Plains All American Pipeline, L.P.'s (PAA) CEO Greg Armstrong Hosts 2016 Analyst Day (Transcript)

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Plains All American Pipeline, L.P. (NYSE:PAA) 2016 Analyst Day May 25, 2016 4:30 PM ET


Ryan Smith - Director, Investor Relations

Greg Armstrong - Chairman and Chief Executive Officer

Jeremy Goebel - Vice President, Acquisitions and Strategic Planning

Harry Pefanis - President and Chief Operating Officer

Willie Chiang - Executive Vice President and Chief Operating Officer, U.S.

Sam Brown - Senior Vice President, US Pipelines

John Keffer - Senior Vice President, Terminals

Jason Balasch - President of Plains Midstream Canada

Al Swanson - Executive Vice President and Chief Financial Officer


Faisel Khan - Citigroup

Justin Jenkins - Raymond James & Associates, Inc.

Shneur Gershuni - UBS

Becca Followill - US Capital Advisors

Kristina Kazarian - Deutsche Bank

John Edwards - Credit Suisse

Jeremy Tonet - JPMorgan

Ryan Smith

Welcome to PAA and PAGP’s 2016 Investor Day. My name is Ryan Smith. For those of you I haven’t met and I’m going to get it started here.

Before we get into the presentation, a couple of front-end items. Hopefully, when you registered, you picked up a presentation book for today. And just to orientate you to some of the materials included in that book, there’s a detailed agenda of kind of our speaker lineup for today, including kind of some scheduled breaks and Q&A. There is also – if you go to the next page, there is contact information for our Investor Relations department. If you have follow-up questions on today’s presentation, or if anything you need going forward from Investor Relations, feel free to give us a call.

There is participant biographies included in the book as well. This includes not just the presenters for today, but the other members of PA senior management that are in attendance today as well. That’s followed by the presentation, of course, a couple of notes on Q&A. We’ll have three Q&A sessions today. The – if you have a question, which we certainly encourage, please raise your hands. We have a couple of folks roaming in the floor with microphones. If – just raise your hand, we’ll get a microphone to you. That will enable everyone to be sure we can hear your question, as well as for the folks listening in on the webcast.

And if you could state your name and the name of your firm, as you ask your question, that would be appreciated as well. For those of you listening in on the webcast, if you have a question during the presentation, feel free to e-mail that to Investor Relations at We’ll do our best to address that in our allotted time for Q&A.

If you look at the PAA logos on this slide, that will kind of give you an idea for the sequencing of Q&A. The first two Q&A sessions when the speaker concludes, all previous speakers will come back to the stage. That’s an opportunity for you to ask whatever question you have in terms of the topics that they presented or whatever questions you might have.

And then our final, third Q&A session will consist of all of the speakers coming back for kind of a full panel for any, again, for any questions you might have, which we encourage. I’m regretting requiring sport jackets for speakers already, given the humidity today.

The – our presentation today will include forward-looking statements. Important factors that could result in our actual results being materially different from these forward-looking statements are included in PAA and PAGP’s SEC filings. The presentation will also include non-GAAP financial measures. For a reconciliation of these measures to the most comparable GAAP measure, you can find this in the Investor Relations section of our website.

We’re going to hear a lot today about the capabilities of PAA’s assets. From a high level standpoint and to kind of get it started, PAA currently handles over 4.6 million barrels a day of crude oil and NGLs across its system. We have a leading position in each major crude oil production area in the U.S. and Canada, which is indicated by the yellow area of the slides.

In addition to the production areas, we have a very significant presence in both inland and coastal terminal and market interchange locations. This would include places like Cushing, St. James, East Coast, West Coast, Gulf Coast, a lot of the different areas that you’re going to be hearing more details on throughout the presentation today.

Looking at a six-year summary of our Investor Day themes tells an interesting story, particularly when it’s overlaid with price and production data points. When we approach this meeting, we always see it as an opportunity to share, both our near-term, intermediate and long-term views in kind of a timely, relevant manner. And hopefully, you will find this year’s presentation to be no exception to that, which brings us to today’s theme, significant capabilities, leveraged to recovery.

To prove this theme out to you, we’ve split our presentation into -- roughly in half with some sections related to industry, as well as other sections that are very specific to PAA. From an industry perspective, you’ll be hearing a lot today about the intermediate and long-term crude oil fundamentals and how they are very positive, very constructive for PAA.

We’re going to be talking about the future of the midstream, how that might look different in the coming years, as we transition from a five-year period of very large organic capital expansion programs into a period where with a renewed focus on rationalization and optimization. We also think the potential for acquisitions and consolidations, or at least, there’s the potential for acquisitions and consolidations to become even more relevant.

From a PAA specific standpoint, you will be hearing a lot today about our three operating segments, including transportation, facilities, and supply and logistics, and how those three segments are complementary to each other and articulate together leading to optimization opportunities through that structure.

We’ll be talking about our integrated crude oil system and the unique capabilities it has spanning across the entire midstream value chain. We are also going to be spending sometime talking about or walking through the substantial operating leverage that we have to an industry recovery.

And then finally, we will be going through our financially – our financial positioning and how that will enable us to manage through a lower for longer scenario.

Before I pass the microphone over to Greg, I have one more important topic to address, which is our ongoing evaluation of a potential simplification transaction involving our incentive distribution rights structure. As we discussed on our earnings call a few weeks ago, our objective is to identify potential win-win transactions that best position PAA for the long-term.

We remain actively engaged in discussions with the Boards of PAA and PAGP, as well as the three largest owners of our GP. These three holders representing more than 50% of the ownership structure of the general partner. PAA’s GP ownership structure is unique within the MLP universe and provides us with more tax-efficient flexibility than is generally available with typical – with the typical GP ownership structure. Notably, that flexibility also results in a more complex analysis.

In the last few weeks, there have been several detailed research reports addressing a wide variety of possible structures and economic outcomes. In addition to providing a structural analysis, a few reports made reference to the timing of today’s Investor Day and the potential for an announcement at today’s events. While I can assure you, we are working hard to complete our evaluation, we do not have a conclusion to announce today.

We do recognize firsthand how involved these simplification analysis can be, and we’re much – and we very much appreciate the investment of time these research reports represents. Interestingly, while there are a lot of common observations among the various research reports, there does not appear to be an obvious consensus view. I think it’s fair to say that the absence of a consensus view highlights the complexity of the various alternatives management, the Boards, and the GP owners face, and also reinforces the importance of a thorough analysis.

So while there’s not a transaction to announce today, I do want to reiterate some important information. PAA’s Up-C structure provides tax efficient alternatives not available in the typical GP structure. As we’ve previously stated publicly, we have a clear bias for a non-taxable transaction and a flow through tax structure. The analysis involves a detailed assessment of PAA’s future performance, opportunities, and financial considerations under various industry scenarios that Greg and Jeremy will discuss in their presentations today. The evaluation also requires a thorough analysis of how each alternative structure impacts our equity and debt stakeholders in each of the scenarios.

Finally, the process itself is very important. Given our structure and the focus that will be directed toward any transaction that might result from this evaluation, it is essential that the process demonstrates thoughtful, prudent, and balanced governance. We certainly understand that there’s a lot of questions and that this topic is on the forefront of investors’ minds right now.

That being said, until we have a specific transaction that we can announce, providing additional disclosure beyond what we’ve already said publicly is counterproductive at this point. We do hope to complete the process and be in a position to announce our conclusions by mid to late summer of this year.

Greg will talk a little bit about more in this section. So at this point, I want to turn the presentation over to Greg.

Greg Armstrong

Thanks, Ryan. I think you may have just had the toughest slide to present today. A couple of interesting observations some people shared with me that – they said, we must have picked today to try to make an announcement on simplification, and the reality is, we set this meeting up about a year ago.

The second one was that we picked 2:30, so that we could have an announcement near the close today. The reality is, the ballgame starts around 7:15 and we wanted to be done by then. So hopefully, what we can do here is talk a little bit about what’s important for purposes of charting the course for Plains for the next several years.

As Ryan mentioned, part of this analysis is basically to figure out what’s the best structure that we can possibly come up with to make us the most competitive and the most successful. And throughout today’s presentation, I think you are going to see the information that will support that analysis that’s currently ongoing. It requires us to have a very informed view of the crude oil and the NGL sector and what it means for midstream in general and PAA specifically, because we have such an extensive asset base in the crude oil space, as well as in NGLs, especially in Canada, we get a lot of information that enables us to have that informed view. We never have as much information as we want. We do think we have enough to have an informed view.

So today as we go through here, we’re going to talk about the macro. We’re going to talk about a little bit – drilling down a little bit deeper into what that means by area, because we have assets in every single one of the areas. And then Willie and Harry will talk specifically about some of the opportunities that that presents for the midstream in general, as well as for PAA.

So when we had our Analyst Meeting in 2014/2015, we were characterized as being too pessimistic about the near-term. Of late, we’ve been characterized as being too optimistic about the near-term. Specifically, we had a conference call on January 12, where we shared our view that oil prices for 2016 would average about $35 in the first quarter, $45 in the second quarter, and about $57 in the second-half of the year.

Shortly after that, oil prices dipped to $26 a barrel, and everybody said Plains is way too optimistic. We also had a view that based upon those cash flows from our price deck that producers could support roughly about a 500 rig, oil rig average, and we based our production forecast off of that information.

Looking at what’s happened so far, our oil price forecast has been pretty close. First quarter oil prices averaged $34 a barrel. And just looking over – before I came over here, the [indiscernible] quarter, so to speak through today for oil price is just under $45 a barrel. Where we missed it and we missed it big was the level of drilling activity, oil rigs working, which for us is a proxy for completions, because that’s the most important aspect of it. We had our conference call on January 12, it was 540 rigs working in the lower 48. As of today, there is roughly 300 to 330 rigs working depending upon which data source you want to look at.

So clearly there has been a disconnect in that whole process. What we think that does is it certainly makes it challenging. We’ve revised our forecast for production for the second-half of the year and also our guidance – financial guidance we lowered it by about 4%. What that does do and I hope you’ll see from the presentation I’m about to give that that kind of sets the stage basically for a fairly significant recovery in years in 2017 and beyond for a lot of reasons, because the road down is a lot easier to get down than the road up.

So we’ll start with just a view of the world petroleum demand. Basically, we are at or near record levels, and yet excess production capacity measured by basically that which is available in OPEC and a few other countries to meet incremental demand is near its trough levels. What that means is, there’s not a lot of room for any kind of meaningful supply disruptions. Annual demand, depending on what source you look at is expected to grow roughly about 1 million barrels a day, plus or minus a couple hundred thousand barrels.

On the supply side, the U.S. has been a huge contributor to that production growth over the last several years and certainly a contributor to the excess production that’s driven up storage. What’s interesting to note, though, is because the production growth is happening primarily in the lower 48 in shale and oil resource plays, roughly 55% of our production at the end of 2015 came from wells drilled in 2014 and 2015. And because these are shale and resource plays, the declines are pretty dramatic, as we will show you a little bit throughout the day here.

When you look at it from a worldwide standpoint assuming a worldwide depletion rate of about 4% to 6%, that means every year, we’re going to be declining 4 million to 6 million barrels of decline. And at the same time that’s happening, we’ve had several big projects, deepwater projects, shelf projects that are being canceled that were collectively expected to bring on about 5 million barrels a couple of years out.

When you basically compare that to the fact that we also have a geopolitical environment that is still pretty fragile, and generally negative things come out of that from a production standpoint instead of positive, it puts us in a situation with just not a lot of room for error. When you combine that with the fact that the industry’s capacity to respond to a demand for increased activity is basically has been or is being impaired, there has been a lot of leverage on the balance sheet. So a lot of the first cash flow will go back to repairing balance sheets. And then the oilfield response has been significant layoffs, equipment cannibalization, and inventory depletion.

We do have quite a bit of inventory and we’ll go through each one of these points here rather quickly, that acts as a near-term shock absorber. But as you will see from history, it just doesn’t take that much to pull it down when there is an event or a significant increase in demand. And so the conclusion that I hope you will leave with this macro is that the longer that prices remain low, the longer the response time is, and the more severe the price response will be.

Quickly looking at lower 48 production, as I mentioned, this chart will show you we went back and categorized production contributions by new well completions in each year. You can see the average decline or the composition of the decline for the last two years 2014 and 2015 is roughly 55%, that’s about the same as the average in the Permian. But when you look at the other three big basins, it’s roughly 60%, 70%, and 80% of the production within those areas comes from wells drilled within the last two years. When you look at the fact that those wells decline at roughly 60% to 80% within the first year, and 30% to 40% in the second year, the only conclusion you can come to is, it takes a lot of activity to main production flat much less grow production.

So if you look at that same chart and in this case, we’ve added 2016 on to reflect the decrease in activity levels and we’ve superimposed a red dotted line there as a concept of what the EIA was forecasting. If you recall, it wasn’t very many months ago that they said the U.S. is going to be energy self-sufficient by 2020, 2021, and we’ll be producing 12 million barrels a day.

Well, that requires a lot of activity. What you’ve seen happen is, since the end of 2014, the oil rig count has dropped in the lower 48, 80%. We’ve gone from just about 1,600 rigs to just around 300 rigs. When you look at – and this is a little bit complicated, so I’ll bring the other slide in here too. Basically to add production, you not only have to add new wells, but you have to add enough new wells and new production to offset decline from the older wells.

So if you look at the chart on the left or the graph on the right, you can see in 2014, we added 1.4 million barrels of net new production from the lower 48, one of the largest growth periods we’ve seen in a long, long time. But to get there, we had to add 3.2 million barrels a day from new wells that were added during that year, so that we could offset a decline of 1.9 million barrels in that same year. When you look at 2016, we’re adding 1.1 million barrels of new production from wells that are drilled primarily in the Permian, as well as some other areas. But it’s not enough to offset roughly about a 1.9 million barrel a day decline in 2016. That’s why we will end up with a net reduction of roughly 800,000 barrels a day from the beginning of the year.

So that leads us to go full on inventory a little bit. And you can see here the correlation between higher inventories and lower prices, and the U.S. is a pretty good proxy to measure excess inventory. If you look at the OECD countries, the largest three Japan, Europe, and the U.S. really account for the big bulk of OECD inventories. And when you look at the excess inventory in the OECD compared to five-year averages, that is to say, where our inventory level is today compared to the five-year average, it’s about 125 million barrels of excess, roughly 80% to 85% of that resides in the U.S.

So, again, the U.S. is a good place to keep your focus on. This chart right here shows the inventory tracking that we do at Plains, and this was prepared at the very beginning of 2016. And you can see on the left, the blue dots represent our forecast at the beginning of the year. And the blue line that’s superimposed on it, which is tracking very closely is basically right spot-on. So again our forecast on inventory has been very close.

What you can see over to the right is that production because of the decrease in the rig counts has started to vary from that line, and we made it up basically by incremental imports. In the interest of full disclosure, there is two other elements that contribute to this. One is imports, and one is refinery inputs. Those actually were variants, but they were offsetting each other, so effectively ended up right on track from the standpoint of inventory projections so far this year. And this information, I believe has been updated as of today’s report, not in your book, but on the screen.

So when you look at the overall supply and demand at the margin from a macro standpoint, various sources are predicting within the next 12 months that we’ll roughly hit basically parity, where the marginal barrel will be met by marginal demand. We are not quite sure we agree with any one source’s forecast, but we certainly agree that everybody is forecasting, it’s going to happen somewhere within that time period.

So if we get back to where we’ve started to meet marginal demand with marginal supply or fail to meet it and we’re pulling down inventories, what will it take to ramp up activity? And I made the comment earlier, it’s going to be difficult for us to do that as an industry. And you might ask the question, why is that a problem? We were just at 1,600 rigs, not 17 months ago.

