millions)

 

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note 1—Organization and Accounting Policies

Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in September 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. and Plains Marketing Canada, L.P. We are engaged in interstate and intrastate crude oil transportation, and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other natural gas related petroleum products. We refer to liquefied petroleum gas and other natural gas related petroleum products collectively as “LPG.” We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key oil producing basins, transportation corridors and at major market hubs in the United States and Canada. In addition, through our 50% equity ownership in PAA/Vulcan Gas Storage, LLC (“PAA/Vulcan”), we are engaged in the development and operation of natural gas storage facilities.

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

Note 2—Trade Accounts Receivable

The majority of our trade accounts receivable relates to our gathering and marketing activities, which can generally be described as high volume and low margin activities. As is customary in the industry, a portion of these receivables is reflected net of payables to the same counterparty based on contractual agreements. We routinely review our trade accounts receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such uncollected amounts involve billing delays and discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered, received or exchanged. We also attempt to monitor changes in the creditworthiness of our customers as a result of developments related to each customer, the industry as a whole and the general economy. Based on these analyses, as well as our historical experience and the facts and circumstances surrounding certain aged balances, we have established an allowance for doubtful trade accounts receivable. At March 31, 2006, substantially all of our net trade accounts receivable were less than 60 days

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

 

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

Note 3—Acquisitions

During the first quarter of 2006, we paid into escrow approximately $17 million related to an acquisition which subsequently closed in April 2006. Also, during March 2006, we signed an agreement to acquire 100% of the equity interests of Andrews Petroleum, Inc. and Lone Star Trucking, Inc. for approximately $205 million. Andrews and Lone Star provide isomerization, fractionation, marketing and transportation services to producers and customers of natural gas liquids (“NGLs”) throughout the Western United States. The acquisiton closed in April 2006 and will be reflected in our gathering, marketing, terminalling and storage operations (“GMT&S”) segment in the second quarter of 2006. See Note 14 to our Consolidated Financial Statements for a discussion of additional acquisition activity subsequent to March 31, 2006.

Note 4—Inventory and Linefill

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

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

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

 

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Note 5—Debt

Below is a description of our debt:

(1)                 At March 31, 2006 and December 31, 2005, we have classified $149.9 million and $155.4 million, respectively, of borrowings under our senior unsecured revolving credit facility as short-term. These borrowings are designated as working capital borrowings, must be repaid within one year, and are primarily for hedged LPG and crude oil inventory and New York Mercantile Exchange (“NYMEX”) margin deposits.

(2)                 At March 31, 2006, the aggregate fair value of our fixed-rate senior notes is estimated to be approximately $951 million. The carrying values of the variable rate instruments in our credit facilities approximate fair value primarily because interest rates fluctuate with prevailing market rates, and the credit spread on outstanding borrowings reflect market.

Note 6—Earnings Per Limited Partner Unit

Except as discussed below, basic and diluted net income per limited partner unit is determined by dividing net income after deducting the amount allocated to the general partner interest (including its incentive distribution in excess of its 2% interest), by the weighted average number of outstanding limited partner units during the period. Subject to applicability of EITF No. 03-06 (“EITF 03-06’’), “Participating Securities and the Two-Class Method under FASB Statement No. 128,” Partnership income is first allocated to the general partner based on the amount of incentive distributions. The remainder is then

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allocated between the limited partners and general partner based on percentage ownership in the Partnership.

The following sets forth the computation of basic and diluted earnings per limited partner unit. The weighted average limited partner units outstanding have been adjusted for instruments considered common unit equivalents at March 31, 2006 and 2005.

(1)      Under EITF 03-06, when the Partnership’s aggregate net income exceeds the aggregate distribution made during such period, earnings per limited partner unit are calculated as if all of the earnings for the period were distributed, regardless of the pro forma nature of the allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective.

