Plains All American Pipeline LP (PAA) 2005 Q1 法說會逐字稿

Welcome to Plains All American Pipeline's First Quarter 2005 Results Conference Call. During today's call, the participants will provide comments on the partnerships outlook for the future, as well as review the results of the prior period. Accordingly in doing so they will use words such as `belief`, `estimate`, `expect`, `anticipate`, etcetera. The law provides Safe Harbor protection to encourage companies to provide forward-looking information. The partnership intends to avail itself of those Safe Harbor provisions and directs you through the risks and warnings set forth in Plains All American Pipeline's most recently filed 10-K, 10-Q, 8-K, and other current and future filings with the Securities and Exchange Commission. In addition, the partnership encourages you to visit Plains All American website at www.paalp.com.

In particular the section entitled non-GAAP reconciliation which presents certain commonly used non-GAAP financial measures such as EBITDA and EBIT, which may be used here today in the prepared remarks or in the Q&A session. This section also presents a reconciliation of those non-GAAP financial measure and include a table of solicited items that impact comparability with respect to the partnerships reported financial information. Any reference during today's call to adjusted EBITDA, adjusted net income, and alike is a reference to the financial measure excluding the effect of selected items impacting comparability.

Today's conference call will be shared by Greg L. Armstrong, Chairman and CEO of Plains All American Pipeline. Also participating in the call are Harry Pefanis, Plains All American President and COO; and Phil Kramer, Plains All American EVP and Chief Financial Officer. I will now turn the call over to Mr. Greg Armstrong.

Thanks Alan. This morning the partnership reported excellent results for the first quarter. I believe it's fair to say there are business proceeding on all during the quarter, as we experienced higher than forecasted pipeline volumes, attract in marketing margins, and healthy contributions from our terminalling in storage assets. Adjusted EBITDA, adjusted net income, and adjusted net income for LP unit each met or exceeded the top end of the updated guidance range we provide on March 17, and significantly exceeded the original guidance range we provided on February 24.

Specifically, first quarter net income of 32.8 million or $0.43 per basic and diluted limited partner unit as compared to first quarter of 2004 net income of $27.9 million or $0.44 per basic and diluted limited partner unit. These results include the effects of selected items that impact comparability between the periods. The current year results were reduced by a total of 16.5 million of such items comprised of 2.2 million non-cash compensation expense chart, and approximate $800,000 loss on foreign currency reevaluation, and a $13.4 million non-cash mark-to-market loss associated with FAS 133.

Last year results by comparison include the 7.5 million non-cash, FASB 133 gain, which was offset by pre-items showing 7.8 million that reduced reported earnings, which resulted in negative impact for comparability purposes of approximately 300,000. As we discussed on our fourth quarter call, the compensation expense in this quarter, years quarter applicable performance related equity brands under a long-term incentive plan and it still will be discussed later in the call the majority of such counts are included in the unit count for all diluted unit measurements.

Adjusting for these selected items impacting comparability, adjusted EBITDA, adjusted net income, and adjusted net income for limited partner unit for the first quarter of 2005. So, 82.9 million, 49.3 million, and $0.67 per basic and diluted unit respectively, these results represent increases of 63%, 75%, and 51% respectively over the corresponding metrics in last year's first quarter. But almost in measure was a very strong if not exceptional quarter.

During the reminder of today's call, we will address four primary topics. First, Harry will briefly touch on first quarter performance drivers and market conditions and will also address the primary performance assumptions that drive the guidance that we'll cover with you later. Harry will also provide a status report on our expansion in organic growth projects, as well as recent acquisition activity. Secondly, we will discuss our capitalization liquidity and third Phil will provide you with financial and operating guidance for the second quarter, as well as the full year of 2005, and then lastly we'll provide some closing comments on our outlook and the current market environment.

For those listeners that are unfamiliar with our conference call procedures, we will have a question and answer period following our prepared remarks, and a complete written transcript of prepared comments will be posted on our website shortly after the completion of this call. With that introduction I will now turn the call over to Harry.

Thanks Greg. And as Greg, just mentioned I am going to give a brief review of performance drivers and market conditions that affected the first quarter performance. Also I will pitch you on our recent acquisition activities and our major projects, and our capital of program. Let me begin by pointing out that our strong performance in the first quarter of 2005 versus the first quarter of 2004 was in part due to our acquisitions. This year's first quarter included a full quarter of the Capline acquisition while last year's quarter only included 1 month of the Capline acquisition. In addition, we completed the acquisition of Link, the Cal Ven pipeline and the Schaefferstown propane storage facility, after the first quarter of 2004.

As Greg also mentioned in his opening remarks, we benefited from a very attractive alignment of market conditions and operating performance in the first quarter. The key factors that combined to create this environmental work, first, increased pipeline volumes are our major assets. Second, increased receipts of foreign crude oil movements at PAA facilities, and then thirdly favorable and volatile market conditions, that were characterize by fairly deep Contango market in the front month, and continued wide differential between grades. Since our March 17 guidance update was financial in nature, it did not contain revised operating metrics and performance drivers and my comments regarding first quarter segment performance will be as compared to the original guidance provided on February 24.

