UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported)—October 27, 2005

Plains All American Pipeline, L.P.

(Exact name of registrant as specified in its charter)

 

333 Clay Street, Suite 1600, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)

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

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

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

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

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

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

Item 9.01.  Financial Statements and Exhibits

(c)   Exhibit 99.1—Press Release dated October 27, 2005

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

Plains All American Pipeline, L.P. (the “Partnership”) today issued a press release reporting its third quarter 2005 results. We are furnishing the press release, attached as Exhibit 99.1, pursuant to Item 2.02 and Item 7.01 of Form 8-K. Pursuant to Item 7.01 we are updating certain aspects of our previous guidance for financial performance for the fourth quarter and full year of calendar 2005 and are providing preliminary guidance for calendar 2006. In accordance with General Instruction B.2. of Form 8-K, the information presented herein under Item 2.02 and Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.

Update of Fourth Quarter and Full Year 2005 Guidance

EBIT and EBITDA (each as defined below in Note 1 to the “Operating and Financial Guidance” table) are non-GAAP financial measures. Net income and cash flows from operating activities are the most directly comparable GAAP measures to EBIT and EBITDA. In Note 11 below, we reconcile EBITDA and EBIT to net income for the guidance periods presented. However, it is impractical to reconcile EBIT and EBITDA to cash flows from operating activities for forecasted periods. We also encourage you to visit our website at www.paalp.com, in particular the section entitled “Non-GAAP Reconciliation,” which presents a historical reconciliation of certain commonly used non-GAAP financial measures, including EBIT and EBITDA. We present EBIT and EBITDA because we believe they provide additional information with respect to both the performance of our fundamental business activities and our ability to meet our future debt service, capital expenditures and working capital requirements. We also believe that debt holders commonly use EBITDA to analyze partnership performance. In addition, we have highlighted the impact on EBITDA, Net Income and Net Income per Limited Partner Unit of our long-term incentive program, revaluations of foreign currency and, to the extent known, gains and losses related to SFAS 133 (primarily non-cash, mark-to-market adjustments).

The following guidance for the three months and the twelve months ending December 31, 2005 as well as the preliminary guidance for calendar 2006 is based on assumptions and estimates that we believe are reasonable given our assessment of historical trends, business cycles and other information reasonably available. However, our assumptions and future performance are both subject to a wide range of business risks and uncertainties so no assurance can be provided that actual performance will fall within the guidance ranges. Please refer to the information under the caption “Forward-Looking Statements and Associated Risks” below. These risks and uncertainties, as well as other unforeseeable risks and uncertainties, could cause our actual results to differ materially from those in the following table. The operating and financial guidance provided below is given as of the date hereof, based on information known to us as of October 26, 2005. We undertake no obligation to publicly update or revise any forward-looking statements.

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

(1)    The projected average foreign exchange rate is $1.20 CAD to $1 USD.

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Notes and Significant Assumptions:

1.                 Definitions.

 

2.                 Pipeline Operations.  Pipeline volume estimates are based on historical trends, anticipated future operating performance and completion of organic growth projects. Volumes are influenced by temporary market-driven storage and withdrawal of oil, end-user refinery maintenance schedules, field declines and other external factors beyond our control. Actual segment profit could vary materially depending on the level of volumes transported.

         The following table summarizes our pipeline volumes and breaks out the major systems that are significant either in total volumes transported or in contribution to total revenue less purchases and related costs.

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

(2)    The aggregate of 11 systems in the West Texas / New Mexico area.

(3)    The aggregate of 8 systems.

(4)    Mid-point of estimate.

Segment profit is forecasted using the volume assumptions in the table above priced at tariff rates currently received, with adjustments where appropriate for estimated escalation in certain rates as allowed by contractual terms, less estimated field operating costs and G&A. Our forecast for variable operating expenses incorporate an estimate for higher fuel and power costs related to the impact of Hurricanes Katrina and Rita. Field operating costs do not include depreciation. To illustrate the impact volume changes may have on segment profit, the following table provides a volume sensitivity

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analysis of three systems representing approximately 30% of total pipeline revenues less purchases and related costs.

