Plains All American Pipeline LP (PAA) 2012 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the PAA PNG earnings conference call. Now at this time all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Instructions will be given at given at that time.

(Operator Instructions)

As a reminder, today's call is being recorded. I'm going to turn the call over to your host, Roy Lamoreaux. Please go ahead.

Good morning. My name is Roy Lamoreaux, Director of Investor Relations. We welcome you to Plains All American Pipeline and PAA Natural Gas Storage first quarter 2012 results conference call. The slide presentation for today's call is available under the conference call tab of the Investor Relations section of our website at www.PAALP.com and www.PNGLP.com.

I would mention that throughout the call we will refer to the Companies by their New York Stock Exchange ticker symbols of PAA and PNG, respectively. As a reminder, Plains All American owns the 2% general partner interest and all of the inventive distribution rights and approximately 62% of the limited partner interest in PNG, which accordingly is consolidated into PAA's results.

In addition to reviewing recent results, we'll provide forward-looking comments on the partnership's outlook for the future. In order to avail ourselves as Safe Harbor precepts and encourage Companies to provide this type of information, we direct you to the risks and warnings set forth in the partnership's most recent and future filings with the Securities and Exchange Commission.

Today's presentation will also include references to certain non-GAAP financial measures such as EBIT and EBITDA. The non-GAAP reconciliation sections of our websites reconcile certain non-GAAP financial measures to the most directly comparable GAAP financial measures and provide the table of selected items that impact comparability to partnerships recorded financial information. References to adjusted financial metrics exclude the effect of these selected items. Also, for PAA, all references to net income are references to net income attributable to Plains.

Today's call will be chaired by Greg L. Armstrong, Chairman and CEO of PAA and PNG. Also participating in the call are Harry Pefanis, President and COO of PAA, Dean Liollio, President of PNG, and Al Swanson, Executive Vice President and CFO of PAA and PNG. In addition to these gentlemen and myself, we have several other members of our management team present and available for the question-and-answer session.

With that, I'll turn the call over to Greg.

Thanks, Roy. Good morning and welcome to everyone.

PAA delivered very strong first quarter results, underpinned by solid fundamental performance and further enhanced by favorable market conditions. Yesterday, after market closed, Plains All American announced first quarter adjusted EBITDA of $472 million. These results exceeded the midpoint of our guidance range by $72 million, or 18%, and were $52 million above the high end of our guidance range. In comparison to last years first quarter, adjusted EBITDA, adjusted net income, and adjusted net income per diluted unit for the first quarter of 2012 increased 36%, 58%, and 53% respectively. These results and additional information are summarized on slide 3.

PAA's first quarter results were driven by solid performance in all three segments with supply and logistics segment being the largest contributor to over performance. As shown on slide 4, our first quarter results marked the 41st consecutive quarter that PAA has delivered results in line with or above guidance. In April, PAA declared a 7.7% year-over-year increase in our annualized run rate distribution to $4.18 per common unit. As shown on slide 5, PAA has increased its distribution in each of the last 11 quarters and 30 quarters out of the last 32 quarters.

As reflected on slide 6, during the remainder of today's call, we will discuss our segment performance relative to guidance, our expansion capital program, our acquisition and integration activities, and our financial position. We will also address the drivers and major assumptions supporting our financial and operating guidance for the second quarter of 2012. We will address similar information for PNG. At the end of the call I will provide a recap as well as some comments regarding our outlook for the future.

And with that, I'll turn the call over to Harry.

Thanks, Greg.

During my section of the call I'll review our first quarter operating results compared to midpoint of our guidance issued on February 8, discuss the operational assumptions used to generate our second quarter guidance, and discuss our 2012 capital program and acquisition activities.

As shown on slide 7, adjusted segment profit for the transportation segment was $173 million, which was $25 million above the midpoint of the guidance. Volumes for the segment of 3.17 million barrels per day were above guidance by approximately 60,000 barrels per day, which combined with a higher pipeline loss allowance volumes accounted for approximately $18 million of the over performance. Operating expenses were approximately $8 million lower than our guidance, primarily due to combination of; one, $4 million of reversal of accrued expenses associated with the Rainbow Pipeline release in 2011, and, secondly, a shift in the timing of certain maintenance and integrity expenses.

On a per unit basis, adjusted segment profit was $0.60 per barrel. Adjusted segment profit for the facility segment was $100 million, or $5 million above the midpoint of our guidance. Volumes of 91 million barrels were in line with guidance, generating adjusted segment profit per barrel of $0.37, which was slightly above the midpoint of guidance. Primary contributors to our financial performance were higher throughput fees and other ancillary fees at several of our accrued oil and LPG terminals, as well as favorable performance from our gas processing assets.