I will start with our pipeline segment. Pipeline segment profit excluding the LTIP charge was $51.4 million, compared to the high end of our original guidance range of 44.9 million. On a per barrel basis our segment profit was approximately $0.33 per barrel in the first quarter. The favorable variants of our guidance was primarily due to increased volumes on Capline and Basin systems and higher revenue attributable to the loss of a component of our . After the first quarter, volumes on Capline system were approximately 20,000 barrels per day, over our guidance volumes, and volumes from the Basin system was approximately 17,000 barrels a day, over the volumes we had used in our guidance. Note that the Capline system was not as negatively impacted by refinery turnarounds that we had previously expected. Actual volumes on some of our major pipelines here in the quarter include 54,000 barrels a day on the American system, 277,000 barrels per day on our share of the Basin pipeline system, 160,000 barrels per day on our share of the Capline pipeline system, and 69,000 per day on the pipeline system in Canada.

As the second quarter guidance still I will walk you through in a few minutes, incorporates volumes of approximately 54,000 barrels per day on the American system, 177,000 per day on our phase on Capline, and 292,000 barrels per day on our stake in the Basin system. Segment profit in our gathering marketing terminaling and stores segment for the first quarter excluding the selected items impacting comparability was approximately $31.5 million, compared to the high end of our original guidance of approximately $26.1 million. On the same basis our segment profitability was approximately $0.50 per barrel. Volumes in this segment were approximately 6000 barrels per day higher than guidance at approximately 706,000 barrels per day. In addition, we had approximately 63,000 barrels per day of foreign that we received into our Gulf Coast facilities during the quarter. As mentioned earlier the higher margins were due to the successful implementation of our hedging strategies in a contangled market. The wider than forecasted differentials and increasing volume of foreign crude delivered to our Gulf Coast facilities.

Our second quarter guidance incorporates gathering market and terminaling and stores volumes of approximately 654,000 barrels per day at an average segment profit of approximately $0.60 per barrel, at the net point. The crude oil least gathering volumes are forecasted to be above 630,000 barrels a day, which is slightly above the first quarter volumes. Our LPG volumes which are seasonal are expected to be approximately 24,000 barrels a day compared to approximately 84,000 barrels a day in the first quarter. Now the forecasted increase in our segment profit is primarily due to fact that the market is in a deeper contangle in the second quarter than it was in the first. And lastly, maintenance capital expenditures for the quarter were approximately $4 million. We do have several expansion, capital project in progress that I would like to briefly review with you. In late February, we completed the construction and put into service the 100 mile 16 inch pipeline that transports crude oil from Cushing, Oklahoma to Broom, Caney. The pipeline services the Coffeyville refinery and has capacity transport of 90,000 barrels a day of crude oil. The pipeline is subject to a long-term agreement that requires the owners of the Coffeyville refineries to meet minimum shipping requirements for the first 5 years is the agreement. In connection with this project, we also entered into a long-term terminaling arrangement at our Cushing terminal. The total cost for this project is in line with our previous estimate of approximately 45 million.

In October 2004, we began the expansion of the pipeline system in the Rocky Montain region. We will construct and operate approximately 32 miles of 8-inch main line and 10 and 70 miles of 6 inch and 4-inch gathering pipeline will connect over 75 liters to our existing pipeline gathering system. We estimate that this project will add an approximate 15 to 20,000 barrels a day of crude oil pipeline system. In exchange of capital commitment, we have received long-term reserve dedications from producers whose leases are being connected. Portions of this project have been completed with the operation during the end of the second quarter of 2005. Total cost of this project was approximately 28 to $30 million. We've recently approved AFB's totaling approximately $19 million to add an additional 70 miles of 6 inch and 4-inch gathering line, and add 17 miles of a new 10 inch loop to the main line of the gathering system. The main line will increase capacity from approximately 24,000 barrels a day to approximately 42,000 barrels a day, while the gathering system expansion will connect an additional 40 wells to assist it and will add approximately 10 to 12,000 barrels a day gathering volume.

In February of this year, we announced to start a phase 5 expansion of our Cushing Terminal, which involves the construction of approximately 1.1 million barrels of additional tankage. This project is supported by the overall growth of our business from terminal arrangement ended into the connection with the construction of the Cushing to main pipeline system. The phase 5 expansion project will actually expand the total capacity of the facility to approximately 7.4 million barrels and it is expected to cost approximately $13 million. The project is proceeding as planned, and we continue to believe the project will be operational from the fourth quarter of 2005. Earlier this month, we began construction of a fractionator in northwest Alberta. The complements of our existing assets and once completed in late 2005, the facility we have ability to process above 4000 barrels a day of natural gas liquid. This facility will also contain approximately 14,000 barrels of storage capacity. The total cost of the project is estimated to be $16 million. Since our last conference call, we made one small acquisition on our LPG business. In March, we announced the acquisition of Propane pipeline and Terminal from Koch. The acquired assets include a 130-mile pipeline originally at Koch's fractionator in Medford, Kansas and terminating at the top of the Oklahoma terminal. As the pipeline is capable of transporting about 10,000 barrels a day of Propane from Tulsa terminal, has a storage capacity of approximately 19,000 barrels. And before I turn the call back over to Bill, I'd like to let you know that we've added another proven industry veteran to our management team.

