Plains All American Pipeline LP (PAA) 2005 Q2 法說會逐字稿

Welcome to the Plains All American Pipeline second quarter 2005 results conference call. During today’s call the participants will provide comments on the partnership’s outlook for the future as well as review the results of the prior period. Accordingly in doing so they will use words such as believe, estimate, expect, anticipate, etc. 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 to the risks and warnings set forth in the Plains All American Pipeline’s most recently filed 10-K, 10-Q, 8-K and other current filings with the Securities and Exchange Commission.

In addition the partnership encourages you to visit Plains All American’s 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 provides a reconciliation of those non-GAAP financial measures to the most directly comparable GAAP financial measures, and includes a table of selected items that impact comparability with respect to the partnership’s reported financial information. Any reference during today’s call to adjusted EBITDA, adjusted net income, and the like, is a reference to the financial measure excluding the effect of selected items impacting comparability.

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

Thanks Ashley, and welcome to everyone. On our first quarter call I described our business as hitting on all eight cylinders, and to continue with that automotive analogy, the turbocharger kicked in during the second quarter, and this morning the partnership reported financial results that exceeded any prior quarter by a very wide margin.

Adjusted EBITDA, adjusted net income and adjusted net income per LP unit each exceeded the top end of the updated guidance range we provided on June 13, and significantly exceeded the original guidance range we provided on April 28.

Specifically, this morning we reported second quarter EBITDA of $96 million, and net income of $62.3 million or $0.74 per limited partner unit. This compares with second quarter 2004 EBITDA of $61.6 million and net income of $35.7 million or $0.54 per limited partner unit.

These results do include the effects of selected items that impact comparability between periods. Such items negatively affected the current quarter results by a total of $19.8 million, which consisted of $7.9 million non-cash compensation expense charge, and an approximate $1 million gain on foreign currency revaluation, and a $12.9 million non-cash market-to-market loss associated with FAS133.

Approximately $1.2 million of the compensation expense charge was a result of the determination by management at the end of the quarter that achieving a $2.80 per unit distribution level is probable. That is a performance benchmark under the equity grants.

Accordingly the amortization period of that traunch of our LTIP units was shortened to four years from the original six year period. In addition, the application of EITFO 306, which Phil will briefly recap later in the call, resulted in a reduction to reported net income per diluted limited partner unit of approximately $0.09 per unit, but had no impact on our aggregate net income or EBITDA. In the aggregate the selected items impacting comparability reduced our net income per LP unit by about $0.37 for the second quarter.

Last year’s second quarter results were similarly reduced by a total of about $6 million, including a $6.9 million non-cash FAS133 loss, which was partially offset by a $1 million gain on foreign currency revaluation.

Adjusted for these selected items impacting comparability, adjusted EBITDA, adjusted net income, and adjusted net income per limited partner unit for the second quarter of 2005 totaled $115.8 million, $82.1 million, and $1.11 per diluted unit respectively. These results represent increases of 71%, 97%, and 75% respectively over the corresponding metrics in last year’s second quarter.

To sum it up I’d say this quarter was by far the strongest quarter in the history of the partnership. The remainder of today’s call will be divided into three parts. First Harry will provide a review of our operations and also our various growth activities. Second, Phil will discuss our capitalization and liquidity and provide you with financial guidance for the third and fourth quarter, as well as the full year of 2005. Then lastly I’ll provide some closing comments and compare our performance today with our 2005 goals.

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 the prepared comments will be posted on our website shortly after the completion of this call. With that introduction I’ll turn the call over to Harry.

Thanks Greg. As Greg mentioned, I’m going to provide a brief review of performance drivers and market conditions that affected second quarter performance, and also update you on major projects in our capital program.

Since we’ve discussed market conditions on our June 14 guidance update conference call, I’ll limit my comments to the high points. I’d point out that the second quarter market conditions were about as favorable as we’ve seen in our terminalling and storage activities, and account for a significant portion of the performance relative to our original guidance.

During the second quarter the average market structure was a contango of $1.21 with a peak of $1.91 contango; and also contributing to the strong performance was the fact that our margins from our gathering and marketing activities, which are typically weaker in a contango market, have normalized.

Operationally we continue to perform at a high level, a portion of the strong performance in the second quarter is associated with synergies realized from assets and businesses that we’ve added and integrated in the last 18 months. Although it’s very difficult to break out each component of the synergies, they are generally derived from proactive management and integration of the Link, Cap Line, El Paso, and the various Canadian assets that we’ve acquired in recent years.

As a result, we’ve been able to outperform our original forecast for those assets, and in addition our rapidly expanding organic growth activities have helped to augment our base cash flow levels.

Now lets move on to our segment results. For comparative purposes I’ll be comparing our actual results to the updated guidance we provided on form 8-K on June 14.