So the rig count right now is 300 rigs versus 1,600 rigs. There is three primary impediments; workforce, equipment, and leverage. From a workforce standpoint, there has been massive layoffs throughout the industry. Hundreds of thousands have been laid off. Some of them have reduced their staff in the oilfield services side by as much as 50%. You’ve got five-man crews out there; they are all five supervisors that used to be running their own crews.

So you’ve got the best of the best working, but you’ve laid off a lot of other hands. And even assuming everybody was sitting home waiting for the phone call to come back to the oilfield, you still have quite a ways to get them up the curve and trained and back in the field. So, again, it’s going to take us some time, and probably we will have to wallet with them a little bit to get them to come back to work in the oilfield.

The oilfield services companies are trying to conserve cash, so they are depleting their equipment inventories. They’re cannibalizing spare parts. When a mud pump goes down, they don’t go buy a new mud pump; they go take one off of a rig that’s parked. You just hope they basically dress the fittings and made it to where when they put the mud pump back, it works as well. But the reality is, everybody is scrambling to try and save as much cash as they possibly can. That’s particularly prevalent in the pressure pumping areas, where the useful life of this equipment is somewhere between four to six years.

The other one is leverage. And I think you can see from these numbers here, leverage on average for E&P companies and oilfield service companies has climbed to roughly 5 times. That’s normally a 1.5 to 2 times metric. So when cash flow does come back, some amount of that’s going to have to be redirected to balance sheet repair. And all of that put together, just so, Plains remains very convinced that we will be able as an industry to respond to that call. But it’s probably going to raise cost, and it’s probably going to take more time.

So I want to use this chart here conceptually to go through the concept that not all equipment, labor, and locations are equal. Basically, again, it’s going to take the ramp up time, it’s going to take more than the ramp down time. We are currently drilling with the best of the best. And if you’ll bear with me on this chart, we have 300 rigs working and we basically arbitrarily assign on a scale of 1 to 10, a 10 factor to those rigs. You’ve literally got the best labor, the best equipment, and you are drilling the absolute best locations.

When you add 200 rigs, you are going to go down a little bit in quality, but not a whole lot. We just – again, we thought we’d be at 500 rigs in 2016. We think you can probably add 200 rigs, they may not be quite as good as the ones in the field, but they’re pretty good. The same thing goes for the labor that was just laid off, and the locations still are very high quality.

When you go down by an incremental 100 rig adds to try and get to 1,000 rigs, which is what you’ll see here in a minute that Jeremy is going to talk about. You can see the quality just has to basically lay off. You are going to basically be taking supervisors from the best of the best and putt them in-charge of labor that you added. And on average, what we’ve said is, the incremental rigs to go from 300 to 1,000, that 700-rig increment will probably be somewhere around 16% or 17% less effective than the rigs that are working today, so it’s not a linear equation of simply adding rigs.

If you look at the last 100 rigs, it’s about a third less efficient. Again, you can put your own numbers to this, and we’ve tried to be fair, but basically representative of what we think will happen as you try to bring labor, equipment, and expand the number of locations. So this is what we think ultimately is going to probably raise cost. You are going to have to encourage the service companies to bring equipment off the sidelines, to get labor off the couch, or out of the unemployment line, or off from some other part of the country, and we think it’s going to take a little bit of a time delay.

So when you put all that in balance, we think the stage is being set for a fairly meaningful recovery in crude oil prices. Beyond the absorption of some of the ready idle capacities, there will be a delay. The longer that we stay at these low levels, the more significant many of these impediments will become. We think oilfield service costs will increase. So when you are calculating break-even cost against today’s cost per well, I don’t think you can go from 300 wells to – or 300 rigs to 1,000 rigs, and basically assume that your 999th rig is going to be operating with the same level of cost and efficiency.

In the midstream, particularly, we think profitability is going to deteriorate for some and increase for others. High priced short-term contracts are going to expire. In many cases, those services being provided, transportation costs are not what is current market, so we think there will be some erosion.

We think in addition, though, as we bring up volume, utilization increases, differentials, competition, and margins will normalize. So as hopefully will be demonstrated throughout today, PAA is basically prepared to withstand an extend – extended period of challenging times, and is very well-positioned to participate in a significant recovery.

With that, I’m going to turn it over to Jeremy.

Jeremy Goebel

Good afternoon. Today, I’m going to talk about how we developed those views that Greg just articulated. But first, I’m going to talk about the production forecast. We basically have three cases to walk through, which have effectively created a band that surrounds the operating environment PAA expects to be in over the period.

As Greg discussed, we feel that we have a strong conviction that a recovery will occur, and U.S. production growth will be needed to balance the markets. It’s a matter of timing. And so while we look at that uncertainty, we need to make sure that in all scenarios, PAA is properly structured and also has the ability to participate in a recovery, while protecting its downside.

So first, we’ll talk about the cases that create that band. And once again, these are projections based on when activity resumes. It’s not a forecast of prices, this is just a view of when activity reviews – so returns. And so when we look at this, some of the general assumptions we are going to talk through are we assume no incremental increases in well productivity.

Now, we continually update our type wells, so we capture what we view are leading edge. And this assumption works very well in mature basins like the Eagle Ford, the Williston, and the DJ. But what we are starting to see is the Permian, there’s still some room for growth. But some of that incremental change that we are seeing now is due to the coring up effect.

And as Greg mentioned, as you go to Tier 1 and Tier 2 areas, areas outside of the core, you could end up having a reversal of some of those gains that you see. So we continually monitor that.

With respect to spud to production times, which really drives completions, as Greg mentioned, that’s what drives production growth. Rigs are a directional measurement, but completions are really the true measurement that we monitor. Those have been fairly consistent within the more mature basins. The Permian, there’s still room for improvement and we’ve tried to capture that.

As we look at our cases, we’ve created three cases to look at different alternatives. Scenario A was created in the fourth quarter of 2015. That’s the case that Greg mentioned with a trough rig count of close to 500. At the time that was created, producers were discussing a reduction of close to 30% in capital year-over-year. Well, when they saw $20 prices in February, everybody went back and made adjustments to down 50% in capital budgets. And so that’s what impacted that number and led to a lower trough that you will see.

So in scenario A, which we would view as the upper band of the environments that we could be within, there is a Q1 2017 recovery and then scenario C, which is effectively our lower for longer case, activity doesn’t resume with respect to rigs until Q1 2018. Scenario B is effectively a hybrid of scenarios A and B to capture a scenario that’s somewhat of a mid – not necessarily the midpoint, but it’s a likely scenario in the middle.

The slope of the recovery could be anywhere from a year to two years in the cases that we’ve developed. And DUC completions, this is different from prior periods, as you’ve got a huge inventory of working capital behind pipe reserves that are effectively in the form of DUCs. And that’s an efficient form of capital, so we tried to capture that. What we have is roughly 200 additional completions per quarter over these different time periods in scenario A and B. But scenario C, we don’t have any additional completions in this time period between 2016 and 2018.

Now, when we look at rig counts, just once again, I wanted to articulate that completions drive the model and rig counts are important, but they don’t capture the whole story, especially in the near- term when you can bring on that additional productive capacity through the DUCs. And so when we look at a trough rig count in scenario B and C, you’ll say, well, the current rig count is 300 to 330 as opposed to 380. We just feel confident that a more efficient form of capital, those additional 60 to 70 well completions will occur just in the form of DUC.

So we look at the balance between our assumptions on the DUC side and our assumptions on the rig side, and we think that those will balance out. And when we look at our long-term rig counts, you will notice that those aren’t the 1,600 that Greg articulated. You will see that due to efficiencies on the drilling side and improvements in well productivity, that 1,000 rigs in scenario B can do the same as the 1,300 to 1,500 rigs that we’re working in the prior growth period. So you’ll see a lot of those efficiencies will be captured and improvements in productivity.

So the first slide we’ll talk about is, what is the impact of a delay in timing? So if we talk about the impact of timing, what you’ll see here is the difference between scenario A and B over the projection period is a loss of close to 500,000 barrels per day in productive capacity from the U.S. And so the issue here is the longer OPEC and Saudi Arabia can continue to compete for market share by doing this and delaying the impact of the revival in production and productive capacity here in the U.S., that’s less they have to compete for in the global market assuming constant demand. And the difference between scenario A and C is materially larger.

So when we start to look at the rig count, what’s happened, and what do we plan to happen? So if we look at the top chart, you will see that the reduction of 80% that Greg mentioned, we’re going back up to 1,000 rigs is really 60% of the peak rig count. But as we’ll show you in a few slides, that that’s sufficient to add the same amount of gross production adds as you had in the prior growth period. The bottom slide just shows – is a reference to show you for other basins.

Now, if we compare the cycles in 2009 versus the current cycle, the first thing to note is the duration of this cycle. In 2019, you had roughly a 10-month period between peak and trough. Now, you’re at 20 months and counting. So that impact and the impediments to bring production back, you are going to see more of those in this period than you did at that time. And then when we look at our projected ramp of close to 40 to 45 rigs per month, that ties pretty closely to the prior period, so we get comfortable there.

One key difference and why you can change the slope of the production now versus before is, you have the ability to bring on those drilled and uncompleted wells that’s not captured by a rig count, and you have better drilling efficiencies and more well productivity. But that should be captured in the absolute rig count that we look toward.

Now, if we compare our forecasted growth to the growth that was exhibited in the prior period 2011 to 2015, I want you to note a few things. This is what we talked about, 1,000 rig, the average of 825 rigs in our forecasted period is materially lower, 60% of that 1,300 to 1,400 rigs in the prior period.

Well, as you’ll see, the growth adds from new wells is basically the same. But one of the key differences now is to grow production, your underlying base decline has gone from an average of close to 1.5 million barrels a day to 1.8 million barrels a day. So those same gross production adds will add less volume going forward just because you have to overcome a bigger decline.

Now if we look at some of the specific basins, so some of the detail behind it, you’ll see that Eagle Ford is a perfect example, very small legacy production base. So pre-2012 is 400,000 barrels a day or less, and you had peak production of 1.7 million barrels per day. And that was exhibited over about a three, four-year period, where that was generated. And so what you’ll see is 70% of current production is associated with wells that were drilled in the last couple of years. What that leads to is a very steep decline.

Now, what’s contributing to that decline? It’s a decline of close to 500,000 to 600,000 barrels a day based on our current estimates. You will see there is an 85% reduction in sand volumes, which to us is one of the leading indicators we use to see two to three months out of production. Sand deliveries can help us get a view of what’s happening in the field and what will happen. You see in the Eagle Ford, there has just been a decimation of activity. And completions have followed that sand, so that also tells us that, we don’t expect a lot of new production within the next few months until activity resumes.

The other thing to note in the Eagle Ford is 80% initial decline. So a well that produces 1,000 barrels a day in the first month will contribute 200 barrels per day in month 13. That’s important and that’s that treadmill that Greg was talking about.

So if we look at the bottom right-hand corner, what you’ll see in 2015 and 2016, the Eagle Ford in 2015 had to overcome a 50% underlying decline. Now, as that decline takes hold and you’ve already seen 400,000 barrels a day reduction in absolute crude oil production and condensate production in the Eagle Ford, it’s starting to level off in the high 30s. And so that’s what leads our view to you could see 500,000 to 600,000 barrels per day decline in the Eagle Ford.

Now what does that do to long-term production? That just means, it’s going to take it a while to get back to peak production levels, five years. And this differs basin by basin, and we’ll quickly walk through a couple of others.

Within the Williston, you had a much larger existing production base. You had a peak production level that was lower. So we have a lower expected decline. So instead of 30%-plus peak-to-trough decline, this is close to 25%. And what you’ll see is our forecasted decline is somewhere between 250,000 to 300,000 barrels a day in the Williston. And you’ve – part of that’s driven by, you see 85% reduction in completions and sand into the Williston.

So we feel that through the early part of the summer, you are going to continue to see a roll. And what we call the Williston is North Dakota and Montana. So you’ve already seen close to 125,000 barrels a day that decline.

In the DJ Basin, you had a much smaller existing production basin, much smaller absolute production base. But a lot of that occurred in 2014 and 2015, when the accelerator was really hit. So 80% of production in the DJ Basin comes from wells drilled in the last two years. And so what we see there is a material reduction in production, but on an absolute basis it’s small, because the basin is – it’s very small relative to those other basins we talked about.

And you will also see less of a reduction in completions and sand activity, so a 70% reduction there, which will allow you to have a much slower net decline. And so what I mean there is, our peak-to-trough in the Williston and the DJ is only close to 20%, whereas it was 25% in the Williston, close to 30% in the Eagle Ford.

Now, the Permian is a different animal. One thing I’ll point to is that pre-2012 production is over 1 million barrels a day. You’ve only had a 55% reduction in sand and completions. And so our net decline forecast is somewhere around the 10% range, and that’s about 150,000 to 200,000 barrels per day. And what you’ll see is, it was a slower slope and growth, and it’s a less mature basin. And so this is the one where we have our eyes on, because we continue to see improvements in drilling and spud to production times and – which is the drilling efficiencies, and we continue to see improvements in well recoveries.

But the one thing I’d point to is, if you look at the sand data, where it flattens out in and around August through early of 2016, that was what was keeping production flat. But you’ll see sand deliveries in February, March, April, and May have been down, which two to three months out from that will indicate decline.

So that peak production of close to 2 million barrels a day in November, we would expect to see declines through the early summer. But if you look at the tail end of this, you start to see sand may be coming back, which is consistent with some of the dialogue the Permian producers have been coming with. So there could be an upward bias to our forecast for the second-half of the year for the Permian. We don’t see that in any other basins, but this is one where we might get comfort that there is additional production there.

So the next question is, why do we do all this? We go into all this detail, part of it’s for the macro forecast, that’s some of the things that Greg talked about. But part of it is to position our assets to be in the right places for a recovery. And so when we look at the Permian Basin, we do this in-depth analysis. We had a great legacy position that we continued to build upon. We have very experienced commercial, operational, and technical personnel. That combined has allowed us to build a system that is more comprehensive than any of the other Permian systems.

So we are very well leveraged to a recovery in the Permian. We can gather in all the core areas, deliver to all the liquidity points, and participate many of the takeaway options. And so this same type of analysis is done within all of our core asset areas. And as you’ll see today with some of the other areas we talked about, we’ll show how we’re positioned similar to this in those basins, in addition to the emerging scoop and stack plays.

With that, I’ll turn it over to Harry.

Harry Pefanis

Thanks, Jeremy. I’m going to spend a little time today just talking about the fate of the midstream segment industry. And I’m just going to start with we think 2016 is going to be a challenging year, it started that way certainly. And to give you a little backdrop of why we think it’s going to be so challenging, if you look at the period from, say, 2010 through kind of 2019, by our account, there will have been 50 or so pipeline – crude oil pipeline projects that either have been completed, or pending, or under construction. And in total, the industry, we expect – or estimate we will have invested $37 billion in those assets and created about 12 million barrels a day of pipeline capacity.

So these new pipelines were typically supported by volumetric commitments. And what we saw happening was that a lot of times, the committed capacity was substantially less than the pipeline capacity. So you may have a situation where a 200,000 barrel a day pipeline is developed and it may only have 100,000 or 120,000 barrels a day of commitments. And that was enough to generate the minimum types of returns for the project developer and also allowed for upside potential with the uncommitted volumes.

We also saw scenarios, where the producers that were willing to backstop some of these pipeline projects said, listen, I think my production could be X, minimum X, and it could be as high as Y. I’ll commit X, but I want to have enough capacity to move Y out of the basin. I don’t want to backstop a project and then have production stranded behind it.