 

3.           Gathering, Marketing, Terminalling and Storage Operations. The level of profit in the GMT&S segment is influenced by overall market structure and the degree of volatility in the crude oil market as well as variable operating expenses. Our forecast for variable operating expenses incorporate an estimate for higher fuel and power costs related to the impact of Hurricanes Katrina and Rita.

(1)            Mid-point of estimate.

Segment profit is forecasted using the volume assumptions stated above and estimates of unit margins, field operating costs, G&A 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. Based on our mid-point projected segment profit per barrel for the fourth quarter of 2005, a 15,000 Bbl/d variance in lease gathering volumes would impact segment profit by approximately $3.9 million on an annualized basis. A $0.01 variance in the aggregate average per-barrel margin would impact segment profit by approximately $2.4 million on an annualized basis.

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

5.                 Foreign Currency Revaluations and Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133).  The guidance presented above does not include assumptions or projections with respect to potential gains or losses related to foreign currency revaluations and 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 foreign currency revaluations and derivatives (primarily mark-to-market adjustments) could cause actual net income to differ materially from our projections.

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6.                 Acquisitions and Capital Expenditures.  Although acquisitions constitute a key element of our growth strategy, the forecasted results and associated estimates do not include any assumptions or forecasts for any material acquisition that may be made after the date hereof. Capital expenditures for expansion projects are forecast to be approximately $170 million during calendar 2005. Following are some of the more notable projects to be undertaken in 2005 and the estimated expenditures for the year.

 

During the nine months ended September 30, 2005, approximately $107 million of the forecasted $170 million of expansion capital was incurred.

Capital expenditures for maintenance projects are forecast to be approximately $17 million during 2005, of which approximately $12 million was incurred in the first nine months.

7.                 Capital Structure.  The guidance is based on our capital structure as of October 2005.

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

Calendar 2005 interest expense is expected to be between $59.9 million and $60.3 million, assuming an average long-term debt balance of approximately $960 million and an all-in average rate of approximately 6.3%. Included in the effective cost of debt are not only current cash payments, but also commitment fees, amortization of long-term debt discounts, 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 Merchantile Exchange margin deposits). Although interest on floating rate debt is based on a forward LIBOR index curve of approximately 4.2%, currently 100% of our projected average long-term debt balance has an average fixed interest rate of 6.0%. The amortization of deferred amounts associated with terminated interest rate hedges results in a non-cash component to interest expense of approximately $1.6 million per year (approximately $400,000 per quarter). Approximately 70% of the non-cash interest expense amounts will be completely amortized by the fourth quarter of 2006. The remainder will be amortized over the next eleven years.

Interest expense does not include interest on borrowings for contango inventory. We treat these costs as carrying costs of the crude and include it as part of the purchase price of the crude.

Long-term debt at December 31, 2005 is projected to be approximately $950 million.

9.                 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. Under Emerging Issues Task Force Issue 03-06: Participating Securities and the Two-Class Method under FASB Statement No. 128 (“EITF 03-06”), when the Partnership’s aggregate net income exceeds the

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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. Although EITF 03-06 does not impact overall net income or other financial results of the Partnership, for periods in which aggregate net income exceeds the aggregate distributions for such period, earnings per limited partner unit will be reduced. The following table sets forth the computation of basic and diluted earnings 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 $2.70 per unit, our general partner’s distribution is forecast to be approximately $22.7 million annually, of which $18.7 million is attributed to the incentive distribution rights. The relative amount of the incentive distribution varies directionally with the number of units outstanding and the level of the distribution on the units. For distribution rates where EITF 03-06 does not apply, each $0.05 per unit annual increase in the distribution over $2.70 per unit, decreases net income available for limited partners by approximately $3.7million ($0.05 per unit) on an annualized basis.