In February, Dan Nerbonne joined our senior management team as Vice President of Engineering. Dan comes to PAA, having spent 25 years in a pipeline industry with Shell and Texaco. It is well with PAA, Dan is responsible for our project implementation activity and has oversight of our maintenance activities, including our API 653, sourcing program and our pipeline integrity management program. PAA has grown over the past several years, reaching significant increase in internal project on an organic growth opportunity as well as an increase in efforts of quality, maintaining our integrity in compliance programs. We believe Dan will be a solid contributor to the Company and we're delighted to have him on board. With that I'd turn the call over to Phil.

My part of the call, I'm going to review our capitalization of liquidity at the end of the first quarter. In addition, I'll walk our updated financial guidance for this year, including guidance for the second quarter. On March 31, PAA had long-term debt outstanding of approximately $930 million with the equity of approximately 1 billion in long-term debt to total GAAP ratio of approximately 48%. Adjusting for the impact of selected items impacting comparability or adjusted EBITDA at interest coverage ratio for the first quarter was approximately 5.7 times. And on the same basis, our long-term debt to first quarter annualized EBITDA was approximately 2.8 times. Based on the mid point of our 2005 guidance and our projected year-end long-term debt balance, we believe we were in the year with the long-term debt to adjusted EBITDA ratio of approximately 3.2 times.

At quarter end, our outstanding long-term debt had an average life of approximately 7.5 years. We had a fixed and floating ratio of 87% fixed and 13% floating. I'd point out that the data in our Contango inventory facility is short term and comprise the vast majority of our short-term debt on March 31. We also classify a short-term the borrowings in our long-term revolver for NYMEX margins in storage and hedged inventory not borrowed done in the Contango inventory facility because of the level of inventory stored at March 31 borrowings under the long-term revolver classified as current were approximately 130 million at that day, which is a higher number than normal. Borrowings under the contango facility of March 31 for 425 million. The borrowings for crude oil stored are self-liquidating, which means that the borrowings repaid when the proceeds are received from the sale of the hedged crude oil. Because of this, our banks and we do not include the short-term borrowings in our credit metrics whether they are borrowed under our long-term revolver or the contango facility. The same reason, our short-term debt is high at quarter end is the same reason our cash flow from operating activities is a negative number for the first quarter. This actually maybe more than any of you want to know about accounting but here goes an explanation. A backward market the purchase of sale of crude oil occurred during the same month with payment collection both occurring in the next month.

Thus the only impact that this has on our operating cash flow is the margin generated by this activity. It is different when we purchase crude oil for storage in the contango market. Essentially, purchases in crude oil for storage have captured this operating activity and have a negative impact in the cash flow statement when we invoice for the crude's pay. Policies we received from our credit facilities to pay for the crude oil was stored and shown as financing activities in the cash flow statement. As such, until we delivered the crude and received payment from our customers, operating activities in the cash flow statement would be negatively impacted by this activity. Conversionally, when we come out of contango and collect on the several crude, operating activities will be positively impacted by the amount of the sales. This has caused fluctuations in our cash flow stated in the past and certainly not mere as large as the first quarter for that reason received for the accounting last year.

Moving on, we completed several financing transactions over the last several months. First, in late February we sold 575,000 common units to an affiliate of Vulcan Energy Corporation in a private placement at 38.13 per unit. Including the general partners proportionate capital contribution, expenses related to the offering the partnership relies net proceeds approximately $22.3 million. The price we received for the units represented a 2.8% discount to the previous day's closing price and a 2.4% discount to the average price for trailing 10-day period. Both of which compare very favorably to the aggregate discount typically experienced on the public offering. The place that was auctioned has taken track with both parties. Second, earlier this month, we increased the capacity our uncommitted contango facility to $500 million. As we mentioned last month -- last quarter and evidenced during the first quarter, there are several factors that are driving the increased need for capacity into this facility. Tank capacity has increased as a result of recent acquisitions and our ongoing expansion at our Cushing terminal. Second, the absolute price level of a barrel of crude oil has continued to increase. Fairly, the last factors that increase in our purchases of amount of crude oil that needs to destroy that crude in the anticipated continued expansion of that activity.

Greg will address some of the big pictures, which prompted us to proactively expand our liquidity later in the call. But I wanted to be sure and make the point that our management team, Board of Directors, and owners of our general partner, are all committed to maintain a solid investment great capital structure and associated credit bankers. Accordingly, we are proactive about taking the steps to maintain excellent financials strength and present levels of liquidity in a dynamic crude oil environment. Given the relative magnitude of SFAS 133 charged this quarter, I would briefly like to remind you how it works and why we spiked it out as an item impacting comparability. SFAS 133 requires the changes in from its fair value we recognize currently in earnings unless specific cash flow hedge accounting criteria met. In which case changes in current value are deferred to other comprehensive income or OCI. And we classified in the earnings when the underlined transaction affect earnings. Accordingly, changes in current value including earnings in the current period for one, derivatives characterizes fair value hedges, two, derivatives that do not qualify for hedge accounting, and then three, the portion of cash flow hedges that is not highly effective and offsetting changes in cash flow as hedged items. We believe that the majority of these instruments we require to mark to market at the end of each quarterly period presume to SFAS 133 serve as economic hedges even though they do not need SFAS 133 hedge definition requirements and that they offset future fiscal positions or anticipate a cash flow related to our assets attributable to the future period. Almost all of our derivative transactions fall under our enterprise level program, which has the objective of hedging exposures arising from our core business.