So the two of those contributed to the excess capacity that exists in a lot of the producing regions. That’s been compounded by the fact that you’ve had declining oil prices and declining rig activities, as Jeremy just went through. And also when you take into consideration – when you look at another factor that’s occurred is that some of the shippers that not only make commitments to pipeline capacity, but they also make commitments to dock capacity, barges, rail facilities, railcars, stabilizers, et cetera.

So sometimes what we are seeing is crude that’s not really moving to the optimal market; it’s moving in an area to satisfy existing commitments. So that’s kind of a longwinded way of saying, we think that for the near-term, there’s going to be excess capacity. This cycle is not – it’s different than 2009. Jeremy just sort of went through the duration component of it. But in addition to that, if you look back at 2009, you’re about 71 MLPs competing for projects, today about 121 at the end of 2015.

And the other couple of other dynamics that have changed is that, some of the pipeline commitments that have been made by large companies, sometimes major oil producers, and they have committed capacity. So what they’ll do is, they’ll go out and compete in a merchant function to gather crude.

So if you look back at 2009, we were probably one of the only MLPs that had kind of a merchant function and transportation assets. It’s similar today. There is not a whole lot of new entities that have both, but some of the shippers are now competing at a merchant level.

Another dynamic that changes some of the midstream companies are backed by private equity capital, and they receive support for some of their projects by E&P companies that are also backed by the sponsors. That’s another level of competition that did not exist in 2009, and also in some of these demand pull pipelines we see refiners with their own MLPs. And they’ll make commitments, but they want some of the equity, in that they want their MLP to participate in the equity of those projects.

So, near-term, what we think, based on the work that Jeremy has done and what we see that develop and being developed on the infrastructure, it’s going to be competitive for new volumes. And one potential of complexity or disruption that also exists today is bankruptcy – producer bankruptcies. I think there has been something like 77 producer bankruptcies since January 1, 2015, and we’ve had a recent court ruling that has allowed a producer to reject its contract commitment that it has made to a midstream entity.

So that provides a little more volatility in this space. From a capital standpoint, we think most of the capital is going to be directed towards completing existing projects in sort of bolt-on type of activities around existing assets. We don’t see a whole lot of new major projects being developed. We think it will not be as capital intensive going forward. And most of the activity will be around trying to fill up existing assets. And it’s sort of ripe for consolidation or rationalization, we’ve thought that for a while. So and we haven’t really seen the consolidation that you might have expected in this type of market, but we do think it’s ripe for some consolidation.

Now, if you look towards the intermediate and longer-term, we’re very bullish on the midstream space, very bullish on our opportunity set at PAA. And that’s because of the resource base, it’s sort of an extensive resource base in North America. We have technology that’s improving. We have efficiencies improving. Wellhead production is improving, and that’s all driving down the break-even price, so you don’t need the high prices to generate the type of rig activity that Jeremy is forecasting in a recovery scenario.

So as production increases, we’ll see increased utilization and also we’ll have improved margins within our segments. So I’m not going to spend a lot of time, Jeremy has talked a lot about sort of the resource space and the potential. But this just gives you a flavor for the magnitude of these resource plays. If you can kind of concentrate on the undrilled locations, the number of them and sort of the years of drilling activity.

So in three of the four areas, we have 15 to 20 years of drilling activity. And in the Permian, we think that’s probably closer to 75 years, and that’s with existing technology, so we only see that improving over time.

I’ll talk a little bit sort of about PAA’s goals in 2016, and I’ll start just, our constant goal is to have a safe, compliant, and environmentally responsible operation. And beyond that, our three goals for this year are, one, to maintain a solid balance sheet with sound credit metrics and ample liquidity.

We want to execute our capital program, because that’s the driver for our cash flow increases and positions us to participate as production increases in a recovery scenario. And we want to be very focused this year, and we want to optimize our assets and really just position ourselves, so whatever environmental encounter will generate the best possible results in that environment.

So I’ll talk a little bit about some of the initiatives that we have during this sort of transitional period as well. And when you look at the three segments, transportation and facilities, I’ll just kind of reiterate we want to deliver our capital projects on-time and on-budget. And we want to provide integrated solutions for our shipper customers to provide a unique product to them. And then we want to use our supply and logistics segment to protect our existing volumes, but then also to use it to increase the utilization of our assets and also be positioned, so we can capture arbitrage opportunities when they are presented.

And then kind of our overriding initiative is really just to continue to push for operational excellence, and that really starts with leadership. It requires collaboration. We have to strive for continuous improvement and we really want our team to have kind of a sense of personal responsibility in these endeavors. And we want to – we strive to go beyond just regulatory compliance. That’s sort of the minimum standard we want to – in areas where we can, we want to exceed the minimum regulatory requirements.

And the goal here is to actively and systematically reduce the risks – the operational risks associated with our assets. You can see on this slide, if you look on the chart at the right, we continue to maintain a very high level of investment in both the maintenance of our assets and the integrity of our assets. And for the last three years or so, we’ve continued to spend $400 million to $500 million a year in these activities with a slight downtick in 2015.

These are in U.S. dollars, so it’s partially driven by the fact that there’s a little bit of weakness in the Canadian dollar, so that drove most of the downtick. You can look at the two charts on the lower, below the spending graph, our releases are trending in the right way. It’s a positive trend on release – on reportable releases that’s down to, I think two in 2015. Our goal is zero, so we still have a little work to go.

Facilities leases ticked up and are flattening out. We have programs that we’re implementing to address our incidents at our facilities. And really if you look at it in total during this time period of 2005 to 2015, we spent about $3 billion on the – maintaining our assets.

Now, a couple of other areas that we focus on is, we have a significant amount of resources towards advancing our operational management system. That’s kind of an overarching platform that will drive improved performance. And it will also provide the opportunity to comply with API Recommended Practice 1173. And we have a lot of our technical folks that are – that participate in numerous industry workgroups. That includes integrity management efforts, data integration efforts, leak detection, cyber security.

So we’re very involved in lot of industry activity. And we also work with tool vendors in trying to develop new technology in tools that will improve our ability to understand the integrity of our assets.

So before I turn it over to Willie, I want to talk a little bit about Line 901. And if you recall, that was an incident that occurred May 19th of last year. We had a release in Santa Barbara and it was about 3,000 barrels. We recovered about 1,100 barrels. And if you look at the upper left, you can see what the beach and the water looked like sort of day one, when the release occurred. And you can see the progress that we made just three days later, if you look over to the right and 17 days later, if you look down below.

So, significant process – progress in a very short amount of time. And that was really driven by the fact that, we responded in force with a commitment to do the right thing and to do it quickly. We had a number of our executive and senior officers on-site within 24 hours, and we did that, because we wanted to be able to make decisions. We wanted to be able to respond quickly to remediate this. At the height, we deployed over 1,000 people in the field, and had 15 to 20 vessels in the water assisting with the cleanup effort.

So the cleanup was substantially complete within about 100 days. We continue to monitor the shoreline. Right now, Line 901, that’s the segment from Las Flores to Gaviota, it runs along the coast, that line has been purged and is out of service. Line 903, the segment from Gaviota to Pentland, which is in the Bakersfield area is also purged and is out of service. Our guidance does not include a restart of those pipelines.

In order for a restart to occur, it’s subject to PHMSA’s approval of our remedial action plan and our restart plan. And of course, PHMSA can impose additional requirements on us as well. So as of today, we’ve established $269 million reserve associated with this incident. About $186 million is estimated to be recovered by insurance. We’ve incurred about $150 million so far in the cleanup and remediation of this incident, and about $112 million is being reimbursed so far.

So more recently, on May 17, PAA and one of our employees were indicted for alleged violations of a law in California in connection with this oil release. The indictment included four felony counts. All the felony counts were attributable to Plains, none to the employee. And they really – three of the counts were for discharges of oil into the waters of the state, and one was for falsely reporting the quantity of oil released.

So I think we initially recorded – reported about 2,400, 2,500 barrels of oil released. Our last update was about 3,000 barrels a day was released – or 3,000 barrels were released, not per day. The indictment also included 42 misdemeanors. Six of those misdemeanors were related again towards discharges of oil into the waters of the state, and then also for failing to timely report the incident. The remaining 36 counts related to take – were wildlife alleged to have been taken as a result of the release.

So, for example, eight brown pelicans taken resulted in eight individual accounts and misdemeanors. So we intend to vigorously defend ourselves against these charges. And we are confident that we’ll demonstrate that these charges represent an inappropriate attempt to criminalize really an unfortunate incident that occurred and or I should say, an unfortunate accident. A couple days later on May 19, PHMSA issued its failure investigation report.

So we are still reviewing that report. PHMSA maintains that there were numerous contributory causes, and those included really in their executive summary, they highlighted three areas; ineffective protection to against an external corrosion, failure to detect and mitigate the the corrosion, and then lack of timely detection and response rupture.

So the report is very large, over 500 pages. It also included three reports from engineering firms. DNV provided two of those reports. DNV was a PHMSA-approved engineering firm, and they performed the mechanical and metallurgical testing report, and they also provided a final root cause analysis.

And then LaMontagne was retained by PHMSA to provide an in line inspection review. So the other thing I should probably point out is that PHMSA intends to separately address the enforcement actions that they will recommend. And then I also mentioned there’s an ongoing DOJ investigation. But we believe that the root cause analysis and the totality of the facts again support our view that this was an unfortunate accident, and that neither the actions of PAA nor our employees were criminal.

So with that, I’ll open it up for Q&A, and ask Greg and Jeremy to come on back up here.

Question-and-Answer Session

Q - Unidentified Analyst

Yes. The question was – a lot of information, so thank you about all of the different basins. But I’m trying to come away with a simple, which probably isn’t the right way to takeaway from it all. You have to look at it basins by basin to see where the over-piping might be, so to speak. And putting aside the Permian in all the other basins, it seems like and maybe just confirmation, the three to five years out to get them back to peak reduction from 2014 was. But even back in 2014, there were planned and additional pipes that went forward and were built.

So my question is, while supply might come back in three to five years to some of these other basins, the Eagle Ford, the Bakken, when does the supply and demand of the capacity, you said will be overbuilt for a while. But how – when do you actually see supply and demand for the takeaway capacity coming back in line with the production? Because you might start getting contracts rolling off that now create additional competition. So I’m trying to get a sense of – clearly, we are not talking about months. But are we talking about five, six, seven years until we really get stable underneath us? I’m just trying to get a sense of a timeline?

Jeremy Goebel

Yes. No, I think it’s going to vary by company and a couple of things -- and, Harry, bail me out if I say something that’s not precise. Most of our contracts, we certainly have our share of MVCs as well, Noah. Most of those have a 7 to 10-year tenure, okay? So and some of them haven’t even kicked in yet. So in some areas up on the slide, I presented, you saw I said some midstream companies are going to deteriorate profitability and some are going to benefit.

We’d like to think we are on the ones that are going to benefit, because we have a lot of projects over $2 billion worth that are just now being put into service. And they most of those have and you’ll see a little bit later on in the presentation, I think. I’m going to stop my answer a little bit short. But a lot of it’s going to be addressed in the rest of the presentation. But I think some contracts, for example, we’re aware of a couple that expire in 2017 and 2018 on other producers, and their tariffs are 50% ahead ours. Okay? So when that expires, we think that volume becomes available to us.

So there is going to be winners and losers within each of those categories and it varies by a basin. With respect to the Permian, which is the area we have the biggest footprint, that’s the shortest period of recovery. And the other one is that, if we do see a price spike and Jeremy’s was activity-based, not price-based in terms of his time, you could see a fairly good acceleration. But it will probably take much higher prices to do that, because service costs are going to be much higher there.

So from a Plains standpoint, I think if you go basin by basin, and we’ll show you some of that today. If we haven’t answered the question toward the end of it, we’ll circle back around 10 years.

Unidentified Analyst

[Question Inaudible]

Jeremy Goebel

So it’s going to be part on timing. I mean, our forecast that we shared at the beginning of the year, we would exit this year roughly around $60, a little bit higher than that a barrel. I think we had a $57 average price for the second-half of this year. We don’t know anything right now to change it. I mean, quite candidly, knock on wood, we’ve been pretty much spot-on for the first five months of the year in terms of average price per quarter.

I think what we are seeing right now is, because activity levels are lower, we think the price that we would have forecasted in 2017, which might have been closer to $70, could actually go much higher, because when they do, basically, if we have any kind of interruptions, supply and demand is so tight worldwide after we depleted inventory then the answer is they are going to basically say, okay, U.S., be the swing producer. They are going to expect us to turn it on a dime, and we don’t think it will happen. So prices will go up, and then there will be a lag before actual volumes come up. But in the meantime, it’s going to look like absolute total chaos.

Harry Pefanis

I think the other thing I would add is, Jeremy, bail me out here if I state this incorrectly, but you get something like a $70, $75 oil price. And it doesn’t matter, all these plays are going to be profitable. So we are driving the rig activity.

Unidentified Analyst

[Question Inaudible]

Jeremy Goebel

You could support it with that, for sure. Yes. I don’t think it could be higher by then, obviously, for other reasons. Yes. Faisel?

Faisel Khan

Okay. Faisel Khan Citigroup. Just a question on the – I know you’re restricted on saying what you can on the simplification strategy. But just so I understand clearly, is the time that it’s taking to come to conclusion, is it more analyzing the outcomes, or is it the negotiation process with all the stakeholders?

Greg Armstrong

Absolutely yes to both.

Faisel Khan


Ryan Smith

We have time here. So, yes, sir.

Justin Jenkins

Thanks. Justin Jenkins of Raymond James. A couple of quick ones from me. I think they were covered in Harry’s slides. But you mentioned competition from the majors from a gathering perspective. Just curious on when you think that might end, or start to stabilize, and how that kind of impacts the S&L segment strategy and financials going forward?

Greg Armstrong

Yes. So it definitely impacts the S&L segment as well, and it’s part of the reason we see margin compression. It’s all going to be volume based. I think, it’s probably, at least, the 12-month period from here. Jeremy, do you have any?

Jeremy Goebel

So is your question, when do you see the competition eroding?

Justin Jenkins

When will things start to stabilize on that front? And does that impact the strategy of S&L trying to compete further with trying to secure incremental volumes?

Jeremy Goebel

I think that’s also going to depend on the slope and the price forecast right. And so I think once you start to get outside of the MVCs and you have marginal barrels, again, that’s when that happens. And so it’s a question of your price forecast. And so what you’ve seen is a reason the differentials are strong, it’s because, it’s now the marginal barrel isn’t being transported because of market driven and collecting a tariff; it’s being driven that the guys who have MVCs are short.

And they are required to deliver those barrels regardless. And so they are actually delivering lower than their economic cost. And so when you start to see prices instead – volumes instead of declining increasing and you start to have marginal barrels that are transported based on pricing signals, I think that’s when it recovers. So a lot of this is just dependent on your own forecast.

Justin Jenkins

And if I heard you correctly you made a reference to when it would make the time to start investing?

Greg Armstrong

Sure. I think what Harry was trying to get across, we think most of the investments already occurred. There’s capacity out there in every single basin right now, the time is to start filling it up. I don’t think we are talking about building major arteries anymore. I think you are talking about tentacles that will connect out to the gathering, and that will be on a specific basis, but that’s where the platform becomes critical, because we can go out and lay from the footprint that you saw in West Texas to somebody’s well and transported seamlessly to the market.

Somebody else could go build that little short gathering system come to us and we say we’re not interested in hooking it up. So it’s – I think, this is where size and scale will start to play in our favor.

Jeremy Goebel

And I should say really, Willie in his slides, he will cover sort of the opportunity set what the potential is and it really lease margins, they usually lag, so because you really need production, I mean, capacity to start filling up before lease margins.

