Plains All American Pipeline LP (PAA) 2013 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the Plains All American Pipeline and PAA Natural Gas Storage first-quarter 2013 results conference call. For the conference, all the participants are in a listen-only mode. There will be an opportunity for your questions, instructions will be given at that time.

(Operator Instructions)

And as a reminder, today's call is being recorded. With that being said, I will turn the conference now to the Director, Investor Relations, Mr. Roy Lamoreaux. Please go ahead, sir.

Thank you, and good morning. Welcome to Plains All American Pipeline and PAA Natural Gas Storage first-quarter results conference call. The slide presentation for today's call is available under the conference call tab of the investor relations sections of our websites at paalp.com and 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, all the incentive distribution rights, and approximately 62% of the limited partner interests in PNG, which accordingly is consolidated into PAA's results.

In addition to reviewing recent results, we will provide forward-looking comments on the Partnership's outlook for the future. In order to avail ourselves of the Safe Harbor precepts that 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 EBITDA. The non-GAAP reconciliation sections of our website, reconcile certain non-GAAP financial measures to the most directly comparable GAAP financial measures and provide the table of selected items that impact comparability of the Partnership's reported 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 will turn it over to Greg.

Thanks, Roy. Good morning, and welcome to everyone. Yesterday, after market close, PAA reported first-quarter results that can justifiably be described as outstanding. First-quarter adjusted EBITDA totaled $739 million, which exceeded the midpoint of our guidance range by $124 million or 20%, and the high end of our guidance range by $99 million, or 15%.

In comparison to last year's first-quarter results, adjusted EBITDA, adjusted net income, and adjusted net income per diluted unit increased by 57%, 64% and 59% respectively. A summary of our first-quarter results is reflected on slide 3.

As reflected on slide 4, these results mark the 45th consecutive quarter that PAA has delivered results in line with or above guidance. Additionally, last month, PAA declared a quarterly distribution of $0.57 per common unit, or $2.30 per unit on an annualized basis payable next week. This distribution represents a 10% increase over the Partnership's distribution paid in May 2012, and a 2.2% increase over the Partnership's distribution paid in February 2013.

Distribution coverage for the quarter was approximately 200%. As reflected on the bottom of slide 4, PAA has increased its distribution in each of the last 15 quarters, and 34 out of the last 36 quarters.

Yesterday evening we also furnished operating and financial guidance for the second quarter and full year of 2013. Sequentially our guidance for the second quarter reflects the impact of routine seasonality in our NGL business, as well as our view of the impact that recent and pending infrastructure projects will have on basis differentials, and on margins in our Supply and Logistics segment.

As we discussed in our last conference call, for the remainder of the year, quarterly comparisons for the Supply and Logistics segment will be challenging as a result of the very favorable market conditions experienced during comparable 2012 periods. Conversely, segment comparisons for the Transportation and Facility segments for the latter half of 2013 should show continued growth as a result of our capital investments.

In the aggregate, we expect full-year adjusted EBITDA comparisons will be favorable. In that regard, yesterday we increased the midpoint of our full-year 2013 adjusted EBITDA guidance by $135 million, or 7%, to $2.16 billion, which exceeds our actual results we reported for 2012, which was a year that included significant contributions for our Supply and Logistics segment due to favorable market conditions. PAA continues to execute well in this environment and we are on track to meet or exceed our 2013 goals, and to position PAA favorably for 2014 and beyond.

During the remainder of today's call, we will discuss the specifics of PAA segment performance relative to guidance, our expansion capital program, our financial position, and the major drivers and assumptions supporting PAA's financial and operating guidance. We will also recap -- also address similar information for PNG, and at the end of the call I will provide a recap, as well as some comments regarding our outlook for the future. With that, I will turn the call over to Harry.

Thanks, Greg. During my section of the call, I will review our first-quarter operating results compared to the midpoint of our guidance, the operational assumptions used to generate our second-quarter guidance, and I will provide an update on our capital program and our acquisition activities.

As I've shown on slide 5, Transportation adjusted segment profit was approximately $175 million, or approximately $3 million below the midpoint of our guidance. Volumes of 3.64 million barrels per day were in line with our guidance, and adjusted segment profit of $0.53 per barrel was slightly below our guidance. That was primarily due to higher-than-forecasted operating expenses.

With respect to our operating expenses for the quarter, Integrity management costs were lower than we forecasted, but they were more than offset by costs related to response from remediation activities associated with a couple of pipeline releases, and costs to test certain idle pipeline segments to see if they can be placed into -- returned to service.

The first-quarter costs related to the pipeline releases, and to the testing of the idle pipeline segments, totaled $16 million and should be nonrecurring. However, the lower spending related to our Integrity management efforts were timing-related and the costs are expected to be incurred later in 2013.

Adjusted segment profit for the Facility segment was $156 million, or approximately $6 million above the midpoint of our guidance. Volumes of 119 million barrels per month were slightly below our guidance, as rail volumes were less than forecasted. That was primarily due to weather and scheduling related delays.