Therefore, we believe the market-to-market adjustments to net income required under SFAS 133 do not provide a complete of the economic substance of the transactions. As these adjustments represent only the real side of these transactions and do not take into account the offsetting fiscal position or cash flow exposure associated with our assets. In addition, the impact vary from quarter to quarter based on market prices at the end of the quarter which were impossible for us to control our forecast and SFAS 133 adjustments will be negated by offsetting danger losses on the underlying fiscal transaction or cash flow of the asset in future periods. The extend of the offset will depend on multiple factors including the price indices of underlying contraction hedges, utilization of our assets, and various other factors. Accordingly, when we evaluate our results internally for performance against our expectations of the guidance and trend analysis, we exclude this non-cash market-to-market impact under SFAS 133.

Now, I am going to shift this discussion of our financial guidance. Our guidance is based on the current state and our outlook for the market, reasonable expectations of volumes and expense level as well as our judgments and assumptions about the potential associates with our business development activities, where the outcome is less than started at this point including estimate and contributions from recent acquisitions. For the second quarter of this year, we would guide you to an adjusted EBITDA range of 82 million to 90 million. That's a mid point of 86 million. We estimate the second quarter G&A should come in approximately 22.8 million and $24 million. For interest expense purposes, we anticipate average long-term debt balances of approximately 960 million resulting in interest expense of 14.5 to 14.9 million, weighted average interest rate of approximately 6.1% including our fixed rate debt, commitment fees, amortization of long-term debt premiums and discount, and deferred amounts associated with terminated interest rate basis. Approximately 400,000 of second quarter projected interest expense is non-cash as it relates to the amortization of deferred amounts associated with the terminated hedge. I would also remind you that for matching purposes, interest cost that we incurred on short-term related borrowings has net debt against the profits we relies on storing the crude and is therefore included in the determination of gross profits in our gathering market determining store segment.

In other words, it doesn't reflect as interest expense. Finally, we estimate depreciation and amortization to be approximately 18.8 million to 19.1 million. Based on these estimates, we forecast adjusted net income 48 to 56.7 million or approximately $0.63 to $0.75 per diluted units. In our 8-K this morning, we also mentioned our guidance for the full year 2005 primarily to take into account the strong performance for the first quarter and the anticipated performance for the second quarter. We will now guide you to an adjusted EBITDA range for this year of 310 million to 325 million. The mid point of 317.5 million represents an increase of approximately 25% above of 2004 adjusted EBITDA and its approximately 13% higher than the mid point of this year's guidance that we provided at the beginning of this year. While we have opted very good start for this year, second quarter looks promising as well. Our updated full year guidance does take into account for cyclical nature of the crude oil industry, the significant amount of time remaining in this year and the uncertainties inherent in projecting future performance. All of these measures and metrics excludes selected items impact in .

We expect G&A for 2005 to be in the range of 91.4 million to 94 million. Annual depreciation and amortization expenses expected to range from $76.7 million to $77.7 million. Interest expenses is expected to range from 61.3 to 62,3 million and is based on weighted-average of long-term debt balance for the year approximately 990 million and weighted-average interest rate of approximately 6.2%. Our weighted-average interest rate for the year also includes the various components I mentioned a moment ago. Approximately 1.6 of this year's projected interest expenses non-cash as it relates to the amortization of deferred amount associated with the terminated interest rate hedges. As I mentioned earlier, these interest expense computations exclude interest cost are already taken into account in the forecast of segment profits. Based on these estimates, we forecast adjusted net income of 170 million to 187 million for the year adequate to $2.22 to $2.46 per diluted units. As we have in the past, we emphasize that our total net income for the partnership is not impacted by change in our annualized cash distribution level, the relative allocation of net income between limited partners to the general partners and therefore the net income per unit is impacted by such a change. For as long as we are in the 25%, that is in a split level, a $0.05 increase in annualized distribution per unit roughly equates to the $0.02 annualized decrease and net income per .

The guidance that I have just provided does not include the impact of any financial or accounting items that again impact comparability of results between current periods such as SFAS 133. In the 8-K filed this morning, we detailed one such potential item that could impact the second quarter, which is our long-term incentive plan. In fact, I hate to do this, talk about accounting, but I am going to spend a few minutes to address the accounting for the long-term equity incentive plans. Substantially, all of the performance benchmarks associated with equity incentive awards granted in connection with the partnerships initial public offering in 1998 and the separation transaction from plaint resources in 2001 have been achieved and reflected in our previous financial results. Over that aggregate time period, we met all this four nation test and increased the distribution of approximately 42%. Following approval of a new equity incentive plan at the January 2005 unit holders meeting, the Board of Directors approved the new round of equity incentive awards. These equity grants established new performance benchmarks that with few exceptions are tied to a six-year service period and also provide for accelerated best team if targeted distribution levels are achieved and a minimum service period is satisfied.