In our pipeline segment, segment profit, excluding the LTIP charge, was in line with our guidance at $45.8 million. Volumes of this segment were approximately 1.8 million barrels a day. On a per barrel basis our segment profit was approximately $0.28 per barrel in the second quarter. also note a couple of items that need to be taken into consideration when comparing second quarter 2005 results to second quarter 2004 results. First the volume increase included approximately 84,000 barrels a day from our new Cushing to Broom pipeline system. Secondly, approximately 35,000 barrels a day from acquisitions, and thirdly, approximately 28,000 barrels a day from pipelines that were reclassified from our gathering, marketing, terminalling and storage segment to our pipeline segment.

Tariff revenues did not increase proportionately as we also voluntarily lowered tariffs on several of the legacy link pipelines, which had the impact of lowering tariff revenues by approximately $5 million on a comparative quarter basis.

Also note that because we are a primary shipper on many of these pipelines segment profit in our gathering, marketing, terminalling and storage segment increased by a similar amount. Also on a comparative quarter basis.

Actual volumes of some of our major pipelines during the quarter include 50,000 barrels per day on our All American Pipeline system, 283,000 barrels a day on our share of the Basin Pipeline system, 143,000 barrels a day on our share of the Cap Line Pipeline system, and 60,000 barrels a day on the Manitou Pipeline system in Canada.

The third quarter guidance that Phil will walk you through in a few minutes incorporates volumes of approximately 51,000 barrels a day at All American, 165,000 barrels a day on our share of the Cap Line system, 285,000 a day on our share of the Basin system, and 65,000 barrels a day on the Manitou system. Overall we’re expecting slightly stronger performance from our pipeline segment in the third quarter.

Segment profit in our gathering, marketing, terminalling and storage segment for the second quarter, excluding selected items impacting comparability, was approximately $69.1 million, or about $3 million higher than the high end of our guidance range. On the same basis, our segment profit was approximately $1.16 per barrel. Finds in this segment were about 16,000 barrels a day lower than the guidance of approximately 654,000 barrels a day; and about 9,000 barrels a day shortfall related to our LPG activities. In addition we had approximately 52,000 barrels a day of foreign crude that we received into our Gulf Coast facilities during the quarter.

Our third quarter guidance incorporates gathering, marketing, terminalling and storage volumes of approximately 670,000 barrels a day at an average segment profit of approximately $0.78 per barrel and the midpoint.

The crude oil lease gathering volumes are forecasted to be approximately 630,000 barrels a day, which is in line with our second quarter volumes. Our LPG volumes, which are seasonal, are expected to be approximately 40,000 barrels a day compared to 26,000 barrels a day in the second quarter.

As I mentioned earlier, our strong performance in this segment during the quarter was due to a combination of a strong contango market and the fact that we were able to generate normal margins in our lease/gathering business. We were able to capture a significant portion of the contango market profit opportunity because of our market view and our allocation of our assets. We have a market view, or allocate our assets, we’re not taking speculative positions but merely allocating our assets or implementing strategy that will maximize our returns based on our view of the market.

A simple analogy is the oil producer hedge. For example, if a producer hedges production to $40 a barrel, he would not have captured the entire benefit of $55 oil. Another way to approach hedging for the producer would be to purchase $40 puts to lock out the downside and be positioned to benefit if indeed oil increased to $55.

Likewise with our tanks, if we had locked in $0.50 contango market spread, which historically would have been a great spread, we would not have captured all the upside opportunity in the second quarter. However, since we use a combination of spreads and options to insure that we locked in certain minimum returns, we retained significant upside exposures. This, coupled with the fact that our gathering and marketing margins were in line with historic margins, created the strong results in the quarter.

Now I mention our gathering and marketing margins because they’re typically weak when the crude oil market transitions into contango, and therefore would offset gains that we typically realize in our terminalling and storage activities. However if the market stays in contango, lease prices adjust to this market environment and the margins become consistent with margins that would be generated in a “normal market”. Since the crude oil market has been contangoed since the fourth quarter of 2004, lease prices have in fact adjusted, and our current margins are reflective of the margins that we would expect to see in a normal market.

Our guidance for the remainder of 2005 incorporates an assumption that market conditions in the third quarter are a little less favorable than the second quarter, and that market conditions in the fourth quarter taper off closer to normal market conditions.

Lastly, maintenance capital expenditures for the quarter were $4.1 million.

As you heard on our June 14 call, our portfolio of attractive organic projects continues to increase. We currently have approximately $190 million of expansion capital budgeted for 2005, which is up 90% from the beginning of the year. The increase from our June 14 call is primarily due to several smaller projects that have added to the program. Because construction activities of our many larger projects will carry over into the first part of 2006, we already anticipate that 2006 organic growth capital will exceed $70 million.

I’d like to take a few minutes to briefly review some of our more significant projects. In mid June we announced our intent to build a 2.85 million barrel crude oil storage terminal facility at St. James Crude Oil Exchange in Louisiana. Since that time we’ve performed additional analysis on the project and have decided to increase the shell capacity of the original facility to approximately 3.25 million barrels.