Adjusted segment profit for the supply and logistics segment was $197 million, or $41 million above the midpoint of our guidance. Our volumes of 932,000 barrels per day were in line with guidance. Adjusted segment profit per barrel was $2.33, or $0.49 per barrel above the one of our guidance. Our financial over performance for the quarter was due to a combination of favorable crude oil basis differentials and stronger than forecasted propane and isobutane margins.

Let me now move to slide 7 and review the operational assumptions used to generate our second quarter 2012 guidance which was furnished in our Form 8-K last night. The guidance includes the benefit of the BP NGL acquisition, which was effective April 1, 2012. For the transportation segment we expect volumes to average approximately 3.5 million barrels per day. That's about 10% higher than first quarter volumes. Approximately 215,000 barrels per day of the increase is related to the BP acquisition.

The balance of the increase primarily relates to increased volume on several pipelines, including our Midcontinent, Capline, and Mesa Pipeline systems. We expect adjusted segment profits per barrel of $0.55, which is about $0.05 per barrel lower than the first quarter segment profit. That's primarily due to the timing of maintenance and integrity spending and then the first quarter had the benefit of the reversal of a portion of the Rainbow Pipeline expense accrual.

Facility segment guidance assumes an average capacity of 111 million barrels of oil equivalent. The increase is primarily due to storage capacity added from BP and Yorktown acquisitions and an NGL fractionation H capacity added for the BP acquisition. Adjusted segment profit is expected to be $0.34 per barrel in the second quarter. Supply and logistics segment guidance volumes are projected to average 940,000 barrels per day for the second quarter of 2012.

While basically flat with the first quarter volumes, forecast includes an increase in our lease gathering volumes of approximately 37,000 barrels per day, which is offset by the seasonal volume decline associated with our NGL activities. Projected midpoint adjusted segment profit is $1.98 per barrel, which is very strong compared to historical levels, but is lower than the first quarter results. And that's primarily due to the seasonality of our NGL activities.

Now let's move on to our capital program. As reflected on slide 9, we have increased our projected expansion capital expenditures for 2012 by $150 million with the targeted amount of (inaudible) in the range of $950 million to $1.1 billion. Now the range reflects the fact that there are issues that could impact the timing of capital expenditures. And that's primarily associated with our pipeline projects, in particular with respect to securing rights of way, sourcing materials such as pumps and certain sizes of pipes, source of power, and, of course, mother nature. Our growth projects are coming in within acceptable tolerance of our forecasted cost and timing. Slide 10 reflects the expected in-service timing of certain of our larger capital projects.

Let me spend a few minutes and provide a brief update on the status of some of our larger capital projects. Our Eagle Ford pipeline project is progressing on schedule. We expect to have the segment Gardendale in service in the third quarter this year and the segment to Corpus Christi in service by the end of the year. Power is an issue in this area and we probably won't be at 100% of capacity until late 2013; however, we should have capacity to move somewhere between 150,000 and 200,000 barrels a day when the line is placed in service.

We have a significant amount of activity in the Permian Basin. Our Bone Spring area pipelines will be in service by the end of May and in Spraberry we have expansion projects totaling over $100 million that are expected to be completed in the second half of the year. These projects will increase our capacity by approximately $125,000 barrels a day, will increase our operating flexibility, and provide the ability to deliver 225,000 barrels of day into the Longhorn Pipeline system at McCamey.

With respect to take-away capacity in the Permian Basin, we've also completed our Mesa expansion and are now delivering an additional 30,000 to 40,000 barrels a day to the West Texas Gulf Pipeline system, and will be capable of an additional 60,000 barrels a day in West Texas Gulf once their expansion is completed. And lastly, we have largely completed the expansion of our Basin Pipeline system, having achieved approximately 90% of the volume uplift expected. The timing of this expansion has been challenged due to the sheer volume of crude oil nominations we've had on the system. We expect to complete the final minor modifications as we are able to.

Maintenance capital expenditures for the first quarter were $35 million. We expect maintenance capital expenditures for 2012 to range between $140 million and $160 million, and that incorporates the expenditures expected as a result of our recent acquisitions.

Moving on to acquisitions, on April 1 we closed the BP -- the acquisition of BP's Canadian NGL business, and as mentioned before, this transaction was not your typical bolt-on acquisition. It will represent a more challenging integration process. We were able to use the four-month period between signing and closing to fine-tune our integration plan, secure most of the equipment required for the integration, and complete a process to lift most of BP's systems and ship them to a platform that communicates with our systems.

We believe we have made some meaningful progress in our integration efforts and believe that we can substantially complete the integration process by the end of the year. I want to note that we'll continue to pursue both asset and IT optimization of opportunities over the next couple years.