Adjusted segment profit of $0.44 per barrel was above our guidance, primarily due to volumetric gains at our NGL storage facilities, and increased revenues associated with processing improvement at our Fort Saskatchewan facility. I'll note that volumetric gains or losses at our NGL storage facility are only recognized after our cabin is empty. This can occur at various times during the year, but frequently occurs at the end of the storage season, once withdrawals are completed.

Adjusted segment profit for the Supply and Logistics segment was $407 million, or $120 million above the midpoint of our guidance. Volumes of approximately 1.15 million barrels per day were slightly above our guidance, and adjusted segment profit of $3.95 per barrel was significantly above our guidance.

Overperformance in this segment was primarily driven by crude oil basis differentials that were wider than we forecasted, particularly the differential between WTI at Midland and Cushing. The quarter also benefited from a wider-than-forecasted LLS to WTI differential, and wider differentials between WTI and several of the Canadian grades.

Let me move now to slide 6 and review the operational assumptions used to generate our second-quarter 2013 guidance furnished yesterday. For the Transportation segment, we are forecasting volumes to average approximately 3.68 million barrels per day, adjusted segment profit of $0.55 per barrel, and total adjusted segment profit of approximately $185 million.

I will note that in the second quarter we expect volumes on certain of our Canadian pipelines to be lower than first quarter, as we temporarily take certain line segments out of service during the high water season, and while we replace a few water crossings.

For the Facilities segment, we expect average capacity of 122 million barrels equivalent per month, adjusted segment profit of $0.38 per barrel, and our total adjusted segment profit midpoint is $140 million. The decrease from first-quarter results reflect a seasonal decrease in our gas storage business, as well as the fact that we do not expect to experience the NGL volume gains recognized in the first quarter.

For the Supply and the Logistics segment we expect average volumes of approximately 1 million barrels per day. Our forecast for adjusted segment profit is $1.19 per barrel, and total adjusted segment profit is $109 million. Second-quarter guidance reflects lower seasonal sales volumes in our NGL business, as well as the expectation for narrower differentials in crude oil.

As Greg mentioned earlier, infrastructure additions in many of the resource plays are beginning to be placed into service in the second quarter, and are relieving some of the transportation constraints that caused the wider differentials we saw in previous quarters.

Let me now move on to our capital program. As shown on slide 7, we have added several new projects in our last earnings call, and as a result, we have increased our 2013 expansion capital plan by $300 million, to a revised target of approximately $1.4 billion.

Slide 8 provides an update on the expected in-service timing of some of our larger projects. I will note that in the aggregate, our costs are in line with our forecast, however we are seeing permitting and right-of-way matters extend the timing of the in-service date on several of our projects.

Let me now provide an update on some of our major projects. In the Mid-Continent, we are on schedule for Phase 1 of our Mississippian Lime pipeline to be in service in July of this year, and for the Phase 2 extension to Coldwater, Kansas, to be in service in the fourth quarter.

Recently, we finalized plans to construct a 95-mile extension of our Oklahoma pipeline system to Reydon, Oklahoma. The pipeline extension will add 75,000 barrels per day of capacity, and will provide access to increasing production at the Granite Wash, Hogshooter and Cleveland Sands producing areas in western Oklahoma and the Texas Panhandle.

The extension is supported by long-term producer commitments, and is expected to be in service by the end of the first quarter of 2014. A description of these projects is included on slide 9.

Last month, we announced that we are proceeding with the construction of the Cactus pipeline, a 310-mile 20-inch crude oil pipeline that will extend from McCamey, Texas, to Gardendale, Texas. A description of the project is reflected on slide 10.

The pipeline will initially provide 200,000 barrels per day of takeaway capacity from the Permian Basin and will connect to our Eagle Ford joint venture pipeline at Gardendale, which will then provide the access to Gulf Coast refiners, as well as to our Gardendale route terminal and our dock facilities at Corpus Christi. We have signed a letter of intent with the producer for the majority of the capacity of the line, and we are in discussions with other potential shippers for the balance of the capacity. We expect this line to be in service in the first quarter of 2015.

In south Texas, we've completed the segment of our Eagle Ford joint venture pipeline from Gardendale to Corpus Christi. The connection to dock facilities at Corpus Christi is expected to be completed by the end of the second quarter, and the extension to the pipeline to a connection with Enterprise at Lyssy is expected to be in service in the third quarter of 2013.

In the Sprayberry, we've recently completed the expansion of our trunk line system, and several producer connections. And this is a very active area. We still have a number of extensions in progress, and we expect to be completing these connections throughout the remainder of the year.

In Canada, we acquired a significant land position in the Fort Saskatchewan area that will provide the opportunity to expand our storage capacity in that area. In addition, we recently announced an open season for the proposed Western Reach pipeline. This is a pipeline that would be a joint venture system with Keyera that will transport C3-plus and condensate to our Fort Saskatchewan facilities from processing plants in both the Gordondale area in northwest Alberta, and the Simonette area in western Alberta.

The open season will terminate on May 15, 2013, but we won't be in a position to provide any more information on this proposed project until we see the results from the open season.

With regard to rail and loading terminals, permitting delays have extended the in-service date at a couple of our facilities. Currently, we expect our Yorktown, Virginia, facility to be placed in service in the third quarter this year, and our Tampa facility to be completed in the fourth quarter.