The facility will be comprised of seven tanks, ranging in size from approximately 180,000 barrels to 590,000 barrels, and importantly, the working capacity will be increased by about 17%. In addition, the revised design incorporates additional pumping and manifold capacity, which will allow for maximum operating flexibility. This will allow for receipts and deliveries with connecting pipelines at their maximum receipt and delivery capabilities, which is about 1.5 million barrels a day, and will readily accommodate future expansion of the facility of approximately 3 million barrels on our existing site.

The revision to the design has increased our estimate of the total cost of the facility to approximately $85 million, of which we estimate $21 million will be spent in 2005, and the balance carrying over to 2006. Subject to weather and permitting, we still expect the facility to be operational in the first quarter of 2007.

During the second quarter we completed the Phase I expansion of our Trenton pipeline system in the Rocky Mountain region, which involved the construction of approximately 32 miles of 8 inch grain [ph] line and 70 miles of 6 inch and 4 inch gathering pipelines. As you recall this project was underpinned by long term reserve dedications from producers whose leases will connect into our system. We’ve added about 20,000 barrels a day of crude oil to our pipeline system, and the total cost of this project was approximately $28 million.

We’re currently working on the Phase II expansion of the Trenton pipeline system, which will add an additional 70 miles of 6 inch and 4 inch gathering line, and 17 miles of new 10 inch loop to the main line of the system. The main line loop will increase capacity by about 26,000 barrels a day from the current 24,000 barrels a day of capacity up to an approximately 50,000 barrels a day. Correspondingly, the gathering system expansions will connect an additional 44 wells to the system, and add approximately 12,000 to 15,000 barrels a day of gathering volume. The Phase II expansion is expected to be completed at the end of the fourth quarter of 2005, and total cost is estimated to be about $20 million.

Our Phase V expansion of our Cushing terminal, which involves construction of 1.1 million barrels of additional tankage remains on schedule. The Phase V expansion project will expand the total capacity of this facility to approximately 7.4 million barrels, and is expected to cost approximately $13 million, and will be operational at the beginning of the first quarter of 2006.

In April we began the construction of a fractionator in northwest Alberta to complement some of our existing assets. Once completed the facility will have the ability to process approximately 4,000 barrels a day of natural gas liquids. The facility will also contain approximately 14,000 barrels of storage capacity. The project is on schedule to be in service by the end of the fourth quarter 2005, at an estimated cost of approximately $16 million.

In June we announced our intent to expand our Coropa [ph] terminal in Canada by approximately 300,000 barrels of new tankage. The total cost of this project, including related expansion of pumping capacity at the facility, will be approximately $12.3 million, of which approximately $9 million will be spent in 2005. We anticipate these tanks will be available for service in the first quarter of 2006.

With our expanding asset base we expect to be able to continue high quality and economically attractive organic growth projects throughout the US and Canada. With that, I’ll turn the call over to Phil.

Thanks Harry. Before I do get going, I want to note that Al Swanson, our Vice President and Treasurer is also here and will be available for any finance questions that might come up after the call. But during my part of the call I’m going to review our capitalization liquidity at the end of the second quarter. In addition I’m going to walk through our updated financial guidance for this year, including our guidance for the third and fourth quarters.

At June 30, PAA had long-term debt outstanding of approximately $953 million, book equity of approximately $1 billion and a long-term debt to total Cap ratio of approximately 49%. Adjusting for the impact of selected items impacting comparability, our adjusted EBITDA to Interest coverage ratio for the second quarter was approximately 8.1 times. That excludes approximately $5.8 million of contango-related borrowings that are reflected as a direct cost and therefore deducted in determining EBITDA.

Based on the midpoint of our 2005 guidance and our projected year-end long-term debt balance, we believe we will end the year with a long-term debt to adjusted EBITDA ratio of approximately 2.8 times. Due to the issuance of 10-year fixed rate notes during the quarter, at June 30th, our outstanding long-term debt had an average life of approximately eight years and 100% of it was subject to fixed rate interest, 100% of our debt. What we did was, we’ve chosen to lock in what we believe to be very attractive long-term rates.

As I did last quarter, I will point out that the debt under our contango inventory facility is short-term and comprised the vast majority of our short-term debt at June 30th. We also classify as short-term, the borrowings under our long-term revolver for NYMEX margins and storage of hedged inventory that’s not borrowed under the Contango inventory facility.

The borrowings for crude oil stored are self liquidating, which means that the borrowings are repaid when the proceeds are received from the sale of the hedge 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 on the contango facility.

I would also remind you, and just mentioned a moment ago, that for classification purposes, interest costs that we incur on short-term contango-related borrowings are netted against the profits we realized on storing the crude and is therefore included in the determination of gross profit in our gathering, marketing, and terminaling [ph] and storage segment. We view the costs as carrying costs associated with the storage transactions as direct costs of the transactions.