Accordingly, the overall service period extends to 2011 and accelerated vesting is tied to achieving distribution levels of $2.60, $2.80 and $3 per unit, for minimum service periods that will be met in 2007, 2009, and 2010 respectively. For accounting purposes, the grants are treated as three different tranches with each tranche associated with a performance threshold and a minimum service period. If the determination has not been made, that achievement of the next performance threshold is probable and all three tranches are amortized on a straight-line basis over 6 years. That was the case of beginning of the year when we prepared our 2005 guidance and they are solely upon a 6-year service period and a unit price of around $39 per unit, we projected in an accrual for 2005 of approximately $10.4 million. However, if the determination is made that achievement of one or more performance threshold is probable, then the value associated with that tranche is amortized over much shorter period of time, which is equivalent to the minimum service period for that particular tranche.

Given the strong first quarter performance, the revised outlook for the second quarter and remainder of the year and the recent increase in the distribution to $2.55 per unit, a determination was made at the end of the first quarter that achievement of the $2.60 per unit threshold is now probable. As a result, it accelerates the expense of the first tranche from being amortized to mid-2011 obviously, a 6-year period to being amortized in mid-2007, which is a 2-year period. That's why along with an increase in the market value per units, we are forecasting the increase for the remainder of the year. One exception to the accounting treatment that I just discussed is associated with the equity incentives awarded to Greg as the CEO, and Harry as our COO. In that particular case, there was no 6-year vesting period. Instead their awards only vest if we are successful on achieving the performance threshold. If we do not, the applicable equity incentives expire worthless in 2011. For that reason, their equity awards are not included in the 6-year straight line amortization and they only impact the income statement, and if a determination is made that it is probable, the partnership will achieve the applicable performance threshold.

Based on the outlook of achieving the distribution level of $2.60 per unit is probable, we now forecast an accrued expense of approximately 19 million for this year of which approximately 6 million will impact the second quarter. As we have in the past, we have spiked up these non-cash charges and included them in the selective items impacting comparability. We believe that is the appropriate treatment as part of this 75% incrementing units associated with the incentive equity awards and any related expenses are already included in the determination of diluted units that reflect the ongoing cost to the partnership once such occurs. The remaining 25% of the units which are those granted to Greg and Harry, will only become part of the diluted unit calculation when the actual thresholds are reached. Until that time the possibility exists that they were never vest and instead expire worthless.

Finally, these charges are non-cash accounting tools and assuming that we achieved the highest performance threshold of $3 per unit, the 1.9 million aggregate units issuable upon investing of the currently outstanding equity in represent an approximate 2.8% dilution to our existing 67.9 million units outstanding that will be experienced in stages in 2007, 2009 and 2010. Finally, consistent with past practice, we do not attempt to forecast any potential impact related to SFAS 133. This way again we have no way to control our forecast crude oil prices on the last day of each quarterly period. Accordingly, the guidance is provided for this year including the second quarter excludes any potential gains or losses associated with our accounting pronouncement as well as other minor items that affect comparability between the periods. And for more detail on the projections as well as other assumptions, we would direct you to the 8-K that we furnished this morning. And with that, I will now turn the call back to over to Greg.

Before I open the call up for questions, I want to stand just a few moments to address three additional items and then make a few comments about the first quarter and our outlook for the balance of the year. First our strategic initiative to establish a meaningful role in the importation of foreign crude oil throughout the Gulf Coast area is advancing well. As a result of integrating our assets from various acquisitions completed in the last two and a half years, we are now able to physically move a barrel of oil and crude oil on PAA-owned asset all the way from the discharge point in our Mobile Bay facility, West along our Liberty pipelines to an air with Capline and then move the crude oil north on our Capline based refineries in the Midwest. This link gives us an excellent opportunity to provide our Midwest refinery customers with a diverse range of foreign crude oil supply alternatives. These capabilities are highlighted by our subsequent progress.

During the first quarter, we successfully discharged volumes from 13 vessels and average volumes exceeded 60,000 barrels per day. It is too early in the process to determine if the high-leveled activity is sustainable, but without question the early indications are encouraging. In addition, we very much believe that this activity will serve to offset domestic production declines and proactively enhance the utilization of our asset base. The second item is that on our third quarter earnings call in October of 2003, some nearly a year and a half ago, we shared with you our views on the medium to long-term dynamics in the crude oil industry. Specifically, we foretold of an increasingly more volatile market that would be sudden to more frequent short-term swings and market prices and shifts in market structure and that we believe such market conditions will play to the strength of our asset base and business model. Over the last seven months alone, crude oil prices ranged from a low of around $40 per barrel to high of approximately $58 per barrel. During that same time period, the spread between the futures contracts in the first two months ranged from nearly $1 back related to as much as $1.90 per barrel contango. In addition to the tight supply and demand relationship, the industry has been experiencing strong fund flows into the energy sector which are driven by a variety of factors, including international tensions and developments and attractive investment returns generated by commodities funds.