We are also continuing to develop our unloading facility in Bakersfield, California. And this is a project we expect to be placed in service in 2014, and will complement our existing pipelines in California.

Maintenance capital expenditures for the quarter were $44 million. We expect 2013 maintenance capital expenditures to range between $170 million and $190 million.

I would like to point out that during 2013, we expect to direct about $30 million of our maintenance capital towards placing certain water crossings, and increasing the depth of coverage at these locations, particularly in Canada, where you can have high water levels due to runoff from melting snow.

And lastly, on the acquisition front, we are active; we're just not in a position where we can discuss the specifics of any of our potential opportunities. So, with that, I will turn the call over to Dean.

Thanks, Harry. In my part of the call, I will review PNG's first-quarter operating and financial results, our financial position as of March 31, 2013, and our financing activities. I will also provide an update on PNG's capital program, and review our second-quarter and full-year 2013 guidance.

Let me begin by discussing the results we released yesterday. As shown on slide 11, PNG reported first-quarter adjusted EBITDA of $31.6 million. This amount exceeded the midpoint of our guidance range by $1.6 million or 5%. In comparison to last year's first-quarter results, adjusted EBITDA, adjusted net income, and adjusted net income per diluted unit increased by 13%, 14% and 13% respectively.

These results mark the 11th consecutive quarter that PNG has delivered results in line with or above guidance, and were underpinned by our fee-based firm storage contract, combined with higher than forecast oil revenues associated with liquids removal activities at our Bluewater facility.

With respect to distributions for the first quarter of 2013, we declared a quarterly distribution of $0.3575 or $1.43 per unit, on an annualized basis, which is equal to last quarter's distribution. Financially, PNG continues to be well positioned.

As shown as slide 12, as of March 31, 2013, PNG had a long-term debt-to-capitalization ratio of 29%, adjusted EBITDA-to-interest coverage of 13.2 times, a long-term debt-to-adjusted-EBITDA ratio of 4 times, and $131 million of committed liquidity.

In March, PNG filed a $75 million continuous equity offering program and through the end of April, PNG had sold 1.27 million units, raising approximately $27 million of equity capital, including the general partner's matching contribution. We believe this program is the most cost efficient, and least disruptive way to raise equity funding for our ongoing capital investments, and fine-tune our liquidity, balance sheet and credit metrics.

Operationally, we are on track to complete our 2013 cavern expansion activities on time and in line with our targeted budget range. In April, we brought approximately 4 Bcf of storage capacity into service, primarily at Southern Pines and Pine Prairie. Through continued leaching activities at both facilities, we plan to create an incremental 4 Bcf of low-cost capacity during the remainder of the year.

In addition to these capacity expansion activities, we remain active in pursuing opportunities to extend and expand our service offerings to meet recent and potential changes in the gas markets, and better service our customer base.

With regard to guidance, as shown on slide 13, we are forecasting midpoint adjusted EBITDA of $26.5 million for the second quarter, and $120 million for the full year. We expect distributable cash flow of $22.6 million, and $108.1 million for the second quarter and full year of 2013, respectively. As expected, due to the seasonality of our business, we project distribution coverage for the second and third quarters of the year to dip below one to one, with implied distribution coverage for the full year 2013 totaling approximately 102%.

For more detailed information on our 2013 guidance, please refer to the Form 8-K that we furnished yesterday evening. With that, I will turn it over to Al.

Thanks, Dean. During my portion of the call, I will review our financing activities, our capitalization and liquidity, as well as our guidance for the second quarter and full year of 2013.

Our finance activities this quarter were limited to our continuous equity offering program. PAA sold approximately 2.4 million units in the first quarter, raising net proceeds of approximately $131 million.

As illustrated on slide 14, PAA ended the first quarter with strong capitalization, credit metrics that are favorable to our targets, and $2.8 billion of committed liquidity. At March 31, 2013, PAA had a long-term debt-to-capitalization ratio of 46%, a long-term debt-to-adjusted EBITDA ratio of 2.9 times, and adjusted EBITDA-to-interest coverage ratio of 9.6 times.

Slide 15 summarizes information regarding our short-term debt, hedged inventory and line sales at quarter-end.

Moving on to PAA's guidance, as summarized on slide 16, we are forecasting midpoint adjusted EBITDA of $435 million and $2.16 billion for the second quarter and full year of 2013 respectively. This updated full-year 2013 guidance reflects a 7% increase in adjusted EBITDA, and an 8% increase in implied DCF from our guidance furnished in February of this year.

As Harry mentioned, our guidance assumes less robust market conditions than we experienced in 2012 and in the first quarter of 2013, and thus is closer to baseline expectation for our Supply and Logistics segment profitability for this part of the year. Our guidance also assumes a mid-year sale of certain refined products pipeline assets. For more detailed information on our 2013 guidance, please refer to the Form 8-K that we furnished yesterday.

As represented on slide 17, based on the midpoint of our 2013 guidance for DCF and distributions to be paid throughout the year, our distribution coverage is forecast to be approximately 135%, well above our minimum targeted coverage of approximately 105% to 110%. Thus enabling PAA to retain approximately $400 million of excess DCF or equity capital.