Our contango facility is somewhat unique among our peers in the MLP sector. As such, some of you that are new to the PAA story might want to reference my part of our first quarter 2005 conference call script, which is available on our website. That will give you additional discussion on the facility and the timing impacts that the contango activities can have on our cash flow from operating activities.

Moving on, we completed several financing transactions during the second quarter. In early May, we increased the size of our two credit facilities, by a total of $450 million. First, we increased the aggregate capacity in our senior secured credit facility, from $750 million to $900 million. The facility also includes a sub-facility for contango borrowings, and that amount was increased from $300 million to $360 million. This facility may be further increased to an aggregate capacity of $1.25 billion, at our option, and subject to obtaining additional commitments from our lenders. Secondly, we increased the capacity of the contango hedged inventory facility, from $500 million to $800 million.

Then in late May, we issued $150 million of 10-year senior unsecured notes in a private placement. The 5-1/4% notes were priced at a slight discount, yield 5.31%. That equates to a credit spread of 127 basis points over the applicable 10-year treasure of 4.04%.

These transactions are representative of our proactive effort to maintain significant liquidity and to position the partnership to continue to optimize its extensive and strategically located asset base in a high crude oil price environment. Our management team, our board of directors and owners of our general partner are all committed to maintaining a solid investment grade capital structure and associated credit metrics. Accordingly, we have been and will continue to be very proactive about taking the steps to maintain excellent financial strength and prudent levels of liquidity in a dynamic crude oil price environment.

Before I move on to guidance, I want to spend just a few moments to elaborate on EITF 03/06, which reduced our reported results by $0.09 per limited partner unit during the second quarter. EITF 03/06 addresses the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the company when, and if, it declares dividends on its common stock, or, in our case, distributions on our common units.

Essentially, EITF 03/06 provides that in any accounting period, where our aggregate net income exceeds our aggregate distribution for that period, we are required to present earnings per unit as if all of the earnings for the period were distributed, regardless of the pro forma nature of this allocation, and whether or not those earnings would actually be distributed during a particular period, from either an economical or practical perspective.

The theoretical results are venues to report our earnings per limited partner unit in accordance with generally accepted accounting principles. EITF 03/06 will not impact our overall net income or other financial results. However, for periods in which aggregate net income exceeds our aggregate distributions for that period, it will have the impact of reducing our reported earnings per limited partner unit. This result occurs because a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights held by our general partner, even though we made cash distributions on the basis of cash available for distributions, not earnings, in any given accounting period. In accounting periods where aggregate net income does not exceed our aggregate distributions for that period, then EITF 03/06 will not have any impact.

I will now shift to a discussion of the partnership’s financial guidance. Our guidance is based on the current state of, and our outlook for, the crude oil market, reasonable expectations of volumes and expense levels, as well as our judgments and assumptions about the potential associated with our business development activities, where the outcome is less than certain at this point. That includes estimated contributions from acquisitions that have been recently completed.

In the 8K that we furnished this morning, we updated our guidance for the third and fourth quarters and amended our full year 2005 guidance to reflect the quarterly changes. For the sake of time, I’ll go over our third quarter numbers and just briefly touch on the fourth quarter and full-year numbers. I remind you, for all the details behind the guidance, I would direct you to the 8K.

For the third quarter of this year, we would guide you to an adjusted, EBITDA range of $95 million to $105 million. That equates to a midpoint of $100 million. We estimate the third quarter G&A should be approximately $26 million to $27 million.

For interest expense purposes, we anticipate average long-term debt balances of approximately $1 million, resulting in interest expense of $16.2 million to $16.8 million, using a fully loaded weighted average interest rate of approximately 6.4%. Approximately $400,000 of the third quarter projected interest expense is non-cash, as it relates to the amortization of deferred amounts associated with terminated interest rate hedges.

I would also remind everyone that interest associated with contango storage activities, again, is not included in the interest forecasts; as such expenditures are included in the costs of sales as a direct cost by those activities. As I noted previously, the second quarter contango interests included in the costs of sales was approximately $5.8 million. And just for further clarification, contango interest in the first quarter of ’05 was $3.4 million. And for all of 2004 and 2003, it was $2 million and $1 million respectively.

Finally, we estimate depreciation and amortization to be approximately $19.8 million to $20.3 million. Based on these estimates, we forecast adjusted net income of between $57.9 million and $69 million, or approximately $0.76 to $0.92 per diluted unit.

The net change to our fourth quarter guidance from our previous guidance is substantially less, as we anticipate the current favorable market conditions will subside. Accordingly, we now anticipate our adjusted EBITDA for the fourth quarter of this year will range from $75 million to $90 million, or a mid-point of $82.5 million. We forecast adjusting net income for the fourth quarter of $37.2 million to $53.1 million. That equates to $0.47 to $0.70 per diluted unit.

We also amended our guidance for the full year of this year to take into account the current views on the third and fourth quarters. Now adjusted EBITDA range for 2005 should be $368.7 million to $393.7 million, again with the midpoint equating to $381.2 million.