Note 7—Partners’ Capital and Distributions

Direct Placement of Common Units

On March 22, 2006, we issued 2,336,448 common units pursuant to our existing shelf registration statement in a direct placement to a group of funds affiliated with institutional investors. The sale price for

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the common units was $42.80 per unit resulting in net proceeds of approximately $101 million, including the general partner’s proportionate capital contribution. In addition, in April 2006, upon closing of the Andrews Petroleum, Inc. acquisition, these investors purchased 1,168,224 additional common units at the same price as noted above, representing an incremental $51 million in proceeds, including the general partner’s proportionate capital contribution. Expenses associated with these transactions were approximately $1 million. The net proceeds were used to fund a portion of the acquisition of Andrews Petroleum, Inc. and related businesses, to reduce indebtedness and for general partnership purposes. Certain of the funds affiliated with the institutional investors involve related parties. We sold approximately 20% of the common units to investment funds affiliated with Kayne Anderson Capital Advisors, L.P. (“KACALP”). KAFU Holdings, L.P., which owns 20.3% of our general partner and has a representative on our board of directors, is managed by KACALP.

Distributions

On April 20, 2006, we declared a cash distribution of $0.7075 per unit on our outstanding common units. The distribution is payable on May 15, 2006, to unitholders of record on May 5, 2006, for the period January 1, 2006, through March 31, 2006. The total distribution to be paid is approximately $63 million, with approximately $55 million to be paid to our common unitholders and approximately $1 million and $7 million to be paid to our general partner for its general partner and incentive distribution interests, respectively.

On January 24, 2006, we declared a cash distribution of $0.6875 per unit on our outstanding common units. The distribution was paid on February 14, 2006 to unitholders of record on February 3, 2006, for the period October 1, 2005 through December 31, 2005. The total distribution paid was approximately $57 million, with approximately $51 million paid to our common unitholders and $1 million and $6 million paid to our general partner for its general partner and incentive distribution interests, respectively.

Note 8—Long-Term Incentive Plans

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

As of March 31, 2006, there were approximately 2.2 million unvested phantom units with a weighted average grant-date fair value of $31.27 per unit outstanding, substantially all of which were granted in February 2005.  In addition, approximately 1.6 million of these Awards include DERs. Approximately 1.5 million of the Awards vest over a six-year period (with performance accelerators), while the remaining awards vest over time only if certain performance conditions are met and are forfeited after seven years if the performance conditions are not met. The DERs vest over time (with performance accelerators) and terminate with the vesting or forfeiture of the related phantom units.

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

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

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

We recognized expense related to our LTIP of approximately $10 million in the first quarter of 2006 under SFAS 123(R) and $2 million for the first quarter of 2005 under our previous accounting model. During the year ended December 31,2005, approximately 97,000 Awards under our LTIP vested. We paid cash of approximately $1 million in lieu of delivery of common units for approximately 25,000 of the phantom units and issued approximately 47,000 new common units (after netting for taxes of approximately $1 million) in connection with the vesting. In addition, we made DER related payments of approximately $1 million during 2005.

As of March 31, 2006, the weighted average contractual life of our outstanding Awards was approximately five years. Based on the March 31, 2006 fair value measurement, we expect to recognize an additional $62 million of expense over the life of our outstanding Awards related to the remaining unrecognized fair value. This estimate is based on the market price of our limited partner units at the end of the period and actual amounts may differ materially as a result of a change in market price. We estimate that the remaining fair value will be recognized in expense as shown below (in millions):

 

Note 9—Derivative Instruments and Hedging Activities

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

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Summary of Financial Impact

The majority of our derivative activity is related to our commodity price risk hedging activities. Through these activities, we hedge our exposure to price fluctuations with respect to crude oil, LPG and natural gas in storage, as well as with respect to expected purchases, sales and transportation of these commodities. The derivative instruments we use consist primarily of futures and options contracts traded on the NYMEX, IPE and over-the-counter transactions, including commodity swap and option contracts entered into with financial institutions and other energy companies.

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

During the first three months of 2006, our earnings include a net gain of approximately $5 million resulting from all derivative activities, including the change in fair value of open derivatives and settled derivatives taken to earnings during the period. This gain includes (i) a net mark-to-market loss on open positions of approximately $1 million, which is primarily related to the net change in fair value during the period of open derivatives used to hedge price exposure that do not qualify for hedge accounting and (ii) a net gain of approximately $6 million related to settled derivatives taken to earnings during the period. The majority of this net gain is related to cash flow hedges that were recognized in earnings in conjunction with the underlying physical transactions that occurred during the quarter.