Slide 11 reflects the primary integration milestones and the status of our integration efforts. While our Canadian team remains focused on integration of the Canadian NGL acquisition in the US, we're continuing to pursue strategic and accretive acquisition opportunities.

And with that, I'll turn the call over to Dean to discuss PNG's operating and financial results.

Thanks, Harry.

In my part of the call, I will review PNG's first quarter operating and financial results and our financial position as of March 31, 2012, provide an update on PNG's operations and capital program, and review our second quarter and full year 2012 guidance.

Let me begin by discussing the results we released yesterday afternoon. As shown on slide 12, PNG delivered first quarter 2012 results in line with the guidance we provided in February. Adjusted EBITDA for the first quarter of 2012 of $27.8 million resulted in adjusted net income of $17.1 million and adjusted net income per diluted unit of $0.23. In comparison to last year's first quarter results, adjusted EBITDA, adjusted net income, and adjusted net income per diluted unit for the first quarter of 2012 increased 43%, 40%, and 15%, respectively.

Financially, PNG continues to be well-positioned. Included on slide 13 is a condensed capitalization table for PNG at March 31, 2012, highlighting PNG's long-term debt-to-capitalization ratio of 27.4%, a long-term debt to adjusted EBITDA ratio of 3.9 times, and $131 million of committed liquidity.

Operationally, we are on track to complete our 2012 capital program on time and on budget. Our 2012 expansion capital plan calls for expenditures to range between $55 million and $60 million. We expect to place a total of approximately 16 Bcf of working storage capacity in service in 2012, increasing our average working capacity for 2012 to 84 Bcf, representing an 18% increase over our 71 Bcf average working capacity in 2011. This increase in capacity will consist of a fifth cavern at Pine Prairie that is scheduled to be placed into service in the second quarter, a fourth cavern at Southern Pine that is scheduled to go into service in the third quarter, along with capacity created by incremental leaching activities at both Pine Prairie and Southern Pines, and the full period benefit of capacity brought into service last year.

Overall market conditions for natural gas storage remain fairly challenging with summer/winter spreads remaining in a very narrow band at or near the lower portion of a multi-year range. The recent weakening of natural gas prices in early 2012 has increased the level of volatility somewhat relative to 2011 and has created some short-term opportunity. Although encouraging, this development has not made a noticeable difference in operating results, nor has it changed our overall outlook for 2012. As a result, we continue to position PNG to manage through a continuation of the conditions we have experienced over the last 18 months.

With that outlook in mind, our annual guidance for 2012 is essentially unchanged with our adjusted EBITDA forecast for 2012 continuing to range between $115 million and $125 million, with the midpoint of $120 million. This guidance is shown at the bottom of slide 14 and represents a 12% increase over our 2011 comparable results. For the second quarter, as shown at the top of slide 14, we expect adjusted EBITDA to range from $26 million to $30 million with the midpoint of $28 million.

As depicted by the chart in the upper right of slide 14, we expect relatively steady adjusted EBITDA for the first three quarters of the year with the seasonal increase in the fourth quarter. With respect to distributions, in early April we announced a quarterly distribution of $1.43 per unit on an annualized basis. This distribution, which is payable next week, is equal to the distribution that was paid in February 2012 and equates to a 3.6% increase over the distribution that was paid in May of 2011. As expected, due to the seasonality of our Business, our distribution coverage for the first quarter was slightly less than one-to-one, but was 105% on a four quarter trailing basis, which metric averages out the seasonal aspects.

As represented on slide 15, achieving the midpoint of our guidance for 2012 will also provide 105% coverage of our existing distribution level. As we have highlighted previously, a critical element of our fundamental business strategy is to commit a high percentage of our storage capacity to firm storage contracts. As a result, PNG's distribution is underpinned by a diverse portfolio of third party firm storage contracts with initial terms ranging from 1 to 10 years in length.

For 2012, approximately 90% of our 2012 net revenue guidance is attributable to these third-party contracts, which have an aggregate remaining weighted average tenure of 3.4 years. And as illustrated on slide 16 for calendar year 2012, approximately 95% of our average capacity is contracted with third parties. As contracts roll off and we add incremental storage capacity, this percentage changes. The comparable percentages for 2013 and 2014 are approximately 70% and 50% respectively. In each case, without taking into account new contracts that we intend to enter into in the future but including incremental storage capacity we expect to place into service.

In conclusion, we believe PNG's strategically-located and operationally flexible assets, supportive parent, attractive contract portfolio, solid capital structure, and low cost expansion projects position PNG very well relative to its peers. Additionally, we believe these attributes will provide growth opportunities in the form of continued organic and acquisition related activities.

With that, I'll turn it over to Al.

Thanks, Dean.