We expect G&A for the full year to range between $100.2 million to $102.2 million; annual depreciation and amortization expense is expected to range from $78.7 million to $79.7 million. Interest expense is expected to range from $61.6 million to $62.6 million. That’s based on a weighted average long-term debt balance for the year of approximately $1 billion and a weighted average interest rate of approximately 6.3% for the full year.

Our weighted average interest rate for this year also includes the various components not previously mentioned. Approximately $1.6 million of this year’s projected interest expense is non cash that relates to the amortization of deferred amounts associated with terminated interest rate hedges.

Based on these estimates, we forecast adjusted net income of $226.4 million to $253.4 million for the year, or approximately $3.01 to $3.40 per diluted unit. As we have in the past, we emphasize that, while total net income for the partnership is not impacted by change in our cash distribution level, the relative allocation of net income, between the limited partners and the general partner, and therefore the net income per unit is impacted by such a change.

As a rule of thumb, when the aggregate distribution is greater than net income, and EITF 03/06 does not apply, for as long as the partnership is in the 25% incentive split level, a nickel increase in annualized distribution per unit roughly equates to a $0.02 annualized decrease in net income per limited partner unit. Once we are in the 50% incentive split level, a nickel increase in annualized distribution per unit will equate to a $0.05 annualized decrease in annual net income, per LP unit.

I’ll also briefly remind everyone that we have excluded charges associated with our long-term incentive plan from our adjusted financial metrics, as the vast majority of the incremental units that would be issued upon investing are already included in the determination of diluted units. These equity incentives have acceleration provisions tied to performance thresholds and continued employment. But regardless, the majority will vest over a six-year period of time.

Finally, consistent with our past practice, we do not attempt to forecast any potential impact related to SFAS 133, as we have no way to control or forecast crude oil prices on the last day of each quarterly period. Accordingly, the guidance I provided for 2005, including the third and fourth quarters, excludes any potential gains or losses associated with this accounting statement, as well as other minor items that affect comparability between periods.

In summary, though, I want to emphasize that you can find the detailed assumptions behind our projections in the 8K that we furnished this morning.

And finally, before I turn the call back over to Greg, I want to make one last point on guidance. Favorable market conditions and solid performance have allowed us to meaningfully increase our guidance in three of the last four quarters. Given that trend, it might be tempting to want to assume that we will continue to follow that pattern in the future. It is extremely important to understand that when we give guidance, we are making our best forecast of how existing market conditions will affect our business during the quarter. We do not believe that it is in anyone’s best interest to be overly aggressive in projecting a lengthy period of very favorable market conditions when there is no empirical evidence to support the existing of such conditions over an extended period of time.

We may ultimately find out that the strong market conditions we have been recently experiencing are sustainable. If that is the case, there is undeniable upside potential for our unit holders. However, if they are temporary, as we suspect they may be, we will have done the prudent thing for the partnership and not overextended ourselves with respect to expectations or distributions. And with that, I’ll now turn the call back over to Greg.

Thanks, Phil. PAA’s second quarter results were very, very strong and illustrate the complementary strength of our asset base and our business model. Over the last 15 years, we have intentionally designed our business model and assembled our asset base to enable us to protect against downside risk, while at the same time provide us with upside opportunities in volatile markets.

In a nutshell, in addition to providing base transportation needs for our customers, we utilize our strategically located asset base, market knowledge and significant capital base in order to capitalize on market opportunities and generate incremental profits for our unit holders. While we have been anticipating that market conditions would be volatile and favorable for our business, we cannot say that these market conditions will persist, and that the earnings levels are permanent or even frequently repetitive.

However, we are able to utilize the excess cash flow generated in these types of markets, to pay down debt, or as equity to invest in acquisitions or organic growth projects. By taking that disciplined approach, we are able to convert the cash flow from what may prove to be a temporary windfall due to extremely favorable market conditions, into a sustainable increase in distributable cash flow that can ultimately be used to increase distributions to our unit holders.

Based on our midpoint 2005 adjusted EBITDA of approximately $381 million, cash interest expense of approximately $60 million and maintenance Cap Ex of $19 million, PAA will generate approximately $302 million of distributable cash flow in 2005. based on achieving the midpoint of our distribution target for November 2005 of $2.65 per unit, total distributions in 2005 will be around $190 million, which provides approximately $112 million of excess cash flow that’s available to fund our organic growth projects, many of which Harry talked about earlier.

As discussed in the June 14 update conference call, a portion of our over performance against original guidance was attributable to extremely favorable market conditions. The balance, which is substantial, is associated with incremental synergies from recent acquisitions, and excellent performance from the entire team. While it is difficult for us to calibrate exactly how much is in each category, we believe that our current sustainable adjusted EBITDA run rate is in the range of $315 million to $330 million per year, which reflects an approximate $35 million to $50 million improvement over the midpoint of our original 2005 guidance due to incremental synergies and what we believe is sustainable performance. In addition we expect to build upon that base level as our organic growth projects, including the St. James terminal, come to fruition.