Given our strong capitalization at quarter-end, the projected refined products pipeline sale, and our projection for retained DCF for the balance of the year, we have effectively pre-funded our 2013 expansion capital program, despite having increased the size of the program by $300 million to $1.4 billion.

Additionally, as a result of our continuous equity offering program, we are also well positioned to finance moderately sized acquisitions, and any further increase in our 2013 capital program. As a result, as we discussed last quarter, absent significant acquisition activity, we do not expect to execute an overnight or marketed equity offering during 2013. With that, I will turn the call over to Greg.

Thanks, Al. PAA delivered outstanding first-quarter results, and is very well positioned to continue to deliver strong baseline growth throughout the balance of the year, and above baseline performance if market volatility and wide differentials persist.

Looking forward, we expect to realize additional contributions in the years ahead from nearly $5 billion of organic and acquisition capital invested in the past two years. We have a strong asset footprint in substantially all the regions in North America where crude oil production is expected to grow.

Furthermore, our multi-billion dollar project portfolio provides visibility for significant organic investment over the next several years, and we will remain active in pursuing acquisition opportunities. 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 our call up for questions, I want to mention that we will be holding a joint PAA and PNG 2013 analyst meeting on May 30 in New York. At this meeting, we will share our views on the industry environment for the next several years, discuss our position with respect to such environment, and provide a more deeper dive into our activities than is possible during our quarterly conference calls or investor conferences. If you have not received an invitation, but would like to attend, please e-mail our investor relations team at info@paalp.com.

Thank you for participating in today's call, and for your investment in PAA and PNG. We are excited about our prospects for the future and we look forward to updating you on our activities at our analyst meeting, and on our next call in August. And John, at this time, we'd open the call up for questions.

(Operator Instructions)

And first on the line, I have Darren Horowitz with Raymond James.

A couple of quick questions. First, with regard to that new crude oil pipe capacity coming online and the impact on regional basis differentials that you and Harry alluded to, and I realize this is a tough question, but is there is any way that you can quantify, as you guys see it, the impact on basis contraction around your S&L margins for the back half of this year?

I think the best way to show it is what we reflected in our guidance. If you try to break down, the first quarter there was obviously a lot of seasonality in there as well as some basis differentials. But, I think last year we estimated that about probably, maybe, what was it Harry, around $300 million plus or minus was related to market opportunities that were associated with some of the congestion in the system.

And so a lot of that is going to be relieved volumetrically, Darren, as we go forward, and again we had hopefully given enough of a head's up to everybody that around April 1 this year, we thought the tides would start changing.

I will point out, and we will talk about it more at the analyst meeting, that there is a shift underway between volumetric bottlenecks, and then ultimately, quality displacement issues that we think probably will create some additional opportunities that may replace some of the opportunities we have been experiencing. It's just pretty early to call that.

We have not forecasted that in our base line, so we don't rule it out. In fact, we are positioning to be able to balance the market and take it, advantage, capitalize on those opportunities. But at this point in time, it's really hard to forecast what that amount is going to be. So, I would take what we got forecasted for the rest of the year as representative of the base line performance.

Okay. And then, my last question, and I know that we talked a little bit about it last quarter. But, has anything changed, from your perspective, with regard to handling condensate production growth, both out of the Eagle Ford and the Permian? I mean, it seems you could leverage the rail capacity at Gardendale, and more importantly, you've got that dock capacity at Corpus where you could probably move condensate east or maybe even, theoretically, up the Mississippi corridor. So I'm just wondering how you guys are thinking about it, and how you are thinking possibly about adding some splitting capacity or additional dock capacity?

Well, I think we've announced the projects that we think make the most sense to handle, not only issues with condensate, but just a wave, if you will, of light sweet crude in excess of regional demand. And the additions we are making to Bakersfield, to Yorktown, and some of the other connections that we are making, clearly the ability to connect west Texas with our assets in south Texas, which gives us access to different markets as well as rail capabilities either to California or to the East Coast really positions us to do everything you are mentioning with respect to condensate.

I would describe condensate as being a very dynamic market, and we are going to see changes that will ripple across the industry a little bit, as we push out the last of the light sweet crude imports, including any condensates that come into the Gulf Coast. And then, we are going to have an excess of light sweet and condensate in the Gulf Coast that's either going to be railed or put on barge or, as we will talk about at our analyst meeting, it's going to take really an all-of-the-above type solution to having an excess of light sweet crude there. And differentials are going to be the economic equalizer for the volumes that are in the wrong place. Harry, do you want to comment on any of that?

Yes, so, the only thing I would add is I think there's been a lot of talk about splitters around the country, there's probably going to be some locations where a splitter makes sense. I don't think we are in a position right now to discuss whether we would be involved in a splitter or just in transportation. But, certainly with increasing condensate production, there probably will be some additional splitting capacity in the US.

Darren, I'd just point out one other thing. We still, with the amount of production, the increase we have, we still -- North America imports about 6.5 million barrels a day. And a lot of that is more medium grades or heavy and sour. And again, we can displace part of that with lighter production. It just takes an economic incentive to the refiners to do it, or to relocate that product from one place to another within the US.