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

 

The net liability as of March 31, 2006 includes approximately $17 million of unrealized losses recognized in earnings and $9 million of unrealized losses on effective cash flow hedges that are deferred to OCI. The majority of the $17 million of unrealized losses that have been recognized in earnings relate to activities associated with our storage assets. In general, revenue from storing crude oil is reduced in a backwardated market (when oil prices for future deliveries are lower than for current deliveries) as there is less incentive to store crude oil from month to month. We enter into derivative contracts that will offset the reduction in revenue by generating offsetting gains in a backwardated market structure. These derivatives do not qualify for hedge accounting because the contracts will not necessarily result in physical delivery.

At March 31, 2006, there was a total unrealized net loss of approximately $14 million deferred to OCI. This included approximately $9 million (referenced above), which predominantly related to unrealized

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losses on derivatives used to hedge physical inventory in storage that receive hedge accounting, and approximately $5 million relating to terminated interest rate swaps, that are being amortized to interest expense over the original terms of the terminated instruments. The inventory hedges are mostly short derivative positions that will result in losses when prices rise. These hedge losses are offset by an increase in the physical inventory value and will be reclassed into earnings from OCI in the same period that the underlying physical inventory is sold. The total amount of deferred net losses recorded in OCI are expected to be reclassified to future earnings contemporaneously with the related physical purchase or delivery of the underlying commodity or payments of interest.

Of the total net loss deferred in OCI at March 31, 2006, a net loss of approximately $11 million will be reclassified into earnings in the next twelve months and the remaining net loss at various intervals (ending in 2016 for amounts related to our terminated interest rate swaps and 2009 for amounts related to our commodity price-risk hedging). Because a portion of these amounts is based on market prices at the current period end, actual amounts to be reclassified may differ and could vary materially as a result of changes in market conditions.

During the three months ended March 31, 2006, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring.

Note 10—Related Party Transactions

PAA/Vulcan is developing a natural gas storage facility through its wholly owned subsidiary, Pine Prairie Energy Center, LLC (“Pine Prairie”). Proper functioning of the Pine Prairie storage caverns will require a minimum operating inventory contained in the caverns at all times (referred to as “pad gas” or “base gas”). We estimate that it will require approximately 7.3 billion cubic feet of pad gas. During the first quarter of 2006, we have arranged to provide the base gas for the storage facility to Pine Prairie at a price not to exceed $8.50 per million cubic feet. In conjunction with this arrangement, we executed hedges on the NYMEX for the relevant delivery periods of 2007, 2008 and 2009. We will receive a fee of approximately $1 million for our services to own and manage the hedge positions and to deliver the natural gas.

Note 11—Commitments and Contingencies

Litigation

Export License Matter.   In our gathering and marketing activities, we import and export crude oil from and to Canada. Exports of crude oil are subject to the “short supply” controls of the Export Administration Regulations (“EAR”) and must be licensed by the Bureau of Industry and Security (the “BIS”) of the U.S. Commerce Department. In 2002, we determined that we may have violated the terms of our licenses with respect to the quantity of crude oil exported and the end-users in Canada. Export of crude oil except as authorized by license is a violation of the EAR. In October 2002, we submitted to the BIS an initial notification of voluntary disclosure. We subsequently supplemented the information in response to internal reviews and requests from the BIS. In March 2006, the BIS opened discussion regarding the settlement of any fines and penalties associated with the potential violations of the EAR. In March 2006, we reached agreement in principle with the BIS to settle the matter for an agreed payment of approximately $82,000.

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. Aggregate costs associated with

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the releases, including estimated remediation costs, are estimated to be approximately $4 million to $5 million. In cooperation with the appropriate state and federal environmental authorities, we have substantially completed our work with respect to site restoration, subject to some ongoing remediation at the Pecos River site. We have been informed by the U.S. Environmental Protection Agency (“EPA”) that it has referred these two crude oil releases, as well as several other smaller releases, to the U.S. Department of Justice (“DOJ”) for further investigation in connection with a possible civil penalty enforcement action under the Federal Clean Water Act. We are cooperating with EPA and DOJ in such investigation.

General.   We, in the ordinary course of business, are a claimant and /or a defendant in various legal proceedings. We do not believe that the outcome of these legal proceedings, individually and in the aggregate, will have a materially 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 or natural disaster. 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. As a result of the significant wind damage claims filed following hurricanes Katrina, Rita and Wilma, the insurance industry has indicated that it will materially reduce the amount of coverage available for windstorm damages. Absent a material favorable change in the insurance markets, these trends are expected to continue as we continue to grow and expand. As a result, we anticipate that we will elect to self-insure more of our activities or incorporate higher retention in our insurance arrangements.