The first items I want to review our PAA's recent financing activities, and our capitalization and liquidity following the closing of the BP NGL acquisition. We have been very active since holding our earnings conference call on February 9, as we have raised an aggregate of $1.7 billion of long-term capital. In early March, we completed a public offering of 5.75 million common units which raised $455 million. As we have indicated in recent conference calls, we intend to file a continuous equity offering program that will allow us to raise equity capital on an ongoing basis while minimizing disruption to the market and lowering our cost. We believe this program will enhance our ability to timely finance the equity needs associated with our ongoing expansion capital programs.

In mid-March, we accessed the debt capital markets, raising an aggregate of $1.25 billion through the sale of $750 million of 10-year senior notes and $500 million of 30-year senior notes. The 10-year notes and 30-year notes were priced to yield 3.67% and 5.17% respectively. Following the closing of these transactions, we terminated the $1.2 billion, 364-day liquidity facility that we put in place in December 2011.

In order to close the BP NGL acquisition on April 1, which was a Sunday, we prefunded $1.63 billion into an escrow account on March 30, 2012. Accordingly, although the acquisition did not technically close until the first day of the second quarter, as illustrated on slide 17, PAA's capitalization as of March 31, 2012 is substantially representative of the capitalization immediately after the closing of the transaction. Since we had already secured the long-term financing for the transaction, the only material element of our capitalization that changed between March 31 and closing is that the $1.682 billion of restricted cash in deposits was transferred to BP, and PAA received $120 million of cash as a part of the acquired entity. This is reflected in the table as an increase in our pro forma liquidity.

As illustrated on this slide, even after consummating the BP NGL acquisition and cancelling the $1.2 billion, 364-day liquidity facility, PAA ended the first quarter of 2012 with strong capitalization, credit metrics that are favorable to our targets, and approximately $2.5 billion of committed liquidity including the cash acquired in the transaction. At March 31, 2012, PAA's long-term debt to capitalization ratio was 47%, total debt to capitalization ratio was 50%, long-term debt to adjusted EBITDA ratio was 3.2 times, and our adjusted EBITDA to interest coverage ratio was 7.3 times. I would note that our total debt ratio includes $757 million of short-term debt that primarily supports our hedged inventory. This debt is essentially self-liquidating from the cash proceeds where we sell the inventory.

For reference, our short-term hedged inventory at March 31, 2012 consisted of approximately 15 million barrels equivalent with an aggregate value of approximately $1.1 billion. These amounts do not include approximately 14 million barrels of equivalent of line fill and base gas in PAA's and third party pipelines and terminals that are classified as long-term asset on our balance sheet with a book value of approximately $700 million and a market value of over $1 billion. Adjusted for the BP transaction, the volumes and book value of our line fill and long-term inventory increased by approximately 5 million barrels and $250 million respectively.

The second item I want to discuss is PAA's guidance for the second quarter and full year of 2012, the highlights of which are summarized on slide 18. For more detailed information, please refer to our guidance 8-K that we furnished last night. We are forecasting adjusted EBITDA for the second quarter of 2012 to range from $440 million to $480 million with adjusted net income ranging from $263 million to $312 million, or $1.17 to $1.46 per diluted unit. Including the benefits of the first quarter 2012 over performance, we are forecasting adjusted EBITDA for the year of -- full year of 2012 to range from $1.74 billion to $1.86 billion, with adjusted net income ranging from $1.045 billion to $1.197 billion, or $4.65 to $5.57 per diluted unit.

Although we typically seen stronger results in our supply and logistics segment in the first and fourth quarters, with slightly lower results in the second and third quarters, we expect the favorable market conditions that we are currently experiencing to more than offset the impact of seasonality during the second quarter. As represented on slide 19, giving effect to our recent financing activities, and based on the midpoint of our 2012 guidance for distributable cash flow, or DSF, NLP distributions, our distribution coverage is forecast to be 130% and we would retain approximately $290 million of excess DCF or equity capital.

Before I turn the call over to Greg I wanted to make a few comments related to our credit rating. Our financial growth strategy includes an objective to achieve or maintain mid-to-high BBB credit ratings. In this regard we are very pleased to receive an upgrade from Moody's on March 8 from BAA3 to BAA2 with a stable outlook. Our credit ratings with Standard & Poor's is BBB minus with a positive outlook. We remain committed to our target of achieving mid-to-high BBB credit ratings and intend to continue to prudently manage our capital structure to achieve this important objective.

With that I'll turn the call over to Greg.

Thanks, Al.