Before I open the call up to questions I want to provide a brief midyear review of our progress versus our 2005 goals. At the beginning of the year we shared with you four very specific goals for 2005. these goals were to 1) deliver operating financial performance in line with guidance; 2) to optimize our field operations to eliminate inefficiencies and improve our ability to service our customers and therefore our competitive position; 3) to position the partnership for continued growth by executing our organic expansion projects and pursuing our target of averaging $200 million to $300 million of accretive and strategic acquisitions; 4) to increase our distribution to unit holders by 5% to 7% without regard to future acquisitions.

With just over half the year complete and a clear picture of our prospects for the second half of the year, we believe we are very well positioned to meet or exceed these goals. First our financial and operating results have far surpasses our original guidance for the year. The approximately $381 million midpoint of our current adjusted EBITDA guidance for 2005 represents an increase of approximately 51% above our 2004 adjusted EBITDA, and is approximately 36% higher than the midpoint of the 2005 guidance we provided at the beginning of the year.

Second, we are devoting significant resources toward optimizing our operation and business activities, which have grown significantly over the last several years. We have several important internal initiatives underway in this area and I look forward to sharing meaningful progress with you at their conclusion.

Third, we are on schedule and on budget with the organic expansion projects in our portfolio. In addition since the beginning of the year we have increased our expansion capital spending plans for 2005 by 90% to increase it to $190 million as we have developed additional projects to enhance our sustainable cash flow. Our business development group continues to be very active evaluating potential acquisition opportunities. Our goal is to average $200 million to $300 million per year of acquisitions on an accumulative basis. Thus far this year we have closed three small acquisitions for a total consideration of approximately $24 million. While we’re behind the targeted pace, we have several targets under various stages of review, that if successful, would allow us to achieve our goal still for 2005.

Fourth and finally, thus far in 2005 we have increased our distribution to unit holders on three separate occasions, including the recently announced increase to $2.60 per unit. This most recent increase represents a 12.6% increase over the corresponding distribution for 2004, and an 8.3% increase over our November 2004 distribution level of $2.40 per unit.

On June 14, as a result of our strong fundamental performance here to date, as well as our outlook for increased base levels of cash flow, we increased dour annual distribution run rate target for our November 2005 distribution to a range of $2.62 to $2.67 per unit, which would equate to an increase of 9.2% to 11.3% for the year-over-year growth.

In conclusion, we continue to believe that Plains All American’s consistent performance and attractive risk reward growth profile puts us squarely in the top tier of the large cap growth MLPs in the sector. We look forward to updating you on our progress on our third quarter conference call in late October. That wraps up the items on our agenda. We’d like to thank all of your for your participation in today’s call. For those that joined us late, a complete written transcript of the prepared remarks for this call will be posted on our website at www.paalp.com very shortly after this call.

Ashley, at this point we’re ready to open the call up for questions.

[OPERATOR INSTRUCTIONS]

Ron Londe of A.G. Edwards.

I’m curious about the tariff adjustment in Link Energy. Was that related to any pressure from competition from third party shippers, and also is that going to put a higher base of cash flow earnings under the gathering and marketing operation going forward? Was that your strategy, or what was your strategy there?

Basically a lot of the Link assets that we had acquired, they had tariffs that had been established a long time ago by predecessors to Link and they just weren’t in line with regional market conditions. So we did adjust the tariffs to be more in line. Really those high tariffs had two negative impacts; first of all it discouraged third parties from shipping on the pipelines, and then secondly, reported pipeline earnings were including some of the gathering and marketing margin in this. So that’s the reason we voluntarily lowered those tariffs.

Ron from just the management of the business, it’s better to know what the regional market conditions are so that you’re making sure that you’re making money on your transportation, and to the extent you’re also the marketer of the barrel, that you’re making money there. When you have artificially high tariffs, artificially being outdated, it’s hard to tell whether you’re really being responsive to market conditions. Long term we think it’s going to be much better and healthier for everybody.

Do you think you’re going to be able to attract some barrels on that line with these new tariffs?

That would certainly be what we think is one of the byproducts of this, that somebody who looks up and let’s say they’re facing $1.00 tariff and we’ve lowered that tariff to $0.60, that’s much more competitive with a truck barrel right now and again we think on the margin is the way you should run the business.

OK, thank you.

[OPERATOR INSTRUCTIONS]

Ross Payne of Wachovia.

Life is good at PAA these days, very impressive numbers here. The first question I’ve got is, normally the gathering profitability is a little weaker in a contango market. Can you explain the dynamics that reversed that during this particular quarter? And secondarily if you can maybe even quantify how much that added to your quarterly EBITDA versus maybe a normal trend for that?