As a result, there is currently a sizable non-commercial or paper presence in the crude oil markets. How long these fund managers decide to remain invested and what happens when they decide to exit the market is anyone's guess, but is likely to exacerbate the outright price movements as well as the overall market structure. The third item I want to address is that we do not believe that anyone really know where the price of crude oil is headed or whether the market structure will stay in contango, revert to backwardation or simply vacillate between the two types of market structure. In our opinion, the aggregate influence of these crude oil market conditions suggest that hidden volatility is here to stay for the foreseeable future. As a result, we believe it is very possible for crude oil prices to spike upward by as much as $25 per barrel and even spike down perhaps as much as 15 to $25 per barrel. In this type of supply and demand environment to the extent one of those scenario has happened, we believe it only increases the likelihood that the other scenario will happen and may will amplify the magnitude of any fluctuation. With that in mind, we believe that all companies including our sales should be prepared for continued volatility with a bias for higher prices than we are currently experiencing. In that regard we intend to take pro-active steps to increase our liquidity and ensure that we are positioned to prudently optimize the use of our asset base in the event process do indeed increase to as high as 75 or even $80 per barrel while at the same time continuing to capitalize on containing those storage opportunities. These steps may include one or more of the following actions; increase in the size of our hedged inventory facility, excess in long-term debt capital markets and thus increasing the availability and our outstanding credit facility, as well as expanding our capacity and our corporate evolvers and even placing strategic levels of that.

These types of steps would position us to utilize all the tools in our tool box in our extensive asset base in order to both protect and enhance our marketing margins and capture incremental profit opportunities for our stakeholders through container transactions. Even though these steps may prove unnecessary, we prefer to be proactive rather than reactive to the actions as these actions also ensure that we continue to maintain very prudent levels of liquidity, excellent financial strength, and a very solid credit profile. We believe this type of forward thinking will also distinguish PAA in the eyes of our customers and the financial markets during volatile times in the market. Before I leave that topic, our efforts over the last couple of months have also focused in on running scenarios just to how this type of volatility will affect our counter parties. As a result, we believe we are well versed in the potential issues that can arise with respect to extending or receiving open credit in the market that either increases or decreases by $25 per barrel.

And then lastly before I open the call up for questions, I just want to say a few words on our year-to-date performance. As has become our practice at the beginning of the year, we share with you our four specific goals for 2005, suffice it to say that while it is still pretty early in the year, we are off to an excellent start and we are confident that we are well positioned to achieve these goals. We believe our first quarter performance demonstrates our ability to not only withstand but also profit from the cyclical and volatile nature of accrual market. This ability is derived from the fact that we own substantial infrastructure assets like pipelines and tunnels that connect and support major crude oil market locations which would ultimately be the end user, which is our refinery customer. Our assets represent crucial transportation North American crude oil markets and play a vital role in keeping our economy moving. By combining our strategically located asset base with our market knowledge and significant capital base, we believe we are well positioned to continue our track record of increasing distributions to our unit holders.

That wraps up the items on our agenda. I would like to thank you for your participation in today's call. We also look forward to updating our progress at the end of the second quarter. For those who joined us late a written transcript of the prepared comments for this call will be posted on our website www.paalp.com very shortly after this call. Alan, at this point in time we are ready to open it up for questions.

[OPERATOR INSTRUCTIONS] Sam Arnold, Friedman, Billings, Ramsey.

Good morning guys. I was wondering if you could just comment a little bit, you know, longer term strategy with the imports coming from the Gulf of Mexico and how you see that being played off against the heavy increase in Canadian oil fields coming down into the US and some of the pipeline reversals that would basically be heading maybe through back down towards the coast?

Basically we are sitting here in an environment where you have got additional Canadian crude that is probably going to be available in 2007-2008 timeframe using, some of the pipelines being reversed, but at the same time you've got increasing Gulf of Mexico production and you have increasing production worldwide to come into this market, you have got increasing refining requirements, defining domestic production. So, there will be sort of a battle of crude moving from North and South and probably we get to the impact of differentials, but we see increasing movements from Canada into the US and we see increasing movements from Gulf coast facilities into the mid continent as well.

Sam, I would add, if you go back and look at our conference call straight back from October of 2003, you know, we kind of gave a forewarning of that very dynamic that Harry was talking about. We've already seen an increase in Canadian crude today since that time as well as in the Gulf of Mexico and clearly we are seeing huge differentials now in the various grades and that is partly because even though -- while crude is viewed as a commodity it is not completely fungible and very certain refineries in the upper mid west can only burn a particular type of crude while there is a wealth of capacity in the Gulf -- Mexico area refineries that can burn various types of goods. So, you actually are going to see probably at some point imports going up in the markets that if crude was fungible, could be served by the Canadian markets because of the quality limitations, you know, the Canadian crude is going to be coming farther south. What happens over the next three to five years with respect to Canadian crude and there are efforts to get crude moved from Canada to the West Coast, which is presumably going to be targeted towards China will also have an influence on those dynamics as Harry just mentioned. And finally, PAA is amid positioning now, the fact that we can seamlessly move a barrel from our Mobil Bay facility on our liberty pipeline to Capline. We are currently running at about a 160,000 barrels a day of capacity on that pipeline and we have an incremental 90,000 barrels a day of availability without having to spend anymore money. So, we like the markets, we've set ourselves up to benefit, and I think we are just kind of having a good time right now watching the dynamics play out.