PAA delivered very strong performance for the first quarter of 2012, and we believe we are well positioned to continue to perform well throughout the balance of the year and to accomplish our 2012 goals, including delivering year-over-year distribution growth of roughly 8% to 9%. Our guidance for 2012 reflects a continuation of strong industry fundamentals but does not assume that market conditions will be as favorable in the second half of 2012 as they were in 2011, or have been in the first half of 2012. Accordingly, as a result of PAA's proven business model and strategic flexible asset base there is an upward bias to our annual guidance should the favorable market conditions that we are currently experiencing continue throughout the second half of the year.

Looking beyond 2012, we believe PAA is well-positioned to continue to deliver attractive results as we realize the contributions from the $1.9 billion of capital we have invested in 2011, the $2.7 billion that we have already invested or expect to invest in 2012, as well as future years capital programs and acquisitions. As always, we will remain focused on prudently financing our growth while maintaining a solid capital structure and a high level of liquidity.

Prior to opening the call up for questions, I wanted to mention that we will be holding our joint PAA and PNG 2012 analyst meeting on May 30 in Houston, followed by a tour of PAA's Midland assets -- area assets. If you have not received an invitation but would like to attend please constant our Investor Relations team at 713-646-4489. Once again, thank you for participating in today's call and for your investment in PAA and PNG. We look forward to updating you on our activities during our second quarter results call in August and hopefully see many of you at our analyst meeting on May 30.

Operator, we're now ready to open the call up for questions.

Thank you.

(Operator Instructions)

Darren Horowitz, Raymond James.

Good morning, Greg. How are you?

Doing good, Dan.

A couple questions for you -- the first, as it relates to what you referenced in your prepared commentary around everything that you all are doing in the Permian Basin. When you're looking at Permian production forecast trends and you're talking to producers, I think the consensus is that demand for take-away capacity is certainly outpacing what is currently there and possibly currently under construction, especially given the volume nominations that you mentioned on Basin and the upside on Mesa once that West Texas system is expanded.

I'm curious as you look across North and South Spraberry, what you're doing with the Barstow line, how much more incremental CapEx do you think is necessary in order to keep pace with the production ramp over the next 18 to 24 months?

Darren, if you allow me to, I think I'd probably try to extend the time period for the capital expenditures to probably a three- to five-year period. As a practical matter, there's -- any capital that you start spending right now to try and solve a problem is unlikely to have a big impact on that roughly 18-month period that you reference, but more likely to have an impact on a 24-plus month area. Wouldn't you agree, Harry?

Yes, I would.

So I'd probably say this -- I think in talking with the producers and our customers and potential customers, we're looking for a fairly significant increase in net production -- that being net of declines in the area. And as we look out, I think if you can envision the balance between supply and demand, it's going to look a little bit like a saw blade from time to time. There will be times when production exceeds take-away capacity, and then all of a sudden you'll bring on some incremental capacity -- whether that's West Texas Gulf or incremental things that we do in the area or the Longhorn Pipeline -- and all of a sudden you'll have take-away capacity in excess of production. But if the production continues to rise, then it won't last for long and all the sudden you'll end up with another tooth of that production curve moving up there.

So I think there's probably order of magnitude over that three- to five-year period, another $300 million to $500 million of capital that probably is going to need to be spent in that area. Again, I extended your time period a little bit, but hopefully that's responsive to your question.

No, it is. It's helpful. I think looking across your asset base if you just step aside from the Bakken for a minute, this area and a lot of what's going on in the Mississippi Lime seems to be one of the biggest aspects of under-investment relative to production through the drill bit, right?

Yes. I would say this, I think you can look in West Texas and probably convince yourself that production's going to go from -- recently it was under 1 million barrels a day -- currently it's well over 1 million, and 2 million barrels a day is not out of the question.

It's probably one of the most active areas as far as rigs are concerned. Just give you a quick update -- sort of where we see take-away capacity. There's probably been 60,000 - 70,000 barrels a day of take-away capacity added from, say, March to May. When West Texas Gulf gets their expansion completed year-end, there will be another 60,000 to 80,000 barrels a day take-away capacity. Magellan comes on with Longhorn first part of 2013 -- I think they're starting off at 75 and ramping up to 225 through 2013. There's some meaningful take-away capacity that's going to be added in the next 12 to 18 months.

And then just shifting over to the Bakken for a minute -- my last question. I'm just trying to get a sense -- looking at the difference in grade quality pricing of a Bakken barrel relative to others, it seems like that's one of the biggest ARB opportunities in grade and regional [diffs] that we see right now, and I'm wondering -- is the thought process still there to move those barrels into Patoka and then leverage that Yorktown rail facility and possibly expand that beyond that 60,000 barrels a day over time? Is that the longer-term focus, Greg?

Hey, Darren, this is Harry. Let me take a crack at a part of that.