I appreciate it, guys. Thanks.

Steve Sherowski with Goldman Sachs.

I'm just trying to drill down a little bit more into your Supply and Logistics margin guidance for the second half of the year? It looks like, at least in your 8-K, you are pointing towards $0.76 versus $3.95 this quarter and $1.19 next quarter. I'm just wondering what are your assumptions driving that decline, just because it is pretty meaningful? I mean, are you just assuming normalization in overall crude spreads or is there one in particular that you think is going to contract more than the others, that you are more sensitive to?

They all seem to be contracting (laughter) BTI, for instance, Midland, Cushing in the first quarter, January and February were $10 differentials and today it's positive. Then take a look at some Canadian grades. You had Canadian heavy grades that were a lot weaker than they are today. And you had some that were $30, $40 differentials, and today they are $15, $20 differentials. So, LLS is coming from $20 to $12 range, $10, $11. They all had some impact on us.

Yes, hopefully, Steve, what you are seeing out there is we're showing what we call, again, our base line against a normalized backdrop. So I think your term is correct. I think we are all reaching to find out what the real true normal is, because it's not something that's been seen in a while. I wouldn't say that we are necessarily, quote, conservative, but I think we are pretty realistic. And I would probably say there is more upside than there is downside to our forecast. But, at this point in time, it's just really hard to nail with any more precision.

The other thing to remember is that our NGL segment is included in our NGL activities. So that's going to be seasonable. It's going to impact the first quarter and the fourth quarter, and it comes off in the second and third quarter.

Okay, no, that's helpful. And, if I could just get some more insight into Cactus. There is some views out there that there is going to be excess pipeline capacity coming out of the Permian and also the Eagle Ford. What really drove your decision to pursue this project? Was this primarily just producer induced, or have you changed your view on Permian and Eagle Ford production? Your longer-term growth forecast.

No change, really, in the Permian and Eagle Ford. It's really trying to balance the quality market issues.

And a lot of what the crude that we will be moving down that line, will be a little bit, when I say heavy it's a relative term, and a slight bit more sour. And so, you are really trying to get the right crude to the right markets. In some cases, the barrels that we will be shipping down there will displace foreign import barrels of the heavier, more sour crudes that would normally still have come into the Gulf Coast through the Corpus Christi market.

I think the other thing is, we went through a period of time where you had a ramp up in production and not enough pipeline capacity in either one of those areas. That spurred a lot of pipeline activity.

I think for a while here, the pipeline capacity is going to be ahead of the production, and over time we think you will see a balance between the pipelines and the production business. In the next 12 months or so, I think you are going to see more pipeline capacity than production in both those areas.

Okay, thanks. And just a final quick modeling question. Could you remind me what the EBITDA contribution was for the two pipelines that you are planning to divest?

On an annual basis, it's probably between $15 million and $20 million.

Combined?

Yes.

All right. That's it for me. Thanks a lot.

Brian Zarahn with Barclays.

I guess I will follow up on the Cactus pipeline. You said the majority of the capacity is under LOI. Can you give us a little more color as to how much? And also, if there is demand long term, how much could the capacity of the line be increased?

At this point in time, what we would say is majority equates to more than half, and we are real close on some other commitments on there. I think if we increased the pump capacity (multiple speakers)

About 280,000 barrels a day.

So, you've got about 40% increase in capacity over what we will start with, if it's needed.

And in terms of the capacity expected under contract, are those longer-term contract, would that be a long-term contract?

Yes.

Okay. And on the topic of narrowing crude differentials. Any impact to your crude rail terminals?

Not really against our acquisition or construction economics. It may take away some of the upside that you would have experienced during periods where we also engage in the merchant activities to be a shipper on our own lines. But nothing, from an adverse level, to the investments that we've made.

Yes, so we expect to see the volume continue through the rail terminals. It's just, on the commercial side, to the extent we are moving those volumes, the margins have narrowed.

And then on your raised 2013 expansion CapEx. Any change to your long-term average expansion CapEx?

Well, we are always a little bit more cautious once we get out of the current year. We are feeling more and more comfortable that between what we've got to invest this year, that will actually carry over into next year, that we are base loading next year. If you had to give it a range today, it might be $200 million higher than what we would have discussed at the beginning of the year. I think we had forecast around $700 million in out years. Today, that number is probably closer to $900 million to as much as $1 billion for 2014. But, again, it's pretty preliminary as this point in time, Brian.

But, the bias has always been to the upside as we develop and actually crystallize some of these projects. Clearly Cactus is an example. There is only a portion that will get spent in 2013. The balance of it will get spent in 2014. So it makes up a fairly high component.

We try to provide directional charts with the check marks showing when these projects are coming onstream. Clearly, there is some of them start off near a 50% to 75% run rate. Others start a little bit lower, some a little bit higher. But, the good news is that we feel real good about the momentum, if you will, of the capital investments we've made carrying through 2014, '15 and even into '16.

That's helpful. And the last one for me, from an industry perspective, can you comment on more recent MLP consolidation activity?

Only to the fact that we probably made a prediction of it three or four years ago, and it's been a little bit longer coming. And since we made that prediction, by the way, instead of the universe shrinking, it's grown. So, it just proves that we don't forecast everything with great precision.