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, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable, or that we have established adequate reserves to the extent that such risks are not insured.

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Note 12—Operating Segments

Our operations consist of two operating segments: (i) pipeline transportation operations (“Pipeline”) and (ii) GMT&S. Through our Pipeline segment, we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities. Through our GMT&S segment, we engage in purchases and resales of crude oil and LPG at various points along the distribution chain, and we operate certain terminalling and storage assets. The following table reflects certain financial data for each segment for the periods indicated:

(1)                 Amounts related to SFAS 133 are included in revenues and impact segment profit.

(2)                 Intersegment sales are conducted at arms length.

(3)                 GMT&S segment profit includes interest expense on contango inventory purchases of $9 million for the quarter ended March 31, 2006 and $4 million for the quarter ended March 31, 2005 .

(4)         The following table reconciles segment profit to consolidated income before cumulative effect of change in accounting principle (in millions):

 

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Note 13—Recent Accounting Pronouncements

In December 2004, SFAS 123(R) was issued which amends SFAS No. 123, “Accounting for Stock-Based Compensation,” and establishes accounting for transactions in which an entity exchanges its equity instruments for goods or services. This statement requires that the cost resulting from all share-based payment transactions be recognized in the financial statements at fair value. We adopted SFAS 123(R) on January 1, 2006 under the modified prospective transition method, as defined in SFAS 123(R), and recognized a cumulative effect of change in accounting principle of approximately $6 million. The cumulative effect adjustment represents a decrease to our Long Term Incentive Plan (“LTIP”) life-to-date accrued expense and related liability under our previous cash-plan, probability-based accounting model and adjusts our aggregate liability to the appropriate fair-value based liability as calculated under a SFAS 123(R) methodology. Under the modified prospective transition method, we are not required to adjust our prior period financial statements to reflect a fair value cost methodology for our LTIP awards.

In September 2005, the Emerging Issues Task Force (“EITF”) issued Issue No. 04-13 (“EITF 04-13”), “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The EITF concluded that inventory purchases and sales transactions with the same counterparty should be combined for accounting purposes if they were entered into in contemplation of each other. The EITF provided indicators to be considered for purposes of determining whether such transactions are entered into in contemplation of each other. Guidance was also provided on the circumstances under which nonmonetary exchanges of inventory within the same line of business should be recognized at fair value. EITF 04-13 will be effective in reporting periods beginning after March 15, 2006.

We adopted EITF 04-13 on April 1, 2006, which will cause inventory purchases and sales under buy/sell transactions, which were recorded gross as purchases and sales, to be treated as inventory exchanges in our consolidated statement of operations. We have parenthetically disclosed buy/sell transactions in our consolidated statements of operations in the first quarter 2006. EITF 04-13 will reduce gross revenues and purchases and will not have a material impact on our financial position, net income, or liquidity. The treatment of buy/sell transactions under EITF 04-13 will reduce the relative amount of revenues on our income statement.

Note 14—Subsequent Events

On April 18, 2006, we closed the acquisition of 100% of the equity interests of Andrews Petroleum, Inc. and Lone Star Trucking, Inc. for a total purchase price of approximately $205 million and transaction costs of approximately $8 million.

Also in April 2006, we announced that in three separate transactions we had entered into definitive agreements to acquire certain crude oil pipelines and gathering and transportation assets as well as a natural gas storage facility for aggregate consideration of approximately $130 million, including approximately $36 million of crude oil and natural gas inventory. These transactions included (i) the purchase of an additional 9.5% interest in the Mesa Pipeline System, which is operated by us, (ii) the purchase of crude oil gathering and transportation assets and related contracts in South Louisiana and (iii) the purchase by a subsidiary of PAA/Vulcan Gas Storage, LLC of the Kimball natural gas storage facility, which is located in close proximity to PAA/Vulcan’s Bluewater gas storage facility in Michigan. We own a 50% interest in PAA/Vulcan. All of these transactions have closed as of the filing date of this document.

Effective May 1, 2006, we have entered into a five-year agreement with a third party marine towing company to time-charter 22 inland tugboats and 22 tank barges. Annual charter costs will be approximately $17 million, subject to escalation limited by the increase in the Producer Price Index—Finished Goods.

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