Justin Jenkins

And then maybe more medium-term for some demand pull projects, do you think Diamond and Caddo joint venture type projects with refining sponsors. Do you think that kind of structure make sense for a medium-term project set investment?

Greg Armstrong

On the demand side, I think it will and as Harry mentioned, the refiners have their own MLPs, and they want our expertise and connectivity, but they want their capital go to work. So on demand pull side of it, there certainly could be some additional plumbing that would be done. But on supply push, I think, we’re done for a while, there’s a gentlemen [indiscernible] view in handy.

Shneur Gershuni

Hey Shneur Gershuni with UBS. Two questions, one is a follow-up to a Faisel’s question. With respect to how you characterized the negotiations, you said it was supposed to be a win-win between all parties. I was wondering if you can define what win-win is? Is it based on that cash basis as to how each party receives distributions, or is it based on how the public securities say the value should be allocated between the two?

Greg Armstrong

Same answer is going to come back at you, yes to all of you. But I think, clearly, the negotiation process and an analysis process, part of that, clearly the GP IDR has a big option on upside. Part of the question is defining, what is that upside? Well, if you’re not having a lot of organic growth then assets under management by issuing new units may not necessarily be a component in the forecast, as we go forward yet acquisitions could very well be, but then you’ve got a cost of capital issue. So all of those have to be thoroughly vetted, analyzed, debated, and everybody has to have a chance within that group, but it’s a tight group, but it’s a diverse group to have your say.

And so, the answer is, it takes a while to go through. It takes a while to actually agree on what the forecast is that you’re basing everything on and when it’s volatile, so a little bit difficult in there. I think from a fairness standpoint, I made the reference earlier and not to get carried away with the percentages, but with the concept ultimately, I would love to get it down to okay, you’re not going to split an apple, you cut it and I’ll choose which half.

Shneur Gershuni

Fair enough. And as a follow-up question, you talked about the spare capacity from some other pipelines, MVCs rolling off over time. How do you think that impacts spot prices? Do you have a scenario, where spot prices for spare capacity goes up with the roll off of the MVCs, or should we actually see a scenario where spot prices for capacity goes down assuming kind of flat production environment?

Jeremy Goebel

Transportation costs?

Shneur Gershuni

Yes, basically, assuming, you’re moving volumes in the Permian today, you’re bidding on open capacity whatever the spot is for that today. Does it go up or down, as let’s say competing pipelines MVC start to rollout?

Jeremy Goebel

Yes, so oil pipelines first don’t really operate the same way natural gas pipelines, where you have a spot market for incremental transportation. But I do think what you’re going to see is MVCs roll off companies that have higher tariffs associated with the MVCs will lower those tariffs. They will be – they will just lower their uncommitted tariff rate.

As an example, I mean, right now we are aware of a couple of producers, they may have 50,000 barrels a day, have commitments on a $3 tariff pipeline, but they only have 25,000 barrels of their production. So if they don’t shift that other 25, they’re going to lose $3 a barrel. They’re going to the wellhead and buying a barrel at $1 loss from a natural market and saying, if I can ship it on that, I lose $2 to the $3. When that goes away, they’re not going to go pay $1 and lose it to take it away from a tariff that may have only been 70s tariff.

And so I think you’re going to see a redistribution of those volumes as those contracts either roll off, companies that are overcommitted have to go through financial restructuring in which case that gets – happens in that environment, or volumes come up and basically compete for the marginal space.

Shneur Gershuni

Thank you.

Jeremy Goebel

Yes, Becca.

Becca Followill

You guys – Becca Followill with US Capital. You guys talked twice, can you hear me?

Jeremy Goebel


Becca Followill

Okay. You talked twice about M&A opportunities or M&A been a driver of the midstream sector going forward. How do you, can you talk about how you participate that in light of tons of private equity that’s been chasing lots of capital available and probably increasing capital available on a rising tape relative to your cost of equity?

Greg Armstrong

So, I think part of what we’re trying to address hopefully with the success of simplification process if it goes through, we’ll address the cost of capital at the marginal issue. I mean, today our yields trade high just for the common, and if you add the GP on top of that is particularly burdensome. So I can’t say, we’re on aggressive offense right now. The way that we can be still competitive for given acquisitions or three words synergies, synergies, and synergies.

And if you look at one acquisition, we’ll talk about today that we are making in this environment, we’ve made it because of synergies, notwithstanding cost of capital. We’ll also talk a little bit about how do we sell assets at multiple that are – is basically attractive versus what we’re reinvesting, so we’re able to roll capital without having to issue new equity. So Willie will cover that in his section.

But I think the threshold issue is, we believe ultimately there is 120 MLPs out there. And I feel pretty confident, none can show you the kind of asset footprints that we have and yet they will be competing in a very competitive market. That means, as Harry said, it’s ripe for consolidation. We need to fix our cost of capital to be able to get there.

Becca Followill

Thank you.

Ryan Smith

I think we’re playing hand-off here.

Kristina Kazarian

I think we are. Kristina Kazarian at Deutsche Bank. So a follow-on to Becca’s question. The one of the first bullet point that Ryan mentioned is that larger scale project aren’t going to happen. And then Harry is talking about how things are more competitive. So can you help me jive that with the comment you just gave to Becca about, are there enough opportunities out there for you guys as consolidated entity to have meaningful growth over the longer-term?

Harry Pefanis

Yes, I think, Kristina, we’re going to cover a lot of that in Willie’s section, both through organic growth. Organic, we don’t want to spend any capital, we just fill up our pipes, okay? So if I’ve got 100,000 barrels of capacity that I’ve already bought paid for it and it’s on the balance sheet, and I just start collecting tariffs as volumes go up 20,000, 30,000, 40,000 barrels, that’s growth okay? It’s the best kind of growth, because it doesn’t require incremental capital.

And not to steal Willie’s thunder, but I mean, it’s as much as $1 billion that’s a lot of growth. In other areas that you saw in Jeremy’s slides, for example, in West Texas, they’re still developing pockets of new core areas and we’ve got major pipelines throughout all that area. And so, we’ll have the ability to consolidate the synergy. So we may have to lay up, let’s say, we even go and we lose 300 basis points against our cost of capital to lay that line. But if capturing that barrel at the wellhead then goes into our pipeline that connects to another pipeline, that connects to another pipeline, and I get $4 of tariff, and I only had to lose $0.20 on a cost of capital are I don’t believe.

Kristina Kazarian

Great. Thanks.

Greg Armstrong

John Edwards. We’re going to get geographically diverse in just to say.

John Edwards

Okay. Just John Edwards at Credit Suisse. So I just want to understand a little bit better on one of these slides, I guess, slide 34, one of the bullet points you have here is about asset utilization. And then I’m trying to think about – how to think about this late layering that against the decline curves that you show for each basin.

And so I’m wondering, where do you see your asset utilization now? And then where do you see that capacity utilization going down to? And then I guess, I’m assuming it’s going to follow this curve, you will come back to 2015 asset utilization levels, depending on the basin anywhere from 2018 and 2020. But when at the trough, you’re going to be at some level. And then how do your contract renewals kind of lay over that. So, how do we think about balancing that utilization against those risks?

Jeremy Goebel

Greg, can I address that?

Greg Armstrong


Jeremy Goebel

If you think of Canada, that still growth at the significant part of our business right? So take that and table that, that wasn’t covered. I would look at the Permian basin, which is roughly half of our first purchase business that had the shortest duration and then probably the larger upside there.

So you take a significant portion of our business and put it there and a lot of those are stated tariffs and not MVCs. And then a lot of the other exposure in the other basins are newly constructed pipes with MVC protection for significant period of time. Would you characterize it differently, Greg?

Greg Armstrong

Yes, I’d say, Jeremy, it’s Greg. I mean, you kind of got to look at it area by area. And again, I think, John, this is another question, kind of Noah’s, if we have an answer that to get through Willie, Sam’s and John’s section we’ll be able to get back to it. But, again, let me just be clear. It said on one of my slides, I think Harry has dwelled on it on his, there is going to be winners and losers within the midstream space. If you have a two-year contract remaining and you’re a competitor of mine at a $5 tariff, and I have a $250 tariff that uncontracted okay?

When your contract is up, okay, you’re going to have a problem to hold onto your customer, because he is probably going to migrate for the best level. So volumes won’t change at all, let’s say, they’re static. But I’ll pick up business throughout that whole process okay? And, again, if we’ve got a more integrated system and you have one stick of a pipeline and I’ve got four that I can connect it to, so we can give them a joint tariff, it’s probably going to blow your socks off okay?

So it’s going to be a very competitive environment, there will be winners and losers. But again this is where we come back to, I think, scale is going to matter a lot going forward. I think, Willie is going to cover that in his presentation.

John Edwards

Okay. So just to confirm and so you believe your tariffs and rates rise are going to be more competitive in your – each of your relative areas? So you believe [Multiple Speakers]

Greg Armstrong

In the vast majority of places absolutely, because part of it’s, because we’ve got legacy assets that have historically the lowest tariffs and part of it, because we consciously chose to set the tariff lower for longer with a longer MVC, so instead of five-year MVC and $1.75, we said, let’s go ahead and give them a 10-year contract, but do it at $1.25 knowing that in five years, their contract expires we got a good situation.

John Edwards


Ryan Smith

We’ve got time for one more real quick one, Jeremy?

Greg Armstrong

Two more, we’re going to get one more out of this row over here.

Jeremy Tonet

If I’m looking at – Jeremy Tonet, JPMorgan. If I’m looking at Slide 15, here, and I look at your projections for 2016 production and see what the actual is. I’m just wondering if you could share with us where the divergence came from if there’s any basins that fell off more quickly than you expected or anything else you can share with us there?

Greg Armstrong

That’s on the inventory slide right next to the inventory slide, is that correct?

Jeremy Tonet


Greg Armstrong

Yes, so it’s just now starting to show up remember those are weeks and they are not months, okay? So we’re probably seeing a little bit of divergence. And keep in mind that this is EIA data and I don’t give you geographic information by week okay? But I’d say we’re probably seeing fairly sizable falloffs in the Eagle Ford – the Eagle Ford being number one.

It’s – so if you say there’s about 800,000 barrels a day of total decline and that’s we look at the monthlies more so than the weeklies. Weeklies are directional illustrations, but we do believe in the acceleration that’s occurred in the last six weeks. We think that that’s consistent with what we’ve seen in sand deliveries. But the Eagle Ford is probably half of the onshore decline, Williston Basin close to 100 to 125. The Mid-Continent is probably an equal amount. The DJ Basin has been a small decline. And then there’s legacy, Gulf Coast type assets California, those could account for the balance. And so I think of the shale basin, that’s probably the largest the Eagle Ford.

Harry Pefanis

Jeremy, not to put toofine a point on it,but again I think if you looked at divergence, and we circled it, but again you’re talking about really it’s reinforcing our forecast of saying, we think we’re going to see the second-half of the year. When you go from 500 rigs to 300, you don’t have it happen immediately. But this is weekly day, so you really got about three to four weeks of data in there. But we’re starting to see the divergence. We’re relying on the EIA’s data, but we’re seeing it in the field as well, okay?

Jeremy Tonet

Great. So it’s really the Eagle Ford and maybe the Bakken, number two is how you guys think?

Jeremy Goebel

Well, you can take and lump all of the conventional assets and probably it’s number two right, and then the Williston and the Mid-Continent are fairly close.

Harry Pefanis

Yes, if you exclude scoop and the stack, most of Oklahoma is on the decline and a little bit more severe than I think people would think. I mean, and you can cut it. I would encourage you to go to HPDI data, or whatever, where they have weekly rig counts, look at where they’ve fallen off. In some cases, they’ve gone down really far and what happened about two months ago is going to translate into today’s production decline.

Jeremy Goebel

The Mississippi lime is an area that’s probably had production declines that have decelerated recently over the last few month or so okay?

Jeremy Tonet

Great. Thank you. Yes, thank you. Another question on simplification although not the detail. My question is why now, given the complexity of achieving agreements amongst the various constituents stakeholders at this point in time. And if it’s just cost of capital, I’m wondering why you’re convinced that taking to pieces of paper that are well understood and putting them together will produce a higher price?

Jeremy Goebel

Unfortunately, probably today’s three minutes I’ve got left to answer that’s not going to give enough time to go through what is a pretty complex now. So, I mean, obviously, we’re not done if it was real simple, we would be there already. So the answer is right now is, I mean, clearly, our cost of capital is out of whack. We need to address it sitting by and just doing nothing doesn’t make a lot of sense.

So trying to come up with a solution, we’ve certainly seen in prior cases, we’re competing against MLPs that have eliminated the general partner and consolidated in a true simplification. And I have certainly the best cost of capital out there today. And so when you look at it on balance, it would not make sense not to look at it. And so we’re taking a hard look at it right now.

Jeremy Tonet

Great. Thank you.

Ryan Smith

That brings us to our first break. We’re going to have to take a pretty quick one to stay on track, but five minute stretch your legs. There’s some snacks over on this side, if you need a drink, we’ll pick back up at 3:55.

Willie Chiang

Okay, why don’t we go ahead and get going here, and get people back to their seats will get the show back on the road get the second session going. I’ll tell you, it feels like some of the Q&A has teed us up on a tall tee here to try to answer a bunch of questions here in the next session.

But let me, I’m Willie Chiang, and I’m pleased to be here. I joined the company just under a year ago. It’s not my first Analyst Meeting, but my first year at Plains. You heard Greg talk about the macro view, near-term challenges, ultimate price recovery, and then ultimate growth. Jeremy showed you the basins that we’re in, gave you the deals and decline and growth that we expect. And Harry talked a lot about midstream and kind of the paradigm in midstream changing and shifting from building large assets, taken what you’ve got, optimizing and acquisitions, repurposing.

So I’m going to spend my time on three things. One, I do want to spend a little bit of time on our business model, because I think it’s very important as it differentiates our ability to optimize the system. So business model and how we optimize, I’m going to share some comments on that.

Second item, I want to talk about is really to give you a feel to some of the questions we got about the capability of the system. I think what you’ll see is an incredible opportunity for us to capitalize on stuff we’ve built or already have to the tune of $1 billion as a spoiler here. And then the last one I want to talk about is give you an update on our asset sales program.

So before I get going, I do want to highlight one thing. I’ve known Plains for quite a while, but I would have been incredibly impressed with the view that we have in our analysis across the industry. I have worked for upstream companies. I have worked for downstream companies. And I will tell you that I think our view across the different basins in the regional markets and when you add the calibration of watching the flows go across our system, it really gives us a unique ability to strategize and position our portfolio as we go forward.

Okay, so let’s go to the business model. This is our integrated value chain. I think, you’ve seen the slide many, many times before, but I do want to spend a bit of time on it. We’ve got the producers on the left-hand side of the slide and the markets or the refiners on the right-hand side, and we participate in everything in the shaded area. And the point I want to make on this is from the producer, we buy barrels and you’ve got all those trucks, rail, pipeline gathering systems, barge and tankers to be able to get volumes to key hubs.

From there, we got trunk lines to take it to another hub, long-haul lines to take it to another hub. In each of these hubs, we’ve got storage tanks, terminaling facilities, which gives us lots of optionality and then you end up serving either local refiner needs, regional or actually now you can get to water and get to other U.S. markets, as well as global markets. 80% of our business is fee-based or fee-based equivalent.

And in that gray area, which I’ll share a bit more on an another slide here is to show you the capability of our commercial opportunities. There’s a lot of optimization opportunities in that gray area. This really differentiates us, because if you look at that system, Greg shared a bit about it. We’ve got a lot of size. We’ve got flexibility. It really allows us to grow our volumes even in today’s market.