Very good. Are you guys actively participating in discussing with refiners, kind of your plans and capabilities and I'm sure they are aware of it because in Midwest, refiners are going to have to start answering that question as well. You know, you are going to see the Lima refinery, Premcor, now Valero starting to get upgraded to be able to handle some of the heavy crude and have you guys been talking with other refiners and letting them know that you do have this capacity and converting to heavy isn't necessarily the best option or you are at least having those discussions with them?

I would say it's safe to assume that the dialogue is constant and ongoing between refiners and service providers such as ourselves and of course they are also working with producers in Canada, and producers in foreign countries to try and secure a stable supply of the crude at best will give them the economics over the long term. And then interestingly, you know if that Lima refinery converts to heavy oil refinery, you know, I don't want to go into a lot of details here but it's not detrimental to us, because I gathered from the question that you are asking if it is detrimental, and it is not.

Mark Caruso, Merrill Lynch.

Congratulations on a good quarter. One question that it's been asked is -- there are rumors we've been hearing that Cushing capacity is getting full and with your tankage, wondering if you could comment on that. And then secondly kind of refresh a little bit, with this price pressure on oil, how that will affect earnings for you guys?

The answer to the first question, I think your rumors are facts, if you got any relatives with swimming pools in the Cushing area, we'd love to lease them. Yes, I would say that storage in Cushing is at or near all-time highs and we wish we had our tanks that were scheduled to come on at the end of this year on right now. As far as -- we are somewhat indifferent to the absolute outright price of crude. There are certain aspects of our business that benefit in a higher crude environment, but there is also aspects that get burnt by, for instance, our pipeline loss allowance and our tariffs benefit in a higher price environment, but our cost of fuel and everything goes up and so, we tend not to try and hedge too much of that because they tend to be offsetting and so we really aren't that exposed to the outright price -- again there is some exposure but again its offset by operating hedge factors.

Ron Londe, A. G. Edwards

Do you think the situation in Cushing is, at this point, is more a factor of turnarounds at various refineries or is it just too much oil in the market?

Both. You know Ron, I think it's a combination, there obviously have been turnarounds that -- and there is oil available in the market. It almost seems like maybe its a little bit like natural gas or you have to have the crude available and produce now to meet the demand on a worldwide basis. But it is interesting that 50, $55 oil -- you are sitting here at $52, you know, contango market. That is typically not the environment that the market has been in.

It is pretty unusual.

Ron, I might just point out, I mean if you look back at the early 1990s, US storage capacity was viewed as being full when it started getting to about 360 million barrels. We are now nation wide at about 325 or 330 and we are brimming over with oil and so what happened over the last 10 years or so is that a lot of storage capacity has been taken out either because of refinery consolidation, pipelines being taken out of service or simply the impact of regulation on API 653. And so, what's happened is we've lost some storage capacity, and then as Harry said, what's happened is we've lost production capacity and world wide demand is not constant, so you know, it kind of peaks and valleys, so we are actually like the gas market, and we think we may see a shift in the utilization of storage assets for crude oil to be much like natural gas, you may need to store during the off peak so that you can deliver during the peak demand period. It does happen by the way. We think very good news for Plains All American.

From the standpoint part of volumes in West Texas and Mexico which were up substantially, I assume, part of that was acquisitions. Is there any way to break out how much was acquisitions and how much was from any kind of production growth there?

You can safely assume that the big majority of it is acquisitions. I think, one of the things we've done and we're very proud is if you look at our annual 10-K and you look at our Quarterly 10-Qs, you'll see we've given our Pipeline sector, kind of the vintage of our acquisition so that you have the ability to track, this is what I call same-store sales, what you all see is the stable base in our pre acquisitions made prior to 2005, 2004, 2003 are very stable. But most of the acquisition, increase a lot of the -- up tick was really from assets we bought from Link that we didn't have at all in the first quarter of last year. And we will continue to provide that information to you in the Qs on a same-store sales concept, so you can track that. I will say that while there is some up tick -- the base level volumes in our legacy systems, if you will, are very stable, slightly up, certainly we are seeing some volume increases, but it's not canny for the big magnitudes, primarily acquisition.

In the other category, there was some big increases in volumes, can you break that out a little, littler better?

The other 5 points?

Yes the other broad category of other.

You know, we've tried Ron, it was a little bit novel, the 5 points. It is really difficult to say that it came from any particular pipeline.

Okay, thank you.

Thank you.

Ross Payne, Wachovia Securities.

How are you doing guys?

Hi, Ross.

Couple of quick questions. First of all, what is the maintenance CapEx number for the year, just to refresh my memory?

I believe we forecasted an overall of about 19.2 million.

Okay, very good. Also Phil you mentioned 3.2 times debt EBITDA at year-end. I've seen that excludes the working capital facility and if so, if you can talk just little briefly about the increase from where we are today to year-end.

About working capital facility US, we are using that as what we, the Contango facility?

That is correct, yes.

The increase will be from capital that we spend. Ross, we've forecasted about a 120 million of expansion capital for the year. And I think we've spent about 45 million through the first quarter. And so when you couple that with the, assuming a 255 distribution and then the cash flow coverts that we have from that, I think, you'll come out of that. I think, we've projected about 990 or so to end the year in our long-term debt. The 800 million of -- okay just over a billion, I was incorrect, about a 1.30 billion.