Our first step is going to be moving volume into Patoka through our Bakken North Pipeline project -- should be online by the end of the year. We've got rail capacity at Yorktown. We've got rail capacity at St. James, and we've got a couple other rail projects that we haven't disclosed yet but that are in the works. So we think the combination of moving crude into Patoka and then moving it on rail to some of the coastal facilities is going to be probably the most economic and most efficient way to move the increasing Bakken production.

Yes. Darren, I would also say -- and I may sound a little bit at risk of sounding like one of these news shows that always tries to tell you a little bit of a teaser and more news at 10 -- but one of the things that we're going to try to do at our analyst meeting is demonstrate, or actually highlight, what we think some of the dynamics are that are going to cause disruptions -- not only volumetrically in terms of just take-away capacity, but the quality of the crude is going to play a bigger and bigger role. And so I think what Harry's alluding to is, we don't think there's any silver bullet solution to any one of these areas. Just the opposite.

We think you're going to need maximum flexibility. And you may see crude move east certain times -- during certain situations -- and actually move south or west in other situations. And I think PAA's asset base is probably as well positioned -- and we're biased, but probably better positioned -- than anybody else is, to be able to help balance those markets, to get the barrels from where they're at to where they most likely should be, not just to get them out of the area. And that's part of what we're going to try to highlight on our Analyst Day on May 30.

I appreciate the color, guys. Thanks.

Thank you.

Brian Zarahn, Barclays.

Good morning.

Good morning, Brian.

I guess keeping on the subject of product flows, one of your fellow Capline owners talked about publicly that the reversal is being examined. Can you talk a little more about the thought process behind potentially reversing it? How long it would take, other types of intricacies, to keep serving existing customers?

I can't. The threshhold issue that everybody needs to focus in on -- there are three owners in the pipeline and a little bit like it takes the UN to do anything, everybody has to agree before anybody can do anything. So it will require an alignment of interest between BP, Marathon, and Plains to be able to make anything happen. If you assume that issue away, I think then, quite candidly, it depends on what -- how fast something can happen -- depends a little bit on what the design solution was. If you're simply trying to reverse Capline and all three owners are in agreement, it's actually not that long of a process.

Six months -- if that was all you were going to do is just turn pumps around.

The issue, Brian, is more complex than that, because there are certain several flows that are currently going on Capline that you'd need to reroute that continue to need to go north. So now you're basically saying, do I want to convert existing infrastructure, and it may be a little bit of a gerrymandered solution there to try and get it back up to supply those markets? Or do I need to build a smaller line going north to offload some of the crude off Capline that's currently moving north so that you can then convert the big part of Capline to bring it south. That solution range, depending on what you come up with, could be anywhere from 12 to 18 months to upwards of 24 months-plus.

You also need some additional capacity to bring crude into Patoka in order to really make a Capline reversal make sense.

But from the north.

From the north, yes.

And I know you provide your volumes on Capline, but do you have a sense of the other owners, what kind of volumes we're seeing? I'm trying to get a sense of the utilization of the system.

It's public information out there. I think overall utilization's probably 80%. A little less?

30% to 40%, probably. It varies by month. We have direct access to our shipper volumes, but not direct access to total volumes.

Okay. Then going backing to the Permian -- can you give a little more color on your comments on the Basin expansion? Is it -- you said it's mostly completed. Do you expect, at all, the additional capacity on that system?

Do we expect to add the rest of the capacity?

I wasn't too clear on the comments earlier about -- can you talk a little more about where the Basin expansion is? Is it entirely complete? Or how much, and what's the current capacity on the system now?

Current capacity is 450,000. Well actually it's probably just slightly under 450,000. Our targeted capacity is 450,000. We've got probably 10,000 barrels a day or so of weeks to get it all the way up to full capacity. We'll probably finish those as we conduct scheduled maintenance activities on the line throughout the year. So we don't really want to take the pipeline down to tweak [finished] leaks.

I saw in your release you have Basin volumes almost of 500,000 barrels a day. What -- is the other 50,000 from another system or --?

No, it's the way tariff volumes are measured, okay? We can have volumes come in at Midland, go off at Wichita falls. We can have volumes come in at Colorado City. So they can go in -- we have tariff volumes of 495,000 barrels total. Okay? Our share of Basin space is 87% of the 450,000. So our share is a little under 300,000 -- or 400,000 barrels a day. That's really got volumes for which we're collecting a tariff is embedded in that 495,000 barrels a day.

Okay. Thanks for the color.

Ted Durbin, Goldman Sachs.

Thanks. Just on the guidance there on supply and logistics, you're looking for a pretty significant margin decline here, sort of down $1 a barrel. You've been above $2 a barrel here for the last two or three quarters. I'm just wondering how are you seeing the market change? Is this just being conservative, here? Is there some seasonality you're trying to forecast? But why the big dropoff in terms of the margin guidance?