I think John Edwards asked a question about, do we expect, as production falls that our volumes will fall. And I’ll point out on the first quarter earnings call that even our view of Permian Basin being flat, you can expect our volumes to continue to grow. And part of that’s, because we’ve got the new projects coming on with MVCs and we’re fierce as heck on competition trying to get the barrels into our system.

So now let’s take a little bit of a deeper dive into the value chain and particularly how lease gathering, on the far left side of the slide in getting that first purchaser barrel really is a distinguishing thing for us, particularly today – in today’s environment. You can see that the boxes – the green boxes and the blue boxes show you kind of margin opportunities that we have across the value chain, and how, with this interconnected system, one barrel flows through and has multiple touch points and generates fees across many of those.

So you can see in the center blue box, we’ve got pipeline margin. So, once we get the volumes in the gathering systems, we’ve got short-haul lines to get them to hubs, and then long-haul lines from there. We also have a lot of these hubs and terminals, and you’ll hear more about this from John and Sam. But we also have storage that we – that third parties take and pay us fees for, and then our commercial organization has capacity in this system as well.

And with this, we’re able to capture a lot of opportunities not always the same ones every year, but depending on the market whether it be blending of different crudes and getting uplifts on that. We’ve got storage contango plays, where the market will reward you for storing, storing storage, storing crude. And then the other thing with the system that we have with the flexibility, you really get the opportunity to capture a lot of arbitrage opportunities.

And when you have significant disruptions, for example, if you have a refinery go down in the Midland area and you were planning on taking that barrel to the Gulf Coast. If the market in Midland is higher, you can easily do that and substitute a barrel from somewhere else.

So that whole system I’ve covered in just a few minutes, but we’ve got an entire organization that focuses on how the heck can you optimize that well. And as you can see from the slide, the key is getting that first barrel into the system. If you can’t get the barrel in, you don’t get to play. And when you look at that margin opportunity across the whole chain, you can see how it gives us the capability to be a bit more aggressive in getting volumes into the system.

One other note is the Supply and Logistics Group Plains All American Supply and Logistics Group is actually the largest customer that we have on our system at just under million barrels a day of crude. Our marketing folks are buying 900,000 barrels a day and putting it into the system in the Permian Basin, that’s actually 450,000 barrels a day.

And then the other point I wanted to make on this is this whole lease gathering strategy changes depending on what the situation is. So the market that we have been in has been constrained pipelines, constrained capacities. And when you have that situation, your priorities are to maximize your lease margins. Volume is actually secondary, because the volumes are filled up.

And then when you go to an environment like we have today, where there’s surplus capacity in these markets, you flip that priority around. And for us now, the organization is focused on, let’s get the barrel in. Margins are not as important across the lease margin. But the question is, is it providing a positive margin across the system? So for now, it’s volume first, and margins second.

Okay, you’ve seen this slide and a lot of people have talked about it. It’s quite a capable system. I’m really focused on the crude side now. You can see, we’ve got a lot of pipeline connectivity. Again, we’ve got terminals, commercial hubs. We got waterborne access, and again, you’ll see a bit more of that in both Sam, John, and Jason’s presentations after this.

But what I wanted to show here is, we’ve talked about the basins that Jeremy has shared. We are in all of the key basins that are out there and the ones that we think are going to grow. And we also have access to greater than 50% of the refining industry. So back to Greg’s comment on size, capability, we’re in the right ZIP Codes for all of that.

And then when you look at where we spent our money, we spent $3 billion to $4 billion over the last number of years, and we’re finishing that up here this year and next. You can see the investments have gone exactly into those basins and areas that we think have a lot of capability going forward. And it really reinforces, again, that we’re investing in the growth, making sure we’ve got takeaway and access to markets for our shippers.

Now, let me go to the Permian Basin in a couple of slides, I’ll give you a better example of that. But before I do that, I wanted to give you a quick update on our projects. So what you see here is the same slide we’ve shown before. It’s our $2 billion of capital that we expect to spend in the next two years, $1.5 billion this year and $500 million in 2017 to complete all the key projects. The majority of these projects we’ve talked about have MVCs or acreage dedication behind them. So they’re anchored by some MVCs.

The majority finish in 2016, with the exception of our Diamond Pipeline, which is fourth quarter of 2017, and then our Fort Sask projects, which have phased startups. But you’re going to see a lot of the benefits from the completion of this year in 2016. All these projects further enhance the footprint. And again, if you look at the picture, if it’s one thing you take away from today, it’s we’re building onto the existing system we have and not only are we getting the benefits of the volumes and the new pipeline that’s being built, but we are getting pull through, through the entire system.

Post-2017, once we get these projects done, again, I’ll show you the capability of the system. We really don’t have a need to go spend significant amount of organic growth, particularly on big projects. And I think you’ll see us end up going back to the $300 million to $500 million of capital for organic growth projects.

Okay, this is the Permian Basin and you’re going to see this slide a few times. But I think some repetition is actually good. This is the value chain, but it’s from a different perspective. We’ve looked at it kind of as a schematic. This is from a geographic view. And what you see in yellow are the capital projects that we are building out in both the Permian, as well as the Cushing system.

These projects allow us to reach deeper into production fields and provide capacity to get into the system, such as the Delaware Basin pipeline system we’ve got off on the Delaware Basin on the left side of the Permian circle, as well as the Saddlehorn Pipeline coming down from the DJ Powder River basin into Cushing. And we’ve got a number of projects that really extend our market reach.

If you think about this just a handful of years ago, Permian producers were really limited to how many markets they could get to. It was essentially local refining markets, Midland, and access to Cushing, and everything else was a very indirect, circuitous route. With some of the projects that we’ve been involved in and again shown here in yellow, you can see we’ve expanded the reach of the Permian to many, many other additional markets. You can see the Cactus Pipeline, I’m working from the lower left and moving up to the right gets access to the Corpus Christi refiners.

We’ve got also waterborne access there, so we can get access to additional U.S. ports and ultimately at some point global markets. We’ve got the BridgeTex joint venture that we have that takes the direct route to Houston. And then you’ve got coming out of Cushing, our Red River Pipeline and our Diamond Pipelines that extend the Cushing reach into the additional refining markets there. And this is a great example of what I was trying to illustrate earlier is, where again you’re building onto the system that allows you to have pull through, through your existing systems.

Okay, this slide here talks to the capability and the capacity that we have. What I’ve – what I have shown here is all of our assets, but the colors mean a little bit different – have a different meaning. If you look on your iPhone, iMap or Google Maps, you got this – where is the traffic constraints at. What this shows is actually where do we have the capacity?

So when you look at this map and you see red, that means, we’re pretty close to capacity on those lines. The yellow lines are shown. We got zero to 100,000 barrels a day capacity, and when you go to the green lines, actually have over 100,000 barrels a day of capacity. And what we’ve done here is, we haven’t taken, for example, if we got a project that we built and it has an MVC commitment to it. We’re talking about volumes in excess of that MVC commitment. So it’s truly additional barrels that we can put in there.

This slide here is also the basis of a lot of our regional optimization work that we’re doing. We’re continuing to analyze every region and try – our goal here is to take green and yellows and make them red, and then find ways to bottlenecking, and it’s a continuous process you can see to optimize the systems.

Just to give you a feel for the volumes, again, going down from the lower left, Cactus, there’s a 100,000 barrels of additional volume there, BridgeTex, 75,000 for our half of it. Our Basin Pipeline Systems got 75,000 barrels a day capacity. Red River’s got a 100,000 and Saddlehorn, White Cliffs lineup in the coming down to Cushing, it’s got 100,000 Diamond and Cap – Diamonds are 100,000 and Capline, which we don’t talk a lot about, but that pipeline is significantly underutilized.

And in the case where that line would be reversed for our share, we’ve had easily 200,000 plus capacity. So it’s a different way of looking things. But instead of building an asset and accounting that volume will really trying to take our existing footprint and figure out what can we actually do with the footprint that we have. And you might say, it also reinforces the theme that we have this year, which is really significant capacity and capability and positioning for recovery.

And, again, you’ll see a lot of those volumes are in the Permian. So we had a lot of questions about, how do you get back to peak capacity? If you think about the Permian Basin, it’s got roughly 2.5 million barrels of takeaway capacity. We’re running about 2 million barrels there now. So, you can figure out what the timeline is, but we start approaching 2.5 million to 3 million, to 4 million to 5 million. The markets get tighter and things start to get back into balance.

So how do you quantify what the value of this capacity is? We’ve had the spoiler alert, and you can see it’s $1 billion of potential growth. But this really is an illustrative slide. We’re not giving guidance here. This is illustrative to give you a feeling for what the system can do.

So we’ve taken, how do you fill the pipes, and then we’ve also looked at our commercial benefits from a most balanced markets in these regions. Each basin, we’ve took the spare capacity. We also double check that against what we think a reasonable share of the market of the growth that we can achieve. And you can see on the top right, there is a $600 million bogie on the transportation and facility side to fill the pipes, with over half of this, by the way generated in the Permian.

The lower pie chart shows our Supply and Logistics capabilities. And this, again, when you get the market back into balance, lot of things change. We’ve talked about the competition for the lease barrel margins. But you can see, going from the top 12 O’clock moving around clockwise, markets balance a bit. The – you don’t get quite as competitive. So our margins will improve in the crude oil side. We also get NGL margins that benefit from it. And with the additional volumes that we put through, you can see we’ll get the green slice. And then there is a large slice on the left-hand side of the chart, which is really what we call our opportunistic – our opportunistic bucket.

And this is where having that commercial capability, whether would be blending, contango storage, being able to find regional arbs takes us back to a market kind of that we were in 2012 and 2013. And if you look at that kind of a market, we can generate that $200 million of opportunistic in the Supply and Logistics.

So, again, what this really is intended to do is just to give you a feeling for what the system we have once we complete our capital projects. We do have a lot of capability and you measure that in large dollars. What we don’t have is, when that’s actually going to happen, because going to be dependent upon a lot of things. And I think, we’ve got a pretty realistic case in here, and as an example, we did not include things such as the Capline reversal.

So let me now move to an update on our asset sales. I think you’ve seen a lot of this again on our last earnings call. We’ve upgraded our asset sales expectations to $500 million to $600 million for 2016. And as you know, we’ve closed four transactions for $350 million to-date. We’ve got another $150 million, we expect to close in second quarter.

The assets that we’ve sold have been primarily non-core assets and we’ve been able to have win-win situations, where the purchaser has had synergies to put to it, and they’ve been able to pay a larger value for us. They’ve been able to cap the synergies and we’ve been able to monetize it.

Now regarding the line in there about evaluating additional asset sales, I do want to give you an update. We’ve actually retained bankers to take our Northern California, our Richmond and Martinez terminals to market here very shortly. This is about 5 million barrels a day of storage capacity, both crude and products, and we expect to take that to market here in the next few weeks. As you can expect the proceeds from the sales, obviously allow to redeploy capital into more accretive investments around the core assets or buy assets and debt reduction.

So let me close on a slide here. It again just reinforces, I think what the story is. We’ve really got a great system at Plains. We’ve got – we’re in the right growth regions, finishing the capital programs that I talked about really strengthens the asset. I can assure, you were very focused on optimization and trying to get everything we can possibly get out of it, including looking at some difficult decisions around our portfolio and executing successfully on our asset sales.

Last but not least, we’ve got a capability – we’ve got a system that has got a lot of capability. And back to leverage to recovery story, we look forward to kind of sharing our successes with you as we see them.

So with that, let me ask Sam to come up and he’ll go into the transportation assets a bit more. Thanks.

Sam Brown

Thank you, Willie. My name is Sam Brown. I have commercial responsibility for our U.S. Pipeline assets. I’m going to try to give you a more in-depth and forward-looking view of our integrated business model centered around our pipeline systems. Our major 2016 initiative is to maximize the utilization of our transportation segment assets, and really it’s all about optimization and why we feel we are in the best position to compete going forward regardless of the pace of this recovery.

In this current price environment and after five years of investing in significant organic projects, we are now focused on optimizing our regional pipeline platforms by increasing revenues to our different commercial activities, reducing costs by identifying and rationalizing marginal or non-core assets.

As you’ve heard, we have complementary operating segments that provide cost effective transportation solutions for our customers to the highest value markets as evidenced by. We have an extensive portfolio of interconnected assets, which gives us a comprehensive network of pipelines, terminals, trucks, barges and rail facilities, which we allows us to wrap our services around these assets.

We have significant and experienced lease gathering capability that are available to base-load these assets. This provides us a competitive presence at the wellhead and aggregating supply, which as Harry pointed out is – makes us unique among our peer group. We’ve had numerous growth opportunities that have been supported by our world-class terminal facilities at the major trading hubs. This gives us a better market optimality and adds value both to our assets and our customers’ portfolio.

We have a unique vantage point within the crude oil industry by able – by being able to match up with producers and refiners in our day-to-day relationships, understand their expectations, right size opportunities, and bridge the expectations from one group to the next. We have extensive longstanding customer relationships. In the eyes of our customers, we are credible and creditworthy.

How did we get here and where are we going? Prior to the advent of horizontal drilling in these oil-rich shale basins, PAA had already developed regional platforms of interconnected assets through a series of acquisitions. The subsequent increase in production in these areas has allowed us to expand on this footprint, and add reliable storage and pipeline capacity to meet our forecasted production gross scenarios.

With the surge in production and the change in supply demand patterns, our capital projects have focused on both supply solutions and demand solutions. Bottom line is, we’re ready. We are ready with robust systems that have ample storage in pipeline capacity, and we are going – in addition, we are going to fully utilize our marketing and terminalling resources to grow these businesses.

This slide is just an illustration of our growth over the last five years. Over the last five years, we’ve transitioned into an organic growth enterprise, while also idling and removing marginal or declining storage and pipeline assets. We’ve improved our asset base by constructing 6,000 miles of new pipelines, while removing 4,000 miles of pipelines that were tired and ready to be brought out of service.

In the process, we have also done substantial terminalling and manifolding improvements to add capacity and capability to help meet these future growth projections. As we’ve transition from an acquisition model to an organic growth model, we’ve replaced old with new and have safer and more reliable business.

We’re going to talk a lot about the Permian Basin today and the reason is, we’re heavily invested there, and we think it has the most upside potential of any producing area in our industry. Permian Basin is a model for our PAA supply push pipeline interconnectivity. PAA owns significant interest in export pipeline capacity from the Permian.

Our basin system is our oldest system that we’ve owned and it has $375,000 barrels a day of capacity from, basically, New Mexico through our Midland terminal into our Cushion terminal. We also have a wholly-owned interest in our Cactus Pipeline, which today is rated at 250,000 barrels a day and it’s currently under expansion to 330,000 barrels a day.

And our net interest in the BridgeTex Pipeline accounts for 150,000 barrels a day of takeaway capacity out of the Permian Basin. But over the last five years, we’ve also developed robust gathering and delivery platforms in both the Midland and Delaware Basins that are linked to all the export pipelines in the Permian, not only the Plains interests, but also third-party interest.

Plains is the largest aggregator of Permian Basin production. Our gathering assets touch roughly 45% of the daily Permian Basin production. So we’re able to provide complete wellhead to market solutions with superior connectivity. It sets us apart from our peer base.

So one thing we’d like to talk about and you’ll hear a lot is our multiple fee model and the Permian Basin is the best example of this, and I’ll talk more about that on the next slide. So our pipeline platform provides us a complementary business model, which works in conjunction with our marketing and business, our marketing business and terminal business also.

This is one of my favorite slides. It’s busy. It looks like a spaghetti bowl, but it’s a well-designed spaghetti bowl, and we’re very proud of it. Basically, this is an illustration of our extensive footprint in the Permian Basin. We have coverage in all three basins, the Midland Basins, Central Basin, and the Delaware Basin.