But I think there is certainly a lot of consolidation, Brian, that makes sense. It's hard to do when the capital markets are as robust as they currently are. If there is a contraction in the capital markets, I think you will see an increase in consolidation.

Stephen Maresca with Morgan Stanley.

First question, on guidance for the second half of this year, and acceleration in the transportation adjusted EBITDA, and just some color into that? I get some uplift on Permian basin volumes, but also see a jump a little bit in profit per barrel. What's the driver there?

Some of it is going to be in the timing of the expenses that Harry mentioned. We schedule some of this work, and it gets pushed around a little bit. So, I think by the time you get to the end of the year, you are seeing what I'd call more of a normalized rate on that as opposed to we had a couple of releases in the first quarter that replaced some expenses we thought were going to be incurred in the quarter, and got pushed to later quarters.

By the end of the year, though, we are pretty much looking at, like I say, a normalized level, realizing that by the time we get there, Stephen, there may be shifts in that. But overall, I would say it's just the impact of projects that will be coming onstream. As we pick up those volumes, and the variable expense associated with that will be pretty minor, and a lot of the fixed expenses are already built into our outlook.

And, if you look at April 1 to the end of the year, part of that is driven by the refined product pipelines. We initially had expected that to close by the end of the first quarter. Now, we are forecasting by the end of the second quarter. So, that has a little bit of EBITDA impact, relative to our earlier guidance.

Okay. And then Harry, I think you mentioned something along the lines of permits and right-of-ways extending time to completion on projects. How much time is it extending it, and is this impacting all projects or specific areas or type of asset?

No, and it's not tremendous. It's gotten the, say, west Texas, on the Sprayberry pipeline, the connections will probably be delayed 90 days or so, versus when we originally thought they would be online. It's just primarily dealing with right-of-ways, there's so much going on, land owners are more sophisticated and it's delayed the progress a little bit.

The permits have mainly been around some of the rail facilities at Yorktown and Tampa, the permits took a little longer, probably delayed those projects by 90 days as well. So nothing real big.

But, as you know, any time you have an extension it costs a little bit more. On balance when we look at our programs, Steve, the cost increases are, in most cases, more than offset by cost decreases where we've executed a little bit ahead of schedule. So, in total the program economics really haven't changed. There is just a little bit of a delay in timing on some of these as to when they will come on stream. And again, not six months or nine months or a year, but more in the 90 days to 120 days.

Okay, thanks. And then final one for me, I guess for you, Greg. Appreciating that you guys have actually been accelerating growth, in terms of distribution payout, while also having very heavy distribution coverage. Have you thought about or would you consider ramping growth even more in the payout, even if it is something that is more of a one-time growth, where you grew really strong for 2013, but went back down to a base line of 10% for 2014 and beyond because you felt comfortable there. But given how much growth you have, and coverage that you have right now, have you thought about that?

I can answer the question have we thought about it, absolutely.

All right, maybe I can rephrase it, what do you think about it?

I didn't think you'd let me off that easy.

Never answer just a yes or no question, right?

Steve, I think we constantly try to balance the level of distribution growth that it takes for us to be competitive with our peers, and to achieve what we think is the optimal cost of capital. There is a point of diminishing returns. If we raise the distribution too rapidly, and it doesn't result in a correlating adjustment to our cost of capital, because we are consumers of capital on balance.

And so right now, the 9% to 10% range feels comfortable as being what I'd call best in class for large cap, low risk, MLPs. And I think our unit price and trading yield reflects that best in class performance. When you look at it, and we are retaining this year close to $400 million, last year it was close to $600 million, what that does is it allows us to save capital costs because we distribute that. And then, because we are growing the business, we ask for it back.

The friction costs on that can be fairly significant. And so we are saving that friction cost for the benefit of the unit holders. We are also, then, staying away from overnight and market equity offerings, which we think are disruptive to the consistent increase in the unit price, because it tends to create disruptions in the market.

So, we're constantly trying to fine-tune that balance. If we felt that it took more distribution growth to be competitive with our peers and achieve the optimal cost to capital, we certainly have that horsepower to be able to do it in our coverage. But right now 9% to 10% feels fairly appropriate, if not at the top of the class, so to speak, within the risk profile that we provide.

Okay. That makes sense. Thanks for the color.

And if we can do that for multiple years, and we haven't given extended levels, I think that's going to be best in best in class.

Yes.

Ethan Bellamy with Baird.

Good morning, guys. Obviously, an epic quarter on Supply and Logistics. Everybody is banging away on new infrastructure. So, I want to ask a counter-cyclical question which is, do you think the crude differential will ultimately go the way of gas differentials? And if so, where does that leave you guys?

Certainly directionally we are seeing some move of differentials tidying up. I think the major difference, Ethan, between the oil and gas is gas, once the shale revolution hit and they were so successful they took gas prices from $13 all the way down to $2, at one point, and caused a tremendous build in infrastructure. And the fungibility of gas then once with excess infrastructure, and a cap of what production can grow because of the economics, it really evened everything out.