Basically what happens is, when the market shifts from say backward or flat to contango, what typically happens is the market shifts, prop barrels are discounted, and it takes time to renegotiate those gathering and marketing margins with producers that we’re gathering crude from and it happens to everybody in the business. If the market stays in contango for a long period of time, which it’s been in contango for at least half the year now, over time those marketing margins adjust. They get renegotiated and they reflect current market conditions and you’re back in a position where you’re gathering and making your normal $0.30 to $0.40 cents a barrel, or $0.50 or $0.10 whatever it is per barrel that your gathering marketing margins are.

So it’s probably in the neighborhood of –

It’s part of the difference between the $380 million run rate that we’re going right now and what we think is a stabilized run rate between 315 and 330. There’s some other factors that are entering into that, but they’re somewhat related to the fact that you’re in contango and therefore you’ve got swelling inventories. I would just point out, Ross, kind of to elaborate on what Harry said, when you go from a contango market, which normally has only existed 20% to 30% of the time to backward dated markets are far prevalent, and if you have a transition into contango and then back into backwardation you only have -- these contracts at the well head are generally 30 to 60 day evergreens. So you don’t have enough time to adjust before you’re back into a different shaped market.

What’s happened this time is, we’ve gone into a contango market and it stayed there, as Harry said, for six months. So the gathering and marketing margins have normalized, and yet we’re still able to work the benefit of the assets. Not to offset lower gathering and marketing margins, but to generate higher terminalling and storage overall on top of normal gathering and marketing margins.

OK, that’s very helpful. Also Greg, is there any significant change in the market that could make these things a little bit more permanent than what they’ve been in the past?

Ross if you go back and you look at the conference call scripts that we had in late 2003 we basically were anticipating that we could very well see these type markets, which is why we expanded storage in Cushing while we were very much interested in owning more storage in strategic locations. The overall fundamentals of the market are evolving, and I would say the critical factors there are that you’ve got supply and demand lines that are converging and there’s very little differential there now. The excess capacity of OPEC or other areas to overcome any blips in that, as you start to get tighter you’re going to have more volatility.

What happens is people have a tendency then to want to store more barrels because of that potential interruption, whether it be political, whether it be because of weather or other factors. So you have swelling inventories and yet a tight supply/demand gap which is what’s causing the absolute price to be high. Everybody knows if you have any interruption in almost any source of production those two lines converge. So you’ve got those factors and then multiple grades on top of that.

What we’re seeing now is what we’ve anticipated seeing. What we do not know, having never been there before, is this temporary and will the market react and come up with significantly more incremental production because prices are high. Will we ultimately see demand destruction that will cause that line to move away from the production capacity line? If we don’t, if we still continue to see tight supply and demand lines converging and you’ve got storage that over time, because of API653 and other factors are going to perhaps force more storage to be taken out of service, then there certainly is the foundation for these conditions to be sustainable, but we just never have been here before.

We think the prudent thing to do is to take a very disciplined approach to the market conditions and not try to either lever up or to over distribute. In the meantime we’re able to take these excess cash flows and plow them in to some very, very attractive organic growth projects, which we know will raise the base level of cash flow regardless of market conditions.

Greg I guess I may have just one other question. I’ve heard that Encana has got some storage assets in natural gas in Canada. Some similar dynamics appear to being going on in natural gas, is that an area that you may have an interest in, in the future?

I think it’s very fair to say that we view this as a hydrocarbon storage business. If you recall from the last conference call, we felt like the crude oil storage business may be moving toward the type profile that we’re seeing in the gas storage where you actually have to store it off peak periods to be able to deliver crude oil with certainty in the peak periods. The conversely we’re seeing natural gas storage patterns kind of move toward the crude oil side, which is because of LNG imports, which is a few years off, but they’re coming, where you’re going to end up with, in effect, tanker loads of gas pushing into a system that’s been used to having it all supplied domestically.

So I think it’s fair to say that Plains All American’s attitude toward hydrocarbon storage would cover both crude oil and natural gas, and perhaps even one day products. So I could not respond one way or another as to whether we’re involved in any kind of process there. But it is a fair statement that says we believe our business model for crude oil is equally applicable to the storage patterns for natural gas.

OK great. Thanks guys.

[OPERATOR INSTRUCTIONS]

Yves Siegel of Wachovia.

Just following up on Ross’s question on storage, are you able to charge a higher fee because the inherent value of storage is increasing? And along those lines, what’s the duration of the contracts on the tanks that you have now? Is it possible to see an increase going forward?

Yves I would tell you the majority of our existing contracts where we provide storage and terminalling services are principally to our refining customers, and we view that as a core service we provide them for the purposes of transporting and delivering to them crude oil that we market from all sources. And so while there’s certainly some truth that the value of storage is going up, both in terms of if you were looking at spot contract markets for it, we view that as a long-term relationship with those refiners.