Well, if you look at it, unfortunately there's a lot of dynamics that goes into that average number. Okay? It includes NGLs. So there were pretty significant margins in our isobutane activities. Propane -- a lot of it is driven by seasonality, and when during the season it was withdrawn. Remember, fourth quarter last year we had a little lower propane margins; first quarter this year we had a little higher. So all that gets sort of baked into the average margin.

We're looking -- we still think we'll have some pretty solid margins in the crude business extending into the second quarter. I don't really have the vision to say that those types of margins will continue into the third and fourth quarter. You've got Seaway reversing -- that's going to take some of the differentials out between the Mid-Continent and the Gulf Coast. You have some of the pipelines expanding in the Permian Basin, which may impact the differentials we see (inaudible) on the Basin. So clearly the second half of the year is going to be a little less -- it will be probably closer to more normal margins than the first half.

Okay. That's helpful.

And then just your thoughts on participating in some of the larger-scale pipeline projects. You've had some multi-billion dollar announcements over the last few months out of the Bakken, through the mid Mid-Continent. I'm just wondering if you've changed your philosophy there? Any desire to participate in the larger-scale projects or do you prefer to stick with the smaller scale stuff that you've historically done?

I think there's a clear bias to staying with the more flexible projects. A lot of these larger scale projects -- and we've seen it happen in a couple of cases in the industry where the bigger projects, by the time you actually get those implemented and engineered, the market's changed. And so it's not to say they're not underpinned by good long-term contracts but, quite candidly, you need more than 10-year contracts to support some of these big expenditures. So I think our bias, Ted, is going to be toward the smaller sizes.

I mean clearly if we were to undertake something like a Capline, that's a big project and it might -- depending on how much new construction that you did to try and move volumes north could you certainly tip into the billion dollar range -- and so we wouldn't back away from something like that. But I think a lot of ours are going to be more in the $200 million to $500 million sweet spot, and those are projects that can be done fast and also have tremendous versatility. There's not probably a pipeline that we've built that we haven't had a backup plan that says, if the market changes, what else could we do with this? And if a refinery shuts down and we're using that line to supply the refinery, that we don't have a backup plan as to how you reverse that pipeline and use it to take away excess production or bring in product.

So it's just harder on those bigger projects to have a backup plan with clarity as to how you're going to do it. So I think you're correct in assuming that our bias is probably not to change our philosophy. That's not to say we wouldn't participate in something, but it's just -- it's going to be the rare exception, not the norm.

Got it. That's it from me. Thanks, guys.

Thank you, Ted.

Mark Reichman, Simmons.

Hello, Mark.

That line did disengage. Next question from the line of Ross Payne, Wells Fargo.

Harry, you mentioned this a little bit before, but Seaway is getting ready to be reversed. What kind of impact do you guys see that having on your systems over the next couple of quarters? Thanks.

I don't think Seaway is going to have a direct impact on our systems other than we'll see more crude flow out of Cushing into the Gulf Coast. I would expect that some of our customers that have a terminal at Cushing would move crude into Seaway. So I think our systems will be relatively unimpacted by Seaway.

Yes. I'd say our systems -- if you're talking about pipeline systems and our terminals -- probably are unaffected, probably the right way. I think we're certainly allowing in our guidance that the impact on our supply and logistic --, it may change some of the margins there. And Ted asked the question, is it a conservatism that we built in there? And the answer is, I'd probably say it's a caution that we built in that probably borders on conservatism. We think there's probably more upside than there is downside to the guidance, which is typically our case of trying to under-promise and over-perform.

So I think the real question is, is what happens when they first open that line up? And I would also just -- personal observation, and that's all it is -- is that I think the quality of the crude that first fills that pipeline as it comes down in the Gulf Coast may be different than the quality of the crude that fills it six months to a year from now. Just because I think there's some balancing of markets that's having to take place with all this pent-up crude that's in Cushing.

Okay. Thanks, Greg. So basically supply and logistics may fill some of this, with the basis differential dropping but that's already plugged into your guidance.

The anticipation of that is baked into our guidance, correct.

Perfect. Thanks.

John Edwards, Credit Suisse.

Yes, good morning everybody. Just a quick question. Greg, maybe if you could talk a little about this -- I don't know if you'll delay this until your Analyst Day but just -- you raised your CapEx guidance this quarter and just what's a reasonable run rate going forward for us to be thinking about? Thanks.