On crude oil, it's a much more regional issue. And, on top of that we are still importing 6.5 million barrels a day to North America, the majority of that coming into the US, probably close to about 5.9 million. So we still have a ways to go before we reach the displacement equivalent there. Whereas on natural gas, it didn't take much.

Only about a 5% of the total consumption was being imported. Now they are talking about exporting. I don't think we are going to talk about exporting crude for quite a few number of years in terms of those types of volumes. Any exports would really be related to try and balancing the quality issue that we talked about earlier. It would really make sense, if we didn't have government restrictions in many cases, to export light sweet to the most appropriate market and continue to bring in heavy sour. But we really don't have that luxury with some limitations or exceptions going to Canada.

So I think, for the next several years, we are not showing that we are going to totally displace foreign water-borne imports for -- well, I don't think we will ever totally displace it because I think the economy will recover. But those that do forecast parity, so to speak, really forecast it in the year 2020.

Our crystal ball, it gets real fuzzy beyond three years and it goes almost completely black beyond five years. So, I would say, right now we feel very comfortable with the current situation as long as there is no interference from government in terms of continuing to be able to develop the resources that the industry has identified in the US.

Thanks, Greg. That's helpful. On to PNG, what does the deal flow look like in gas storage? Are you seeing any capitulation on the part of private equity owners in that area, yet? Are any assets being marketed?

Ethan, this is Dean. It's pretty quiet, at least right now, with the market being, kind of bouncing off the bottom. I think most have decided to ride out the storm. I mean, we certainly feel it's going to change in the next two to three years with demand building up. But, I think most have decided to ride it out, so we are not seeing much activity, at least currently, in that area.

I think what you are seeing, Ethan, and there is certainly one very public natural gas MLP that's pretty much acknowledged that the market is not going to return to what we saw five years ago any time soon. With their recent recapitalization. So, I think there are signs of acceptance that this may be the new normal market for a while.

And, once you get to that point, I think it's just a matter of time before people then say how do I best create value? Consolidation and synergies that come from not only administrative savings, but operational flexibility, is certainly -- should be a driver in those thought processes. So again, I think it's ultimately going to get here, it's just a question of, as Dean pointed out, how long.

We've used the analogy before that we think it's coming, and we think we can hold our breath longer than everybody else. And generate results that support our current distribution on a one-to-one basis with potential for growth, as we ultimately see a slight market recovery. If and when, some of the events that we think are going to be coming to pass over what I call the intermediate to long term, that being probably in the three year out period, looks pretty encouraging. We will be covering part of that at our analyst meeting.

But, you can assume it includes issues with respect to gas exports, as well as a lot of conversion of power plants from coal to natural gas. As you see that demand increase, and you also see some of the pipes that are currently excess capacity in the gas business being converted to liquids capacity, it starts to take some of the slack out of the system. So, I think those motivating factors may cause some people to say we would be better to attack that at a larger scale than what any of us are individually, right now.

Okay. Couple housekeeping questions. The excess profitability on liquids recoveries for this quarter, is that expected to continue, and is that in guidance and can you quantify that for us?

That is really related, Ethan, to up at Bluewater. Those conditions really just exist for 1Q, a little bit into 2Q, and have to do with customers withdrawing gas, at least this year compared to other years, emptying out the reservoir.

When those conditions exist, we can get more oil production and it really occurs in mainly the first quarter, a little bit in 2Q. Once they start filling back up, the facility fills back up with gas, those type of conditions go away and that kind of production dampens itself. And really on a year-to-year basis, it depends what the customers do that dictates that kind of production.

If you recall, last year total volumes in storage really hit all new time highs at the low point, and so we didn't have as much opportunity last year. This year, we have seen what would be closer to more of a normal five year withdrawal.

Okay. And then the eight Bs of new capacity, I think four coming online soon and then four at the end of the year, is that contracted being marketed? Is it going to be accretive when those are brought online?

Some of that is already contracted. And some of it is not. I would say about 50/50 right now.

Yes, Ethan, the important thing there is, we are adding that space at such low cost that even in the current dismal market that we are in, the individual capital investments are actually generating attractive returns.

The offset to that is we have some contracts that are at higher rates that are rolling off, and will be recontracted, but they will be recontracted at lower rates. What's happening is the economic gains of incremental capital investments, they are offsetting the contractual diminution in value coming from high rates to low rates.

That's one of the neat things about PNG as an investment is, while we are doing this, we are holding our own, but we are really coiling, if you will, for future growth in the future because we are expanding our storage capacity. And, if we get $0.02 or $0.03 increase in storage rates, which sounds small but as a percentage-wise, that's 15% or 20% on current rates. You can imagine what that looks like as you apply it to that expanded storage capacity.

That's great, that's helpful. Last thing for both PAA and PNG, should we be modeling the same level of ATM equity sales that we saw in Q1?

I think for PNG you'd see a more moderate. We had an opportunity there, where there was some new funds that were coming to market that hit us about the time that we announced the ATM, and so it was just logical to basically pull the trigger and fill the demand there. And we didn't fill 100% of it, so we, hopefully, got some market support after the fact.