10.          Long-term Incentive Plans.  The majority of phantom unit grants outstanding under our 1998 and 2005 Long-Term Incentive Plans contain vesting criteria that are based on a combination of performance benchmarks and service period. The phantom units under the 2005 plan generally vest on the later of 2 years, 4 years or 5 years, or achievement of annualized distribution levels of $2.60, $2.80 and $3.00 per unit, respectively, and the majority of the phantom units have a final service period vesting in 2011. In addition to exceeding the distribution level of $2.60, it has been deemed probable that the $2.80 distribution level will be reached. Accordingly, guidance includes, for phantom units tied to the $2.60 and $2.80 performance levels, an accrual over the corresponding service period. For the phantom units that vest when the $3.00 performance threshold is achieved but have a final service period vesting in 2011, guidance includes a pro rata accrual associated with a six-year service period. For 2005, the guidance includes approximately $23.8 million of principally non-cash expense associated with these phantom units. The actual amount of LTIP expense amortization in any given

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year will be directly influenced by fluctuations in our unit price and the amount of amortization in the early years and will also be increased if a determination is made that achievement of any of the remaining performance thresholds is probable.

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

 

Preliminary 2006 Guidance

This preliminary adjusted EBITDA guidance for 2006 is based on continued operating and financial performance of our existing assets under normalized market conditions, continuation of current pipeline shipments and anticipated natural field declines. In that regard, we would expect daily pipeline shipments to average approximately 270,000 Bbl/d for Basin, 48,000 Bbl/d for All American and 135,000 Bbl/d for Capline. Similarly, we would expect gathering and marketing volumes to average approximately 675,000 Bbl/d, and that realized margins would be consistent with historical results generated from oil price volatility experienced over the longer term rather than the price volatility experienced to-date in 2005.

The following table summarizes the range of selected key financial data of our preliminary sustainable projections for calendar year 2006.

Preliminary Calendar 2006 Guidance (in millions)

 

Our preliminary guidance for interest expense is based on our projected capital structure as of December 31, 2005, the current market outlook for floating interest rates and approved capital projects for 2006. Our preliminary guidance for depreciation and amortization is based on projected depreciation from our present asset base, and approved capital projects for 2006. Our preliminary guidance for maintenance capital expenditures is based on our estimated level of recurring expenditures of approximately $20 million, increased by approximately $3 million of carryover expenditures from 2005. We are currently in the process of reviewing and completing our capital program for 2006 and any increase in projected expansion or maintenance capital may increase our forecast for projected interest expense, depreciation and amortization, and maintenance capital expenditures. The potential effects of any gains or losses from Foreign Exchange Revaluations and SFAS 133 (see Note 5 above) are not included in the guidance for 2006.

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Forward-Looking Statements and Associated Risks

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

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

·       the success of our risk management activities;

·       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;

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

·       maintenance of our credit rating and ability to receive open credit from our suppliers and trade counter-parties;

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

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

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

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

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

·       interruptions in service and fluctuations in rates of third party pipelines;

·       the effects of competition;

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

·       the impact of crude oil and natural gas price fluctuations;

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

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·       shortages or cost increases of power supplies, materials or labor (including the direct and indirect effects of Hurricanes Katrina and Rita on the availability of materials, the cost of natural gas and the demand for oilfield services);

·       weather interference with business operations or project construction, including the continued impact of hurricanes Katrina and Rita;

·       the currency exchange rate of the Canadian dollar;

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

·       general economic, market or business conditions; and

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

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

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Exhibit 99.1

 

FOR IMMEDIATE RELEASE

Plains All American Pipeline, L.P. Reports
Strong Financial Results for Third Quarter 2005—
Net Income Up 65%; Net Income Per Unit Up 34%;
EBITDA Up 47%

(Houston—October 27, 2005) Plains All American Pipeline, L.P. (NYSE: PAA) today reported net income of $69.0 million, or $0.79 per diluted limited partner unit, for the third quarter of 2005. These financial results represent an increase of 65% and 34%, respectively, over net income of $41.7 million, or $0.59 per diluted limited partner unit, for the third quarter of 2004. For the first nine months of 2005, the Partnership reported net income of $164.1 million, or $2.07 per diluted limited partner unit, an increase of 56% and 31%, respectively, over net income of $105.3 million, or $1.58 per diluted limited partner unit, for the first nine months of 2004.