What I think is also fair to say is the value of storage is somewhat reflected in the shape of the market, in the contango market. You know, we used to consider a $0.30 to $0.50 contango market, as Harry alluded to earlier, as being a very prime pricing. Today, we’re seeing those spreads go out to as wide as a dollar and they’ve actually been a little even higher than that. So, I think the market is confirming your question right there, and that is, the value of storage, certainly in certain times of the year, is definitely going up, because, there’s a limited volume of it.

And then, you’ve got these overall supply-demand aspects of needing to make sure that you have crude oil in the peak periods as well as the disruption potential of, you know, with geo-political or weather. So, there’s no doubt the value of a tank has gone up. As far as whether we would try and exercise pricing power with our refiners, because that’s a relationship issue, but I think what you can say is the futures market is actually pricing the value of that crude through the spreads.

How far out can you lock in that spread?

Well, it generally starts, and I don’t have something in front of me right now, but for instance, the spread between the prompt and the second month today is probably around $1.00. The next month out, it’s around $0.50 to $0.70, and the next month out, it’s probably $0.30 to $0.40. So, you can’t lock in the current margin of a dollar for a very long period of time.

What we have seen, though, is as that prompt month rolls off, the next month tends to trade in that range it was before. And then, it widens and takes a position. We saw the spreads, the contango spread in early June, tighten to as tight as $0.20, and then widen out by the end of the month to about $1.15. So, you couldn’t lock in a dollar contango per month for very long. In fact, you couldn’t do it for more than one month. But, if you’re patient and you’ve got the discipline with respect to, as Harry mentioned earlier, putting strategies around your assets, whether that be through outright sales or through option strategies, you can lock out the downside and still retain upside potential.

And that’s what we think our asset base, our business model and probably of equal, if not more importance is, the technical skill sets and experience that our team members have, to position us to do that and still deliver, at a minimum, of what our base expectations are, is the value of investing in Plains All American.

That’s great. Thanks a lot, Greg.

Your next question is coming from Mark Easterbrook, of RBC Capital Markets. Please go ahead.

Yes, hi guys. You guys might have mentioned this in a comment and I missed it, but what are the types of rates of returns that you’re expecting on the $190 million in Cap Ex? And then secondly, you stated you had about $70 million of Cap Ex for 2006. But, do you expect that to grow up to maybe the same level as we’ve seen in 2005, like around $150 million to $200 million?

To answer the last part of your question first, that’s certainly the goal. I mean, what we’ve already seen this year, Mark, since the beginning of the year, we started with a very well defined capital program of around $100 million and we’re at $190 million. Could we see that kind of velocity in 2006? I think the answer is potentially yes. Would it be prudent at this point in time to predict it that way? I feel a little bit uncomfortable, but I can tell you we’ve got better visibility now, looking into the 2006 organic capital program than we had at this same time last year, looking at 2005.

So, what we believe, and we certainly monitored the likes of the Kinder Morgans and the Enterprises, the other large cap MLPs that I believe are business builders, similar to PAA. And what we’ve seen is as the scale and scope of the entity grows, the range and number of organic growth projects seem to be growing with it, so that you become less acquisition dependent and in fact more organic growth dependent. And that’s what we think we’re seeing.

We were simply just kind of communicating a flash read right now that says, we’re starting off in mid-2005 with a good outlook for 2006 in organic growth. And we didn’t have that last year. We do now. We certainly don’t intend to quit working on projects. We’ve got several that are in the incubation stage that we think provide the opportunity to, in fact, perhaps maybe achieve the $150 million that you mention. It’s just too early to say at this point in time.

I’m sorry, what types of rates of returns are you expecting?

You know, you can kind of reverse engineer it. We’ve used kind of multiples as an example. The multiples on some of these projects range from a multiple as low as four, with respect to investment to EBITDA generate or DCF generated, to as high as seven or eight, with some upside opportunity to beyond there.

For instance, where we may be building something that has a seven or an eight multiple, which by reverse engineering would imply a 12% to 13% range of return for a long-life sustainable asset that really doesn’t depreciate over time because of the nature of them--which is, by the way, very favorable relative to our current cost of capital, which is in the 50/50 debt to equity in the 6% and change range, to, when we look at those, we’re actually looking at opportunities that if the market stays volatile, it will give us the ability to realize and [inaudible] take that seven or eight multiple and actually make it look like a five or a six. So, they’re very attractive relative to our cost of capital.

Any time, even at a 13% rate of return, you can generate your cost of capital plus 100% of that is something that we really want to do, especially when it has the risk profile of being very sustainable.

OK, thanks.

At this time, there are no further questions. I’d like to turn the floor back over to the presenters for any closing remarks.

Thanks to everyone for participating. As Ross Payne said, it truly is, there are good times at PAA and we don’t take them for granted. We’re going to work very hard to make sure we deliver very solid results going forward and hopefully, these favorable market conditions persist.

But in any event, the base levels of cash flows are far beyond what our original guidance was. We have an optimistic outlook for the future. Thank you very much. We look forward to updating you at the October phone call.

That does conclude today’s teleconference. You may disconnect your lines at this time. Have a wonderful day.