We have a multiple fee model in all three basins. Basically, when you look at this, we have gathering assets, which are our smaller diameter pipelines, which are connected to our interbasin trunk lines, which are connected to our regional hub system. From there, we deliver through our larger interbasin trunk lines to our bigger terminals and then to the export pipelines. So we get a fee for gathering. We get a fee from moving within the basin and we get a fee for leaving the basin.

In the meantime, we have about 10 million barrels of storage around our pipeline assets in the basin, and this is very important once again is what sets us apart from our competition. These regional hubs and storage allow us to ratably gather and deliver crude, so that we don’t interrupt the production flow with our producers and meet the delivery schedules with our connecting carriers and the refineries can run on a ratable delivery schedule.

So most important is this system access a fungible header system throughout the basin. So that we’re able to make deliveries to all the yellow dots that you see on here, which are all the export pipeline delivery locations. This is as close as we’ll get to a gas system in the industry.

I’ll talk a little bit about our 2016 pipeline projects that Willie mentioned and there are – three of them are demand pull oriented and we’ve got one supply push oriented pipeline. I think this slide is important, because it’s really focused on our Cushing Terminal more than our pipeline projects.

Probably our Cushing Terminal is the best example of Plains ability to grow and forecast the needs of the industry. We have the premier terminal and John will talk more about that in a minute. But really the Cushing Terminal as a mark – Cushing as a market hub and our terminal’s preeminent position there has either complemented or drove the development of these pipeline projects.

The Diamond Pipeline goes from Cushing to Memphis to support Valero’s Memphis refinery. And Valero picked Plains and Cushing, because they wanted diversity of crude supply and they wanted to company that execute on a ratable basis and deliver to their refinery when they needed there.

Our Red River Pipeline and Diamond Pipeline is supported by long-term contractual commitment. Our Red River Pipeline goes from Cushing to Longview, is also supported by two refiners in the ArkLaTex area. And once again these refiners wanted the ability to source Midland crude, but instead of signing up for somebody out of the Midland area, they also wanted the diversity of being able to source Midland and Cushing crudes. And so we gave them a solution to where they could do both through our basin in this new Red River Pipeline.

And finally, the Red River Pipeline is connected to the Caddo Pipeline, which connects to the refineries. And the last example is our Saddlehorn Pipeline out of the DJ Basin. We’re real bullish on DJ Basin from a resource standpoint. We feel, it’s a good investment long-term and complements our White Cliffs investment. And this is a supply push investment, but it’s anchored at the end with our Cushing terminal.

So this incremental connectivity at Cushing adds value to our facilities and they also add value to our customers’ portfolio of assets. It gives them access to multiple markets, access to multiple grades, and it drives demand for our services.

Finally, I want to reiterate what Harry talked about earlier and it’s really a driving concern within the company and always has been. In addition to improving our asset base for the last five years through organic growth initiatives, we have also made significant investments in maintaining and monitoring the integrity of these assets.

So it’s important for PAA’s transportation assets to deliver safe, consistent and reliable results. PAA maintains a consistent and enhanced comprehensive suite of integrity management and risk-screening programs, including a continual improvement process. And we have ongoing management and Board of Directors reporting to increase knowledge throughout the organization and share transparency about our results.

That’s all I’ve got. I’ll turn it over to John

John Keffer

All right. Thank you, Sam. My name is John Keffer, and I’m responsible for the terminal activities within our business. I want to make a few points before we go on. The first is today, I want to be able to show you how – what the U.S. terminal role is in the midstream value chain that Willie talked about.

I want to show you, additionally, how it does serve as a platform for growth for other Plains assets and allowed the growth in my areas is not as robust as other asset basis. I want to show you that it is constant and it does perform in all sorts of markets. And lastly, we’re going to talk a little bit about some of the activities behind what we’re doing to operate in a safe and complaint manner.

I know you’ve seen the slide before, but one, we really like it. Two, is it drives the point home that Plains has a significant presence in the liquid-rich regions and strategic locations throughout the central U.S. and the Coastal regions. In our total portfolio, we provide liquid storage, gas storage, marine and rail capabilities that allow our customers to take full advantage of all market conditions, and increase their flexibility, which brings them to our assets.

Connectivity to the Plains system is extremely important, as well as connectivity to the other industry systems, which we’ll see in just a moment. Also, Plains well positioned for future growth, be it organic, acquisition, or an increase in domestic production.

Focusing a little bit on the U.S. crude terminals, I want to explain in some of the ways why it has so many advantages to our customers? First of all, Willie slide showed earlier, our primary customer base are going to be the producers and a refiners. And within that, we have great connectivity to the oil in the field that brings it into our facilities and then takes it directly to the refiners. And that’s important, because the two things in my line of business are important or segregation and crude quality.

And the fact that, we have these direct connections does give us the ability to provide those assurances to our customers. Also, within our facilities, we have extensive line for management endeavors that help ensure that we maintain quality while the crude is in our custodial care.

Also within our facilities, this is more than just housing crude as it comes through from pipelines and stored during different market conditions. There is actually business to transact there, and it takes place multiple times every month. Also, our facilities provide for operational upsets at any level, whether it’s in the field or it’s in a refinery.

Our pump capability is superior. Then on our header system is complex, such that we can provide multiple services, such as blending. For most of our refining customers and they do it for a number of reasons, whether it’s to maximize volume, through viscosity, through a pipeline, or just to take advantage of the multiple grades that come into our hub and the Cushing facility. Also, they use it for contango and we’re seen that in the recent past.

This slide gives you a feel for why our hubs are platforms for growth. The connectivity that you see that’s example that – and the example that you see in the center of the slide, the – just briefly that blue lines are the incoming pipeline systems through our hubs. The red lines are outgoing pipeline systems, and the green are actually buy directional.

The dotted lines that you see are the systems that are in some phase of development, whether they are – we have a connection agreement already and we’re waiting for construction or they’re currently under construction. Of course, you’ll see the Diamond Pipeline project and the Red River Pipeline project at the Cushing hub that Sam talked about just a few minutes ago.

And you can see the connectivity and all the different types of crudes in the regions that it comes from, that attracts those customers to those projects. Also, in the lower portion of this slide, you can see some smaller hubs. And the reason why I put those on there is, because we have – we do have other projects at our secondary tier hubs that will contribute to other segments within the Plains – within the Plains Group.

One of the things that we’ve done at our main hubs is, we’ve overbuilt the manifolds, and this is particularly true in the Cushing hub. Back in 1982, when Greg and Harry first built Cushing, they built a manifold system that was far and above what they needed for the 2 million barrels that were built. And while it took a little bit for that first growth spurt, once it started, we saw positive results, both economically and timing that allowed us to increase the storage and services at that hub, prior to any other significant of capital being put into the infrastructure.

As a matter of fact, if you look at that slide under the graph underneath Cushing, you’ll notice that 2010 Phase 7 was actually the first time that we had to spend any significant capital for the manifold. We now have three separate manifold systems that have plenty of capacity for future growth. And as we look at our other terminals, we’ve used this same philosophy. And with 5.5 million barrels of capacity that we’re building today, we can do it without any significant capital toward infrastructure that helps us both in timing and with our economics.

Lastly, our – in this slide, our recipe for growth has truly been our ability to have relationships – long-term relationships with our customers. That comes from handling their crude and developing their trust, finding solutions to their operational issues and the instance that there is a problem that we handle it correctly and in a timely manner. The results are shown in the lower right-hand portion of this slide. We have re-contracting rates that are at 90% or above in most of our terminals and actually most of them are over 100%.

I didn’t want to go through this presentation without talking a little bit about our coastal hubs. We’ve just recently received the export ban has been lifted, and we have the ability to take crude to other countries if we – if the market dictate. Well, all of our crude oil terminals can service ships either inbound or outbound.

It’s a matter of fact, St. James from 2015, while it has serviced multiple vessels of various sizes has loaded 36 vessels for export and most of those were actually under special certification bound for Canada. But we have the capability today and we can service our customers. And when you couple that with the pipeline capacity that we have at each of our terminals, we can provide for any market condition for our customers.

Lastly, I do want to reiterate what Harry talked and what Sam touched on is that, we have an extensive facilities integrity program. And the first one is the facility integrity management program, which was developed from a series of prior programs. But the idea behind this is primarily to make sure that there is consistent and – I’m sorry, yes, that’s right consistent application to this process for every facility.

In this program, it mitigates releases by in terms of the inspections and then the non-invasive testing that we do. In the developmental of the programs – I’m sorry, the tank integrity program for line – the API 653 program was developed in order to protect and assure compliance and reliable service for our tanks, which includes both internal and external of inspections at our periodic intervals.

Anyway, we don’t need to go through all of these, but I just wanted to bring it up in order to emphasize the point that we do have carry a great importance to operating safely and with operational compliance.

With that, I will turn the podium over to Jason Balasch.

Jason Balasch

Good afternoon, everybody. Ryan is giving me the hurry-up signal already. So I’m going to skip the outline and introductions and jump right into the Canadian business. I’ll start out with a bit of a fundamentals overview of the Canadian crude supply. In the top left, you’ll see a graph with our kind of our forecast for conventional – Canadian conventional crude. This ties with Jeremy’s mid-case, really in assumption of moving back to more normal activity levels in mid-to-late 2017 and growth ramping up from there.

What’s a little different from the U.S. crude outlook is in the bottom left of the oilsands supply. We’re forecasting continued growth with that throughout the period. There is – there are several major projects coming online, lots have been cancelled. This graph doesn’t slop up with growth as much as we had originally anticipated, but we still see continued growth.

A word on Fort McMurray, it’s been in the news a lot. We’ve had about 1.3 million barrels a day of production offline due to the fire. The news from there is sounding pretty good. There has been some rain, and unfortunately for us in Calgary some snow. But fires are under control and moving away all the major facilities are either in the process of restarting or staffing up to restart and we should be getting back to normal there soon.

One bit of perspective, when all that happened and even at the worst and most uncertain times for the market with considerable production shutdowns, the Western Canadian market, it moved and prices went up, but not near as much as maybe some of us would have expected a few years ago. But with the growth in the past few years and more storage tankage and storage in Western Canada and a Cushing in high inventory levels. This event wasn’t – didn’t really have the impact on the market than we might have guessed.

So, from a long-term perspective and a macro market perspective, not a major event – major event for people living in Fort McMurray and some of the other places. But not really anything we’re spending any more time on it. The production growth and oilsands growth will at some point depending on the rate of recovery mean the Canadian production once again exceeds its export pipeline capacity takeaway. And to talk a little more about that, I’ll talk about our Plains Canadian crude assets.

That’s shown on the map in red. Those are primarily the trunk lines. But similar to a lot of the U.S. systems, we have trucking. We have gathering lines and trunk lines and the system is really designed to gather crude into three major storage and crude oil hubs at Edmonton, Kerrobert and Regina. At all three of those hubs, we can inject crude into the export pipelines and bridge Trans Mountain and some of the others.

And if you were here last year, I talked about how the system is really well situated to connect to some of the upcoming and announced really crude pipeline megaprojects Trans Mountain, Keystone XL, TransCanada’s Energy East, major Enbridge expansions. Our hubs in our gathering system, it really well situated to connect into those.

But with the current political environment and the social environment in the market, we feel like we’re all a little maybe longer way away from any of those projects getting completed then we were hoping for a year or two ago. And kind of time to the theme that we hit several times to the presentation, we have in Canada been more focused on our existing assets and existing system and getting value-added capacity in that system.

And there’s two real obvious opportunities for us with the crude pipelines, both the Rangeland Pipeline and the Wascana Pipeline highlighted by those big arrows. Those are existing pipes with spare capacity that cross the border that have existing residential permits and a well setup to move crude south when the demand for that movement increases with growing production.

The first is the Wascana Pipeline. Right now, it connects us – I’ll show you on the map in the second, but it’s moving – right now moving crude north out of the Bakken into Regina for transportation on Enbridge. And the second is Rangeland, right now Rangeland is moving crude from Southern Alberta.

Mostly north into Edmonton and there’s a small amount of crude that moves south into local Montana refining markets, but there is a lot of spare capacity and opportunity with both of those border crossings. This is another version of really our favorite map today. It shows the Canadian crude system, some of Plains major U.S. pipes and then some major third-party pipes that move crude out of Canada to the U.S.

Back to Wascana, I mentioned we’re moving crude north out of Trenton right now at the Regina. Once Enbridge Sandpiper or Energy Transfer’s Dakota Access come on, we expect them to have spare capacity to move crude out of the Bakken and that really creates an opportunity for us to reverse Wascana and move Canadian crude south to Trenton and then on to markets whether it is Patoka, Cushing or wherever. These projects – there is spare capacity. They will take some capital were working on defining that right now, reversing, debottlenecking, things like that, but the capacity is really there and waiting for the opportunity.

The second one is Rangeland, and as you can see it’s directly connected to Plains Western Corridor and with more capacity in Saddlehorn and the spare capacities that really was talking about there is an opportunity to move Canadian crude south today right to Cushing.

And there’s a lot of Canadian crude moving to Cushing right now on Keystone and the Enbridge systems and some of those others Canadian crudes becoming more and more important in Cushing market. This gives us a ready-made opportunity to provide Canadian producers with another way to move to Cushing and access the markets south of there as well. So both of these are exciting optimization opportunities that we’re working on and the good example of the kind of things we’re looking at in a capital constrained environment.

I’ll move on to the NGL business. Now I’m going to talk a little bit about our business and our strategy and then I’ll move into the recent acquisition that we announced and how that fits in it. First of all, NGL supply outlook, same story here, kind of the same assumptions around returning to activity levels, a couple interesting things or a few interesting things with this graph is, one – once we do get to normal activity levels we shall growth well belong – well beyond previous historical highs.

The second thing is that surprisingly a bit is we’ve seen an actual spike in production in the last half of 2015 and the early part of 2016. There’s been a number of gas field developments and gas plant developments that were started before the downturn that were finished and production actually has kicked up.

The last thing I’ll point out about this is most of the future growth is forecasted to come from the BC, Montney and the Alberta Deep Basin. It’s kind of tough to see on the overlay map. But our assets particularly are Co-Ed Pipeline are well positioned to capitalize on that growth and there is capacity there.

This is a map of our NGL business. It’s a North American wide supply and marketing business. I talked a bit about it last year and really the base for the system is equity supply centered around our Fort Saskatchewan, Empress, and Sarnia assets. That’s a system of NGL gathering, fractionation storage, gas processing, really – primarily a fee-based business to bring liquids into the system.

But really what makes this business unique is – it’s more demand more demand-pulled and supply-push. All the red squares throughout the U.S. are various market based and market focus terminals. Storage in your markets, rail to truck access in your markets and we really do try and we do market NGLs and LPGs particularly continent wide.

And I show this last year, and talked about it, what I wanted to add this year was, we improved our graphic and you can see all the green dots there, these are major third-party terminals that were active and marketing through. You’ll see a few green stars sprinkled in there. Those are facilities where we have 100% access to whether it’s 100% control of the throughput or 100% control of the supply. But that really gives us a better graphical representation of our North American wide marketing focus.

I’ll take a step back and jump into some numbers now. I talked about equity supply, all of that comes out of Western Canada, either through our own Co-Ed Pipeline or through other third-party mixed pipelines to the Fort Saskatchewan facility, major production that Empress and we have the ability to move product on the Enbridge Pipeline to Sarnia where we have another fractionation and storage hub.

Throwing some numbers out there are mixed supply right now is 109,000 barrels a day and that split between field supply, which is purchasing liquids from other folks, really on a liquids price basis and straddle plant supply from our own or other straddle plants, which are major – big gas processing facilities straddling gas transportation systems. But the key there is straddle plant supply typically priced on the gas price basis.