As reported, earnings before interest, taxes, depreciation and amortization (“EBITDA”) for the third quarter of 2005 were $104.6 million, an increase of 47% as compared with EBITDA of $71.2 million for the third quarter of 2004. EBITDA for the first nine months of 2005 was $267.0 million, an increase of 46% as compared with EBITDA of $183.4 million for the first nine months of 2004. (See the section of this release entitled “Non-GAAP Financial Measures” and the attached tables for discussion of EBITDA and other non-GAAP financial measures, and reconciliations of such measures to the comparable GAAP measures.)

“Plains All American reported strong operating and financial results for the third quarter of 2005 and continued the Partnership’s year-to-date record financial performance,” said Greg L. Armstrong, Chairman and CEO of the Partnership. “These results were driven by solid performance from both our pipeline and our gathering, marketing, terminalling and storage segments and were achieved despite the adverse impacts of Hurricanes Katrina and Rita. The Partnership’s extensive asset base, proven business model and growing inventory of organic expansion projects continue to generate sustainable distributable cash flow growth.” Armstrong also noted that the Partnership continued to follow a disciplined financial growth strategy, as recent capital markets activities further improved its liquidity and financial flexibility and strengthened its overall capital structure.

Reported results include the impact of various items that affect comparability between reporting periods. Adjusting for selected items impacting comparability, the Partnership’s third quarter 2005 adjusted net income, adjusted net income per limited partner unit and adjusted EBITDA were $71.1 million, $0.95 per diluted unit, and $106.6 million, respectively. Similarly, the Partnership’s third quarter 2004 adjusted net income, adjusted net income per limited partner unit and adjusted EBITDA were $38.1 million, $0.53 per diluted unit, and $67.6 million, respectively. On a comparable basis, third quarter 2005 adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA increased 86%, 78% and 58%, respectively, over third quarter 2004.

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The following table summarizes selected items that the Partnership believes impact the comparability of financial results between reporting periods:

Note: Figures may not sum due to rounding.

⁽¹⁾                 For the third quarter and nine month period ended September 30, 2005, the Partnership’s net income exceeded the cash distribution paid during such periods, which required the application of Emerging Issues Task Force Issue No. 03-06: “Participating Securities and the Two-Class Method under FASB Statement No. 128” (“EITF 03-06”). This theoretical calculation does not impact the Partnership’s aggregate net income or EBITDA, but does reduce the Partnership’s net income per limited partner unit. The application of EITF 03-06 negatively impacted basic and diluted earnings per limited partner unit by $0.13 and $0.12 for the third quarter and first nine months of 2005, respectively.

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The following table presents certain selected financial information by segment for the third quarter reporting periods:

⁽¹⁾                 Includes intersegment amounts.

⁽²⁾                 Segment general and administrative expenses (G&A) reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

⁽³⁾                 Amounts related to SFAS 133 are included in revenues and impact segment profit. The SFAS 133 mark-to-market adjustment is primarily based upon crude oil prices at the end of the period and is related to the non-effective portion of our cash flow hedges, as well as certain derivative contracts that do not qualify under SFAS 133 as cash flow hedges. The net gain or loss related to these derivative instruments is principally offset by physical positions in future periods.

⁽⁴⁾                 Gains/losses on foreign currency revaluation are included in the Gathering, Marketing, Terminalling & Storage segment.

Excluding selected items impacting comparability in both periods, segment profit from pipeline operations in the third quarter of 2005 was $49.4 million versus $44.0 million for the third quarter of 2004 on average daily pipeline volumes of 1.8 million barrels per day versus 1.6 million barrels per day. Third quarter 2005 pipeline segment profit was reduced by approximately $3.0 million due to market rate adjustments made by the Partnership to tariffs on certain pipelines formerly owned by Link Energy. As a result of these lower tariffs on barrels shipped by PAA in connection with its gathering and marketing activities, segment profit from gathering, marketing, terminalling and storage was increased by a comparable amount. Excluding selected items impacting comparability in both periods, segment profit

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from gathering, marketing, terminalling and storage operations was up approximately 144% over the corresponding period in 2004 as a result of favorable market conditions, including the continuation of a prolonged contango price curve with volatility, as well as the tariff adjustments noted above.