On PAA, I'd say we are going to pace ourself relative to our capital program outlook and acquisitions. We will err on the side of being overcapitalized, one, because we have the excess capacity and two, we believe while we are not currently announcing any acquisitions that we will be acquisitive. And we just think it's a lot more beneficial to all of our unit holders to acquire capital at lowest friction costs and least disruption to the market. And so far, we seem to be able to do both. So, I would say we will continue to pace ourself. We may increase or decrease in any given quarter, depending upon that outlook. But, overall we will be more biased towards an overequitized balance sheet.

All right, thank you, gentlemen. See you in New York.

John Edwards from Credit Suisse.

Just if we could come back to the guidance on Supply and Logistics just for a moment. The margins you are guiding to look like they haven't been that low since about the second half of 2010, when there was very little spread between Brent and WTI. So I was just curious, how much of that is in there, or is this a bias toward being conservative in case, with these pipes coming on, you see a more dramatic contraction in those spreads than maybe is represented in the futures market?

I will address the philosophy, and I will let Harry address the details. I would say it's a bias to be as realistic as we think we should be. I would not call it conservative, per se, because I think what we are forecasting is a very realistic outlook.

I think it's hard, and I mentioned earlier, we are trying to figure out when we talk about a return to normal, is trying to figure out what that normal is. It's been such a dynamic market, with changes in production growth, pipeline capacity, new pipelines, et cetera, that it's really hard to peg what a normal is. I think trying to run a one year, two year, three year normalized average is interesting, but it's almost irrelevant. Because at the end of the day, there's also been a significant increase in competition in those markets, and ultimately if there is an excess of pipeline capacity, people are going to try and fill that, and that typically lowers rates.

So, I think we are realistic about what the potential impact could be, even if margins between WTI and Brent stay in the $10 range. So, anyway, the takeaway from my comment is it's realistic as opposed to conservative. But, keeping in mind that our whole goal is always to underpromise and overperform. So, with that philosophical issue, I will let Harry talk about the details.

No, I think Greg had most of it. They are realistic and the differentials have come in quite a bit even though Brent and WTI is, at most, around $10 or so. A lot of the differentials reflect the transportation differential to get to that market, without a whole lot of quality differential involved. Just look at Midland. Cushing differential is actually trading positive, Midland over Cushing today. I think a lot of the Canadian crudes are in as tight as they have been in a long, long time. So, I think they are realistic.

And part of the environment that we are in today. And I think we've thought for a long time that these fine logistic margins would come in, and over time they would transfer to our transportation-related activities.

Yes, if you go back, John, important thing to remember is 99% of all of our capital investments are focused in on the transportation and facility side with the fee-based part of it. And while we don't have those slides in today's presentation, if you look at our first quarter -- excuse me, our year-end presentation, we showed a directional pattern there of what the transportation and facilities EBITDA growth was going to be.

So, I think if you take an average, and I am going to throw out just a place holder, not a precision number, of $500 million for the Supply and Logistics, and a normal base line. And then you add that to a growing transportation and facilities EBITDA outlook, I think you are going to like the growth curves that support continued distribution growth, and still a fairly high retention of DCF.

That does not rule out that there will be opportunities for Supply and Logistics to overperform that base line. I think that's inherent in our business model, and inherent in the markets that we are going to be encountering. Having said that, trying to predict which quarter that's going to show up in, is almost impossible.

So, I would not call what's been going on as nonrecurring, in terms of the over base line performance, I would just say it's very hard to predict. And there may be periods of time, including as much as a 12-month period, where you might not see significant overperformance. But, if you ask me at the end of two years or three years, would we have failed to see opportunities, I would be surprised. And, we are positioned to execute and capitalize on those, both tactically and financially.

And, John, I'll add one thing. You might be looking at the per unit metric we are showing in the second half in the 8-K. If you actually look at how we modeled it, imbedded inside of the guidance, we have a typo there. It isn't $0.76 per barrel, it's $1.15 roughly, for the second half.

Again, what Greg described, if you take our second half Supply and Logistics and annualize it, you come real close to the base line number. It's just we have one typo. It didn't drive any assumptions, it's just an informational field. So, again, we're seeing a reversion back closer to the $1.15, $1.20 on Supply and Logistics, which is a level we haven't seen for a period of time, as you mentioned.

All right. The detail is really helpful. Thank you very much.

Ross Payne with Wells Fargo.

Obviously, acquisitions have come up a few times during this call. I just wanted to ask is, is the order of magnitude, is this something that would be somewhat transformative or is it hitting singles and doubles? Thanks.

But now you got me in a corner, right. Harry said we can't comment, and now you are saying can I comment? I think the opportunities, I will be circumspect but hopefully on point. I think the opportunities that are out there today are more singles and doubles, not home run-type things that are in the market today. That could change 30 days from now or six months from now, and we don't shy away from those. But, right now, I would say there is more singles and doubles-type opportunities out there as opposed to transformative issues.

Perfect. Thanks.

And with no further questions in queue, I will turn it back to the presenters.

If there is no other questions, we will go ahead and close the call right at about an hour, it looks like. But, I want to, again, appreciate everybody attending, and we also appreciate your trust and support financially as we continue to grow PAA. Thank you.

Ladies and gentlemen, that does conclude your conference for today. Thank you for your participation. You may now disconnect.