I’ll talk more about the Empress acquisition in a second, but when we were talking about supply, I wanted to point out, it’s going to add to our supply, brings us up to 124,000 barrels a day. But more importantly a balance is so between field and straddle supply a little more evenly, and the root of our businesses we’re selling NGLs and the ability to buy NGLs both on a liquids price basis and gas price basis provides us a lot of flexibility both on sources of production and pricing of production.

Once we have the equity supply, the second point to our system is we do buy a lot of third-party spec LPGs from other folks and I won’t go into a bunch of detail here, but the point I wanted to leave you with is we’re buying throughout the U.S. in different regions and relatively balanced. Obviously, we don’t buy as much as in Canada, that’s where the equity is. But we need to buy a lot of third-party supply throughout to manage the content wide market.

If you take that equity supply in these third-party purchases, it works up to a regional sales profile, roughly represented by this graphic and again without going into detail, the point is it’s fairly well balanced geographically across the U.S. and that’s really the heart of the strategy as we buy supply in multiple locations, we produce supply east and west multiple locations and we sell throughout the continent.

And it’s a real Supply and Logistics business and what we do is use the flexibility of multiple markets and multiple supplies to balance region. This is a snapshot of how we think that – how that’s going to play of this year. You can see obviously a lot moving out of the west into different markets.

But you’ll notice, we moved the supply into the Southeast and Midwest supply into the west and really it’s – again it’s just – it’s the nature of that strategy, supply and markets in multiple places and optimize it. In a year or two, this regional transfer could look a lot different, but if production – regional production profiles change, we can shift our supply focus and move demands around. If demand changes due to weather or other factors we can shift supply around and move it region to region.

The point is that the flexible system and another one I’ll mention is, it’s really based on – the economics are based on regional supply differentials that makes us somewhat desensitized to price movement, a lot of the value in the system is moving between regions of high-value to – low value to high-value. We’d like higher prices, but its region – really a regional basis, differential system and so were somewhat insulated from that.

Now we talk about Empress acquisition a little bit. We announced recently the purchase of Spectra’s straddle plant business in Canada for $150 million. We’re currently going through a regulatory process and approval process and we’re hoping to be able to close that transaction sometime in June or later this summer.

The assets shown in orange on the map, there’s another gas straddle plant at Empress, right across the street from our existing facility. A fractionation facility at Empress, pipeline from Empress to Fort White, storage and terminals along that system and rail terminals at Empress and Fort White.

If you can look at the map and see the obvious fit, you can look at the value chain and see the obvious fit. It’s gas plant, it’s fractionation, it’s storage, it’s terminals, it’s exactly what we do. But Greg had mentioned his three criteria for acquisition were synergy, synergy, synergy and actually not planned, I do have three kind of strategic things that I wanted to layout that we really like about this acquisition.

The first I already mentioned partly is that extra supply at Empress and it straddle supply. But also what’s really important about that supply is it’s – is the fractionator there. Right now our system for equity production, we can either fractionated at Fort Saskatchewan or Sarnia, but all of our Empress production today has to go to Sarnia. That fractionator at Empress has spare capacity. We can utilize it for our existing production and Spectra production, but it gives us the option to make more liquids in the west and distribute them in the west. That’s what those regional balances dictate.

The second real strategic benefit for us is that – is the truck terminals and storage along that pipeline. It gives us more product market access in an area Saskatchewan and Manitoba where we really don’t have a significant product, presence right now. And third and probably most importantly is that rail facilities at Empress and Fort White.

My regional balance slide and the strategy and all I talk about moving product around, a lot of its on pipe, but a lot of its on rail. We do utilize rail quite a bit to optimize the system and if you have a facility, most facilities are connected to a single railroad that – when that happens you disadvantaged. One, geographically to where that railroad goes and two, trying to negotiate rates of the railroad stuff if you only connected to one railway.

Empress has connections to CP and Fort White have connections to CP and BN, and what that does when you take our system now from Fort Saskatchewan to Sarnia with the Empress rail rack and Fort White rail rack in the middle of it, really the same equity liquids in our system, our equity production can now access five different railways, which really helps us out geographically and rate wise.

So just real quick to give you kind of a graphical overview of what these facilities will do for us from a product distribution standpoint; this slide shows roughly how the system works today. It’s an approximation, but the gray circles are really a realistic truck access market and red circles are storage and we’re really centered like I said with our equity production at Fort Saskatchewan and Sarnia.

And we can access a lot of markets via rail out of those areas. But you can see a gap in the middle and with Spectra it really fills in the middle. We’ve got a lot more truck access to the Southern Canadian and Northern Midwest U.S. market and with two more railway connections it just gives us a lot more optionality and where to make product, where to send it out and where to send it to, which again is really part of a whole strategy.

I did talk quite a bit about Fort Saskatchewan being a hub and we talked about it last year, the expansion project is ongoing. It’s a major capital investment and some of the phases that started up already and we’re already beginning to see the benefits from those. We’ve got more caverns, rack expansions and other facilities coming on stream in the next couple years.

And this next slide, again we showed it to you before, but what it does, it show what the growth – what this expansion projects really doing in the growth from where the asset was when we acquired it in 2012 to where it is today? And what I want to highlight here again trying into that theme of our business strategy is not only there’s big numbers and doubling land footprint and frac capacity and more storage, but it’s really the added flexibility. It doesn’t show up on the slide, but we switched from really just storing mix to storing products.

We’ve added rail loading. We’ve added truck loading, and once again it’s the same as with the Empress, Spectra Empress frac, gives us more ability to decide whether we want to make product in the west and market them out of the west, to the Western half of the continent or send them east to the Sarnia hub. But this expansion is going to work out real well for us in terms of product flexibility and fitting into that overall strategy.

Finally Harry, Sam and John, all talked about various aspects of pipeline and integrity management and operational excellence. In Canada, it’s no different. We’ve been on a multiyear journey to really develop and implement an operational management system and that really governs and puts a lot of structure around every facet of our operation and engineering functions just the way we do our physical business brings it all under one umbrella.

Pipeline integrity and facilities integrity are key pillars to that and we’ve got a lot of – we got a lot of effort focused on that. And I wanted to point out, the sub-bullets there are – are there that pipeline integrity is more than a single topic. There’s a lot that goes into it in a lot of different facets of it. Same as facilities integrity management and all of this is stuff we’ve been doing in and all responsible operators do for a long time. But we’re really focused on now is developing programs and consistency around those.

When I looked at the draft of the slide with sub-bullets, the word program pops up there every time and I thought it looked a little stupid, and I started deleting them. But I decided to leave them in there, because I did want to make the point that each one of the sub-bullets again it’s more than just a concept, each one of these now has a very detailed program of consistent policies, procedures, measurable goals, self-assessments, third-party audits and it’s kind of a constant improvement cycle where we set goals and measure how we’re working towards those goals in a lot of different ways of checking into things.

And it’s more structure and more focus on things that we were already doing, but as senior management goes from my standpoint, I feel a lot better having a system like this in place. It’s a lot easier to call it down and make sure that with all the complexity of all this that we’re doing the best we can. We’re exceeding regulatory compliance wherever we can and we’re not dropping any balls, missing one piece of this or missing one region. So can’t stress enough how much effort goes into this and it’s the right thing to do and it will pay off long-term for our operations.

Finally just to conclude, and it ties in with a lot of the things that that Willie and Greg particularly talked about. I came up in the Q&A. We knew – we know we need to implement capital program that we have going on. But we have focused a lot more on optimizing and finding value within our existing assets.

Those crude connectivity projects are one good example of that. But another thing I didn’t really have a slide on, but I’d like to address is ties to Willie’s value chain in Canada, the crude system and the NGL system are both full value chain from wellhead to market systems where we make money, collecting fees or moving products around regions at every step of the way.

And that full value chain has really given us a lot of opportunities to optimize the system. We are competing stronger for volumes and ensuring that we keep our capacity full and having that access to that value system and looking at is as an end-to-end business. It has paid off a lot of dividends for us already and it’s going to be a focus going forward to make sure that we continue to grow the business, given our capital constrains and existing spare capacity.

So with that, I’d like to thank you and move on to Q&A. How would I do?

Ryan Smith

Actually, not quite, so at this point in the presentation, we had our second Q&A session planned. In the interest of time, we’re going to have to continue with the presentation. I’m sure some of you have questions at this point. If you do, just hold on to it. We have a third or following our closing remarks at the end, if you recall. We’ll have a full panel for Q&A purposes and hopefully we can address your questions at that time.

So one quick housekeeping notes, if you are not attending the game tonight, which therefore you do not have a game ticket in your possession, what the Astra security is telling us, you – they really don’t want you going out these doors. If you need, believe the rooms are to make a phone call and you don’t have a game ticker, you need to go out the back doors, given what they told us.

So appreciate with conservation there, and Al is going to go forward with our financial overview.

Al Swanson

Thanks Ryan. My presentation, I’m going to touch on our financial strategy. Our execution against it, 2016 guidance, and a little bit of historic performance, counterparty credit worthiness, DCF distribution coverage, as well as just touch on PAGP’s tax attributes.

Financial strategy, this has been generally consistent, really since inception of the midstream, pre-IPO arguably. So for a very long time, we think it served us very well. It served us very well with the execution of our business strategy over – again, since inception for over a decade.

Targeted fund growth capital with a prudent amount of equity or retained cash flow of 55% at least. Minimized market risk, we’ve done that a number of times in 2015 and then 2016. Target a credit profile that is commensurate with investment grade credit ratings, as depicted here. I won’t read all the metrics to you.

Achieve and maintain mid to high-BBB-equivalent credit rating. Clearly we’ve got a lot of questions around the investment grade, hopefully through this. We are committed to investment grade. We intend to retain our investment grade credit ratings. Maintain significant liquidity as well as prudently manage our interest rate exposure and debt maturity profile.

Cap structure and credit metrics, as you could see, this shows kind of year ended as well as end of the first quarter for both PAA and PAGP. Two points really to note, clearly the preferred equity raise that we did in the first quarter significant improvement in our financial position as well as when you look at the consolidated metrics PAGP, there is a modest amount of debt at the GP entities above the MLP, approximately $600 million. So you see some change in credit metrics, but not a material change when you look on a fully consolidated basis.

Sources and uses of cash: we used this on the conference call just with the asset sales and acquisitions just kind of give a bigger picture. In essence, we’ve commented publicly that we expect to exit 2016 was slightly less long-term debt than we entered the year. You can kind of see the math $1.6 billion, $550 million of asset sales basically that the midpoint of the range Willie mentioned earlier, uses our capital program, the Spectra acquisition Jason just discussed.

We view kind of the swap of higher asset sales, selling non-strategic assets to us and redeploying it into something that is clearly very strategic for our business in our NGL platform. We think that’s a win-win. Greg mentioned earlier, the cash deficit on the distribution $240 million, this assumes flat distributions for the year and that we picked the preferred and you can see the map about $260 million that would be available for debt reduction.

Debt maturity profile and kind of the view of it at 3/31 $19.2 billion, 13 year average maturity, 100% fixed, and average rate just under 5%. This doesn’t show the two small maturities we have in the next 12 months. We have $175 million note in August and a $400 million note in January the preferred effectively refinanced those, so we’re showing those as short-term debt on a March 31 balance sheet.

The other point I would mention just in the callout in the upper right, kind of shows the – kind of change of this mix over several years going back to 2009, clearly, roughly the same maturity a little longer significant growth in the company, but significantly lower average coupon, clearly we’re in a very low rate environment and have been for a few years. That is one of the reasons is driving us to 100% fixed. We don’t believe it makes sense to flow when the rates have been were there at.

And a lot of data on this slide, and we have had a long track record of financial discipline and funding growth for a long period of time. The bar charts on both sides, the top one shows book capitalization, so you can see over this period roughly nine times growth in capitalization.

The bottom one, the bars represent cumulative invested capital over $20 billion during this period. The redline and the little shaded area shows RT credit metric that we will get long-term debt to EBITDA and you can see a good track record for a large number of years and clearly we went about our target at year end 2015 at March 31.

The same date in the bottom chart with the red line – the green line shows oil prices, clearly the industry conditions and the impacts that have caused our leverage to be higher. We are committed to our leverage metrics in our financial strategy that I articulated earlier. We’re committed to the investment grade ratings we recognize that we need to keep a close eye on this and manage it to return back into be within our metrics. Again clearly cash flow growth projects industry recovery but we will look to manage to get back with him our credit metrics targets.

Liquidity, one of the other key points on the financial strategy that red line show kind of what a high and low has been for number of years that the line be in kind of the average. Clearly we’ve had a very intense focus on making sure we have prudent amount of liquidity. We view liquidity as has both offensive and defensive of aspects to it.

Clearly in challenging times, it provides a degree of Cushing and the offensive side of it is – it allows you to move very decisively should opportunities present. So again you can see following kind of the financial crisis of 2008, 2009, a more intense focus on making sure we have adequately liquidity.

A lot of data on this chart, historical kind of guidance and performance, when you look at the top bar chart, what you see is basically a consistent growth in the two fee-based segments, transportation and facilities. You’ll see more variations in Supply and Logistics, a little bit like what Willie was describing earlier.

Clearly there was a period of time in the recent past were rapidly growing production of the shale basin, lack of infrastructure created a significant kind of above baseline environment for that segment. When you look at 2012, 2013, 2014 we’ve always expected that that segment would produce around $500 to $500 million of what we call baseline. Profit had a Supply and Logistics; we were articulating that as we were generating $800 million, $900 million and in essence our view was that won’t be sustainable.

We’re now entering a period where you heard Willie talk about intense competition at the lease margin compression form overcommitments on MVCs. You can see we dial that in. We’re forecasting for this year below what we felt like baseline was at $440 million of Supply and Logistics segment profit.

The bar charts and the data in the bottom are volumes and unit met margins that support the data in the top bar chart. Transportation what you can see is raising – growing volumes, growing margins, again even in this environment were growing volumes just not as much as what we would expected 12 or 18 months ago.

Facility segment, kind of the same slight growth, little flatter margin. Supply and Logistics, you can really see the impact a little bit of the return to more normal markets are now very intense competition on the margins for the Supply and Logistics segment by the red line and in that chart.

And for a number of years, we’ve communicated that we believed with capital investments that we would see a migration from the fee-based mix to about 80/20. This chart really shows that that we’re approaching at or add that this year, again that’s not a surprise that something we expected, again driven by the investments and in pipelines and terminals.

And this chart, we’ve got a number of questions for the last several months around MVCs, growth of MVCs credit quality around those contracts. What I try to do here was on the bar chart side on the left panel of really show kind of some of the growth projects that that Willie discussed that have significant MVC back into six pipeline projects and – what you can see is the difference between 16 and what they step up to or what they will be when they hit kind of run rate generally late 2017 and 2018, again Diamond doesn’t come on till late in the 2018.

The little circle graph on the other side shows kind of the credit quality of our portfolio of MVCs including other existing ones and legacy assets. But what you see is roughly about 80% on investment grade. Companies, we do have non-investment grade or non-rated entities behind them. We do our own credit work behind these. We actually don’t rely on the – take a credit rating as the basis for a – our capital project or credit extension.

Again a number of these are backstopped by – of non-investment grade or backstopped by refiners on demand-pull project. As I discussed and walk through in detail on our February earnings call, we do have non-investment grade producers backstopping contracts, but as you can see by what’s left, it’s fairly relatively modest, relative to the size of PAA.

This next chart shows kind of our aggregate credit exposure relative to top 100 customers when you think of it in aggregate for the company, our Supply and Logistics segment really drives that and when you think of Supply and Logistics is dominated by the crude we buy from producers themselves to our refiner customers, exposure 60 days or less at any point in time, we have the right to ask for security, which would be an LC or prepayment.