I think on a run rate basis we're probably still talking about something in the area of $500 million to $700 million range. I think, for example, if we're able to grow the capital budget in 2012 by accelerating some things or adding new projects to it, that may carry over into a higher number for 2013 and then getting back, though, probably to that $500 million to $700 million range for 2014. And if we cannot accelerate some of these projects into 2012, that probably means 2013 is a little bit higher than it would have been. So probably $700 million-plus in 2013 is a number that you would want to put out there almost irrespective. But, again, we're not trying to say we can see visibility for a never-changing crude oil environment for the next five years.

I think we're going to see some head fakes and some dips and spikes come out of this. I just think PAA's going to be as well positioned as anybody to implement some of the highest return projects by simply leveraging our existing asset base. I think it's -- we're going to grow and we're going to grow pretty impressively, but we kind of start putting a little bit of fuzziness on just how big that could be because that's all upside from where we're at.

All right. Thank you very much.

Thanks, John.

Kurt Lahner, (inaudible).

Good morning and thank you. I just wanted to follow up relative to the BP acquisition. You gave us the integration milestones, also out of that -- wanted to ask your impressions relative to operating and financial factors that you're finding as you get more and more into that. Other companies that are involved in and around that area, specifically Empress, have recently reported disappointing results given low gas prices, volumes, propane prices, and the like. If you could give us any kind of an update as to what you're finding there operationally and financially, I'd appreciate that. Thank you.

Thanks, Kurt. I would say there's no question that conditions in Canada in general and around Empress, in particular, are probably extremely challenging. We dialed in pretty much those in anticipation of very difficult conditions into our guidance, so I would -- not our guidance, but our expectations, our acquisition modeling -- and if you may recall from that conference call that we had announced, we basically said we're going to be changing the way that those assets are managed. And so a lot of what we're planning on doing hasn't deteriorated at all. In fact, if anything I'd say we're probably as excited or more so about what we think we can do with these assets going forward than we were when we announced the acquisition.

Again, no question, it's very challenging around Empress and it can have a drag on not only our results but others in the area. But we anticipated that drag when we made the acquisition, did our modeling; and we built that drag into our forecast for 2012, which is included in our guidance.

Understood. And if I could just have a quick follow-up here relative to it -- does any of that relate to contractual control with BP as the former owner, or anything else that you've done to restructure contracts to make them more fee-based?

No, not really. A lot of what we're doing is just a different way we're going to be managing the assets. I think we're certainly open to a little bit more fee-for-service base. There's a lot of storage, a lot of pipeline capacity and other facilities that we have that just were not previously made available to competitors or to the public. It was more run as a pure proprietary system. And so it's really rationalizing those assets, especially when you realize, Kurt, that in the US we're going to be -- we're certainly net long natural gas and we're net long natural gas liquids, and if you take away the 49th parallel, that's one market. So the question is, how do you rationalize 22 million barrels of storage and 240,000 barrels a day of fractionation and pipeline capacity? And we think that makes a lot of sense to basically open those assets up to more of a fee-based commercial approach as opposed to a proprietary trading approach.

Absolutely. Thank you very much.

Kurt, let me just add -- what others have said is true. Volumes -- gas volumes are down. Fraction premiums are up. Propane prices are soft. And so anybody that's in that Empress complex is seeing weaker margins than they've seen historically.

We're no different. I think what Greg was saying is we had baked most of that into our forecast and our assumptions for 2012. So we don't have historicals to compare it to, unlike some of the other operators, but it is softer but it's just been baked in.

Okay. Thank you.

(Operator instructions)

Selman Akyol, Stifel Nicolaus.

Thank you. Good morning. Just as a follow-up on the BP question there -- you said you took over 5 million barrels of inventory there. And I was just wondering how that related to your expectations going into the transaction, and how quickly you'll be able to work through those?

Yes, actually the -- point of clarification -- when we actually signed the agreement, I think we had right at about 10 million barrels of inventory, 5 million barrels of which we considered to be line-filled or long-term. In other words -- so it's kind of a neutral inventory position that really don't go below that level. So that was the 5 million barrels that Al mentioned in his part of the presentation was that simply gets added to what we have at PAA, which was already about 14 million barrels of line fill that it takes just to run the business. And so that 5 million barrels is additive to it. The other 5 million barrels -- a portion of that was worked down between the October 1 effective date, through closing, and the balance of that has been fully hedged.

So there really is no excess inventory to manage as we sit here today. There certainly was -- it was managed by BP during the period from October 1 through the effective date, through the closing on April 1, and then when we took over we basically hedged the balance of that.

Alright. Thank you very much.

Thank you.

At this time we have no additional questions in queue.

If there are no additional questions we will end the call. I would, though, encourage those again to join us for our May 30 analyst presentation, and we look forward to updating you, if you're not there, on the next call. Thank you very much.

Ladies and gentlemen, that does conclude your conference. We do thank you for joining, while using AT&T executive teleconference. You may now disconnect. Have a good day.