990 was the average.

Yes, 990 was the average. We have 800 million of capital markets debts, so that's about, well over 230 million on the revolver. We are about long term, at the end of the quarter we are about 130 million out on that revolver. So, that increase really ties almost exactly to that remainder of the capital.

Okay, very good. Also I'll make sure, I look at this right. The interest associated with the Contango facility, I know, when you guys look at individual profits that the interest is netted out against the profitability. On the income statement, is that true as well?

Yes, that was the income statement that I was referring to for the guidance. S

It is directly not associated with that profit activity and self liquidity, we actually reduce EBITDA, so if we wanted to gross it up, it would actually help our coverage ratios there because we associate the profit only exist in the tank, because they can exceed the carrying cost, we associate those together.

Okay, very good. And finally where did you guys end up on coverage ratio of your distribution for the quarter?

Large. If you just looked at it on a quarter basis, snapshot, it's about a 136%. If you look at it for the guidance for the year using the mid point, Ross, for 2005, it's about 125%.

Excellent, okay. Guys, great job, thanks.

And by the way Ross that's the 255 level, so is not average, this is the absolute

Kent Green, Boston American Asset Management.

Yes. I have a question about acquisitions, you know has there been any real change in the company's cost of acquisitions, you know recently or have you had to expand as it become much bigger company to look at larger acquisitions and then could you put a for us please. What areas are you looking at?

Kent, I'll do my best. I would say that over the last 3 years it was an evolution in what we are willing to look at with respect to acquisitions you know late last year I believed in our analyst meeting we basically talked about we have looked into areas that are complementary to the crude oil sector but not necessary down the middle of the fare where we can say our business model and transport it always to areas where we think we can add that kind of value by integrating our skill set or capital in the business model and again a complement. Today we -- so far that expansion is really been limited to the LPG areas, but we are not saying that work is limited to as we go forward. As far as the outlook on the size of the acquisition we have been targeting 200 to 300 million a year for several years and we sited you that target on average because we don't budget an acquisition. What we found is it is very easy to hit budgets. You say we're going to make 300 million this year, all you got to do is over pay for it and you can hedge your budget as far as that metric holds by long-term that doesn't necessarily give you the best returns on capital. Last year was our largest year ever in acquisitions 550 million, and prior to that time we kept averaging over a 5-year period prior to that. You know about the 300 million to 325 million a year. We certainly looking at some merger opportunities as we go forward, part because of scale of our company have grown and because it seems like that is where we can see you know some sweet spots. We continue to make a number of smaller acquisitions. Like already this year we completed 4,5 smaller one's.

In 2003, I think, we didn't make any big one's but we completed 11 or 12 smaller acquisitions an aggregate of about 160 million. So, we are very much focused in on the quality and the opportunity that complement to our business or our business model. And while I will tell you that the market has got more competitive for acquisitions partly because the entry barriers to become an MLP and access what is very attractively priced capital has been lowered. We still think that our competitive advantages that we enjoy because we have a business plan that has proven because we have people that re seasoned and know how to make money and generate returns on capital. We think long-term we are still well positioned to compete against those and alternatively we think, you know, some of those late entrance to the game may well find that its harder overtime to maintain that growth without a fundamental business plan and they become opportunities for consolidation which there you might see us take a little bit different approach because we think we are well positioned to be a consolidator of those types of entities.

Is there areas we can exclude like you are not interested in offshore pipelines, you know, platforms as some of the MLPs have moved into or, you know, are you not interested in gas gathering systems or let us say, you know, contentious with some of the other operations?

I will answer the last one first. Gas gathering does not appear to fit well with our business model. It is generally associated with areas that even if they have some expansion opportunities and the reserves are generally depleting areas and gas as not is portable as oil is or products or other and then on top of that one's it gets into pipeline system gases are fairly commodity so it is difficult without storage or other assets complementary to create much value for your unit holders there. So I will try to say that is not an area that we are spending any time on. The other areas that we would talk -- as far as -- we would loved to be involved in the Canon pipeline system which is an offshore. We would probably not be looking for you know stray gathering assets for crude oil even in the offshore unless we had some mainland system to build the backbone around.

Thank you.

Actually before we leave the call, Ron this is Harry, I misunderstood your question, I am sorry. That the other pipeline they were all basically the increase in volumes under pipelines were all basically from acquisitions as well. The link pipelines systems had about 85,000 barrels a day and mid time in Oklahoma area that were added had about 60,000 barrels a day in North Dakota area that are net another that were added just year over last year by another 60,000 barrels a day in the Mississippi Alabama area. The capital for pipeline system which we required same time we acquired cap line from Shell, added about 100 a day and then we acquired some Shell Gockers pipeline systems, that is of 25,000 barrels a day. So that is where most of the increase in the other items came from. We are just trying to clarify Alan that I answer to Ron Londe's question. So if there are any more questions, we can take those now.

Not a problem, sir. At this time, I am showing no further questions.

If there are no further questions, we will go ahead and conclude the call, and we say thanks to everybody who attended, and we look forward to update you at the end of second quarter. Thank you.

Thank you, this does conclude today's conference. You may disconnect your lines at this time and have a wonderful day.