And smaller part of S&L is exposure on our NGL business that Jason just walked through is characterized by small numbers to literally hundreds of different customers. You think of all those little dots that he was showing and the different customers at this location.

Transportation facilities, again S&L segment is a big user of our own assets, a large majority of what we do is with investment grade counterparties. We do have line fill and and inventory that act as a form of credit protection. We’re very comparable with our credit exposure.

When you look at the pie chart, when you combine A rated and BBB and secured at roughly about 80%. You can see the non-investment grade wedges and then you can see not rated. There is actually a decent number of smaller refineries that aren’t rated that have very strong credit profiles to them. Again we are comfortable with our credit exposure.

DCF and distribution coverage, for a large number of years, we targeted 105% to 110% distribution coverage. The historical data included in the chart, show an average of that the stock, 117% coverage and 1.18 [ph] clearly with what’s happened in the industry, we fell below one-to-one in 2015. Our guidance would show that were below in 2016 as well.

We recognize that that sub one-to-one coverage for MLP is not sustainable or really not an acceptable practice over the long-term. We are committed to returning to positive coverage. As we do look at that, we are actually at least considering is the 105% to 110% the right metric, when we get back to positive coverage and should we be thinking of more Cushing and/or using more retained DCF to minimize the need to access equity markets. So again really the messages we’re aware of it. We understand that it’s not a sustainable practice.

And PAGP’s tax position, this is a whole different format than what we probably use last year, but the two tax attributes are still there. There are still very favorable. If you look at March 31, balance sheet for PAGP, the tax asset on it was $1.9 billion. It equates to a little over $7 per share. We do not expect PAGP to be a taxpaying entity for a long time to come. The parenthetical there says with 10% growth, it would be over 10 years.

Cash distributions are return to capital. So it’s a deferred cash stream. We don’t expect those will become – we won’t have a quote dividend to pay tax on until we see positive earnings and profits. So again a very favorable tax position, there are no change.

My final slide before I turn it over to Greg. I think I’ve hit most of these bullets as we went through. I just wanted to have kind of a closing thought. Clearly the one we will get questions on are the first and last bullets, I hope I hit those as I walk through. We are very much committed to investment grade ratings.

And really I should clarify it earlier, when I commented on that, it’s more than just Greg and myself and our executive management team, it’s or Boards, it’s our GP owners. We are committed to that. And then on the bottom one, we are very much focused on returning to greater than one-to-one coverage.

And with that, I’ll let Greg to wrap up.

Greg Armstrong

We’re in the home stretch. We got one more Q&A session that we’ll fill in here, so just real quick on closing remarks. There’s been some questions certainly in January and February in general, but the viability and sustainability of the MLP model, I’m not going to read this to – we’ve placing just kind of highlighted what we think are the critical drivers for what has been known for many, many years and we’ve been in MLP, since 1998 as the MLP distribution and financing model.

Over the past five years, I think it’s been fair as we’ve had a significant increase in a number of MLPs. Capital has been very cheap and widely available. But that MLP universe, the quality of the assets has certainly expanded and, in some arguments, we would say has deteriorated.

And as a result, the MLP universe really became focused in on unrestrained access to capital. As we look forward, we think ultimately the MLP models certainly not broken. It’s very sustainable on long-term, but it does require high-quality businesses and integrated asset basis that we think have limited exposure to commodity prices and a disciplined approach to distribution coverage and pre-funding and I think you’ll see a migration back toward that in whole of the industrial over time.

By closing with that thought is that PAA, we believe exceeds the criteria of sustainable MLP. I think hopefully we’ve demonstrated today. We have tremendous system, located in all the right basins, with tremendous interconnectivity, very minimal direct exposure to commodity price. We’re certainly influenced by the trends when there’s a major change as we’ve seen in the last 18 months.

And we’ve got multiple projects coming on that are going to reinforce the distribution of the cash flow growth and supports our distributions, and then ultimately we’ve got a lot of incremental capacity, as Willie went through, and synergies that we think will represent a competitive advantage in a consolidated environment.

So with that, I think we’ve got time for last questions, and feel free to ask any and all. I think we had a couple that we were going to circle back around. Faisal, we’ll start with you instead of Noah at this time. We’ll come back to you Noah.

Faisel Khan

Thanks. Faisel from Citigroup. Just a couple of questions. I just want to make sure, I understand the investment-grade comment. So you are committed to investment grade at all three agencies?

Al Swanson

We don’t – we have ratings at S&P and Moody’s.

Faisel Khan

Okay, so that’s clear, okay. And if I think about a couple of things, I guess for Willie and Jason. If I look at the markets you guys touch, it is no doubt the other supply pushout of the Permian. But as I look at the refining markets, you don’t quite touch out of the Permian basin, it’s sort of the PADD II market and the east of the east of Houston market into Louisiana.

So I’m just trying to understand, are there projects like the Diamond Pipeline, which gets you into Memphis that could also get Permian crude into the east of Houston market and then to the PADD II market. I mean, how do you really connect the whole system, so you have more of a demand pull and supply push market. And then I – one question on NGLs?

Al Swanson

With the BridgeTex system, we get into east Houston market. So we get into Magellan East Houston that’s the terminal for that facility. Within PADD II, I think, John walked you through our Patoka facility. That’s connected to many and we have pipeline system up there that connects many of the PADD II refineries.

John Keffer

I would also add that in many case we don’t have to have direct pipeline connections to have basically the ability to as a conduits. When you looked at the slides we had out of Cushing, we connect, I think, we outpace connectivity wise our nearest competitor by a factor of 2 to 1 on connectivity. So they can use our tanks and our supply system. They didn’t go through a third-party pipeline to get almost any refinery in the Midwest.

Faisel Khan

Okay, yes. I was just trying to compare your system with the Enbridge system, which seems to be, not only supply push out of the Canadian West – the Western Canadian basin, but also a huge demand-pull into the PADD II and Gulf Coast markets. So I was just trying to understand that dynamic and how you’re thinking about the evolution of your pipelines over the next several years.

John Keffer


Faisel Khan


John Keffer

…don’t forget about Capline, I mean.

Faisel Khan


John Keffer

It’s going north now, but if you, again, play forward, there’s a lot of connectivity to the Eastern Gulf there. And if you look at that one drawing we have, if you’ll take a look at Red River and both Diamond, you’ve got a lot of potential capability to tie into the Eastern Gulf.

Faisel Khan


Greg Armstrong

Yes, I think, Faisel, we can circle back and we have…

Faisel Khan

Yes, sure, I understand.

Greg Armstrong

…really good connectivity in PADD II I’m not.

Faisel Khan

Okay. And then just on the NGL price exposure that Jason and Willie mentioned. So, I mean, if NGL prices go up substantially from here, what is – what’s the exposure you guys have? What’s the net benefit or uplift that you guys have to your cash flows earnings?

Jeremy Goebel

Well, on the – with NGL prices, the regional bases will widen out. So we’ll do better there if they increase. And then the second piece of it, which I didn’t spend a lot of time is on frac spreads The straddle plants do give us frac spread exposure. We manage that risk, but if NGL prices and crude shoot up and gas stays flat that will be positive for us as well.

Faisel Khan

Is there anyway to quantify that? If ethane prices were to double, how would you benefit from that?

Jeremy Goebel

If you look at the slide that had the pie chart, where we had kind of the incremental upside that Willie went through, there was a slice in there for NGLs and supply and logistics that will quantify that for you.

Faisel Khan

Okay. Thanks.

Ryan Smith

Are there questions?

Faisel Khan

Thank you.

Unidentified Analyst

Okay, I got the mike now. I’m just trying to play connect-the-dots a little bit. And so if I get any of my recollections wrong, let me know. I think Willie said that post – once you get past 2017 and this hyper-growth spurt with all the projects, that you kind of see growth CapEx going back down to what it used to be in a $300 million to $500 million range. And I’m trying to connect that dot to what Al said about, is 105 to 110 not the right coverage ratio maybe needs to be something higher.

So I’m just trying to get a sense of if typically we try to be 50-50 debt to equity in our growth CapEx maybe a little higher to balance it out. But every 5 basis points over a one times coverage ratio, how much extra cash flow does that provide? In other words, do you want to create enough cushion, so that you’re 100% self-funded? Do you want to create enough push and so that you can you possibly deliver or delivers a ratio, because you’re not borrowing. Well, I’m just trying to get a sense of all that, so what it all comes down to what is that number for every 5 – 0.05 multiple?

Greg Armstrong

Yes, I don’t know that I’ve thought of it exactly that way. But let me give it to you the way we have thought and that’s part of our discussions, that’s kind of the ongoing, how do we make sure we position Plains as we go through these simplification discussions, which involves as somebody pointed out tremendous number of variables in there. But if you, if I just pick a number, let’s say DCF is $1.8 billion, and you said I wanted to have a 115% coverage okay, you said something higher, so I’m just going to go above 110%.

Effectively, you’d be right at about $270 million of excess that you would say, I would retain. If you do a 55, 45 financial and that would support Noah roughly either $270 million of debt reduction, if you were too high, or it would support about $450 million of organic growth of that or touch the equity market. Does that help? Yes, and I think one of things that Willie mentioned when he said, we would go back to that.

I mean, right now, we don’t really foresee any meaningful made after 2017 for CapEx for a while. But if you go back to a situation, we said what would it normally be after thing start to fill up and we’re having to re-plumb, it’s in a $300 million to $500 million range.

So, I think what we’re looking at right now is as we size ourselves and we plan for and we’re certainly focused in on the future on distribution growth. We’ve got to get back to one-to-one first. But when we lay out this out and we’re doing multi-year models and we’re saying cost of capital tweaking,it we’re saying basically it’s a simplification structure better off than an IDR structure.

We’re looking at that and say, what do we need to do today to put in place and communicate that to the public? What they should expect from us in terms of growth and in terms of distribution coverage on what we call our base business?

Unidentified Analyst


Greg Armstrong

You’re all looking like at me like I’m standing between you and happy hour. Yes, Rebecca. Oh, come back.

Jeremy Tonet

Jeremy Tonet, JPMorgan. At the risk of jumping the gun here with regards to arrangement, it seems like crossing the border is an ever more difficult proposition. And it seems like we have a pretty good advantaged position right there. Just wondering, what it would take for you guys to move forward with reversal project there? I mean, it seems like there’s really some bottlenecks in Western Canada, given the oversubscription on the mainline, some of it moving by rail, it seems like arrangements in a pretty good position there. What type of capital would it require? What type of commitment? Any color you can share there?

Jeremy Goebel

Yes, the – your question about the first part of your question I wasn’t clear. But we do have residential permits and they’re fully permitted max capacity going both ways, so that’s not an issue. If your second part was the capital between $30 million and $40 million for Rangeland and $30 million and $40 million for Wascana, and I don’t remember the exact capacities, but it’s in the 80,000 to 100,000 barrels a day range for both.

Greg Armstrong

And Jeremy, if I – let me finish okay. When we finished Saddlehorn, which I think will be in the third quarter, fourth quarter?

Jeremy Goebel

Fourth quarter, the extension up to…

Greg Armstrong

That would allow us to basically make the final connection all the way down into Cushing. And then incrementally to reverse it, it’s not that much money $30 million, $40 million.

Jeremy Tonet

Gotcha. So you could bring it all the way from Western Canada down to Cushing without…?

Greg Armstrong

Through the Rangeland system, yes.

Jeremy Tonet

Yes.,It’s just interesting given…

Greg Armstrong

And it’s – through the Rangeland system to our system on Saddlehorn and various connections, so it gets back to that multiplier effect in that platform.

Jeremy Tonet

Right, make sense. And then just want to think about with regards to Moody’s downgrade recently and leaving on negative watch just trying to get a sense for how much cushion there is with agencies there? If scenario C plays out, is that a situation where you need more equity injection or to retain cash flow in some fashion, or is there anything you can share with us there?

Greg Armstrong

What I would point you to is just read what Moody’s put out, it’s probably the best. I think they’re at a much lower kind of operating scenario than probably what our – that scenario is. I think they laid out their expectation with that. And I think you when you read that, I think they would expect us to revert back and not lose it.

Clearly, if the environment turned out differently, we’ll have to make some changes and address that. But the resumption for oil prices are $33, $38, and $43. And so they’ve dialed in a pretty difficult operating environment, probably worse than probably what any of you all would think would be the scenario playing out. So I think, if you read that, it would answer your question, but we intend to not lose that Moody’s ratings.

Jeremy Goebel

One of things we’ve learned is not speaking on behalf of the rating agencies.

Jeremy Tonet

Make sense. Thank you.

Greg Armstrong

Thank you. Becca, you had a question.

Becca Followill

Becca Followill, U.S. Capital. What’s your targeted time to get back within your targeted credit metrics?

Jeremy Goebel

As soon as we can.

Becca Followill

That’s all.

Greg Armstrong

I think mid-summer we should have some information mid to late summer obviously we’ll work. I mean, we’ll – this evaluation process, whether anything comes out or not, we’re going to be in a position where we need and want to communicate to you those types of specific details. While we’re still in that evaluation data, I think, it will be very – it would just, it would put us way over the tips of our skis and having to catch up.

Becca Followill

Thank you.

Greg Armstrong

Yes, sir.

Shneur Gershuni

Shneur Gershuni with UBS. Two questions. One, is there any intent to try and get a rating from Fitch, so that, if you were to lose your rating, you wouldn’t come out of the investment grade index?

And then secondly, is the distribution policy as part of the pickup. Is the distribution policy under consideration as part of the simplification process that you’re evaluating, or you committed to the two agencies that exist today?

Greg Armstrong

So I can answer the last question first. The distribution policy and exactly where it should be said, how it should be adhered to is part of the whole evaluation. I mean, consider this kind of a strategic internal review of how do we make sure, we’ve had a sea change in activity and the expected growth, we’ve gone from being self-sufficient projected by the government in 2022 to something that’s a whole lot different. My guess is, we’ll change our forecast again next week.

But we’re having to come with ours. And I think, we have the groundwork, hopefully, we have shared that today that we have a very informed view of what the future looks like. We don’t have any absolute insights into which one of those three cases it will be, but we’re going to be prepared for all three of it. So that – it will be a part of that whole simplification evaluation, it’s a bigger issue than just simplification, I’ll let Al to answer.

Al Swanson

I didn’t hear the first question, I’m sorry.

Shneur Gershuni

The first question was whether you’re pursuing a rating with Fitch so that you would have three and you don’t fall out of IG?

Al Swanson

You were cutting in and out. We have considered and are considering whether our third rating. We understand the two or three issue as it relates to holders of our security, we would, if we had any really belief, we would lose it, we would definitely add a third rating. We haven’t included whether we will right now, but we have had dialogue. We have had consideration. We have evaluated how they look at midstream entities, how they would rate us. And but again, we don’t intend to lose the Moody’s rating.

Shneur Gershuni

Thank you.

Greg Armstrong

Any other questions? If not, I’m going to turn it over to Ryan. Before I do, I want to thank everybody for their attendance. We’ll be around here for another 30 to 45 minutes in this room. And then we’ll be for those that are staying for the game.

Jeremy Goebel

Right. We’ll be heading over to the suites at 5:45, Greg.

Greg Armstrong

Okay, cheers.

Ryan Smith

All right. And so like just Jeremy said, it’s about 5:30. You can grab a cocktail here in the room. We’re going to hang up a little bit and then breakup at 5.45. There will be a group headed up to suites. So if you want to form with that you’re welcome to or if you want to make your – check up the ballpark and make your own way up there, you’re welcome to do that as well. So, thank you.

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