For the first nine months of 2005, the Partnership’s adjusted net income, adjusted net income per limited partner unit and adjusted EBITDA were $202.4 million, $2.73 per diluted unit, and $305.3 million, respectively. Similarly, the Partnership’s adjusted net income, adjusted net income per limited partner unit and adjusted EBITDA for the first nine months of 2004 were $107.9 million, $1.62 per diluted unit, and $186.0 million, respectively. On a comparable basis, adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA for the first nine months of 2005 increased 88%, 69% and 64%, respectively, over the first nine months of 2004.

The following table presents certain selected financial information by segment for the first nine-month reporting periods:

⁽¹⁾                 Includes intersegment amounts.

⁽²⁾                 Segment general and administrative expenses (G&A) reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

⁽³⁾                 Amounts related to SFAS 133 are included in revenues and impact segment profit. The SFAS 133 mark-to-market adjustment is primarily based upon crude oil prices at the end of the period and is related to the non-effective portion of our cash flow hedges, as well as certain derivative contracts that

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do not qualify under SFAS 133 as cash flow hedges. The net gain or loss related to these derivative instruments is principally offset by physical positions in future periods.

⁽⁴⁾                 Gains/losses on foreign currency revaluation are included in the Gathering, Marketing, Terminalling & Storage segment.

The Partnership’s basic weighted average units outstanding for the third quarter of 2005 totaled 68.0 million (69.4 million diluted) as compared to 65.8 million (65.8 million diluted) in last year’s third quarter. At October 24, 2005, the Partnership had approximately 73.8 million units outstanding. At September 30, 2005 the Partnership had long-term debt of $952.4 million and a long-term debt-to-total capitalization ratio of approximately 42%.

On October 25, 2005, the Partnership declared a cash distribution of $0.675 per unit ($2.70 per unit on an annualized basis) on its outstanding limited partner units. The distribution will be paid on November 14, 2005, to holders of record of such units at the close of business on November 4, 2005. The distribution represents an increase of 12.5% over the November 2004 distribution and approximately 3.85% over the August 2005 distribution. This represents the 13^th distribution increase for the Partnership in the last 19 quarters.

The Partnership today furnished a current report on Form 8-K, which included material in this press release and financial and operational guidance for the fourth quarter and full year 2005 and preliminary guidance for 2006. A copy of the Form 8-K is available on the Partnership’s website at www.paalp.com.

Non-GAAP Financial Measures

In this release, the Partnership’s EBITDA disclosure is not presented in accordance with generally accepted accounting principles and is not intended to be used in lieu of GAAP presentations of results of operations or cash provided by operating activities. EBITDA is presented because we believe it provides additional information with respect to both the performance of our fundamental business activities as well as our ability to meet our future debt service, capital expenditures and working capital requirements. We also believe that debt holders commonly use EBITDA to analyze Partnership performance. In addition, we present selected items that impact the comparability of our operating results as additional information that may be helpful to your understanding of our financial results. We consider an understanding of these selected items impacting comparability to be material to our evaluation of our operating results and prospects. Although we present selected items that we consider in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions and numerous other factors. These types of variations are not separately identified in this release, but will be discussed in management’s discussion and analysis of operating results in our Quarterly Report on Form 10-Q.

A reconciliation of EBITDA to net income and cash flow from operating activities for the periods presented is included in the tables attached to this release. In addition, the Partnership maintains on its website (www.paalp.com) a reconciliation of all non-GAAP financial information, such as EBITDA, that it reconciles to the most comparable GAAP measures. To access the information, investors should click on the “Investor Relations” link on the Partnership’s home page and then the “Non-GAAP Reconciliation” link on the Investor Relations page.